SEPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-80-051
March 1980
Stack Gas Reheat
Evaluation
Interagency
Energy/Environment
R&D Program Report
-------
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tion Service, Springfield, Virginia 22161.
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EPA-600/7-80-051
March 1980
Stack Gas Reheat Evaluation
by
W.R. Menzies, C.A. Muela,
and G.P. Behrens
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78766
Contract No. 68-02-2642
rogram Element No. INE827
EPA Project Officer: Theodore G. Brna
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
Technical and economic evaluations of stack gas reheat (SGR) following
wet flue gas desulfurization (FGD) for coal-fired power plants were made.
These evaluations were based on information from literature and a survey of
FGD users, vendors, and architect/engineer (A/E) firms. Reheat processes
and their features and commercial operating experience were summarized. The
benefits and energy requirements associated with SGR were addressed, and a
method for estimating reheat costs was developed and illustrated.
Stack gas reheat can protect equipment downstream of a wet scrubber from
corrosion, reduce the potential for acid rainout near the plant stack, pre-
clude visible stack plumes, and reduce ground level pollutant concentrations
by increasing plume buoyancy. Reheat users have generally installed SGR for
equipment protection (30°F or greater level of reheat is normally specified).
Most A/E firms and vendors do not recommend SGR as a necessary part of a
wet FGD system and prefer indirect hot air injection because of higher
reliability if reheat is requested by customers.
Plants slated for operation with wet scrubbers in 1983 will use inline
(30 percent), bypass (24 percent), and indirect hot air (14 percent) reheat
or no reheat (wet stacks, 20 percent). Inline reheat is generally less
costly but exhibits lower reliability than indirect hot air injection reheat.
Bypass reheat is the most economical system, however, its application is
limited by SOz emission regulations.
iii
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CONTENTS
Abstract ill
Figures vi
Tables viii
Acknowledgments xi
1. Introduction 1
2. Summary 3
Stack gas reheat state-of-the-art 4
The need for reheat 8
Economic evaluation 15
3. Conclusions 20
The need for stack gas reheat 20
Survey of current practice 21
Evaluation and comparison of reheat configurations 21
4. Recommendations 24
5. Survey of Current Practice 25
Literature review 25
Survey results 32
Survey summary and conclusions 68
6. The Need for Stack Gas Reheat 71
Downstream equipment corrosion 72
Visible plume formation 87
Acid rainout in the vicinity of the stack 101
Increased ground-level pollutant concentrations 110
Applicability of bypass reheat 124
iv
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CONTENTS (continued)
7. Stack Gas Reheat Economics 129
Availability and cost of steam 130
Reheat exchanger sizing 134
Costs of various reheat configurations 136
Comparison of reheat system economics 165
References 170
Appendices
A. Description of Radian's dispersion and wet plume models 176
B. Questionnaire forms 183
C. Generalized 500-MW steam cycle—development and steam cost
analys is 209
D. Equipment sizing bases (reheat exchangers, fans, stacks) 235
E. Reheat configuration component cost assumptions 254
F. Factors for conversion of English units to the international
system of units (SI) 300
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FIGURES
Number Page
1 Simplified schematics of various reheat configurations 5
2 Simplified schematics of various reheat configurations 30
3 Calculated temperature rise due to work of compression 78
4 Simplified schematic of FGD systems with forced and induced
draft primary fans 79
5 Induced draft fan arrangement of inline, indirect, and direct
combustion reheat configurations 81
6 Psychrometric chart showing state point of flue gas-air mixture
during combustion, scrubbing, and reheat 88
7 Psychrometric chart showing the influence of relative humidities
on the temperature range at which an unscrubbed flue gas will
form a visible plume 96
8 Psychrometric chart showing the impact of 50°F reheat on visible
plume length at different relative humidities 98
9 Impact of scrubbing and reheating on visible plume length at
various ambient air temperatures and relative humidities 99
10 Predicted impact of wind speed and reheat on detached distance
of visible plume 100
11 Model-predicted time lengths that the density of the condensed
water vapor in visible plumes was greater than 3.12 x 10 lb/
ft3 for various reheat levels 107
12 Model-predicted maximum densities attained by condensed water
vapor in visible plumes for various reheat levels 108
13 Model-predicted three-hour, ground-level SOa concentration down-
wind of the stack for an unstable atmosphere 113
14 Model-predicted three-hour, ground-level N0x concentration down-
wind of the stack for an unstable atmosphere 114
15 Model-predicted three-hour, ground-level SOz concentration down-
wind of the stack for a neutral atmosphere 116
16 Model-predicted three-hour, ground-level NOX concentration down-
wind of the stack for a neutral atmosphere 117
vi
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FIGURES (continued)
Number Page
17 Schematics of different fan arrangements used to develop
economics of various reheat configurations 139
18 Simplified schematic of indirect hot air reheat configuration
with a forced draft primary fan arrangement 149
19 Simplified schematic of indirect hot air reheat configuration
with an induced draft primary fan 154
20 Simplified schematic of indirect hot air reheat configuration
with a forced draft primary fan arrangement 156
21 Simplified schematic of exit gas recirculation reheat with an
induced draft primary fan arrangement 159
22 Simplified schematic of an advanced EGR reheat configuration.... 161
23 Schematics of direct combustion reheat configurations with
forced and induced draft primary fan arrangements 163
vii
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TABLES
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Reheat Configuration Operating Characteristics
FGD Process Vendor and Architect/Engineering Company Responses.
Heat Input Required to Prevent the Occurrence of Moisture
Downstream of the Scrubber
Reheat Required to Prevent a Visible Plume
Impact of Stack Gas Reheat on Maximum Three-Hour Ground-Level
Pollutant Concentrations
Stack Gas Reheat Economic Evaluation Summary (1978 $)
Reheat Configurations and Potential Energy Sources
Electric Utility Units and Specified Type of Reheat
Reheat Temperature Levels at Operating and Planned Units
Reheat Energy Sources
Indirect Hot Air Reheat Systems
Wet Stack Systems
Temperature Drop Through Duct With and Without Insulation
Flue Gas Temperature Drop Due to Heat Loss From a 600-Foot
Stack
Heat Input Required to Prevent the Occurrence of Moisture
Reheat Required to Prevent a Visible Plume
Parameters for Utilization in Wet Plume Model (500-MW Plant)...
Page
7
8
10
12
14
17
27
33
35
37
40
41
42
45
54
58
62
65
70
74
75
86
90
92
viii
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CABLES (continued)
Number Page
25 Visible Plume Length and Detached Distance (Neutral Stratifi-
cation, Wind Speed = 5 MPH) 93
26 Visible Plume Length and Detached Distance (Neutral Stratifi-
cation, Wind Speed - 15 MPH) 94
27 Visible Plume Length and Detached Distance (Neutral Stratifi-
cation, Wind Speed = 25 MPH) 95
28 Plume Characteristics for Various Scrubbing and Reheat Levels
(Neutral Atmosphere, Wind Speed « 5 MPH) 104
29 Plume Characteristics for Various Scrubbing and Reheat Levels
(Neutral Atmosphere, Wind Speed * 15 MPH) 105
30 Plume Characteristics for Various Scrubbing and Reheat Levels
(Neutral Atmosphere, Wind Speed » 25 MPH) 106
31 Flue Gas, Stack and Emission Parameters 112
32 Impact of S02 Removal Efficiency on Maximum Three-Hour Ground-
Level S02 Concentrations 118
33 Impact of Stack Height on Maximum Three-Hour Ground-Level
Pollutant Concentrations 119
34 Maximum Annual Average Pollutant Concentrations 120
35 Seasonal Effect of Reheat on Ground-Level S02 Concentration 122
36 Available Steam Conditions in the Base Case Steam Cycle 131
37 Cost (1978 $) of Various Steam Levels for Reheating Flue Gas 133
38 Capital and Operating Cost Bases Used to Develop Economics of
Various Reheat Configurations 135
39 Plant Characteristics and FGD Configurations Used to Develop
Economics of Various Reheat Configurations 138
40 Cost Summary Sheet for Inline Reheat 140
41 Costs of Inline Reheat Using Various Dry, Saturated Steams 142
42 Summary and Comparison of Economics for Inline Reheat
(Sensitivity Analyses) 144
43 Evaluation of Exchanger Tube Metallurgy for Inline Reheat
(1978 $) 147
44 Cost Summary Sheet for Indirect Hot Air Reheat 150
45 Economics of Using Dry, Saturated Steam in Indirect Hot Air
Reheat Systems 151
ix
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TABLES (continued)
Number Page
46 Summary and Comparison of Economics Developed for Indirect
Hot Air Reheat Sensitivity Studies 153
47 Cost Summary Sheet for Exit Gas Recirculation 157
48 Cost of Using Dry, Saturated Steam to Reheat Flue Gas With an
Exit Gas Recirculation System 158
49 Economics for Exit Gas Recirculation Sensitivity Studies 160
50 Costs of Direct Combustion Reheat (1978 $) 162
51 Stack Gas Reheat Economic Evaluation Summary (1978 $) 166
52 Impact of Assumptions on Economics of 50°F Reheat With Inline
Reheat System 169
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ACKNOWLEDGMENTS
The authors would like to express their appreciation to Dr. Theodore
G. Brna, EPA Project Officer, for his advice and technical guidance provided
throughout the project.
Dr. Phillip S. Lowell provided substantial technical input to this
program and his work is gratefully acknowledged.
Special thanks are also given to Ms. Christy K. Holcomb for her efforts
in preparing the report.
In addition, numerous individuals contacted as part of an OMB-approved
survey contributed their advice and assistance during the course of the
project. These individuals are listed in the Reference Section of the
report.
xi
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SECTION 1
INTRODUCTION
Stack gases from utility boilers without flue gas desulfurization (FGD)
are normally discharged to the atmosphere at a temperature of 250°F to 300°F.
In this temperature range, the flue gas is relatively dry and noncorrosive.
The wet FGD processes currently being used commercially in the United States
cool the boiler flue gas from about 300°F to its adiabatic saturation temper-
ature, typically 125-140°F. This saturated (with water vapor) flue gas may
cause the following problems:
(1) The corrosion of equipment downstream of the scrubber
(duct work, fan, stack) due to the presence of moisture,
acid, and chlorides.
(2) The occurrence of acid rainout* in the vicinity of the
plant stack.
(3) The formation of a visible plume which may be hazardous
to any ground and air traffic in the vicinity of the
power plant.
(4) High ground-level pollutant concentrations downwind
from the stack due to poor plume buoyancy.
Reheating the saturated flue gas to a temperature above its saturation tem-
perature will lessen the impacts of each of these four potential problems.
The objectives of this study were to survey the utility industry to
determine their present practices regarding the use of stack gas reheat (SGR),
*The term acid rainout is used in this report to refer to rain in the vicin-
ity of the plant stack to distinguish it from the term acid rain which is
used to describe a different phenomenon.
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determine how much reheat is needed and its costs, and compare the economics
and reliabilities of the available reheat methods.
The various analyses conducted, as well as the significant results and
recommendations, are discussed in the following sections:
Sections 1-4 - Introduction, Summary, Conclusions, Recommendations
Section 5 - Current industrial practices with respect to the use
of reheat are reported and analyzed. Operating data
for commercially available reheat configurations are
also presented. This information reflects data ob-
tained from reheat users, FGD process vendors, archi-
tect/engineering companies, and available literature.
Section 6 - The problems (presented on page 1) that may be caused
by the use of wet FGD processes and the mechanisms
by which these problems occur are discussed. The
quantity of reheat that is theoretically required
to eliminate these problems (where possible) and
the impact of varying degrees of reheat are also
evaluated.
Section 7 - The capital requirements and operating costs for SGR
systems providing 50"F of reheat are estimated and
discussed. A methodology is developed for estimating
steam and hot water costs in power plants using SGR.
The annualized costs for four commercially available
and/or promising reheat configurations are developed
and compared. The sensitivity of the costs of these
configurations to various design and operating param-
eters is also analyzed.
It should be noted that English units have been used throughout this report
for the convenience of the reader. These units can be readily converted to
the International System of Units with the conversion factors presented in
Appendix F of this report.
This report was submitted in fulfillment of Contract No. 68-03-2642 by
Radian Corporation under the sponsorship of the U.S. Environmental Protection
Agency. The majority of the project work was conducted from June, 1977 to
September, 1978.
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SECTION 2
SUMMARY
An economic and technical assessment of stack gas reheat (SGR) technology
was conducted with the following approach:
(1) A survey of the state-of-the-art in SGR practices and
technology was conducted. Information was obtained from
available literature and an OMB-approved questionnaire
which was distributed to reheat users, flue gas desulfuri-
zation (FGD) process vendors, and architect/engineering
(A/E) companies. The objectives of this survey were to:
—Identify the problems associated with saturated flue
gases resulting from wet scrubbing,
—Identify commercially available and promising reheat
techniques, and
—Assess current industry practice and experience with
SGR systems.
(2) A theoretical evaluation of the need for reheat was per-
formed. The objectives of this evaluation were to:
—Identify the mechanisms causing the problems associated
with wet stack gases,
—Evaluate the impact of varying levels of SGR on these
problems, and
—Estimate the energy requirements and limitations asso-
ciated with various reheat configurations.
(3) Capital and operating costs for various SGR configurations
were estimated. The analyses included:
—Estimating and comparing the costs for the principal
reheat configurations, and
—Analyzing the sensitivity of SGR economics to changes
in important parameters.
-------
STACK GAS REHEAT STATE-OF-THE-ART
Based on a review of the various types of FGD processes, it was
determined that processes that cool and saturate the flue gas with water
may require stack gas reheat. Saturated stack gases may cause the following
problems compared to unscrubbed stack gases:
(1) The corrosion of equipment downstream of the scrubber due to
the occurrence of condensation
(2) The formation of a visible plume which may be hazardous to
ground and air traffic in the vicinity of the power plant
(3) The occurrence of acid rainout in the vicinity of the plant
stack
(4) Increased ground-level pollutant concentrations (compared to
the unscrubbed flue gas) downwind from the stack due to poor
plume buoyancy
The impact of these problems can be reduced or eliminated by using SGR to
heat the saturated stack gas above its dew point.
Several methods have been employed or envisioned to reheat scrubbed
flue gas. Schematics of these methods are presented in Figure 1 and
descriptions are presented below:
(1) Inline reheat - The scrubbed flue gas is heated by passing
it through a heat exchanger located in the duct work.
(2) Indirect hot air injection reheat - Air is heated in an
exchanger and then mixed with the scrubbed flue gas.
(3) Direct combustion reheat - Hot combustion gases which are
generated by firing fuel oil or natural gas are mixed with
the scrubbed flue gas.
(4) Exit gas recirculation (EGR) reheat - A portion of the
reheated scrubbed flue gas is passed through the reheater,
heated to a higher temperature, and then mixed with the
saturated flue gas.
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acruoocr
Flue Cu
Reheat Exchanger
To Stack
Steaa or
Dot Water
(a) Inline Reheat
Scrubber
Flu* Gas
Air
Sceaa
_> To Stack
Air Heater
(b) Indirect Hot Air Reheat
Flue G
Futl 011/N
I
____\r^ Coabustion
latural Gas )[ \ Qiaober
To Stack
'Air
(c) Direct Combustion Reheat
Flue Gas
To Stack
_/Reheat
Stea» / Exchanger
(d) Exit Gas Recirculation Reheat
flue Ga* •
To Stack
Scrubber
(e) Bypass Reheat
Flu* Cat
Cooler
Scrubber
Flue Sae
../.. 7 Flu* Gas
' Better
' To Stack
"^ Racireulatint
Fluid
(f) Waste Heat Recovery Reheat
Note: Fans and pumps not shown for simplicity.
Figure 1. Simplified schematics of various reheat configurations.
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(5) Bypass reheat - A portion of the boiler flue gas is routed
around the scrubber and mixed with the scrubbed flue gas.
(6) Waste heat recovery reheat - Hot unscrubbed flue gas is used
to heat the scrubbed flue gas in a dual exchanger arrangement.1
Table 1 presents a summary of the advantages, disadvantages, and operating
characteristics of the various reheat configurations as applied to new and
retrofit applications.
Questionnaires were distributed to reheat users (limited to coal-fired
power plants with scrubbers), FGD process vendors, and architect/engineering
companies in order to determine current trends in the use of stack gas
reheat, identify those configurations that were or are used commercially,
and to obtain operating and reliability data for these configurations. The
responses to those questionnaires reflect industry practice and experience
as of mid-1978. These responses indicate that the majority of FGD process
vendors and A/E companies do not recommend the use of SGR as a necessary
part of a wet scrubbing system. Additional data obtained from FGD process
vendor and design responses are presented in Table 2.
Data obtained from the users of reheat indicate:
(1) The major reason given for using reheat is equipment protection
against corrosion.
(2) The second reason most often given for using reheat is
increased plume buoyancy for pollutant dispersion.
(3) Plants presently using stack gas reheat generally heat the
scrubbed flue gas by 30°F or more in order to accomplish
items 1 and/or 2.
(4) The inline, indirect hot air, direct combustion, and bypass
reheat methods are the commercially-used configurations.
Inline reheat is the most widely used configuration.
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TABLE 1. REHEAT CONFIGURATION OPERATING CHARACTERISTICS
Current commercial
usage (percentage
of total)'
PeitLittttge of total
reheat/no reheat
systems to be used
by 19»3*
Advantages of
configuration
Disadvantages of
configuration
Inline
39
50
(1) Simple design.
(2) Mo increase In
the flue gas.
(3) l*ss energy than
other systems
except bypass and
BGR for a set
degree of reheat .
(1) Corrosion and
plugging commonly
occur.
(2) Difficult to
retrofit*
Indirect Hot Air
20
14
(1) No corrosion
or plugging of
experienced.
(2) More reliable
than inline.
(1) Mass flow
rate of
flue gas
increased ,
(2) External
energy
required in
order to
drive auxil-
iary air fan
when needed.
(3) Severely
limited for
retrofit
applications.
Reheat Configuration
Direct Combustion Bypass
18 7
12 25
(1) Simple design (1) Host economical
and operation. form of reheat.
(2) No corrosion (21 Simple design
or plugging (3) No external
experienced. energy required.
(3) Relatively low
capital coat.
(4) Easiest to
retrofit.
(1) Cast highly (1) Use Is restrlc-
sensitive to ted by SO2 emis-
fuel cost. slon standards.
Also, low sul- (2) Hay be difficult
fur fuels to retrofit.
(natural gas
and No. 2 fuel
oil availabil-
ity and/or cost
may prohibit
use.
(2) FUme stability
and incomplete
combustion have
been experienced
when fuel oil
was used.
(3) Hot combustion
gases can damage
duct work if
mliUg with flue
gas not done
properly.
" "*
Exit Gas
Recalculation (ECU) Uaste Heat Recovery
Not proven on commer- Hot proven on commer-
cial scale cial scale
0 0
(1) Less corrosion (1) W.-.KIC lu-at
than Inline roruvi r»-d so
flue gas howled energy required.
before contacting
teheater.
(1) Not proven on (1) Not proven on
(2) External en*rgv (2) Front fiad ex-
required In order changer will
tan. corrosion prob-
(3) Hucb equipment lent*.
required, there- (3) Relatively large
fore retrofit may heat transfer
Wet Stacks
16
20
(1) No reheat required.
(2) Significant s.ivings
to systems In which
reh«ar is used.
(duct work and stack).
(2) Arid raimiut m.iv
orcur .
( 3) Scrubber ret rof it
may require substan-
tial modification to
stack.
(4) Bypass ol scrubber
has blistered some
stack linings.
This percentage was developed from data which reflect present sod future operation of 102 power plnnta. The use of wet stacks was included la the development of this percentage.
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(5) The bypass reheat systems and the no reheat system (wet
stacks) outnumber other reheat systems for power plants
coming onstream after January 1, 1978 (this includes
planned facilities for which information was available).
(6) Current and future use of bypass reheat is restricted by
emission standards.
TABLE 2. FGD PROCESS VENDOR AND ARCHITECT/ENGINEERING COMPANY RESPONSES
Configuration Recommendations Remarks
Inline 3 Recommended reheat materials are site
specific but range from carbon steel
to Inconel 625. Soot blowers should
be used.
Indirect Hot Air 10 Finned carbon steel or copper tubes
should be used.
Direct Combustion 1
Bypass 7 Some did not recommend bypass because
it was felt that future S02 emission
standards would limit applicability.
Exit Gas Recirculation 0 Not commercially proven.
Waste Heat Recovery 0 Not commercially proven. Heat ex-
changer equipment material requirements
are uncertain.
3Although 12 A/E and vendors responded, some firms recommended more than one
form of reheat. These are the reheat configuration recommendations that
the respondees would make if a client requests an SGR system in connection
with the wet scrubber.
THE NEED FOR REHEAT
An analysis of each of the problems associated with a wet stack gas and
the benefits and energy penalties that result when stack gas reheat is
utilized are presented below.
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Equipment Corrosion
Because the scrubbed flue gas contains SOz, SO3, COz, chlorides, NOX,
and some sulfuric acid mist, the flue gas can be very corrosive in the pres-
ence of condensed water vapor. A study to determine the impact of reheat on
the presence of moisture in the system was conducted. The heat input re-
quired to prevent condensation is dependent on several variables, with the
most important variables being:
(1) Heat losses from the duct work and stack
(2) Quantity of mist carry-over from the scrubber
(3) Reheat configuration used
Responses to the questionnaire indicated that a temperature drop of
about 5°F is typically experienced in new plants from the reheater or scrubber
exit to the top of the stack. This provides a good estimate of the heat
loss through the duct and stack walls. This verifies calculations performed
as part of this study.
The theoretical reheat energy input required to prevent the occurrence
of moisture downstream of the scrubber was calculated for inline, direct
combustion, and indirect hot air reheat. These heat requirements are
summarized in Table 3. A comparison of these data indicates that the
indirect hot air reheat method requires more energy than inline or direct
combustion reheat.
Industry users generally indicate that 30°F of reheat or more is
required to adequately protect equipment from corrosion. In this assessment
of SGR, a detailed evaluation of the mechanism of mist vaporization by
reheat in the duct work and stack was not undertaken. Modelling liquid
(mist carryover) droplet size, characteristics, and residence time in the
-------
TABLE 3. HEAT INPUT REQUIRED TO PREVENT THE OCCURRENCE OF MOISTURE DOWNSTREAM
OF THE SCRUBBER
Keheat Coul i £ural ion
Inline
F.utialued Liquid (gr/scf)1 0.012 0.805
(lb/hr) 130 8840
Dew Point Temperature at Stack Exit (°F) 129 129. 5
Ambient Air Character Istlcs
Temperature (°F)
Relative timidity (I)
Heated All Temperature (°F)
Flow Kale (Ib/hr)
Assumed Heat Loss (10C Blu/hr)" 6.6 6.6
Heal Required For Vaporizing Entrainment 0.13 9.0
(10 Btu/lir)
Sensible Heat Required for Keheat Medium*
(10* Utu/hr)
Theoretical Heal Required to Prevent
I'rcsence ul Moisture (10C Btu/lir) 6.7 15.6
(Z of boiler input) 0.15 0.35
Direct
0.012
130
129
60
50
_
-
6.6
0.13
0.01
6.7
0.15
Combustion
O.SOb
8B40
129.5
60
50
_
92
6.6
9.0
O.02
15.6
0.35
Indirect
0.012
130
128.4
64
50
4OO
,500
6.6
0.13
1.6
8.3
0.18
Hot Air
o.aos
uaw
I2U
60
50
400
212,500
6.6
9.0
3.6
19.2
0.43
'Reference 3 reports eiitminuieni loading of ,O12 gr/scf for a bottom wash mist eliminator and
.805 gr/t>cf for a top wash wist eliminator.
'Total heat losses assumed to lie equivalent for all configurations and correspond Co a 5*F dro|> In
flue UBS leutpcTtit ure .
*Tliltt sensible deal cuuals tbe hoat required to raise the reheat nediun from its ambient temperature
to the stack exit temperature.
Bjb.-a:
(1) 500 MM mill
(2) 4,0(Ki Utii/kWIi lieal rate
(1) Forced tlraft tan configuration (wi tli respect to the scrubber)
(4) Flw I'.an saturation tew|ieralure - 129°F
(5) Flue gas flow rale - 5.14 x 10b Ih/lir
(6) Fluv ra:. haul <-i|iaclty - 0.26 Blu/lb-'F
(7) For direct coBbustion, natural gas ambient temperature assumed to he 60°F.
(tt) I'nteiil f ;i I mid kinetic energy ch
-------
duct work and stack should provide insight into why as much as 50°F of reheat
is needed to protect downstream equipment.
Visible Plume Formation
The heat input to wet flue gas required to prevent a visible plume was
determined for the inline and indirect hot air configurations at various
ambient air temperatures and relative humidities (see Table 4). The results
of these analyses show that the heat input required to prevent a visible
plume for the two configurations is approximately the same. The quantity
of energy required to eliminate a visible plume under all ambient conditions
is prohibitively large. For example, at 32°F and 100 percent relative
humidity, about 9 percent of the boiler heat input would be required to
prevent a visible plume.
Acid Rainout in the Vicinity of the Plant Stack
Acid rainout may be caused by the condensation of acid vapor in the
system and its subsequent entrainment, entrainment of condensed water vapor
which has reacted with SCh and then oxidized to sulfuric acid (HaSOO, and/or
condensation of acid vapor when it exits the stack. Reheat can reduce the
potential for acid rain by preventing the occurrence of condensation; however,
the degree of this reduction cannot be readily quantified since the percent-
age of acid rain attributable to various mechanisms is undetermined.
A plume simulation program was used to study the impact of reheat on
the density of condensed water vapor in a visible plume. Several levels of
reheat (increase in flue gas temperature), ambient temperature, relative
humidity, and wind speed were considered in this study. These analyses
showed that reheat can decrease the concentration of condensed water vapor
in the plume and, consequently, the potential for acid rain. However, this
impact is dependent on climatic conditions and there are some conditions,
such as low temperatures and high humidities, at which reheat has little or
no effect.
11
-------
TABLE 4. REHEAT REQUIRED TO PREVENT A VISIBLE PLUME
NJ
Reheat Configuration
Ambient Air Temperature (°F)
Relative Humidity (%)
Flue Gas (at scrubber exit)
Saturation Temperature (°F)
Heated Air Temperature (°F)
60
50
129
-
Inline.
60
100
129
-
32
100
129
-
Quantity of Heated Air Required (106 Ib/hr) -
Stack Gas Reheat Temperature Required
To Prevent Visible Plume (°F)
Reheat Required to Prevent Visible
Plume Formation (106 Btu/hr)
(% Boiler Input)
183
71.0
1.58
240
149.0
3.31
439
416.0
9.24
Indirect
60
50
129
400
0.84
166
71.0
(70.5)
1.58
(1.56)
Hot Air Injection
60
100
129
400
1.75
196
149.0
(147.7)
3.31
(3.28)
32
100
129
400
4.52
253
416.0
(412.0)
9.24
(9.15)
Bases and Comments:
(1) Flue gas flow rate (existing scrubber) is 5.14 x 106 Ib/hr (representative of a 500-MW plant).
(2) Flue gas water content (exiting scrubber) is assumed to be 14.7 percent (vol.) for all cases.
(3) A heat rate of 9000 Btu/kWh was assumed.
(4) Heat losses in duct work and stack are assumed to be negligible.
(5) Liquid entrainment from the mist eliminator is assumed to be zero.
(6) Primary fan arrangement is forced draft with respect to the scrubber.
(7) Reheat requirements in parentheses for indirect hot air were developed by taking credit for
heat due to work of compression produced by the auxiliary fan. The pressure drop in the air
heater was assumed to be 6 in. H20 and an 85 percent fan efficiency was also assumed.
-------
Totally eliminating the presence of sulfuric acid in the system would
involve vaporizing any aqueous acid or acid mist. This would require enough
heat input to raise the flue gas temperature above the acid dew point
(approximately 300°F). This heat input is considerably more than is gener-
ally used by industry (0 to 100°F of reheat). Moreover, raising the flue
gas temperature to 300°F does not insure that condensation of sulfuric acid
vapor will not occur when the flue gas exits the stack and mixes with ambient
air. Currently, not enough data are available to identify the benefit which
would be obtained with reheat beyond the level required to prevent water
vapor condensation in the stack or duct work.
pollutant Dispersion
Scrubbing the boiler flue gas can adversely affect ground-level pollu-
tant concentrations. By cooling and saturating the flue gas with water, the
scrubbing process causes poor plume buoyancy which, in turn, reduces the
dispersion of pollutants exiting the stack. Reheat will reduce ground-
level pollutant concentrations and a plume dispersion model was used to study
this effect. The bases and results of part of this study are presented in
Table 5 and show that:
(1) Scrubbing (without reheat) significantly reduces the maximum
three-hour ground-level SOa concentration that results from an
unscrubbed flue gas. Scrubbing, however, increases the ground-
level concentration of NOX above the values for the corresponding
unscrubbed flue gas. However, in all cases the pollutant concen-
trations are well below applicable air quality standards.
(2) Reheating the scrubbed flue gas by 50°F can significantly
reduce the ground-level N0x and SC>2 concentration (on a
percentage basis) compared to the ground-level concentra-
tions obtained with scrubbing and no reheat.
(3) Reheating the scrubbed flue gas by an additional 50°F (100'F
of total reheat) further reduces the ground-level S02 and N0x
concentrations, but the relative reduction attained is diminished.
(4) The maximum ground-level concentration of N0x from an unscrubbed
stack gas (at 300°F) remains significantly lower than the maximum
13
-------
TABLE 5. IMPACT OF STACK GAS REHEAT ON MAXIMUM THREE-HOUR GROUND-LEVEL
POLLUTANT CONCENTRATIONS
Stack Height
(ft) Scrubbing-Reheat Level
300 Unscrubbed
Scrubbed with no reheat
Scrubbed with 50°F reheat
Scrubbed with 100°F reheat
600 Unscrubbed
Scrubbed with no reheat
Scrubbed with 50° F reheat
Scrubbed with 100°F reheat
Maximum Ground Level
S02 Concentration
yg/m3
180
98
70
55
78
30
24
20
% of unscrubbed
100
54
39
31
100
38
31
26
Maximum Ground Level
NOx Concentration
yg/m3
21
58
42
32
9
18
14
12
% of unscrubbed
100
276
200
152
100
200
156
133
Bases:
(1) Neutral atmospheric stability
(2) 18-mph wind speed
(3) 500-MW plant
(4) Atmospheric temperature is assumed to be 60°F.
(5) 80 percent S02 removal
(6) 30.6-foot stack diameter
(7) Stack gas velocities
(a) unscrubbed - 35.0 ft/sec
(b) scrubbed - 28.7 ft/sec
(c) scrubbed with 50°F reheat - 31.1 ft/sec
(d) scrubbed with 100°F reheat - 33.5 ft/sec
(8) Unscrubbed stack gas temperature - 300°F
(9) Scrubbed stack gas temperature (with no reheat) - 129°F
-------
ground-level N0x concentration obtained from a scrubbed
stack gas (with 100°F of reheat).
(5) The impacts of reheat on maximum ground-level concentrations
are lessened at taller stack heights.
A comparison of the effect of inline and indirect hot air reheat on
ground-level pollutant concentration showed that for the same degree of re-
heat (equivalent stack exit temperature), the indirect hot air scheme pro-
duces the lowest ground-level pollutant concentrations. However, the volume
of injected air substantially increases the heat input required.
ECONOMIC EVALUATION
Capital requirements and operating costs were estimated for reheat
systems* (inline, indirect hot air, direct combustion, EGR) providing 50°F
of reheat to the scrubbed flue gases from a new 500-MW power plant. For
those reheat configurations involving the design of heat exchangers, a
design procedure was developed which allowed estimation of heat transfer
surface area as a function of:
(1) Steam quality (temperature, pressure)
(2) Gas-side pressure drop
(3) Tube size, spacing, and alignment
*Economics for bypass reheat were not estimated. Current SOa NSPS (1979) for
power plants will not permit obtaining a reheat level of 50°F with bypass.
However, with low sulfur coals, some bypass will be feasible and another
method of reheat could be used to supplement the bypass reheat in order to
obtain 50°F of reheat (if desired). Bypass reheat is the most economical
reheat system up to the level permitted by environmental regulations. The
economics methodology developed in this study for inline, EGR, indirect hot
air and direct combustion can be used to estimate costs for 50°F of reheat
using bypass and some other supplemental form of reheat. It is expected
that some users of low sulfur coals will opt for this method of stack gas
reheat.
15
-------
(4) Gas-heating medium approach temperatures
(5) Scrubbed flue gas temperature (at scrubber exit) and level
of reheat required
The reheat exchangers were not designed optimally, but reasonable design
values were selected, and sensitivity analyses were performed.
Economic Results
Capital investment and operating costs for SGR systems will vary con-
siderably depending on the following parameters:
(1) Steam quality (temperature, pressure) and cost
(2) Plant fuel cost ($/106 Btu)
(3) Reheat configuration selected (EGR, inline, indirect hot air,
direct combustion)
(4) Exchanger design criteria
(5) Reheat temperature desired
(6) New or retrofit installation
(7) Coal quality
(8) Ductwork and stack heat losses
(9) Mist carryover from scrubber mist eliminator
Ranges of costs for selected reheat cases are presented in Table 6. The
costs are compared to costs for a new coal-fired plant and a limestone FGD
system. It should be emphasized that the reheat costs shown are not for op-
timized designs. Reheat media (steam) quality and reheat exchanger parameters
such as gas-side pressure drop, exchanger approach temperature, tube spacing
and use of finned tubes for hot air injection, have not been optimized. Also
the cost of reheater downtime (this may translate to scrubber downtime and
boiler load reduction) has not been factored into the economic analysis.
16
-------
TABLE 6. STACK GAS REHEAT ECONOMIC EVALUATION SUMMARY (1978 $)
Kuliuat System
Reheat System Capital
Requirement. 10'$
Z of FCD System3 Capital
Requirement
Z of Total Power Plant
Capital Requirement
Reheat System Annual
Revenue Requirement (ARR) ,
10' ?/year
* of FCD System3 ARR
Z of Total Power
Plant6 ARR
H.isoa
Steam futility
Tube Material
Fuel Costs
Inline
0.8 - 2.9C
1.1 - 3.6
0.2 - 0.7
1.5 - 1.7
7.1 - 8.1
1.4 - 1.5
Dry, Saturated
(165-600 psla)
Carbon Steel,
316 SS
Inconcl 625
Based on coal
in new power
plant at $1/10'
Bcu
Indirect
Hot Air
1.4 - 2.4
1.9 - 3.2
0.4 - 0.6
1.9 - 2.1
9.0 - 10.0
1.7 - 1.9
Dry, Saturated
(165-600 psia)
Carbon Steel
Based on coal
in new power
plant at $1/10'
lieu
Exit Gas
Recirculatiun (EGR)
1.3 - 2.1
1.7 - 2.8
0.3 - 0.5
1.4 - 1.6
6.7 - 7.6
1.3 - 1.5
Dry, Saturated
(165-600 psla)
Carbon Steel
Based on coal
in new power
plant at SI/106
ticu
Direct
Combustion
0.8
1.1
0.2
1.6 - 2.0
7.6 - 9.5
1.5 - 1.8
-
-
$3-4/10' Btu
No. 2 fuel
oil
3FCD system costs are taken as $150/kW (capital requirement) and 6 raills/kWh (annual revenue
.requirement).
A new power plant (Including FGD system) costs are taken as $800/kW (capital requirement)
and 31.4 mllls/kWh (annual revenue requirement). See Appendix E.
cFor Inline reheat the large range for capital requirement is due primarily to the estimation
of capital investments for several different tube materials.
Bases: (1) 50°F of reheat
(2) No nlst carryover from scrubber
(3) No heat losses from ductwork and stack
(4) New SOO-MW power plant with a heat rate of 9000 Btu/kWh
-------
Since indirect hot air injection exhibits better reliability than inline
reheat, this is a factor that may make indirect hot air injection competitive
with other reheat systems for some users.
The following are noted (for the results given in Table 6):
(1) Inline and EGR reheat are generally lower cost systems than
direct combustion and indirect hot air injection reheat.
EGR reheat, however, has not been tested commercially.
(2) The better indirect hot air reheat reliability (compared to
inline) may make indirect hot air reheat competitive with the
other systems for some users.
(3) Since the direct combustion system annual revenue requirement
(ARR) is highly dependent on fuels which may be subject to
availability constraints and high cost escalation, its use
in new power plants is expected to be limited.
Impact of Assumptions on Economics
It is recognized that all power plants and scrubbers are different and
consequently, the reheat configurations used in these plants will also be
different. The technical and economic assumptions used in the economic
evaluation obviously do not apply to all situations. An evaluation of how
changes in the bases affect the costs associated with an inline reheater was
conducted. A base case inline reheater was selected for this analysis:
(1) New 500-MW power plant
(2) 9000 Btu/kWh plant heat rate
(3) Heat losses from the stack and duct work (downstream of
the mist eliminator) considered megligible
(4) Entrainment from the mist eliminator considered negligible
(5) 50aF flue gas temperature rise through the reheater
(6) Carbon steel tubes in the reheater
(7) 165 psia, dry, saturated steam as reheat steam
18
-------
These assumptions are essentially the same as those used to prepare the
information in Table 6. They resulted in a required heat input of 66.8 x 106
Btu/hr, a capital requirement of $1,090,000, and an annual revenue require-
ment of $l,520,000/yr. Several differences in the base case assumptions were
evaluated as described below:
Case A - The only base case values changed are related to the
entrained mist and heat loss assumptions. The entrained
mist is assumed to be 0.802 gr/scf. A 5°F temperature
drop in the flue gas due to heat losses from the system
equipment downstream of the mist eliminator is also as-
sumed. These values increase the reheat requirement
from 66.8 x 106 to 82.4 x 106 Btu/hr and the annual
revenue required from $1.52 x 10s to $1.87 x 106. The
new capital requirement is $1.34 x 106.
Case B - In addition to the heat losses that were assumed in
Case A, the reheater tube material is 316 stainless
steel instead of carbon steel (base case). The change
results in increasing the annual revenue requirement of
the base case by about 26 percent to $1.91 x 106. The
capital requirement of the reheat exchanger increases
significantly (from $1.09 x 106 to $1.84 x 106).
Case C - In this case the entrained mist is 0.802 gr/scf. Heat
losses are equivalent to a 5°F drop in flue gas tempera-
ture. The reheater tube material is 316 stainless steel,
while the plant heat rate is 10,350 Btu/kWh. These
assumptions increase the base case reheat energy require-
ment from 66.8 x 106 Btu/hr to 95.9 x 106 Btu/hr and
the annual revenue requirement from $1.52 x 106 to $2.20
x 106 (or a 45 percent increase in base case ARR). The
new capital requirement is about $2.12 x 10s.
19
-------
SECTION 3
CONCLUSIONS
THE NEED FOR STACK GAS REHEAT
Since the impact of each of the problems that may be caused by wet flue
gases (125-140°F) is affected differently by a given level of reheat, the
need for reheat must be considered with respect to each separate problem.
Based on the results of the analyses conducted for each problem, the follow-
ing were concluded:
(1) Stack gas reheat (SGR) is an effective method for reducing
corrosion that may occur downstream of a wet FGD process
(duct work, fan, stack). However, forced draft fans (rela-
tive to the scrubber) and lined stacks and ducts can also
be used for corrosion protection caused by wet stack gases.
(2) SGR can reduce the potential for acid rainout in the vicinity
of the stack by elimination of moisture downstream of the
scrubber and reduction of the condensed water vapor concentra-
tion in the plume. However, the mechanisms that result in
acid rainout are not well enough understood to quantify the
acid rainout that will occur at various atmospheric conditions
and consequently, the expected reduction resulting from the
use of reheat. Other alternatives for reducing the potential
for acid rain are high efficiency mist eliminators, well-
insulated ducts and stacks, and low velocity stacks.
(3) SGR should not be used to eliminate a visible plume except
under circumstances where air or ground transportation is
significantly affected. There is no other alternative
available for eliminating visible plumes.
(4) SGR is a viable approach for reducing ground-level pollutant
concentrations. Other alternatives, such as taller stacks
(for NO and SOa) and increased scrubber efficiency (for
removal), are also effective.
20
-------
SGR should not be considered a necessary part of a wet scrubbing system since
there are other alternatives available for minimizing the problems associated
with wet stack gases (except for elimination of a visible plume which is, in
most cases, considered uneconomical).
SURVEY OF CURRENT PRACTICE
A survey of reheat users, FGD process vendors, and architect/engineering
(A/E) companies has shown that:
(1) Reheat users cite equipment protection as the main
reason for reheat. Enhancement of plume buoyancy
is the reason specified most often after equipment
protection.
(2) Reheat users specify a 30°F (or greater) degree of
reheat for adequate protection of equipment against
corrosion.
(3) Reheat users specify inline reheat most often compared
to other configurations with economics being cited as
the reason.
(4) Reheat has been selected and is being planned for new
power plant installations more often than wet stacks.
(5) The majority of A/E contractors and FGD process vendors
surveyed do not recommend SGR as a necessary part of a
wet FGD system. If SGR is requested by the customer,
then indirect hot air injection reheat is the preferred
configuration of the majority of the A/E firms and FGD
process vendors surveyed because of reliability.
EVALUATION AND COMPARISON OF REHEAT CONFIGURATIONS
Technical and economic evaluations were performed for five reheat
configurations (inline, indirect hot air injection, exit gas recirculation,
direct combustion, and FGD system bypass) as applied to the scrubbed flue
gas from a power plant. The conclusions developed from these evaluations
are:
21
-------
(1) Energy requirements to achieve a specified stack gas
exit temperature (level of reheat)
—Bypass reheat requires the least energy since waste
heat (heat that would be lost during flue gas cool-
ing and saturation of the flue gas in the scrubber)
is used to reheat the stack gases. However, environ-
mental regulations for SOa emissions control have
limited this application.
—Direct combustion, inline, and exit gas recirculation
reheat have similar energy requirements.
—Indirect hot air reheat has the highest energy
requirement since both the injected air and flue
gas must be heated to the stack exit temperature.
(2) Reliability
—The operating reliability of bypass reheat should be
the best; however, operation of this reheat scheme
will be restricted by S02 emission standards.
—Indirect hot air injection reheat reliability will
also be good since the reheat exchanger does not
come in contact with wet, corrosive flue gas.
—Inline reheat exchangers contact wet, saturated
flue gas. Site specific factors (primarily coai
sulfur and chloride content) may require expensive
alloys (stainless steel, Inconel 625, etc.) to pro-
vide long exchanger life.
—Exit gas recirculation (EGR) reheat should exhibit
better reliability than inline reheat but is commer-
cially unproven.
—Direct combustion reheat is very reliable; however,
availability and cost of fuels may limit its appli-
cation.
(3) Capital and operating costs of reheat systems are highly
dependent on
—Degree of reheat (*F)
—Mist carryover from the scrubber
—Heat losses from the duct work and stack
22
-------
—Position of draft equipment relative to the scrubber
—Power plant heat rate
—Coal sulfur and chloride content
—Type of reheat system
—Type, quality, and cost of reheat media
—Reheat exchanger tube material and life
(4) Economics were developed for reheat systems (applied to a 500-MW
power plant) which raise the stack exit temperature 50°F above
the scrubber exit temperature.
—Inline reheat is generally less costly (annual revenue require-
ment) than indirect hot air reheat due to lower energy require-
ments. However, since reliability will be a major consideration
in selecting reheat systems, the better reliability of indirect
hot air reheat may make this system competitive for some users.
—Exit gas recirculation reheat is economically attractive compared
to the other reheat systems but has not been proven commercially.
—Direct combustion reheat economics (compared to inline, EGR, and
indirect hot air) depend heavily on delivered fuel price. Due
to fuels availability and cost escalation considerations, this
form of reheat is not expected to be used to a significant degree
in new boiler-FGD applications.
—Economics for bypass reheat were not developed because S02 emis-
sion regulations (June 11, 1979 Federal Register) for new coal-
fired power plants will not permit a 50°F reheat level to be
obtained.* However, bypass remains the most economical form of
SGR available. For low sulfur coals, bypass reheat plus a
supplemental reheater (inline, indirect hot air, EGR, or direct
combustion) may be the most economical reheat configuration.
—Capital and operating costs are relatively small compared to the
cost of the scrubber and power plant. Capital investment for
the various systems are less than 1 and 5 percent of the capital
investment for the complete power plant and scrubber, respec-
tively. Annualized costs are less than 3 and 15 percent of the
annualized costs for the complete power plant and scrubber,
respectively.
*Unless a supplemental reheater is used.
23
-------
SECTION 4
RECOMMENDATIONS
Based on the results of this study, the following are recommended!
(1) Future development of the exit gas recirculation reheat
configuration should be considered, since it appears to
be economically competitive with other reheat configura-
tions and to have certain reliability advantages.
(2) A study of the mechanisms resulting in the occurrence
of acid rainout in the vicinity of the plant should be
undertaken. A series of investigations at demonstration
facilities are recommended to:
—Study the mechanism of acid rainout occurrence as a
function of climatic conditions, mist eliminator
performance, stack velocity, and stack height.
—Study the impact of different levels of reheat on the
quantity of acid rainout as a function of climatic
conditions. The results of this study should be com-
pared with the impacts expected from other alternative
measures for the prevention of acid rainout.
(3) At a commercial power plant facility, a program should be
initiated to determine the quantity of reheat required to
protect downstream equipment. The theoretical energy
required to prevent the occurrence of downstream conden-
sation is the energy needed to keep the temperature of the
flue gas above its dew point. However, industrial users
usually specify higher levels (at least 30°F) of reheat
to protect equipment; this indicates that other factors
such as liquid droplet size, physical and chemical char-
acteristics, and residence time (in the equipment down-
stream of the mist eliminator) should be considered in
such an analysis.
24
-------
SECTION 5
SURVEY OF CURRENT PRACTICE
As a part of this study, the state-of-the-art of stack gas reheat was
investigated. Information was obtained from publications, electric utili-
ties, architect/engineering (A/E) companies, and FGD system vendors using
the following techniques.
(1) A review of existing FGD literature sources
(2) Circulation of a reheat questionnaire, approved by the Office
of Management and Budget (OMB#158-578001), to 11 A/E firms,
7 FGD process vendors, and 46 electric utility companies.
About 60 percent of the questionnaires distributed were
returned. A copy of the questionnaire and a list of
recipients are presented in Appendix B.
(3) Telephone calls to clarify the information obtained in
the questionnaire
(4) Visits to three utility stations using various reheat
configurations:
-Kansas City Power and Light Company - La Cygne Station
-Kansas Power and Light Company - Lawrence Energy Center
-Public Service Company of Colorado - Cherokee Power Plant
LITERATURE REVIEW
The current state-of-the-art of stack gas reheat was reviewed as the
initial phase of this study. The results of this review are presented and
used throughout the report. As an introduction to the presentation of
results of the OMB-approved questionnaire, a brief discussion is presented
concerning reasons for using reheat, viable reheat configurations, and
available forms (reheat media) of energy for reheat.
25
-------
Reasons for Reheating Stack Gases
Stack gases from utility boilers without flue gas desulfurization (FGD)
are normally exhausted at a temperature of 250 to 300°F. In this temperature
range, the flue gas is relatively dry and noncorrosive. The wet FGD processes
currently being used commercially in the United States cool the boiler flue
gas from about 300°F to its adiabatic saturation temperature, normally 125-
140°F. This saturated flue gas may cause the following problems:
(1) The corrosion of equipment downstream of the scrubber due
to the presence of moisture, acid, and chlorides
(2) The occurrence of acid rainout in the vicinity of the
plant stack
(3) The formation of a visible plume which may be hazardous
to ground and air traffic in the vicinity of the power
plant
(4) High ground-level pollutant concentrations downwind
from the stack due to poor plume buoyancy
Reheating the saturated flue gas to a temperature above its saturation
temperature will lessen the impacts of each of these four potential problems
As the above discussion indicated, the need for reheating a scrubbed
flue gas is dependent on the temperature and water content of the flue gas.
These characteristics are, in turn, functions of the type of FGD process
used. There are presently some 100 processes that have been conceived for
the control of sulfur dioxide in flue gases. Of these processes, there are
five that are in commercial use today in the United States. In addition,
there are six that are currently at the demonstration level of development.
Table 7 presents a brief characterization of these 11 FGD processes. These
processes can be categorized as being dry or wet depending on the temperature
and water vapor content of the treated gas.
26
-------
TABLE 7. FGD PROCESS CHARACTERIZATION
N>
Process
l.lne/l.lmestoue
Double Alkali
Wcllman-Lord
Magnesium Oxide
Sodium Scrubbing
Spray Drying
Cltrale/Pliospliate
Uergbau-Porsctiung/
Foster Wheeler
Atowlc.s International/
Aqueous Carbonate
Process (Spray Dryer)
Shell /mil"
Clilyoda 121
Development Process
Status Type
Commercialized Wet
Commercialized Uet
Commercialized Uut
Commercialized Uet
Conme rclal Ized Wet
110 full tu'ale data
available at this
time
6O-MW demonstra- Wet
tlon underway
20-MW demonstra- Ory
tration completed
1.2-HU deuonstra- l>ry
tration completed;
100-MU demount ra-
tion planned
0.6-KH demons tr a- Dry
tlon completed;
40- MW application
in Japan
20- HU deuonstra- Uet
tion completed
Approximate Flue Gas
Temperature <°K)
Kntering Exiting Amount of
(•'CD Process fC,tl Process Water Added
300 125-140 Saturates flue gas
300 125-140 Saturates flue gas
300 125-140 Saturates flue gas
300 125-140 Saturates flue gas
300 125-140 Saturates flue gas
does not saturate
300 125-140 Saturates flue gas
100 2 70- 3 30 None
300 140+ Adilti some water but
does not saturated
700-750 700-750 None
tliO 125-140 Saturates flue gas
-------
A wet FGD process saturates the flue gas with water vapor while cooling
the gas to its adiabatic saturation temperature (normally in the range of
125-140°F). Dry processes do not saturate the flue gas with water vapor.
Spray dryers (one type of dry system) cool the flue gas by adding water,
although the gas temperature is maintained at least 10-15°F above the adia-
batic saturation temperature. Some dry processes (such as Bergbau-Forschung)
do not cool the flue gas. Flue gas exits these processes at temperatures
greater than 250°F.
It is likely that reheat will not be used in conjunction with most dry
FGD processes but may be required for wet scrubbing processes. Only wet pro-
cesses were considered for reheat applications in this study. However, the
techniques used to determine the need for and cost of stack gas reheat are
applicable to dry FGD systems as well.
Reheat Configurations
Although reheating a saturated flue gas can be achieved by several
methods, currently all methods heat the flue gas and raise its temperature
before it enters the stack. Raising the flue gas temperature can eliminate
or reduce the impact of the problems that may be caused by a wet saturated
flue gas. The quantity of reheat needed is dependent on the specific problem
which is to be resolved, the reheat method used, and other factors which are
site-specific. Some of these factors are:
(1) The quantity of entrained mist downstream of the scrubber
(2) The quantity of heat lost from the system through the
walls of the flue gas duct and plant stack
(3) The position of the flue gas fan relative to the scrubber
The theoretical levels of reheat required to eliminate each of the potential
problems associated with saturated flue gases are discussed in Section 6.
28
-------
Several methods have been developed to reheat flue gases. Descriptions
of those reheat methods that have been most extensively developed are pre-
sented below.
Inline Reheat—
In this reheat scheme, an exchanger is placed directly in the duct work
to heat the scrubbed flue gas. The heating medium can be either saturated
or superheated steam or hot water. The advantages with this configuration
are its simplicity of design and low energy consumption. However, this
configuration typically exhibits poor operating reliability since the
exchanger is exposed to highly corrosive wet flue gas. A schematic of this
configuration is presented in Figure 2a,
Indirect Hot Air Injection Reheat—
Ambient air is heated in an exchanger with steam or hot water and is
then mixed with flue gas in order to raise the flue gas temperature. This
reheat configuration exhibits better operating reliability than the inline
method because the exchanger is not contacted by the corrosive flue gas.
This method not only heats the flue gas but also dilutes it with ambient air.
The dilution effect caused by the addition of air lowers the dew point of
the scrubbed gas and lowers the pollutant concentrations exiting the stack.
A drawback to the configuration is that more energy is required compared to
inline reheat because heat is required to raise the temperature of both the
flue gas and injected air to the desired stack temperature. A simplified
schematic of indirect hot air reheat is presented in, Figure 2b.
Direct Combustion Reheat—
Direct combustion reheat mixes hot exhaust gases generated by firing
fuel oil or natural gas with the flue gas in order to raise its temperature.
Like indirect hot air reheat, this configuration exhibits good operating
reliability. However, increasing fuel oil and natural gas costs and avail-
ability for power plant use are likely to limit the use of direct combustion
29
-------
Scrubber
Flue Gw
To Stack
Reheat Exchanger
Stem or
Hot Water
(a) Inline Reheat
Scrubber
Flue Cw
Aoblrat Air
sta
To Stack
Air H»«ttr
(b) Indirect Hot Air Reheat
flat Gaa
Fuel Oil/N,
~ I 1
vr1"! Conbuation
latural Ga« 7\_j Chadxr
> To Stack
'Air
(c) Direct Combustion Reheat
Scrubber
Flue CM
To Stack
Stea« / Exchanger
(d) Exit Gas Recirculation Reheat
To Stack
Scrubber
(e) Bypass Reheat
Flue Gaa
Flue Gaa
Heater
Jo Stack
Reclrculatlag
Fluid
(f) Waste Heat Recovery Reheat
Note: Fans and pumps not shown for simplicity.
Figure 2. Simplified schematics of various reheat configurations.
30
-------
reheat. Emission standards will also limit the use of reheat fuels
containing sulfur. A schematic of this configuration is presented in
Figure 2c.
Exit Gas Recirculation Reheat—
In this reheat configuration, a portion of the flue gas that has been
scrubbed and reheated is routed to an exchanger where it is heated further.
This heated flue gas is then mixed with saturated flue gas. This configura-
tion seems to possess the best qualities of both the inline and the indirect
hot air reheat configurations. Like the inline system, the energy supplied
goes directly into heating the flue gas since the flue gas mass flow rate
exiting the stack is not increased. Like indirect hot air reheating, the
exchanger does not directly contact wet, saturated flue gas and this system
should therefore exhibit good reliability. However, this configuration has
not been commercially proven. A schematic of exit gas recirculation reheat
is presented in Figure 2d.
Bypass Reheat—
In a bypass reheat system, a portion of the boiler flue gas is routed
around the scrubber and mixed with the scrubbed flue gas. The initial
investment and operating costs associated with this configuration are low
compared to other reheat schemes. However, future use of this method is
restricted by SOa emission standards. A simplified schematic of this reheat
method is presented in Figure 2e.
