United States Office of Air Quality EPA-450/3-80-027
Environmental Protection Planning and Standards December 1980
Agency Research Triangle Park NC 27711
Air
Organic Chemical
Manufacturing
Volume 5: Adsorption,
Condensation, and
Absorption Devices
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EPA-450/3-80-027
Organic Chemical Manufacturing
Volume 5: Adsorption, Condensation,
and Absorption Devices
Emission Standards and Engineering Division
U.S. Environmental Protection Agency
Library (PH2J)
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
December 1 980
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U.S. Environmental Protection
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Ill
This report was furnished to the Environmental Protection Agency by IT Enviro-
science, 9041 Executive Park Drive, Knoxville, Tennessee 37923, in fulfillment
of Contract No. 68-02-2577. The contents of this report are reproduced herein
as received from IT Enviroscience. The opinions, findings, and conclusions
expressed are those of the authors and not necessarily those of the Environmen-
tal Protection Agency. Mention of trade names or commercial products is not
intended to constitute endorsement or recommendation for use. Copies of this
report are available, as supplies permit, through the Library Services Office
(MD-35), U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina 27711, or from National Technical Information Services, 5285 Port
Royal Road, Springfield, Virginia 22161.
D124R
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V
CONTENTS
Page
INTRODUCTION vii
Report Page
1. CONTROL DEVICE EVALUATION CARBON ADSORPTION 1-i
2. CONTROL DEVICE EVALUATION CONDENSATION 2-i
3. CONTROL DEVICE EVALUATION GAS ABSORPTION 3-i
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VI1
INTRODUCTION
A. SOCMI PROGRAM
Concern over widespread violation of the national ambient air quality standard
for ozone (formerly photochemical oxidants) and over the presence of a number
of toxic and potentially toxic chemicals in the atmosphere led the Environ-
mental Protection Agency to initiate standards development programs for the
control of volatile organic compound (VOC) emissions. The program goals were
to reduce emissions through three mechanisms: (1) publication of Control Tech-
niques Guidelines to be used by state and local air pollution control agencies
in developing and revising regulations for existing sources; (2) promulgation
of New Source Performance Standards according to Section lll(b) of the Clean
Air Act; and (3) promulgation, as appropriate, of National Emission Standards
for Hazardous Air Pollutants under Section 112 of the Clean Air Act. Most of
the effort was to center on the development of New Source Performance Stan-
dards .
One program in particular focused on the synthetic organic chemical manufactur-
ing industry (SOCMI), that is, the industry consisting of those facilities
primarily producing basic and intermediate organics from petroleum feedstock
meterials. The potentially broad program scope was reduced by concentrating on
the production of the nearly 400 higher volume, higher volatility chemicals
estimated to account for a great majority of overall industry emissions. EPA
anticipated developing generic regulations, applicable across chemical and
process lines, since it would be practically impossible to develop separate
regulations for 400 chemicals within a reasonable time frame.
To handle the considerable task of gathering, assembling, and analyzing data to
support standards for this diverse and complex industry, EPA solicited the
technical assistance of IT Enviroscience, Inc., of Knoxville, Tennessee (EPA
Contract No. 68-02-2577). IT Enviroscience was asked to investigate emissions
and emission controls for a wide range of important organic chemicals. Their
efforts focused on the four major chemical plant emission areas: process
vents, storage tanks, fugitive sources, and secondary sources (i.e., liquid,
solid, and aqueous waste treatment facilities that can emit VOC).
121G
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IX
B. REPORTS
To develop reasonable support for regulations, IT Enviroscience gathered data
on about 150 major chemicals and studied in-depth the manufacture of about
40 chemical products and product families. These chemicals were chosen consid-
ering their total VOC emissions from production, the potential toxicity of
emissions, and to encompass the significant unit processes and operations used
by the industry. From the in-depth studies and related investigations, IT
Enviroscience prepared 53 individual reports that were assembled into 10 vol-
umes. These ten volumes are listed below:
Volume 1
Volume 2
Volume 3
Volume 4
Volume 5
Volume 6-10
Study Summary
Process Sources
Storage, Fugitive, and Secondary Sources
Combustion Control Devices
Adsorption, Condensation, and Absorption Devices
Selected Processes
Volumes 4 and 5 are dedicated to the evaluation of control devices used as add-
on controls to reduce VOC emissions. These add-on controls are discussed general-
ly in Volumes 2 and 3 as emission control options for the control of VOC emis-
sions from generic sources. The use of these add-on controls in specific applica-
tions is demonstrated in the process studies covered in Volumes 6 through 10.
This volume covers the application of carbon adsorption, gas absorption, and
condensation as add-on VOC emission control devices. These reports discuss the
practical use of each control device, describe the systems, and discuss key
design considerations. Data, tables, and curves are presented to enable pre-
liminary cost and energy impacts to be determined for a wide range of potential
applications. These control device evaluation reports were used to develop the
cost effectiveness and energy impact determinations presented in the process
reports of Volumes 6 through 10. The focus of these reports is on control of
new sources rather than on existing sources in keeping with the main program
objective of developing new source performance standards for the industry. The
reports do not outline regulations and are not intended for that purpose, but
they do provide a data base for regulation development by the EPA.
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REPORT 1
CONTROL DEVICE EVALUATION
CARBON ADSORPTION
H. S. Basdekis
C. S. Parmele
IT Enviroscience
9041 Executive Park Drive
Knoxville, Tennessee 37923
Prepared for
Emission Standards and Engineering Division
Office of Air Quality Planning and Standards
ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park, North Carolina
January 1981
D122A
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CONTENTS OF REPORT 1
I. INTRODUCTION 1-1
II. CARBON ADSORPTION SYSTEMS AND FACTORS INFLUENCING PERFORMANCE II-l
AND DESIGN
A. Fixed-Bed Adsorption II-l
B. Alternative Carbon Adsorption Systems 11-22
III. CONSIDERATIONS FOR INSTALLING NEW CARBON ADSORPTION EQUIPMENT III-l
A. New Plants III-l
B. Existing Plants III-l
IV. COST AND ENERGY IMPACTS OF CARBON ADSORPTION IV-1
A. Base-Case Adsorber Design Summary IV-1
B. Cost Basis IV-1
C. Annual Costs IV-5
D. Cost and Energy Effectiveness IV-5
V. SUMMARY AND CONCLUSIONS V-l
VI. REFERENCES VI-1
APPENDIX OF REPORT 1
A. ANNUAL COST DATA A-l
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1-v
TABLES OF REPORT 1
Number
II-l Important Properties for Design of Adsorption System for II-6
Selected Organics
IV-1 Factors Used for Estimating Total Installed Costs IV-3
IV-2 Annual Cost Parameters IV-6
IV-3 Cost Effect of Varying Carbon Life and Steam Price IV-11
IV-4 Cost Effectiveness of Carbon Adsorption for Removal of VOC IV-12
IV-5 Energy Effectiveness of Carbon Adsorption for VOC Removal IV-14
IV-6 Change in Cost Effectiveness and Energy Effectiveness with IV-20
Increasing Regeneration Steam Usage
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1-vid
FIGURES OF REPORT 1
Number
1-1 Activated-Carbon Adsorption System 1-2
II-l Nomograph for Determining Carbon Requirement II-4
II-2 Bed Pressure Drop for BPL Carbon II-9
II-3 Loading Time for Various Carbon Requirements and Bed Depths at 11-10
100-fpm Velocity and a Carbon Density of 30 lb/ft3
II-4 Adsorbed-Phase Profile for Trichloroethene Service Time When 11-13
Vapor Starts to Penetrate Bed; BPL V Type Carbon
II-5 Adsorbed-Phase Profiles for Trichloroethane at Various Stages 11-13
of Regeneration; BPL V Type Carbon
II-6 Desorption Efficiency Based on Steam Usage 11-14
II-7 Effluent VOC Concentration Based on Steam Usage 11-16
II-8 Condenser Area Based on Steam Usage 11-19
II-9 Vacuum Regeneration System 11-21
11-10 Fluid-Bed Carbon Adsorption System 11-24
IV-1 Installed Capital Cost of Carbon Adsorption Systems IV-4
IV-2 Net Annual Cost vs Flow Rate for Carbon Adsorption at a Steam IV-7
Rate of 0.3 Ib of Steam/Ib of Carbon
IV-3 Net Annual Cost vs Flow Rate for Carbon Adsorption at a Steam IV-8
Rate of 0.6 Ib of Steam/Ib of Carbon
IV-4 Net Annual Cost vs Flow Rate for Carbon Adsorption at a Steam IV-9
Rate of 1 Ib of Steam/Ib of Carbon
IV-5 Net Annual Cost vs Flow Rate for Carbon Adsorption at a Steam IV-10
Rate of 2 Ib of Steam/lb of Carbon
IV-6 Cost Effectiveness vs Feed Rate at 1.393 and 6.96 Ib of IV-15
Carbon/1000 scf
IV-7 Cost Effectiveness vs Steam Regeneration Rates at 1000 scfm IV-16
IV-8 Cost Effectiveness vs Steam Regeneration Rates at 20,000 scfm IV-17
IV-9 Cost Effectiveness vs Steam Regeneration Rates at 100,000 scfm IV-18
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1-1
I. INTRODUCTION
Vapor-phase carbon adsorption is currently used by many industries as an
emission control or solvent recovery technique.1* As a control technique for
volatile organic compound (VOC) emissions it can be used on waste-gas streams
of low VOC concentration when such devices as condensers or scrubbers are
ineffective or uneconomical. The main function of a vapor-phase carbon adsorp-
tion system is to contain and concentrate the dilute organic vapors. Once
the organics are in a concentrated form, they can be recovered or disposed of.