Waste Heat Recovery (From Stack Gases With Temperature <300°F)—
This reheat method involves heating the scrubbed flue gas directly or
indirectly (with a heating medium) with unscrubbed flue gas. There are
several possible configurations for this type of reheat:
(1) Bypass reheat
(2) Ljungstrom heat exchangers (gas-gas heat exchanger)
(3) Recirculating heating media (two gas-liquid heat exchangers)
31
-------
Bypass reheat has been discussed earlier. The liquid-gas (Figure 2f) and
gas-gas exchangers (Ljungstrom) have not been proven in commercial applica-
tions for stack gas reheat. The extremely corrosive conditions encountered
when flue gas is cooled below the sulfuric acid dew point make the use of
exchangers for waste heat recovery questionable on the basis of reliability
Results of ongoing commercial tests in Japan should be obtained and examined
before pursuing the use of the Ljungstrom type exchanger for reheat applica-
tions.
Reheat Energy Media
In a power plant, there are many potential energy sources available as
reheat media. Presented in Table 8 is a summary of the important reheat
configurations and a listing of reheat media that could be used in each.
In this report, extraction steam from a turbine for inline, indirect hot
air, and exit gas recirculation, and fuel oil or natural gas for direct com-
bustion will receive primary emphasis.
SURVEY RESULTS
Questionnaires were sent to FGD system users, vendors, and designers
to determine how many of the reheat configurations identified in the litera-
ture survey have been used in commercial applications. For those configura-
tions that had been used commercially, the purpose of the survey was to learn
the design philosophy and operating history of each application. This infor-
mation was then used to evaluate the feasibility, reliability and cost of
each reheat configuration. The results obtained from the survey are dis-
cussed as follows:
(1) Architect/engineering companies and FGD process vendor
responses
(2) Electric utility responses which include:
32
-------
TABLE 8. REHEAT CONFIGURATIONS AND POTENTIAL ENERGY SOURCES
Comments
Inline and Exit Gas Recirculation
Throttle Steam
Extraction Steam
Hot Water
Flue Gas (before air preheater)
In heat exchanger
In heat exchanger
In heat exchanger
In heat exchanger
Indirect Hot Air
Throttle Steam
Extraction Steam
Hot Water
Heated Air From Air Preheater
In heat exchanger
In heat exchanger
In heat exchanger
No exchanger needed
Direct Combustion
Natural Gas
Low Sulfur Fuel Oil
Waste Heat Recovery
Bypass*
Ljungstrom (gas-gas)
Recirculating Liquid
Energy supplied from flue
gas (temperature <300°F)
*Either flue gas entering or exiting air preheater. Flue gas withdrawn for
scrubber bypass prior to entering the air preheater would contain some
recoverable energy. Therefore, it would not be considered as totally
using waste heat.
33
-------
—General information
—Inline reheat users
—Indirect hot air reheat users
—Direct combustion reheat users
—Bypass reheat users
—Wet stack users
These questionnaires were returned to Radian during the time period January
1978 - July, 1978.
Architect/Engineering Company - FGD Process Vendor Responses
Of the 18 questionnaires distributed to A/E firms and FGD process
vendors, 12 responses were returned. Ten companies indicated that they do
not recommend reheat as a necessary part of a wet scrubbing system. Two
companies always recommend reheat.
Table 9 presents the preferred reheat configurations (if reheat is
specified by the client) of the A/E firms and vendors. Indirect hot air
reheat is recommended most often because of its better reliability compared
to an inline system. Bypass reheat is the most economical form, not only
because it requires no additional energy source, but also because the
scrubber size is smaller. However, many A/E firms felt that the proposed
(promulgated in the June 11, 1979 Federal Register) S02 standards would
severely restrict using bypass reheat. Some therefore did not specify it
as a choice. (This information was gathered before the final utility boiler
NSPS were promulgated in June 1979. The final standards do allow partial
scrubbing of low sulfur coals).
Most firms did not recommend inline reheat because of reliability con-
cerns. These include corrosion and plugging due to mist and solids carry-
over. Direct combustion reheat has been used mainly for retrofit and test
facilities where space was critical. Fuel oil or gas availability, while
not a major problem for utilities currently using direct combustion, may be
34
-------
TABLE 9. FGD PROCESS VENDOR- AND A/E-PREFERRED REHEAT SYSTEMS3
Configuration Number of Recommendations
Inline 3
Indirect (Hot Air) 10
Direct Combustion 1
Bypass 7
Exit Gas Recirculation 0
Waste Heat Recovery 0
3Although 12 A/E companies and FGD process vendors responded, some firms
recommended more than one form of reheat.
Other pertinent information contained in the A/E-vendor questionnaire
responses is listed below:
1) Temperature drop from reheater exit to stack exit: ^50F
2) Typical stack velocities: 40-90 ft/sec
3) Typical duct velocities: 50-70 ft/sec
4) Indirect hot air reheat systems should be designed with
carbon steel or copper tubes with fins.
5) Inline reheat systems should be composed of bare tube
exchangers. Recommended metals included carbon steel,
stainless steels, and nickel alloys. Soot blowing is
a recommended maintenance procedure.
6) Mist loadings downstream of the mist eliminators will
probably be lower for clear liquor scrubbers compared
to processes with slurry streams.
7) Steam was generally recommended over hot water as the
reheat medium for inline and indirect hot air systems.
35
-------
an important consideration for new facilities. Also, over the life of the
plant, the fuel cost may become prohibitively expensive. Government poli-
cies, such as the "Powerplant and Industrial Fuel Use Act of 1978" may also
have an important influence on the use of direct combustion reheat.
Electric Utility Responses
In this section, general information relating to overall industry
practice is discussed. Details of individual company experience regarding
each of the currently used reheat methods are also presented.
Table 10 lists the currently used or proposed stack treatment methods
(wet stack, inline reheat, indirect hot air, etc.) for 103 scrubbing facili_
ties. The selection of an SOa removal system and/or reheat system for 49
facilities is currently undecided. Information for this table was obtained
via the survey and personal communications. Additional information was
obtained from the FGD literature.
The total number of reheat configurations and their tentative startup
dates are presented in Table 11. The table indicates a movement from reheat-
ing with energy sources other than the flue gas (inline, indirect hot air
and direct combustion) to bypass reheating and wet stacks. At the time thes
data were collected, it was unknown whether the final New Source Performance
Standards (issued in June 11, 1979 Federal Register) would allow partial
scrubbing and, therefore, bypass reheat.
At the time the survey and literature review were conducted for this
report, no utility was using or planning a waste heat recovery system or
an exit gas recirculation system. Note that the inline reheat system is
selected more often than any other wet flue gas treatment method. This con-
trasts with the A/E and FGD process vendor recommendation. The simplicity
economics, and success of some inline reheat systems evidently makes the
inline system a better choice for many utilities than the more reliable, but
more expensive, indirect hot air reheat method.
36
-------
TABLE 10. ELECTRIC UTILITY UNITS AND SPECIFIED TYPE
OF REHEAT
Company
Alabama Electric Co-op.
Allegheny Power Syetem
Arizona El«c. Power Co-op.
Arizona Public Service
Basin Else. Power Co-op.
Big Rivera Clec. Co-op.
Board of Municipal Utilities
Brazo* Elec. Power Corp.
Central IllinoU Light Co.
Central Illlnoi* Public Serv.
Central Maine Power Co.
Cincinnati G«s and Elec.
Colorado Ute Elec. Ate.
Coluobua end S. Ohio Elec.
Coononvealth Ed t ion
Deloarva Power Co.
Detroit Ediion Co.
Duquesne Light
Eaat Kentucky Power Co-op.
General Public Utilitle*
Gulf Power Co.
Hooaier Co-op.
Indianapolle Power 4 Light
Kanaaa City Power & Light
Plant
Tombigbee #2
#3
Pleaaanta #1
#2
Apache #2
Cholla #1
#2
#4
Four Comer a #1
#2
#3
#4
«
Antelope Valley #1
Laraole River #1
#2
#3
Reid #2
#3
Sikeston Power Station
San Miguel *1
Duck Creek #1
#2
Newton #1
Sean laland *1
Eaat Bend t2
Craig Jl
Coneiville #5
#6
Poaton tS
*6
Powerton *5
Will County #1
Deltware City #1,2,3
St. Clalr
Elrana
Phlllipa
SpurlocVt *2
Coho #1
Seward *7
Criat »4.#5
Criat #6. #7
Lansing Smith #1,12
Heron #1
#2
Petersburg #3
*4
Hawthorn #3
La Cygne Jl
Start-up
6-78
6-79
3-79
3-80
6-78
4-79
10-73
6-78
6-80
Unknown
Unknown
Unknown
Unknown
Unknown
1981
1983
4-80
10-80
6-83
12-79
12-80
11-80
12-79
8-78
1-82
11-79
11-86
1-81
3-79
3-79
1-77
10-78
1981
1983
12-79
2-72
4-30
5-76
10-75
7-73
3-80
5-87
5-84
1978
1980
1980
1980
1981
10-77
4-82
11-72
8-72
2-73
Reheat Syaten
Bypaee
Bypass
Bypass
Bypass
Wet Stack
Wet Stack
Inline
Inline
Inline
Undecided
Undecided
Undecided
Undecided
Undecided
Undecided
Undecided
Wet Stack
Wet Stack
Vet Stack
Indirect
Indirect
Wet Stack
Wet Stack
Wet Stack
Wet Stack
Bypaas , Inline
Undecided
Undecided
Inline
Inline
Wet Stack
"unoetlded
Undecided
Inline
Inline
Direct
Direct
Wet Stack
Wet Stack
Undecided
Undecided
Undecided
Undecided
Undecided
Undecided
Undecided
Undecided
Undecided
Undecided
Inline
Inline
Inline
(continued)
37
-------
TABLE 10 (continued).
Jcapany
Xinsal Powar and Light:
•:«:uckv cciliciat
Lakaland Bciliciaa
Louiavilla Caa and Slac.
Minnesota ?owar and Light
Minnkoca ?o««r CO-OD.
>!bncana ?cwar Co.
;:avada ?ow«r
Maw England Slac. Sya
:Uaj»r« Mohawk ?ov*r Co-op.
Ilorcaara Indiana Public
Sarvica
:iorihara Scacai ?o««r Co.
Oscar tail ?owar Co
'acieic Gaa and Slaccric
'ictfic ?ovar and Lijh:
?annaylvania ?owar Co.
P^.f.idalpftia ilac. Co.
Plane
Jafiarv »l
«
Lawranca »4
•<5
Sraan .livtr "1.2,3
Me In co »h M
Cana Run A
i*5
•W
Kill Craik »L
»:
#3
*4
Paddy '< Run l
l>2
43
#4
Raid Cardnar
:.iliaa
Zalina
l^diracc
".'ndacidad
Strict
Znliaa
Sir ace
Inlica
Iniz.na
InllM
Inlina
Dtracc
3ypa>a
Uac Scack
Bypass
Inlina
Inlina
Islina
Inlina
'.'niaoiiai
Cj'ndaci^ad
'Jndacidad
- ndac idad
Indiracc
"r.dirac;
Ir.diracc
.'ncacidid
-'ndaci&ad
Jndacidad
"ndacidad
Jndacidad
O'ndacidad
L'r.dacidad
wac Scack
(Diracc availabla)
Inlina
Ir.iina
u'auvciud
Vndaciiad
Dry Scrubb«r
I'ndac idad
Jndacidad
Vac 5:ack
'Vac Scack
Since
Dirac:
Sirae:
Vr.iiciiai
Oiracc
Siric:
3irac -
'.'ndaciiad
(ceneieuae)
38
-------
TABLE 10 (continued).
COR? any
Pocooac ZUc. and ?owtr
?ow«r Authority or" "«w York
Public S«rvict-Coiorado
Public $«rvict-N«w Mtxico
Public Service- Indiana
Sale Riv«r Project
Souch Carolina Public S«rvic*
Souchtrn Illinois Pov«r CO-JD
Souchara Indiana Ga« and £l«c.
S- Miaaisiippi £L«c.
SsrtngfUld Cicy 'Jclliciai
Sarinjfiald '.factr .lijhc & ?ow«r
T«nn*jt«* v«^l«*r Auchoricy
t«x«.* :*ic.i-ii.?»i Public A^«rxy
7«xa* ?sw«r ind liahc
T«xu UciLici*s C3.
L'nictd Power AKOC.
"rail Povar ind I-i?h=
Virjini* Sljctrie and ?3t«r Co.
'7isconsir. ?cw«r and «ghc
Plane
Dictcarson '.'1
Arthur Kill
Arapaho >'4
Charokaa ^1
Valoons *5
San Juan 41
«
"tbion «5
Coronada 'H
+2
Wiayih »2
;i»rion <>4
AS Ironn VI
5.. 9 Moron *l
Sou:hw«ic <>l
Oallman ^3
vtdovi Crack 47
CUboni Cr««'n ^1
Sandov 44
Twin OaRi "I
#2
Fortie Grov* ^l
JUrttn Uk« ->1
«O
^neicillo #3
Caal Cr«%k *1
Kuoc'iateon ^l
MS. Seara
Ccluabia ''-
"oc«: "••'«^ scack i«r.ot«» ch« *=i»iioa of a s«suric«d flu<
Sources: ?«rson*l ^a3r.unic4cion
Qu*s:ionn*ir« rcspont*
^afiraneas I ?hrou;ri :
•rftta itilivr .
Star-.-.f
1979
197?
5-35
9-3:
9-73
0-73
11-72
7-74
H-71
11-77
11-77
1-79
5-31
1982
4-75
4-80
1937
7-77
1930
6-78
4-79
2-73
3-78
4-77
7-30
i-72
-'n known
5-77
3-78
7-30
S-33
9-34
1980
10-77
12-78
11-32
2-78
11-78
11-79
1-79
3-73
6-30
'Jzknourv
1-30
l j»j visa r.o
?..h.i: Sy«:.-.
'.'r.dtcilad
'Jndacidid
:"r.cir»c:
I^dtrvcc
'.'ndacidad
Vndacidad
3y?ass
BvpaJi
•.-.id*cid^ ;unt. :rs.
39
-------
TABLE 11. STARTUP DATES FOR VARIOUS REHEAT SYSTEMS
Startup
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
Total for
1968-1977
Total for
1978-1983
Total for
All Years
Indirect
Inline Hot Air
1
2
4
4
3
1 1
2 1
3 4
3 2
4 1
3 2
2
1
17 9
13 5
30 14
Direct
Combustion Bypass Wet Stack
2 1
1 2
1 1
3
1 3 3
7 4
1 84
3 7 3
1
1
8 3 7
4 22 13
12 25 ^
40
-------
Table 12 was developed from information provided by electric utilities
that responded to the questionnaire and from the literature survey. It
shows that the operating plants which use reheat typically use more than
30°F as a reheat temperature criterion. In general, the overriding reason
given by most utilities for using reheat was for equipment protection
against corrosion. Enhanced plume rise was the second most numerous reason
given for using reheat.
TABLE 12. REHEAT TEMPERATURE LEVELS AT OPERATING AND PLANNED UNITS*
Operating Planned
AT (°F) Units Units
<20°F 1 3
20-40°F 1 4
40-60°F 8 1
60-100eF 1 2
>100°F 2 0
*This is the reheat level (stack exit temperature minus scrubber
exit temperature) for reheat systems for which this information
is known.
Sources of energy for reheat include steam, hot water, natural gas,
fuel oil, and bypassed flue gas. The information obtained from the utility
industry survey indicated the following breakdown of energy sources:
(1) Inline reheat
—80 percent use steam
—20 percent use hot water
(2) Indirect hot air injection reheat - all use steam
3) Direct combustion reheat
—35 percent use natural gas
—65 percent use fuel oil
(4) Bypass reheat - uses heat in unscrubbed flue gas
41
-------
No survey responses indicated any serious energy availability problems. Some
retrofit units had to use throttle steam because extraction steam from the
turbine was not available in sufficient quantities to provide the desired
reheat level. Table 13 presents the number of responses relating to reheat
media. Different units at the same plant were counted separately in deter-
mining these values.
TABLE 13. REHEAT ENERGY SOURCES
Energy Source
Steam
Hot Water
Gas
Fuel Oil
Inline
Reheat
14
4
-
-
Indirect
Hot Air
Reheat
9
-
-
-
Direct
Combustion
Reheat
-
-
4
7
In the following sections electric utility experience, as determined
from the survey for each type of reheat system, is summarized. Additionally
the use of wet stacks is discussed. The system descriptions do not incor-
porate experience since early 1978.
Inline Reheat—
Parameters affecting performance—Inline reheat is perhaps the simplest
reheat configuration. Basically, hot elements (tubes or plates) are placed
in the scrubbed gas stream. Forced convection heating from the hot surface
to the flue gas occurs. Steam or hot water can be used as the heating
medium.
In most cases the problems encountered by inline reheaters are caused
by direct contact with the wet flue gas. Several factors can influence
these problems. These include mist eliminator performance, flue gas chloride
level, SOz and SO3 concentrations, and the particulate loading. Additional
factors which affect the reliability of the system include tube metallurgy
and the reheat medium.
42
-------
The major problem encountered is corrosion of the exchanger tubes.
Corrosion may be caused by several mechanisms. One of the most common is
acid attack. Data from several plants have shown that installations using
high sulfur coals have experienced greater acid problems. The La Cygne and
Lawrence power plants illustrate this trend. La Cygne burns a local coal
with 5.3 percent sulfur and has experienced severe acid corrosion problems.
Lawrence Unit #5 burns a 0.5 percent sulfur coal and has had very few corro-
sion problems in the last five years with its carbon steel tubes.
Coals generally contain chlorides which form hydrochloric acid follow-
ing combustion. This acid is easily scrubbed out and, being a soluble
species, the chloride ion remains in the scrubbing liquor. In closed-loop
scrubbing systems, concentrations can reach several thousand ppm. If the
mist eliminator does not remove the entrained slurry droplets, they will
impinge on the hot surface of the reheater tubes. Here evaporation and
chloride concentration occurs. The chloride ion acts on the metal surface
causing stress corrosion and eventual failure. Systems with low chloride
coal or that operate open-loop generally do not have stress corrosion
problems.
Inline reheaters have experienced erosion and plugging of the reheater
tubes. Fly ash is very abrasive on the reheater surfaces. Plugging occurs
from slurry carry-over and subsequent deposition. In some cases, the depos-
ited fly ash and unreacted alkali can remove SC-2 from the flue gas. Plug-
ging is intensified by sulfite oxidation resulting in gypsum scale formation.
In installations where plugging has occurred, various methods have allevi-
ated the problem. Wider tube spacing, along with square (in-line) rather
than triangular-pitched (staggered) tubes reduce plugging. Some reheat
users have also replaced finned tubes with bare tubes in order to avoid
these problems. Soot blowers are also used at most installations; the
frequency of blowing ranges up to three times a shift.
43
-------
Based on the survey responses, the two predominate materials specified
for inline reheat exchangers are carbon steel and stainless steel type 316
(316SS). At the present time, there is not sufficient information to corre-
late material with tube service life. The variables discussed previously
such as coal composition, exchanger dimensions, and maintenance procedures
appear to have a major impact on tube life. Utility usage of more corrosion
resistant metals is increasing. However, there are not enough results from
inline reheat users to quantitatively determine the economic value of these
generally higher-priced alloys.
The reheat medium used also influences the reliability of an inline
reheater. Superheated steam, saturated steam, and hot water can all be used
in an inline reheater. In extreme cases, the drop in degrees of steam super-
heat can be 300-4008F and can occur over a short portion of tubing. To avoid
problems, braces are installed across the tube bundle which permit longitu-
dinal expansion but eliminate lateral vibrations. Saturated steam will not
have a temperature drop because only a phase change occurs. Hot water is
also a readily available heating medium in a utility plant. Most installa-
tions using hot water circulate it from the deaerator. Three installations
using hot water have experienced excellent tube life. However, long tube
life and low corrosion may be more dependent on burning low sulfur and low
chloride content coal than using hot water. Both stations (Lawrence and
Sherburne) using hot water burn 1.0 percent or less sulfur coal.
The startup and shutdown procedures for an inline reheater are influ-
enced by several factors, the most important being the prevention of conden-
sation on and corrosion of the reheater tubes. This is usually accomplished
by introducing steam to the reheater before it is contacted with the wet
flue gas and keeping steam in the exchanger after the scrubber is shut down.
Inline installations—The use of inline reheat at eight facilities is
discussed below. Table 14 presents information gathered for each system.
44
-------
TABLE 14. INLINE REHEAT SYSTEMS
Company
Unit
Arizona Public Service
Cholla Unit #1
Commonwealth Edison
Will County Unit *1
Reason for Reheat
Reason for Inline
Boiler Size (MW)
Coal
Type
Sulfur (percent)
Heating Value (Btu/lb)
Scrubbing System
Start-up Date
Scrubbed Flue Gas
Flow (acfm)
Temperature (°F)
SOz Concentration (ppm)
Heating Medium
Type
Pressure (psig)
Temperature (°F)
Flow Rate (Ib/hr)
Heat Exchanger
Tube Size
Tube Length
Tubes per Bundle
Bundles per Module
Tube Material
Tube Life
Soot Blowers
Ductwork
Corrosion
Stack
Corrosion
Reheat <1T (°F)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Rainout
Fog
Comments
Source or Reference
Equipment protection
None given
115
New Mexico
0.5
10,200
Limestone (Research Cottrell)
October, 1973
490,000
120
100
Steam
250
400
20,000
1" OD
2
316LSS
Steam, 3/bundle, every 8 hrs
Carbon Steel/Ceilcote
Yea
40
Upstream
Vibrations have caused tube
failure in the past. Baffles
were installed which alleviated
the problem.
P,1,2,1.2
Equipment protection
Economics
156
Western
0.5
9,000
Limestone (BiW)
February, 1972
707,000
128
500
Throttle steam
350
485
60,000
5/8" OD, .065" wall
11.5 feet
32
27
316LSS and Carbon steel
12-15 months
Every 4 hours
Steel w/brick liner
None observed
60-80
Downstream
Xo
No
No
Acid corrosion prompted
use of 316LSS on lower
tubes in banks. Pinhole
corrosion usually occurs.
Tubes kept hot during
outages for longer life.
P.Q.1,2,12
No information available
1 _ personal communication
Q - Questionnaire response
45
-------
TABLE 14 (continued).
Company
Unit
Northern States Power Co.
Sherburne County Unit 'ti
Public Service Co. of Colorado
Cherokee Unit #1
Reason for Reheat
Reason for Inline
Boiler Size (MW)
Coal
Type
Sulfur (percent)
Heating Value (Btu/lb)
Scrubbing System
Start-up Date
Scrubbed Flue Gas
Flow (acfm)
502 Concentration (ppm)
Heating Medium
Type
Pressure (psig)
Temperature (°F)
Flow Rate (Ib/hr)
Heat Exchanger
Tube Size
Tubes per Bundle
Bundles per Module
Tube Material
Tube Life
Soot Blowers
Ductwork
Corrosion
Stack
Corrosion
Reheat iT (*F)
Fan Position (relative to
scrubber)
Atmospheric Effects
.Hist
Acid Rainouc
Fog
Comments
Source or Reference
Equipment pro tec don
Original design
710
Montana
0.8
3300
Limestone (CE)
3-76
2,240,000
130
150-250
Hot water
60
350 in - 230 out
2300 (gpm-circulated)
1 3/4" 00 Finned
45
4
Carbon steel
3 steam blowers, once a shift
Carbon steel
No
Corten/liner
No
40
Downstream
No
No
No
No noticeable condensation or
serious corrosion occurring.
Slight plugging occasionally.
P.Q.12
Equipment protection, plume
buoyancy
Original-design
120
Colorado
0.5
9500
Particulate - TCA (UOP)
6-73
402,000
100
425
Steam
300
420
18,000
5/8" OD
3
316SS
Mot used
Carbon steel
Yes, when no reheat
Concrete
Yes, when no reheat
50
Upstream
Yes, only on cold days with
high humidity
No
No
Originally had finned tubes
which plugged and corroded.
Bare tubes stay clean, do noc
require soot blowing.
P.1,11
—No information available
P - Personal communication
Q - Questionnaire response
46
-------
TABLE 14 (continued).
Company
Unit
Reason for Reheat
Reason for Inline
Boiler Size (MW)
Coal
Type
Sulfur (percent)
Heating Value (Btu/lb)
Scrubbing System
Start-up Date
Scrubbed Flue Gas
Flow (acfm)
Temperature (°F)
SOj Concentration (ppm)
Heating Medium
Type
Pressure (psig)
Temperature (T)
Flow Rate (Ib/hr)
Heat Exchanger
Tube Size
Tube Length
Tubes per Bundle
Bundles per Module
Tube Material
Tube Life
Soot Blowers
Ductwork
Corrosion
Stack
Kansas City Fower and Light
Hawthorne Unit »3
Equipment protection
Original design
100
Oklahoma
3.0
12,000
Lime (CE)
11-72
306.000
122
100-600
Steam
1" OD Finned
1
Carbon steel
>5 years
Steam
—
—
Kansas City Power and
taOgne Unit -H
Equipment protection,
rise
Original design
820
Kansas
5.3
9,300
Limestone (B 4 W)
2-73
2,460,000
122
1,200
Extraction steam
150
650
60,000
Light
plume
5/8" OD, .12" wall*
30'
24
16 (32 in two modules)
Desensitized 316LSS
3 - 3-1/2 years
Steam, 4 per module, once
per 8 hour shift
Carbon steel/Plascite
Occurs if gas is wet -
recoat every 2 years
Carbon steel/Plascite
4005-5
Corrosion
Reheat AT <*F)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Rainout
Fog
Comments
Source or Reference
50
Downstream
No
No
So
Plugging has been a greater
problem than corrosion.
Modules are shutdown every
three days for overall cleaning.
15 1 •> 1 T
* ,-'•»->•*••'-
25 (50 in 3 of 3 modules)
Downstream
Yes, has been occasionally
experienced
Yes, car paint damage
noticed
Yes, infrequent
High SO2 and ash levels
have caused 304SS, CS,
316SS tubes to fail. Care-
ful cleaning and elimina-
tion of mechanical vibra-
tion was key to recent
success. Reheat 50°F in
all modules is desired;
however, piping limited
at present.
"Module *8 has 1"OD tubes x 30'x.12" wall - 8 bundles due to scrubber configuration.
—Ho information available
P - Personal communication
47
-------
TABLE 14 (continued).
Company
Unit
Kansas Power and Light
Lawrence Unit #5
Montana Power Co.
Colstrip Unit !»1
Reason for Reheat
Reason for Inline
Boiler Size (MW)
Coal
Type
Sulfur (percent)
Heating Value (Btu/lb)
Scrubbing System
Scrubbed Flue Gas
Flow (acfm)
Temperature (*F)
SOz Concentration (ppm)
Heating Medium
Type
Pressure (psig)
Temperature (°7)
Flow Rate (Ib/hr)
Heat Exchanger
Tube Size
Tubes per Bundle
Bundles per Module
Tube Material
Tube Life
Soot Blowers
Ductwork.
Corrosion
Stack
Corrosion
R«h«at AT (°F)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Rainouc
Fog
Comments
Source or Reference
Equipment protection
Original design
400
S.E. Wyoming
0.5
10,000
Limestone (CE)
636,000
120
100-500
Hot water
200
250 in - 180 out
1 3/4" 00, 3/4" Fins
64
4
Carbon steel
6-10 years
250 psig air - twice per shift
Sceel/gunnite
30
Downstream
No
So
No
Low SO:> SOs, chloride and
ash levels important to long
tube life.
Equipment protection
Economics 4 performance
360
Montana - sub-bituminous
0.8 (avg.)
8,550
Lime, fly ash (ADL-CEA)
Steam
150
360
Not applicable
11 panels per bank
2 sections, 6 banks each
Top-Inconel 625, Bottom-
Hastelloy G (one in each
of three modules)
4 per module
No
No
50
Downstream
No corrosion of plate coil.
Plugging occurred once after
a temperature excursion and
subsequent mise eliminator
failure.
P.12
48
-------
Cholla Unit #1—Arizona Public Service: This unit has experienced
corrosion caused by condensation and subsequent dilute sulfurous acid forma-
tion. This resulted from the design which allowed condensate to collect in
stagnant pockets. The Corten expansion joints were most affected. Insula-
tion of the ducts and replacement of the Corten with rubber liners helped
stop the corrosion.
Tube vibrations occurred due to the constriction of the gas flow in
the reheater. Baffles were installed which eliminated this problem. Some
stress corrosion due to chloride attack has been noticed on the stainless
steel tubes.
Will County Unit #1—Commonwealth Edison: Corrosion of the lower tube
banks occurred and prompted the use of 316SS for the lower tube bundles of
the reheater. The tubes are kept hot even when the scrubber is off line to
prevent acid attack. A high reheat temperature is used to prevent damage to
the induced draft fan. The fan is washed and inspected during each outage.
Reheater tube failure has caused a shutdown three times in the past two years.
The tube bundles are either patched, blanked off, or replaced during the out-
ages.
Hawthorne Units #3 and #4—Kansas City Power and Light: The Hawthorne
Units 3 and 4 originally used hot water as the reheat medium. During an out-
age in 1977, the system was modified to use steam. This produced higher re-
heat temperatures and better plume buoyancy. Erosion and plugging of the
finned carbon steel tubes has been a greater problem than corrosion. As the
old tubes fail after eight years of service, they are being replaced by 316SS
tubes. These tubes are on a square pitch (inline) rather than triangular
(staggered). The utility feels this arrangement will alleviate some plugging
problems.
49
-------
La Cygne Unit #1—Kansas City Power and Light: Inline reheat problems
at LaCygne are probably as severe as any utility location. The local coal
is high in sulfur and ash. The scrubber is used for both particulate and
SOz control; consequently, the entrained slurry is both abrasive and corro-
sive. Approximately 50-60 ppm of SOs has been detected downstream of the
scrubber. The original 304SS tubes failed within six months of startup.
Replacement carbon steel tubes lasted nine months. Desensitized 316SS
tubes were then used and lasted 12-15 months.
After the 316SS tubes failed, ducts from the air preheater were
installed to deliver hot air to the scrubbed flue gas. About 15-17 percent
of the heated air was mixed with the flue gas. This method limited the
boiler output and was discontinued. The ducts were not removed, and at
present, about two percent of the preheated air mixes with the scrubbed gas.
Presently, thick wall tubes of desensitized 316SS are in use. They have
been in operation three to three and one-half years. Braces on each bundle
prevent harmonic vibrations. The tubes are washed as soon as a module is
taken out of service to remove deposits. Soot blowers are used once a shift
The utility feels that continued improvement in mist eliminator performance
and preventive maintenance will extend tube life considerably.
Three of the eight modules can reheat 50°F. The other five reheat
25°F. The downstream I.D. fans contribute 15-20°F of reheat to the gas.
Even at these reheat temperature ranges, mist, acid rainout, and fog have
occasionally been experienced. The stack has a carbon steel liner coated
with plasite. This coating is reapplied every two years. There is not a
stress corrosion problem because the chloride level in the coal is rather
low.
Lawrence Unit #5—Kansas Power and Light: Unit #5 uses a venturi-
absorber system for both particulate and SOa control. A low sulfur, low
50
-------
ash Wyoming coal is burned and inline finned carbon steel tubes are used
for reheat to protect the I.D. fan and stack. Hot water (250°F) from the
deaerator is used for heating. The original tubes had copper fins which
flattened under the soot blower pressure. Plugging was also a problem.
Redesign of the mist eliminator helped reduce the plugging significantly.
Carbon steel fins were installed and have operated satisfactorily for more
than six years. Soot blowers, using compressed air, are operated twice a
shift. After 18 months of service, the tubes on Unit #5 have not required
any service. The utility feels that low sulfur, chloride and ash levels
in their coal are responsible for the long tube life. This utility would.
probably use inline finned tubes on a new unit burning the same type coal.
Colstrip Unit #1—Montana Power Company: The Colstrip units are unique
in that they are the first units to use plate coils for reheat rather than
tube bundles. Reheat is used to protect the induced draft fan and stack.
Each module has two reheat sections and each section has six banks. Each
bank is composed of 11 plate coil panels. The bottom section is made of
Hastelloy C and the top section is Inconel 625.
There are four soot blowers per module and the pressure drop across
the reheaters is 2 to 3 inches of water. To date, there have been no
serious plugging problems and no corrosion has occurred.
Sherburne County Unit #1—Northern States Power Company: The inline
finned tubes at Sherburne County use hot water to protect the I.D. fan and
stack and to improve plume dispersion. Hot water is circulated from the
deaerator. Soot blowers are used once a shift. No other special mainte-
nance is employed for the reheater. Some corrosion has occurred, although
it has not been very serious. The boiler burns a low sulfur Western coal.
Cherokee Unit #1—Public Service of Colorado: The Cherokee units use
three-stage turbulent contact absorbers for particulate removal. The origi-
nal reheater consisted of one bare and two finned banks of carbon steel
51
-------
tubes. After two years of continual plugging, they were replaced with 316SS
bare tubes. These tubes stay clean and do not require soot blowing. They
are inspected during every outage and have not shown any problems.
During periods when reheat was not used, corrosion in the ducts and
stack occurred. Mist has been observed during cold weather at high humid-
ity; however, most of this mist is generated by nearby cooling towers.
Indirect Hot Air Injection Reheat—-
Parameters affecting performance—Indirect reheat involves heating air
with steam and mixing the heated air with the wet flue gas. It differs from
inline reheat in that the heat exchanger surface does not contact the wet
flue gas. Consequently, this system exhibits a better reliability than the
inline configuration because corrosion and plugging are less likely. A
greater volume of gas must be handled through the ducts and stack with
indirect reheat due to the air injected. This may have an adverse effect
on an existing primary fan in retrofit situations. Also, when reheating
to the same stack temperature, indirect reheat requires significantly more
energy than inline reheat. This extra energy is required to heat the added
air from ambient conditions to the stack temperature. In general, the capi-
tal and operating costs of indirect systems are higher than inline but have
been justified by some utilities because of longer exchanger life and better
reliability.
Mixing of the hot air with the flue gas must be successfully accom-
plished to prevent hot spots on the duct walls. This can be done with in-
jection nozzles, or merging ducts. It is also important to protect the
duct walls from overheating during startup and shutdown. This can be done
by bringing the scrubber on stream before the air heater and shutting down,
the air heater before the scrubber. A small air flow across the tubes is
advised until the corrosive saturated flue gas is purged from the ductwork
during outages. The majority of the reheaters use carbon steel tubes. Some
52
-------
corrosion has occurred due to flue gas in-leakage; however, with proper
design and operating practice it appears that stainless steels and other
alloys are not required.
Indirect hot air installations—Of the 13 planned and operating indirect
systems, five were selected for discussion. They are Reid Gardner Unit #1—
Nevada Power Company, Cherokee Unit #4—Public Service Company of Colorado,
Widow's Creek Unit #8—Tennessee Valley Authority, Green River—Kentucky Util-
ities, and Huntington Unit //I—Utah Power and Light. Table 15 presents
summary information for four of these installations.
Reid Gardner Unit #1—Nevada Power Company: All three Reid Gardner
scrubbers use sodium carbonate scrubbing and indirect hot air reheat. Car-
bon steel finned tubes are used to heat air to approximately 490°F which is
then mixed with the scrubbed gas. In four years of service, no significant
problems have occurred. The reheater is placed in service after the scrub-
ber is online. It is removed from service before the scrubber is shut down.
This avoids any thermal damage to the duct lining.
Cherokee Unit #4—Public Service Company of Colorado: Experiences with
inline reheat at Cherokee Units #1 and #3 and the Valmont and Arapaho sta-
tions prompted the use of indirect reheating at Cherokee Unit #4. The util-
ity has found that the indirect system requires more maintenance than the
inline system. This is due to the forced draft fan configuration (primary
fan) which occasionally forces flue gas into the hot air ducts. The original
carbon steel finned tubes have corroded due to this flue gas infiltration.
New finned tubes will be made of stainless steel. The air flow rate is
between 40 and 50 percent of the flue gas rate. It was found that indirect
hot air reheat requires more steam than inline reheat to get the same outlet
stack temperature. In another installation the utility has indicated that
if reheat were selected, inline reheat would be used rather than indirect
hot air because of the high maintenance and operating costs (related to
steam use) they have now experienced with indirect systems.
53
-------
TABLE 15. INDIRECT HOT AIR REHEAT SYSTEMS
Company
Unit
Nevada Power Company
Reid Gardner Unit il
Public Service Company of
Colorado - Cherokee L'nit ?
Reason for Raheat
Reason for Indirect
Boiler Size (MW)
Coal
Type
Sulfur (percent)
Heating Value (Btu/lb)
Scrubbing System
Start-up 3ate
Scrubbed Flue Gas
Flow (acfm)
Temperature (°F)
SOz Concentration (ppm)
Heating Medium
Type
Pressure (psig)
Temperature CF)
Flow Sate (Ib/hr)
Air
Flow (scfm)
Outlet Temperature (°F)
Heat Exchanger
Tube Size
Tube Length
Tubes per Bundle
Bundles per Module
Tuba Material
Corrosion
Ductwork
Corrosion
Stack
Corrosion
Raheat dT (°F)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Rainout
Fog
Comments
Source or Reference
Equipment protection
Better reliability
125
0.5
12,500
Sodium carbonate (ADL/CEA)
4-74
448,000
119
50
Steam
450
760
30,000
67,000
490
5/8" OD Finned, .049" wall
10'
65
6
Carbon steel
None
Carbon steel/liner
Concrete/Brick liner
25-35
Upstream
No
No
No
No problems after 4 years of
operation
P,Q,1,18,19
Equipment protection
Problems with inline reheat
on Units 1 and 3
370
Colorado
0.5
9.500
Particulate - TCA (UOP)
7-74
1,210,000
100
425
Steam
600
486
50,000
196,000
440
5/8" OD Finned
Carbon steel
Some due to badonixing
Carbon steel
yes
Concrete
yes
40-50
Upstream
Yes, when no reheat
No
So
More maintenance required the^n
for inline reheat
P.1,11
—No information available
P - Personal communication
Q - Questionnaire response
-------
TABLE 15 (continued).
Company
Unit
Tennessee Valley Authority
Widow's Creek Unit #8
Utah Power and Light
Huntington Unit tfl
Reason for Reheat
Reason for Indirect
Boiler Size (MW)
Coal
Type
Sulfur (percent)
Heating Value (Btu/lb)
Scrubbing System
Start-up Date
Scrubbed Flue Gas
Flow (acfm)
Temperature (*F)
SOz Concentration (ppm)
Heating Medium
Type
Pressure (psig)
Temperature (°F)
Flow Rate (Ib/hr)
Air
Flow (scfm)
Outlet Temperature (°F)
Heat Exchanger
Tube Size
Tubes per Bundle
Bundles per Module
Tube Material
Corrosion
Ductwork
Corrosion
Stack
Corrosion
Reheat AT (T)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Ralnout
Fog
Comments
Source or Reference
Equipment protection, plume
dispersion
At time of installation most
reliable type of reheat
550
Mix (AL.TN.KY)
2.3
10,920
Limestone (TVA)
5-77
1,400,000
125
200-500
Extraction steam
500
650
160,000
120,000
400
5/8" OD, 8 Fins/inch
40
2
Carbon steel/copper fins
none
Equipment protection, plume
rise
Reliability
400
Bituminous - Utah
0.55
12,000-12,500
Lire (spray cower)
5-71
119
300-400
Extraction steam
275
600
300
Finned
Carbon steel
Corten Carbon steel/precrete liner
Reinforced concrete/brick liner Acid brick
50 20
Upstream
No
No
No
TVA will use inline on Widow's
Creek #7 because capital cost
is less and most operating
problems have been reduced.
P.Q.2
Upstream
No
No
No
In operation only about 3 mo.
Used bypass reheat most of
the t ime.
—No information available
P - Personal communication
Q - Questionnaire response
55
-------
Widow's Creek Unit #8—Tennessee Valley Authority: The terrain and
local meteorological conditions around the plant eliminate the possibility
of using a wet stack. Reheat is used to enhance plume dispersion which is
necessary for acceptable ground-level pollutant concentrations. TVA selected
indirect hot air reheat because of problems they experienced with the inline
configuration. However, in Widow's Creek Unit //7, TVA will try inline reheat
because it is felt that the earlier problems have been minimized by a better
mist eliminator design and improved maintenance procedures. TVA has
observed that the capital and operating costs for the indirect hot air sys-
tems are higher than those for an inline reheater. No operating problems
have occurred with the indirect system at Widow's Creek.
Green River—Kentucky Utilities: The Green River scrubber was started
up in September 1975 with a wet stack. In February, 1977 the Carboline
lining in the stack was replaced due to failure. Substantial damage to the
paint on parked cars was also encountered at this facility. In an attempt
to eliminate these problems, Kentucky Utilities decided to install an in-
direct hot air system to raise the flue gas temperature 50°F. The Carbo-
line lining was removed and replaced with Precrete over a wire mesh.
Direct Combustion Reheat—
Factors affecting performance—Direct combustion of oil or gas is one
of the simplest forms of reheat. Combustion can occur either in an internal
or external chamber with a refractory lining. Startup must be accomplished
slowly to prevent damage to the refractory lining. Since fuel oil combus-
tion in an internal chamber can produce flame instability and incomplete
combustion, most oil burning sites use external combustion chambers. A
small fan for combustion air is also required. Gas systems have greater
flame stability and may be used directly in the flue gas stream as oxygen
in the flue gas is available to support combustion.
56
-------
A definite advantage of direct combustion reheat is its limited space
requirements. Compared to the tube bundles and duct work of the other sys-
tems, its size is more conducive to retrofit installations. Also, the
capital investment for the burners and refractory materials is small com-
pared with other systems. Since low sulfur fuel is required for this reheat
process in order to satisfy SOj emission regulations, the availability and
cost of such a fuel may limit the use of this configuration. The impact of
government legislation, such as the "Powerplant and Industrial Fuel Use Act
of 1978" may also affect the applications of direct combustion for reheat,
although no user response indicated availability problems at the time these
responses were returned.
The "Powerplant and Industrial Fuel Use Act of 1978" prohibits the use
of oil and gas as primary fuel in new power plants unless specific exemp-
tions are granted. While there is no specific prohibition of the use of
these fuels as a stack gas reheat energy source, the use of steam and hot
water generated from the firing of coal will probably be encouraged by regu-
latory agencies.
Direct combustion installations—Four systems which use direct combus-
tion reheat are discussed below. Three of the facilities use oil and one
uses natural gas. Table 16 presents summary information on these four units.
Other direct combustion reheat units are also mentioned.
Cane Run Unit #4—Louisville Gas and Electric: This boiler has been
retrofitted with an FGD system. Direct combustion reheat was selected be-
cause it was the easiest to retrofit and a fuel oil tank was available at
the plant. Operation has been good; however, some trouble has been experi-
enced with an uneven temperature profile resulting in overheated ducts.
The temperature of the combustion gases is about 900eF prior to mixing with
the flue gas.
57
-------
TABLE 16. DIRECT COMBUSTION REHEAT SYSTEMS
Company
Unit
Louisville Gas and Electric
Cane Run Unic #4
Louisville Gas and Electric
Run fnic 116
Reason for Reheat
Reason Cor Direct
Boiler Size (MW)
Coal
Type
Sulfur (percent)
Heating value (Bcu/lb)
Scrubbing System
Start-up Date
Scrubbed Flue Gas
Flow (acfm)
Temperature (*F)
SOz Concentration (ppra)
Fuel and Combustion
Combustion Chamber
Fuel Type
Fuel Rate
Ductwork
Corrosion
Stack
Corrosion
Reheat AT (*F)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Rainout
Fog
Conmencs
Source or Reference
Equipment protection
Easiest to retrofit
178
Peabody
3.5
10,800
Lime (AAF)
8-76
735,000
125
200
02 fuel oil
72 (gph)
Steel/Plascice 4005
None
Concrete/Precrete
35-40
Upstream
No
No
No
Duct walls have overheated
at times
P.Q.2
Equipment protection
Easiest to retrofit
65
Peabody
3.7
10,800
Lime (CE)
4-73
250,000
L26
150
Internal
Gas
20,000 (scfh)
Mild steel
Concrete/Precrete
45-55
Downstream
No
No
No
Excellent service for
over 44 years
Q,1,2,12.19
—No in formation available
P - Personal communication
Q * Questionnaire response
58
-------
TABLE 16 (continued),
Company
Unit
Philadelphia Electric
Eddys cone LA
Tennessee Valley Authority
Shawnee
Reason for Reheac
Reason for Direcc
Boiler Size (MW)
Coal
Type
Sulfur (percent)
Heating value (Btu/lb)
Scrubbing System
Start-up Date
Scrubbed Flue Gas
Flow (acfm)
Temperature (*F)
SOz Concentration (ppm)
Fuel and Combustion
Combustion Chamber
Fuel Type
Fuel Rate
Ductwork
Corrosion
Stack
Corrosion
Reheat AT (*F)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Rainout
Fog
Comments
Source or Reference
Equipment protection
High AT required
310
West Virginia-Pennsylvania
2.5
12,100
Mig-Ox (United Engr.)
7-75
268,000
127
50
External
Oil
Carbon steel/liner
125
Upstream
Some refractory cracking has
occurred due to temperature
sensor malfunctions.
P.2,12
Equipment protection
Easiest for Cest system
150
Kentucky-Illinois
3 - 5
12,000
3-10MW*
4-72
20,400 -(3)
125
250
External
n Fuel Oil
J7 (gph)
Refractory Lining
316SS
Pitting observed
125
Downstream
Internal chamber was removed
due to flame instability. No
corrosion problems experienced.
Refractory must be heated slow-
ly to prevent damage.
1,2,12
--No information available
P - Personal communication
*The Shawnee Facility has 3 demonstration FGD systems, each of which can treat about 10 MW
equivalent of flue gas.
59
-------
Paddy's Run Unit #6—Louisville Gas and Electric: Paddy's Run Unit #6
uses natural gas in an inline combustion chamber for induced draft fan and
stack protection. No problems have occurred in five years of usage. Gas
is used because of its availability, while the system was selected based on
the ease of retrofitting. Reheat availability has been nearly 100 percent
over the operating period.
Eddystone Unit #1A—Philadelphia Electric: The Eddystone Station is
on the flight path of Philadelphia International Airport. As a result, the
scrubbed flue gas is reheated more than 125°F to avoid the occurrence of a
visible plume. The original refractory burner lining failed due to high
temperatures in startup. A new refractory and a slower heat-up period have
proved satisfactory.
Shawnee—Tennessee Valley Authority: The Shawnee Plant has three
small scrubbers on a larger unit. They each treat about 10 MW equivalent
of flue gas. Being a small test system, direct combustion was chosen be-
cause it was the easiest way to protect downstream equipment. Fuel oil
(No. 2) is fired in an external chamber and the resulting combustion products
are mixed with the scrubbed flue gas. The chamber is heated at 50°F/hour
during startup to prevent refractory damage. Some pitting has been ob-
served in the FGD system stack.
Other direct combustion systems: The Delaware City Unit #1 of
Delmarva Power Company will be firing syngas available from local industries
at its Wellman-Lord scrubber for equipment protection and plume buoyancy.
The St. Clair demonstration unit of Detroit Edison uses direct oil firing.
Half of the gas from Unit #6 is scrubbed and reheated to its prescrubbed
temperature. This avoids thermal shock in the stack when it is mixed with
the unscrubbed gas. Bruce Mansfield Units #1 and #2 of Pennsylvania Power
Company have had some flame stability problems due to flue gas infiltration
into the external combustion chamber. Vibration has also caused some damage
to the refractory.
60
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Bypass Reheat—
Parameters affecting performance—Bypass reheat is the most economical
form of reheat. It requires only duct work and control dampers. Addition-
ally, both capital and operating cost savings are realized because a smaller
scrubbing system can be used with this configuration. However, proposed
legislation* may limit the amount of gas which can be bypassed. If 70-90
percent S02 removal is required for all coals (regardless of sulfur content),
then the use of bypass reheat will be restricted.
Under the old NSPS of 1.2 lb S02/106 Btu, a number of utilities con-
tracted to burn low sulfur coal. Partial scrubbing is sufficient to meet
the emission standard. The remaining gas is bypassed. Reheat and its
associated benefits are obtained whether desired or not. Of the 65 wet
scrubbing facilities due for startup from 1977 to 1980, 25 are planning to
use bypass reheat. Only two of the installations (Allegheny Power) will be
burning medium-high (2-4 percent) sulfur coal. Allegheny Power System, at
its two Pleasants Station units, expects a 5-8°F temperature rise due to a
5 percent bypass. The remaining bypass installations are using low sulfur
coal and bypassing 20 percent or more of the flue gas.
Bypass installations—Survey information on the Coronado Units of the
Salt River Project and the R. D. Morrow unit of the South Mississippi Elec-
tric Power Association are presented below. Table 17 summarizes data for
these two units. Other bypass systems are also discussed briefly.
Coronado Unit #1—Salt River Project: The Salt River Project Company
was a participant in testing of the Mohave-Southern California Edison pilot
scrubbers. These two pilot scrubbers used inline and indirect hot air
reheat, respectively. Construction of the new scrubber for Coronado Unit
#1 is based on low sulfur coal with partial flue gas bypass providing
reheat. The percentage of flue gas bypassed will vary. The scrubber will
*When these questionnaires were returned by reheat users, the new SOa NSPS
for electric utility boilers (issued on June 11, 1979) had not been
promulgated.
61
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TABLE 17. BYPASS REHEAT SYSTEMS
Company
Unit
Salt River Project
Coronado Unit IH
South Mississippi Electric
RD Morrow Unit 41
Reason for Reheat
Reason for Bypass
Boiler Size (MW)
Coal
Type
Sulfur (percent)
Heating Value (Beu/lb)
Scrubbing System
Start-up Date
Scrubbed Flue Gas
Flow (acfm)
Temperature (°F)
SO2 Concentration (ppn)
Flue Gas Bypassed
Percent Total Flow
Flow (acfm)
Temperature (°T)
50j Concentration (ppm)
Flue Gas to Stack.
Flow (acfm)
Temperature (°F)
SOj Concentration (ppm)
Ductwork
Corrosion
Stack
Corrosion
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Raiaout
Fog
Comments
Not all gas needs scrubbing to
meet 502 emission requirements
350
Western
1.0 (max.)
Limestone (Pullman-Kellogg)
April, 1979
990,000
117
155
>20
449,000
254
850
1,440,000
155
315
Carbon steel/Precrate
Concrete/FRP* liner
Upstream
Percent bypass will maintain
maximum of 0.8 Ib SOs/lO* Btu
emission.
Not all gas needs scrubbing to
meet S02 emission requirements
180
1.0
Limestone (Riley-Stoker)
August, 1978
350,000
126
S38
408,000
290
738,000
187
Carbon steel/glass flake
Carbon steel/acid brick
Scrubber treats all gas up to
62X of full load gas flow.
The rest is bypassed. At loot
capacity, emissions are 1.2 ib
S02/10« Btu.
Source or Reference
P.Q.2
?,Q,2
~^o information available
P - Personal communication
Q - Questionnaire response
*FRP - fiberglass reinforced plastic
62
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treat the amount of flue gas required to keep an emission rate of 0.8 Ib
SOa/106 Btu, and the reheat level will vary accordingly.
R. D. Morrow Unit #1—South Mississippi Electric Power Association:
Bypass reheat is used because all of the gas does not require scrubbing
to meet the NSPS. The first 62 percent of the gas will be scrubbed. At
higher capacities, the extra gas will be bypassed. The stack is designed
for wet or dry conditions. At full load, the sulfur dioxide emission rate
is 1.2 Ib S02/106 Btu.
Other bypass units: Other units burning low sulfur coal bypass about
15-40 percent of the flue gas. This gives an equivalent 25-60°F of reheat.
As stated earlier, only the Allegheny Power System Pleasants units are burn-
ing medium-high sulfur coal. The utility has performed some pilot tests
which indicate that 5-8°F of reheat is necessary to prevent condensation in
the ducts and stack. Since startup has not occurred, this value has not
been proven.
The Newton Station Unit #1 of Central Illinois Public Service will
utilize bypass reheat on one module and inline reheat on the other. They
are doing this to gain firsthand experience with reheat systems.
Wet Stacks-
Parameters affecting performance—As evidenced by the vendor and A/E
recommendations, many do not believe reheat is necessary. They cite the
extra cost of building and operating the reheat system and the operating
and maintenance problems. An alternative to stack gas reheat is no reheat
(operation with a wet stack). However, condensation then occurs in the
ducts and stacks, mist and acid rain may occur in the near vicinity, the
plume may droop with potential high ground-level pollutant concentrations,
and duct and stack corrosion can occur.
Generally, corrosion following condensation is the primary adverse
result of wet flue gas. The use of forced draft primary fans reduces the
63
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negative impact of the corrosion problems. The duct walls can be insulated
and lined to control condensation/corrosion. New stack linings such as fib
glass reinforced plastics, Ceilcote, Precrete, and Epoxy may limit stack
corrosion. However, these linings have not been tested long enough to deter-
mine their useful life. Low flue gas velocities can be incorporated in the
stack design to minimize entrainment of condensed water vapor. This sh uld
help reduce the potential for acid rain in the vicinity of the stack.
Wet stack installations—In general, wet stacks are used because of
economics and the problems associated with reheat systems. The five unit
described in Table 18 are discussed below. Other wet stacks of inter
are also discussed briefly.
Duck Creek Unit #1—Central Illinois Light Company: This utility
selected a wet stack for Duck Creek based on economics. At present, it has
not been run wet because all four scrubbing modules have not been completed.
The utility is burning low sulfur coal without operating the scrubber until
all the modules are completed. High temperatures in the stack have caused
the Ceilcote to flake off in some spots. A wet stack is planned for Duck
Creek Unit #2 also.
Conesville Unit #5—Columbus and South Ohio Electric Company: The
wet stack was selected over reheat because of economics. Problems with
the scrubber have resulted in complete bypass operation at times. The hot
bypassed gas blistered the original Ceilcote-lined stack. An acid brick
stack lining has since been installed. No corrosion has been noticed over
the few months it has been used with a wet gas.
Phillips—Duquesne Light Company: The Phillips and Elrama Stations
were designed for wet stacks with acid brick lining. Direct combustion
reheaters were included to help dissipate the plume in winter. However,
these were seldom used due to operating problems and the high cost of fuel.