Carbon adsorption is usually a batch operation involving two main steps,
adsorption and regeneration. The system usually includes multiple beds so
that at least one bed is adsorbing the organics from the gas stream while at
least one other bed is being regenerated, thereby ensuring that the emissions
will be continually controlled. The system shown in Fig. 1-1 is a typical
fixed-bed carbon adsorption system that uses steam to regenerate the spent
beds. A blower is usually required to overcome the pressure drop across the
carbon bed. The VOC-laden gas is passed down through the fixed carbon bed and
the cleaned gas is exhausted to the atmosphere. When the VOC concentration
of the exhausted gas starts to increase from its baseline effluent concentration
level, that bed is shut off and the VOC-laden gas is routed to another carbon
bed. The amount of material adsorbed per unit weight of carbon is called the
operating capacity.
The spent carbon bed is usually regenerated with low-pressure steam that is
passed up through the bed. The steam and VOC vapors leaving the bed are
condensed, and VOC is separated from the water by decantation or distillation.
After regeneration the carbon bed is cooled and dried to improve adsorption.
This report deals mainly with the design and cost of a fixed-bed adsorber with
steam regeneration. However, there are alternative designs for carbon adsorp-
tion systems, such as those making use of hot inert gas or vacuum regeneration
instead of steam regeneration and those employing fluidized instead of fixed
carbon beds. The alternative designs are briefly discussed in Sect. II.
*See Sect. VII for references cited in this report.
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1-2
EXHAUST
UOW- PRE
PROCESS
ro
-
VAPOR -1_ADEIO
AIR STREAM
--(XJ--
—cxj--
rt!y!^
p*»""i
i
•ex
-00-
IX-
COOUUG AK1O
DRY! MQ BUOWEP,
^COMDELMSEP.
COOLIKJ<5
AM61EUTT 4
RECOVEREO
WASTE.
VA/AJE.K
Fig. i-l. Activated-Carbon Adsorption System
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1-3
Carbon adsorption for control of VOC gas streams has several limitations.
The gas entering the adsorber must be free of particles or liquid; particles
in the feed gas would build up on the bed surface and cause an excessive
pressure drop across the adsorber. Liquid in the feed gas may cause excessive
temperature increases in the carbon bed due to heat of adsorption. Liquids
and solids may cause loss of efficiency by blocking adsorption sites. If the
feed gas contains particulates or liquid, it must be pretreated. Humidity
control will be necessary for feed gas streams that have above 50% relative
humidity so that the water vapors will not affect the adsorption capacity of
the carbon.
The inlet VOC concentrations may be limited to comply with insurance codes
requiring that the concentration be maintained below some percent of the lower
explosion limit (LEL) or to prevent the possibility of temperature increases
due to the heat of adsorption.
Since carbon is a very good insulator, undissipated heat may cause hot spots
to develop, and a condenser may have to be used to remove those VOC with high
boiling points. Dilution air may also be added to reduce the VOC concentration.
The adsorption and regeneration limitations of a carbon system prohibit the
effective control of many VOC by carbon adsorption. For example, very low
molecular weight VOC do not adsorb well on carbon and very high molecular
weight compounds are difficult to remove during regeneration.
The temperature of the feed-gas stream should be below 100°F. Lower temperatures
give higher operating capacities if the gas stream is dry. However, if moisture
is present, lower temperatures give higher relative humidities and these
higher humidities can decrease operating capacities. This decrease becomes
pronounced at relative humidities of over 50%. The optimum feed-gas temperature
must therefore be determined on a case-by-case basis.
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II-l
II. CARBON ADSORPTION SYSTEMS AND FACTORS INFLUENCING
PERFORMANCE AND DESIGN
In this section the main elements of a carbon adsorption system are discussed
and factors influencing system design and performance are analyzed. The analysis
is directed toward development of a design for a typical or base-case adsorption
system. It is this base-case system and variations of it that form the basis
for the cost estimation given in Sect. IV.
Fixed-bed adsorption with steam regeneration is the only system examined in
depth here. This system includes carbon beds, blowers, condenser, condensate
decanter, piping, valves, and instrumentation. For some carbon systems,
however, additional equipment may be required for pretreatment of the gas
stream or for additional treatment of the VOC recovered during regeneration.