64
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TABLE 18. WET STACK SYSTEMS
Company
Unit
Central Illinois Light Company
Duck Creek Unit i'l
Columbus i South Ohio Electric
Company - ConiisvLlle Unit
SO: Concentration (ppm)
Ductwork
Corrosion
Scack
Corrosion
Diameter (ID-fe)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Rainout
Fog
Comments
Most economical
400
Ohio
4.5 - 4.9
10,700
Lime (UOP)
February, 1977
1,050,000
130
34
Cortetx/Saureisen Coating
Carbon steel/Ceilcote flakeline 151 Concrete/acid brick
See comments
19 26
Most economical
400
Illinois
2.5 - 4.0
10,500
Limestone (Riley-Stoker)
September, 1976
1,200,000
127
Source or Reference
Upstream
No
No
No
One of four modules completed in
1976. The other three were sched-
uled for completion in September,
1978. Therefore 75% bypass was
occurring at the time thase data
were gathered. Hot gas has occa-
sionally blistered stack lining.
P.Q.2
Upstream
No
No
No
Originally had ceilcote lined
stack. Without scrubber, hot
gas blistered lining. Acid
brick lining was adiied and has
been satisfactory.
P.Q.2
—No information available
P - Personal communication
Q - Questionnaire response
65
-------
TABLE 18 (continued).
Company
Unit
Duquesne Light Company
Phillips
Pacific Pover i Light Company
Dave Johnston
Reason for no Reheat
Boiler Size
Coal
Type
Sulfur - (percent)
Heating Value (Btu/lb)
Scrubbing System
Starc-up Date
Scrubbed Flue Gas
Flow (acfm)
Tenperature (*F)
SOs Concentration (ppo)
Ductwork
Corrosion
Stack
Corrosion
diameter (ID.fC)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Rainout
Fog
Comments
Source or Reference
Original design, reheat is used
only for plume dispersion in
vinter.
410
1.8 - 2.2
11,350
Lime (Chemico)
July, 1973
1,900,000
120
Carbon steel/ceilcote
Carbon steel/acid brick
26
Between venturi and absorber
No
No
Mo
Originally had oil-fired reheaters
at Phillips and Elrana. Neither
were used extensively and have
both been removed' Some seep-
age through norcar in stack lining
has occurred. Stack annulus is
to be pressurized as a solution.
P.Q.2
At time of design, no reheat
systems were reliable or con-
sidered necessary.
330
Sub-bituminous
0.5
7,800
Particular removal only
L972
1,543,000
125
Carbon steel/flake lining
Yes
Downstream - wet
Yes
No
Mo
Have had prob lens in Che past
with the wet fan. Stack is
beginning to show severe cor-
rosion problems after 8 years
of operation.
P.Q.ll
—No information available
P - Personal communication
Q - Questionnaire response
66
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TABLE 18 (continued).
Company
Unit
Springfield City Utilities
Southwest Unit fi
Reason for no Reheat
Boiler Size (MW)
Coal
Type
Sulfur - (percent)
Heating value (Btu/lb)
Scrubbing System
Start-up Date
Scrubbed Flue Gas
Flow (acfm)
Temperature (*T)
SOj Concentration (ppra)
Ductwork
Corrosion
Stack
Corrosion
Diameter (ID,ft)
Fan Position (relative to
scrubber)
Atmospheric Effects
Mist
Acid Rainout
Fog
Comments
Source or Reference
Reheat systems not reliable. Stack
velocity and height are adequate for
dispersion.
200
Bituminous
3.5
11,000
Limestone (UOP)
May, 1977
500,000
125
500
Mild steel/flake lining
Concrete/acid brick
No
12.9
Upstream
Occasionally
No
No
Stack bottom is continuously
drained.
P.Q.2
—No information available
P - Personal communication
Q - Questionnaire response
67
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These reheaters have since been removed. Some acidic seepage through the
brick mortar in the stack has occurred, corroding the carbon steel support
bands. An acid-resistant mortar was installed which stopped the seepage.
Dave Johnston—Pacific Power and Light: The Dave Johnston Plant is one
of the oldest with a wet stack. In operation since 1972, the carbon steel,
flake-lined stack is beginning to show severe corrosion problems. A wet fan
is also used and is washed continually. It has experienced operating problem^
in the past including scale build-up. The scrubber is currently used for
particulate removal only.
Southwest Unit tfl—Springfield City Utilities (Missouri) : Springfield
City Utilities selected a wet stack because they felt reheat systems are not
reliable. Stack configuration produces the velocity and height needed for
adequate dispersion. Occasionally mist carry-over is observed when both
scrubber modules are operated. No corrosion has been observed in the stack
after one year of operation.
Other wet stacks: The Wellman-Lord scrubber at D. H. Mitchell Unit #11,
Northern Indiana Public Service, has a natural gas reheater which has never
been used. The stack is lined with fiberglass reinforced plastic (FRP).
Mist carry-over has been noticed occasionally.
SURVEY SUMMARY AND CONCLUSIONS
Based on the information collected during the survey conducted for this
study, the following results and conclusions were obtained:
(1) Although the need for and use of reheat is site specific,
utilities generally use reheat to protect equipment against
condensation and subsequent corrosion. Plume buoyancy
enhancement is often given as a secondary reason for reheat.
(2) The degree of reheat used by industry varies from OaF (no
reheat) to more than 100°F; however, a range of about 40-60°F
is typically used by operating plants.
68
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(3) The majority of the responding A/E's and vendors do not
recommend the use of reheat systems. When reheat is
requested by a customer, these companies generally
recommend the indirect hot air reheat configuration
because of greater reliability.
(4) Although operating problems are greater with inline
than other reheat configurations, many utility com-
panies prefer to use inline reheat because of lower
capital and operating costs.
(5) Bypassing of unscrubbed flue gas is quite economical
and is used frequently. However, future utilization
may be limited by SOa emission standards.
(6) Direct combustion reheat has exhibited good reliability
and the best characteristics for retrofit applications.
Future utilization is difficult to assess due to both
economic constraints (fuel availability and price) and
governmental regulations.
(7) No problems have been encountered or identified by
utilities and/or vendors with regard to reheater tube
material availability.
Table 19 presents a comparison of the advantages and disadvantages of
the various reheat configurations for new and retrofit installations. Much
of this information is based on the responses to the OMB-approved survey.
Additionally, planned and existing utilization is presented for each reheat
configuration.
69
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TABLE 19. REHEAT CONFIGURATION OPERATING CHARACTERISTICS
Current coanercial
u*age (percentage
of total)*
Percentage of total
reheat/no rebeat
systena to be used
by 19o3"
advantages of
con f iteration
Disadvantages of
configuration
Inline
39
10
(1) Slsvle dealgn.
(2) Mo increase In
ntaas flow rate of
the flue gas.
(3) Less energy than
other syste«s
except bypass and
ECK for a net
degree of reheat .
(1) Corrosion and
plugging coamanly
occur.
(2) Difficult to
retrofit.
Indirect Hot air
20
14
(1) Ho corrosion
or plugging of
exchanger
experienced.
(2> More reliable
than. Inline.
(1) Mass flow
rat* of
flue gas
inc rened .
(2) External
energy
required in
drive auxil-
wbcn needed.
O) Severely
limited for
retrofit
applications.
Reheat Configuration
Direct Coubustion Bypass
18 7
U 25
(1) Single design (1) Host economical
and operation. for* of reheat.
(2) No corrosion (2) Staple design.
or plugging (3) No external
experienced. energy required.
(3) Relatively low
capital cost.
(4) Eu lest to
retrofit.
(1) Cost highly (1) Us« Is restric-
sensUive to ted by SO2 eajis-
fuel cost. sion standards.
Also, low aul- <2) May be difficult
fur fuels to retrofit.
(natural gas
and Ho. 2 fuel
ity and/ or coat
use.
(2) Flaw stability
and tncoasilete
conbvstlMi have
been experienced
when fuel nil
uis need.
(3) Not coatee t ion
gasea can deawg*
duct work if
•ixing with flue
Exit Gas
(^circulation (BCR) Waste Beat Recovery
Not proven on coaster- Not proven on coa»er-
cial scale ctal scale
0 0
(1) Leas corrosion (1) Hat.ie In-at
than inline refovi/rvd sn
likely because that no external
flue gas heated energy required.
before contacting
reheater.
(I) Not proven on (1) Not proven on
coMscrcial scale. coaswrcial scale.
(2) External energy (2) Front end ex-
equlred In order changer will
o drive Auxiliary experience severe
an. corrosion prob-
0) ttoct. trt,«jpa«ut lea*.
ore retrofit nay heat transfer
> «i
Wet Stacks
16
2U
(1) No reheat required.
(2) Significant savings
exhibited custpared
to s) stead In which
rehear is used.
(1) Corrosion nay occur
(duct work and stack).
(2) Arid raino.it mat
of cur .
(3) Scrubber retrofit
nay reuu? re substan-
tial nod.f i cat loo to
(4) Rypass ol scrubber
acid-res slant
stack linings.
*TkU r*rea*U(> >•• 4*v*lor*' *ro" *"* "hick r«fl«ct rrtitmt mad f»c«r« ofmttam of 10J fow>r plimtt. TW M« of u«t >uck« v«. Included I. the
-------
SECTION 6
THE NEED FOR STACK GAS REHEAT
Stack gas reheat (SGR) can be used to eliminate or reduce the impact of
the following potential problems associated with wet stack gases from flue
gas desulfurization (FGD) processes:
(1) Corrosion of equipment downstream of the scrubber
(2) Occurrence of acid rainout in the vicinity of the stack
(3) Formation of a visible plume
(4) Increased ground-level concentrations of pollutants
(other than SOa) compared to an unscrubbed flue gas
due to poor plume buoyancy
In this section, the problems caused by vet stack gases are examined in
detail, and the impacts of varying levels of reheat on these problems are
quantified where possible. In addition, the impacts of several of the
commercially available reheat systems on the problems caused by wet stack
gases will be discussed. The information obtained from the user/vendor
survey regarding (1) reasons for stack gas reheat, (2) degree of reheat
utilized, (3) type of reheat configuration used, and (4) operating history
of commercial installations are used as the bases for the information devel-
oped in this section.
A general solution to the required quantity of reheat and its impact
on a wet flue gas cannot be readily determined because:
71
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(1) The problems associated with a wet flue gas are not
interdependent; therefore, each may require a differ-
ent solution.
(2) Reheat requirements are highly site specific.
(3) Completely eliminating the problems mentioned above
requires a level of reheat that most reheat users
consider impractical; therefore, a level that
will reduce the potential problems but not eliminate
them is normally selected.
Consequently, the occurrence of the potential problems as well as the Impact
of various reheat configurations and several levels of reheat on each of these
problems is discussed separately. Because the use of bypass reheat is
limited by air quality standards that do not restrict the use of other reheat
configurations, its application is discussed separately at the end of this
section.
DOWNSTREAM EQUIPMENT CORROSION
Occurrence
Because the scrubbed flue gas contains SOa, 80s, COz, chlorides, and
sulfuric acid mist, the flue gas can be very corrosive in the presence of
moisture. Moisture can be present due to entrainment of water from the
scrubber mist eliminator and/or condensation of water vapor. Since wet FGD
processes saturate and cool the flue gas to its adiabatic saturation tempera-
ture, a small drop in flue gas temperature will result in water vapor condens-
ing in the system. Such a drop in temperature can result from heat losses
through the duct and stack walls. Responses to the reheat questionnaire
(by FGD process vendors and A/E contractors) indicate a stack gas temperature
drop of about 5°F in the stack and duct work following the scrubber.
72
-------
A substantial quantity of heat can be lost through the duct work of the
system. This heat loss is a function of the temperature difference between
the flue gas and ambient air and the overall heat transfer coefficient of
the duct wall (and insulation, if used). This overall heat transfer coef-
ficient is made up of the following individual factors:
(1) The heat transfer coefficient of the flue gas film
on the inside of the duct
(2) Thermal conductivity of the metal from which the
duct is constructed
(3) Thermal conductivity of the insulating material
(if any is used)
(4) The heat transfer coefficient of the air film on
the outside of the duct
The heat transfer coefficient of the air film is a function of wind speed.
Typically, this heat transfer coefficient is proportional to the wind speed
raised to the 0.6 power
When the duct work is insulated, the insulation becomes the controlling
resistance to heat transfer from the flue gas to the ambient air and thereby
decreases the heat loss and the flue gas temperature drop. However, it should
be noted that duct work in power plants is typically insulated only in areas
where employees may come in contact with hot surfaces. Calculations developed
for uninsulated and insulated duct work show that insulation can reduce heat
losses through the duct work by more than 90 percent (see Table 20) .
Heat loss will also occur in the stack. This loss can be caused by two
different mechanisms. One mechanism involves the loss of heat due to heat
transfer through the stack wall. Stack insulation can be provided by build-
ing an outer stack so that the air in the annular space acts as insulation.
By design, the air in the annulus becomes the controlling resistance for
73
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TABLE 20. TEMPERATURE DROP THROUGH DUCT WITH AND WITHOUT INSULATION
Ambient Air
Temperature
With Insulation 0
50
80
Without Insulation 0
50
80
Flue Gas Temperature Drop
(°F) at Wind Velocitv
0 MPH3
0.03
0.02
0.01
1,4
0.8
0.5
20 MPHa
0.03
0.02
0.01
3.6
2.2
1.4
aEnglish units are used throughout this report. Factors for converting
these units to the international system of units are given in Appendix F.
Bases:
(1) For the insulated duct, overall heat transfer coefficient at 0 MPH
wind velocity is 0.0273 Btu/hr-ft2-°F; at 20 MPH wind velocity it
is 0.0278 Btu/hr-ft2-°F (insulation thermal conductivity is 0.028
Btu/hr-ft2-°F.
(2) For uninsulated duct, the overall heat transfer coefficient at 0 MPH
wind velocity is 1.15 Btu/hr-ft2-°F; at 20 MPH it is 3.10 Btu/hr-ft2-°F.
(3) A 500-MW unit having a flue gas flow rate of 5.14 x 106 Ib/hr (at a
scrubber exit temperature of 130°F) was assumed.
(4) A rectangular (12 ft wide x 10 ft high x 100 ft long) duct having an
uninsulated surface area of 12,000 ft2 was assumed for all cases
considered. Insulation thickness was taken as one inch.
(5) Radiation heat transfer was assumed negligible.
74
-------
heat transfer. The heat loss from a 600-foot stack and the corresponding gas
temperature drop were calculated for different ambient air temperatures. For
these calculations it was assumed that the inner wall thickness, annular
space, and outer wall thickness decreased linearly with an increase in stack
height. This allowed average overall heat transfer coefficients to be calcu-
lated for 100-foot stack height increments. These coefficients were used to
develop an overall heat transfer coefficient for the stack wall. The results
of these calculations are presented in Table 21.
TABLE 21. FLUE GAS TEMPERATURE DROP DUE TO HEAT
LOSS FROM A 600-FOOT STACK
Ambient Air
Temperature (°F)
0
50
80
Flue Gas
Temperature Drop (°F)
1.5
1.0
0.6
Bases:
(1) A 500-MW unit having a flue gas flow rate of
5.14 x 106 Ib/hr (at a scrubber exit tempera-
ture of 130°F) was assumed.
(2) Heat transfer area is 46,000 ft2.
(3) Average overall heat transfer coefficient was calculated
to be 0.34 Btu/hr-ft2-°F.
(4) Wind velocity was assumed to be 15 MPH normal to
the stack axis.
As the gas rises in the stack, it undergoes isentropic expansion, which
also causes a temperature drop to occur. The flue gas temperature resulting
from the expansion of the gas can be estimated from the following expression:
R/C
75
-------
where: Ta » exiting temperature of flue gas (°R)
TI = entering temperature of flue gas (°R)
P2 - exiting pressure of flue gas (psia)
PI * entering pressure of flue gas (psia)
R = universal gas constant (Btu/lb mole-°R)
Cp » specific heat of flue gas (Btu/lb mole-°R)
The use of this expression is dependent on the flue gas experiencing no (or
negligible) heat loss in the stack. The small heat losses shown in Table 21
indicate that Equation 1 provides a good engineering estimate of the tempera-
ture drop due to the expansion of the gas in the stack. Using this equation,
a temperature drop of about 1°F was calculated for a flue gas from a 500-MW
unit that had undergone isentropic expansion in a 600-foot stack. In this
calculation it was assumed that the natural draft in the stack was approxi-
mately 2 inches (HaO) and the flue gas velocity was constant (throughout the
stack). This stack draft (2 inches HzO) is probably an upper limit of what
would be expected in a utility plant environment for a saturated flue gas.
The flue gas temperature drop for the two mechanisms (heat loss through
the walls of the stack and duct and temperature drop due to isentropic expan-
sion) can probably be held to about 5°F using a double-walled stack and well-
insulated ducts.
Some of the heat lost from the system may be replaced by the heat
resulting from work of compression by the fan that is utilized to overcome
the pressure drop incurred in the boiler-FGD unit-reheat system. The flue
gas temperature resulting from adiabatic compression can be determined from
the following expression:
76
-------
where: t2 = temperature of flue gas exiting the fan (°F)
ti s temperature of flue gas entering the fan (°F)
TI * temperature of flue gas entering the fan (°R)
n = adiabatic fan efficiency
?2 » pressure of flue gas exiting the fan (psia)
Pi = pressure of flue gas entering the fan (psia)
R » universal gas constant (Btu/lb mole-°R)
Cp » specific heat of flue gas (Btu/lb mole-°R)
To determine the variation in flue gas temperature rise (across the fan) with
system pressure drop, Equation 2 was solved assuming various pressure drops
and fan efficiencies of 65 and 85 percent (see Figure 3). In a 500-MW power
plant utilizing a limestone FGD process and an inline reheater, the total
system pressure drop is approximately 40 inches of water. Of this total,
about 15 inches of pressure drop is attributable to the scrubbing (9 in.)
and reheat (6 in.) portion of the plant. In Figure 3, it can be seen that
the flue gas temperature rise corresponding to a 40-inch pressure drop is
approximately 19°F for a flue gas at 1298F and a fan efficiency of 85 per-
cent. (This assumes that the fan providing the entire system pressure drop
requirement is placed after the scrubber.)
Although it is apparent that the primary fan can substantially raise
the flue gas temperature, the use of the work of compression to reheat flue
gas is dependent on the position of the fan in the system. In a forced
draft system* (see Figure 4a), the fan raises the temperature of the flue
gas before it is scrubbed. It is obvious that this fan positioning will
not provide any stack gas reheat as a result of the work of compression.
An induced draft fan (see Figure 4b) raises the temperature of the gas
*The reader should note that the terms forced and induced draft used in this
report refer to the position of the fan relative to the scrubber. In con-
ventional power plant practice, the boiler is the reference point; a forced
draft fan is upstream of the boiler while an induced draft fan follows the
boiler.
77
-------
1) FLUE GAS TEMPERATURE ENTERING FAN - 129»F
2) INITIAL SYSTEM PRESSURE - 14.7 PSIA
(3) FAN EFFICIENCIES • 65%, 35S
•130
PRESSURE DROP (INCHES OF
Figure 3. Calculated temperature rise due to work of compression,
78
-------
after it has exited the scrubber and therefore, it may be appropriate to
credit an induced draft fan with supplying a portion of the reheat desired.
Boiler
Scrubber
Forced
Draft
Fan
Stick
(a) Forced draft fan configuration
Scrubber
Boiler
Induced
Draft
Fan
Stack
(b) Induced draft fan configuration
Figure 4. Simplified schematic of FGD systems with
forced and induced draft primary fans.*
Prevention of Condensed Water Vapor in Equipment Downstream of the Scrubber
Energy balances were developed for the inline, indirect hot air, and
direct combustion reheat configurations in order to determine the quantity
of heat required by each configuration to eliminate the presence of moisture
downstream of the scrubber. The energy balances were developed only for
these configurations because of their distinct impact on the wet flue gas.
*The reader should note that the terms forced and induced draft used in this
report refer to the position of the fan relative to the scrubber. In con-
ventional power plant practice, the boiler is the reference point; a forced
draft fan is upstream of the boiler while an induced draft fan follows the
boiler.
79
-------
Inline Reheat Energy Balance—
The heat input supplied by an inline reheat configuration is dependent
on variables such as the quantity of mist entrained in the flue gas, the heat
lost from the stack and duct, heat input due to the work of compression from
the induced draft fan, the change in potential and kinetic energies of the
flue gas and entrained mist, and the scrubber exit and stack exit tempera-
tures. For the system shown in Figure 5a, a steady-state energy balance
permits calculation of the quantity of energy that an inline reheater must
supply in order to provide a given level of reheat (T -T ).
S £ S
Vhw,s- hw.f.> + jjj (Az) (mf + V 0)
"tl
where QD » heat supplied by reheater (Btu/hr)
K
m, * flue gas flow rate (Ib/hr)
C , » mean specific heat of flue gas (Btu/lb-°F)
P»r
T * temperature of flue gas at the stack outlet (°F)
Tf « flue gas temperature at the exit of the scrubber (°F)
m » mass flow rate of liquid carry-over (Ib/hr)
h » enthalpy of vaporized entrained mist at the stack outlet
W>S (Btu/lb)
hw ^g « enthalpy of the entrained mist at the scrubber outlet (Btu/lb)
g » local acceleration of gravity (ft/sec2)
g - conversion factor, Cft-lbm/sec2-lbf)
j - mechanical equivalent of heat (778 ft-lbf/Btu)
Az « net elevation traversed by flue gas (approximately the
difference in duct and stack outlet height)(ft)
v * velocity of the gas at the stack outlet (ft/sec)
S
vf . * velocity of the flue gas at the scrubber outlet (ft/sec)
r, rs
80
-------
Wet
scrubber
Flue gas
a) Inline Reheat
Reheater
Induced
draft fan
Heating medium
Stack
oo
Wet
scrubber
pt >»
Flue & " ^
/^ Conbustlon
, rf^. / chamber
Induced /I
draft fan / |
^>-X L
1
Induced 1
draft fan
QJ
Stack
Stack
c) Direct Combustion Reheat
Air
Figure 5. Induced draft fan arrangement of inline, indirect,
and direct combustion reheat configurations.
-------
v = velocity of the entrained mist at the scrubber outlet (ft/sec}
w,fs '
Q » heat resulting from the work of compression by the induced
f draft fan (Btu/hr) (This term is zero if there is no fan
between the scrubber and the stack.)
Q » total heat lost from the duct and stack (Btu/hr)
A rigorous examination of the inline reheat configuration requires the solu-
tion to Equation 3. However, in this study certain assumptions are made to
simplify the calculational procedure. These include (1) assuming that the
potential* and kinetic terms in Equation 3 are small and (2) assuming that
only the latent heat of vaporization must be input to the mist carried over
from the mist eliminator (i.e., the change in sensible heat of the vaporized
mist is negligible). Making these assumptions allows Equation 3 to be re-
duced to the following expression:
OR ' mfcP,f (VTfS) + mwxw + Qti - Qf
where, in addition to previously defined symbols:
X « latent heat of vaporization of water at the scrubber
w exit temperature (Btu/lb)
When the prevention of water vapor condensation is the specific objec-
tive, Equation A can be solved for the minimum reheat energy (Q,,M) required
to prevent water vapor condensation. This minimum occurs when the flue gas
stack exit temperature (T ) equals its dew point (T,). Therefore, Equation
S Q
4 becomes:
It should be noted that typically Td will be slightly higher than Tfg
because some mist carry-over from the scrubber will evaporate.
*For tall stacks this term begins to be significant. For example, a 300 ft
stack requires about 1.5°F of reheat to provide the increased potential
energy of each pound of gas exiting the stack. This is about 3% of the
energy required for 50°F of reheat.
82
-------
Indirect Hot Air Reheat Energy Balance—
A generalized steady-state energy balance for the induced draft primary
fan arrangement of an indirect hot air reheat system (Figure 5b) follows:
Q_ • m C ,(T -T ) + m (h -h ) 4- m C (T -T ) (6)
XR f p,f s fs w w,s w.fs a p,a s a
mf m
4 A- (Az)(m 4- m 4- m ) 4- -r—- (v2 -v2. .. ) 4- -^-r (v2 -v2 _ )
Jg. f w a 2g j s f.fs' 2g^j s w,fs^
where, in addition to the previously defined symbols:
m = mass flow rate of air (Ib/hr)
a
C = heat capacity of air (Btu/lb-°F)
p,a
T - ambient air temperature (°F)
a
T « temperature of flue gas-air mixture at top of stack (°F)
S
As in the case of the inline reheat system, assuming that the kinetic
and potential energy terms are small and that the change in sensible heat of
the vaporized mist is negligible, Equation 6 reduces to:
The heat supplied by the reheater is also defined by the following equation:
0_ - m C (T, -T ) (&\
XR a p,a h a vo;
where T, m temperature of heated air (°F)
Equations 7 and 8 define an indirect hot air reheat system for a given
level of reheat (Tg-Tf g) . To determine the minimum reheat energy required
(Q^) to prevent water vapor condensation in downstream equipment, the dew
83
-------
point (T,) of the flue gas-air mixture (exiting the stack) is substituted
for T (temperature of the flue gas-air mixture at the stack outlet) in
s
Equations 7 and 8. Therefore, these two equations become:
%M ' *fCp,f (Td - Tf> + Vw + Vp,a)
There are many solutions to these equations since for any non-trivial mass
flow rate of air (m ) there is a heated air temperature (T ) which will pro-
3 n
vide the reheat level. It should be noted that dilution of the wet flue gas
with heated air will, in most cases, cause the dew point of the flue gas-air
mixture to drop below the flue gas saturation temperature (at the scrubber
exit).
Direct Combustion Reheat Energy Balance —
Like indirect hot air reheat, direct combustion reheat also dilutes
the flue gas; however, the dilution effect is not as pronounced as that ex-
hibited by indirect hot air reheat. Making the same assumptions* as before,
the simplified steady-state energy balance equations for a direct combustion
reheat system (Figure 5c) are:
QR - fq (11)
and
+ Qtl - Qf
where, in addition to the previously defined symbols:
f - flow rate of combustion fuel (Ib/hr)
q - heating value (LHV) of fuel (Btu/lb)
*Kinetic and potential energy terms are small. Sensible heat of vaporized
mist is negligible.
84
-------
m * mass flow of combustion gases (Ib/hr)
O
T - temperature of combustion gases (°F)
O
These equations can be used to solve for the minimum reheat fuel requirement
that will prevent the occurrence of moisture in the equipment downstream
of the scrubber. This minimum will occur when the stack exit temperature
is equal to the dew point of the flue gas-reheat combustion gas mixture.
Results—
The respective energy balances were used to calculate the minimum
energy requirements of the inline, indirect hot air, and direct combustion
reheat configurations to vaporize any liquid carry-over from the scrubber
and prevent water vapor condensation downstream of the scrubber. Because
the actual heat required is dependent on several factors such as heat losses
and the presence of entrained liquid, the reheat needed will be very site
specific. In all the cases considered, the primary fan was assumed to be a
forced draft fan (with respect to the scrubber) so that any heat due to the work
of compression was added to the flue gas prior to its being scrubbed; there-
fore, the Qf portion of the developed expressions was considered to be zero.
For all the configurations analyzed, it was assumed that heat losses from
the system (from stack and duct work) would result in a 5°F drop in the flue
gas temperature from the reheater to the stack exit. The results of these
calculations are presented in Table 22. These data show that the
(1) Inline reheat configuration requires the lowest heat input
to prevent condensation downstream of the scrubber, and
(2) Indirect hot air configuration requires the highest heat
input to prevent condensation.
As the data in the table indicate, all the reheat configurations studied
change the dew point due to the vaporization of entrained liquid or dilution
with air or combustion gases or both.
85
-------
TABLE 22. HEAT INPUT REQUIRED TO PREVENT THE OCCURRENCE OF MOISTURE
DOWNSTREAM OF THE SCRUBBER.
00
Reheat
Entrained Liquid (gr/»cf)>
-------
It is apparent from Table 22 that the level of reheat required to
prevent condensation in the system is highly dependent on the quantity of
liquid entrainment in the flue gas. Although a study of mist eliminator
performance was beyond the scope of this study, the results illustrate the
importance of good mist eliminator design and operation.
Overall, it is concluded that stack gas reheat is a viable technique
to eliminate the presence of moisture downstream of the mist eliminator and,
therefore, to protect the system from subsequent corrosion. While the quan-
tity of heat required to prevent the presence of moisture is influenced by
several factors, this study showed the required heat is highly dependent on
the quantity of moisture entrained in the flue gas. It is stressed that only
the minimum quantity of reheat required to prevent the presence of moisture
in the system was considered in this study. In this analysis, the total heat
input required to vaporize the liquid carried over from the mist eliminator
and to offset heat losses from the system was determined. However, analyses
of. other factors such as the impact of liquid droplet size, composition, and
residence time (in the ductwork) on heat input requirements were not con-
sidered. It is expected that the reheat requirements in an actual plant (to
prevent the occurrence of moisture) will be higher than the minimum levels
calculated in this study. However, the actual requirements can only be de-
termined by a thorough evaluation of an operating plant situation.
VISIBLE PLUME FORMATION
Occurrence
A saturated flue gas can result in the formation of a visible plume.
While a visible plume does not have a negative impact on the environment,
it is aesthetically displeasing and potentially hazardous to ground and air
traffic. The mechanics of visible plume formation are illustrated in Figure
6. Ambient air conditions (temperature, relative humidity) are represented
87
-------
by point 1 in this figure. Point 2 corresponds to the conditions of the
hot flue gas as it exits the boiler. The flue gas is saturated and cooled
during the scrubbing operation and is ultimately represented by point 3.
As the saturated flue gas exits the stack, it mixes with ambient air. This
mixing process is represented by line 3-1. A plume is formed when the
ambient air-saturated flue gas mixture intersects the saturation curve and
crosses into the fogged field area of the chart. 20»21
AMBIENT AIR
ENTERING
FURNACE
SATURATION CURVE
AT BAROMETRIC
PRESSURE
FOGGED
FIELD
COMBUSTION GAS
LEAVING SCRUBBER
CLEAR FIELD
HO
AIR REHEAT
T,
x
* \~-~~ ""COM
~^^-^|f
\
COMBUSTION GAS '
FURNACE
o
03
o.
t/)
DRY BULB TEMPERATURE, °F
Figure 6. Psychrometric chart showing state point of flue gas-air
mixture during combustion, scrubbing, and reheat.20
88
-------
Prevention
Prevention of a visible plume with the use of reheat involves the clock-
wise rotation of line 3-1 (saturated flue gas-ambient air mixing line) until
Lt is tangent to the saturation curve. The temperature to which the flue gas
nust be heated to prevent the formation of a visible plume is represented by
point 5 when inline reheat is used and point 4 when indirect hot air reheat
is used. Point 6 represents the heated air temperature prior to mixing with
Che flue gas in the indirect hot air reheat method.
The heat inputs required by the inline and indirect hot air configura-
tions to prevent the formation of a visible plume at various climatic condi-
tions were calculated. Only these two configurations were considered with
regard to the prevention of a visible plume because the impacts of the
inline and indirect configurations are expected to define the range of
impacts of reheat on the formation of a visible plume. The bases for and
the results of these calculations are presented in Table 23. The results
show that:
(1) The greatest quantity of reheat to prevent visible plume forma-
tion is required when the ambient air is at low temperature and
high humidity. For example, at 100 percent relative humidity
and an ambient air temperature of 32°F, an inline reheater
would have to raise the flue gas temperature to approximately
440°F in order to avoid a visible plume.
(2) As expected, the theoretical heat required to suppress a visible
plume is approximately the same for the inline and indirect hot
air reheat configurations for the same climatic conditions.
Impact of Reheat on Visible Plume Formation and Characteristics
Radian's Wet Plume Model was used to analyze the effect of reheat on the
length of a visible plume and the plume's detached distance (the distance
from the stack before the plume becomes visible). The length of the plume is
the actual length as measured down the center of the plume. A description of
89
-------
TABLE 23. REHEAT REQUIRED TO PREVENT A VISIBLE PLUME
vO
o
Reheat Configuration
Ambient Air Temperature (°F)
Relative Humidity (%)
Flue Gas (at scrubber exit)
Saturation Temperature (°F)
Heated Air Temperature (°F)
Quantity of Heated Air Required (106lb/hr)
Stack Gas Reheat Temperature Required
To Prevent Visible Plume (°F)
Reheat Required to Prevent Visible
Plume Formation (106 Btu/hr)
(% Boiler Input)
60
50
129
-
-
183
71.0
1.58
Inline
60
100
129
-
-
240
149.0
3.31
Indirect Hot Air
32
100
129
-
-
439
416.0
9.24
60
50
129
400
0.84
166
71.0
(70.5)
1.58
(1.56)
60
100
129
400
1.75
196
149.0
(147.7)
3.31
(3.28)
32
100
129
400
4.52
253
416.0
(412.0)
9.24
(9.15)
Bases and Comments:
(1) Flue gas flow rate (exiting scrubber) is 5.14 x 106 Ib/hr (representative of a 500-MW plant).
(2) Flue gas water content (exiting scrubber) is assumed to be 14.7 percent (vol.) for all cases.
(3) A heat rate of 9000 Btu/kWh was assumed.
(4) Heat losses in duct work and stack are assumed to be negligible.
(5) Liquid entraimnent from the mist eliminator is assumed to be zero.
(6) Forced draft primary fan arrangement (with respect to the scrubber).
(7) Reheat requirements in parentheses for indirect hot air were developed by taking credit for
heat due to work of compression produced by the auxiliary fan. The pressure drop in the air
heater was assumed to be 6 in. HaO and an 85 percent fan efficiency was also assumed.
-------
the model is presented in Appendix A. In this analysis, 648 cases were
developed. This reflected 162 different combinations of meterological
conditions and four scrubbing-reheat levels. The meterological and stack
exit parameters used in this model are shown in Table 24,
An initial conclusion of the study was that changes in ambient tempera-
ture with respect to height (atmospheric stability) had little effect on
plume length or the detached distance of the plume. Consequently, only a
neutrally stratified atmosphere was considered for further analysis, and
only these data are presented below.
Presented in Tables 25 through 27 are data developed using the model
for the length of a visible plume and the detached distance that result from
unscrubbed flue gas and scrubbed flue gases that were reheated by 0°F, 50°F,
and 100°F. These data show that:
(1) An unscrubbed flue gas will form a visible plume at
100 percent relative humidity regardless of the ambient
air temperature (in the 0-100°F range). This occurs
since the stack gas contains more water vapor than the
saturated ambient air. Therefore, as the stack gas is
cooled, this additional water vapor in the plume will
condense (according to the wet plume model).
As the relative humidity drops, the temperatures at
which an unscrubbed flue gas will form a visible plume
are decreased. A psychrometric chart (Figure 7) is used
to illustrate this model result. This figure shows that
at 50 percent relative humidity the unscrubbed flue gas
will form a visible plume at ambient air temperatures
less than about 25°F. However, at 0 percent relative
humidity the same flue gas would form a visible plume
at ambient temperatures less than about 19°F.
(2) At nearly all ambient air conditions, a scrubbed flue gas
with no reheat forms a visible plume immediately as the
gas exits the stack. Also, the plume length of a scrubbed
gas is substantially longer than the plume formed by an
unscrubbed flue gas at comparable ambient air conditions.
91
-------
TABLE 24. PARAMETERS FOR UTILIZATION IN WET PLUME MODEL (500 MW PLANT)
ro
STACK PARAMETERS
Scrubbing- Reheat
Levels
Unscrubbed
Scrubbed, No Reheat
Scrubbed, 50° F Reheatb
Scrubbed, 100°F Reheat
Stack Exit
Temperature
<°F)
300
129
179
b 229
Stack Exit
Velocity
(ft/sec)
35.0
28.7
31.1
33.5
H20 Molea
Fraction
0.088
0.147
0.147
0.147
Stack
Radius
(ft)
15.3
15.3
15.3
15.3
Stack
Height
(ft)
300
300
300
300
METEROLOGICAL PARAMETERS
Wind Speed (mph)
5,15,25
Surface Air
Temperatures (°F)
0,20,40,60,80,100
Vertical Temp.
Gradients (°F/103
-5.4 (neutral)
Relative
ft) Humidities (%)
0,50,100
Surface
Atmospheric
Pressure (psia^
14.7
Assumed stack exit water vapor content for all cases investigated.
Using an inline reheater.
-------
TABLE 25. VISIBLE PLUME LENGTH AND DETACHED DISTANCE
(NEUTRAL STRATIFICATION, WIND SPEED = 5 MPH)
\o
Scrubbing - Reheac Level
Unscrubbed Scrubbed
Relative Ambient Detached
Hualdlty Air Temp Distance
(Z) (*F) (feet)
0 0 75
20
40
60
80
100
SO 0 72
20 151
40
60
80
100
100 0 72
I
20 118
40 377
60 754
80 863
100 866
Sc rubbed Plus
50° f Reheat
Plume Detached Plume Detached Plume
Length Distance Length Distance Length
(feet) (feet) (feet) (feet) (feet)
40O o
0
0
0
0
-
964 0
151 0
0
0
0
-
•H- 0
i+ 0
-H- 0
•H- 0
4+ 0
•H- 0
731
380
200
98
30
-
•H-
728
364
184
72
-
-H-
-H-
4-f
-H-
++
-H-
16 712
20 351
33 148
-
-
-
16 ++
20 692
30 305
-
-
-
16 -H-
20 4+
30 -H-
52 -H-
197 -H-
453 -t-f
Scrubbed Plus
100°F Reheat
Detached
Distance
(feet)
30
43
-
-
-
30
43
72
-
-
-
30
39
62
154
505
640
Plume
Length
(feet)
692
315
-
-
-
++
646
216
-
-
-
•H-
-H-
-H-
•f-t
++
•H-
Indicates the plume was never visible.
Indicates the plume was visible for a distance beyond the 1640 foot (500 meters) limit in the model.
-------
TABLE 26. VISIBLE PLUME LENGTH AND DETACHED DISTANCE
(NEUTRAL STRATIFICATION, WIND SPEED = 15 MPH)
VO
Scrubbing - Reheat Level
Unsc rubbed
Relative Ambient Detached Plume
Humidity Air Temp Distance Length
(*> (*F) (feet) (feet)
0 0 79 512
20
40
60
80
100
50 0 75 197
20 174 184
40
60
80
100
100 0 75 •»+
20 131 ++
40 518 ++
60 1230 ++
80 U73 ++
100 1512 ++
Scrubbed
Detached Plume
Distance Length
(feet) (feet)
0 974
0 485
0 246
0 112
0 30
-
0 ++
0 961
0 469
0 226
0 82
-
0 -M-
0 ++
0 ++
0 -H-
o •*-*
0 ++
Scrubbed Plus
50°F Reheat
Detached Plume
Distance Length
(feet) (feet)
16 935
20 446
33 184
-
-
-
16 ++
20 899
30 394
-
-
-
16 ++
20 ++
30 -H.
52 ++
272 M-
813 -M-
Sc rubbed Plus
100° F Reheat
Detached
Distance
(feet)
30
43
-
-
-
-
30
43
79
-
-
-
30
43
69
187
833
1132
Plume
Length
(feet)
899
403
-
-
-
-
-H-
830
276
-
-
-
++
++
++
•H-
•H-
-H-
Indicates the plume was never visible.
++ Indicates the plume was visible for a distance beyond the 1640 foot (500 mctur) limit In the model.
-------
TABLE 27. VISIBLE PLUME LENGTH AND DETACHED DISTANCE
(NEUTRAL STRATIFICATION, WIND SPEED = 25 MPH)
\o
Ln
Scrubbing - Reheat Level
Unscrubbed
Relative Ambient Detached Plume
Humidity Air Temp Distance Length
(Z) (*F) (meters) (meters)
0 0 89 659
\
20 • -
40
60
( 80 -
100
50 0 85 1496
20 207 226
40
60
80
100
100 0 82 -H-
i
20 154 -H-
40 718 -H-
60 -* **
80 -* **
100 -* **
Scrubbed Plus Scrubbed Plus
Scrubbed 50°K Heliuat 100°K Rehuul
Detached
Distance
(meters)
0
0
0
0
0
-
0
0
0
0
0
-
0
0
0
0
0
0
Plume Detached
Length Distance
(meters) (meters)
1273 16
620 20
305 32
131
33
~ —
**• 16
•w- 20
-w- 33
•H-
•H-
-
++ 16
++ 20
++ 30
-H- 62
-H- 374
•H- 1263
Plume Detached
Length Distance
(meters) (meters)
1214 33
574 46
230
-
-
-
-H- 33
1151 46
505 89
-
-
-
++ 33
++ 46
++ 75
-H- 230
-H- 1263
-H- -*
Plume
Length
(meters)
1161
515
-
-
-
-
-H-
1059
354
-
-
-
++
-H-
++
-H-
•H-
_*
Indicates the plume was never visible
•H- Indicates the plume was visible for a distance beyond 1640 foot (500 meter) limit in the model.
* In this case, a plume would have occurred; however, it would have occurred at a distance greater than
the Halts in the model. Therefore, the detached distance could not be projected.
** Plume cannot be estimated because the plume was formed at a detached distance that is greater than
the limits of the plume.
-------
vO
Sg
P
.090-
.085 -
.080-
.075
.070 -
.065 -
.060 •
.055 -
.050 -
.045 -
.040 -
.035
.030 -
.025 -
.020 -
.015
.010
.005
0
Aablent Air at 19*F.
OZ Relative Himldlcy
Arfitent Air at 25'F,
-50Z Relative Humidity
10 20 3O 4O 50 60 70 8O
90 100 110 120 IJO 1*0 150 160 170 180 190 200 210 220 230 240 250 260 270 280
MY BULB TEMPERATURE (*F)
JOO
Figure 7. Psychrometric chart showing the influence of relative humidities on the temperature
range at which an unscrubbed flue gas will form a visible plume.
-------
(3) At the low (0 percent) and moderate (50 percent) humidities
analyzed in this study and ambient air temperatures above
40°F, reheating a scrubbed flue gas by 50°F to 100°F sig-
nificantly increases the detached distance and reduces the
length of the plume that results from scrubbing. However,
at 100 percent relative humidity, the impact of these
levels of reheat is diminished. As before, a psychrometric
chart is used to illustrate this conclusion (see Figure 8).
This figure shows that the plume length associated with 50
percent relative humidity (line EF) should be shorter than
that resulting at 100 percent (line DB).
(4) The length of the visible plume is increased as the wind
speed increases.
The model-predicted plume length data in Table 25 are presented graphically
in Figure 9. This figure shows the effect of reheat on plume length for
relative humidities of 0 and 50 percent and different ambient air tempera-
tures at a constant wind speed of 5 mph. This figure also emphasizes the
increased length of a visible plume that results from scrubbing. It is
also apparent from Figure 9 that even substantial levels of reheat CVIOOT)
may only slightly reduce the length of a visible plume caused by scrubbing
at low or moderate ambient air temperatures.
Figure 10 shows the effect of scrubbing and reheat on the detached
distance of a plume for different wind velocities and a constant relative
humidity of 100 percent. This figure shows that the detached distance of
the visible plume resulting from a scrubbed flue gas is shorter than that
from an unscrubbed flue gas for each ambient air temperature considered.
In fact, a scrubbed stack gas will form a visible plume as soon as it exits
the stack at most climatic conditions. It is also apparent in Figure 10 that
reheating the scrubbed flue gas by 50-100°F does not increase the detached
distance to its initial length (that length which corresponds to an unscrubbed
plume). However, reheating a scrubbed stack gas by 50°F may provide a de-
tached distance of at least 10-15 feet for those conditions under which a
visible plume is formed.
97
-------
Saturated
Flue Gas
Temperature Resulting
FI-OB SO'F of Reheat
00
.uvo -
.085 -
// A\
/ i f ^^ Ucr £r-n»kt»f«« rtf
.080 - Line AB represents the length of the / / f ~^-~- ---_-..-..., —
visible plume
..yc scrubbed flue
discharged itt
and 100 Z hum
.070 -
.065 -
.060 -
.055 -
.045 -
.040 -
Line DB Represents the
Length of the Visible
.035 - Plume That is Formed
When a Scrubbed Flue
.030 - Gas Which Has Been — ^,
Reheated 50*F Is
fl-c Discharged into Ambient
Air at 50*F and 1001
Relative Humidity
.020 - 1
.015 - 1 i
.010 - Ambient Air at 50'F /^
and 100Z Relative— -J/TO'
.005 - Humidity ^^ I/
____— ~^^ /I— '
c^
° 1 1 1 1 1 1
that la formed when a j 1 f ^**^^
|as with no reheat is / 1 ff ^~^^
to ambient air at SO'F/ / ff ^^~
idlty / / // ^>^
/ / / ^\
// / ^\
/ I/ 1
II I // Combustion Gases at '
If 1 // Exit of Air Preheater.
H I// Specific Humidity of
// If / Combustion Cases Aa-
// J / sumed to be the same
// /]/ regardless of Ambient
// /I/ Air Humidity.
II / f E
// / /I Llne EF Represents the Length
// / // at the Visible Plume That is
\// / // Formed Uhen a Scrubbed Flue
rr^-/ / 1 Sas Uhlch Has Been Reheated
// / / / 50*F is Discharged Into
// /AT Ambient Air at 50«F
1 1 / / / and 50Z Relative Humidity
X s
'S,
CM
Ambient Air at 50*F °
and 502 Relative Humidity
1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 '' 1 1 1 1 1 1 ~1
0 10 20 30 40 50 6O 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230 2*0 250 260 270 280 290 301
DDT MM TEMPERATURE (*F)
Figure 8.
Psychrometric chart showing the impact of 50°F reheat on
visible plume length at different relative humidities.
-------
100 •
50 -
SYMBOLS
a
o
x
AMBIENT
AIR_TEMP.
0' F
20°F
403F
50'F
30'F
UJ
ac
SCRUB. •
UNSCRUB.
il-i .-j
: 323
(100)
Note: (1) At 100'F ambient air,
no plume is formed.
(2) See footnote b
>
656 984 1312 1640
(200) (300) (400) (500)
RELATIVE HUMIDITY > OX
PLUME LENGTH, F£ET (DETERS)
SCRUB. -
UNSCP.UB.
328
(100)
655
(200)
Note: (1) At 0*F ambient air,
the plume length is
longer than the
maximum length
handled by the
model (1640 feet).
(2) At 100'F ambient air,
no plume is formed.
(3) See footnote b
*r
984
(300)
1312
(400)
1640
(500)
RELATIVE HUMIDITY - 5015
PLUME LENGTH, FEET (METERS)
The symbols do not represent data points, but rather are model solutions
.for specific stack gas parameters.
The dashed lines shown in this figure do not Indicate a physical connection
between the unscrubbed and scrubbed flue gases; these lines facilitate the
comparison of the detached distances of plumes resulting from these gases.
Figure 9. Impact of scrubbing and reheating on visible plume length at
various ambient air temperatures and relative humidities
(neutral stratification, wind speed - 5 mph).
99
-------
100
50
LJ
SCRUB.
UNSCRU8.
SYMBOLS8
a
O
x
0
Note:
AMBIENT
AIR TEMP.
O'F
20'F
60'F
80*F
100'F
See footnote b
328
(100)
656
(200)
984
(300)
1312
(400)
1640
(SCO)
WIND SPEED * 5 mph
DETACHED DISTANCE, FEET (METERS)
SCRUB.
UNSCRUB.
Note: See footnote b
328
(100)
656
(200)
948
(300)
1312
(400)
WIND SPEED - 15 *iph
DETACHED DISTANCE, FEET (METERS)
1640
(500)
'these symbols do not represent data points, but rather are model solutions
hfor specific stack gas parameters.
The dashed lines shown in this figure do not Indicate a physical connection
between the unscrubbed and scrubbed flue gases; these lines facilitate the
comparison of the plume lengths resulting from these gases.
Figure 10. Predicted impact of wind speed and reheat on detached
distance of visible plume (neutral stratification,
relative humidity - 100 percent).
100
-------
In summary, the following results were obtained using the Wet Plume
Model:
(1) Scrubbing leads to an increased plume length and a
decreased detached distance of the plume from the
stack.
(2) There are some climatic conditions, such as low
temperature and high humidity, at which the increased
plume length and decreased detached distance that result
from scrubbing cannot be significantly reversed with the
levels of reheat (0 to 100°F increase in flue gas tempera-
ture) currently used by industry.
(3) Reheat can significantly decrease plume length and increase
detached distance at conditions of mild temperature and low
humidity; however, at these conditions a short plume is
likely to occur, whether reheat is used or not.
ACID RAINOUT IN THE VICINITY OF THE STACK
Occurrence
Acid (H2SOu and ^SOs) rainout* in the vicinity of the stack can be
generated by two mechanisms in a boiler-FGD system. One mechanism involves
the formation of SOa which then reacts with HaO vapor in the system to form
HaSOi* vapor. Because the dew point of sulfuric acid is higher than the adia-
batic saturation temperature of the flue gas, the H2SOi» vapor is condensed
to a mist, which then may agglomerate into rain droplets as the flue gas
exits the stack.
The second mechanism involves the presence of moisture on the stack wall
due to the condensation of water vapor and/or liquid carry-over from the
mist eliminator and subsequent absorption and oxidation of residual SOj.
The resulting sulfurous and sulfuric acid droplets are entrained in the gas
stream. When the velocity of the gas is no longer sufficient to entrain the
*0ther acids present include nitrous, nitric, hydrochloric, carbonic, and
hydrofluoric.
101
-------
droplets, rain may result from the plume. The degree of rainout has been
correlated to the presence of condensation in the stack and the stack gas
velocity. Rainout potential is greatest when there is substantial conden-
sate present in the stack and the gas velocity is greater than 25 ft/sec.22
Stacks are usually designed for velocities greater than 25 ft/sec.
Prevention
Reheat can be used to suppress acid rainout by:
(1) Preventing condensation of water vapor from occurring in
the duct and stack downstream of the scrubber due to heat
losses from stack or duct work
(2) Vaporizing any entrained liquid from the mist eliminator
(3) Vaporizing any sulfuric acid mist that is present in the
system
The heat required to prevent the presence of moisture downstream of the
scrubber is substantially less than the heat which is required to vaporize
sulfuric acid mist. Preventing the condensation of water vapor requires the
input of enough heat to keep the scrubbed flue gas above its dew point,
which is approximately 125 to 140°F. Vaporizing any sulfuric acid that is
present requires the flue gas to be heated to a temperature higher than the
sulfuric acid dew point, which is approximately 200 to 300°F. Even though
all the sulfuric acid in the system can be vaporized with a substantial heat
input, sulfuric acid condensation may occur when the flue gas exits the
stack and mixes with the cooler ambient air.
Predicted Impact of Reheat on Rainout From Plume
Although little work has been done on rainout from power plant stacks
considerable work has been done on rainout frora cooling towers, and several
theories have been suggested to explain its occurrence. Two of the most
102
-------
prominent theories were presented by Blum23 and Overcamp and Hoult24 (also
Martin and Barber ). Blum concluded that rainout would occur when the liquid
density in the plume was 3.12-6.24 x 10~5 lb/ft3 (0.5-1.0 gm/m3). Overcamp
and Hoult concluded that rainout was caused by entrained mist. As their
basis, these investigators estimated that at a condition of 0.5 percent
water vapor supersaturation in the plume, about 100 seconds were required
before a droplet could grow (by the mechanism of water vapor condensation)
to the size that would rain from the plume.
In this study, a Wet Plume Simulation Model (described in Appendix A)
was used to simulate the water content of a flue gas plume for different
meterological conditions and degrees of reheat. Based on the two theories
presented above, the model was used to study the effect of reheat on the
density of condensed water vapor in the plume and the time length over which
the water density was equal to or greater than a specified density. The
data generated by the model for different wind speeds are presented in
Tables 28 through 30. The data in Table 28 on (1) the time length the den-
sity of condensed water vapor in a visible plume is equal to or greater than
3.12 and 6.24 x 10~5 lb/ft3 (0.5 and 1.0 gm/m3) and (2) the maximum density
attained by the condensed water vapor in a visible plume are graphically
presented in Figures 11 and 12. The data in Tables 28 through 30 and these
figures show that:
(1) As the relative humidity increases, the maximum water
density and the time length that the density of con-
densed water vapor in the plume is equal to or greater
than 3.12 and 6.24 x 10" 5lb/ft3 (0.5 and 1 gm/m3) is
increased for the unscrubbed and scrubbed (with and
without reheat) stack gases.
(2) Scrubbing with no reheat significantly increases (compared
to an unscrubbed plume);
—the temperature range in which condensed water vapor
is present in the plume,
—the time length that the density of the condensed water
vapor is above any given limit, and
—the maximum condensed water vapor density.
103
-------
TABLE 28. PLUME CHARACTERISTICS FOR VARIOUS SCRUBBING AND REHEAT LEVELS (NEUTRAL ATMOSPHERE, WIND
SPEED = 5 MPH)
SCRUBBING AND REHEAT LEVELS
UnaeriMted
Relative Ambient Air
Humidity Teaperatur*
(X) CF)
0 0
20
40
60
80
100
50 0
20
40
60
SO
100
100 0
20
40
60
to
100
TlM
P>0. 5 «•>/»>
(•ec)
12
-
-
-
-
-
18
0
-
-
-
-
27
17
0
100+
135+
147+
TlM
p±l (•/»'
(•ec)
7
.
-
-
.
-
10
0
-
-
-
-
1)
0
0
0
90+
129+
MaxlmUB
Density
(«•/•')
2
-
-
-
-
-
2
<0.25
-
-
-
-
3
1
1
1
2
3
Scrubbed. No Reheat
TlM
p>0.5 gm/m'
<«c)
28
18
10
5
1
-
40
29
18
10
4
-
60
70
227+
227+
228+
229+
TlM
p>l «./»'
25
25
19
12
5
-
30
25
19
13
7
4
Scrubbed, SO'F Rebut
Tin*
p>0.5 (./.'
~ (»ec)
26
16
8
-
-
-
36
26
15
-
-
-
53
60
88
225+
198+
177+
TlM
P»l gm/m1
(•ec)
19
13
6
-
-
-
24
22
12
-
-
-
30
30
30
25
136+
157+
Maximum
Penalty
(£•/•')
17
11
4
-
-
-
17
12
6
-
-
-
17
12
7
3
2
4
Scrubbed. 100*F Reheat
TlM
PiO.S gm/m1
(aec)
24
14
-
-
-
-
32
22
9
-
-
-
47
51
59
50+
165+
163+
Tine
Pi* «•/»'
(aec)
17
11
-
-
-
-
21
16
5
-
-
-
26
26
22
0
116+
144+
Maxima
Denalty
(«•/»*}
10
6
-
-
-
-
11
6
2
-
-
-
11
7
3
1
2
3
Note: 0.5 (•/•' - 3.12 x-10"* lb/ft': 1.0 g»/»' - 6.24 x 10 * lb/ft'.
- Indicates fl\me was Dot risible; consequent!;, no condensed water was present In the plo»e.
+ Thia la only ao approximate tisx becauae the pluM surpassed the 1640 foot (500 Mter) validity limit of the andel.