These considerations are briefly discussed but design and cost details are not
presented. Fluid-bed adsorption systems are also mentioned but not analyzed.
A. FIXED-BED ADSORPTION
1. Pretreatment
A VOC emission stream may have to be treated before it can be sent to the
carbon adsorber. Stream conditions or contaminants that adversely affect
carbon adsorber performance are excessively high temperatures, high humidity,
entrained solids, entrained liquids, and high-boiling organics. The effect
and subsequent additional cost of these conditions or contaminants on a
particular carbon adsorption system must be dealt with for each individual
application. The various types of inlet-stream conditions or contaminants
that might be encountered are discussed and the steps that might be required to
deal with the situation are outlined.
a. Temperature The adsorption capacity of the carbon and the effluent concentration
of the adsorber are directly related to the temperature of the inlet stream to
the adsorber. Normally the temperature of the inlet stream should be below
100°F or else the adsorption capacity will be affected. Inlet-stream coolers
are normally required when the waste-gas temperatures are in excess of 100°F.
Water-cooled finned-tube types of heat exchangers are usually provided to cool
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II-2
the inlet stream. Costs associated with cooling the inlet stream depend on the
inlet temperature, flow rate, and temperature of the cooling water available.
b. Humidity Relative humidities greater than 50% can have a significant effect
on the operating capacity of carbon. The effect of relative humidity on the
system should be dealt with for each individual application, but systems in
which the relative humidity approaches 100% will require additional equipment
to reduce the water content. The equipment required for humidity control is
usually a series of coolers (to remove water) and reheaters. However, a single
heater could be used if the temperature of the inlet stream is significantly
low, and the increase in temperature will not greatly affect adsorption efficiency.
Another alternative to decrease the relative humidity of a stream is to add
dilution air to the system. This method will work if the dilution-air humidity
is significantly less than the inlet stream humidity. Adding dilution air will
increase the size and thus the cost of the adsorber required. The installed
cost of humidity control by a series of heaters and coolers or a single heater
will be $l/cfm to $2/cfm for a 5000-scfm carbon adsorption unit.
c- Entrained Solids Entrained solids such as airborne dust, lint, and other
general particulates may cause the carbon bed to plug over a period of time.
The particulates that could affect adsorption performance are usually controlled
by a cloth or fiberglass filter. Depending on the application, either a simple
throw-away filter or a fabric filter can be used. A throw-away type of filter
costs in the range of $100/1000 cfm. Information on fabric filters can be
found in ref 2, and cost data can be found in ref 3. Electrostatic precipitators
are not usually reocmmended for pretreatment of carbon adsorption inlet streams,
because there is a possible safety problem of electric arc in the duct with
organic vapors in the explosive range. Normally the inlet stream concentration
to the adsorption unit is less than 25% of the LEL but upsets could cause the
concentration to rise into the LEL range.
d- Entrained Liquids Entrained liquids can cause operational problems for carbon
adsorption. If the entrained liquid is water, it should be removed for the
same reason discussed for relatively humidity. If the entrained liquid is a
volatile organic, it will also consume adsorption capacity needlessly. A
number of mist eliminators are available, and one should be used if this problem
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II-3
exists. For droplets greater than 5 to 10 pm in diameter a cyclone or zigzag
baffle can be used, which, if properly designed, will result in efficiencies of
greater than 95%. To control droplets in the 1- to 5-(jm range a small-mesh screen
would be required. For droplets less than I \Jm a packed filter device would be
necessary. A packed filter device has a high pressure drop (15 to 20 in. H20)
compared to the pressure drop (less than 1 in. H20) across the cyclone or
zigzag baffle or the screen. For further information on mist eliminators refer
to ref 4. The cost of a mesh-type mist eliminator is in the range of $150/1000 cfm.
e. High Boilers A high percentage of high boilers in the off-gas feed stream
will be adsorbed on the carbon and will not be removed during steam regeneration.
This constant buildup of high boilers remaining on the carbon will greatly
reduce the operating capacity and will require frequent replacement of the
carbon. Also, plasticizers or resins should be prevented from entering the
carbon bed since they may react chemically on the carbon to form a solid that
cannot be removed from the bed during steaming. To prevent frequent replacement
of the carbon a condenser may be necessary to reduce the high-boiler concentration.
If the high boilers are in the form of entrained liquids, such as oil droplets,
a mist eliminator will reduce the buildup. If the high boilers cannot be
removed from the inlet stream to the adsorber, a carbon guard bed in the adsorber
may result in less carbon being replaced periodically. The guard bed would be
considered as a sacrificial device and would be replaced more often than the
entire bed.