-------
o
in
TABLE 29. PLUME CHARACTERISTICS FOR VARIOUS SCRUBBING AND REHEAT LEVELS (NEUTRAL ATMOSPHERE, WIND
SPEED = 15 MPH)
SCRUBBING AND REHEAT LEVELS
Unscrubbed
Relative Ambient Air
Hunidlty Temperature
(I) CF)
0 0
20
40
60
80
10O
SO 0
20
40
60
80
100
100 0
20
40
60
80
100
Time
p>0.5 gm/m3
(sec)
11
-
-
-
-
-
16
0
-
-
-
-
24
IS
0
0
0
0
Time
.-.>! g./.3
(sec)
a
-
-
-
-
-
9
0
-
-
-
-
12
0
0
0
0
0
Maximum
Density
(gm/m»)
2
-
-
-
-
-
2
<0.25
-
-
-
-
3
1
1
1
1
1
Scrubbed, No Reheat
Time
p>0.5 gm/m3
(sec)
25
16
9
5
1
-
35
25
16
9
4
-
52
58
76
78+
78+
79+
Time
P>1 gm/m3
(sec)
19
13
8
5
1
-
28
19
13
8
3
-
29
30
32
34
37
79+
Maxim,,.
Density
25
25
18
10
2
-
>25
25
18
12
5
-
31
25
19
13
8
3
Scrubbed
Time
p>0.5 gn/n3
(sec)
23
14
7
-
-
-
32
22
13
-
-
•-
46
50
58
75+
38+
23+
, SOT Reheat
Time
p>l gm/m3
(sec)
17
12
6
-
-
-
21
17
10
-
-
-
26
27
26
20
0
0
Maximum
Density
(gm/m*)
17
11
4
-
-
-
17
12
6
-
-
-
17
12
7
3
1
1
Scrubbed
Time
p>0.5 gm/m3
(sec)
21
12
-
-
-
-
29
20
8
-
-
-
41
43
44
12
6+
10+
, 1OOT Reheat
Time
~(sec)
16
11
-
-
-
-
19
17
5
-
-
-
23
23
19
0
0
0
Maximum
Density
(gm/m3)
11
6
-
-
-
-
11
6
2
-
-
-
1
7
3
1
1
1
Note: 0.5 g»/«3 - 3.12 x 10~s lb/ft3; 1.0 g»/n3 - 6.24 x 10'5 lb/ft3.
Indicates plume was not visible; consequently, no condensed water was present in the plu»e.
+ This IK only an approximate time because the plume surpassed the 1640 foot (500 meter) validity limit of the model.
-------
TABLE 30. PLUME CHARACTERISTICS FOR VARIOUS SCRUBBING AND REHEAT LEVELS (NEUTRAL ATMOSPHERE,
WIND SPEED =25 MPH)
SCRUBBING AND
Relative
Humidity
0
50
100
Ambient Air
Temperature
0
20
40
60
80
100
0
20
40
60
80
100
0
20
40
60
80
100
Unscrubbed
Tim* Time
P>0.5gm7m' PUgm/m1
(sec) (sec)
9 6
-
-
-
-
-
14 8
0 0
-
-
-
-
21 11
13 0
0 0
-
-
— -
Scrubbed, No Reheat
Maximum Time
Density p^0.5 gm/m2
(&•/«') (sec)
2 22
14
8
4
1
-
2 31
<0.2S 22
14
a
3
-
3 46
1 47+
1 47+
48+
48+
49+
Time
~(«ec"
17
12
8
4
1
-
21
17
12
7
3
-
26
27
20
28
28
23
Maximum
Density
(gm/«J>
25
25
18
10
2
-
>25
25
18
12
5
-
31
25
19
13
8
3
REHEAT LEVELS
Scrubbed, 50*F Reheat
Time
p>0.5 gm/m1
(sec)
21
13
6
-
-
-
28
20
11
-
-
-
41
44
46+
45+
30+
2+
Time
Pi.1 tftln
(aec)
18
11
5
-
-
-
19
15
9
-
-
-
23
24
23
17
0
0
Maximum
Density
16
11
4
-
-
-
17
12
6
-
-
-
17
12
7
3
1
1
Scrubbed,
Time
P>0.5zm/m'
(sec)
19
11
-
-
-
-
26
17
7
-
-
-
37
38
36
1+
0
-
100* F Reheat
Time
~(aec)
14
9
-
-
-
-
17
13
5
-
-
-
21
20
17
0
0
-
Maximum
Density
11
5
-
-
-
-
11
6
2
-
-
-
11
7
3
1
1
-
Note: 0.5 urn/.' = 3.12 x 10"5 Ib/ft'; 1.0 gm/m1 - 6.24 I 10 i Ib/ft1.
- Indicates plume was not visible; consequently, no condensed water was present In the plume.
* This Is only an ru»imat<; time because the plume surpassed the 1640 foot (SOO Meters) validity limit of the oodel.
-------
SYMBOL*
a
AMBIENT
AIR TEMP.
ff
20'F
JO'1
60'?
= SCRUB.
UNSCRUB.
tote: (1) Case for 100'F ambient »1r does not
Indicate the presence of condensed
water
(2) See footnote b
0 10 20
RELATIVE HUMIDITY . Oi
30 40
TIME (SECONDS)
Note: (1) Case for 100'F ambient air does not
indicate the presence of condensed
water
(2) See footnote b
0 10 20
RELATIVE HUHIOtTf - 501
30 40
TIME (SECONDS)
30
These symbols do not represent data points, but rather are model solutions
ufor specific stack gas parameters.
The dashed lines shown In this figure do not indicate a physical connection
between the unscrubbed and scrubbed flue gases; these lines facilitate the
comparison of the properties exhibited by the condensed water vaoor in the
visible plumes resulting from these gases.
Figure 11. Model-predicted time lengths that the density of the condensed
water^vapor in visible plumes was greater than 3.12 x 10~5
Ib/ft for various reheat levels (neutral atmosphere, wind
speed - 5 mph).
107
-------
AMBIENT
SYMBOL* tlR 'tW.
a
O
X
O
O'F
2Q'F
JC'-
60' F
30'F
100 V
100 1
- 50
SCRUB.
UNSCRUB.
Not«: (]) Sii footnotf b
DENSITY tug/m')
RELATIVE HUMIDITY • 01
ICO
Nott; (!) S«« footnotf 6
UNSCRUB.
DENSITY (js/inj)
RELATIVE HUMIOIH • SOX
*Thtu symbols do not nprtsent dat« points, but rather art model solutions
for specific stack gas parameters.
dashed lines shown In this figure do not Indicate a physical connection
between the unscrubbed and scrubbed flue gases; these lines facilitate the
comparison of the properties exhibited by the condensed water vapor 1n the
visible plumes resulting from these gases.
Figure 12. Model-predicted maximum densities attained by condensed water
vapor in visible plumes for various-reheat levels (neutral
atmosphere, wind speed • 5 mph).
108
-------
(3) At low and moderate humidities (represented by 0 and 50
percent in this study), reheating a scrubbed flue gas by
50°F does not significantly reduce either the time the
density of condensed water vapor is greater than 3.12 x
10~5 lb/ft3 (0.5 gra/m3) or the maximum density attained
by condensed water vapor in the visible plume unless the
ambient air temperature is SO0!1 or higher.
(4) The impact of reheat is diminished as the relative humidity
increases. Figure 11 clearly illustrates that at 40°F and
zero percent humidity, 100°F of reheat reduces the time
the density of the condensed water vapor is equal to or
greater than 3.12 x 10~5 lb/ft3 to zero seconds; however,
at 50 percent humidity, 100°F of reheat reduces this time
to approximately 9 seconds.
(5) An increase in wind speed has essentially no effect on
the maximum density of condensed water in the plume and
slightly shortens the time the condensed water is equiva-
lent to or greater than the specified density limit.
It should be noted that the trends outlined by data corresponding to the
100 percent relative humidity and 60°F to 100°F ambient air temperature cases
are not as well defined as in other cases. These anomalies are a result of
the model's validity limits being exceeded by such a high humidity case.
However, these anomalies should not invalidate the trends and conclusions
developed from the overall data presented in Tables 28 through 30.
Analysis of the concentration of condensed water in a stack plume shows
that reheat may have a significant impact on rainout at conditions of mild
temperatures and low relative humidities; however, this conclusion is very
speculative since the mechanism causing rainout is not fully understood.
Analysis of the effect of reheat on rainout at a commercial installation
should be undertaken to better define the potential benefit of reheat in
reducing the impacts of this problem.
109
-------
INCREASED GROUND-LEVEL POLLUTANT CONCENTRATIONS
Occurrence
The ground-level concentration of pollutants resulting from dispersion
of stack gases is dependent on plume buoyancy, which is affected by the tem-
perature of the flue gas. As the plume rises, it is in vigorous turbulent
motion. This turbulence is caused by momentum and buoyancy forces. The
momentum forces are effective only for a short distance downwind from the
stack. The buoyancy forces then become the dominant forces and accelerate
the plume upward because the flue gas is hotter and, therefore, less dense
than the air.* These forces will continue to drive the flue gas upward as
long as it is hotter than the ambient air. Buoyancy-induced turbulence can
be effective for a distance that is on the order of several hundred stack
diameters downwind from the stack.
Unscrubbed stack gases are emitted to the atmosphere at about 300°F.
Scrubbed stack gases (without reheat) are emitted to the atmosphere at about
125-140°F. Therefore, the plume rise associated with a scrubbed plume is
considerably less than with an unscrubbed plume. Ground-level concentrations
of pollutants not removed by the scrubbing process (for example, NO ) will
generally be higher for plants with wet S02 scrubbing than those without
scrubbing. Stack gas reheat can be used to enhance plume buoyancy for
scrubbed stack gases and therefore reduce ground-level concentrations of
SO2 and NOX-
Impact of Reheat on Ground-Level Pollutant Concentration
With the use of the plume modeling program described in Appendix A, the
effect of reheat on the short term (three-hour) SOa and N0 ground-level
*This assumes that the densities of air and the stack gas are equal at the
same temperatures and pressures. This is a close approximation for air
and stack gases.
110
-------
concentrations was analyzed. Of three possible atmospheric stabilities,
only two, unstable and neutral, were studied because these stabilities
produce high ground-level pollutant concentrations. With these stabilities,
the model was used to predict the impact of reheat on maximum ground-level
pollutant concentrations. The occurrence of an unstable atmosphere is rela-
tively infrequent and is caused by intense, solar heating of the ground.
This results in large vertical temperature gradients. The heated air rises
and undergoes vigorous mixing. When the plume is caught up in this mixing,
it is brought to the ground relatively close to the stack. At this distance
the plume has not been greatly diluted. A neutral atmosphere occurs more
frequently than an unstable atmosphere and produces lower ground-level pollu-
tant concentrations compared to the unstable atmosphere.
The meteorological conditions used with the unstable atmosphere were
a 5-mph wind speed, an ambient air temperature of 60°F, and an ambient tem-
perature gradient of -10.7 "F/1000 ft. The flue gas, stack, and emission
parameters used in the model are given in Table 31. The results of this
analysis are illustrated in Figures 13 and 14 and show that:
(1) The highest S02 ground-level concentrations are exhibited
by unscrubbed flue gas. However, since scrubbing does not
remove NOX, the unscrubbed flue gas exhibits the lowest
ground-level NOX concentrations compared to all of the
scrubbing-reheat levels analyzed.
(2) Scrubbing the flue gas reduces the maximum ground-level
S02 concentration by approximately 48 percent. However,
scrubbing increases the ground-level NOX concentration by
approximately 160 percent over that of the unscrubbed flue
gas. Both the SC>2 and NOX concentrations that result from
scrubbing are below applicable ambient air quality standards.
(3) Reheating the scrubbed flue gas by 508F reduces the ground-
level SOa and NOX concentrations appr<
compared to scrubbing with no reheat.
level SOa and NOX concentrations approximately 33 percent
(4) The addition of 100°F of reheat to the scrubbed flue gas
reduces the ground-level SOa and NOX concentrations by
about 47 percent compared to a flue gas which has been
scrubbed but not reheated.
Ill
-------
TABLE 31. FLUE GAS, STACK AND EMISSION PARAMETERS
Flue Gas Exit Flue Gas Stack Stack Emission
Temperature Exit Velocity Radius Height Short -Terra
Unsc rubbed
Scrubbed, No Reheat
Scrubbed, 50'F Reheat
Scrubbed. 100'F Reheat
Annual rates are based on
Bases:
CF>
300
129
179
229
(ft/sec) (ft)
35.0 15.3
28.7 15.3
31.1 15.3
33.5 15.3
(ft) S02
300 25,130
300 5,025
300 5,025
300 5,025
Rates (lb/hr^
Annual
S02 NOX
20,104 2,418
4,020 2,418
4,020 2,418
4,020 2,418
80Z utilization of power plant.
(1) SO2 removal (in the scrubber) is assumed to be BOZ.
(2) Flue gas composition
Note: Quantity of CO
(3) Coal composition:
Higher Heating Value
(representative
Component
N2
02
C02
SO?
S03
NOx
HC1
H20
is very snail
Component
C
H2
N2
O
S
Cl
Ash
H20
- 10,500 Btu/lb
of 500-MW Power Plant):
Scrubber Inlet
(Ibs/hr) (wt I)
3,450,000 70.3
258,200 5.3
904,200 18.4
25,130 0.5
317 0.0
3,022 0.1
661 O. 1
264,500 5.4
Scrubber Exit
(Ibs/hr) (wt Z)
3,450,000 67.7
258.200 5.1
904,200 17.8
5.025 0.1
317 0.0
3,022 0.1
0 0.0
472,200 9.3
and is consequently included with C02.
Wt Z (as fired)
57.56
4.14
1.29
7.00
3.12
0.15
16.00
10.74
(4) Meteorological conditions:
Unstable Atmosphere Neutral
Ambient Air
Temperature (*F)
Wind Speed (mph)
Temperature
60
5
-10.7
Atmosphere
60
18
-5.4
Gradient (*F/10J ft)
-------
900-
SYMBOL REHEAT LEVEL
©
a
800 •
700-
600-
E
01
•2 500-
§
400-
300-
200
100
UNSCRUBBED
SCRUBBED, NO REHEAT
SCRUBBED, SO' REHEAT
SCRUBBED, 100* REHEAT
0 1 2
DOWNWIND DISTANCE FROM STACK (MILES)
Figure 13. Model-predicted three-hour, ground-
level SOz concentration downwind of
the stack for an unstable atmosphere
(wind speed * 5 mph).
113
-------
320 •
300 •
230 •
260 •
240 •
fn
f 220 •
&
I 200 •
i
5 180 •
I
SCRUBBED. 100° REHEAT
1.0
DOWNWIND DISTANCE FROM STACK (MILES)
2.0
Figure 14.
Model-predicted three-hour, ground-level NOX
concentration downwind of the stack for an
unstable atmosphere (wind speed » 5 mph).
114
-------
(5) The maximum ground-level concentration of NOX resulting from
the scrubbed plume (with 100°F reheat) is approximately 40
percent greater than the maximum NOX ground-level concentration
exhibited by the unscrubbed plume.
Similar effects (observed for NOx) would be anticipated for other pollutants
not removed in the scrubbing process.
The meteorological conditions assumed for the neutral atmosphere
modeling were an 18-mph speed, a 60°F ambient air temperature, and an
ambient temperature gradient of -5.4°F/103 ft. The results predicted for
the neutral atmosphere are illustrated in Figures 15 and 16 and show the
same general trends in SOz and NOX reduction that were shown for the unstable
atmosphere. Both the SOa and NOX maximum ground-level concentrations for the
neutral atmosphere are considerably less than those exhibited in an unstable
atmosphere.
It should be noted that other techniques can be used to reduce ground-
level pollutant concentrations. For instance, the use of a more efficient
scrubber would reduce the ground-level SOz concentration. The impact of
improved scrubber efficiency on the maximum ground-level SOa concentration
for a neutral atmospheric stability is shown in Table 32. The data in this
table show that the effect of a given level of reheat on ground-level SOa
concentration is diminished as the SOa removal efficiency is increased.
Since NOX is not removed by the scrubbing process, the same ground-level NOX
concentration would be exhibited regardless of the SC>2 removal efficiency.
An increased stack height can also reduce the ground-level pollutant
concentrations. Data presented in Table 33 show the impact of increased
stack height on maximum ground-level SOa and NO concentrations. From these
data it can be seen that the reduction in ground-level pollutant concentra-
tions that is gained by the progressive addition of reheat to a scrubbed
flue gas is diminished at an increased stack height.
115
-------
SYMBOL REHEAT LEVEL
200-1
© UNSCRUB5ED
A SCRUBBED, HO REHEAT
0 SCRUBBED, 50" REHEAT
SCRUBBED, 100' REHEAT
Ul
o
100-
8 10 12
OOHNW1ND DISTANCE FROH STACK (MILES)
14
16
18
Figure 15. Model-predicted three-hour, ground-level S02 concentration downwind of
the stack for a neutral atmosphere (wind speed = 18 mph).
-------
SYMBOL REHEAT LEVEL
UNSCRUBBED
SCRUBBED. NO REHEAT
SCRUBBED, 50° REHEAT
SCRUBBED, 100" REHEAT
18
DOWNWIND DISTANCE FROM STACK (MILES)
Figure 16.
Model-predicted three-hour, ground-level NOX concentration downwind
of the stack for a neutral atmosphere (wind speed = 18 mph).
-------
TABLE 32. IMPACT OF SOz REMOVAL EFFICIENCY ON MAXIMUM THREE-HOUR GROUND-LEVEL S02 CONCENTRATIONS
Maximum Ground Level SOa Concentrations
SOa Removal Efficiency (%) Scrubbing-Reheat Level Mg/m3 % of unscrubbed
OO
Bases:
70 Unscrubbed
Scrubbed with no reheat
Scrubbed with 50°F reheat
Scrubbed with 100°F reheat
80 Unscrubbed
Scrubbed with no reheat
Scrubbed with 50°F reheat
Scrubbed with 100°F reheat
90 , Unscrubbed
Scrubbed with no reheat
Scrubbed with 50° F reheat
Scrubbed with 100° F reheat
180
147
105
84
180
98
70
55
180
49
35
28
100
82
58
47
100
54
39
31
100
27
19
16
(1) Neutral atmospheric stability
(2) 18-mph wind speed
(3) 500-MW plant
(4) 300-foot stack height
(5) 30.6-foot stack diameter
(6) Stack gas velocities
(a) unscrubbed - 35.0 ft/sec
(b) scrubbed - 28.7 ft/sec
(c) scrubbed with 50°F reheat - 31.1 ft/sec
(d) scrubbed with 100°F reheat - 33.5 ft/sec
(7) Unscrubbed stack gas temperature - 300°F
(8) Scrubbed stack gas temperature (with no reheat) - 129°F
-------
TABLE 33. IMPACT OF STACK HEIGHT ON MAXIMUM THREE-HOUR GROUND-LEVEL POLLUTANT CONCENTRATIONS
Stack Height
(ft) Scrubbing-Reheat Level
300
600
Unscrubbed
Scrubbed with no reheat
Scrubbed with 50°F reheat
Scrubbed with 100°F reheat
Unscrubbed
Scrubbed with no reheat
Scrubbed with 50°F reheat
Scrubbed with 100°F reheat
Maximum Ground Level
S02 Concentration
Mg/m3
180
98
70
55
78
30
24
20
% of unscrubbed
100
54
39
31
100
38
31
26
Maximum Ground Level
NOx Concentration
Pg/m*
21
58
42
32
9
18
14
12
% of unscrubbed
100
276
200
152
100
200
156
133
Bases:
(1) Neutral atmospheric stability
(2) 18-mph wind speed
(3) 500-MW plant
(4) Atmospheric temperature is assumed to be 60°F.
(5) 80 percent S02 removal
(6) 30.6-foot stack diameter
(7) Stack gas velocities
(a) unscrubbed - 35.0 ft/sec
(b) scrubbed - 28.7 ft/sec
(c) scrubbed with 50°F reheat - 31.1 ft/sec
(d) scrubbed with 100°F reheat - 33.5 ft/sec
(8) Unscrubbed stack gas temperature - 300°F
(9) Scrubbed stack gas temperature (with no reheat) - 129°F
-------
Annual average concentrations were also estimated; however, these
concentrations were estimated with the Gauss/X-Star Modeling program which
utilizes the algorithm developed by Busse and Zimmerman in 1973.2S The
results of the annual average modeling are given in Table 34. These results
show that the annual average S02 concentration is progressively reduced by
scrubbing and the addition of 50°F and 100°F of reheat. As expected, the
ground-level NOX concentration is increased by scrubbing. It is also appar-
ent that 50°F and 100°F of reheat reduces ground-level NOX but do not
reduce the NO concentration to the level exhibited by unscrubbed flue gas.
It should be noted that the concentrations of both N0x and 862 are well
below current applicable air quality standards.
TABLE 34. MAXIMUM ANNUAL AVERAGE POLLUTANT CONCENTRATIONS
Unscrubbed
Scrubbed, no reheat
Scrubbed, 50 °F reheat
Scrubbed, 100° F reheat
S02
Ug/m3
9.0
4.3
2.8
2.3
NOX
Ug/m3
1.1
2.4
1.6
1.3
Distance from
stack (km)
7.9
4.5
6.8
6.8
Bases: Same as given in Table 32.
Based on the predictions of the plume models, it is concluded that
reheating the flue gas can significantly reduce the ground-level pollutant
concentrations that occur when a flue gas is scrubbed. However, other
techniques, such as improved SOz removal efficiency and increased stack
height, can also reduce the ground-level pollutant concentrations. Conse-
quently, the selection of any technique should be based on a technical and
economic assessment of all available alternatives.
120
-------
Impact of Climate on Ground-Level SO^ Concentration
The impact of reheat on ground-level SOa concentrations at various
climatic conditions was also investigated. In this analysis the effect
it
of scrubbing and various reheat temperatures on ground-level SOa concentra-
tions at ambient air temperatures of 70°F (summer), 40°F (spring-fall), and
10°F (winter) was determined. The results of this study are presented in
Table 35. These data show that:
(1) The highest maximum ground-level concentrations occur
in the summer.
(2) A given level of reheat will have more impact (in terms
of reducing ground-level concentrations) in the summer
than in the cooler seasons.
Impact of Indirect Hot Air Reheat Configuration on Ground-Level S02
Concentrations
Since the indirect hot air configuration dilutes the flue gas as well
as heats it, it is of interest to determine the effects on ground-level
pollutant concentrations of reheating the flue gas to the same exit tem-
perature by using the inline and indirect hot air reheat configurations.
As shown in Appendix A, the time-averaged ground-level S02 concentration
as proposed by Turner27 is given by the following expression:
where x * the pollutant concentration (lb/ft3)
x * distance downwind from stack (ft)
y » radius of the plume at (x,H)
H * height of plume center line relative to ground (ft)
u * wind speed (ft/min)
121
-------
TABLE 35. SEASONAL EFFECT OF REHEAT ON GROUND-LEVEL S02 CONCENTRATION
K>
Ambient Air Scrubbing znd
Temperature Degree of Ret eat
10*F, Winter Unscrubbed
Scrubbed with cj reheat
Scrubbed, 25*F reheat
Scrubbed, 50* F reheat
Scrubbed, 100*1 reheat
40'F, Spring-Fall Unscrubbed
Scrubbed with to reheat
Scrubbed. 25°F reheat
Scrubbed, 50* F reheat
Scrubbed, 100°F reheat
70°F, Summer Unscrubbed
Scrubbed with to reheat
Scrubbed, 25°F reheat
Scrubbed, 50°F reheat
Scrubbed. 100° 7 reheat
Maximum Ground Level
S02 Concentration
(Ug/mJ)
117
28
24
20
16
131
35
29
24
19
148
47
36
30
22
Distance at Which
Max! nun SO2 Occurs
(K.)
47
26
29
31
37
43
22
26
29
34
40
19
22
25
30
Z SO 2 Reduction
Compared to Unscrubbed
0
76
80
83
86
0
73
78
81
66
0
69
75
80
85
Bases:
(1) 15-mph wind speed
(2) Neutral atmospheric stability
(3) 600-foot stack height
(4) 24.6-foot stack diameter
(5) 500-MU plant (same coal as in Table 27)
(6) One-hour average concentrations
(7) 80 percent SOj removal in scrubber
(8) Stack gas velocities
(a) unscrubbed - 47.2 ft/sec
(b) scrubbed - 41.9 ft/sec
(c) scrubbed with 25*F reheat - 43.8 ft/sec
(d) scrubbed with 50*F reheat - i5.6 ft/sec
(e) scrubbed with 100*F reheat - 49.1 ft/sec
-------
Q = pollutant source strength (Ib/min)
a = horizontal dispersion coefficient (ft)
a = vertical dispersion coefficient (ft)
z
In this expression, only H, the height of the plume centerline, is affected
by the reheat method. The height of the plume centerline or plume rise is
expressed as:
1/3 2/3
H - h -f ^2£ £ (9
where H = height of plume centerline
h - stack height (ft)
F = buoyancy flux (ftVmin3)
x ™ downwind distance (ft)
u « wind speed (ft/min)
Reheat affects the plume rise through the buoyancy flux variable which can
be expressed as:
(10)
where V » velocity of flue gas in the stack (ft/min)
s
g = local acceleration due to gravity (ft/min2)
R » stack radius at exit (ft)
S
T * stack exit temperature (°R)
S
T - ambient temperature (°R)
The term V R 2 is directly proportional to the volumetric flow rate of
s s
the gas at the stack exit. If the same stack exit temperature is obtained
with both the inline and indirect hot air methods, then F will be greater
for the indirect hot air system. Looking at Equations 8 and 9, a higher F
value will result in a higher H value and therefore, a lower x value.
123.
-------
Assuming (1) the heat input with each reheat configuration (inline and
indirect hot air) are equal, (2) the specific heats of air and flue gas are
equal, (3) the stack diameter is the same for each configuration, and (4)
the gases can be described by the ideal gas law; it can be shown that
F = F
indirect inline
This result indicates that as far as ground-level pollutant concentrations
are concerned, the dilution effect of hot air injection makes the inline and
indirect systems comparable at the same heat input.
APPLICABILITY OF BYPASS REHEAT
The utilization of bypass reheat is limited by pollutant emission con-
straints. Consequently, the quantity of flue gas bypassed and the corre-
sponding degree of reheat are dependent on the 862 emission standards and
the attainable SOz removal efficiency in the scrubber. The restrictions
imposed by SOz regulations on the use of bypass reheat are discussed for
two cases:
(1) Old NSPS for steam electric plants
(2) Current NSPS for steam electric plants
Old New Source Performance Standards for SOz Emissions
Until June 11, 1979 the NSPS for S02 emissions from coal-fired steam
electric plants allowed the emission of 1.2 Ib of S02/106 Btu fuel input.
Based on this standard the fraction of unscrubbed flue gas that could be
bypassed can be determined with the following expression.
FBP
124
-------
where: FBP = fraction of total flue gas flow that can be bypassed
E * SOa removal efficiency capability of the scrubber
(fraction)
W = weight of fuel required for 106 Btu (Ib)
S = weight fraction of sulfur in the fuel
An approximation of the allowable fraction of flue gas which could be
bypassed under these standards is presented below for several different
coal qualities (assuming a 300°F unscrubbed stack gas temperature, a 130°F
scrubber exit gas temperature, and a scrubber with a maximum capability of
90 percent SOa removal).
Coal Quality Fraction of Approximate
Heating ValueSulfur Content Flue Gas That Stack Exit
Btu/lb Wt % Could be Bypassed Temperature, °F
8,500 0.5 1.00* 300
10,500 1.5 0.35 185
10,500 3.0 0.12 145
As shown, a substantial fraction of the flue gas could be bypassed when
firing low to medium sulfur (0.5-1.5 Wt %) coals.
Current New Source Performance Standards
The New Stationary Source Performance Standards for electric utility
steam generating units (published in 6/11/79 Federal Register) require
scrubbers with ^70 percent SOz removal efficiency for all coals. Included
in the standard is a maximum emission limitation of 1.2 Ib SOz/10 Btu fuel
input. This standard provides a sliding scale for required SOa removal with
high sulfur coals requiring about 90 percent removal and very low sulfur
coals requiring 70 percent SOa removal. An approximation of the
*No scrubber required
125
-------
maximum stack temperature that can be obtained with bypass reheat is given
below (assuming a 300°F unscrubbed stack gas temperature, a 130°F scrubber
exit temperature, and a scrubber with an average capability of 90 percent
removal) .
Average Required SO 2 Fraction of Flue Gas Approximate Stack Exit
Removal Efficiency, % That Could Be Bypassed Temperature. °F
70 0.22 165
80 0.11 147
90 0.00 130
Therefore about 35°F is the maximum stack gas reheat level that can be
achieved under current electric utility standards and this will only apply
for very low sulfur coals (unless extremely high S02 removal standards are
employed). It is recognized that the above analysis is quite simplistic
and does not consider the compliance requirements of the NSPS. Therefore
the potential reheat levels shown above are somewhat higher than an operating
plant could realistically achieve.
Energy Balance
Once the maximum allowable bypass fraction has been determined the
degree of reheat attainable can be calculated using the following energy
balance (as long as Tg _> dewpoint of the gas exiting the stack and all of the
mist carry-over is evaporated):
CP.BP(TBP-V * mfCP,f(VTfs>
m
-
+ m + n ) + -r-iy (v - v? ) + —2- (v2 -v2 )
f w 2g j f,s f,fs 2g j w,s w,fsj
126
-------
where: m = mass flow rate of bypassed flue gas (Ib/hr)
C = specific heat of the bypassed flue gas (Btu/lb-°F)
P > or
T p = temperature of bypassed flue gas (°F)
T = temperature of gas exiting the stack (°F)
mf * mass flow rate of gas exiting the scrubber (Ib/hr)
C * specific heat of gas exiting the scrubber (Btu/lb-°F)
Tf = temperature of gas exiting the scrubber (°F)
m = mist carry-over (Ib/hr)
w
h = enthalpy of vaporized entrained mist at the stack outlet
W'S (Btu/lb)
h , « enthalpy of the entrained mist exiting the scrubber (Btu/lb)
W i £ S
g = acceleration of gravity (ft/sec2)
g * conversion factor (ft-lb -
c m r
j «• mechanical equivalent of heat (778 ft-lb f/Btu)
Az = net elevation traversed by flue gas (approximately the
difference in duct and stack outlet height) (ft)
vf s = velocity of the flue gas at the stack outlet (ft/sec)
vf fg = velocity of the flue gas at the scrubber outlet (ft/sec)
v " velocity at the stack outlet of the vaporized entrained
' mist (ft/sec)
vw fg - velocity at the scrubber outlet of the entrained mist (ft/sec)
v - velocity of bypassed flue gas prior to mixing with
BP
scrubbed flue gas (ft/sec)
Qf * heat resulting from the work of compression by an induced
draft fan (Btu/hr)
Q » total heat lost from the duct and stack (Btu/hr)
Q - heat input using supplemental reheater (Btu/hr)
R
Assuming the sensible heat required for the vaporized liquid is negli-
gible and the required heat input associated with the kinetic and potential
energy terms is small, the energy balance equation is reduced to:
CP,BP(TBP-V ' mfCp,r 'V'fs' + Vw + Qtl - ^ - QR
127
-------
As indicated above, if an insufficient fraction of the flue gas can be
bypassed to effect the required reheat, then a supplemental reheater could
be used to heat the scrubbed gas further. This could be accomplished in one
of two ways:
(1) The reheater could be placed in the bypassed gas circuit.
Since this gas would be relatively dry and noncorrosive,
the reliability problems incurred with an inline system
would not be expected.
(2) The reheating could be done conventionally (inline,
indirect hot air, exit gas recirculation) for the com-
bined bypass and scrubber exit gases.
In summary, bypass reheat is the most economical method available for
stack gas reheat since waste heat is utilized and expensive heat exchange
equipment is not required. SOz emission standards will restrict the use
of bypass reheat somewhat. However, it is expected that industry will still
utilize bypass reheat to the degree allowed under current regulations. Sup-
plemental reheat in the manner described above will permit reheat of stack
gases to any level desired.
128
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«-5 a 2-f
SECTION 7
STACK GAS REHEAT ECONOMICS
The capital and operating costs of reheating a flue gas from a new
500-MW power plant were estimated for the inline, indirect hot air, direct
combustion, and exit gas recirculation reheat configurations. The stack
gas was heated 50°F above the scrubber exit temperature. These costs were
estimated (in mid-1978 dollars) using the following approach:
(1) A steam cycle for a new 500-MW power plant was developed;
those steam levels that could be used for reheat were
identified and their respective costs estimated. A cost
for hot water from the steam cycle was also estimated.
(2) The reheat exchangers were sized and their installed
costs (capital investment) estimated.
(3) The capital investment for direct combustion reheat
systems was estimated based on published information
for similar facilities.
(4) The operating costs of the various reheat configurations
were estimated.
The cost of using bypass reheat was not estimated since current S02
emission standards for new coal-fired power plants significantly restrict
its use. Fifty degrees (50°F) of reheat cannot be obtained using bypass
reheat* unless a supplemental reheater is used (see Section 6 for details).
However, the cost of bypass reheat is very low compared to other reheat
methods (no external energy and heat exchange equipment required). There-
fore it is anticipated that industry will continue to use bypass reheat to
the extent permitted by environmental regulations (see Section 6) and maxi-
mum scrubber S02 removal capability.
*Under the recently promulgated (June 11, 1979 Federal Register) NSPS for
utility boilers.
129
-------
After estimating the capital and operating costs of the various
configurations, an annual revenue requirement (consisting of operating
and capital investment-related costs) was calculated for each configuration.
This annualized cost was used to compare the costs of all the cases analyzed
in this study.
AVAILABILITY AND COST OF STEAM
The initial step in estimating the costs of the various SGR configura-
tions was to identify the steam levels that can be used for reheat and
estimate their respective costs.
(1) A steam cycle was developed for a "hypothetical"
new 500-MW power plant in which no reheat is used.
This steam cycle was considered to be the base case.
(2) Several steam levels (extraction steam from the
turbine) were identified as applicable for use
as a reheat medium.
(3) The impact (on the base case steam cycle) of using
each of the applicable steam levels for reheat was
determined. Based on this effect, the cost of each
steam level was estimated.
Steam Cycle Development and Applicability of Different Quality Steams to SGR
The development of the base case steam cycle is presented in detail in
Appendix C. In this steam cycle, nine levels of steam are hypothetically
available for use as the heating medium in a reheat system. These steam
conditions are presented in Table 36. Although throttle steam (at the
turbine inlet) could be used for reheat, it is assumed that this steam would
be too valuable to be used for reheat in a new power plant. The suitability
of the other steam levels in Table 36 for use in SGR was based on the cri-
teria thau (1) the steam temperature must be greater than the flue gas tem-
perature, and (2) the steam pressure should be greater than the flue gas
130
-------
pressure. The latter criterion insures that if a leak were to develop in the
exchanger the steam would leak into the flue gas instead of the flue gas
leaking into the steam system. Therefore, steam with pressure less than about
15 psia was considered unsuitable. Steam ranging in pressure from M5 psia
to high pressure turbine exhaust conditions was considered applicable. For
the base case steam cycle, applicable steam pressures ranged from 16 to 600
psia.
TABLE 36. AVAILABLE STEAM CONDITIONS IN THE BASE CASE STEAM CYCLE
Description
Throttle steam
Extraction steam
Extraction steam
Extraction steam
Extraction steam
Extraction steam
Extraction steam
Extraction steam
Turbine exhaust
Steam
Pressure
(psia)
2600
600
310
165
83
39
16
5.6
1.7
Conditions
Temperature
(°F>
1000
639
870
745
610
475
344
208
120
Applicability as
Reheat Steam
OK but very
expensive
Acceptable
Acceptable
Acceptable
Acceptable
Acceptable
Acceptable
Not acceptable
Not acceptable
Each of the applicable steam levels was analyzed to determine how its
use as reheat steam would affect the base case cycle. The steam cycle was
adjusted to provide the required quantity of reheat steam while maintaining
the 500-MW (net) output and constant enthalpy for all streams. These
analyses provided the following data for each steam level evaluated as
reheat steam:
(1) Additional plant fuel requirement?
(2) Change in plant condenser heat rejection requirements
(3) Change in steam flows in turbine and feedwater heaters
131
-------
The primary objective of this economic analysis was to develop and illus-
trate a methodology for estimating the costs of stack gas reheat systems. The
results can be used to illustrate the cost trends (not a rigorous calculation)
associated with the use of low through high pressure extraction steams. While
a particular steam cycle was chosen for analysis, the trends should be similar
for any steam cycle.
Cost of Various Steam Levels
Although it is recognized that steam costs are very site specific, the
relative costs of the different steam levels are expected to be similar for
other steam cycles. Consequently, the trends exhibited by the steam costs
developed in this section are considered to be applicable to other systems.
The annualized cost ($/lb steam) associated with using each of the
applicable steam levels for reheat (from the base case steam cycle) is also
developed in Appendix C. These annualized costs (presented in Table 37)
include the capital-related and operating costs incurred in producing the
reheat steam. To develop the dry, saturated steam costs, it was assumed
that the superheated steam was desuperheated by spraying condensate into
the steam. Some users of reheat have indicated that the use of dry, satu-
rated steam in SGR would result in more reliable operation compared to
operation with a highly superheated steam. Therefore, costs for dry, satu-
rated steam at the same pressure are also presented in Table 37.
It should be noted that the steam costs presented in Table 37 are rep-
resentative of a new 500-MW power plant with scrubber and reheat. If a
reheat system were retrofitted to an existing power plant, different results
would be expected. Depending on site specific factors for a particular
retrofit situation, steam costs may range from low (if the steam cycle can
easily be readjusted such that the plant power output is unaffected) to high
(if the power output is significantly reduced).
132
-------
TABLE 37. COST (1978 $) OF VARIOUS STEAM LEVELS FOR REHEATING FLUE GAS*
OJ
U)
Extraction Steam (Superheated) and Hot Water
Pressure
(psia)
600
310
165
83
39
16
Hot Water
165
Temperature
(°F)
639
870
745
610
475
344
366
Enthalpy
(Btu/lb)
1314
1457
1396
1335
1274
1213
399
Cost
($/1000 Ib)
1.95
2.27
1.93
1.60
1.22
0.83
0.24
Pressure
(psia)
600
310
165
83
39
16
-
Dry, Saturated Steam
Temperature
(°F)
486
420
366
319
266
216
-
Enthalpy
(Btu/lb)
1204
1204
1196
1184
1169
1152
-
Cost**
($/1000 Ib)
1.69
1.73
1.57
1.37
1.10
0.78
-
*For small quantities of reheat steam ($/1000 Ib) in a new 500-MW power plant. Coal cost is $l/106Btu.
**Saturated steam is desuperheated by spraying condensate into superheated steam. It was assumed
that the costs of the equipment required (pump, desuperheating vessel, and piping) to desuperheat
the steam are negligible compared to the cost of the steam. Therefore, the cost of saturated
steam was estimated using the following equation:
dry, saturated steam saturated liquid c-y-mnn IK /superheated\
, , X y/ -LL/v/v/ J.D f J
superheated steam ~ "saturated liquid steam
$/1000 Ib [saturated]
\ steam /
-------
REHEAT EXCHANGER SIZING
After estimating the costs for various levels of steam (for a new
power plant), reheat exchangers were sized on the basis of using superheated
and saturated steam. The initial step in each case was the determination of
the overall heat transfer coefficients. These coefficients are highly
dependent on the resistance to heat transfer due to fouling of the tubes.
Industry data indicated that inline exchangers are fouled by solids result-
ing from evaporation of scrubbing liquor carried-over from the mist elimina-
tor as well as residual fly ash in the flue gas. However, no specific
information about the resistance to heat transfer due to fouling was
obtained. In the case of mist carry-over, it is expected that the front
tubes will foul badly while the rear tubes will remain clean. Therefore
the lead tubes will have to be cleaned on a more frequent basis. Thus,
safety factors should probably be added as excess tubes rather than by
estimation of a fouling factor. The safety factors incorporated in the
reheater designs are presented in Table 38.
For both superheated and saturated steam, the film heat transfer coeffi-
cient for steam is much greater than the flue gas film coefficient. Conse-
quently, the flue gas film was considered to be the controlling resistance
to heat transfer in the exchanger and therefore, to have the greatest
impact on the overall heat transfer coefficient. An analysis of the flue
gas film coefficient for reheat exchangers showed that this coefficient is
dependent on: 1) flue gas properties, velocity, and temperatures (entering
and exiting the exchanger), 2) tube spacing, and 3) the pressure drop
experienced by the flue gas in the exchanger. A calculational scheme rela-
ting these various parameters, the flue gas film heat transfer coefficient
and the resulting exchanger heat transfer area was developed. The expres-
sions used in the development of this calculational scheme are presented
in Appendix D.
134
-------
a-S a
TABLE 38. CAPITAL AND OPERATING COST BASES* USED TO DEVELOP
ECONOMICS OF VARIOUS REHEAT CONFIGURATIONS
Uaea Ua«d In Study
UptC«l Co»C
exchanger Tub* Metallurgy
Required Exchanger Are*
- InllM Reheat
bit CM ieclrculatlo* tefceat
Indirect Hat Air
Exchanger Tub* Lift and Co*C*»
- Inline K*h*at
—carbon ac**l
— U*L at*lnl*ea *C**1
*-l«COMl 615
• lad 1 race Hoc Air fcehaat
—carbon a teal
• Kilt Gae Raclreflation ftaheat
—carbon tteel
Primary and Auxiliary Faa Siting
and Coat*
Soot Blower COM*
Dlr«cc Ubor end Materlala Coat
(loatallatlo* o( rtb*«t *mcnanger)
Indirect Coaca
SC**m Coat a
tarar Coat a
Halntenanc*
C«rben »et*l tub* •*t*Uurgy «• «v»lu-
«e*d far lalta*. tat, *M lodlr*cc hoe
•lr Injection. Se*laL«t ict*l Typ« 316
*n4 Ineon«l 613 v*r* *1M *v«luAC*d for
inlln* lyiccM.
To ptowld* • ••(•ty factor for plut|in|
«ad fmilinf, « 3" c*nt»r-c*aE»r tub«
•••clni **M iu«d *ad th* c*lcul«ctd
*wh«it*r aurfac* *r*« wu lacr*a**d
by 21t.
To «r«vld« • Mf*ty (actor for »lu«|ia|
wd foulini a 3" cantar-cantar Cub*
•paelai «•• UMd and th* calculated
axehaa|*r turfac* araa waa taeru**d
by 23X.
A 1.3" e*nc*r*cancar tub* (pacing waa
u**d and • 10Z aaftty 'actor w*a Incor-
porated Into tb* *>chMt«r aurfaca araa.
KO/fc1; 0.10" Mil thloltnaaa, 2-yr Ufa
|3«/ft'| 0.10" Mil thlckneaa, 4-yr Ufa
170/d1; 0.10" v»U tttiekaasi. 5-yr li'a
111/ft1; 0.03" Mil ehlcknaaa, 10-yr Ufa
$20/ft:; 0.10- Mil chlekncaa, 5-yr lift
CoMputat progru uaod to ilia and
c**t tana,
B«a* cas* coac of *tack !• 2.6MNI for
* 300' auck wlch a 22.4' diaMt*r.
Baa* coat * U700/«ach
JB9.100 plua 113.40/fc1 of *Mhani*r
fur£ac« art* (R*f. 33).
btuala 43X of total diract c»ata
<*qutp**nt coata plua direct labor
MO* MCarlal* coac)
Optra tint Coat I«l«tad Uaea
St*a> coata |lvan 15 T*«la 37
90.0114/k«h
laaed on direct labor and Mterlali
coat, capital co*c of *nhan(*r, and
tub* Ufa
Uaad on 25-yr atraliht-LlM dapreelatlon
Annualiiad Coet of Confljuration
ARR • K * C/M + (0.0»5 yr"1) C
All • Amtu*l |t*v*au* R**ulre«*nt
H • Operating Coaci (1/yr)
C • Capital Inveecteflt (!)
H • KqulOMnt Lift (yra)
3«« Appandlx D for
exchanger ailing.
S*« Appendix C for d*vtlop«*nt of axehangar
See App«n41x 0 for baeei of coa^utattona.
Th* Indirect hot air configuration Incraaa**
voluMttrlc flow rat* of flu* (••; it eh*
•tick ga* velocity la to r***in tha aa*e,
th* dla**ter of * propoa*d stack would hav*
to ba ineraaaed, Con«*qu*ncly, It* coat
would, alao, Increaa*. 5*a Appendix D for
detailed development.
S«« Append IK D far J*velop«i*nE of >>**•».
Sat Appendix K for development of b*a«a.
S*« Appaodix E for d*v*loF**nc of b*aei.
See Appendix C for development,
S*« Appendix I for development.
Sa* Appendix E for development.
Th* AM reflect* th* capital and operating
coat componentn ciaoclated with each con-
figuration. For purpa*«* of thla atudy.
a 25-yt iEr*lght~line tqulpment deprectatioa
w«a uaid. See Appendix C for economic baaes
No additional coat h«a b**n Included tor
loat powtr gmcratlon capability If
r*heat*r downtleja ou**i th* boiler
to r*duc* load oc ahut down.
•AH eoet« are •ld-1978*.
**tMhaog*r coat, r.o.ft. plant. ,Ul tubas ar* 1 Inch O.D.
135
-------
It should be noted that for the exchangers in the inline and exit gas
recirculation reheat configurations, a triangular pitch exchanger was
selected with a tube spacing of 3 inches center-center (or 2 inches between
tubes) because industry data show pluggage is common at lesser tube spac-
ings. The overall heat transfer coefficients for the condensing portion* of
these exchangers were calculated to be 17 to 32 Btu/hr-ft2-°F, while the
coefficients in the desuperheat section* of these exchangers ranged from 16
to 19 Btu/hr-ft2-°F. For the exchangers in the indirect hot air reheat con-
figuration, a tube spacing of 1-1/2 inches center-center (0.5 inch between
tubes) was assumed. This reflects the clean conditions expected to exist in
these exchangers. The overall heat transfer coefficients for the condensing
portion* of these exchangers were calculated to be 24 to 42.5 Btu/hr-ft2-°F.
The value of the overall coefficient in the desuperheat section* ranged from
20.9 to 27.8 Btu/hr-ft2-°F.
COSTS OF VARIOUS REHEAT CONFIGURATIONS
After the exchangers for the various configurations analyzed in this
study were sized, the following approach was used to estimate the costs of
these configurations.
(1) The capital investment and operating costs associated with
the inline, indirect hot air, and exit gas recirculation
configurations were estimated using each level of saturated
steam shown in Table 36.
(2) One case developed for each configuration in step (1) of
this approach was selected as a "base case."
3) Various parameters (exchanger pressure drop, fan position,
etc.) of each configuration's base case were changed in
order to determine the impact of each parameter on the costs.
Also, the impacts of using superheated steam and different
tube materials were investigated.
*Exchangers using superheated steam were designed with separate desuperheat
and condensing sections. Exchangers using dry, saturated steam would have
overall heat transfer coefficients similar to the condensing section
coefficients.
136
-------
.s-S 3
(4) The capital investment and operating costs associated
with direct combustion reheat were estimated.
(5) An annual revenue requirement (ARR) was calculated based
on the capital investment and operating costs so that the
costs of the various systems could be compared.
The technical and economic bases used to develop the overall economics
of the different reheat configurations are presented in Tables 38 and 39,
and Figure 17. For this study, the flue gas was reheated by a nominal 50°F
(the level indicated most by industrial users in the survey-see Section 5).
Economics of Inline Reheat Configuration
To estimate the costs of reheating the flue gas from a new 500-MW plant
(described in Table 39) with an inline reheater and various dry, saturated
steam levels, the following assumptions were made:
(1) The flue gas was reheated by 50°F, which is equivalant to
a heat input of about 66.8 x 10s Btu/hr.
(2) It was assumed that no mist entrainment was present in the flue
gas and that no heat was lost from the flue gas through the walls
of the duct or stack.
Initially, only a forced draft primary fan configuration (Figure 17b)
having an overall pressure drop of 40 inches of water and the use of dry,
saturated steam were considered. The capital and operating costs associated
with using 600 psia, saturated steam as the heating medium in this configura-
tion are presented in Table 40. Cost summary sheets for the other saturated
steam levels analyzed are presented in Tables E-l through E-7 in Appendix E.
Table 40 shows that the capital requirement for this configuration
consists of the direct and indirect costs that are necessary to make an
inline reheat system operational. In addition to the reheat equipment,
incremental capital investments are included for other equipment which
must increase in capacity if a reheat system were to be incorporated into
137
-------
TABLE 39. PLANT CHARACTERISTICS AND FGD CONFIGURATIONS USED TO
DEVELOP ECONOMICS OF VARIOUS REHEAT CONFIGURATIONS
Power Plant Bases, Fuel and Flue Gas Compositions
Power Plant
Characteristics
• New, 500-MW
• 9,000 Btu/Wh
Heat Rate
• Flue gas temperature
entering scrubber Is
300'F
Coal Cot
Component
C
H
N
0
S
Cl
H20
Ash
Heat Content
aposit ion
Weight
Percent
57.56
4.14
1.29
7.00
3.12
0.15
10.74
16.00
10,500 Btu/lb
Flue Gas Composition Entering
Volume
Component Percent
HI 73.76
02 4.83
C02* 12.31
S02 0.24
SOj 0.0024
NOX 0.06
HC1 ' 0.01
HZ0 8.79
Scrubber
Ib/hr
3,450,000
258,200
904,200
25,130
317
3,022
661
264,500
4.906,030
^includes a small amount of CO
Primary Fan Arrangement and Equipment Pressure Drop Assumptions
Equipment Pressure Drop
• Bailer A? - 22 in. H20
• Scrubber A? • 9 in. HjO
> Reheat Exchanger
iP - 6 in. H20
• Sock, Duct Work
iP • 3 in. H20
Impact of Fan Location on Flue Gas Composition and Adiabatic Saturation Temperature
Fan Configuration
Forced Craft
34"AP
(Figure 17a )
130
Forced Draft
40"iP
(Figure 17b)
131
Induced Draft
40"4P
(Figure 17c)
126
Saturation Temperature (*F)
normalized Flue Gas
Composition
Component
HI
02
co»
H20
5.139.000 5.142.000 5.120,000
Note: The flue gas specific heat of each configuration was calculated to be
0.26 Btu/lb-*F.
Ibs/hr
3,471,000
259,700
909,600
498,400
Ibs/hr
3,471,000
259,700
909.600
501.600
Iba/hr
3,471,000
259,700
909,600
430,100
138
-------
S 3
Temperature
(°F)
-x-300
^320
M30
Pressure
(in. H20)
376.8
410.8
401.8
398.8
Fuel
Stack
Boiler
Scrubber
(a) Forced draft FGD system with no reheat (overall pressure drop
34 in. H20)
Temperature
CF)
^300
•\-320
M.31
M.81
Pressure
(in. HjO)
376.8
416.8
407.8
401.8
398.8
/^\ > . V^ J_J"\
____i
Forced
Boiler Draft
Fan
i
<§>/Z>f <§> )
)C/ '_ '
Scrubber Exchanger
Stack
(b) Forced draft FGD system with inline reheat (overall pressure drop
40 in. H20)
4>
Temperature
(°F)
^300
M26
-V156
M76
-V176
Pressure
(in.
Stack
Fuel—»
Boiler
Scrubber
Reheat
Exchanger
Induced Draft
Fan
(c) Induced draft FGD system with inline reheat (overall pressure drop
40 in. H20)
Figure 17. Schematics of different fan arrangements used to develop
economics of various reheat configurations.
139
-------
TABLE 40. COST SUMMARY SHEET FOR INLINE REHEAT
(600 psia, dry saturated steam)
Scrubber
Flue Gas
J«qairtd Htat issue (13'3cu/'nr) -66.8
Serubbtd Flat Ga*:
T«ap«racurt (•?) • 131
Flow a*ct (lb«/hr) - 5,140,000
Sthtac Sctao:
Ttmptracurt C'F) - 486
?rts»urt (psia) - 600
Flow EUct Clbt/hr) - 91,300
To Stack
Stae* ixi; Taaiptracurt (••)
^•circulation Exit 543 .-
Ttmptracurt C'F) -
Flow iUci Ubi/hr) -
iUhtac Air .-
Ambitnc Ttnptraeurt (•") -
Htactd Ttaptracurt (•?) -
Flow iUci (Ibi/hr) -
181
spgcirtCATTass A.VD CAPITAL l
Toc»l
181
So. RtVd.
4 8,100.::;:)*
Total - Incr«m«ncal
20
ixic Ttmp. t'F. _____
Exchanjtr iP (in.H,0) - 6
Condensing Htat Transfer Coefficient (Scu/hr-fs'-'F) -
Suptrhtat H«at Transfer Coefficient (Bcu/hr-fc'-'F)' -
!°*: 3240 4
31.5
s 38.000 Meh
Tocal Co»: (S)
162,000
151,000
Auxiliary Fan* •
i? fia.a.QX - ,~ ~ ~ 5 ~ ,aeh
Incremental
5 tacit Cost-:
Seee 3iav«» : 16 S 1,700 «,sH
27 000
Tocal Equipment Cose*
Direct Labor and Mactrials Cose (far txehangtr and looc blower inscallacion)
Indirect Costs (^ST, si Tocal iquiptntnt and Dirtcc Labor i Macerial Coses)
TOTAL CAPITAL ISVBSTSST
OP_SATTSC COSTS
:tta Quanelcv Ur.irtd Cost/Unit Tatai
5c«im/Hoe Vactr 91,300 (Ibs/hr) 1.69 cs/T.fl'l.h,\
iUeeriei:/ /»-,i/ "U~
?ri=.ry Fan 1.^60 (kv) 0.0314 (s/kwh)
J4U.UUO
198.000
^^^,000
' /HO. 000
Annual Cos:' Si
1,080,000
321,000
Xainttnanct and iUplaccswnc Cos;
3«prtciaeion
UOKAL JKVSHKt 5£QUta£3
118.000
31.000
l.bbU.OOO
' 1,624,000
*Araa s.-.own is 10". jrtactr :r.an arta calculattd.
Cvtrill XtaC :rans:tr Cotfficitnc far fondtnsin; portion ac txchanjtr.
jlv«ra-'- -.tit trans:tr cottiizitr.: far dtsu?«rntac portion oi txchanztt.
"?riaary fan'J iast iiz« jsrrtSBonds :o a forstd irai: "0 proctss vi;iioi.
'Auxiliary' fan rtcuirtd for indirect hot ai; and «xi; tin rtcirtulacion eoniijuracions
•tr.cTtotncal itacic coj; txp«ri«nc«.t :an and inert
jtack sosti included in this local art isscalltd costi.
140
-------
the base case design (Figure 17a). An example is the increase in the
capacity of the primary fan due to the increased system pressure drop that
results from the addition of an inline reheat exchanger.