2. Adsorption
Defining the VOC content and the operating capacity as explained below will
reduce the number of variables required to cover the necessary range of flows,
concentrations, and VOC molecular weights and will simplify the presentation of
cost and environmental impacts.
a. VOC Content In this study the VOC content of the gas to be treated is defined
in the units of Ib of VOC/1000 scf. The conversion from ppm (volume) can be
made by using the first part of Fig. II-l or by the following relationship:
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10r
II-4
OPERATING CAPACITY:
Ib of VOC
10,OOO - .01
.001
a
a
-1OOO
O
o
o
o
o
100
10
.01 O.1 1-0
VOC CONTENT (ib of VOC/1OOO scf)
Fig. II-l. Nomograph for Determining Carbon Requirement
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II-5
Ib of VOC/1000 scf = PP"V * VOC molecular weight (Ib/lb-mole)
359 X 1000
b. Operating Capacity The determination of the actual operating capacity (also
commonly referred to as working capacity) of carbon is considered to be beyond
the scope of this study, since it is affected by a multitude of factors. These
factors include the properties of the carbon, the properties of the feed stream,
such as humidity and multiple components, and the percent of containment that
must be removed. Consideration of the theoretical aspects can be found in the
literature.5—12 For the purpose of this study it is assumed that for a particular
VOC feed stream the operating capacity can be determined from operating industrial
units, carbon manufacturers, carbon equipment vendors, or pilot-plant studies.
Pilot tests should be continued through enough cycles to determine the residual
constant VOC. It is important that the operating capacity used includes all
the factors that occur in actual practice and for each specific case that the
operating capacity is considered to be less than the saturated adsorption
capacity that may be reported. (Some reported operating capacities are shown
in Table II-l.)
c. Carbon Requirement Carbon requirement in this study is defined as Ib of
carbon/1000 scf and is a function of the VOC content of the gas to be treated
and the operating capacity of the carbon:
Ib of carbon _ VOC content (Ib of VOC/1000 scf) X 100
Carbon requirement 1000 scf - operating capacity (Ib of VOC/100 Ib carbon) '
Figure II-l is a nomograph for determining the carbon requirement for systems
with a variety of VOC concentrations, molecular weights, and operating capacities.
Systems with high VOC operating capacities per Ib of carbon and high concentrations
of VOC in the process waste gas can have the same carbon requirement as systems
with low VOC operating capacities per Ib of carbon and low concentrations of
VOC in the waste gas.
In this study costs were determined for nine different carbon requirements,
ranging from 0.1 to 10.0 Ib of carbon/1000 scf.
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II-6
Table II-l. Important Properties for Design of
Adsorption System for Selected Organics
Compound
Benzene
Butyl acetate
n-Butyl alcohol
Cyclohexane
Ethyl acetate
Ethyl alcohol
Heptane
Hexane
Isopropyl acetate
Methyl acetate
Methyl alcohol
Toluene
Trichlorotrifluoroethane
Xylene
Boiling
Point
(°P)
176
260
210
178
171
173
208
154
199
135
149
231
118
291
Liquid
Molar
Volume3
(cm^/mole)
95
152
105
118
106
61
163
140
129
83
42
118
120
140
Lower
Explosion
Limit3
(ppm)
14,000
14,000
17,000
13,000
25,000
33,000
12,000
13,000
18,000
31,000
60,000
14,000
10,000
Reported .
Operating Capaicity
(lb/100 Ib of carbon)
6
8
8
6
8
8
6
6
8
7
7
7
8
10
See ref 7.
See ref 12. Capacities are for relatively dry compounds (or simple mixtures of compounds)
that are particulate-free at 100°F. The effluent concentration achievable with these
capacities is not reported.
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II-7
d. Flow Rate (of Gas To Be Treated) In this study base-case costs were determined
for six different flow rates, ranging from 300 to 100,000 scfm.
e.
Temperature The feed-gas temperature is assumed to be 100°F for the base
case. Carbon adsorption units operate most effectively in the temperature
range of 60 to 130°F. Most current carbon adsorption units are operated at 75
to 100°F/ with a few units being operated at 60°F and a few as high as 200°F.
Increase or decrease of temperature within the range of 90 to 110°F will have
little effect on adsorption.
f. Gas Velocity (Superficial) Linear velocities of 50 to 100 fpm are normally
used in bed designs. At higher velocities the bed pressure drop becomes too
high for standard blowers. At lower velocities the bed becomes too large and
expensive. If inlet concentrations are low (as is expected in the SOCMI industry),
the bed area required for the volume of carbon needed usually permits a velocity
at the high end of this range. Therefore a superficial velocity of 100 fpm is
used in the base case.
g. Bed Depth Fixed-bed carbon adsorption systems normally have bed depths of 1.5
to 3 ft, although under certain conditions the depth may be as small as a few
inches. The minimum bed depth of 1.5 ft is assigned for the adsorption zone.
The maximum bed depth of 3 ft is considered to be reasonable with regard to the
pressure developed by standard blowers.
The difference in capital cost between a 1.5-ft-deep bed and a 3-ft-deep bed
arises from the cost of the additional carbon and the larger-pressure-drop
blower. The carbon bed containers are usually large enough for the extra
1.5 ft to be added to the bed at minimal cost, and therefore there is little
capital cost difference between the 1.5-ft bed and the 3.0-ft bed. Since the
incremental cost of adding more carbon to a large vessel is more than offset by
the added flexibility that a longer adsorption cycle gives, a bed depth of 3 ft
is used in the base case.
h. Pressure Drop The pressure of the feed gas will affect the design of the
system in terms of the power requirements of the blower. A pressure drop of
2.5 to 10 in. H20/ft of carbon bed is normally experienced with a flow velocity
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1.
II-8
of 50 to 100 fpm through the carbon bed. If the feed-gas pressure is high
enough to permit a reasonable superficial velocity, then no blower is required.
The base-case system is assumed to require a blower to develop the necessary
pressure.
The base-case adsorber uses 4 X 10 mesh BPL carbon, which at the base case
velocity of 100 fpm has a pressure drop of 6.5 in. H20/ft of carbon bed. With
the base-case bed depth of 3 ft the total pressure drop is 19.5 in. H20. (Bed
pressure drop vs superficial velocity for two different BPL carbons is shown in
Fig. II-2.) This differential pressure can be developed efficiently by standard
blowers.
Loading Time (per Bed) Loading time is calculated from bed depth, carbon
density, gas velocity (superficial), and carbon requirement:
loading time (hr) =
. bed depth (ft) X density (lb/ft3) X 1000
velocity (fpm) X 60 (min/hr) X carbon required (lb/1000 ft3)
Figure II-3 shows the loading time for various carbon requirements and bed
depths for a bed with a carbon density of 30 lb/ft3 and a superficial gas
velocity of 100 fpm.
j- Bed Area and Pounds of Carbon (per Bed) The bed area (per bed) is calculated
by dividing the flow rate (scfm) by the superficial gas velocity through the
bed (for the base-case, 100 fpm). The pounds of carbon (per bed) are most
conveniently determined by calculating the bed volume and multiplying by the
bed density. In the base case the bed depth is 3 ft and the bed density is
30 lb/ft3:
bed area (ft2) = flow rate (acfm)/gas velocity (ppm).
carbon (Ib) = bed area (ft2) X bed depth (ft) X bed density (lb/ft3).
k- Minimum Cycle Time The minimum cycle time for the system is normally dependent
on the time required to regenerate, dry, and cool the bed. Steam regeneration
rates are typically 0.5 to 1 (Ib of steam/min)/ft2 but can be as high as 4 (Ib
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II-9
a.
O
cc
O
Ul
cc
D
V)
ai
£C
o.
15 2O 30 40 50
SUPERFICIAL VELOCITY
60 70 80 9O 1OO
Fig. 11-2. Bed Pressure Drop for BPL Carbon
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3 f-
Q.
Ill
Q
O
LU
CD
2 —
Minimum —>
Bed Depth
LOADING TIME (hr)
i i i i i i i
.02
0.1 1.0 10
CARBON REQUIREMENT (ib of carbon/1000 set)
20
i
H
O
Fig. II-3. Loading Time for Various Carbon Requirements and Bed Depths at
100-fpm Velocity and a Carbon Density of 30
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11-11
of steam/min)/ft2. These rates correspond to regeneration times of 30 to
90 min at steam regeneration ratios of 0.3 or 1 Ib of steam/lb of carbon.
Cooling and drying the beds can normally be done in 15 min. The minimum possible
time for regeneration, drying, and cooling used in this study is 1 hr. Since
the bed is loaded for the same period of time, the total minimum cycle for one
bed takes 2 hr. Since two beds are usually employed, each carbon bed must have
enough adsorption capacity to allow sufficient time for the other bed to be
regenerated, dried, cooled, and placed back in adsorption service before break-
through .
1. Bed Configuration In the base case for carbon systems handling flows below
10,000 scfm two vertical tanks are used so that one bed can be regenerated
while the other bed is adsorbing the VOC from the off-gas stream. For flows
above 10,000 scfm vertical tanks would have diameters greater than 12 ft, which
is above transportation limits; therefore horizontal tanks are required. For
flows above 20,000 scfm three or more tanks are used in order to reduce capital
cost by reducing the tank size and reducing carbon inventory. When three beds
are used, one will be regenerating while the other two are adsorbing with
parallel waste-gas flow. A sequence procedure must be established to prevent
two tanks from being ready for regeneration at the same time.