The results of estimating the costs associated with reheating flue gas
with an inline reheater and various levels of saturated steam are summarized
in Table 41 for an exchanger constructed with carbon steel tubes. The data
in this table show that the exchanger surface area increases as the steam
pressure decreases due to corresponding decreases in the temperature driving
force. This increases the total capital investment as the steam pressure
decreases from 600 psia to 16 psia. The operating costs, which are influ-
enced by the quality of steam required for reheat, decrease as the steam
pressure decreases from 600 psia to 83 psia; at 39 psia the operating costs
begin to increase and reach their highest level at the lowest steam pressure,
16 psia. Comparison of the data in Table 41 shows that the most economical
saturated steam level to use in a forced draft inline reheat configuration
(with carbon steel tubes) may lie in the range of about 80 psia to 200 psia.*
Based on these findings, it is expected that higher fuel (coal) costs will
shift the optimum steam pressure downward. Also, higher exchanger costs
(with stainless steel and Inconel 625 tubes) would tend to shift the optimum
steam pressure upward.
Economic Sensitivity Studies for Inline Reheat Configurations—
Several sensitivity studies were conducted in order to determine how
changes in various parameters would affect the costs of an inline reheater.
For these studies a steam quality, fan arrangement, exchanger pressure drop,
and tube material were selected as base case parameters. These parameters
are:
*The economics developed in this study are based on many assumptions. With
this in mind, the reheat costs for steam pressures greater than 16 psia
are all fairly comparable.
141
-------
TABLE 41. COSTS OF INLINE REHEAT USING VARIOUS DRY, SATURATED STEAMS
Dry, Saturated
Steam Pressure
(psia)
600
310
165
83
39
16
Hot Water
(165)
Steam
Required
(Ibs/hr)
91,300
82,900
78,000
74,300
71,500
69,100
534,000
Exchanger
Area
(ft2)
8,100
10,800
14,500
20,900
33,800
73,300
23,000
Total Capital
Investment
($io6)
0.78
0.91
1.09
1.40
1.90
3.94
1.50
Operating
Cost
($106/yr)
1.55
1.51
1.42
1.36
1.36
1.75
1.57
Annual Revenue
Requirement
($106)
1.62
1.60
1.52
1.49
1.54
2.13
1.71
Bases:
(1) New 500-MW power plant described in Table 39.
(2) Exchanger pressure drop equals 6 in. H20.
(3) Flue gas is heated 50°F.
(4) Mist carryover from the scrubber and duct and stack heat losses are considered negligible.
(5) 66.8 x 106 Btu/hr heat input in the reheater.
(6) Bases for exchanger sizing given in Appendix E.
-------
Steam Pressure: 165 psia, dry, saturated steam
Primary Fan Arrangement; Forced draft
Exchanger Characteristics: (a) pressure drop - 6 in. H20
(b) tube material - carbon steel
(c) tube life - 2 years
Annual Revenue Requirement (ARR): $1.52 x 106/yr
The results of the sensitivity studies conducted for the inline reheat
configuration are summarized in Table 42. Also, presented in this table is
a comparison of the annual revenue requirement for each case with that of
the base case. The bases and results of the sensitivity studies are
described below:
Case A - The tube material is changed from carbon steel (in the
base case exchanger) to 316L stainless steel in this case.
It was estimated that the use of 316L SS would increase
the tube life from 2 years (base case) to 4 years based
on information obtained from the reheat survey (Section 5).
The ARR increased by about 2 percent compared to the base
case ARR. The ARR increase is the result of the substan-
tial increase in capital requirement resulting from the
use of stainless steel tubes.
Case B - In this case, the exchanger tube material is Inconel 625.
Based on heat exchanger vendor information, it was estimated
that the use of Inconel 625 would increase tube life to about
eight years. This very expensive alloy results in the ARR
being about 6 percent higher than the base case ARR.
Case C - In this case, the exchanger pressure drop is designed as
3 in. HaO. It was anticipated that the lower pressure
drop would increase the surface area requirements of the
exchanger. Consequently, increased capital costs and
decreased operating costs were expected for Case C com-
pared with the base case.
The results of this analysis show that the design of an
exchanger with a 3 in. HjO pressure drop results in an
8 percent lower ARR requirement compared to the base
case ARR. Although the lower pressure drop slightly
increases the exchanger surface area and capital costs,
the savings in operating costs due to the decreased
primary fan energy requirement is the overriding
factor.
143
-------
TABLE 42. SUMMARY AND COMPARISON OF ECONOMICS FOR INLINE REHEAT (SENSITIVITY ANALYSES)
Cases
Studied
Base Case
Sensitivities
• Case Ab
• Case B°
• Case C
• Case D
• Case E
• Case F
• Case C
Reheat
Steam
Quality
165 psia.
dry.
saturated
165 psia.
dry.
saturated
165 psia.
dry.
saturated
165 psia.
dry.
saturated
165 psia.
superheated
165 psia.
dry.
saturated
165 psia.
dry,
saturated
165 psia.
dry.
saturated
Primary
Fan
Position
forced
draft
forced
draft
forced
draft
forced
draft
forced
draft
induced
draft
induced
draft
forced
draft
Stack Exit
Temperature
CF)
181
181
181
181
181
176
197
181
Exchanger
Pressure
Drop
(in. HZ0)
6
6
6
3
6
3
6
6
Tube
Life
(years)
2
4
8
2
2
2
2
1
Total
Capital
Investment
(10'$)
1.09
1.49
2.14
1.13
1.05
0.51
0.90
1.09
Operating
Cost
(10'$/yr)
1.42
1.41
1.41
1.29
1.40
0.55
1.11
1.60
Annual Impact on Base
Revenue Case ARRa
Requirement 7, %
(10'$) Increase Decrease
1. 52 base case
1.55 2
1.62 6
1.40 8
1.50 1
0.59 61
1.19 22
1.70 12
.Annual revenue requirement
Exchanger tubes constructed of 316L stainless steel; tube life assumed to be 4 years.
Exchanger tubes constructed of Inconel 625; tube life assumed to be 8 years.
Bases:
(1) rlue gas is nominally reheated by 50'F. Mist carryover and heat losses are assumed to be negligible.
(2) Tube material and tube life in base case exchanger are carbon steel and 2 years, respectively.
(3) New 500-flW power plant described in Table 39.
(4) Bases for total capital investment, operating cost, and annual revenue requirement given in Appendix C.
(5) 1978$
-------
Case D - Superheated steam (165 psia, 745°F) is utilized as
reheat steam in Case D. As expected, the use of super-
heated steam reduces the capital requirement; however,
the overall benefit achieved by using superheated
steam instead of saturated steam is marginal (approxi-
mately a one percent decrease in the base case annual
revenue requirement).
Case E - In this case, the fan is repositioned to follow the
scrubber and reheater (induced draft). The pressure
drop in the exchanger is 3 in. HjO. The induced draft
fan increases the flue gas temperature by about 20°F
due to the work of compression; consequently, the re-
heater need supply only about 30°F of heat input com-
pared to the 50°F input required with the forced draft
primary fan configuration. A schematic of an inline
reheater being utilized with an induced draft fan is
presented in Figure 17 C.
This case shows the benefit to be gained by using the
work of compression of an induced draft primary fan
to supply a portion of the desired reheat.
Case F - Some users of inline reheaters who responded to the
OMB-approved questionnaire indicated that 50°F of
reheat should be added to the flue gas prior to its
entering an induced draft fan in order to protect
the fan against corrosion. Consequently, this case
involves the use of the same configuration as Case
E (Figure 17C). However, the reheater supplies 50°F
of reheat; while the fan adds another 20°F due to the
work of compression. Thus, the resulting reheater
gas exit temperature is 708F greater than the scrubber
exit temperature.
Although this case exhibits the poorest economics
of the induced draft cases studied, it is still
economically attractive compared to the forced draft
primary fan cases evaluated.
Case G - In this case, the base case tube life is changed
from 1 years to 1 year to illustrate the sensitivity
of the economics to a change in tube life without a
change in tube material.
The cost summary sheets developed for these cases are presented in Tables
E-8 through E-14 in Appendix E.
-------
The economics (capital requirements and operating costs) for inline
reheat systems (with different exchanger tube materials) are summarized
in Table 43. The data show that both the capital investment and ARR
increase when higher priced alloys are used.
Summary—
Based on the various studies conducted for inline reheat, the following
are concluded:
(1) The use of more expensive alloys such as 316L SS and
Inconel 625 will substantially increase the capital
requirement of an inline system. The annual revenue
requirement is affected to a lesser degree, however,
since longer tube life is expected. Reheat users
should consider using expensive alloys in the front
of the exchanger and less expensive materials (corten
or carbon steel) at the rear of the exchanger.
(2) The annualized cost of an inline reheat is highly
dependent on tube life. Therefore, factors that
would influence tube life (mist eliminator performance
soot blowing, tube material) are important parameters
to be considered in designing an inline reheat system.
(3) For the bases used in this study, the lowest costs
for reheating a flue gas with an inline reheater
were attained with the use of medium pressure steam.
(4) The advantage of using a superheated instead of a dry satu-
rated steam of the same pressure appears to be marginal
(5) The use of an induced draft primary fan to supply a
portion of the desired reheat has significant economic
advantages over a forced draft arrangement. However
the viability of this concept is dependent on protection
of the fan from corrosion.
(6) An optimum exchanger pressure drop (gas-side) appears to
be closer to 3 in. HaO than 6 in.
Economics of the Indirect Hot Air Reheat Configuration
Two heat input bases were used to estimate the costs of utilizing the
indirect hot air configuration. In the first basis, it is assumed that
146
-------
TABLE 43. EVALUATION OF EXCHANGER TUBE METALLURGY FOR INLINE REHEAT (1978 $)
Reheat Exctianger
Tube Material
Dry, Saturated
Steam Pressure
_*
4.6
2.9
1.5 1.6 2.1
1.9
l.t>
Annual Revenue
Requirement
<10'$/yr)
1.8
1.6
1.6
1.7
1.7
*Heans that the economics were not estimated for that case
Reheat Exchanger Bases:
(1) See Table 38 for exchanger sizing and cost development.
(2) Forced draft primary fan arrangement (see Figure 17a).
(3) Exchanger AP - 6 In. H2O.
(*) Flue gas is reheated 50*F.
-------
the quantity of heat added to the ambient air before it was mixed with the
wet flue gas is equivalent to the heat added to the flue gas by an inline
reheater supplying 50°F of reheat. This basis reflects the results developed
in Section 6 which show that the heat required to prevent visible plume for-
mation is approximately the same for the inline and indirect hot air config-
urations. It was also shown in Section 6 that the two configurations have
comparable impacts on ground-level pollutant concentrations when equivalent
heat inputs are used. For a 500-MW power plant, a heat input (to the flue
gas) of 66.8 x 10 6 Btu/hr* is required to provide 50°F of reheat with an
inline reheater. Depending on the steam level used for reheat, the use of
the indirect hot air configuration to input 66.8 x 106 Btu/hr resulted in
the flue gas-heated air mixture having a stack exit temperature that varied
from 133-165°F. This temperature range reflects the different hot air tem-
peratures and flow rates that result from the use of the various steam
levels.
The second basis reflected the response obtained from reheat users
indicating that an approximate 50"F increase in the stack exit temperature of
the scrubbed flue gas-heated air mixture was needed to protect downstrea
equipment. Based on this information, the stack exit temperature was
defined to be 50°F hotter than the scrubber exit temperature. Achiev'
this temperature rise in a forced draft primary fan arrangement resulted
in a 180°F stack exit temperature.
Initially, only dry, saturated steam levels and a forced draft pri
fan arrangement were considered during the sizing and subsequent cost esti-
mation of the indirect hot air configuration. Since each steam level had
a different condensing temperature, several air approach temperatures
(temperature difference between the temperatures of the entering steam and
the exiting air) were evaluated for the different steam levels. A simplif' d
schematic of a forced draft primary fan, indirect hot air reheat configura-
tion is presented in Figure 18. An example cost summary sheet which shows
*See bases on page 137.
148
-------
the capital and operating costs that must be considered for this configuration
is presented in Table 44. As this table shows, the capital investment for
this configuration not only includes the costs of the exchanger and auxiliary
air fan, but also includes an incremental stack cost. Since indirect hot air
reheat increases the mass flow rate of the flue gas, the incremental stack
cost reflects an increase in the base case stack size in order to keep the
stack velocity constant. It was assumed that no soot blowers were needed for
this configuration because the air being heated is considerably cleaner than
flue gas. Cost summary sheets for cases based on both the assumed 180°F
stack exit temperature and the assumed heat input of 66.8 x 106 Btu/hr are
presented in Tables E-15 through E-25 in Appendix E.
Forced Draft
Fan
To Stack
Steam or
Hot Water
Air
Auxiliary
Fan
Reheater
Figure 18. Simplified schematic of indirect hot air reheat
configuration with a forced draft primary fan
arrangement.
The costs developed for the indirect hot air configurations are
presented in Table 45. This table shows that for the same steam pressure
and air approach temperature, the costs of those cases in which a heat input
of 66.8 x 106 Btu/hr was specified are significantly less than the costs of
those cases in which a 180°F stack exit temperature is required. However,
the maximum stack exit temperature attained in any case for the heat input
of 66.8 x 10s Btu/hr is 165°F and a minimum stack exit temperature of 133°F
is attained when 16 psia, dry, saturated steam is used as the heating medium.
Since many reheat users indicate that (1) equipment protection is the
149
-------
TABLE 44. COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(600 psia, dry saturated steam, air approach
temperature = 80°F, AT
flue gas
50°F)
CONFIGURATION:
Scrubber
Flue Gas
—3
Required Heat Input UO«Bcu/hr) - 102
Scrubbed Flu* Gaa:
T«mp«r«tur« OF) - 130
Flow Rat. (lb»/hr) - 5 14Q QQQ
Reheat Steam:
Stack
Air
Stack Extt T«mp«ratur« CF) - 180
Temperature (*F) -
Pressure (psia) -
Flow Rat. (Ib./hr) - 138,000
Recirculation Exit Gas:
Temperature CF) -
Flow Rate (Ibs/hr) -
Reheat Air:
Ambient Temperature CF) - AQ
Heated Temperature CF) - 4Q6
Flow Rat. (lb,/hr) - 1,180,000
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
486
600
Item
Total
Capacity
No. Req'd.
* 21,500^. 7
Total - Incremental
Cost/Unit
Reheat Exchanger:
Exit Temp. CF) -406
Exchanger AP (in.HjO) - ft
Condensing Heat Transfer Coefficient (Btu/hr-ft'-'F)b - 26 .
Superheat Heat Transfer Coefficient (Btu/hr-fC2-*F)C -
Primary Fand:
Size (HP) - 2755 4
Total Cost (Si
237,000
6P (in.HiO) -
Auxiliary Fan* :
ap (in.H.O) -
Incremental
Stack Coscf:
Soot Blowers :
34 •*^-
9.3 4 114 (HP) $22.800 ..,„
S each
Total Equipment Coat'
Direct Labor and Materials Cost (for exchanger and soot blower installation)
Indirect Costs (457. of Total Equipment and Direct Labor & Material Costs)
TOTAL CAPITAL 11
((VESTMENT
91
ZA_»
286
- filA
- -.378;
- ^06*
i^QR
nnn
uuy
nnn
_nnn
000
000
QQQ_
OPERATING COSTS
Item Quantity Required Cost/Unit
Steam/Hot Water 138,000 (Ibs/hr) 1 . 6
-------
TABLE 45. ECONOMICS OF USING DRY, SATURATED STEAM IN INDIRECT HOT AIR REHEAT SYSTEMS
Bases
For
Studies
180T
Stack Exit c
Temperature
66.8 x 10'
Btu/hr ,
Heat Input
Steam
Pressure
(psia)
600
310
165.
165
165
600
310
165
165
165
16
Air Approach8
Temperature
<-F)
80
80
40
80
120
80
80
40
80
120
80
Required
Heat Input
(108 Btu/hr)
102
117
122
142
188
66.8
66.8
66.8
66.8
66.8
66.8
Stack Exit
Temperature
(•F)
180
180
180
180
180
165
162
161
158
155
133
Steam Exchanger^* Capital
Required Area Cost
(105 Ibs/hr) (ft*) (10$')
138
143
140
164
216
90
82
77
77
77
67
21
27
43
35
35
14
15
24
16
12
19
,500
,500
,900
,300
.500
.100
.700
,100
.600
,600
,900
1
1
2.
2.
2
0.
1.
1.
1.
1.
1.
.40
83
.47
40
.90
.97
09
40
20
14
98
Annual
Operating
Costs
(10'$/Vr)
1
1
1
2
2
1.
1.
1.
1.
1.
0.
.80
.96
.83
.12
.81
19
13
01
00
01
72
Annual
Revenue
Required
O0'$)
1.94
2. 14
2.06
2.35
3.09
1.28
1.23
1.14
1.11
1.12
0.90
?This temperature represents the approach of the air temperature leaving the reheater to the entering temperature of the steam.
Area shown includes a 10 percent safety factor.
°Reflects survey responses which indicate that the stack exit temperature is typically heated to a level about 50°F above the
.scrubber exit temperature in order to protect downstream equipment from corrosion.
Equivalent to reheating a flue gas (with an inline reheater) by 50°F assuming no mist entrainment and no stack or duct work
heat loss.
Bases:
(1) New 500-MW power plant
(2) No mist entrainment or heat losses occur downstream of the mist eliminator.
(3) Forced draft primary fan configuration
(4) Exchanger pressure drop = 6 in. HjO
(5) Ten year tube life
-------
primary reason for the use of reheat and (2) a 50°F increase in the stack
temperature is required to adequately protect downstream equipment, it is
likely that most indirect hot air reheat systems will be designed based on
a specified stack exit temperature rather than a specified heat input to th
gas.
A comparison of the cases presented in Table 45 which are based on a
180°F stack exit temperature shows that the lowest costs correspond to the
600 psia, dry, saturated steam case. This indicates that the higher cost
for high pressure steam is more than offset by lower exchanger surface are
and energy requirements compared to the low pressure steam cases.
Sensitivity Studies for the Indirect Hot Air Reheat Configuracion—
During the saturated steam studies, several parameters which could have
a significant impact on the indirect hot air reheat configuration were iden-
tified. In order to quantify their impact, an indirect hot air reheat case
was selected as the base case for a design parameter sensitivity study Thl
base case is defined below.
Reheat Level: Based on the stack exit temperature being 50°F
greater than scrubber exit
Reheat Conditions: Dry, saturated, 165 psia steam
Fan Configuration: Forced draft primary fan (see Figure 18)
Exchanger Characteristics: (a) pressure drop = 6 in. H20
(b) carbon steel tubes
(c) tube life = 10 years
(d) air approach temperature = 80°F
Annual Revenue Requirement: $2.35 x 10s
The results of the indirect hot air reheat sensitivity studies are
presented in Table 46. The bases and results of these sensitivity studies
are discussed below:
152
-------
TABLE 46. SUMMARY AND COMPARISON OF ECONOMICS DEVELOPED FOR INDIRECT HOT AIR REHEAT
SENSITIVITY STUDIES
Bases
for
Studies
Base Case
Sensitivity
Studies
- Case A
• Case B
• Case C
• Case D
• Case E
Cn
U)
Bases:
Steam
Quality
165 psia.
dry,
saturated
165 psia.
dry.
saturated
165 psia.
745-F.
superheated
165 psia.
dry.
saturated
600 psia.
dry.
saturated
600 psia.
639*F,
superheated
Fan
Position
forced
draft
forced
draft
forced
draft
induced
draft
induced
draft
induced
draft
Stack Exit
Temperature
CF)
180
180
180
175
193
176
Exchanger
Pressure
Drop
(in. H20)
6
12
6
30
30
30
Air
Approach
Temperature
CF)
80
80
80
(in con-
denser)
80
40
40
(in con-
denser)
Heat
Input
Required
(Btu/hr)
142 x
142 x
117 x
109 x
120 x
81 x
10'
10'
10'
10'
10'
10'
Capital
Invest-
ment
(10$')
2.40
2.29
1.94
1.10
1.07
0.61
Annual
Operating
Costs
(10$' /yr)
2.12
2.19
1.70
1.30
1.78
0.82
Annual
Revenue
Reauired
UO^/yr)
2.35
2.41
1.89
1.41
1.89
0.88
Impact on Base
Case ARR
Z *
Increase Decrease
base case
3
20
40
20
63
(1) New 500-MW power plant
(2) 50"F of
(3) No heat
reheat
loss downstream of the :
scrubber and
no mist entrainment occur.
-------
Case A - In this case the exchanger pressure drop is increased from
6 to 12 in. HaO. As expected, operating costs increase
and capital costs decrease compared to the base case. The
resulting ARR is about 3 percent higher than the base case
ARR.
Case B - For this case 165 psia, superheated steam is used as the
heating medium. It was expected that use of this steam
level would decrease the energy requirements because less
air would be needed to reheat the flue gas. The resulting
ARR is about 20 percent lower than the base case ARR.
Case C - In this case, the primary fan in the base case was reposi-
tioned to follow both the scrubber and the hot air-flue
gas mixing point. This induced draft primary fan arrange-
ment raises the temperature of the flue gas-air mixture
by about 20°F due to the work of compression. Consequently,
the exchanger for this case is sized to supply enough heat
so the hot air raises the scrubbed flue gas temperature by
30°F after mixing. A simplified schematic of this configura-
tion is presented in Figure 19. The resulting annual revenue
requirement is about 40 percent lower than the base case ARR.
Flue Gas
Induced Draft
Fan
To Stack
Scrubber
Air
Figure 19. Simplified schematic of indirect hot air reheat
configuration with an induced draft primary fan.
Case D - Several of the base case parameters were changed:
(1) 600 psia, dry, saturated steam as the reheat media
(2) An induced draft primary fan configuration (Figure 19)
(3) A 40°F air approach temperature
The air heater in this case is sized to supply enough
heat to raise the temperature of the flue gas-air mixture
by 50"F. Users of reheat have indicated that heating
154
-------
5 2
the flue gas to this temperature will protect the fan from
corrosion. Since the work of compression (from the primary
fan) will raise the flue gas-injected air temperature by
about 18°F, the actual stack gas exit temperature is 68°F
above the scrubber exit temperature. The annual revenue
requirement is about 20 percent less than the base case
ARR.
Case E - The induced draft primary fan arrangement (see Figure 19)
is utilized. The steam level used in this case is 600 psia,
639°F superheated steam. The stack gas exit temperature is
50°F above the scrubber exit temperature. Since the work of
compression contributes approximately 20°F, the air heater
is sized to supply 30°F of reheat. The annual revenue re-
quirement is about 63 percent less than the base case ARR.
The cost summary sheets developed for the different cases defined above are
presented in Tables E-26 through E-30 in Appendix E.
Summary—
Assuming a stack exit temperature that is 50°F higher than the scrubber
exit temperature, it is concluded that:
(1) Indirect hot air reheat is generally more expensive than inline
reheat. This is because the indirect hot air reheat configura-
tion requires substantially more energy than inline reheat due
to the greater mass of gas (total gas made up of flue gas and
air) that must be heated to the stack exit temperature.
(2) The indirect hot air reheat user has strong economic incentives
to minimize the air injected into the flue gas since excess
reheat energy is required for the air. Therefore high injected
air temperatures (exiting the reheater) are advantageous. This
means that high grade steam (high pressure with superheat) and
close approach temperatures in the exchanger offer advantages.
(3) There are significant economic advantages associated with the
use of an induced draft primary fan configuration because it
can supply a portion of the flue gas reheat due to the work of
compression. However, the viability of this configuration is
dependent on the flue gas entering the fan being hot enough to
protect the primary fan from corrosion and deposition of solids.
155
-------
Economics of Exit Gas Recirculation (EGR) Reheat
Although exit gas recirculation has not been commercially proven the
capital and operating costs of using various levels of saturated steam with
this configuration were estimated. The size and cost of the reheat exchanger
in this configuration are expected to be very dependent on the approach
temperature in the reheat exchanger.* Consequently, several approach tempera-
tures were considered for each steam level. In each case, a forced draft pri-
mary fan configuration (see Figure 20) and 50°F increase** in the stack gas
temperature is the basis for the reheater design. An example cost summary
sheet for this reheat system is presented in Table 47. The cost summary
sheets developed for cases analyzed in this study are presented in Tables
E-31 through E-35 in Appendix E. The results of this study are summarized
in Table 48. The data presented in this table show that exit gas recircula-
tion may be economically attractive compared to inline reheat.
Forced Draft
Fliip
Gas
Fan
fex
Sc
A
:rubber /dx^ ^
f S «
•* To Stack
f
Steaja
-
Cheater
Auxiliary
Fan
Figure 20. Simplified schematic of exit gas recirculation configuration
with a forced draft primary fan arrangement.
Exit Gas Recirculation Sensitivity Studies—
The base case conditions selected for evaluating the economic sensitivit
of exit gas recirculation to various design parameters are. as follows:
*Approach temperature is defined as the temperature of steam entering the
reheat exchanger minus the temperature of the heated gas leaving the
exchanger.
**Mist carryover and heat losses downstream of the mist eliminator were
assumed negligible.
156
-------
TABLE 47 . COST SUMMARY SHEET FOR EXIT GAS RE CIRCULATION
(600 psia, dry saturated steam; flue gas approach
temperature = 40 F)
CONFIGURATION:
Scrubber
Flue Gas
Required H««c Input (10'Btu/hr) - gg.8
Scrubbed Flu* CM :
Temperature CF) • 130
Flow Race (lbi/hr) -5,140,000
Reheat Steam:
Temperature (*F) - 486
Pressure (psia) - 6QO
Flow Race (lb«/hr) -90,300
To Stack
Stack Exit Temperature (•») - ]_80
Recirculacion Exic Gas :
Temperature CF> - 446
Flow Rate (Ibs/hr) - 913,000
Reheat Air:
Ambient Temperature ("F) -
Heated Temperature OF) -
Flow Race (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF)
446
No. Req'd
4
Total
Capacity
Total - Incremental
Cost/Unit
37,700(fe:)a . 20
Total Cost (SI
754,000
Exchanger SP (in.H:0) - P
Condensing Heat Transfer Coefficient (Bcu/hr-fc:-*F)
Superheat Heat Transfer Coefficient (Btu/hr-£t!-'F)c
Primary Fand: ___ .
Size (HP) .2755 4
16.9
iP Cin.H^O) - ,
Auxiliary Fan* :
*P (ln.H:0> -_
Incremental
Scack Cose"
Soot Blowers ;
6
4
8
70 (HP) $17,
• i.
500 each
700 each
70,000
_
14,000
Toc.il Equipment Cose**
Direct Labor and Macerials Cost (for exchanger and sooc blower installation)
Indirect Costs (^57. of Total Equipment and Direct Labor & Material Costs)
nan
QQQ
64s nnn
TOTAL CAPITAL INVESTMENT
nnn
OPERATING COSTS
Item Quantity
Steam/Hot Water Q0,30(
Electricity
Primary Fan —
Auxiliary Fan 208
Maintenance and Replacement Cost
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Required
•) (Ibs/hr)
(kw)
(kw)
Cost/Unit
1.69 (S/10'lbs)
(5/kwh)
Q.Q314($/fcwh)
Total Annual Cnst(St
1,068,000
_
46,000
931 nqn
83j OQO
i .428 nnn
1.63 x 10°
fArea shown is 251 creacer Chan area calculated.
Overall heat transfer coefficient for condensing portion of exchanger.
^Overall heat transfer coefficient for desuoerheac portion of exchanger.
Primary fan's base size corresponds Co a forced draft FCD process without reheat.
^Auxiliary fin required for indirect hot air and exit (as recirculation configurations.
Incremental stack cost experienced only with indirect hoc air configuration
&Total cost of equipment chat is needed as a result of reheat. The fan and incremental
stack costs included In this total are installed costs.
157
-------
TABLE 48. COST OF USING DRY, SATURATED STEAM TO REHEAT FLUE GAS WITH AN EXIT
GAS RECIRCULATION SYSTEM
Saturated Approach Reheat Exchanger
Steam Pressure Temperature Gas Side Pressure
(|>sla) OF) Drop (in. H,O)
600 40
600 80
310 120
165 80
165 120
6
6
6
6
6
Exchanger
Area
(ft?)
37
26
21
31
21
,700
.200
,100
.300
.000
Capital Operating
Requirement Cost
(10'$) (10'$/yr)
2.
1.
I
1
1
08
53
31
.82
.37
1
I.
1
1
1
43
35
.27
.22
.21
Annual Revenue
Requirement
(10«$/yr)
1.
1
1
1
1
.63
.49
.40
.39
.34
Steam Inlet (to reheat exchanger) temperature minus flue gas temperature exiting the reheat exchanger.
Bases:
(1) New 500-MW power plant with 50*F of flue gas reheat after the scrubber.
(2) No entrainment present or heat losses occur downstream of the mist eliminator.
(3) 180°F stack exit temperature.
(4) Forced draft primary fan arrangement.
(5) Tube life assumed to be 4 years
Ui
OO
-------
Steam Level: 165 psia, dry, saturated
Approach Temperature: 80°F
Exchanger Pressure Drop: 6 in. HzO
Primary Fan Configuration: Forced draft (Figure 20)
Annual Revenue Requirement: $1.39 x 106
The results of the sensitivity analysis are summarized in Table 49. The
bases and results for the sensitivity studies conducted are:
Case A - A 165 psia, 745°F superheated steam is used as the reheat
medium. An 80°F approach temperature and a 6 in. Had
pressure drop is also incorporated into the design. The
resulting ARR is about 1 percent lower than the base case
ARR. Therefore, the use of superheated steam appears to
offer no significant advantage over saturated steam in
EGR systems.
Case B - An induced draft primary fan configuration is evaluated
in this case. An auxiliary fan is also required. A
simplified schematic of the induced draft arrangement is
presented in Figure 21. The resulting ARR is about 56
percent lower than the base case ARR.
Induced Draft
To Stack
Flue Gas
S
crubbe
r [^\
)SJ o
/ Reheater
Sf cam
r^ -"
r
A Auxiliary
Fan
Figure 21. Simplified schematic of exit gas recirculation reheat
with an induced draft primary fan arrangement.
Case C - An induced draft primary fan arrangement (Figure 22)
is the last case evaluated. A small exchanger is used
to reheat the recirculated gas enough to protect the
fan. In this case the heat due to the work of compres-
sion supplies a portion of the desired reheat, while a
larger exchanger which follows the fan supplies the re-
mainder of the reheat needed. The resulting ARR is about
159
-------
TABLE 49. ECONOMICS FOR EXIT GAS RECIRCULATION SENSITIVITY
STUDIES
Cases
Studied
Base Case
Sensitivity
• Case A
• Case B
• Case C
Steam
Quality
165 psia.
dry.
saturated
165 psia.
745*F,
superheat
165 psia,
saturated
165 psia.
saturated
Approach
Temperature
(-F)
80
80
dr.- 80
dr. 80
1'rimary
Fan
Position
forced
draft
forced
draft
induced
draft
induced
draft
Reheat
Exchanger
AP
(in. HjO)
6
6
6
30(auxiliary'
3(prinary)
Exchanger
Area
(ft1)
31,300
30.900
19,700
) 3.300
5,700
Capital
Investment
(10?')
1.82
1.79
1.02
0.46
Annua 1
Operating
Costs
(10$')
1.22
1.20
0.52
0.51
Annual
Revenue
Required
(10$')
1.39
1.37
0.61
0.56
Impact on Base Case
•i. " ' " x '
Increase Decrease
base case
1
56
60
Exchanger area 25 percent greater than actually calculated.
Bases:
(1) New 500-MW power plan:
(2) No heat losses or mist entrainment occur downstream of the mist eliminator.
(3) 180°F stack exit temperature
-------
60 percent lower than the base case annual revenue requirement.
In this case, however, the fan may not be adequately protected
against corrosion.
Induced Draft
Fan
Gas
S
/
c rubber
/<"
^ £
K
Steam
Primary
Reheater
To Stack
Steam
Auxiliary
Reheater
Figure 22. Simplified schematic of an advanced EGR
reheat configuration.
Summary—
From the cases developed for exit gas recirculation reheat, it is
concluded that:
(1) EGR, although unproven commercially, appears to be economically
attractive compared to inline and indirect hot air reheat
systems.
(2) Superheated steam appears to offer no significant economic
advantage over saturated steam as the reheat medium.
(3) There are significant economic advantages associated with the
use of an induced draft primary fan configuration because it
can supply a portion of the flue gas reheat due to the work of
compression. However, the viability of this configuration is
dependent on the flue gas entering the fan at a high enough
temperature for protection against corrosion.
Economics of Direct Combustion
The costs of reheating a flue gas with a direct combustion reheat system
are also estimated. The equipment costs for a fuel oil-fired direct combus-
tion reheat system are based on a 500-MW power plant and were obtained from
the literature. 9'3° These costs are presented in Table 50 for both forced
and induced draft primary fan configurations. Schematics of these config-
urations are presented in Figure 23.
161
-------
TABLE 50. COSTS OF DIRECT COMBUSTION REHEAT (1978 $)
Capital Requirement
Oil Storage Tank (1 required)*
Burner Packages (4 required)
Primary Fan Credit
Total Equipment Cost
Direct Labor and Materials (Installation)
Indirect Costs
TOTAL CAPITAL INVESTMENT
Operating Costs
Fuel ($3.00/106 Btu)
Electricity Credit
Maintenance , 8%
Depreciation
ANNUAL OPERATING COST
ANNUAL REVENUE REQUIREMENT
Primary Fan
Forced Draft
$ 95,000
292,000
387,000
155,000
244,000
$ 786,000
1,403,000
43,000
31,000
1,477,000
$1,552,000
~
Configuration
Induced Draft
$ 70,000
215,000
<11,000>
274,000
110,000
173,000
$557,000
841,000
<167,000>
31,000
22,000
727,000
780,000
*Approximately 30-day capacity.
Bases:
(1) Stack exit temperature is 50°F higher than scrubber exit temperature.
(2) For induced draft case, it was assumed that 20°F of desired reheat was
obtained from work of compression; consequently, reheat system
designed to supply 30°F of reheat.
(3) Economics reflect firing of No. 2 fuel oil.
162
-------
Flue
Gas
Forced Draft
Fan
/•v
I
Sc
:rubber „ , ,.
Fuel y
/
V
Combustion
Chamber
Air
(a) forced draft primary fan configuration
Flue_
Gas
Scrubber
Fuel
Induced Draft
Fan
-> To Stack
Combustion
Chamber
T
lAir
(b) induced draft configuration
Figure 23. Schematics of direct combustion reheat configurations
with forced and induced draft primary fan arrangements.
As expected, the direct combustion reheat configuration with an induced
draft primary fan is considerably less expensive than the forced draft fan
arrangement. This is due to (1) the lower fuel consumption exhibited by the
induced draft fan arrangement, and (2) the smaller sized fan which is needed
for the induced draft system (the smaller fan requirements result in credit
for both the capital and operating costs).
The costs in Table 50 show that the annual revenue requirements of a
direct combustion (fuel oil firing) reheat scheme are competitive with the
other reheat configurations/ However, over the life of the process the
*For the fuel costs specified. No. 2 fuel oil costs are currently much
higher than the $3/106 Btu used in this example.
163
-------
revenue requirements of the direct combustion system are expected to rise
faster than those of the inline, indirect hot air, and EGR reheat configura-
tions because a higher fraction of this configuration's revenue requirements
is attributable to fuel costs.
A direct combustion reheat system firing natural gas would exhibit the
following characteristics.* The capital requirement would be somewhat lower
since a fuel oil tank would not be required. Although the burner packages
(including the combustion chamber) would differ somewhat, the capital invest-
ment is expected to be similar. Since the major component of the annual
revenue requirement for a direct combustion system is related to the f 1
costs, small differences in the capital requirements will not have a sig-
nificant impact on the relative ARR's of the two systems. The economic
viability of a natural gas versus fuel oil system will depend primarily on
the relative delivered costs (on a $/106 Btu basis) of the fuels
Retrofit Reheat Systems
The economic assessment of the costs of retrofitting reheat
existing boiler-FGD system is very site specific. The items that are expected
to cause uncertainties are:
(1) Capability of existing primary fan to handle higher flow
rates and/or pressure drops.
(2) Capability of the existing turbine to supply reheat steam
and the resulting energy or power generation penalties.
(3) Space for installing the reheat system.
The direct combustion case economics developed for new plants are a zo d
approximation of retrofit costs for this reheat system. The inline EGR
and indirect hot air reheat system economics for retrofit applications
too site specific and are not attempted in this report.
*Compared to a diract combustion system firing oil.
164
-------
COMPARISON OF REHEAT SYSTEM ECONOMICS
The economics of the four reheat systems for new 500-MW power plants
are analyzed and compared below.
Evaluation of Reheat System Costs and Comparison to FGD System and Power
Plant Costs
Capital investment and operating costs for SGR systems will vary
considerably depending on the following parameters:
(1) Steam quality (temperature, pressure) and availability
(2) Fuel cost ($/106 Btu for coal, fuel oil, natural gas, steam)
(3) Type of reheat system selected (EGR, inline, indirect hot air,
direct combustion)
(4) Exchanger design criteria
(5) Reheat temperature desired
(6) Reheat exchanger metallurgy
(7) New or retrofit installation
Ranges of costs for selected reheat cases are presented in Table 51.
The costs are compared to costs for a new coal-fired plant and a limestone
FGD system. It should be emphasized that the reheat costs shown are not for
optimized designs. The inline, indirect hot air, and exit gas recirculation
ranges are based on the use of dry, saturated steam (165-600 psia) as the
reheat medium. This basis penalizes the indirect hot air injection system
since the use of superheated steam is very attractive for indirect hot air
but only marginally attractive for inline and EGR reheat. In addition,
other reheat exchanger parameters, such as gas-side pressure drop, exchanger
approach temperature, tube spacing, and use of finned tubes for hot air
injection, have not been optimized. Finally, the cost of reheater downtime
165
-------
TABLE 51. STACK GAS REHEAT ECONOMIC EVALUATION SUMMARY (1978 $)
o\
cr>
Reheat System
Reheat System Capital
Requirement, 10'$
% of FIJD System* Capital
Requirement
% of Total Power Plant
Capita] Requirement
Reheat System Annual
Revenue Requirement (ARR) ,
106 $/year
% of FGD System* ARR
% of Total Power
l'lanib ARR
Bases
Steam Quality
Tube Metallurgy0
Fuel Costs
Tnl ine
O.8 - 2.9C
1.1 - 3.6
0.2 - 0.7
1.5 - 1.7
7.1 - 8.1
1.4 - 1.5
Dry, Saturated
(165-600 psia)
Carbon Steel,
lib SS
Inconel 625
Based on coal
in new power
plant at $l/10l
Btu
Indi rect
Hot Air
1.4 - 2.4
1.9 - 3.2
0.4 - 0.6
1.9 - 2.1
9.0 - 10.0
1.7 - 1.9
Dry, Saturated
(165-600 psia)
Carbon Steel
Based on coal
in new power
plant at $1/10'
Btu
Exit Cas
Rec irculation (KGR)
1.3 - 2.1
1.7 - 2.8
0.3 - 0.5
1.4 - 1.6
6.7 - 7.6
1.3 - 1.5
Dry, Saturated
(165-600 psia)
Carbon Steel
B.ised on coal
in new power
pli.nL at SI/10'
Btu
Direct
Combustion
0.8
1.1
0.2
1.6 - 2.0
7.6 - 9.5
1.5 - 1.8
$3-4/106Blu
No. 2 fuel
oil
aFGD system costs .ire taken as $150/kw (capital requirement) and 6 mills/kwh (annual revenue
requi rement).
A new power plant (including FGD system) costs are taken as $800/kw (capital requirement) and
31.4 uills/kwli (annual revenue requirement). See Appendix E.
cFor inline reheat the large range for capital requirement is due primarily to the estimation
of capital investments for several different tube materials.
Bases: (1) 50*F of reheat.
(2) No mist carryover from scrubber.
(3) No heat losses from ductwork and stack.
(4) New SOO-MW power plant.
-------
(this may translate to scrubber downtime and resulting boiler load reduc-
tion) has not been factored into the economic analysis. Since indirect
hot air injection exhibits better reliability than inline reheat, this is
another factor that may make indirect hot air injection competitive with
other reheat systems.
The following results are noted (for the bases given in Table 51):
(1) Inline and EGR reheat are generally lower cost (annualized cost)
systems than direct combustion and indirect hot air. EGR reheat,
however, has not been tested commercially.
(2) The better reliability of the indirect hot air reheat system
(compared to inline) may make indirect hot air competitive
with the other systems for some users.
(3) Since the direct combustion system ARR is highly dependent on
fuels which may be subject to availability constaints and high
cost escalation, its use in new power plants is expected to be
limited.
Impact of Assumptions on Economics
It is recognized that all power plants are different and, consequently,
the reheat requirements used in these plants will also be different. The
bases (presented in Tables 38 and 39 and Appendix E) used to develop the
preceding economics could not and do not apply to every possible reheat
situation. An evaluation of how changes in design parameters affect the
costs associated with an inline reheater was conducted. The cost estimate
for the "base case" inline reheater is based on the following:
(1) 9000 Btu/hr plant heat rate
(2) 50°F of reheat
(3) No heat losses from the stack and duct work(downstream
of the mist eliminator)
(4) No mist entrainment from the mist eliminator
167
-------
(5) Carbon steel tubes in the reheater
(6) New 500-MW power plant
(7) 165 psia, dry, saturated steam as reheat steam
These assumptions result in a required heat input of 66.8 x 106 Btu/hr
capital requirement of $1,090,000, and an annual revenue requirement of
$1,520,000 (see Table 40). Several differences in these assumptions were
evaluated as described below and the results are presented in Table 52
Case A - The only base case values changed were related to the
entrainment mist and heat loss assumptions. The entrained
mist from the scrubber was taken as 0.802 gr/scf. Heat
losses from the duct and stack equivalent to a 5°F flue
gas temperature drop were also assumed. These values in-
creased the base case reheat requirement from 66.8 x 106
to 82.4 x 105 Btu/hr and the annual revenue requirement
from $1.52 x 106 to $1.87 x 106.
Case B - In addition to the heat losses that were assumed in Case A
the reheater tube material was assumed to be 316 stai 1 '
steel instead of carbon steel (base case). The change £SS
resulted in increasing the annual revenue requirement
compared to the base case by about 26 percent. The
capital requirement of the reheat exchanger increased
significantly also.
Case C - In this case the entrained mist was assumed to be 0 802
gr/scf. Heat losses were equivalent to a 5°F drop in
flue gas temperature. The reheater tube material was
316 stainless steel, while a plant heat rate of 10 350
base case reheat energy requirement from 66 8 x 10* RI-,, /
hr to 95.9 x 10 Btu/hr and the annual revenue requirement
from $1.52 x 106 to $2.20 x 10« (or a 45 percent increase
over the base case ARR). increase
168
-------
TABLE 52. IMPACT OF ASSUMPTIONS ON ECONOMICS OF 50°F REHEAT WITH INLINE REHEAT SYSTEM
Ki-liciit Annual
Entrained Mist Total Rt-licaLur Ki-vi-nue
Base
Case
Case
Case
"for
System
•V
Caseb 0
A 5
B 5
C 5
vaporization
Heat Losses
10' Btu/hr
0
6.7
6.7
8.9
Concenlrac ion
gr/scf
0
0.802
O.B02
0.8O2
Heat Required3
1O' Btu/hr
0
8.9
8.9
10.2
Blu/kuh 10'$
9000 1.09
9000 1.34
9000 1.84
10350 ->-2.12
Nt.'at Input Requ irt.'u
\O
-------
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1. Choi, P. S. K., et al. Stack Gas Reheat for Wet Flue Gas
Desulfurization Systems. Final Report. EPRI FR-361, RP 209-2
Battelle Columbus Laboratory, Columbus, OH, 1977.
2. Laseke, Bernard A., Jr. EPA Utility FGD Survey: December 1977
January 1978. EPA Contract No. 68-01-4147, Task 3, EPA 600/7-78-051a
PEDCo Environmental, Cincinnati, OH, March 1978.
3. Laseke, Bernard A., Jr. Survey of Flue Gas Desulfurization Systems-
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4.
Laseke, Bernard A., Jr. Survey of Flue Gas Desulfurization Systems-
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6. Isaacs, Gerald A. and Fouad K. Zada. Survey of Flue Gas Desulf
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La Cygne Station, Kansas City Power and Light Co., Final Reoort
EPA Contract No. 68-01-4147, Task 3, EPA 600/7-78-048d. PEDCo Envfmn
mental, Cincinnati, OH, March 1978. "iviron-
8. McDaniel, Clifford F. "La Cygne Station Unit No. 1 Wet Scrubber
Operating Experience", Presented at the Utility Scrubber Conference
Denver, CO, March 1978.
9. Isaacs, Gerald A. and Fouad K. Zada. Survey of Flue Gas Desulfuriza-
tion Systems: Lawrence Power Station, Kansas Power and Light Co.
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OH, September 1975. '
170
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10. Ayer, Franklin, A. Flue Gas Desulfurization, Hollywood, FL, November
1977, Symposium Proceedings, 2 volumes. EPA Contract No. 68-02-2612,
Task 38, EPA 600/7-78-058a,b. Research Triangle Institute, Research
Triangle Park, NC, March 1978.
11. Proceedings: Symposium on Flue Gas Desulfurization, New Orleans,
March 1976. IERL, U.S. Environmental Protection Agency, Research
Triangle Park, NC, May 1976.
12. Leivo, C. C. Flue Gas Desulfurization Systems: Design and Operating
Considerations, Final Report, 2 volumes. EPA Contract No. 68-02-2612,
Task 2, EPA 600/7-78-030a,b. Bechtel Corp., San Francisco, CA, March
1978.
13. Gerstle, Richard W. and Gerald A. Isaacs. Survey of Flue Gas Desul-
furization Systems: Reid Gardner Station, Nevada Power Co. EPA 650/
2-75-057. PEDCo Environmental Specialists, Inc., Cincinnati, OH,
October 1975.
14. Gibbs and Hill, Inc. Omaha Public Power District Site Selection Studies
for Pumped Storage Addition. New York, November 1974.
15. Isaacs, Gerald A. Survey of Flue Gas Desulfurization Systems: Eddy-
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16. Isaacs, Gerald A. Survey of Flue Gas Desulfurization Systems:
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17. Pacific Chemical Engineering Congress (PAChEC '77), Second, Denver, CO,
August 1977, Proceedings, volume 1. American Institute of Chemical
Engineers, New York, 1977.
18. Bechtel Corp. Flue Gas Desulfurization: Implications of SOz Removal
Requirements, Coal Properties and Reheat. Draft Report. EPA Contract
No. 68-02-2616. San Francisco, CA, September 1977.
19. PEDCo Environmental, Inc. Flue Gas Desulfurization Systems. Summary
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20. Rohr, F. W. Suppression of the Steam Plume From Incinerator Stacks.
In: National Incinerator Conference, New York, May 1968, Proceedings.
New York, ASME, 1968, pp. 216-24.
21. Rohr, Fred W. Suppressing Scrubber Steam Plume. Pollution Engineering
1 (1), 1969. pp. 20-22.
171
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22. Ellison, W. Designing Large Wet-Scrubber Systems. Power 116 f2>)
1972, pp. 67-69. '
23. Blum, A. Drizzle Precipitation From Water Cooling Tower. Engineer
August 6, 1948, pp. 128-130.
24. Overcamp, Thomas J. and David P. Hoult. Precipitation in the Wake of
Cooling Towers. Atmospheric Environment 5, September 1971 pp. 751-
765.
25. Martin, A. and F. R. Barber. Measurements of Precipitation Downwind
of Cooling Towers. Atmospheric Environment 8, 1974, pp. 373-381.
26. Busse, A. D. and J. R. Zimmerman. User's Guide for the Climatological
Dispersion Model. Environmental Protection Agency, NERC, OR&D
Triangle Park, NC, December 1973. *
27. Turner, D. B. Workbook of Atmospheric Dispersion Estimates U S
Environmental Protection Agency, Office of Air Programs PubM^a
No. AP-26, 1970. ' cat
28. McGlamery, G. G., et al. Detailed Cost Estimates for Advanced
Effluent Desulfurization Processes. Final Report. EPA 600/2 7S
TVA, Muscle Shoals, AL, January 1975. /^-o-
29. Calvin, E. L. A Process Cost Estimate for Limestone Slurry ScruhM™
of Flue Gas. Final Report. EPA-R2-73-148a. Catalytic T UDDlng
Charlotte, NC, 1973. ' *'
30. Calvin, E. L. A Process Cost Estimate for Limestone Slurrv Scr,,hM«
of Flue Gas, Part II, Detailed Estimate Sheets. Final Renor? r
lytic, Inc., Charlotte, NC, 1973. ^ cata~
31. Wigley, T. M. A Numerical Analysis of the Effect of CondensaMrm
Plume Rise. Journal of Applied Methodology, Volume 14 19 7< " ??ne
HQ9 ' *•'••> i pp. J.JLU5—
32. Briggs, G. A. Some Recent Analyses of Plume Rise Observation. In-
Proceedings of the Second International Clean Air Congress. England
H. M. and W. T. Barry (ed.), 1971.
33. Bechtel Power Corporation, San Francisco Power Division. Coal-Fired
Power Plant Capital Cost Estimates. Final Report. EPRI AF-342
State-of-the-Art 75-329. San Francisco, CA, January 1977. '
34. Perry, John H. Chemical Engineers Handbook, 5th Edition. McGraw-Hill
New York, 1973.
35. Guthrie, K. M. Process Plant Estimating Evaluation and Control.
Craftsman Book Co., Solana Beach, CA, 1974.
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36. Peters, Max S. and Klaus D. Tiiranerhaus. Plant Design and Economics for
Chemical Engineers, 2nd Edition. McGraw-Hill, New York, 1968.
37. Ponder, Thomas C., et al. Simplified Procedures for Estimating Flue
Gas Desulfurization System Costs. EPA 600/2-76-150, EPA Contract No.
68-02-1321, Task 12. PEDCo Environmental Specialists, Inc., Cincinnati,
OH, June 1976.
173
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The following companies and individuals contributed their advice and
assistance during the course of this project.
Alabama Electric Coop. - Tombigbee Station - A. Wells
Allegheney Power System - Pleasants Station - T. L. Misner
American Air Filter - Dan Josephs
Arizona Electric Power Coop. - Apache Station - J. Wharrie, L. D. Porter
Arizona Public Service - Cholla Station - C. Walker
- Four Corners Station - Mr. Haelbig
Babcock and Wilcox - H. M. Majdeski
Basin Electric Power Coop. - Antelope Valley and Laramie River Stations
R. L. Eriksen
Bechtel National, Inc. - R. M. Sherwin
Big Rivers Electric Corp. - Reid Station - T. Carter
Brazos Electric Power Corp. - San Miguel Station - D. Boyle
Buffalo Forge Co. - F. Heinzmann
Burns and McDonnell - D. Froelich, J. Landweir, B. Thompson
Burns and Roe, Inc. - J. Whipple
Central Illinois Light Co. - Duck Creek Station - L. H. Haynes, K. Swahlstedt
Central Illinois Public Service - Newton Station - J. Slavin
Columbus and Southern Ohio Electric Co. - Conesville Station - R. E. Ruby
Combustion Engineering - J. R. Martin
Commonwealth Edison - Powerton Station - C. C. Johnson
- Will County Station - J. Reid
Copes-Vulcan - T. Shortser
Davy Powergas, Inc. - L. H. Grives, R. I. Pedroso
Delmarva Power Co. - Delaware City Station - B. McConnell
Detroit Edison Co. - St. Clair Station - J. E. Myers
Diamond Power Specialty Corp. - L. Palmer
Duquesne Light Co. - Elrama and Phillips Stations - R. D. O'Hara
Environeering, Inc. - S. V. D'Souza
Indianapolis Power and Light Co. - Petersburg Station - Mr. Readle
Kansas City Power and Light Co. - Hawthorn Station - L. L. Marks
- La Cygne Station - C. F.' McDaniel S
Kansas Power and Light Co. - Jeffery Station - L. Brunton
- Lawrence Station - R. Teeters
Kentucky Utilities - Green River Station - J. W. Reisinger
Kinetics Engineering - B. Hedricks
Louisville Gas and Electric Co. - Cane Run, Mill Creek, and Paddy's Run
Stations - R. P. Van Ness
Montana Power Co. - Colstrip Station - M. Hofacher, B. Lewis, E. Handell
Nevada Power Co. - Reid Gardner Station - T. Leavitt
Niagara Mohawk Power Coop. - Huntley Station - W. C. Hiestand
Northern Indiana Public Service - Bailly Station - D. Kuhn
- D. H. Mitchell Station - E. L. Manns
Northern States Power Co. - Sherburne Co. Station - R. J. Kruger, L. p.
Gordon
Otter Tail Power Co. - Coyote Station - T. Graumann
174
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Pacific Power and Light Co. - Dave Johnson Station - T. M. Phillips
Pennsylvania Power Co. - Bruce Mansfield Station - D. Thomas
Philadelphia Electric Co. - Cromby Station - E. Boyer
- Eddystone Station - B. Helt
Potomac Electric and Power - Dickerson Station - W. C. Jenson
Public Service Company of Colorado - Arapaho, Cherokee, and Valmont
Stations - K. Barnett
Public Service Company of Indiana - Gibson Station - L. W. Leath
Public Service Company of New Mexico - San Juan Station - T. Warnke,
J. T. Ferrill
Pullman-Kellogg - J. C. Yarze
Pullman Power Products - E. Yondy
Ralph M. Parsons - N. Alispones
Research-Cottrell - Dr. R. L. Kent
Salt River Project - Coronado Station - R. F. Durning
South Carolina Public Service Co. - Winyah Station - C. L. Osborne
Southern Illinois Power Coop. - Marion Station - Mr. Stafford
Southern Indiana Gas and Electric - AB Station - J. Milhorn
Southern Mississippi Electric - R. D. Morrow Station - C. A. Webb, Jr.