3. Regeneration
a. Steam Requirements Regeneration of a carbon bed saturated with VOC is most
often accomplished by the use of steam. In regenerating a bed a certain amount
of steam is required to heat the carbon bed from its operating temperature to
the regeneration temperature and to provide the heat of desorption. However,
most of the steam flow is needed to provide a sufficient concentration gradient
to promote mass transfer of the adsorbate from the carbon bed. Even with
extensive steam regeneration some VOC will be left on the bed. The adsorbate
left on the carbon (the heel) after regeneration accounts for most of the
difference between the saturated adsorption capacity and the operating capacity.
For a given compound-carbon combination the amount of heel is determined by the
amount of steam used during the regeneration cycle.
-------
11-12
Figures II-4 and II-5 illustrate the effect of regeneration on the concentration
of the adsorbate left on the carbon. Figure II-4 is the adsorption profile of
a single compound just before a breakthrough occurs on the bed. This is the
usual or desired status of the system just before regeneration. Figure II-5
shows the progression of the desorption profiles with increasingly larger
amounts of steam passing through the bed. Profiles 1 and 2 are achieved with
relatively small amounts of steam; profiles 3, 4, and 5 are the results of
increasingly larger amounts of steam.8
Figure II-6 shows the effect that varying the steam regeneration ratio (Ib of
steam per Ib of carbon) will have on the desorption efficiency. The S-shaped
curve in Fig. II-613 indicates that a large amount of steam is required to
achieve nearly 100% desorption efficiency (minimum heel) but that a relatively
smaller amount is required to achieve 90% desorption efficiency (10% plus
minimum heel left). If the designer is not limited by the effluent VOC concen-
tration required, he has a choice of how much heel to leave on the bed. Based
on Fig. II-6 an adsorption designer might choose between 0.25 and 0.35 Ib of
steam/lb of carbon as the preferred design condition, which will provide the
greatest amount of operating capacity for the amount of steam used.
The desorption efficiency curve in Fig. II-6 is a function of the compound(s)
adsorbed on the carbon, of the operating capacity of the adsorbent, and of the
temperature and pressure of the regeneration steam. It may also be a weak
function of steam regeneration rate [(Ib of steam/min)/ft2], but there are very
little data in this area. A strongly adsorbed compound would have a curve
skewed more to the right, since more steam would be required to remove it. A
compound with a high loading capacity may require more steam per pound of
carbon to account for the extra heat needed for the heats of desorption and the
greater amount of material to be desorbed. Higher temperature regeneration
steam may decrease the amount of steam required per pound of VOC removed (steam
regeneration ratio) and may increase the amount of material desorbed. The net
effect is that the curve will be skewed to the left and the heel remaining on
the carbon will be less. The steam regeneration ratio may have an effect on
the shape of the curve but will be most important when determining cycle times.
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11-15
Figure II-7 shows a generalized relationship between the amount of steam used
for regeneration and the outlet VOC concentration during the next adsorption
cycle. The exact relationship will depend on the type of VOC being removed and
the operating characteristics of the system. In accordance with state-of-the-art
carbon adsorption systems for solvent recovery, the outlet concentrations are
usually in the range of 50 to 100 ppmv-6 This level may correspond to a steam
regeneration ratio of 0.3 Ib of steam/lb of carbon, the ratio normally required
for solvent recovery adsorption systems. The lower achievable effluent concentra-
tion levels are in the range of 10 to 20 ppmv,14 which would correspond to a
higher steam ratio. However, for some compounds effluent levels are achievable
below 1 ppm . Figure II-7 shows that reduced effluent concentration is obtained
by increasing the steam ratio and that very low effluent concentration levels
may be obtained with high steam ratios. Figure II-7 is not meant to correspond
to any one particular compound or adsorption condition but is used to illustrate
a general trend. It shows that the position of the effluent concentration
curve for each particular compound is a function of the adsorption temperature,
regeneration temperature, and carbon operating capacity. The effluent concentration
curve is relatively independent of inlet VOC concentrations. When the adsorp-
tion temperature increases, the effluent outlet concentration curve baseline
may increase. Higher regeneration temperatures may shift the effluent outlet
concentration curve downward. A different operating capacity may shift the curve
laterally, since different amounts of steam may be required to regenerate the
carbon. Data in this area are not readily available but could be generated in
pilot-plant studies.