Springfield City Utilities - Southwest Station - L. Killingsworth
Springfield Water, Light and Power - Dallman Station - C. J. Saladino
Tennessee Valley Authority - Shawnee and Widows Creek Stations -
Dr. G. A. Hollinden, G. Munson, R. Robards
Texas Municipal Public Agency - Gibbons Creek Station - D. Howard
Texas Utilities Co. - Monticello Station - C. L. Merka
Tranter, Inc., Texas Division - Gerry Delaney
United Engineers and Constructors, Inc. - G. Frey
United Power Association - Coal Creek Station - W. R. Smit, J. Weeda
UOP, Inc. - Dr. N. Ostroff
Utah Power and Light Co. - Emery Station - A. L. Perry
- Huntington Station - M. W. Kenney, G. N. Lacey
Wisconsin Power and Light Co. - Columbia Station - S. S. Frey
Zurn Industries, Inc. - A. Broski
175
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APPENDIX A
DESCRIPTION OF RADIAN'S DISPERSION AND WET PLUME MODELS
176
-------
APPENDIX A
DESCRIPTION OF RADIAN'S DISPERSION AND WET PLUME MODELS
DESCRIPTION OF WET PLUME MODEL
Radian's Wet Plume Model was used to analyze the effect of reheat on
the length of visible plumes and the concentration of condensed water in the
plume with regard to possible rainout. The Wet Plume Model is based on the
set of conservation equations presented by Wigley in 1975.31 The set consists
of equations of conservation of mass, momentum, and energy, and an assumed
entrainment equation. Major assumptions associated with the model are that
the plume has a definite boundary and that the properties of the plume are
uniform in a cross section. These assumptions allow all of the equations
to be written as ordinary differential equations rather than the more com-
plicated partial differential equations.
The equations are stated here for completeness but will not be dis-
cussed in detail.
2v
£- (VR2) - -=£ VR2 (A-l)
UL K
r ~i ^^
d VR2 (q - q + 0) - - —~ VR2w
~;— I o I dz
dt [ J
[, / T* - T * \1 99
VR 8 [ o La \ - -N2VR2w
V V "Vo^J
(A-2)
(A-3)
177
-------
[, "I
™ "J
d_ VR v - U d_ ^VK , (A_5)
dt L J dt
£ . v CA-6)
dx / . -.N
= v (A"7)
The symbols are identified as follows:
t * independent variable, time
V • centerline plume velocity
R = radius of the plume
v = entrainment velocity
q » specific humidity
v,w = x and z components of the plume velocity, respectively
a • liquid water mixing ratio
g - acceleration due to gravity
T* * virtual temperature
L = latent heat of vaporization of water
N * the Brunt-Vaisala frequency
U * ambient wind velocity
Subscript o - atmospheric variable
No subscript * plume variable
The entrainment speed v is given by
v = a !w
e ' ' (A-8)
178
-------
where a is an empirical constant, and the Brunt-Vaisala frequency is given by
(A-9)
where F , is the adiabatic lapse rate and F is the actual lapse rate.
Equation A-l is the entrainment assumption, Equation A-2 is the total
water mass balance equation, and Equation A-3 is the energy conservation
equation. The conservation of vertical and horizontal momentum are given
by Equations A-4 and A-5, respectively, and the spatial locations are
defined by Equations A-6 and A-7.
Note that these equations do not address the momentum-dominated dynamics
explicitly. It has been generally assumed by previous investigators that
this effect can be ignored in favor of the buoyancy-dominated dynamics.
These equations are valid only for a relatively short distance downwind
of the stack. The results, discussed in Section 5, become invalid at about
1640 feet (500 meters) downwind of the source.
DESCRIPTION GAUSS/X-CURVE PLUME MODELING PROGRAM (THREE-HOUR CONCENTRATIONS)
With the use of Radian's Gauss/X-Curve plume modeling program, the
effect of reheat on the short term (three-hour) S02 and NOX ground-level
concentrations was analyzed for two atmospheric stabilities, unstable and
neutral. The algorithms used in this model are similar to those expressions
presented by Turner in Workbook of Atmospheric Dispersion Estimates.27 The
time-averaged ground-level concentration is given by:
X(x,y:H)
-S-
(A-10)
179
-------
where: x = tne pollutant concentration
x » distance downwind
y = radius of the plume at (x,H)
H = height of plume centerline (relative to ground-level)
u = wind speed
Q * pollutant source strength
G » horizontal dispersion coefficient
7
a « vertical dispersion coefficient
z
The plume rise formula used in the study was derived by Briggs (1971)32.
H = h + 1.6F1/3u"1x2/3 when x <. 3.5x*
and
1/3 -1
H - h + 1.6FX/ u X(3.5x*r when x > 3.5X*
5/8
and x* = 14F when F <_ 55
(A-ll)
3AF2/5
when F > 55
where: H - effective stack height (stack height plus plume rise)
h » stack height
x = downwind distance
u » wind speed
F » buoyancy flux
The total buoyancy flux, F, is the only term affected by the rehea
configuration that is used and is given by
Vs V
180
-------
where: V = velocity of flue gas exiting the stack
s
g = local acceleration due to gravity
R = stack radius
T = gas temperature exiting the stack
T = ambient air temperature
3.
The plume dispersion coefficients used in the model were determined from
the Pasquill-Gifford curves presented by Turner in the previously mentioned
publication.
DESCRIPTION OF GAUSS/X-STAR MODEL (ANNUAL AVERAGE CONCENTRATIONS)
Annual average concentrations were estimated with the Radian Gauss/
X-Star program which utilizes the algorithm presented by Busse and Zimmerman
in 1973. The basis for this program is annual average ground-level concen-
tration due to a single source which is given by
c 16 I I *(k'*'")G S("VP») f
g ZTT jl-i m=l p('
where: C * annual average ground-level concentration
o
(k,£,m) = joint frequency function (dimensionless)
k « wind section appropriate to the source (dimensionless)
£ » index identifying the wind speed class (dimensionless)
m = index identifying the class of the Pasquill stability
category
G " pollutant emission rate of the source
S » dispersion function
p « distance from the receptor to the source
U, » representative wind speed
P * Pasquill stability category
m
181
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The dispersion function, S, in this expression is given by:
exp
when o < 0.8L
z —
and
where: H = plume centerline height
L * afternoon mixing height
a = vertical dispersion coefficient
(seconds/meter2)
(A-14)
when a > 0. 8L
Z
(A-15)
This expression is the basis for a statistical technique that uses multit»l
years of NWS meterological observations to develop a frequency distributi
The data used for this exercise were collected at Wayne City, Michigan (
Detroit) over the period 1959 - 1968.
182
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APPENDIX B
QUESTIONNAIRE FORMS
183
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APPENDIX B
QUESTIONNAIRE FORMS
Presented in this appendix are the questionnaires sent to A/E firm
FGD process vendors, and utilities. The companies that were sent questi
naires are listed.
A/E QUESTIONNAIRE
The questionnaire sent to A/E-consulting firms is presented as Atta h
-ment I. The companies that received the questionnaires are listed below
Seven out of eleven companies responded.
Bechtel Corporation
Black and Veatch
Burns and McDonnell
Burns and Roe
Combustion Engineering
Peabody Engineering
Pullman Kellogg
Ralph M. Parsons
Steams-Roger
United Engineers and Constructors, Inc.
UOP Incorporated
184
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Attachment I
A&E/CONSULTANT QUESTIONNAIRE
WET SCRUBBING FLUE GAS REHEAT SYSTEMS
I. ORGANIZATION INFORMATION
A. Company Name
Address
city state zip code
Telephone number
B. Person Completing Form
name
title
II. REHEAT RECOMMENDATIONS
A. Do you recommend that reheat always be used?
B. Do you specify reheat systems only when required by the customer?
C. Do you recommend against reheat? If so, why?
III. REHEAT EQUIPMENT CONFIGURATION
A. Which Type of Reheat Equipment Do You Recommend (check one)
1. Direct Combustion (see B)
2. Indirect Hot Air (see c;
3. Inline (see D)
4. Bypass Csee E)
5. Other Csee F)
185
-------
Items B-G are for your recommendations on specific equipment items, confi2Ura
tions, and philosophies. °
B. Direct Combustion Reheat
1. Fuel type
2. Combustion chamber type (check one)
Internal
External
3. Mixing chamber
Materials of construction
Mixing device
4. Recommended nozzle type and material of construction
5. Control philosophy
Indirect Hot Air Injection Reheat
1. Heat exchanger type
2. Materials of construction
3. Heating medium
4. Recommended exchanger configuration
5. Mixing chamber device
6. Control philosophy
Inline Reheat
1. Heat exchanger type
2. Materials of construction
3. Heating medium
4. Recommended exchanger configuration
186
-------
5. Cleaning devices
6. Control philosophy
E. Bypass Reheat
1. Control philosophy
2. Supplemental reheat recommended
F. Other Reheat Methods
G. Ductwork and Stack Design
1. Materials of construction
2. Insulation (R value)
3. Duct gas velocity (ft/sec)
4. Stack discharge velocity (ft/sec)
5. Temperature drop between reheat and stack outlet (°F)
6. Mist eliminator type
name
7. Mist eliminator location (check one)
a) Horizontal duct
b) Vertical duct
187
-------
V. What is your experience concerning the problems reheat systems have
had and how was the reliability improved. Have you discontinued any
reheat configurations or have you developed any new technology?
Please explain (all information will be held in complete confidence)
VI. What fraction of the total capital cost of an FGD System does the
reheat system represent?
What fraction of the total operating cost?
What fraction of the total maintenance cost?
VII. Copies of any sales or technical publications which you distribute
would be very beneficial.
188
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FGD PROCESS VENDOR QUESTIONNAIRE
Attachment II is the questionnaire sent to FGD process vendors. The
companies to whom the questionnaire was sent are listed below. Five out of
the seven companies responded.
American Air Filter
Babcock and Wilcox
Chemico
Davy Powergas
Arthur D. Little
Environeering, Inc.
Research Cottrell
ELECTRIC UTILITY (REHEAT USER) QUESTIONNAIRE
Attachment III is the questionnaire sent to utilities. Utilities who
received the questionnaires are listed below. Twenty-six out of the forty-six
questionnaires were returned.
Alabama Electric Co-op., Inc.
Allegheny Power Cystem
Arizona Electric Power Co-op.
Arizona Public Service Co.
Basin Electric Power Co-op.
Big Rivers Electric Corp.
Brazos Electric Power Co-op.
Central Illinois Light Co.
Cincinnati Gas and Electric Co.
Colorado Ute Electric Association
Columbus and South Ohio Electric Co.
Commonwealth Edison Co.
Duquesne Light Co.
Eastern Kentucky Power Co-op.
Indianapolis Power and Light Co.
Kansas City Power and Light Co.
Kansas Power and Light Co.
Kentucky Utilities Co.
Louisville Gas and Electric
Minnesota Power and Light Co.
Minnkota Power Co-op.
Montana Power Co.
Nevada Power Co.
New England Electric System
Niagra Mohawk Power Corp.
Northern Indiana Public Service
Northern States Power Co.
Otter Tail Power Co.
Pacific Power and Light Co.
Pennsylvania Power Co.
Philadelphia Electric Co.
Potomac Electric Power Co.
189
-------
Public Service Co. of Indiana
Public Service Co. of New Mexico
Salt River Project
South Carolina Public Service Authority
Southern Illinois Power Co-op.
Southern Indiana Gas and Electric
South Mississippi Electric Power Association
Springfield City Utilities
Tennessee Valley Authority
Texas Power and Light Co.
Texas Utilities Co.
United Power Association
Utah Power and Light Co.
Wisconsin Power and Light Co.
190
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Attachment II
FGD VENDOR QUESTIONNAIRE
WET SCRUBBING FLUE GAS REHEAT SYSTEMS
I. ORGANIZATION INFORMATION
A. Company Name
Address
city state zip code
Telephone number
B. Person Completing Form
name
title
II. TYPE OF FLUE GAS DESULFURIZATION SYSTEM (check one)
A. Regenerable
1. Wellman-Lord
2. Mag-Ox
3. Other
name
B. Nonregenerable
1. Lime/limestone
2. Double Alkali
3. Other
name
191
-------
The following section concerns your design recommendations to present a d
prospective customers. Drawings or descriptive literature would be be
ficial.
III. MIST ELIMINATOR, DUCT, AND STACK DESIGN
A. Recommended Mist Eliminator Type
name
B. Recommended Mist Eliminator Location (check one)
1. Horizontal duct
2. Vertical duct
C. Expected Outlet Mist Eliminator Loadings
1. Solids (gr/scf)
2. Condensed Vapor (gr/scf)
D. Ductwork and Stack Design
1. Recommended materials of construction
2. Recommended insulation thickness or "R" value
3. Duct gas velocity (ft/sec)
4. Stack discharge velocity (ft/sec)
5. Expected temperature drop between reheat and stack outlet
192
-------
IV. STACK GAS REHEAT
A. Always Recommended Reheat
B. Design Only at Customer's Request
C. Never Recommend Reheat
D. If reheat is not recommended, please explain
V. RECOMMENDED REHEAT EQUIPMENT CONFIGURATION
A. Type of Reheat Equipment (check one)
1. Direct combustion (see B)
2. Indirect hot air (see C)
3. Inline (see D)
4. Bypass (see E)
5. Other (see F)
The following sections (B-F) are for your recommendations for specific
equipment and configurations.
B. Direct Combustion Reheat
1. Fuel type
2. Combustion chamber type (check one)
Internal
External __
3, Mixing chamber
Materials of construction
Mixing device
4. Recommended nozzle type and materials of construction
193
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5. Control philosophy
C. Indirect Hot Air Injection Reheat
1. Heat exchanger type
2. Materials of construction
3. Heating medium
4. Recommended exchanger configuration
5. Mixing chamber device
6. Control philosophy
D. Inline Reheat
1. Heat exchanger type
2. Materials of construction
3. Heating medium
4. Recommended exchanger configuration
5. Cleaning devices
6. Control philosophy
E. Bypass Reheat
1. Control philosophy
2. Supplemental reheat recommended
F. Other Reheat Methods
194
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VI. QUANTITY OF REHEAT
If not specified by the customer, how do you estimate the quantity of reheat
required?
VII. REHEATER SYSTEM RELIABILITY EXPERIENCE
The following questions relate to your experience with reheat systems.
A. Corrosion
1. Tubes
Materials of construction
2. Ductwork
3. Stack
B. Solids Deposition
Removal Equipment & Location
C. Reheater Material Availability
D. Replacement Parts Availability
E. Maintenance Requirements (Include reheater, downstream fans and
equipment)
195
-------
VIII. What fraction of the total Capital Cost of an FGD System does the
reheat system represent?
What fraction of the total operating cost?
What fraction of the total maintenance cost?
IX. Copies of any sales or technical publications which you distrib
would be very beneficial.
196
-------
IX. USERS OF YOUR EQUIPMENT
PedCo Environmental has identified the following utilities as present or
future users of your equipment. To establish the trends in stack gas reheat,
please complete the following table.
Utility
Type of
reheat
Heating
medium
Degree
of reheat
197
-------
I.
II.
OMB #158-578001
Issued Jan. 25, 1978
Expires Feb., 1979
Attachment III
USER QUESTIONNAIRE
WET SCRUBBING-FLUE GAS REHEAT SYSTEMS
ORGANIZATION INFORMATION
A. Company Name
Address
Telephone Number
B. Person Completing Form
FGD/REHEAT DESIGN AND PHILOSOPHY
A. FGD System Type
1. Full-scale unit
a) New
b) Retrofit
2. Demonstration unit
3. Pilot-plant unit
4. Other (please describe)
city
state
code
name
B. Reheat System (please explain)
1. Recommend and use
198
-------
2. Recommend but do not use
3. Do not recommend
III. TYPE OF FLUE GAS DESULFURIZATION SYSTEM (check one)
A. Wet Absorption
1. Regenerable
a) Wellman-Lord
b) Mag-Ox
c) Other
2. Nonregenerable
a) Lime/limestone
b) Double alkali
c) Other
B. Vendor
C. Installation Date
1. New
2. Retrofit
name
name
name
address
199
-------
IV. SYSTEM DESIGN
A. Mist Eliminator
1. Mist eliminator type
name
2. Mist eliminator location (check one)
a) Horizontal duct
b) Vertical duct
3. Outlet mist eliminator loadings
a) Solids (gr/scf)
b) Condensed vapor (gr/scf)
B. Ductwork and Stack Design
1. Materials of construction
3. Duct size (ftxft) or gas velocity (ft/sec)
4. Stack discharge diameter (ft)
5, Temperature drop between reheat and stack outlet (°
F)
6. Stack height (ft)
C. Flue Gas Properties
1. Gas analysis, scrubber outlet, (volumetric analysis
N2 H20
HC1 S02
02 C02
200
-------
2. Temperature (9F)
3. Volumetric flowrate (acfm)
V. REHEAT EQUIPMENT CONFIGURATION
A. Type of Reheat Equipment (check one)
1. Direct (see B)
2. Indirect hot air injection (see CJ
3. Inline (see D)
4. Bypass Csee E)
B. Direct
1. Fuel type
2. Fuel analysis
Fuel oil Natural gas ('volumetric analysis, %)
(gravimetric (Please list constituents & percentages)
analysis, %)
C
H
N
0
Cl
s
3. Heating value (please indicate higher or lower value)
4. Consumption rate (Please add units)
5. Combustion chamber type
6. Excess Air (%;
201
-------
c.
7. Gas temperature before mixing (°F)
8. Resulting flue gas temperature after mixing (°F)
Indirect hot air injection
1. Hot air properties
a) Flowrate (scfm)
b) Inlet temperature (°F) _
c) Outlet temperature (°F)
d) Outlet specific humidity
.lb water vapor.
( lb dry air '
e) Outlet pressure (psia)
2. Heating medium
a) Medium temperature (°F)
b) Medium pressure (psig)
c) Consumption rate (Ib/hr)
or
(scfm/hr)
d) Heating value or energy supplied
(Btu/lb)
or
(Btu/scfm)
3. Heat exchanger information
a) Tube size
b) Number of tubes/bank
c) Number of banks
d) Materials of construction
4. Mixing method
5. Resulting flue gas temperature (°F)
202
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D. Inline
1. Heating medium
a) Medium temperature (°F)
b) Medium pressure (psig)
c) Consumption rate (Ib/hr)
2. Heat exchangers
a) Tube size
b) Number of tubes/bank
c) Number of banks
d) Materials of construction
e) Tube cleaning device and schedule
3. Resulting flue gas temperature (°F)
E. Bypass
1. Untreated flue gas temperature (°F)
2. Untreated flue gas volume (acfm)
3. Resulting stack gas temperature (°F)
4. SO2 Analysis
a) Scrubber inlet ppm
b) Scrubber outlet ppm
c) Stack outlet ppm
F. Other Reheat Methods
203
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G. Amount of Reheat
1. Required design temperature increase 0
2. Atmospheric conditions
a) Normal temperature range (°F)
b) Normal pressure range (psi)
c) Normal wind speeds (mph)
d) Design plume rise (ft)
e) Discharge stack velocity (ft/sec)
f) Other pertinent information
3. Basis used for selection of amount of reheat
4. Reason(s) for selection of type of reheater
H. Reheater System Reliability Experience (description)
1. Equipment
a) Corrosion
1) Tubes
Materials of construction
2) Ductwork
3) Stack
204
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b) Solids deposition
Removal equipment & location
c) Reheater material availability
d) Replacement parts availability
e) Maintenance requirements (Include reheater, fans &
downstream equipment)
2. Reheat medium availability problems (yes/no)
a) Fuel oil
b) Natural gas
c) Other ('please specify)
I. Plume Dispersion Problems (yes/no)
1. Ground-level pollutants
if yes, weather conditions
windspeed (mph) & directions
wet bulb temperature (°F)
dry bulb temperature (°F)
ground-level concentrations
2. Ground-level fog (yes/no)
if yes, frequency
duration
205
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weather conditions:
3. Rain or moisture fallout (yes/no)
if yes, frequency
duration
weather conditions:
windspeed (mph) & direction
wet bulb temperature (°F)
dry bulb temperature (°F)
J. Reheater Costs
1. Capital costs
a) Equipment ($)
b) Installation ($)
2. Operating costs
a) Reheater duty (percentage of boiler availability)
b) Maintenance costs ($/unit of measure)
c) Reheat medium cost ($)
d) Reheat total cost (percent of boiler output)
206
-------
For units using internal reheat medium, such as steam, please describe the
steps necessary to establish the cost of the fuel. If steam is used, please
indicate its source and condition (pressure, temperature and quality if wet).
VI. SUMMARY OF REHEAT EXPERIENCE
A. Summary of Operating Systems
The following space is for summary information concerning
points raised on the preceding pages.
207
-------
B. Related Experience
The following space is for information regarding past systems
which have failed, and systems presently being designed.
208
-------
APPENDIX C
GENERALIZED 500-MW STEAM CYCLE—DEVELOPMENT AND STEAM COST ANALYSIS
209
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APPENDIX C
GENERALIZED 500-MW STEAM CYCLE—DEVELOPMENT AND STEAM COST ANALYSIS
There are several sources of heat available in a power plant to
accomplish stack gas reheat (SGR). Examples are steam extracted from the
turbine power cycle of a utility boiler, combustion of additional fuel and
addition of hot air. The use of extraction steam from the turbine is ana-
lyzed in this Appendix. Energy and material flows were calculated for a
"hypothetical" 500-MW coal-fired power plant with wet scrubbing of stack
gases and SGR of about 40°F.
The objective of this work is to show the trends associated with the
use of low through high pressure extraction steams for SGR. While a par-
ticular cycle has been chosen for this example, the trends should hold for
all cases. It is expected that high pressure steam will be more economical
(compared to low pressure steam) with respect to _design and cost of the
reheater. However, high pressure steam will be more valuable (because of
higher available energy) with respect to the turbine than the low pressure
steam. This section will provide a methodology for estimating the cost f
various quality steams. In Appendix D, the methodology for designine th
reheat exchangers for various quality steams will be presented.
As discussed above, a "hypothetical" steam cycle was developed in
order to assess the availability and costs of various steam levels that are
applicable as reheat steam. The approach used to identify the applicable
levels and to determine the impact on the steam cycle of using these steam
levels for reheat consisted of:
(1) Developing a base case steam cycle which corresponds
to a new 500-MW power plant with no stack gas reheat (SGR)
210
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(2) Identifying the qualities of steam available for stack
gas reheat (for this "hypothetical" steam cycle only)
(3) Determining the amount of steam at available steam levels
that is required for SGR and adjusting the base case steam
cycle to reflect this requirement while maintaining the same
500 MW turbine output
(4) Estimating the impacts on the steam cycle and the resulting
costs of using reheat steam at the different quality levels
(for the hypothetical cycle only).
DEVELOPMENT OF STEAM CYCLE
The boiler and turbine for new power plant installations can be
designed with extraction steam (normally used for feedwater heating) used
for SGR being taken into consideration in the manner described above. It
is for the new power plant that the above technique best applies. For
retrofit FGD/reheat installations, the boiler/turbine cycle will probably
not be adjustable in the manner described. The resulting energy penalty (for
retrofit cases) associated with extracting steam for SGR may range from the
same as for the newly designed plant (best case) to loss of electrical power
generation capability in proportion to work lost through the steam being ex-
tracted for reheat (worst case). In some retrofit cases main steam may have
to be used for stack gas reheat steam.
This analysis is not intended to be a rigorous calculation of the
costs of steam (at several conditions) within a new power plant. In a power
plant steam is available at turbine exhaust conditions (value of Btu content
is negligible), main steam conditions (value of Btu content is high), and
several intermediate conditions (value of Btu content is between that of
main steam and exhaust steam depending on available energy to produce work).
The following steam cycle development and analysis is intended to provide a
general methodology for assessing the relative value of various quality
steams as SGR steam. These costs for several different quality steams will
be used to estimate the total cost of reheating stack gases.
211
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Base Case Steam Cycle and Approach for Extraction Steam Evaluation
Figure C-l is a schematic of the base case steam cycle. High pressure
steam from the boiler, Stream 1, passes through Stage 1 of the turbine
Each stage may actually be one or more turbine wheels. The main steam fl
(4) is further superheated in the boiler. A minor flow goes to the feed
pump turbine (3) and to heat the feedwater (6). The superheated steam (5)
passes through Stages 2 through 8, respectively, of the turbine. After each
stage, a small amount of steam is extracted and used to heat the boiler feed
water as it passes through the respective feedwater heaters. The main boil
feed pump is large enough that it is driven by a steam turbine.
The base case flow rates corresponding to Figure C-l are presented in
Table C-l, as are the bases for their development. Based on these assump-
tions, the turbine heat rate of the base case steam cycle is 9130 Btu/kWh
Assuming a boiler efficiency of 85 percent gives a gross station heat rate
of 10,740 Btu/kWh on a fuel basis.
After the base case steam cycle was established, the effect "of using
extraction steam following all eight turbine stages as reheat steam was
investigated. Main steam was considered too valuable to be used as stack
gas reheat steam. Only operation of the plant at full load was evaluated
Analysis of each applicable steam level was based on the following appro
(1) The steam requirement to provide the reheat duty was
calculated. The reheat duty was taken as 66.1 x 106
Btu/hr and would heat the stack gas about 40°F (assum-
ing no heat losses from the stack gas through duct and
stack walls and no mist carry-over from the scrubber).
(2) Steam for flue gas reheat was taken at the same condi-
tions as the extraction steam. It was also condensed
at the same conditions as the extraction steam. The
condensate from the flue gas reheater was added to the
condensate from the appropriate feedwater heater.
(3) The steam cycle was adjusted such that all stream
enthalpies are identical to the base case enthalpies
212
-------
ro
G
Figure C-l. Base case.
-------
TABLE C-l. BASE CASE STEAM CYCLE FLOW RATES
Scream Number
1
2
3
4
5
6
7
3
9
10
11
Zb/Hr
3,781,260
3,781,260
205,780
3,391,140
3,391,140
184,340
3,391,140
184,340
3,206,800
184,340
3,022,460
Scream Number
12
13
14
15
16
17
18
19
20
21
22
2b/Hr
115,180
2,907,280
120,300
2,786,980
120,300
2,666,680
120,300
2,546,380
2,752,160
2,113,060
3,228,240
Bases:
(1) A new coal-fired power plant.
(2) 50Q-MW net output.
(3) Steam cycle basis:
• Feedwater heating is accomplished with three closed, low pressure
heaters, one direct contact deaerating heater, and three closed,
high pressure heaters. The three low pressure feedwatar heaters
have equal steam flows.* The deaerating heater operates at 53
psia. The three high pressure heaters have equal steam flow rates
• Throttle conditions are 1000*7, 2600 psia.
Expansion, in the first stage (high pressure turbine stage) is from
throttle conditions to 600 psia at 80 percent efficiency.
Steam is reheated to 1000°? after the first stage.
• Turbine exhausts at 3.5 in. Hg (1.7 psia), 98 percent quality steam
• Lower stage efficiency is 75 percent with each stage exhibiting equal
change in enthalpy. The seven extraction steam conditions w«e set
in the same manner (i.e., alter constant changes in enthalpy through
the turbine). Refer to Figure C-l for these extraction steam condi-
tions.
Feedwater enters economizer at 4508F.
Main boiler feedwater pump is driven by auxiliary turbine using f->rst
stage extraction steam. Auxiliary turbine exhaust conditions are^the
same as exhaust conditions for main power turbine. Pump efficiency
is 85 percent.
Pressure drop in the superheater is 10 percent of the superheater
inlet pressure.
• Feedwater pump discharge is 20 percent greater than drum pressure.
• Parasitic power losses equal to 22 MW (turbine losses, generator
losses, other fixed losses, auxiliary requirements for pulverizers,
fans, ESP's, and miscellaneous requirements). Does not include
scrubber requirements.
*An optimized cycle would probably have equal enthalpy rise through aach
closed feedwater heater. This cycle was selected Co simplify the evalua-
tion.
214
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and such that the turbine output is identical to the
base case output. The steam going to the flue gas
reheater will have generated power in the high pressure
stages of the turbine. The net effect on the turbine
will be to have slightly more power generated in the
high pressure stages and slightly less power generated
in the low pressure stages compared to the base case.
(4) The incremental fuel required to support the steam cycle
with SGR was calculated and compared to the base case
fuel requirement.
(5) The decrease in the main condenser load and the size
of the changes in steam flows within the turbine are
also evaluated.
The same approach was used to determine the impact of using hot water to
reheat flue gas. The hot water was extracted from the condensate stream
exiting the number 3 heater (see Figure C-l). After use in the reheater
the "cooled" water was mixed with the boiler feedwater exiting heater 5.
Results
Based on the above assumptions and procedures, the following results
were obtained:
(1) Extraction steam is considered suitable if its pressure
is higher than the flue gas pressure. In case of tube
failure, steam will leak into the flue gas rather than
flue gas into the steam. This restriction eliminates the
5.6 psia and 1.7 psia steam levels.
(2) Depending on the steam level selected, the amount of
additional fuel required to yield 66.1 x 10s Btu/hr
of stack gas reheat is approximately 0.4-1.1 percent
of the total fuel consumption of the plant (5370 x 106
Btu/hr). The 0.4 percent number corresponds to the
lower level steam (334°F, 16 psia), and the 1.1 percent
figure refers to the highest level steam (639°F, 600
psia). The incremental heat input required by the steam
cycle is always less when using extraction steam for
reheat than the actual Btu's transferred to the stack
gas in the reheat exchanger. This is what one would
intuitively expect. If exhaust steam would suffice,
215
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the increased heat requirement would have been zero.
Had steam at high pressure throttle conditions been
used, the heat input increase (to the steam cycle)
would have been on a one-to-one basis compared to
the heat transferred to the stack gas in the reheat
exchanger. This indicates that, as the availability
of energy in the steam that can be converted to work
decreases, the impact of its removal from the cycle
decreases.
(3) The flow diagrams and stream flow rates that result
from the use of the various applicable steam levels
are presented in Figures C-2 through C-7 and Tables
C-2 through C-7.
(4) The addition of an SGR system to the base case steam
cycle increases the required heat input and decreases
the condenser load. These results are shown in Table
C-8. The increased heat input to the steam cycle re-
sults in increasing the boiler fuel requirements; this
result is shown in Table C-9.
(5) The influence on turbine flow rates is of interest
in new and especially retrofit situations. The
percent change in steam mass flow rate after each
turbine stage was calculated for all cases evaluated
(see Table C-10). The turbine flow differences are
usually less than 1 percent and always less than 2
percent. Therefore, it is realistic to expect that
the design of new turbines could be adjusted to pro-
vide flue gas reheat steam in a manner similar to
that described in this section. Use of extraction
steam for reheat in retrofit applications may, how-
ever, result in a greater increase in fuel require-
ments or in a decrease in plant output.
COST OF EXTRACTION STEAM
For a new 500-MW plant the annualized cost associated with each
level that is suitable for reheat includes a capital cost and an operati
cost component. If SGR is to be used in a new 500-MW power plant, the
capital cost component reflects larger capacities of certain facilities
compared to the 500-MW plant with no reheat. Those facilities that could be
expected to be larger are:
216
-------
Figure C-2. Extraction after Stage 1.
-------
to
M
00
Figure C-3. Extraction after Stage 2.
-------
ro
M
vo
Figure C-4. Extraction after Stage 3.
-------
Ni
IXi
O
70-1261-2
Figure C-5. Extraction after Stage 4.
-------
1-0
N>
Figure C-6. Extraction after Stage 5.
-------
Ni
to
Figure C-7. Extraction after Stage 6.
-------
TABLE C-2. FLOW RATES FOR EXTRACTION AFTER STAGE 1
Stream Number
1
2
3
4
5
6
7
3
9
10
11
12
Ib/hr Stream Number
3,835,540 13
3,835,540 14
205,780 15
3,367,950 16
3,367,950 17
183,310 18
3,367,950 19
181,730 20
3,186,220 21
181,730 22
3,004,490
114,540 Rl
Ib/hr
2,889,950
119,630
2,770,320
119,630
2,650,690
119,630
2,531,060
2,736,840
3,095,730
3,210,270
78,500
TABLE C-3. FLOW RATES FOR EXTRACTION AFTER STAGE 2
Stream Number
1
2
3
4
5
6
7
8
9
10
Ib/hr Stream Number Ib/hr Stream Number
3,819,780 11 2,999,990 21
3,819,780 12 114,380 22
205,780 13 2,885,610
3,428,470 14 119,460 R2
3,428,470 15 2,766,150
185,530 16 119,460
3,428,470 17 2,646,690
183,060 18 119,460
3,183,050 19 2,527,230
183,060 20 2,733,010
Ib/hr
3,091,390
3,205,770
62,360
223
-------
TABLE C-4. FLOW RATES FOR EXTRACTION AFTER STAGE 3
Stream Number
1
2
3
4
5
6
7
8
9
10
Stream Number
1
2
3
4
5
6
7
8
9
10
Ib/hr
3,814,400
3,814,400
205,780
3,422,960
3,422,960
185,660
3,422,960
185,660
3,237,300
182,610
TABLE C-5.
Ib/hr
3,808,370
3,808,370
205,780
3,416,930
3,416,930
185,660
3,416,930
185,660
3,231,270
185,660
Stream Number
11
12
13
14
15
16
17
18
19
20
FLOW RATES FOR
Stream Number
11
12
13
14
15
16
17
18
19
20
Ib/hr Stream Number
2,992,150 21
114,100 22
2,878,050
119,170 R3
2,758,880
119,170
2,639,710
119,170
2,520,540
2,726,320
EXTRACTION AFTER STAGE 4
Ib/hr Stream Number
3,045,610 21
112,020 22
2,870,640
118,880 R4
2,751,760
118,880
2,632,880
118,880
2,514,000
2,719,780
Ib/hr
3,083,830
3,197,930
62,540
Ib/hr
3,076,420
3,251,390
62,950
224
-------
TABLE C-6. FLOW RATES FOR EXTRACTION AFTER STAGE 5
Stream Number
1
2
3
4
5
6
7
8
9
10
Ib/hr
3,802,080
3,802,080
205,780
3,410,970
3,410,970
185,330
3,410,970
185,330
3,225,640
185,330
Stream Number Ib/hr Stream Number
11
12
13
14
15
16
17
18
19
20
TABLE C-7. FLOW RATES
Stream Number
1
2
3
4
5
6
7
8
9
10
Ib/hr
3,795,590
3,795,590
205,780
3,404,770
3,404,770
185,040
3,404,770
185,040
3,219,730
185,040
Stream
11
12
13
14
15
16
17
18
19
20
3,040,310 21
114,630 22
2,295,680
118,550 R5
2,743,510
118,550
2,624,960
118,550
2,506,410
2,712,190
FOR EXTRACTION AFTER STAGE 6
Number Ib/hr Stream Number
3,034,690 21
115,610 22
2,919,080
120,020 R6
2,799,060
118,200
2,616,620
118,200
2,498,420
2,704,200
Ib/hr
2,131,460
3,246,090
63,620
Ib/hr
3,124,860
3,240,470
64,240
225
-------
TABLE C-8. IMPACT OF UTILIZING VARIOUS STEAM LEVELS FOR SGR ON BASE CASE STEAM CYCLE
NJ
Energy Change ! ,
Extraction Conditions for SGR
After
Stage
6
5
4
3
2
1
Temp . ,
°F
344
475
610
745
870
639
Pressure,
psia
16
39
83
165
310
600
Saturation
Temp., °F
216
266
315
366
421
486
Flow,
Ib/hr
64,240
63,620
62,950
62,540
62,360
78,500
106 Btu/hr
Increase in
Steam Cycle
Energy Input
17.6
25.7
33.4
40.0
46.8
50.6
Decrease in
Condenser
Load
48.5
40.4
32.7
26.1
19.3
15.5
Steam Cycle Heat
Input Increase2
(Fraction of
Reheat Duty)
0.266
.389
.505
.605
.708
.766
Sum (absolute value) of steam cycle increase and condenser decrease equals SGR heat requirements
(66.1 x 106 Btu/hr).
2Example : For extraction after turbine stage 6, fraction of reheat duty = (17.6 x 106 Btu/hr)/
(66.1 x 106 Btu/hr) = 0.266.
-------
TABLE C-9. IMPACT OF UTILIZING VARIOUS STEAM LEVELS FOR SGR ON BASE CASE FUEL REQUIREMENTS
Reheat Steam Taken Increase in Fuel Fraction of Base Case
After Turbine Stage Requirements1, 106 Btu/hr Plant Fuel Requirement2
6 20.7 0.0039
5 30.2 .0056
4 39.3 .0073
3 47.1 .0088
2 55.1 .0103
1 59.5 .0111
base case fuel requirements. This is the fuel (to boiler) makeup required to supply 66.1 x
106 Btu/hr of reheat steam.
Base case fuel requirement is 5370 x 106 Btu/hr.
ro
K>
-------
TABLE C-10. TURBINE FLOW CHANGES
to
Main Steam Flow (Percent Change From Base Case Flows)
After Turbine
Stage
1
2
3
4
5
6
7
8
Base Case Flows,
103 Ib/hr
3,781
3,391
3,206
3,022
2,907
2,786
2,666
2,546
6
0.37
0.38
0.41
0.40
0.41
0.47
-1.88
-1.89
Reheat Steam Taken After Turbine Stage
5432
0.56
0.59
0.59
0.60
0.62
-1.54
-1.57
-1.57
0.71
0.74
0.78
0.76
-1.27
-1.26
-1.27
-1.26
0.87
0.91
0.97
-0.99
-1.00
-1.00
-1.01
-1.02
1.01
1.09
-0.72
-0.76
-0.76
-0.72
-0.75
-0.75
1
1.42
-0.71
-0.63
-0.60
-0.62
-0.57
-0.60
-0.59
Example: If the flue gas reheat steam is extracted after turbine stage 6, then the following
analysis can be developed (using data from Tables C-l and C-7).
Stream
Number
Figure C-l
Location
(After Turbine
Stage)
1
2
3
4
5
6
7
8
Base Case
Flow Rate
From Table C-l
(103 Ib/hr)
3,781
3,391
3,206
3,022
2,907
2,786
2,666
2,546
Case Adjusted
for Reheat
From Table C-7
(103 Ib/hr)
3,795
3,404
3,219
3,034
2,919
2,799
2,616
2,498
Percent Change in
Flow of Adjusted Case
Compared to Base Case
0.37
0.38
0.41
0.40
0.41
0.47
-1.88
-1.89
-------
(1) The coal preparation and handling equipment
(2) The boiler and associated equipment
(3) FGD system and solid waste disposal area
(4) Plant stack and duct work
(5) Larger fans to overcome system AP for air and stack
gases associated with the added fuel firing rate.
The operating cost component consists of fuel and operating and maintenance
costs. These components as well as the annualized costs of the various
steam levels are summarized in Table C-ll and are developed below.
Capital Component of Steam Cost
The bases for developing the capital component of the steam cost are
presented below:
..Total capital requirement for 500-MW power plant = $800/kW (mid-1978
dollars)*
Fraction of plant capital cost that will
increase in proportion to the increase
in fuel firing because of the addition
of reheat (Derived from information = ^65 percent
reported by Bechtel)33
Using the bases presented above and the incremental fuel required for using
the various levels of steam for reheat, the capital investment required for
the production of reheat steam in the quantities required for this example
problem is estimated and shown in Table C-ll.
*Includes installed equipment cost, contingency, allowance for funds used
during construction, and other indirect costs.
229
-------
NJ
OJ
O
TABLE C-ll. COSTS OF VARIOUS LEVELS OF STEAM (NEW 500-MW PLANT)
TO PROVIDE 66 x 106 BTU/HR OF REHEAT
Additional
Extraction Steam for Reheat
Flow Kate
(103 Ib/hr)
64.2
63.6
63.0
62.5
62.4
78.5
Steam
(psia)
16
39
83
165
310
600
Temp.
CF)
344
475
610
745
870
639
Fuel Requirements
10' Btu/hra
20.7
30.2
39.3
47.1
55.1
59.5
Fraction of
Base Case
.0039
.0056
.0073
.0088
.0103
.0111
Capital0
Investment
(103 $)
1010
1460
1900
2290
2680
2890
Operating
Costs
(103 $/yr)
236
345
448
537
629
679
Annual
Revenue
Required
(103 $/yr)
373
542
705
846
991
1069
Steam Costs (1978 $)
$/106
Btu*
0.81
1.17
1.52
1.83
2.14
2.31
Superheated
$/1000 lbe
0.83
1.22
1.60
1.93
2.27
1.95
Saturated
$/1000 Ib
0.78
1.10
1.37
1.57
1.73
1.69
534.0
Hot Water 366
49.0
.0093
2420
565
891
1.93
This is the additional fuel required to provide 66.1 x 106 Btu/hr of reheat steam at the stated quality.
The plant ba.se case fuel consumption is 5370 x 10 Btu/hr.
This reflects increased capacity of some plant equipment as a result of adding reheat to plant (fraction of base case fuel requirement x
base case total plant capital investment x 0.65).
This reflects the incremental fuel and plant O&M costs |($1.00/106 Btu + $0.63/106 Btu) x additional annual fuel requirement].
^Annual revenue required to generate additional steam for 66.1 x 106 Btu/hr of reheat.
Unit cost of steam is based on annualized cost of plant (annual revenue requirement divided by 66.1 x 10 Btu/hr x 7000 hr/year).
^Annual revenue requirement divided by annual steam flow.
*Cost of saturated steam at same pressure using desuperheater.
-------
Operating Cost Component of Steam Cost
The operating cost component of the steam cost reflects the incremental
fuel requirements and O&M charges. The bases for the development of these
operating cost components are presented below.
Fuel cost = $1/106 Btu
Operating and maintenance costs* for 500 MW plant = 'W mills/kwh
= ^$0.63/106 Btu of
fuel input
Using these assumptions, the calculated incremental fuel input required for
producing reheat steam, and the calculated fractional increase in plant capac-
ity, the operating cost component of the steam costs was determined.*" This
component is shown in Table C-ll.
Annual Revenue Requirement
The annual revenue requirement for each steam level was developed by
combining the annual operating cost component and the annual cost associated
with capital investment. The expression and bases for developing the annual
revenue requirement follow, while the costs are presented in Table C-ll.
A utility financing method was chosen as the basis for estimating
annual costs of owning and operating reheat equipment. Presented below is
a derivation of the equations used:
(1) Nomenclature and assumptions:
Total federal and state taxes - 50 percent
C = total capital investment required
* Includes O&M for boiler, turbine, and all auxiliaries (including FGD system
and solid waste disposal).
**A capacity factor of 7000 hr/yr was selected.
231
-------
N = annual operating cost = heating media cost 4-
O&M cost
d = fraction debt
± = interest rate for borrowing capital
r = percent return on equity
p = percent return on rate base
m = equipment life in years
TRR = total revenue requirement over the life of the equipment
Depreciation schedule is straight line .
(2) Calculate rate base in n year
Depreciable investment = C
Accrued depreciation at mid-point of n year = (1/m) (n-0 5">r
Rate base = C-(l/m)(n-0.5)C = C[l-(l/m)(n-0.5)]
(3) Calculate percent return on rate base
p = (d)i + (l-d)r
(4) Calculate cash flows in n year
Return on rate base = 0.01 p C[1-(1/m)(n-0.5)]
Return on equity* = 0.01 r C[l-d][l-(l/m)(n-0.5)]
Taxes* = 0.01 r C[l-d][l-(l/m)(n-0.5)]
Depreciation = C/m
Annual revenue requirement** = N 4- return on rate base +
i . *
depreciation
« N + C/m + 0.01 C [p + r(l-d)][l - (1/m)(n-0.5)]
*Return on equity and state and federal taxes are identical when the ta
rate is 50%.
**Return on equity (ROE) is included in return on rate base calculation.
ROE was calculated separately so that state and federal taxes could be
r» a 1 CMI 1 a 1"pH .
calculated.
232
-------
(5) Calculate total revenue requirement over the life of the
project (assuming no operating cost escalation)
TRR = mN + C + 0.01 C [p + r(l-d)]
i 2
n=l
TRR - mN + C + 0.005 m C[p + r(l-d)]
(6) Average annual revenue requirement = ARR = TRR/m
ARR = N + C/m + 0.005 C[p + r(l-d)]
(7) As a basis for this study:
a) All investments and operating costs are expressed
in terms of 1978 dollars.
b) Operating costs (N) are not escalated.
c) d - 0.50
d) r - 14
e) i - 10
f) Therefore p = 12
TRR « mN + C + 0.095m C
ARR - N + C/m + 0.095 C
g) The Average Annual Revenue Requirement will be used
to make economic comparisons when expected equipment
life is known.
Cost of Various Steam Levels
The costs developed for various steam levels from the "hypothetical"
steam cycle are presented in Table C-ll. Although it is recognized that
steam costs are very site specific, the relative costs (trends) of the steam
levels are expected to be similar for other steam cycles. Factors that will
233
-------
influence steam costs are the design of the steam cycle, fuel costs fuel
quality, capital cost of the power plant, and turbine design, etc. The ste
costs shown in Table C-ll are considered to be the costs of reheat steam th
would be obtainable from new 500-MW power plants.*
Costs for superheated steam (at extraction steam conditions) and
saturated steam (superheated steam is desuperheated by spraying condensate
into the steam) are presented in Table C-ll. Reheat users responding to th
OMB-approved survey stated that the use of saturated steam (instead of suoe
heated steam) offers reliability advantages.
Costs of steam from existing power plants for retrofit FGD/SGR or SGR
systems are much more difficult to quantify. The value of steam, at a e'
quality, could range from:
(1) the marginal cost (fuel only) of producing that steam to
(2) the value of the lost power production resulting from
utilizing the steam in a reheater.
Also sufficient quantities of steam for reheat purposes may not be availabl
for extraction on existing turbines.
Any of the reheat cases developed in this study could be used to esf
mate the cost of SGR on retrofit installations. The cost of the steam is
the unknown quantity. Available boiler fuel capacity, turbine ability to
provide sufficient steam quantities, resulting turbine output and heat rate
after extraction of reheat steam, and fuel value would have to be evaluated
to determine a steam cost.
*These are the steam qualities that are evaluated in Chapter 7 to develop
costs. It is recognized that these steams do not absolutely define the
availability of steam for SGR at any power plant. However, the relative
costs are expected to be reasonable and the use of different quality steam
would not be expected to change the general results and trends noted in this
study.
234
-------
APPENDIX D
EQUIPMENT SIZING BASES
(REHEAT EXCHANGERS, FANS, STACKS)
235
-------
APPENDIX D
EQUIPMENT SIZING BASES (REHEAT EXCHANGERS, FANS, STACKS)
INTRODUCTION
The calculational procedures and bases for sizing the equipment
required for various reheat configurations are presented in this aoo H1
BASES
A 500-MW plant was selected for the base case in all reheat econo '
calculations. The base coal and scrubbed flue gas composition for this
plant is presented in Table D-l along with the scrubber exit gas composi-
tions that result from different primary fan placements and reheat confi
urations (see Figure D-l). The heat rate of the plant is 9000 Btu/kWb.
HEAT EXCHANGER SURFACE AREA REQUIREMENTS
For the inline, indirect hot air, and exit gas recirculation reheat
schemes, heat exchangers are required. In this report, capital investment
for these reheat schemes are calculated on the bases of estimated exch
surface area. Exchanger surface area will be a function of steam qualit
exchanger gas-side pressure drop, temperature profiles, and tube orientati
and dimensions, etc. An accurate estimate of the factors affecting th
is desired in order to develop meaningful cost estimates.
To estimate the exchanger surface area required, the quantity of he
that is needed to achieve a given level of reheat must be determined. TH•
heat requirement (at steady-state) can be calculated with Equation D-l (a
nomenclature section is presented at the end of Appendix D). Equation D-l
236
-------
TABLE D-l. PLANT CHARACTERISTICS AND PRIMARY FAN CONFIGURATIONS
IsJ
U>
Power Plant liases. Fuel and Flue Gas Compositions .
Coal Composition Flue Gas
Power Plant Height
Characteristics Component Percent Component
• Hew, 500-MU C 57.56 N2
• 9.000 Btu/kUh U 4.14 02
Ueac Rate N t ?9 CQ *
• Flue gas temperature „ ,_„„ SQj
entering scrubber Is
JOO'F S 3.12 SO,
Cl 0.15 NOX
II20 10.74 IIC1
Ash 16. OO H20
Heat Content 10,500 Btu/lb
Mncludes a
Primary Fan Arrangement and Equlpme- - Pressure Drop
Equipment Pressure Drop Impact of Fan Location on Flue Gas Composition
• Boiler AP - 22 in. H2O Fan Configuration Forced Draft
34 "AP
• Scrubber AP • 9 In. H20 (Figure U-.la)
• Reheat Exchanger
AP - 6 In. H20 Saturation Temperature, (°F) 130
AP « \ u ci Normalized Flue Gas
2 Composition
Component Ibs/hr
N2 3,471,000
02 259,700
CO 2 909,600
H20 498,400
5,139,000
Composition Knterlnt;
Volume
Percent
73.76
4.83
12.31
0.24
0.0024
0.06
0.01
8.79
small amount of CO
Assumpt ions
Scrubber
Ib/hr
3,450,000
258.200
904,200
25.130
317
3,022
661
264,500
4.906,030
and Adlabatic Saturation Temperature
Forced Draft
40"AP
(Figure D-lb)
131
Ib3/hr
3,471,000
259,700
909,600
501,600
5,142.000
Induced Draft
40"AP
(Figure I)-lc)
126
Ibs/hr
3.471,000
259,700
909,600
480,100
5,120.000
Note: The flue gas spc-clflc lieut ol uauh configuration was taken
0.26 Iltu/11i-'F.
-------
Temperature
CF)
•V300
M20
^130
M30
Absolute
Pressure
(in. H20)
376.8
410.8 t
401.8
398. S
<^S .— ! — Ss£ — ^ ^ _., /
Fuel »• ^ (-») '-^
h-— - For tied j'-tuuuet
BOU« Draft
Fan
Stack
(a) Forced draft FGD system with no reheat (overall pressure droo
34 in. H20)
Temperature
CF)
•^300
^320
•v.131
M81
•v.181
Absolute
Pressure
(In. H20)
376.8
416.8
407.8
401.8
398.8
U- — torced jctubbei
Boiler Draft
Fan
Stack
'Reheat
Exchanger
(b) Forced draft FGD system with inline reheat (overall pressure drop
40 in. H20)
Absolute
Temperature Pressure
CF)
(in.
^300
-v-126
•^156
M76
M76
Fuel—»|
Boiler
Scrubber
Reheat
Exchanger
Draft
Fan
(c) Induced draft FGD system with inline reheat (overall pressure drop =
40 in. H20)
Figure D-l. Schematics of FGD systems with different primary fan positions
238
-------
reflects the assumptions that no liquid is entrained in the flue gas and no
heat is lost from the flue gas (through the walls of the duct and stack):
CFGAtEB
In this expression, At_,_ represents the difference between the stack exit
EB
and scrubber exit temperatures or the desired level of reheat.
The amount of steam required to supply this energy is obtained next.
Using dry, saturated steam and condensing it in the reheater, the required
•
steam flow (m ) is:
mg = Q/\ (D-2)
where A is the latent heat of vaporization of the steam.
The reheaters considered in this study have the gas flow outside and
perpendicular to the tubes. The heating medium, steam or water, will flow
inside the tubes. Since major economic factors of reheater design will be
surface area and gas-side pressure drop, a correlation relating these two
variables is developed.
The pressure drop is best correlated in dimensionless form. The
pressure drop is calculated as the number of velocity heads lost per column
of tubes. Equation D-3 does this.
AP = (AfN)(v2/2g) (D-3)
The friction factor, f, is normally correlated as a function of the
Reynolds number.
239
-------
(D-4a)
= 3M (D-4b)
The standard equation for heat transfer is given in Equation D-5
Q = U ^ AtH (D-5)
where ^ is the exchanger surface area, U is the overall heat transfer
ficient, and At^ is the logarithmic mean temperature difference (Fie
Equation D-6 is useful if one thermal resistance is much smaller
the others. This is the case with condensing steam and turbulent h
The inside coefficient is much higher than the gas-side coefficient
result, the gas-side coefficient is a good approximation of the overall
coefficient and equation D-5 becomes:
Q = hVCH (D-6)
where h is the gas-side heat transfer coefficient and A ±s the total h
transfer surface area (surface area on outside of tubes).
Heat transfer coefficients are also best correlated with dimensionl
groups. A frequently used form is Equation D-7.
3 2/3 .
?r = JH (D-7)
The "j" factor for heat transfer is normally assumed to be a funcf
of the Reynolds number.
240
-------
In many cases, including gaseous flow outside of tubes, the j-factors for
heat and momentum transfer are considered equal. This is known as the Colburn
j-factor analogy. It can provide an estimation method for heat transfer or
pressure drop if only one is known. In this study the pressure drop across
the exchanger will be estimated, allowing calculation of the heat transfer
coefficient. The tube bundle layout for this analysis is shown in Figures
D-2 and D-3. The Reynolds number is based on the tube diameter and the maxi-
mum actual velocity, v, that occurs in the bundle and -is determined from
equation D-9.
Re = Dvp/y (D-9)
For the equilateral triangular pitch used in this study, this maximum velocity
will occur in the space, S-D, between tubes perpendicular to the flow as
shown in Figure D-2.
The pressure drop equations, D-3 and D-4, may be combined to yield:
AP = (8JMN)(v2/2g) (D-10)
The j-factor is already a function of Reynolds number, Re, only.
The velocity term may be converted to Re by multiplying and dividing by
(Dp/u)2.
AP - fS(BlB.-) R*'^)' (D-ll,
This equation may be solved for Re:
The Reynolds number in Equation D-12 may be substituted into the heat
transfer j-factor equation. Rearrangement of Equation D-7 and use of
241
-------
-i f-
S-D
Figure D-2. Front view of first column
of reheater tubes.
ROW
COLUMN 1
-r (*•»•
o
o •- o
o o •••• o
o
O : O •••• O
: : O :
• O O •••• O
Figure D-3. Side view of reheater tubes.
242
-------
Equations D-8 and D-12 results in the heat transfer coefficient given by
Equation D-13b.
CFrpv
h - -£y7v jp (D-13a)
pr2/3 H
(D-13b)
Steady-state energy and mass balances must be made to solve these equa-
tions. The mass balance relates the total flue gas flow to tube geometry and
velocity as shown in the following expressions:
pv (S-D)LM (D-14a)
= pv (S/D-DDLM (D-i4b)
The heat balance requires that the heat added to the flue gas as calcu-
lated by the transfer mechanism is equal to the heat added as calculated by
an energy balance. The schematic in Figure D-4 describes the terms to be
used. Equation D-6 defines the heat required by the heat transfer mechanism,
and substitution of the variables that define the heat transfer area into
this expression yields:
Q - h TTDLMN Atu (D-15)
n
where TrDL is the surface area of one tube and MN is the total number of
tubes.
243
-------
at Source ^
Out ,j
In
iti - 9j-t,
ti
>
Reheater
1- n "I- it 2 -it i
Vt\
litj
i
Heat Sou
- 8,-tj
tj
Out
For Energy Balance,
Figure D-4. Schematic of inline reheater for energy balance consideration
The steady-state energy balance term is written in terms of the veloc't
using Equations D-l and D-14.
JFG EB
pv (S/D-1)
(D-16a)
(D-16b)
Equations D-15 and D-16b may be equated:
hTTDLMNAt = pv (S/D-1) DLMC^ At
H FG EB
hiTNAtH = pv (S/D-1)
(D-17a)
(D-17b)
The value for h from Equation D-13b may be substituted into equati
D-17b resulting in:
CFGPV.
Pr
273 a2|4Na
:AP /Dp\ 21:
Nai ^u ) J
7rNAtu » pv (S/D-1)
H
(D-l8a)
mo. 2
pr2/3 [4Nai
-n;
^f"
y JJ
AtT = (S/D-1) At
EB
(D-18b)
244
-------
If the pressure drop (AP) is assumed, the number of columns, N, becomes
the only unknown in Equation D-18b.
N. flS/Ihl)_Pr
2'3
(S/D-1) Pr
EB
2-nt
gAP
2-ni""! 2+(n2-ni)
2-m
2+(n2-ni)
AP
2+(n2-ni)
(D-19a)
(D-19b)
The other variables and parameters in this expression may be determined
from the physical properties of the flue gas or exchanger. The Reynolds
number is calculated from Equation D-12 now that N is known. The velocity,
v, can be calculated from the definition of Re (Equation D-9).
v - Re/(Dp/y)
(D-20)
The total tube length per column, LM, for the number of tubes in a
column, may be solved from Equation D-21, which was derived from the rear-
rangement of Equation D-14. The parameters, DLM (S/D-1) collectively repre-
sent the cross sectional area available for the flow of flue gas.
LM
FG
pv D(S/D-1)
(D-21)
A reasonable value for L is selected so that M may be calculated.
The total surface area required for heat transfer can now be obtained
with the following expression:
NLM7TD
(D-22)
To compensate for possible fouling, 25 percent additional area is added
to the areas calculated for the exchanger in the inline and exit gas
245
-------
recirculation reheat configurations. A safety factor of 10 npT-^r,-
j-u percent was used
for the indirect hot air configuration.
The heat transfer coefficient is also of interest. It ran n~ u
•uu "-<*" now be cal-
culated using Equations D-7 and D-8.
(D-23)
As an example, the area for the inline exchanger using 600 psia
saturated steam with a 6-inch (water) pressure drop is calculated (
E-l, Appendix E). In this example, the values of the flue gas phvsi
properties that are used are determined at the average temperature
flue gas.
Assumptions:
(1) Flue gas temperature (entering exchanger) = 131°F
(2) Flue gas temperature (exiting exchanger) = 181°F
(3) 1-inch O.D. tubes for the reheat exchanger
(4) 3-inch center-to-center equilateral tube spacing
(5) Pr = CFG y
K
= (.26)(1.34 x 10"5)/(4.44 x 10~s) = 0.78
(6) Exchanger pressure drop (AP) = 6" H20 = 495 feet of gas
(pH20 considered to be 62.4 Ib /ft3 for all cases).
m
(7) p = MW x P/R x T = average density of flue gas
= 28.5(14.6)/10.73(460 + 156) = .0629 lb/ft3
(8) AtEB = (181-131)°F = 50°F
(9) At = (486-131) °F - (486-181) °F/ln ^""^l£ • 329°F
n *
(10) ni = .247 n2 = .40
cci = .36 a2 = .33 (Ref. 34)
(11) g = 32.2 ft/sec2
246
-------
First the amount of energy required to heat the flue gas 50°F will
be obtained for a 500-MW plant (assuming no heat losses or mist carry-over)
Q = mfg CFG(At)
= 5,140,000 ^ x .26
= 66.8 x 106 Btu/hr
(D-l)
x (181-131) °F
The amount of steam required to achieve the specified heat duty is obtained
next.
QA
(66.8 x 106 Btu/hr)/(732 Btu/lb)
91,300 Ib/hr
(D-2)
The number of tube columns can now be calculated. Putting the above
parameters into Equation D-19b yields:
2-.247 .4
(3-1) (.78)2/3 /50
TT .33
2+(.4-.247)
32.2(495)
4(0.36) U.34 x 10-s
;.0629)
16.8
2+(.4-.247)
(D-19b)
The Reynolds number through the exchanger may be obtained using Equation
D-12.
Re
FgAP /Dp\2]
4Nai \y /
U J
32.2(495) /l/12(.0629)\z| 2-.247
14(16.8) (.36) U.34 x lO"5/
36,700
1 2-.
1
(D-12)
247 >
-------
The flue gas velocity is obtained with the following expression-
v = Re/
-------
h = 3600 CFGpva2Re~'VPr2/3 (D-23)
= 3600 (.26)(.0629X94 )(.33)(36,700)~"*/(.78)2/3
= 32 Btu/hr-ft2-F° (before providing fouling safety factors)
The results of the above sample calculation are as follows:
(1) Flue gas temperature increase = 50°F
(2) Heat input required = 66.8 x 106 Btu/hr
(3) Flue gas flow rate = 5.14 x 106 Ib/hr
(4) Required steam flow rate = 91,000 Ib/hr
(5) Number of tube columns (N) =16.8 (without 25% extra tubes)
(6) Reynolds number displayed by flue gas (Re) = 36,700
(7) Flue gas velocity (v) = 94 ft/sec
(8) Total tube length per column (LM) = 1450 ft
(9) Total heat transfer area - 8,000 ft2
(10) Outside (of tube) heat transfer coefficient (h ) = 32 Btu/hr-ft2-°F
o
(11) Assuming a square duct for four individual reheat modules, the exchanger
dimensions can be calculated:
Duct width = 9.5 ft
Total exchanger / T „ ., 0 , / ,1N iic
,. ° - 4 x L xMxNx3.14x
-------
recirculation cases, an auxiliary fan is required for each module rather than
an increase in the main fan size.
In developing costs, an estimated mid-1978 price index was used. Shaft
horsepower was calculated as follows (Ref. 36):
HP = .000157 x qxAP/n ,_
(D-24)
whe re:
q = the gas flow rate, acfm
AP « the developed head, in. H20
H " fan efficiency
HP = shaft horsepower
Example
For a system having a flue gas flow rate of 5.14 x 10s Ibs/hr and no
reheater (Case A, Figure D-l), four 2760 horsepower fans were required
The addition of an inline reheater results in an additional six-inch
pressure drop to this system (see Case B, Figure D-l). This ultimately
requires the use of four 3260 horsepower fans. The incremental capital
cost and power costs are shown in Table E-l and Appendix D.
STACK SIZE
A significant increase in flow rate occurs in the stack with the
indirect hot air method. Rather than increase the stack velocity and
therefore the pressure drop, it was decided to increase the stack diam
and keep the velocity constant. In actuality, both velocity and diamet
would probably be increased. A constant 60 ft/sec velocity was select d
This gave a 22.4 ft diameter stack for the base case 500-MW plant.
Again, only the incremental stack cost was charged to the reheat
system. It was assumed the stack height would be constant and that the
price was linear with diameter. A base price of $2,550,000 (1978$) for tv
stack (22.4 ft diameter) was used. The incremental stack cost is calculat
as follows:
250
-------
D
AStack Cost =• 1 -~j- - 1 ) $2,550,000
£^ • ^f
(D-25)
where D
(lb/hr)
new
p(lb/ft3)x60 (ft/sec)x3600 (sec/hr)7rj
.5
(D-26)
251
-------
NOMENCLATURE
A area, (ft2)
C heat capacity, (Btu/lb-F°)
D tube or stack diameter, (ft)
f friction factor, (dimensionless)
gc dimensional constant, (ft-lbF/lbm-sec2)
h gas film coefficient, (Btu/hr-ft2-F°)
HP power, (hp)
j j-factor function, (dimensionless)
K thermal conductivity, (Btu/F°-ft-sec)
L tube length, (ft)
M number of tube rows per column
m mass flow rate, (Ib/hr)
MW molecular weight, (lb/lb mole)
n exponent in j-factor correlation
N number of tube columns
p" average pressure, (psia)
P pressure, (ft of fluid)
Pr Prandtl number, (dimensionless)
q volumetric flow rate, (ft3/min)
Q heat transferred, (Btu/hr)
R gas constant, (10.73 psia ft3/R°-lb mole)
Re Reynolds number, (dimensionless)
S tube spacing, (ft)
t temperature, (°F)
U overall heat transfer coefficient, (Btu/hr-ft2-°F)
v maximum velocity, (ft/sec)
W total mass flow rate, (Ib/sec)
252
-------
Greek
\ latent heat of vaporization, (Btu/lb)
a coefficient in j-factor correlation
U viscosity, (Ib-Vft-sec)
M
H efficiency
p density, (lbM/ft3)
M
9 heating fluid temperature, (°F)
A difference in two quantities (such as temperature, pressure, etc.)
Subscripts
EB energy balance
FG flue gas
H heat transfer
L logarithmic
S steam
A air
M momentum transfer
momentum transfer correlation
2 heat transfer correlation
253
-------
APPENDIX E
REHEAT CONFIGURATION COMPONENT COST ASSUMPTIONS
254
-------
APPENDIX E
REHEAT CONFIGURATION COMPONENT COST ASSUMPTIONS
INTRODUCTION
This Appendix presents the bases for the costs used for each component
of the reheat system. These include equipment costs, installation costs,
indirect costs, operating costs and other items included in the annual
revenue requirement. The equipment considered, as well as the bases used,
is presented below. Cost summary sheets for each reheat system evaluated
are presented at the end of this Appendix.
DIRECT EQUIPMENT COSTS
Heat Exchanger
Materials—
Responses to the industry questionnaire (distributed to reheat users,
A/E firms, and FGD process vendors) indicate that:
(1) Carbon steel tubes are used or recommended for use in
most indirect hot air reheat systems, and
(2) Current practices and recommendations for inline reheat
range from carbon steel to Inconel 625.
Although these is no industrial experience with exit gas recirculation
reheat, the gases in contact with the exchanger would probably be less
corrosive than that in contact with an inline exchanger.
255
-------
The tube materials used for inline reheat will be very site
and depend on the:
(1) Chloride and sulfur content of the coal
(2) Type of scrubbing system used
(3) Open or closed loop water system
(4) Quality of the steam level or hot water used for reheat
In this study, costs of inline reheat exchangers were evaluated usi
carbon steel, stainless steel Type 316, and Inconel 625 alloys. Tub
was estimated to be 2, 4, and 8 years, respectively for these various all
Tube Dimensions—
Based on survey information, a tube wall thickness of 0.1-inch w
selected for inline reheaters and 0.05-inch for indirect hot air reheat
The exit gas recirculation reheaters were designed conservatively with
0.1-inch thick tube walls. The thin tube for indirect hot air reheat
was selected because of less severe service compared to the inline r h
For all cases 1-inch OD tubes were specified.
Tube Life—
Based on survey results, the following tube life expectancy wac
r «"._/ was assumed
(for carbon steel): inline - 2 years, indirect - 10 years. The tube lif
for exit gas recirculation reheaters made of carbon steel was estimat
4 years. An average tube life of up to 4 years may be expected using
less steel in inline service. Because industry's use of Inconel has h
very limited, no tube life data were available from these sources- h
vendors that were contacted indicated that the average life of Inconel
could be expected to be approximately four times longer than the life
carbon steel tubes. Consequently, Inconel tubes were estimated to have
life of eight years in these analyses. It should be pointed out that the
of these tube life figures are estimates and that definitive operating
experience to confirm these numbers is not available.
256
-------
Tube Costs—
Based on contacts with exchanger vendors, the following costs for
delivered prices of tube bundles specified above were developed:
Tube Thickness for 0.1 0.05
1-in. OD tubes (inches)
Cost ($/ft2 of surface area):
Carbon Steel 20 11
Stainless Steel (316L) 39 21
Inconel 625 70 39
The exchanger vendors indicated that the reheat exchangers being looked at
in this study would essentially have a scale factor of 1.0 because of their
large size.
Fins--
All the reheaters in this study were assumed to consist of bare tubes
with no fins. Data obtained by the survey indicate that bare, unfinned
tubes are commonly used for inline reheat. An indirect hot air reheater
would probably be designed with finned tubes to reduce the physical size
of the exchanger. Exchanger vendors indicated that replacing the bare tubes
with finned tubes would probably not change the cost of the system apprecia-
bly. Only the physical size of the exchanger would be reduced.
Main and Auxiliary Fans
Fan costs were obtained using an in-house computer program. A mid-1978
Marshall and Stevens escalation factor of 540 was used. The FGD system for
the base case 500-MW plant has four scrubbing modules, each having a fan. In
the exit gas recirculation and indirect systems, four auxiliary fans were
added.
257
-------
Incremental Stack Cost
As
system
discussed in the previous appendix, the indirect hot air in'
required a larger stack diameter to keep the gas velocity at 60 f /
sec. Therefore, the more air injected, the greater the stack diamete
subsequently, the cost. A base price of $2,550,000* was used for a 300
high, 22.4-foot diameter stack. The cost for larger stacks was assu d
be directly proportional to the diameter.
be directly proportional to the diameter.
Soot Blowers
Soot blower costs were obtained from vendors and are about $1700 f
each blower. Based on survey results, four were specified for
scrubber
module for inline service. Since the exit gas recirculation method has
yet been demonstrated, the use of two soot blowers per module was ass
None was specified for the indirect systems.
DIRECT LABOR AND MATERIALS COSTS (INSTALLATION COSTS)
The direct labor and materials (DL+M) costs for reheat exchangers
(installation costs) were estimated based on information reported by
McGlamery et al.28 The information in this reference was used to de 1
28
an expression for installation costs:
DL4W = $89,000 + SA x $13.4/ft:
where DL-ttl is reheat exchanger installation costs (1978$) and SA is exch
surface area, ft2.
The resulting installation costs are typical of costs that would be
ep<
Perry31* and Ponder et al.37.
estimated using factors reported by Guthrie , Peters and Timmerhaus3S
^Installed cost
258
-------
INDIRECT COSTS
Indirect costs were estimated as 45 percent of the direct investment
(equipment cost, labor and materials). This factor was obtained in part
from the sources mentioned above. It includes engineering, construction
expenses, contractor fees, and a 20 percent contingency. It does not include
interest during construction or start-up costs.
OPERATING COSTS
Steam and Hot Water Costs
The steam costs used have been derived previously in Appendix C. As
developed, they vary depending on their energy level (or steam quality).
Electricity Costs
Electricity costs are based on estimated capital and operating expenses
for a new 500-MW power plant. The bases for estimating these respective
costs are presented below:
Capital Investment Basis
Assumed capital investment* - $800/kW for a 500-MW plant
(mid-1978 dollars)
Operating Expense Bases
Assumed fuel costs - $1.00/10S Btu
Plant heat rate - 9000 Btu/kwh (38 percent thermal efficiency)
Fuel consumption - 428,600 Ibs/hr
Coal heating value - 10,500 Btu/lb
Annual operating period - 7000 hr/yr (79.9 percent capacity factor)
Assumed operating and maintenance cost** - 7 mills/kwh
* Includes installed cost, engineering, contingency, interest during construc-
tion, start-up costs.
**Includes operating and maintenance cost for plant and all auxiliaries
(FGD system, solid waste disposal).
259
-------
Using the above, operating expense bases, the operating cost was calculated
from Equation E-l.
N = annual operating cost = fuel cost 4- O&M cost + depreciation (E-l)
9000 — x 7000 — x 500,000 kW x $1.00/l06Btu + $.007/kWh x
kWh yr '
7000 — x 500,000 kW + $800/kW x 500,000 kW x ±r = $72,000,000/yr
- * £.D earo
The annual revenue requirement was calculated in accordance with the
expression developed in Appendix C and was determined to be $110,000,0007
year. The annual power generated is:
500,000 kW x 7000 hr/yr = 3.5 x 109 kWh/year (E-2)
The annual revenue requirement divided by the annual power generated yields
an average unit price of $0.0314/kWh for electricity (1978$).
Maintenance and Replacement Cost for Reheat Exchangers
The maintenance cost for the reheat exchanger is expected to be very
dependent on tube life. This will be primarily associated with the replace-
ment (equipment plus installation) of corroded tubes. The following expres-
sion was assumed for estimating total reheat system maintenance costs
(annual) :
M + R = [-25(DL+M) + Exchanger Cost]
tube life
260
-------
Maintenance for Other Equipment Items
The annual maintenance cost for other equipment items such as fans and
direct combustion reheat systems was taken as 8 percent of the installed
equipment cost.
Depreciation
Depreciation was calculated using the straight line method over 25
years.
COST SUMMARY SHEETS
The capital and operating cost bases described above were used to
develop the cost of the various reheat configurations as well as sensitivity
studies considered. The cost of each study conducted is presented in Tables
E-l through E-38.
Note the information concerning the primary fan. The fan size listed
is the size of each of 4 fans required for the case shown. For example, in
Table E-l, four 3240 HP fans are required. The capital investments shown
to the right reflect the incremental investment required for the fan in the
reheat configuration compared to a forced draft fan configuration with no
reheat. The forced draft fan base case required four 2755 HP fans to over-
come a 34-in. HaO pressure drop.
261
-------
TABLE E-l. COST SUMMARY SHEET FOR INLINE REHEAT
(600 psia, dry saturated steam)
CONFIGURATION:
Required Heat Input (10'Btu/hr) - 66.8
Scrubbed Flue Gag:
Temperature (*F) - 131
Flow Sat* Ubs/hr) '5,140,000
Reheat Steam:
Temperature (°F) - 486
Pressure (psia) - 600
Flow Rate (Ibs/hr) '91,300
Stack Exit Temperature (*P) - 181
Recirculation Exit Gas:
Temperature (°F) -
Flow Rate (Iba/hr) -
Reheat Air:
Ambient Temperature OF) -
Heated Temperature OF) -
Flow Rate (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
No. Req'd.
Total
Capacity
8,100 (ft')a $_
Total - Incremental
Cost/Unit
Reheat Exchanger: ^
Exit Temp. (°F) - 181
Exchanger iP (in.HjO) - 6
Condensing Heat Transfer Coefficient (Btu/hr-ft2-°F)b -
Superheat Heat Transfer Coefficient (Btu/hr-ftJ-°F)c -
Primary Fan"*:
Size (HP) - 3240 4
AP (in.H20) - **U
Auxiliary Fan*:
AP (in.HiO) -__ ~ ~
Incremental
Stack Cost^:
Soot Blowers ; ±~
20
/ft'
Total Cost ($)
162,000
31.5
38,000
each
151,000
(HP)
each
1,700
e.ch
, u
Total Equipment Cost8 - 340,001J
Direct Labor and Materials Cost (for exchanger and soot blower installation) - 198, 000
Indirect Costs (45% of Total Equipment and Direct Labor & Material Costs) - 242,000
TOTAL CAPITAL INVESTMENT
780.000
OPERATING COSTS
Item
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
Quantity Required
91,300 (lbs/hr)
1,460
Cost
(kw)
(kw)
Coat/Unit
1«69 ($/10!lbs)
0.0314 _ ^
(S/kwh)
($/kwh)
Total Annual Cost(S)
1,080,000
321,000
••
118, UUU
31,000
TOTAL ANNUAL OPERATING COST 1^550^000
ANNUAL REVENUE REQUIRED
1,624,000
?Area shown is 25% greater Chan area calculated.
"Overall heat transfer coefficient for condensing portion of exchanger.
.Overall heat transfer coefficient for desuperheat portion of exchanger.
Primary fan's base size corresponds co a forced draft FGD process without reheat.
^Auxiliary fan required for indirect hot air and exit gas recirculation configurations.
Incremental stack cost experienced only with indirect hot air configuration.
^Total cost of equipment that is needed as a result of reheat. The fan and incremental
stack costs included in this total are installed costs.
262
-------
TABLE E-2. COST SUMMARY SHEET FOR INLINE REHEAT
(310 psia, dry saturated steam)
CONFIGURATION:
—g—0
Required Heat Input (10'Btu/hr) - 66.8
Scrubbed Flue Gas
Temperature C'F) - 131.
Flow Rate (lbs/hr) -5,140,000
Reheat Steam:
Temperature CF) - 420
Pressure (psia) - 310
Flow Rate (lbs/hr) - 82,900
Stack Exit Temperature (•?) - 181
Recirculacion Exit Gas:
Temperature (°F) -
Flow Race (lbs/hr) -
Reheat Air:
Ambient Temperature I'F) -
Heated Temperature CF) -
Flow Rate (lbs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Total
Capacity
Total - Incremental
Coat/Unit
t,S\
181
Reheat Exchanger:
Exit Temp. (*F) -
Exchanger IP Un.H;C> - 6
Condensing Heat Transfer Coefficient-(Btu/hr-ft:-'F)b
Superheat Heat Transfer Coefficient (Btu/hr-ft:-'F)c -
Primary Fand:
Sice (HP) - 3240 4
•IP (in.H.O) - 4fl
Auxiliary Fane:
'•P (ir..H 01 -. ~ ~ ~
Incremental
Stack Coscf:
Soot Blowers:
10,800^:,. . 20 /ft:
29.6
S38.OOP each
(HP)
16
1,700
each
_g ac h
216,000
151.000
27,000
Tot.il Equipment Cost*
Direct Labor and Materials Cost (for exchanger and soot blower Installation!
Indirect Costs (^57. of Total Equipment anu Direct Labor i Material Costs)
394.000
234.000
283.000
TOTAL CAPITAL INVESTMENT
911.000
OPERATING COSTS
Item
Steam/Hoc Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL A.WAL OPERATING COST
ANNUAL REVENUE REQUIRED
Quantity Required
82,900
1,460
_
Cost
(lbs.hr)
(kw)
(kw)
Cost/ Unit
1.73 (S.'lO'lbs)
0.0314(S/kwh)
- (S/kwh)
Total Annual Ci-'st (,S^
1,003,000
321,000
_
149 r 000
36,000
1,509.006
1,596,000
?Area shown is -5". greater than area calculated
Overall heat transfer coefficient for condensi
stack costs included in this total are Installed costs
263
-------
TABLE E-3. COST SUMMARY SHEET FOR INLINE REHEAT
(165 psia, dry saturated steam)
CONFIGURATION:
__rj—JJ
Required Heat Input (10'Btu/hr) - 66.8
Scrubbed Flue Gas:
Temperature CF) - 131
Flow Rate (Ibs/hr) -5,140,000
Reheat Steam:
Temperature CF) - 366
Pressure (psia) - 165
Elow Rate (Ibs/hr) -78,000
Stack Exit Temperature CF) - 181
Recirculation Exit Gas:
Temperature CF) -
Flow Rate (Ibs/hr) -
Reheat Air:
Ambient Temperature CF) -
Heated Temperature CF) -
Flow Rate (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
No.
Reheat Exchanger:
Exit Temp. CF) -
Req'd.
4
Total
Capacity
Total - Incremental
Cost/Unit
I4,500(ft1)a $
20
/ft'
Exchanger 4P (in.HjO) - 6_
Condensing Heat Transfer Coefficient (Btu/hr-ft!-'F) -
Superheat Heat Transfer Coefficient (Btu/hr-ft2-°F)c -
Primary Fand-.
UT.N _ 3240 4
27.7
38,000
each
Total Cost ($)
290,000
151,000
a? (in.HjO) - 40
Auxiliary Fan* :
AP (in.H-,0) - ~
Incremental
Stack Cost':
Soot Blowers:
~ (HP) S ~ each
_
16 S 1,700 each 2/.UUU
Total Equipment Cost*
Direct Labor and Materials Cost (for exchanger and soot blower installation) - 284,000
Indirect Costs (457. of Total Equipment and Direct Labor 6. Material Costs) - 338,000
TOTAL CAPITAL INVESTMENT
- 1.090.000
OPERATING COSTS
Item Quantity Required
Steam/Hot Water 78,000 (lbs/hr)
Electricity
Primary Fan 1460 (ku^
Auxiliary Fan (kw)
Maintenance and Replacement Cost
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Cost/Unit
1-57 (S/10!lbs)
0.0314 (S/kwh)
($/kwh)
Total Annual Cost($)
857,000
321,000
-
193,000
44,000
1.41b.OOU
1,519,000
?Area shown is 257. greater than area calculated.
Overall heat transfer coefficient for condensing portion of exchanger.
^Overall heat transfe- coefficient for desuperheat portion of exchanger.
Primary fan's base size corresponds to a forced draft FGD process without reheat.
^Auxiliary fan required for indirect hot air and exit gas recirculation configurations.
Incremental stack cost experienced only with indirect hot air configuration.
^Total cost of equipment chat is needed as a result of reheat. The fan and incremental
scack costs included in this total are installed costs.
264
-------
TABLE E-4. COST SUMMARY SHEET FOR INLINE REHEAT
(83 psia, dry saturated steam)
CONFIGURATION:
Required Heat Input (10'Btu/hr) "66.8
Scrubbed Flue Gas:
Temperature (•?) - 131
Flow Race Ubs/hr) - 5,140,000
Reheat Steam:
Temperature (*F) - 315
Pre
Flo
ressure (peia) - $3
low Race (Ibs/hr) - 74,300
Stack Exit Temperature (•?)
Recirculacion Exic Gas:
Temperacure ("F) -
Flow Race (Ibs/hr) -
Reheat Air:
Ambient Temperature (°F) •
Heated Temperature CF) -
Flow Rate (Lbs/hr) -
181
EQUIPMENT SPECIFICATIONS AMD CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exic Temp. C'F) - 18_L.
Exchanger IP (in.H;0> -
Condensing Heac Transfer
Superheat Heat Transfer
Primary Fand:
Siie (HP) - 3240
-IP (in.H.O) - 40
Auxiliary Fan*:
VP Un.H 0) - ~
Incremental
Stack Costf
Soot Blowers:
Total
No. Req'd. Capacity
4 20,900(ft
Coefficient "(Btu/hr-ft;!-'F)b
Coefficient (Btu/hr-f f' -• f)c -
4
Total - Incremental
Cose/ Unit
•-•>* $
. 25.6
$38.
- - (HP) S
16
Totjl Equipment Cost*
Direct Labor and Material* Cost (for exchanger and soot
Indirect Costs (i5?. of Total Equipment and Direct Labor
TOTAL CAPITAL INVESTMENT
20 /ft:
000 each
— each
$1,700 each
blower installation)
SL Material Costs)
Total Cost (SI
418,000
151,000
27,000
- 596.000
^70 000
4^000
- i,4ni,nnn
OPERATING COSTS
Item
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciacion
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Quantity Required
74,400 abs hr)
1,460 ,kw)
- (kw>
Cost
Cost /Unit
1.37 (S/10'lbs)
0.0314(S/kwh)
(5/kwh)
Total Annual Cost (Si
713.000
321,000
-
267,000
56 r 000
1.357.000
i,49n,nnn
_ _.....:. . .
?Area shown is 25*. greater than area calculated.
Overall heat transfer coefficient for condensing portion of exchanger.
^Overall heat transfer coefficient for desuperheac portion of exchanger.
Primary fan's base size corresponds to a forced draft FGD process without reheat.
".Auxiliary fan required for indirect hot air and exit sas recirculation configurations.
Incremental stack cost experienced only with indirect hoc air confiruracion.
sTotal cost of equipment chat U needed as a result of reheat. The fan and incremental
stack coses included in this total are installed costs.
265
-------
TABLE E-5. COST SUMMARY SHEET FOR INLINE REHEAT
(39 psia, dry saturated steam)
CONFIGURATION:
Required Heat Input (10'Bcu/hr) - 66.8
Scrubbed Flu* G*s:
Temperature CF) - 131
Flow Rate (lb«/hr) -5,140,00
Reheat Steam:
Temperature CF) - 266
Pressure Cpsla) - 39
b./hr) - 71,500
Flow Race (Ibi
Item
Stack Exit Temperature (-F)
Recirculacion Exit Gas
Temperature ("F) -
Flow Rate (Ibs/hr) -
Reheat Air
Ambient Temperature CF)
Heated Temperature (•f) .
Flow Rate (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
No. Reg'd
4
Total
Capacity
33,800^).
Total - Incremental
Cost/Unit
Reheat Exchanger:
Exit Temp. CF) - 181
Exchanger iP (in.H.O) - 6
Condensing Heat Transfer Coefficienc"(Btu/hr-ft:--F) -
Superheat Heat Transfer Coefficient (Btu/hr-ft:-'F)c -
Primary Fand:
Size (IIP) - 3240 4
-P (in.H.O) - 4fl
Auxiliary Fan4:
^P Un.H.Ol - ~ ~ (HP)
Incremental
Stack Costf:
Soot Blowers: -*-O
20
23.0
s 38.000 „..
1,700
Total Co
676,000
-15UJQO
3Hffl
Toc.'l Equipment Cost6
Direct Labor and Materials Cose (for exchanger and soot hlower installation)
Indirect Costs (-57. of Total Equipment And Direct Labor & Material Costs)
TOTAL CAPITAL INVESTMENT
OPERATING COSTS
Item
Steam/Hoc Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement Cost
Depreciation
TOTAL ANNUAL OPERATING COST
Quantity Required
71.500 Ubs hr)
Cost/Untr
1.10 (S 10'lbs)
T''tal *nnq.i1_r.^ s : i S ^
ssiToob
1,460
_(kw)
(kw)
0.0314(3/,vh)
($^-vh)
ANNUAL REVENUE REQUIRED
J*Area shown is 25% sreater than area calculated.
Overall heat transfer coefficient for condensing portion of exchanger.
^Overall heat transfer coefficient for desuperheat oortion ot exchaneer.
Primary fan's base size corresoonds to a forced draft FGO process without reheat.
^Auxiliary fan required for indirect hot air and exit jas recirculacion configurations
Incremental stack cost experienced only with indirect hot air confijuration."
S7otal :osc of equipment that is needed as a result of reheat. The fan and incremental
stack costs included in this total are installed costs
266
-------
TABLE E-6. COST SUMMARY SHEET FOR INLINE REHEAT
(16 psia, dry saturated steam)
CONFIGURATION:
Required Heat Input (10'Bcu/hr) -66.8
Scrubbed Flue Cae ;
Temperature CF) - 131
Flow Rate (Ibs/hr) - 5,140,000
Reheat Steam
Temperature (*F> -
Pressure (psia) -
Flow Race (Ibs/hr) - 09,100
216
Stack Exit Temperature (*F)
Recirculation Exit Gas:
Temperature ('F) -
Flow Rate (Ibs/hr) -
Reheat Air
Ambient Temperature CF) -
Heated Temperature ("F) -
Flow Rate (Ibs/hr) -
•181
EQUIPMENT SPECIFICATIONS AMD CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF) -
No. Req'd.
Total
Capacity
Total - Incremental
Cost/Unit
73.3QO(t-e-)a $ 20 /fe:
Exchanger AP (in.H;0> -
Condensing Heat Transfer Coefficienc "(Btu/hr-ft:-'F)b -
Superheat Heat Transfer Coefficient (Btu/hr-ft:-*F)C -
Primary Fand:
Size (HP) - 3240 4
19.5
$38.000 each
Total-Cost tS)
1.466.000
151.000
iP (in.H.O) - 40
Auxiliary Fan" :
\P tin.H 0) -~ ~ — (HPJ^ S each
Incremental
Stack Costf:
Soot Blowers: 16 Sl,700 each
27.000
TOCJ'. Equipment Cost* - 1. 64*t . QQQ
Direct Labor and Materials Cost (for exchanger and sooc blower installation! - 1 Q72. 000
Indirect Costs (J51; of Total Equipment and Direct Labor 4 Material Costs) - 1 222 _ QQD
TOTAL CAPITAL INVESTMENT - '
OPERATING COSTS
Item
Steam/Hoc Water
Electricity
Primary Fan
Auxiliary Fan
.Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Quant itv Required
69,000
1,460
Cose
(Ibs hr)
(kw)
(kw)
Cosc/Unic
0.78 (S.'lO'lbs)
0.0314 (5,kwh)
($/'<-.wh)
Tot.U innual C.-'sfiSl
377,000
321,000
—
8Q8,non
T»3. 000
i.TSA^nn
2,128,000
wAr*a ^hown is ^5", greater than arta calculated.
.Ovtrall h«ac cransctr coef£tci«nc £or oondensinit portion oc «
tatH ^O*V B»yWC^«»V«u Wll4» »<*k.n h4i—»fc«»- .iw*. »-fc
cost of equipment chat ts needed as a result of reheat.
stack costs included tn thi« total are installed coses.
267
-------
TABLE E-7. COST SUMMARY SHEET FOR INLINE REHEAT
(165 psia, hot water)
CONFIGURATION:
Required Heat Input (10'Bcu/hr) -66.8
Scrubbed Flue Gas :
Temperature CF) - 131
5,140,000
Flow Race (lb»/hr)
Reheat Steam:
Temperature CF) -
Pressure (psla) -
Flow Race (Ibs/hr)
366
165
- 534,000
Stack Exit Temperature (°F) • 181
Recirculation Exit Gas
Temperature CF) -
Flow Rate (Ibs/hr) -
Reheat Air
Ambient Temperature (*F) -
Heated Temperature CD -
Flow Race Ubs.'hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
181
No . Reg'd.
4
Total
Capacity
Total - Incremental
Cose /Unit
23,000(ft=)« $
Reheat Exchanger:
Exit Temp. CF) -
Exchanger 4P (in.H;0) - 6
Condensing Heat Transfer Coefficient '(Btu/hr-ft:-°F) -
Superheat Heat Transfer Coefficient (.Bcu/ hr-f c; -' F)c -
Primary Fand;
Size (HP) - 3240 4
AP (in.H;0) - 40
Auxiliary Fan4:
'P Un.H 01 - — - — (HP)
Incremental
Stack Coat* - ,
Sooc Blowers:
20
24.8
$38.000 each
s
each
Tocal Case (?)
460,000
151.QQQ
27.uOO
Totjl Equipment Cost**
Direct Labor and Materials Cost (for exchanger and s^oc blower installation^
Indirect Costs (45% of Total Equipment and Direct Labor & Material Costsl
39S.OOO
TOTAL CAPITAL INVESTMENT
OPERATING COSTS
Item
Quantity Required
534.000 at,.'
Cost/Unit
Total AnnuaL
Steam/Hot Water
Electricity
Primary Fan 1,460
Auxiliary Fan —
Maintenance and Replacement Cose
Depreciation
0.24
-------
TABLE E-8. COST SUMMARY SHEETS FOR INLINE REHEAT
SENSITIVITY STUDY (Case A, 316L Stainless
Steel Tubes)
CONFIGURATION:
Required Heat Input (lO«Btu/hr) - 66.8
Scrubbed Flue Gas:
Temperature CF) - 131
Flow Rate 5i,
^eat .
f ^1
000
000
nno
nnn
000
uuO
",Auxi.liarv fan required for indirect hot air and exit 2a» rectrculation configurations.
'Incremental stack cose experienced only with indirect hot air confizuration
*Total cost of equipment that is needed as a result of reheat. The fan and incremental
stack costs included in this cotal are Installed costs.
269
-------
TABLE E-9.
COST SUMMARY SHEET FOR TURBINE REHEAT
SENSITIVITY STUDY (Case B, Inconel 625
Exchanger Tubes)
CONFIGURATION:
Required Heat Input UO'Beu/hr) - 66.8
Scrubbed Flue Gas:
Temperature CF) - 131
Flow Race (lb«/hr) -5,140,000
Reheac Steam:
Temperature ("F) - 366
Pressure (psia) - 165
Flow Rate Ubs/hr) "78,000
Stack Exit Temperature ('*) - 181
RecircuUtion Exit Gas:
Temperature (°F) -
Flow Rate (Ibs/hr) -
Reheat Air
Ambient Temperature CF) -
Heated Temperature (•F) -
Flow Rate (lbs/hr) -
EQUIPMENT SPECIFICATIONS AMD CAPITAL INVESTMENT
Item
No . 8eq ' d.
Reheat Exchanger:
Exit Temp. CF)
. 181
Total
Capacity
14.500(rV)
Total - Incremental
Cost/Unit
70
.'Et-
Exchanger IP (in.H;0) - p
Condensing Heat Transfer Coefficient ~t,8tu/hr-ft:-
T)
27.7
Superheat Heat Transfer Coefficient: (Btu/hr-f t: -'F)e -
TOTAL CAPITAL INVESTMENT
Total Cost (S)
1,015,000
Primary Fand:
si« (HP) - 3240 4
iP (in.K;0) -
Auxiliary Fan*:
•P Ur..K oi -
Incremental
Stack Cosc^:
Soot Blowers :
Tot.-! Equipment
Direct Labor and
Indirect Costs (
40_
16
Materials Cost (for exchaneer and
45% of Total Equipment and Direct
S
(HP) S
S
38
1,
,000 .ach
each
700 each
soot blower installation!
Labor i Material Costs)
151
.
27 .
- 1.193
284
665
,000
000
,000
,000
,000
2.142.000
OPERATING COSTS
Item
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
Quantity Required
78.000
1460
_
Co»t
(Ibs 'hr)
(kw)
(kw)
Co s t / Un i t
1.57 (s.io'ibs)
0.0314($/kwh)
(S/'-wh)
Total Annual Cc*r. { $ ^
857,000
321,000
-
148.000
86.000
TOTAL ANNUAL OPERATING COST 1 41 9 ODD
ANNUAL REVENUE REQUIRED
1.615,000
^Area shewn is 25% greater than area calculated.
^Overall heat transrer coefficient for condensing portion of exchanger.
.Overall heat transfer coefficient for desuperheat portion of exchanger.
^Primary Jan's base size corresponds to a forced draft FGD process without reheat.
'.Auxiliary ran required for indirect hot air and exit zas recirculation confijurations
'Incremental stack cost experienced only with indirect hot air confizuration
^Total cost of equipment that is needed as i result of reheat. The fan and incremental
stack costs included in this total are '.nstalled costs
270
-------
TABLE E-10. COST SUMMARY SHEET FOR INLINE REHEAT
SENSITIVITY STUDY (Case C)
CONFIGURATION:
Required Heat Input UO'Btu/hr) - 66 . 8
Scrubbed Flue Gas:
Temperature CF) - 131
Flow Rate (Ibs/hr) -5,140,000
Reheat Steam:
Temperature (°F) - 366
Pressure (psia) - 165
Flow Rate (lbi/hr) -73 QOO
Stack Exit Temperature (*F) - 181
Rectrculation Exit Gas
Temperature (°F) -
Flow Rate (Ibs/hr) -
Reheat Air
Ambient Temperature ("F) -
Heated Temperature CF) -
Flow Race (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Total
Item No. Req'd. Capacity
Reheat Exchanger 4 17r600(fc;)
Exit Temp. CF) -1R1
Exchanger ap Un.K;0> - 3
Condensing Hea: Transfer Coefficient "
-------
TABLE E-ll. COST SUMMARY SHEET FOR INLINE REHEAT
SENSITIVITY STUDY (Case D)
CONFIGURATION:
Required Heat Input (10'Btu/hr) -
Scrubbed Flue Gas:
Temperature CF) - 131
Flow Race (Ib./hr) -5,140,000
Reheat Steam:
Temperature (°F) - 745
Pressure (paia) - 165
Flow Rate Ubs/hr) - 63,200
66.8
Stack Exit Temperature (•?)
Recirculation Exit Gas:
Temperature (JF) -
Flow Rate (Ibs/hr) -
Reheat Air:
Ambient Temperature (T) -
Heated Temperature ("F) -
Flow Rate (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Total
Item No. Req'd. Capacity
Reheat Exehanzer: 4 13,600(ft:)
Exit Temp. CF) - _1SLL_
Exchanger IP Un.H-0) - 6
Condensing Heat Transfer Coef f icient "(Bcu/hr-f t; -«F) -
Superheat Heat Transfer Coefficient (Bcu/hr-f t : - 'F)c -
Primary Fand:
Size (HP) - 3240 4
iP (in.H.O) - 40
Auxiliary Fan*
'P ( Ln.H 01 - (HP)
Incremental
Stack Cosrf
Soot Blowers : 16
Total - Incremental
- Cost/Unit Tocal CQSE (<;.
a s ^O /fr'~ ?72 OOC
58. S
19.0
s 38. 000 .,,h ^aSTjioc
$ each
51700 each IIIITJ^g^
Toc.il Equipment Cost*
Direct Labor and Materials Cost (for exchanger and soot blower installation!
Indirect Costs (i5* of Total Equipment and Direct Labor i Material Costs)
AL
AL
Item
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement Cost
Depreciation
TOTAL AAWAL OPERATING COST
OPERATIMC COSTS
Quantity Required
63,200 Ubs hr>
Cosj^Unit
1.93
TrtJl Ann'.i.il
1,460
_kkw)
(kw)
0.0314
(S'lO'lbs)
(5/kwh)
857,000
321,000
ilJDOO
AL REV
UE REQUIRED
1^102^000
!*Ar*a shown is 25"» *reacer than area calculaced.
Overall heat transfer coec'ficienc for condensing porcion oc exchaneer.
^Overall heat transfer coe£fictenc cor desuoerheat oorcLon of excnaneer.
Pri'nar/ fan's base size corresponds co a forced drafc FGD process without reheat.
^Auxiliary fan required cor indirect: hoc air and exit eas recirculacion cent"igurations
"Incremental stack cost experienced onLv with indirect hot air configuration.
^TotaL cost of equipment chat is needed as a result of reheac. The fan and incremental
stack coses included in chis cotaL are installed coses.
272
-------
TABLE E-12. COST SUMMARY SHEET FOR INLINE REHEAT
SENSITIVITY STUDY (Case E)
CONFIGURATION:
Required Htac Input (10'Bcu/hr)
Scrubbed Flu* Ga»
Temperature CF) - 126
Flow Rat. (Ibs/hr) -5,120,000
Rcheac Steam:
Temperature CF) - 366
Pressure (p»ia) - 165
Flow Rate (Ib./hr) -48,100
66.6
Stack Exit Temperature ('") - \"J (\
Racirculation Exit Gas:
Temperature (*F) -
Flow Rate (Ibs/hr) -
Reheac Air
Ambient Temperature (*F) -
Heated Temperature CF) -
Flow Rate (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF) - 1 S6
Exchanger -
Coefficient (Btu/hr-f t: -'F)c -
4
(HP)
16
Tot.tl Equipment Cost**
Total - Incremental
Cost/ Unit Total Cost
a $ 20 m=
24.7
—
.<18,000>..ch
$ each
$ 1.7 00 each
.
Direct Labor and Materials Coit (for exchanger and soot blower installation)
Indirect Costs (i5* of Total Equipment and Direct Labor 4
TOTAL CAPITAL INVESTMENT
Material Costs)
-
186,
<73,
'it ^
140,
214.
159,
513,
(S)
000
000
uuu
oOo
ooo
noo
000
OPERATING COSTS
teem
Steam/Hoc Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and
Depreciation
Quanc it v Required Cost/ Unic
Replacement
48,100
<536>
Cost
(lbs.hr) 1.57 (S 10'lbs)
(kw) 0.0314(s/icuh)
(kw) (S/k«h)
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE
uArea shown i»
Overall h»»ae t
REQUIRED
-5*'. greater
ranctcr co*f
than area calcu
ficienc for con
lated.
densinz oortion of exchanger.
Total Annual C^stlS'i
528,000
<118,000>
114.000
21,000
545,000
594.000
'.Overall heat transfer coefficient for desuoerheat portion ot" exchaneer.
Primary fan's base size corresponds to a forced draft FCO process without reheat.
^Auxiliary fan required for indirect hot air and exit nas recirculation configurations
Incremental stack cost experienced only with indirect hot ilr conftzuratlon
*Total cost of equipment that is needed 13 a result of reheat. The fan and incremental
stack costs included in this total ire Installed costs
273
-------
TABLE E-13. COST SUMMARY SHEET FOR INLINE REHEAT (Case F)
CONFIGURATION:
Required H««c Inpuc UO'Btu/hr) - 95
Scrubbed Flue Gas:
Temperacure OF) - 125.5
Flow Rate (Ib./hr) '5,120,000
Reheac Steam
Temperature (°F) - 366
Pressure (psia) - 165
Flow Race (Iba/hr) - 78,000
Stack Exit Temperacure C") '196.9
Recirculation Exic Gas:
Temperacure (JF) -
Flow Race Ubs/hr) -
Reheat Air
Ambienc Temperacure (°F) -
Heaced Temperacure (• F) -
Flow Race Clbs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
No. Req'd.
Tocal
Capacity
Reheac Exchanger: ^ •—_
Exit Temp. (8F) - 1 7 S t S
Exchanger :iP Un.H.O) - 6
Condensing Heac Transfer Coefcicienc \6cu/hr-ft:-*F)
Superheat Heat Transfer Coefficient (Bcu/hr-fc;-JF)C -
Primary Fand:
Si-e'(HP) -2800 4
-P (tn.H.O) -
Auxiliary Fan6:
•P Un.K 0> - _
local - Incremental
Cosc/Unic _
/ft:
20
26.2
2800
each
Tocal Cose (S)
296,000
11,000
(HP)
each
Incremental
Stack Costc
Soo t Blowers :
16
Tot. 'I Equipment Cost^
Direct Labor and Materials Cost (for exchanger and s.ioc
Indirect Coses (^5" of Tocal Equipmenc and Direcc Labor
TOTAL CAPITAL INVESTMENT
S 1700 each
_
Mow«?r installation1!
^ Material Costs)
-
'2.1 ,UUU
334,000
288 r 000
280rOOO
902.000
OPERATING COSTS
Item
Steam/Hot Water
Eleccrtcicy
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Quantity Required
78.000
131
Cost
Ubs hr)
(Wu)
(kw)
Cost; Unit Tctal
1.57 (S/10'lbs)
0.0314 cs/kwh,
(S/V'-wh)
Annual C^itiil
857,000
29,000
131; nnn
36 ^>00
1,107,000
1,193,000
?Area shown is 25". greater than area calculated.
,Overall heat cransfer coefficient for condensing porf.cn jt exchanger.
^Overall heac cransfer coefficient for desuoerheac portion Jf exchanger.
aPrimary fan's base size corresponds Co a forced dracc FGO process without reheac.
^-Auxiliary fan required for indirect hot air and exit gas recirculatton configurations.
'Incremental scack cost experienced only with indirecc hoc air configuration."
?Total cost of equipment that is needed as a result of reheat. The fan and incremental
stack costs included in this total are installed costs
274
-------
TABLE E-14. COST SUMMARY SHEET FOR INLINE REHEAT (Case G)
CONFIGURATION:
Required Heat Input (10'Btu/hr) - 66.8
Scrubbed Flue Get•
Temperature (*F) - 131
Flow Race Ubs/hr) -5,140,000
Reheat Steam
Temperature (°F) - 366
Pressure (psia) - 165
Flow Rate (lb»/hr) -78,000
Stack Exit Temperature (•*)
Recirculation Exit Gas.
Temperature (JF) -
Flow Rate (Ibs/hr) -
Reheat Air
Ambient Temperature (T)
Heated Temperature (' F) -
Flow Race Ubs/hr) -
181
EQUIPMENT SPECIFICATIONS UNO CAPITAL INVESTMENT
Total
Item No. Req'd. Capacity
Reheat Exchanger: 4 14,500(tW
Exit Temp (-F) -181
Exchanger iP (in.K.O) - fi
Condensing Heat Transfer Coefficient ~iBtu/hr- ft- -• F)b -
Superheat Heat Transfer Coefficient (Btu/hr-f t: -'F)c -
Primary Fand
Size' (HP) - 3240 4
iP (in.H.O) - 40
Auxiliary Fan* •
^P iln.H 0) - ' CHP)
Incremental
Stack Cost'
Soot Blowers: 16
Total - Incremental
Cost/Unit
3 s 20 /ft;
27.7
$38,000 each
$ each
$ 1,700 each
Total Cose
290,
151,
97
(S,
000
000
nnn
• V — — —
Tot.il Equipment Cost^
Direct Labor and Materials Cost (for exchanger and soot blower installation)
Indirect Costs (^57. of Total Equipment and Direct Labor & Material Costs)
TOTAL CAPITAL INVESTMENT
- 468,
284,
338,
- 1,090,
nno
000
000
ono
OPERATING COSTS
teem
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement:
Depreciation
Cjuancicv Required
78,000
1460
Cost
(Ibs-hr)
(kw>
(lew)
Cost /Unit
1. 57 (S'lO'lba)
0.03l4($/kwh)
(S/kwh)
Total Annual Cost I SI
857,000
321,000
_
373.000
44 nnn
TOTAL ANNUAL OPERATING COST 1} SQ^f)^
ANNUAL REVENUE REQUIRED
1,699,000
uArea shewn
5% greater than area calculated.
"Overall heat transfer coefficient for condensing portion of exchanger.
^Overall heat transfer coefficient for desuoerheat portion of exchaneer.
Priiury fan's base size corresponds to a forced draft FGD process without reheat.
"-Auxiliary fan required for indirect hot air and exit gas recirculation configurations.
Incremental stack cost experienced only with Indirect hot air configuration.
^Total cost of equipment that is needed as a result of reheat. The fan and incremental
stack costs included in this total are installed costs
275
-------
TABLE E-15. COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(600 psia, dry saturated steam, air approach
temperature = 80°F, AT = sn°T7\
flue gas J
CONFIGURATION:
-ff
Q
Required Heat Input (lO'Btu/hr) - 102
Scrubbed Flu* G«»:
Temperature (•?) - 130
Flow Rate (Ibs/hr) - 5,140,000
Reheat Steam:
Temperature (*F) - 486
Pressure (psia) - 600
Flow Race (Ibs/hr) - 138,000
Stack Exit Temperature (•?) -
Recirculation Exit Gas:
Temperature ('F) -
Flow Rate (Ibs/hr) -
Reheat Air
Ambient Temperature (-F) -
Heated Temperature (
Flow Rate (Ib./hr) - i , an nn
1,180,000
EQUIPMENT SPECIFICATIONS AMP CAPITAL INVESTMENT
Total Co.,.
Reheat
Item
Exchanger:
No. Req'd.
4
Total
Capacity
21,500(ft«}«
Total - Incremental
Cost/Unit
5_ 11 ,fr>
Exchanger IP (in.HiO) -
Condensing Heat Transfer Coefficient (Btu/hr-ft'-'F)b - 26.2
Superheat Heat Transfer Coefficient (Btu/hr-ftJ-'F)c -
Primary Fand:
Size (HP) - 2755 4
ap (in.HiO) -
Auxiliary Fan*:
iP (in.HiO) -
Incremental
Stack Cost^:
Soot Blowers:
34
9.3 4 114 (HP) s22r8QO ....„ _J^^rL
5 ~ ea,h ^S^mKL
Direct Labor and Materials Cost (for exchanger and soot blower installation)
Indirect Costs (457. of Total Equipment and Direct Labor 4 Material Costs)
Item
Sceara/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement Cost
Depreciation
OPERATING COSTS
Quantity Required
138. QQO (Ibs/hr)
Cost /Unit
(kw)
.($/kwh)
.(S/fcwh)
Total Annual p,,..
fArea shown is 107. greater than area calculated.
Overall heat tr,
07. greater than area calculated.
ansfer coefficient for condensing portion of exchanger.
.
jOverall heat transfer coefficient for desuperheat portion of exchanger.
Primary fan's base size corresponds to a forced draft FGD process without reheat
^Auxiliary fan required for indirect hot air and exit gas recirculacion configurations
Incremental stack cost experienced only with indirect hot air configuration.
^Total cose of equipment chat is needed as a result of reheat. The tan and incremental
stack costs Included in this total are installed costs.
276
-------
TABLE E-16.
COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(310 psia, dry saturated steam; air approach
temperature = 80°F, AT.,.._ ___ - 50°F)
CONFIGURATION
117
Required Heat Input (10'Btu/hr)
Scrubbed Flue Gal;
Temperature (-F) - 130
Flow Rate (Ibe/hr) - 5,140,000
Reheat Steam:
Temperature ('F> - 420
Pressure (psia) - 310
Flow Race Ubs/hr) - 143,000
Stack Exit Temperature CF) - 180
Recirculation Exit Gas:
Temperature CF) -
Flow Rate (Ibs/hr) -
Reheat Air
Ambient Temperature CF) - 60
Heated Temperature CF) - 34Q
1,690,000
Flow Rate (Ibe/hr) -
EQUIPMENT SPECIFICATIONS. AND CAPITAL INVESTMENT
Total
Item No. Req'd. Capacity
Reheat Exchanger: * 27,500(ft'>
Exit Temp. CF) - 340
Exchanger a? (in.HiO) - "
Condensing Heat Transfer Coefficient (Btu/hr-ft'-'F)b -
Superheat Heat Transfer Coefficient (Btu/hr-ft'-'F)0 -
Primary Fand:
si« (HP) -2755 4
4P (in.HiO) - 34
Auxiliary Fan*:
AP (in.H.ox - -9.3 4 163 (HP)
Incremental
Stack CostV _
Soot Blovers.-
Total - Incremental
Cose/Unit Total Cose (S)
• $ 11 m' 302,000
26.23
S - each
$27,000 each
$ each
108 , 000
393.000
_
Total Equipment Cost*
.
Direct Labor and Material* Cost (for exchanger and soot blower installation)
Indirect Costs (45X of Total Equipment and Direct Labor 4
TOTAL CAPITAL INVESTMENT
Material Costs)
- J
803,000
458,000
S67,nnr>
-.828., 000
OPERATING COSTS
Item
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Quantity Required
143,000 (Ibs/hr)
(kw)
485 ckwj
Cost
Cost /Unit
1.73 (,/io'ib.)
~ ($/kvh)
0.0314($/kwh)
Total Annual Cost(S)
1,732,000
-
107,000
50.000
71 000
i 96? fiftn
2.14 x 10b
u&rea shown is 107. grtac«r Chan area calculated.
^Overall h«ac transfer co«£fici«nc for condensing portion of «xchanger.
jOvtrall heic transfer coefficient for desuptrheac portion of exchan^tr.
Primary fan's baa* >izt corresponds to a forced draft ?GD process without reheat.
^Auxiliary fan required for indirect hoc air and «xic gas r«circulacion configurations.
'Incremancal stack cost experienced only with indirect hot air configuration.
^Total cost of equipment that is needed as a result of reheat. The ran and incremental
scack costs included in this total are installed coses.
277
-------
TABLE E-17. COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(165 psia, dry saturated steam; air approach
temperature = 40 F; AT ,, - 50°Fl
flue gas ;
CONFIGURATION:
Required Heat Input (10'Bcu/hr) - 122
Scrubbed flue Cat:
Temperature OF) - 130
Flow Rate (Ibs/hr) -5,140,000
Reheat Steam:
Temperature (*F) - 366
Pressure (psia) - 165
Flow Race (Ibe/hr) - 140,000
Stack Exit Temperature (-F) -
Recirculation Exit Gas :
Temperature (°F) -
Flow Race (Ibs/hr) -
Reheat Air :
Ambient Temperature CF) .
Heated Temperature CF)
Flow Rate
-------
TABLE E-18. COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(165 psia, dry saturated steam; air approach
temperature = 80 F; AT
flue gas
50UF)
CONFIGURATION:
Required Heat Input (10'Beu/hr) - 142
Scrubbtd Flu* Ga«:
Temperature CF) - 130
Flow Rate (lbe/hr> -5,140,000
Reheat Steam:
Temperature OF) - 366
Pr««»ur« (psia) - 165
Flow Rate (Ib./hr) -164,000
Stack Exit Temperature (•») - 180
Recirculation Exit GAS:
Temperature (aF) -
Flo« Race (Ibs/hr) -
Reheat Air.
Ambient Temperature (-F) - gQ
Heated Temperature CF) - 286
Flow Race (Ibe/hr) - 2,520,000
EQUIPMENT SPECmCATIOKS_AMD CAPITAL INVESTMENT
It«a
So. Req'd.
4
Total
Capacity
Reheat Exchanger:
Exit Temp. CD -
Exchanger iP (in.HiO) - 6
Condenstng Heat Transfer Coefficient (Btu/hr-ft!-'F)b
Superheat Heat Transfer Coefficient (Btu/hr-ft'-'F)c -
Primary Fand;
size (HP) - 2755 4_
Total - Incremental
Cost/Unit
j . . 11 /ft'
Total Cost ($)
388.000
27.1
each
4P Cin.HjO) - 34
Auxiliary Fan«t
4P (in.H.O) - 9_. 3
Incremental
Stack Coscf.
Soot Blovera :
4 243 (HP) $32.900 e.ch
$ - each
Total Equipment Cost*
Direct Labor and Materiala Coat (for exchanger and sooc blower installation)
Indirect Coats O57. of Total Equipment and Direct Labor & Material Costs)
TOTAL CAPITAL INVESTMENT
132rOQO
573,000
—
- i.rm.nnn
- 563! 000
745, OQO
- 2.401.000
OPERATING. COSTS
Item
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Quantity Required
164,000ub./hr>
(kw)
7 2 S (kw)
Coat
Cose/Unit local Annual Cosc(S)
1.57 (5/io'ibs) 1,802,000
~ ($/kvh)
n,cm4(s/kvh) •) e^q nnn
63*000
96,000
2 , 120 r 000
2.35 X 10C
Area shown ts 107. greater chart area calculaced.
Overall httac cranafer coefficient for condensing portion of exchanger.
^Overall heac transfer coefficient for desuperheat portion of exchanger.
Primary fan's base size corresponds to a forced draft FCD process without reheat.
*Auxiliary fan required for indirect hot air and exit gas recirculation configurations.
"Incremental stack cost experienced only with indirect hoc air configuration.
^Tocal cost of equipment chac is needed as a result of reheat. The fan and incremental
scack cost* included in chis total are installed coses.
279
-------
TABLE E-19,
COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(165 psia, dry saturated steam; air approach
temperature = 120 F; AT
flue gas
50°F)
CONFIGURATION;
Required Heat Input (10'Btu/hr) - 188
Scrubbed Flue Cas:
Temperature CF) - 130
Flow Rate (Ibs/hr) - 5,140,000
Reheat Steam:
Temperature CF) - 366
Pressure (psia) - 165
Flow Rate (lb«/hr) -216,000
Stack Exit Temperature (T) -]_gQ
Recirculacion Exit Gas:
Temperature CF) -
Flow Rate (Ibs/hr) -
Reheat Air:
Ambient Temperature CF) - cr\
Heated Temperature CF) - 246
Flow Rat. (Ibs/hr) - 4,050,000
EQUIPMENT SPECIFICATIONS ASP CAPITAL INVESTMENT
Item
Total
No. Req'd. Capacity
4 35,500(tEt).
Reheat Exchanger.-
Exit Temp. CF) -246
Exchanger 4P (in.HiO) -
Condensing Heat Transfer Coefficient (Btu/hr-f t'-T)b
Superheat Heat Transfer Coefficient (Btu/hr-ft!-°F)° -
Primary Fand;
size (HP) - 2755 4
IP Un.HiO) - 34
Auxiliary Fan':
4P (in.H,0) - 9-3 4_
Incremental
Stack Coscf:
Soot Blowers: *
Total - Incremental
Cost/Unit
11
/ft'
Total Cosr f^
391,000
30.27
each
390 (HP) ?42.600
ach
eict\
Total Equipment Cost*
Direct Labor and Materials Cost (for exchanger and soot blower installation)
Indirect Costs (45% of Total Equipment and Direct Labor & Material Costs)
OPERATINC COSTS
Item
Steam/Hot Water
Electricity
Primary Fan _
Auxiliary Fan
Maintenance and Replacement Cost
Depreciation
Quantity Required
216,000 (Ibs/hr)
~ (kw)
1 ^160 (kw)
Total Annual r-n^T(.
ANNUAL REVENUE REQUIRED
.Area shown is 107. greater than area calculated.
"Overall heat transfer coefficient for condensing portion of exchanger.
^Overall heat transfer coefficient for desuperheat portion of exchanger.
Primary fan's base size corresponds Co a forced draft FCD process without reheat
^Auxiliary fan required for indirect ho: air and exit as recirculation configurations
'Incremental stack cost txperienced only with indirect hot air configuration.
The tan and incremental
cost of equipment chat is needed as a result of reheat.
stack costs included in this total are installed costs.
280
-------
TABLE E-20. COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(600 psia, dry saturated steam; air approach
temperature = 80 F; heat input specified)
CONFIGURATION:
—Q-LJ
Required Heat Input (10'Bcu/hr) - 66.8
Scrubbed Flu* Gas:
Temperature CF) - 120
Flow Rate (ibs/hr) - 5,140,000
Reheat Steam:
Temperature (T) - 486
Pressure (psia) - 600
Flow Rate (Ibs/hr) -90,400
Stack Exit Temperature C'F) -
Recirculation Exit Gas:
Temperature CF) -
Flov Rate (Ibs/hr) -
Reheat Air .-
Ambient Temperature CF) - 60
Heated Temperature CF) -406
Flow Rate (Ibs/hr) - 773,000
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF) - 4Qk
Exchanger 4P (in.HiO) -I
Condensing Heat Transfer
Superheat Heat Transfer
Primary F«nd:
size (HP) - 2755
IP (in.H.0) - 34
Auxiliary Fan*:
4P (in.SiO) -9.3
Incremental
Stack Costf;
Sooc Blowers:
No. Req
4
r
Coefficient
Coefficient
4
4
Total
1 d. Capacity
14, 100 (fc')
(Btu/hr-ft1-'F)b -
(Btu/hr-ft2-'F)c -
300 (HP)
Total - Incremental
Cose /Unit
a $ 11 /ft*
26.2
-
$ — each
$ 19.000 each
$ — each
Total Equipment CosC^
Direct Labor and Materials Cost (for exchanger and toot blower Installation)
Indirect Costs (457. of Total Equipment and Direct Labor 4 Material Costs)
TOTAL CAPITAL INVESTMENT
Total Cost (5)
155,000
-76.000
160,000
—
391,000
?78 noo
•?oi nr)Q
Q7ntnnQ
OPERATING COSTS
Item Quantity Required Cost/Unit
Steam/Hot Water 90,400 (Ibs/hr) 1.69 (S/lo'lbs)
Electricity
Primary Fan ~ (kw) ~ ($/kwh)
Auxiliary Fan ^22"4 (kw) 0.03l^$/kwh)
Maintenance and Replacement Cost
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
focal Annu
1,
1,
1.
a 1 Cosz^")
069,000
-
49.000
29 OnO
3QtQOQ
186,000
28 x 10°
?Area shown is 107. xreacer Chan area calculated.
Overall haac cransctr coefficianc Eor condensing portion of excnanjer.
.Overall heat transfer coeffictenc for desuperheac portion of exchanger.
Primary fan's base size correspond! co a forced draft FCD process without reheat,
^Auxiliary fan required for indirect hot air and exit gas recirculation configurations.
Incremental stack cost experienced only with indirect hot air configuration.
^Total cost of equipment that is needed as a resulc of reheac. The fan and incremental
stack costs included in this cotal are installed costs.
281
-------
TABLE E-21. COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(310 psia, dry saturated steam; air approach
temperature = 80°F; heat input specified)
CONFIGURATION;
66.8
Required Heat Input (10'Bcu/hr)
Scrubbed Flue Gas:
Temperature OF) - 130
Flow Rate (Ibs/hr) - 5,140,000
Reheat Steam:
Temperature OF) - 420
Pressure (psia) - 310
Flow Rate (Ibs/hr) -82,000
Stack Exit Temperature OP) - 162
Rtcirculacion Exit Gas:
Temperature CF) -
Flow Rate Ubs/hr) -
Reh«at Air•
Ambient Temperature OF) - 60
Heated Temperature OF) - 340
Flow Rate (Ibs/hr) - 955,000
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Tocal
Icem No. Req'd. Capacity
Reheat Exchanger: ^ 15,700(feJ)
Exit Temp. OF) - 340
Exchanger AP (in.H20) - 6
Condensing H«ac Transfer Coefficient (Btu/hr-ftJ-'F)b -
Superheac Heat Transfer Coefficient (Bcu/hr-fc'-'F)c -
Primary Fend:
Size (HP) - f'1 JJ H
4P (in.H,0> - 34
Auxiliary Fan8:
AP Un.H.Ol • 9t 3 * 364 (HP)
Incremental
Scack CoscE:
Soot Blowers : ~
Tocal - Incremental
Cosc/Unic
a $ 11 /fci
26.23
$ each
$ 20,700 each
$ - each
Tocal Cose
173,
-83,
195,
_
(S)
000
000
000
'
Tocal Equipmenc Cosc^
Direct Labor and Materials Cost (for exchanger and sooc blower inscallacion)
Indirect Coses (45% of Total Equipmenc and Direct Labor & Material Costs)
TOTAL CAPITAL INVESTMENT
451,
3.00-
33o ,
- 1.089.
ouu
QQQ
(ioo
ooo
OPERATING COSTS
Icem Quancicy Required Cost/Unit Total Annual Cost(S)
Steam/Hot Witer 82,000 (Ibs/hr) 1.73 (S/10'lbs)
993
,000
Electricity
Primary Fan ~ fcv) ~ (5/kwh)
Auxiliary Fan 271 (kw) 0 mi4<$/kwh)
60
.000
Maintenance and Replacement Co»c "\\ finfl
Depreciation . ^^ ("|(")ft
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
1 1 0 fl
1.23 :
tnnn
x lu
?Ar»» shown is 107. greater Chan area calculated.
Overall heat cransfer coeffici«nc for condensing portion of exchanger.
.Overall heat transfer coefficient for desuperheat portion of exchanger
"Primary fan's base size corresponds Co i forced draft FGD process without reheat.
"Auxiliary fan required for indirect hoc air and exit jas recirculation configurations.
"Incremental stack cost experienced only with indirect hot air configuration.
»Tocal cose of equipment chat is needed as a result of reheat. The Ian and incremental
sra^lc costs includarf in ^hi« rrtfal are triers! 1»H <-n«ra
ack costs included in this cocal are installed costs.
282
-------
TABLE E-22. COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(165 psia, dry saturated steam; air approach
temperature = 40°F; heat input specified)
CONFIGURATION:
R«quirid Heat Input (10'Btu/hr) - 66.8
Scrubbed Flue Gas:
Temperature CF) - 130
Flow Race (Ibs/hr) -5,140,000
R«h«»c Steam:
Temperature (*F) - 366
Preisure (psia) - 165
Flow Rate (Ibs/hr) -77,000
Stack Exit Temperature ('F) - 161
Raclrculation Exit Gas:
Temperature OF) -
Flow Rate (Ibs/hr) -
Reheat Air:
Ambient Temperature CF) - 60
Heated Temperature (-F) -326
Flow Rate (lbf/hr) -1,010,000
EQUIPMENT SPECIFICATIONS AMD CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF) - 326
Exchanger 4P (in.HjO) -
Condensing Heat Transfer
Superheat Heat Transfer
Primary Fand:
Size (HP) - //J->
4P Un.HiO) - 34
Auxiliary Fan*:
« (in.H.O) -9.3
Incremental
Stack Cost^.-
Soot Blowers:
Total
No. Rea'd. Capacity
4 24.100(ff)
Coefficient (Btu/hr-ft'-'F)1* -
Coefficient (Bcu/hr-f t' -'F)c -
4
4 388 (HP)
Total - Incremental
Cost/Unit
8 S 11 /ft'
24.33
_
S - each
S 2 1.300 each
S ~ each
Total Equipment Cost*
Direct Labor and Materials Cost (for exchanger and soot blower installation)
Indirect Costs (457. of Total Equipment and Direct Labor & Material Costs)
TOTAL CAPITAL INVESTMENT
Total Cost (S)
265,000
- 85.000
204,000
™
554rOOO
412,000
435.000
- 1,401.000
OPERATING COSTS
Item
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Quantity Required
77,000 (lb./hr)
_
28Q
Cost
(kw)
(kw)
Cost/Unic
1.57 ($/io!lbs)
($/kwh)
Q.Q314($/kwh)
Total Annual Cost(S)
845,000
—
64.000
LL nnn
56 000
1 nno nnn
1.14 x 10b
l-Area shown is 107. greater than area calculated.
Overall heat transfer coefficient for condensing portion of exchanger.
.Overall heat transfer coefficient for desuperheat portion of exchanger-
Primary fan's base size corresponds Co a forced draft FGD process without reheat.
^Auxiliary fan required for indirect hot air and exit gas recirculation configurations.
Incremental stack cost experienced only with indirect hot air configuration.
°Total cost of equipment that is needed as a result of reheat. The fan and incremental
stack costs included in this total are installed costs.
283
-------
TABLE E-23. COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(165 psia, dry saturated steam; air approach
temperature = 80 F; heat input specified)
CONFIGURATION:
Required Heat Input (10'Btu/hr)
Scrubbed Flue Gas:
Temperature CF) - 130
Flow Rate (Ibs/hr) -5,140,000
Reheat Steam:
Temperature CF) - 366
Pressure (psia) - 165
Flow Rate (Ibs/hr) - 77,000
66.8
Stack Exit Temperature CF) -158
Recirculation Exit Gas:
Temperature (*F) -
Flow Rate (Ibs/hr) -
Reheat Air:
Ambient Temperature CF) - 60
Heated Temperature CF) -286
Flow Race
-------
TABLE E-24. COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(165 psia, dry saturated steam; air approach
temperature = 120°F; heat input specified)
CONFIGURATION:
Required Heat Input (10'Btu/hr) - 66.8
Scrubbed Flue Gas:
Temperature CF) - 130
Flow Rate (Ibs/hr) -5,140,000
Reheat Steam:
Temperature CF) - 366
Pr«5»urt (p«l«) - 165
Flow Rat. (lbi/hr) - 76,600
Stack Exit Temperature CF) - 155
Recirculation Exit Gas:
Temperature OF) -
Flow Race (Ibs/hr) -
Reheat Air:
Ambient Temperature CF) • 60
Heated Temperature CF) - 246
Flow Rate (Ibs/hr) - 1,440,000
EQUIPMENT SPECIFICATIONS AMI CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF) - 246
Exchanger 4P (in.HiO) -
No. Req'd.
4
Total
Capacity
Total - Incremental
Cost/Unit
12.600 (ft')" s_
11 /ft'
Total Cost ($)
139.000
Condensing Heat Transfer Coefficient (Btu/hr-ft!-'F)b
Superheat Heat Transfer Coefficient (Btu/hr-ft'-'F)c -
Primary Fand: ,_._ ,
Size (HP) - *•! 33
30.4
each
it Un.HtO) - 34
Auxiliary Fan':
iP fin.H.O) - 9.3 4 560 (HP) $ 253,000each
Incremental
Stack Costf:
Soot Blowers: ~ 5 - each
101
287
,000
,000
—
Total Equipment Cost8
Direct Labor and Materials Cost (for exchanger and soot blower installation)
Indirect Costs (457. of Total Equipment and Direct Labor & Material Costs)
TOTAL CAPITAL INVESTMENT
5?7
258
353
- 1.138
,000
,000
,000
,000
OPERATING COSTS
Itttn
Quantity Required
Steam/Hot Water 76,600
Electricity
Primary Fan ~°
Auxiliary Fan 418
Maintenance and Replacement Cost
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
(Ibs/hr) 1.57 ($/io'lbs)
(kw) ~ (S/kwh)
(kw) Q.0314;$/kwh)
841,000
-
92,000
28,000
4fi,nno
1.007.000
1.12 x 10C
.Area shown is 107. greater than area calculated.
"Overall heat transfer coefficient for condensing portion of exchanger.
jOverall heat transfer coefficient for desuperheat portion of exchanger.
••Primary fan's base size corresponds to a forced draft FGD process without reheat.
.Auxiliary fan required for indirect hoc air and exit gas recirculacion configurations.
Incremental scack cose experienced only with indirect hot air configuration.
'Total cost of equipment that Is needed as a result of reheat. The fan and incremental
stack costs included in this total are installed coses.
285
-------
TABLE E-25.
COST SUMMARY SHEET FOR INDIRECT HOT AIR REHEAT
(16 psia, dry saturated steam; air approach
temperature - 80 F; heat input specified)
CONFIGURATION:
Required Heat Input (10'Btu/hr) -
Scrubbtd Flue Gas :
Temperature (*F) - 130
Flow Rate (Ibs/hr) - 5,140,000
Reheat Steam:
Temperature (*F) - 216
Pressure (psia) - 16
Flow Rate (lb«/hr) - 67 , 100
66.8
Stack Exit Temperature OF) -
Recirculacion Exit Cas.
Temperature (»F) -
Flow Rate (Ibs/hr) -
Reheat Ain
Ambient Temperature (-F) -
Heated Temperature ('F) -
Flow Rate (lb«/hr) -
60
136
3,530,000
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
No. Req'd.
4
Total
Capacity
Total - Incremental
Cost/Unit
19.9QQ(ft')* $
Reheat Exchanger:
Exit Temp. CF) -136
Exchanger iP (in.HaO) - ^
Condensing Heat Transfer Coefficient (Btu/hr-f^-'F)13 -
Superheat Heat Transfer Coefficient (3tu/hr-ft!-"F)c -
Primary Fand:
Size (HP) - 2755 _4
iP Un.HiO) - 34
Auxiliary Fan8:
AP (in.H,0) -Q. 1 ^ 198Q (HP)
Incremental
Stack Cost^:
Soot Blowers : **
Jl.
each
j40,OOQ ...H
each
Total Cose
Total Equipment Cost*
Direct Labor and Materials Cost (for exchanger and soot blower installation)
Indirect Costs (457. of Total Equipment and Direct Labor & Material Costs)
TOTAL CAPITAL INVESTMENT
OPERATING COSTS
Item
Quantity Required
67,100 (ib,/
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan 1.030 "
Maintenance and Replacement Cost
Depreciation
flew)
Cost/ Unit
0-78
O.Q314
($/kwhi
Total Ann,,.' r
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
jArea shown is 107. greater than area calculated.
Overall heat transrer coefficient for condensing porcion of exchanger.
^Overall heat transfer coefficient for desuperheat portion of exchanger.
Primary fan's base size corresponds to 3 forced draft FGD process without reheat
"Auxiliary ran required for indirect hot air and exit jtas recirculation configurations
'Incremental stack cost experienced only with indirect hot air configuration.
*Total cost of equipment that is needed as a result of reheat. The tan and incremental
stack costs included in this total are installed costs.
286
-------
TABLE E-26. COST SUMMARY SHEET FOR INDIRECT HOT AIR
REHEAT SENSITIVITY (CASE A)
CONFIGURATION:
Required Heat Input (10'Stu/hr) - 142
Scrubbed Flue Gas:
Temperature CF) - 130
Flow Rate (Ibs/hr) - 5,140,000
Reheat Steaai
Temperature CF) - 366
Pressure (psla) - 165
Flow Rate (Ib./hr) - 164 > QOO
Stack Exit Temperature CF) - 180
Recirculation Exit Gas:
Temperature OF) -
Flow Rate (Ibs/hr) -
Reheat Air;
Amblenc Temperature CF) - 60
Heated Temperature CF) -286
Flow Rat. (Ib5/hr) - 2,520,000
EQUIPMENT SPECIFICATIONS AMD CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF)
Exchanger AP (in
. 286
.HiO) -
No.
12
Req
4
'd.
Total
Capacity
Total - Incremental
Cost/Unit
29.200(ft')' $ 11
/ft'
Total Cos; ($)
321,000
Condensing Heat Transfer Coefficient (Btu/hr-ft'-'F)
Superheat Heat Transfer Coefficient (Btu/hr-ft!-°F)e
Primary Fend.-
size (HP) - 2755 4_
34.36
each
4P (in.HjO) - 34
Auxiliary Fan*:
4P (in.H,0) 15.. 3
Incremental
Stack Costf:
Soot Blowers :
4 400
-
Total Equipment Cost*
Direct Labor and Materials Cost (for exchanger and
Indirect Co*t> (45Z of Total Equipment and Direct
(HP) $51,200 »aeh
$ each
soot blower installation)
Labor 4 Material Costs)
204,000
573,000
.
- l,Q80rOOO
481.000
711.000
TOTAL CAPITAL INVESTMENT - ' UUU
OPERATING COSTS
Item Quantity Required Cost/Unit "
Steam/Hot Water 162,000 (Ibs/hr) 1.57 (S/lO'lbs)
rotal Annual Cos:(S)
1
,780,000
Electricity
Primary Fan ~ (kw) ~ (S/kwh) ' ~
Auxiliary Fan TjI90~ (kw) 0 . 03l4.$/kwh)
Maintenance and Replacement Coat
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
£
2
262.000
60.000
92.0QO
.194.000
.41 x 106
shown i> 107. greater than area calculated.
"Overall heat transfer coefficient for condensing portion of exchanger.
•Overall heat transfer coefficient for desuperheat portion of exchanger.
"Primary fan's base size corresponds to a forced draft FGD process without reheac.
^Auxiliary fan required for indirect hot air and exit gas recirculaticn configurations.
Incremental stack cost experienced only wtth indirect hoc air configuration.
•Total cost of equipment that is needed as a result of reheat. The fin and Incremental
stack costs included in this total are installed costs.
287
-------
TABLE E-27. COST SUMMARY SHEET FOR INDIRECT HOT AIR
REHEAT SENSITIVITY (CASE B)
CONFIGURATION:
Required Heat Input UO'Jtu/hr) - 117
Scrubbed Flue Gas:
Temperature CF) - 130
Flow Rate Ub./hr) - 5,140,000
Reheat Steam:
Temperature (*F) - 745
Pressure (peia) - 165
Flov Rat* (Ib./hr) - 1Q8 , 000
Stack Exit Temperature CF) -
Recirculation Exit Gas:
Temperature CF) -
Flow Rate (Ibs/hr) -
Reheat Air :
Ambient Temperature CF)
Heated Temperature CD
Flow Rate (Iba/hr) -
- 60
286
1,670,000
EQUIPMENT SPECIFICATIONS AMD CAPITAL INVESTMENT
Item
Exit Temp CF) - 338
Exchanger 4P (in.HjO) -
Condensing Heat Transfer
Superheat Heat Transfer
Primary Fan<*:
Size (HP) - 2755
IP (in.H.O) - 34
Auxiliary Fan8:
ftP (in.H.O) -9.3
Incremental
Stack Costf:
Soot Blowers:
Total Total - Incremental
No Req'd. Capacity Cost/Unit
4 Sl.SOQft^a $ 11 /£t!
6 ,. ,
Coefficient (8tu/hr-ft'--F)b - '••'••»
Coefficient (Bcu/hr-ft!-°F)c - 20.9
4 $ - each
4 161 (HP) S26.900 each
~ $ — each
Total Equipment Coar*
Direct Labor and Materials Cost (for exchanger and soot blower installation)
Indirect Costs (457. of Total Equipment and Direct Labor & Material Costs)
TOTAL CAPITAL INVESTMENT
Total Cost (S)
341
108
385
834
505
603
- 1,94Z
,000
,000
,000
•
,000
,000
,noo
,000
OPERATING COSTS
Item Quantity Required
Steam/Hot Water 108,000 (ios/hr)
Electricity
Primary Fan (kw)
Auxiliary Fan Zj'SQ (kw)
Maintenance and Replacement Cast
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Cost/Unit
1 cn
• 7 J ($/ 10 Ibs)
(S/kvh)
O.Q314
-------
TABLE E-28. COST SUMMARY SHEET FOR INDIRECT HOT AIR
REHEAT SENSITIVITY (CASE C)
CONFIGURATION:
Required H««t Input (10'Btu/hr) - 109
Scrubbed Flu* Gas.
Temperature CF) - 125
Flow Rat* (lb»/hr) - 5,120,000
R*heac Steam:
Temperature (*F) - 366
Pr«s»ur* (p»ia) - 165
Flow Rat* Ube/hr) -Q7 500
Stack Exit Temperature OF) - 175
Recirculation Exit Gas:
Temperature CF) -
Flow Rate (Ibs/hr) -
Reheat Air•
Ambient Temperature (4F) • 60
Heated Temperature CF) - 286
Flow Rat. (lbi/hr) '1,480,000
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF) - 286
Exchanger 4P (in.H,0) -
Condensing Keac Transfer
Superheat Heat Transfer
Primary Fand:
Size (HP) - 3010
ap (in.H.O) - 34
Auxiliary Fan*:
iP (in.H,Oi • ~
Incremental
Stack Cost':
Soot Blowers:
Total
No. Req'd. Capacity
4 12 4QQiftJ)
Ji°—
Coefficient (Btu/hr-ft'-'Fr -
Coefficient (Btu/hr-ft'-'F)0 -
4
(HP)
-
Total - Incremental
Cost/Unit
1 S 11 /ft1
42.51
-
S<2,800> each
$ - each
$ ~ each
Total Equipment Cose*
Direct Labor and Materials Cost (for exchanger and sooc blower installation)
Indirect Coses (457, of Total Equipment and Direct Labor & Material Costs)
TOTAL CAPITAL INVESTMENT
Total Cost (5)
147,000
<11.000:
353.000
_
489,000
269,000
341.000
- 1,099,000
OPERATING COSTS
Item
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Quantity Required
97.500
760
-
Cost
(Ibs/hr)
(kw)
(lew)
Cost/Unit
1.57 ($/io'ibs)
0.0314 (S/kwh)
(S/kwh)
Total Annual Cos:(S)
Ir072r000
167.000
_
21,000
44,nno
1,304,000
1.41 x 10C
shown is 10% greater than area calculated.
.....11 heat transfer coefficient for condensing portion of exchanger.
.Overall heat transfer coefficient for desuperhaat portion of exchanger.
Primary fan's base size corresponds to a forced draft FGD process without reheat.
-Auxiliary fan required for indirect hot air and exit gas recirculation configurations.
Incremental stack cost experienced only with indirect hoc air configuration.
*Tocal cose of equipment chat is needed as a result of reheat. The ran and incremental
stack costs included in this total are installed coats.
289
-------
TABLE E-29. COST SUMMARY SHEET FOR INDIRECT HOT AIR
REHEAT SENSITIVITY (CASE D)
CONFIGURATION:
Re-quired Heat Input (10'Bcu/hr) - 120
Scrubbed Flue Gas:
Temperature OF) - 125
Flow Race (Ibs/hr) -5,120,000
Reheat Stean:
Temperature CF) - 486
Pressure (psia) - 600
Flow Rate (Ibt/hr) - 129 , 550
Stack Exit Temperature (*") - 193
Recirculation Exit Gas:
Temperature CD -
Flow Rate (Ibs/hr) -
Reheat Air:
Ambient Temperature CF) - 60
Heated Temperature CF) - 446
Flow Rate (Ibs/hr) - 928,270
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Icem No. Rtq
Exit Temp. CF) - 446
Exchanger 4P (in.HiO) - 30
Condensing Heat Transfer Coefficient
Superheat Heat Transfer Coefficient
Primary Fand:
Sire (HP) - 2860 4
iP (in.HiO) - 34
Auxiliary Fan* .-
4P (in.H.O) - ~- ~
Incremental
Stack Cost£: _
Soot Blowers:
Total
'd. Capacity
17, 500 (ft
(Btu/hr-ft!-'F)b
(Btu/hr-ft'-'F)c -
Total - Incremental
Cost /Unit
»)" S 11 /ft'
- 35.99
_
S <8.400>each
Total Cost ($)
193,000
<•*£, nnn>
- (HP) S - each ' -
$ ~ each
256.000
-
Total Equipment Cost8
Direct Labor and Materials Cost (for exchanger and soot
Indirect Costs (457. of Total Equipment and Direct Labor
TOTAL CAPITAL INVESTMENT
blower installation)
& Material Costs)
411,000
794 nnn
333; ooo
- 1.072.000
OPERATING COSTS
Item Quantity Required Cost/Unit Total Annual Cost($)
Steam/Hot Water 129 , 5 SO (Ibs/hr) 1.69 ($/io'lb«)
Electricity
Primary Fan 835 (kw) 0 . 0314 (S/kwh) '
Auxiliary Fan (kw) (S/kwh)
Maintenance and Replacement Cost
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
1,532,00
184,000
25.000
/i 3, 000
1,784,000
1, 89 x 10°
?Area shown is 107. greater than are
Overall heat transfer coefficient
rea calculated.
— •—- — -- -—— - _._..-.—. .— — .__..v..c for condensing portion of exchanger.
jOverall heat transfer coefficient for desuperheat portion of exchanger.
"Primary fan's base size corresponds to a forced draft FGD process without reheat.
^Auxiliary fan required for indirect hoc air and exic zas recircuiation configurations.
"Incremental stack cost experienced only with indirect hot air configuration.
&Totai cost of equipment that is needed as a result of reheat. The tan and incremental
stack costs included in this cotsl are installed costs.
290
-------
TABLE E-30. COST SUMMARY SHEET FOR INDIRECT HOT AIR
REHEAT SENSITIVITY (CASE E)
CONFIGURATION:
Required Heat Input (10'Btu/hr) -
Scrubbed Flu* Gas:
Temperature (*F) -
Flow Rate (Ib./hr)
Reheat Steam:
Temperature (*F) -
Pressure (p«i») -
Flow Rat. (Ib./hr) "66,000
81.4
126
5,120,000
539
600
Stuck Exit Temperature (•?) - 176
Rtclrculacion Exit Gas:
Temperature (*F) •
Flow Rate (Ibs/hr) -
Reheat Air•
Ambient Temperature OF) - 60
Heated Temperature CF) - 446
Flow Rate »ach
each
S_
each
Total Cose (S)
139,000
Total Equipment Cost*
Direct Labor and Materials Cost (for exchanger and soot blower installation)
Indirect Costs (<>n of Total Equipment and Direct Labor & Material Costs)
160,000
258.OOP
188,QUO
TOTAL CAPITAL INVESTMENT
606,000
OPERATING COSTS
Quantity Required
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
66,000 (lbi/hr) 1.95 (S/10,lbsl
<536> new) 0.0314($/kwh) '
Otw) - (5/kwh)
Cost
901,000
<118,000>
-
13,000
24,000
820.000
0.88 x 106
portion of exchanger.
?Area shown is 10% greater than area calculated.
Overall heat transfer coefficient for condensing
.Overall heat transfer coefficient for deiuperheat'portion of exchanger.
^Primary f«n'J bale size corresponds Co a forced draft FCO process wichout rahaac.
.Auxiliary fan required for indirect hot air and exit gas recirculation configurations.
^Incremental stack cost experienced only with indirect hot air configuration.
'Total cost of equipment that is needed as a result of reheat. The Ian and incremental
stack costs included in this total are Installed costs.
291
-------
TABLE E-31. COST SUMMARY SHEET FOR EXIT GAS RECIRCULATION
(600 psia, dry saturated steam; flue gas approach
temperature - 40 F)
CONFIGURATION:
Required Heat Input (10'Btu/hr) - 66.8
Scrubbed Flue Gas:
Temperature CF) - 130
Flow Race (Ibs/hr) -5,140,000
Reheat Steam:
Temperature ("F) - 486
Pressure (psia) - 600
Flow Rate (Ibs/hr) -90,300
Stack Exit Temperature C") - 180
Recirculation Exit Gas:
Temperature CF) - 446
Flow Rate (Ibs/hr) - 913,000
Reheat Air
Ambient Temperature (°F) -
Heated Temperature CD -
Flow Race (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
No. Req'd,
Total
Capacity
Total - Incremental
Cost/Unit
446
Reheat Exchanger:
Exit Temp. CF)
Exchanger iP (in.HjO) - 6
Condensing Heat Transfer Coefficient "(Btu/hr-ft:-•r,
Superheat Heat Transfer Coefficient (Stu/hr-fc:-'F)c -
Primary Fan": „_ __ ,
37,700^=,. s 20
/fc:
Total Cost (Si
754,000
16.9
Si:« (HP1 - *•' 33
-P (in. HO) - 34
Auxiliary Fan6 :
'P lin.H. 01 - 6
Incremental
Stack Costf:
Soot Blowers :
H S each
4 70 (HPl $17,500 each
8 s 1,700 each
Tot.il Equipment Cost*
Direct Labor and Materials Cost (for exchanger Jnd soot blower installation^
Indirect Costs (*57. of Total Equipment and Direct Labor i Material Costs)
TOTAL CAPITAL INVESTMENT
Item
Steam/Hoc Water
Electricity
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COS-
ANNUAL REVENUE REQUIRED
-
OPERATING COSTS
Quantity Required Cost/Unit T^-tal
Qn,3nn dbs hr) 1.69 (S'io'ibS>
- ikw) — (5/kwh)
2n8
-------
TABLE E-32. COST SUMMARY SHEET FOR EXIT GAS RECIRCULATION
REHEAT (600 psia, dry saturated steam; flue gas
approach temperature
80°F)
CONFIGURATION:
Required Heat Input (10*Btu/hr) - 66*3
Scrubbed Flue G«<:
Temperature (*F) - 130
Flow Rate abs/hr) -5,140,000
Reheat Steam:
Temperature (°F) - 486
Pressure (psia) - gQO
Flow Race (lb»/hr) - 9Q 1QO
Stack Exit Temperature ('F) - 180
Recirculation Exit Cas
Temperature ('F,i - 406
Flow Rate (lbs/hr> - 1,080,000
Reheat Air
Ambient Temperature CF) -
Heated Temperature C°F) -
Flow Rate (Ibs/'hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item No. Reel
Reheat Exchanger: ^
Exit Temp CF) -406
Exchanger iP (in.H:0) - ft
Condensing Heat Transfer Coefficient
Superheat Heat Transfer Coefficient
Primary Fand;
Size (HP1 - 2755 4
-P Un.H.O) - 34
Auxiliary Fane -.
'P Un.H 0* - fi° 4
Incremental
Stack Coacf
Soot Blowers: y
Total
'd. Capacity
26.200uv>
"(Btu/hr-ft-'--F)b -
(Btu/hr-ff'-'F)c -
ft1} (HP>
Total - Incremental
Cost/Unit
a $ 20 'ft:
18.9
—
$ - each
$18,900 each
$ 1,700 each
Tot.'l Equipment Cost^1
Direct Labor and Materials Cose (for exchanger And soot blower installation"*
Indirect Costs (*57. of Total Equipment and Direct Labor & Material Co.«ts>
TOTAL CAPITAL INVESTMENT
Total Cost (SI
524,000
77,000
1 4 000
615,000
441,000
47"; 000
- 1^531,000
OPERATING COSTS
I ten
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
Ouan t i t v
90,100
_
248
Cost
Required
Ubs hr)
itew)
(kw)
Cost/Unir Total Annual Ojri.:M
1.69 1,066,000
(S/kwh) -
0.0314(3';-.wh) 55.000
165 000
fil^OQO
1,347,000
1.49 x 10°
j*Area sh^wn is 25% ireacer chan area calculaced.
,Ov«raLL heac transfer co«ffict«nc for condensing portion o: exchanger.
^Overall Keac cranafer coefficient for desuperheac porcion of exchaneer.
Prttrary fan's base siz* corresponds co a forced dratc FCD process wtchouc reheac.
^Auxiiiarv fan required for indirect hot air and exit gas recirculation configurations
Incremental stack cost experienced only vith indirect hot air confi«uracion.
^TocaL cose of equipment chat is needed as a result of reheat. The fan and incremental
stack costs included in this total are installed coses.
293
-------
TABLE E-33. COST SUMMARY SHEET FOR EXIT GAS RECIRCULATION
REHEAT (310 psia, dry saturated steam; flue
gas approach temperature = 120 F)
CONFIGURATION:
Required Heat Input (lO'Bcu/hr) - 66.8
Scrubbed Flue Gas:
Temperature (T) - 130
Flow Race (Ibs/hr) -5,140,000
Reheat Steam:
Temperature CF) - 420
Pressure (psia) - 310
Flow Rate Ubs/hr) -gQ
Stack Exit Temperature CF) - 180
Recircuiacion Exit Gas
Temperature CF) - 300
Flow Rate (Ibs/hr) -2,040,000
Reheat Air
Ambient Temperature CF) •
Heated Temperature CF) -
Flow Rate (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
Mo Req ' d.
Total
Capacity
Total - Incremental
Cost;Unit
21.100(tV)a s_
Reheat Exchanger:
Exit Temp CF) -300
Exchanger 3P (in.H;0) - fi
Condensing Heat Transfer Coefficient (Btu/hr-ft;-'Fj
Superheat Heat Transfer Coefficient (Btu/hr-ft:-'F)c -
Primary Fan^:
Si;e (HP) - 2755
20
Total Cose iSl
422,000
22.3
iP (in.H.O) - 34
Auxiliary Fane :
'P Ur..H 0) • 6
Incremental
Stack Coscf:
Soot Blowers :
4 157
8
Tot.il Equipment Cost^
Direct Labor and Materials Cost (for exchanger ana
Indirect Costs (i5". of Total Equirmenc and Direct
TOTAL CAPITAL INVESTMENT
(HP) $ 25, 200 each
S 1,700 each
soot blower installat ion)
Labor i Material Costs)
101,
-
14 r
- 537,
^7?
409,
- 1-318,
000
OUU
OUO
nnn
000
000
OPERATING COSTS
Item
Steam/Hoc Water
EUccricicy
Primary Fan
Auxiliary Fan
Mainc0nanc« and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENIT REQUIRED
Quant i:v Required
80.900 ubs'hr)
~ ikw)
468 (k«)
Cose
Cost 'Unir
1.73 (S/lO'lbs)
~ (S/'kwh)
0.0314($/',-.wh)
T.-tal Annual C.-st i J)
980,000
_
103, OUU
137,000
si nno
] 273,000
1.40 x 10G
^Area sho-jn is 25* greater :han area calculates.
Overall heat transfer coefficient for condensing porf-on ot exchanger.
Overall heat transfer coefficient for desuperheat'oorcion of exchanger
"Primary tan's base siie corresponds Co a forced draf: FCD process without reheat.
^Auxiliary ran required for indirect hot air and exit zas recirculation configurations
•Incremental stack cost experienced only with indirect hot sir confizuration
^Tocal ejisc of e^uip.rent that is needed is a result of reheat. The fan ar.d increrencaL
stack costs included in this total are installed costs
294
-------
TABLE E-34. COST SUMMARY SHEET FOR EXIT GAS RECIRCULATION
REHEAT (165 psia, dry saturated steam; flue
gas approach temperature
80°F)
CONFIGURATION:
-OH
Required Heat Inpuc (10'Btu/hr) - 66.8
Scrubbed Flue G«i
Temperature CF) - 130
Flow Race Ub./hr) - 5,140,000
Reheat Sceaoi:
Temperature (°F) - 366
Pressure (psia) - 165
Flow Rate (Ibi/hr) - 75,800
Stack Exit Temperature (T) - 180
Recirculation Exit Gas:
Temperature (JF) - 286
Flow Rate (Ibs/hr) -2,370,000
Reheat Air
Ambient Temperature (*F) -
Heated Temperature CF) -
Flow Rate (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AMD CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF) - J>86
Exchanger AP vin.H.O) -
Condensing Heat Transfer
Total Total - Incremental
No. Req'd. Capacity Cost/Unit
4 31,300(t-t=)a s 20 /tv
Coefficient "(Btu/hr-ft:-'F)b - 20-8
Total Cost tS>
626,000
Superheat Heat Transfer Coefficient iBcu/hr-f t: -'F)c - ~
Primary Fand;
Size (HP) - 2785
iP (in.H.O) - 34
Auxiliary Fan* :
'P Ur..H 01 - "
Incremental
Stack Costf
Soot Blowers:
4 S - each
4 182 CHP) 3 27, 200 eaoh
8 5 1,700 each
Tot.il Equipment Cost*
Direct Labor and Materials Cost (for exchanger and sc'ot blower installation!
Indirect Costs (i5T. of Total Equipment anJ Direct Labor i Material Costs)
TOTAL CAPITAL INVESTMENT
-
109,000
1^,000
- 749,000
-. 509,000
566-000
- 1,824,500
OPERATING COSTS
Item
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
f*Area shown is 25", greater
Ojaantitv Required Cost/Unit
75,800
_
543
Cost
(lb» hr) 1. 57 (5 10'lbs)
(kw) "~ ($/kwh)
(kw) Q,Q314\S/',-.wh)
Toe.U -nnu.il Os"^
832,000
-
119,000
197.000
7 "* 000
1 991,000
1.39 x 10G
than area calculated.
295
-------
TABLE E-35. COST SUMMARY SHEET FOR EXIT GAS RECIRCULATION
REHEAT (165 psia, dry saturated steam; flue gas
approach temperature = 120 F)
CONFIGURATION:
Required Heac Input (10'Btu/hr) - 66.8
Scrubbed Flue Gas
Temperature CF) - 130
Flow Race (Ib^/hr) - 5,140,000
Reheac Sceam:
Temperature (°F) - 366
Pressure (psla) - 165
Flow Rate (Ibs/hr) -74,700
Stack Exit Temperature ('*) - 180
Recirculation Exit Gas
Temperature CF) - 246
Flow Rate (Ibs/hr) - 3,850,000
Reheat Air
Ambient Temperature C°F) -
Heated Temperature ("F> -
Flow Rate (lbs;hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
Total
Capacity
Total - Incremental
Co s t / Un i t
Reheat Exchanger:
Exit Temp. CF) - 246
Exchanger iP (in.H.O) -
No Reg' d
4 21.QQOcV)a s 20
Total Cost (S)
420,000
28.5
Condensing Heac Transfer Coefficient (8tu/hr-ft:-•F! -
Superheat Heat Transfer Coefficient (Ecu/hr-ft:-'F)c -
Primary Fand:
sue CUP) - 2755 _4
iP (in.K.O) -34
AuxiHarv Fan*:
•P Ur.'.H 0> - 6 4 295 (HP) $35.000 each
Incremental
Stack
140,000
Soot Blowers: ° S 1 , 7UU each
Totjl Equipmenc Cose6
Direct Labor and Materials Cost (for exchanger jno s^ot blower installation)
Indirect Costs (i5". of Total Equipment .inJ Direct Labor & Material Costi)
TOTAL CAPITAL INVESTMENT
OPERATING COSTS
Item Quantitv Required Cosc.'Unic T.-t:\l
Steam/Hoc Water 74,700 Ubshr) 1.57 (S'lO'lbs)
-14
574
371
425
1,3/0
Annual C.
820
i ooo
,000
,000
.000
,000
,000
Electricity
Primary Fan ~ (kw) ~ (S/kwh) ~
Auxiliary Fan 880 (kw) 0 . 0314^(5 'k«h)
Maintenance and Replacement Cost
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVENUE REQUIRED
193
139
ss
1,207
1.34
,000
,000
,noo
,000
x 10
uAr«a shown is 25% areac«r chan area cal^ui-aced.
^Overall hea: cranscer coecficienc t'jr condensing portion of excnanaer.
"•.Overall heac cransf-jr coefficient tor desuoerheac nor:ion of exchaneer
Primary fan's base size corresponds co a forced dracc FGD process withouc reheac.
^Auxiliary fan required for indirecr hoc air and exi: za^ recirculacion confisuracions.
^IncreT.encal scack cost experienced only wich indirecc hoc air configuration.
-local c^sc of equipment thac ii needed as a resulc of reheac The fan and incremental
stack coses included in chi> total are installed costs,
296
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TABLE E-36. COST SUMMARY SHEET FOR EXIT GAS RECIRCULATION
REHEAT SENSITIVITY (Case A)
CONFIGURATION:
Required Heat Input (10'Btu/hr) - 66.8
Scrubbed Flue Gas .-
Temperature CF) - 130
Flow Rate (Ibs/hr) -5,140,000
Reheat Steam:
Temperature CF) - 745
Pressure (psia) - 165
Flow Rate (Ibs/hr) -61,800
Stack Exit Temperature Cp> - 180
Recirculacion Exit Gas
Temperature CF) - 310
Flow Race (Ibs/hr) - 1,920,000
Reheat Air
Ambient Temperature CF) -
Heated Temperature CF) -
Flow Race (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
Reheat Exchanger;
Exit Temp CF) - 310
Exchanger iP an.H;0> -
Condensing Heat Transfer
Superheat Heat Transfer (
Primary Fand :
Si:e (HP) - 2755
iP (in.H.O) - 34"'
Auxiliary Fan* :
^P Ur..H 01 - 6
Incremental
Scack Cost*
Soot Blowers:
Total
No. Req'd. Capacity
Total - Incremental
Cost /Unit
4 30,900(tv)a $ 20 /ft =
6
Coefficient "(Btu/hr- fc: -• F)b -
inefficient (Btu/hr-f c: -°F)° -
4
4 148
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TABLE E-37. COST SUMMARY SHEET FOR EXIT GAS RECIRCULATION
REHEAT SENSITIVITY (Case B)
CONFIGURATION:
Required H«»c Input UO«Btu/hr) - 66.6
Scrubbed Flue Gas:
Temperature OF) - 126
Flow Rate (Ibs/hr) -5,120,000
Reheat Steam:
Temperature (°F) -
Pressure (psia) -
now Rate Ubs/hr) -
366
16S
49,500
Stack Exit Temperature CP1 - 176
Recirculacion Exit Gas
Temperature C'F) - 296
Flow Rate (Lbs/hr) -1,290,000
Reheat Air
Ambient Temperature CF) -
Heated Temperature CF) -
Flow Rate (Lbs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF) - 286
Exchanger ^P Un.H.O) -
Condensing Heat Transfer C
Superheat Heat Transfer Co
Primary Fand:
Si:e (HP) - 2350
iP (in.H 0) - 34
Auxiliary Fan13
'P Un.H 0' 6
Incremental
Stack Cost
Soot 31owers:
Total Total - Incremental
No Req'd. Capacity Cost/Unit
4 19.700(ft:)a $ 20 /fc:
oefficient "(Btu/hr-f t; -• F)b - 20. J
efficient (Stu/hr-f t: -'F1C - —
4 $<36,400>ea,-h
4 104 (HP) 521.600 each
8 $1,700 each
Tot.tl Equipment Cost**
Direct Labor and Materials Cost (for exchanger and sooc blower installation)
Indirect Costs (iS* of Total Equipment and 3tr«cc Labor i. Material Costs)
TOTAL CAPITAL INVESTMENT
I ten
Steam/Hot Water
Electricity
Primary Fan
Auxiliary Fan
Maintenance and Replacement
Depreciation
TOTAL ANNUAL OPERATING COST
ANNUAL REVEMUF. REQUIRED
OPERATING COSTS
quantitv Required Cost: Unit TV-
49,500 Ubs.hr) 1. 57(5 '10'lbsl
<1200> ikw) 0.03 14 < 3 ;•--.«[,)
310 (kw> Q.Q3l4>-kwhi
Cost
Total Cost (SI
394,000
<146.000>
87,000
_
14,001)
349.000
353 000
T 1 6 ,' nOO
- l,ni8,QOjO
CA'L Annual C.'*t (,5>
543,000
<264,000>
68,000
128.000
41.000
sift,noD
.61 x 10*
.Area shown is -5% greater chan area caicuLdced
°Ch.-erjll heat transfer coefficient for condensing portion of exchanger.
.Overall heat transfer coefficient for desurerhaat portion of exchanzer.
Primary fan's base size corresponds to a rorced draft FGD process without reheat.
^Auxiliary fan required for indirect hot air and exit zas recirculation configurations-
Incremental stack cost experienced only with indirect hot air configuration.
?Total :cst of equipment that is needed as a result of reheat. The fan and incremental
stack coses included in this total are installed costs.
298
-------
TABLE E-38. COST SUMMARY SHEET FOR EXIT GAS RECIRCULATION
REHEAT SENSITIVITY (Case C)
CONFIGURATION:
Required Heat Input (10'Btu/hr) - 66.6
Scrubbed Flue G«s:
Temperature OF) - 125
Flow Race Ubs/hr) -5,120,000
Reheat Steam:
Temperature (*F) - 366
Pressure (psia) - 165
Flow R.C. (ib./hr) -13,700; 33,900
Stack Exit Temperature OF) - J. / J
Recirculation Exit Gas:
Temperature CF) - 286
Flow Rate (Ibs/hr) - 337 QQQ
Reheat Air:
Ambient Temperature (°F).-
Heated Temperature CF) -
Flow Rate (Ibs/hr) -
EQUIPMENT SPECIFICATIONS AND CAPITAL INVESTMENT
Item
Reheat Exchanger:
Exit Temp. CF) -
Exchanger 4P (in.H:0> -
No . Req'd.
4
Total
176
JJUU
3TW
uV)a
Total - Incremental
Cost/Unit _
$ 20 -ft-
Total Cost (SI
180.000
.; -
Condensing Heat Transfer Coefficient "(3tu/hr-ft: -• F)b - 33 . 4 ', 31 . 7
Superheat Heac Transfer Coefficient (Btu/hr-f c: -'
Primary Fand:
Size (HP> 2620 4
-P (in.H.O) - 37
Auxiliary Fan* :
'•P (ip. H O1 -~ —
Incremental
Stack Co»tf:
Soot Blowers: 8
Tot.il Equipment Cost*
Direct Labor and Materials Cost (for exchanger and
Indirect Costs (45" of Total Equipment and Direct
TOTAL CAPITAL INVESTMENT
>F)C -
S<21,000>each
(HP) S - each
$1,700 each
soot blower installation)
Labor 4 Material Costs'!
<84,
—
14 ,
- 110,
- 210,
- 144
- 464 1
000-
000
000
noo
onn
noo
OPERATING COSTS
Item
Quantity Required
47.600 Ubs/hr)
Cost, 'Unit
T^-Cal Annual Cost i, $"»
Steam/Hot Water
Electricity
Primary Fan <4QQ> (kw)
Auxiliary Fan — (kw)
Maintenance and Replacement Cost
Depreciation
1.57 (S'lO'lbs)
0.0314;$/kwh)
- (S/V.wh)
522,000
<88.00Q>
58,000
19,000
TOTAL ANNUAL OPERATING COST
000
0.56 x 10°
ANNUAL REVENUE REQUIRED
uArea shown is 25% uraacer than area caLculac«d.
Overall heat cranstgr coeffici*nc for condensing portion oc exchanger.
^Overall heat transfer coefficient for desuoerheat portion of exchanger.
Primary fan'* base size corresponds to a forced draft FCO process without reheat.
^Auxiliary fan required for indirect hot air and exit zas recirculation configurations.
'incremental stack co*t experienced only wich indirect hot air confieuration.
^Tocal cost of equipment that is needed as a result of reheat. The fan and incremental
stack costs included in chis total are installed costs.
299
-------
APPENDIX F
FACTORS FOR CONVERSION OF ENGLISH UNITS TO THE
INTERNATIONAL SYSTEM OF UNITS (SI)
300
-------
English Units
Multiplication Factor
For Conversion
Btu
Btu/hr
Btu/hr-ft2-°F
Btu/kWh
Btu/lbn,
Btu/lbm-°F
ftz
ft/sec
ftVmin
gal/hr
gr/scf (grain/std. cubic foot)
hp (horsepower)
inch
in. H20 9 60*F
kWh
mile
lbn,
Ibn/hr
lbf/in.2
lbn/»ec
1.06 x 103
2.92 x 10"1
5.67
1.06
2.32 x 103
4.18 x 103
3.05 x 10"1
3.05 x 10"1
A. 72 x 10""
1.05 x 10"'
2.29 x 10"s
7.46 x 10"2
2.54 x 10"2
2.-49 x 102
3.60 x 10s
1.61 x 10s
4.54 x 10"1
1.26 x 10"
6.89 x 10J
4.54 x 10'1
SI Units
joule (J)
watt (W)
watt/meter2-°C (W/m2-°C)
joule/watt-hour (J/Wh)
joule/kilogram (J/kg)
Joule/kllogram-"C (J/kg-"C)
meter (m)
meter/second (ra/s)
meter3/second (m3/s)
meter3/second (ra3/s)
kilogram/meter3 (kg/ra3)
watts (W)
meters (ra)
pascal (Pa)
joule (J)
meter (m)
kilogram (kg)
kilogram/second (kg/s)
pascal (Pa)
kilogram/second (kg/s)
Temperature Conversions:
T("C) • 0.56[T(°F)-32]
TCK) - 0.56(T("R)]
301
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-80-051
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Stack Gas Reheat Evaluation
5. REPORT DATE
March 1980
6. PERFORMING ORGANIZATION CODE
7. AUTHQR(S)
W.R.Menzies, C.A.Muela, and G. P. Behrens
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78766
10. PROGRAM ELEMENT NO.
INE827
11. CONTRACT/GMANT NO.
68-02-2642
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 6/77-2/80
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES J.ERL-RTP project officer is Theodore G. Brna, Mail Drop 61
919/541-2683.
16. ABSTRACT
The report gives results of technical and economic evaluations of stack gas
reheat (SGR) following wet flue gas desulfurization (FGD) for coal-fired power
plants. The evaluations were based on information from literature and a survey of
FGD users, vendors, and architect/engineer (A/E) firms. The report summarizes
SGR processes and their features and their commercial operating experience. It
addresses benefits and energy requirements associated with SGR, and describes a
developed method for estimating reheat costs. SGR can protect equipment down-
stream of a wet scrubber from corrosion, reduce the potential for acid rainout near
the plant stack, preclude visible stack plumes, and reduce ground-level pollutant
concentrations by increasing plume buoyancy. SGR users have generally installed it
for equipment protection (30°F or higher reheat is normally specified). Most A/E
firms and vendors do not recommend SGR as a necessary part of a wet FGD system;
they prefer the higher reliability of indirect hot air injection. Plants slated for oper-
ation with wet scrubbers in 1983 will use inline (30%), bypass (24%), and indirect hot
air (14%) reheat or no reheat (wet stacks, 20%). Inline reheat is generally less costly
but has lower reliability than indirect hot air reheat. Bypass reheat is the most eco-
nomical; but its application is limited by SO2 emission regulations.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Pollution
Desulfurization
Flue Gases
Reheating
Coal
Combustion
Evaluation
b.lDENTIFIERS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
Stack Gas Reheat
COSATI Field/Group
13B
07A,07D
2 IB
13A
2 ID
14B
13. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
31. NO. OF PAGES
314
20. SECURITY CLASS (Thispage!
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
302
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