The achievable effluent quality values assumed for the purpose of evaluating
adsorption systems in this study are the following: 0.3 Ib of steam/lb of
carbon will achieve an effluent quality of 70 ppmv, and 1.0 Ib of steam/lb of
carobn will achieve an effluent quality of 12 ppny Although these values may
not be realized for all VOC compounds, they are appropriate for those compounds
that are normally controlled by carbon adsorption.
b. Blower—For the base-case carbon adsorption system a blower is used following
regeneration to provide drying and cooling air to sweep some VOC from the
regenerated bed. To achieve the highest possible removal efficiency, regenera-
tion should be started before an unacceptably effluent concentration occurs and
-------
11-16
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13
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adsorption temperature, and
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012
STEAM USAGE (Ib of steam / Ib of carbon )
Fig. II-7. Effluent VOC Concentration Based on Steam Usage.
(Not for Any Actual Compound)
-------
11-17
the drying and cooling air should be sent to the adsorbing bed. Routing the
drying and cooling air through the adsorbing bed requires a larger pressure
drop for the drying and cooling air blower and main blower, additional valves
and controls, and a slightly larger carbon bed. When additional air enters the
adsorbing bed, no additional carbon capacity will be required since the concentra-
tion is low; however, a slightly larger cross-sectional area will be required
because of the increased flow rate. This practice of routing the drying and
cooling gas may not be practical for all cases since additional water will be
brought into the adsorbing bed, which may affect the operating capacity of the
carbon and cause operational problems.
The flow rate of the drying and cooling air blower is assumed to be about 30%
of the off-gas flow rate. The pressure drop for the blower will be the total
of the pressure drop for the regeneration bed and adsorbing bed, since the air
is routed through both beds. For pressure-drop calculations it is assumed that
4 X 10 mesh carbon is used, that the bed depth is 3 ft, and that the superficial
gas velicty is 100 fpm for the total cooling air and gas flow. The drying and
cooling time is 15 min per cycle.
Condenser—All the steam required to regenerate the carbon has to be condensed
and cooled to 100°F. Some of the heat will stay with the bed and be removed by
the drying and cooling air, but most of it has to be removed by the condenser.
The reduction in heat duty for the condenser is not significant; so the heat
duty for the condenser is based on the amount of steam required to regenerate
the bed. For the base-case design it is assumed that the steam will be used
during 75% of the regeneration time; therefore the condenser will have to be
sized to handle instantaneous heat duty, which is 33% more than the average
steam consumption.
For the base-case design, atmospheric steam at 212°F and 970 Btu/lb of heat of
vaporization was used. The condenser was designed to condensate the steam and
VOC, cool the condensate mixture to 100°F, and raise the cooling water from
85°F to 120°F.
The overall heat transfer coefficient for the condenser was assumed to be 150
Btu/(hr)(ft2)(°F) (ref 15). The area of the condenser per pound of carbon as
-------
11-18
shown in Fig. II-8 was based on various steam requirements and on a log-mean
(or conservative) At of 42.4°F.
Although a decanter to separate the organic from the water is included in the
battery limits of the carbon adsorption system, no additional equipment is
included to separate water-soluble organics. Some separation option must be
considered when large quantities of organics enter the condensate since most
local authorities will not allow such water to be discharged into municipal
sewage treatment systems. A complex distillation system may be required to
fractionate the mixture into separate components, or a simple system can be
designed to merely strip out the organics.
Other options for separation of the water-soluble compounds from the condensate
include liquid extraction or liquid-phase carbon adsorption with solvent regenera-
tion.
d- Alternatives to Steam Regeneration Hot inert-gas regeneration and vacuum
regeneration can be used as alternatives to steam regeneration. With the first
method, after hot gas is used to regenerate the carbon bed, the VOC-laden gas
can be incinerated. Another method is to recirculate the inert gas through a
preheater, into the adsorber, and through a condenser. Each pass through the
bed with the hot inert gas will pick up additional VOC of higher molecular
weights. Removal from the adsorber and condensation of the VOC will continue
until an equilibrium is reached between the bed, the hot inert gas, and the
condenser. Higher gas temperatures or lower condenser temperatures will
improve the recovery efficiency of the system.
In the second method, which involves indirect heating and a vacuum applied to
the carbon bed, the boiling points of the VOC will be lowered and the VOC will
be more easily removed from the bed. The vacuum regeneration cycle begins with
the bed being heated with recirculating heated air or inert gas. Auxiliary
heating coils within the bed are sometimes used. When the bed reaches the
specified temperature, a vacuum pump then reduces the pressure in the bed to
about 0.2 in. H20. The high boilers thereby removed are condensed with a
chilled-water condenser, and the low-boiling VOC are condensed with a Freon-
cooled condenser (-40°C). After the desorption step is complete, the bed is
-------
11-19
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of 33% more than the average
rate was used to calculate the
condenser area.
1 2 3
STEAM USAGE ( Ib of steam / Ib of carbon)
Fig. II-8. Condenser Area Based on Steam Usage
-------
11-20
restored to atmospheric pressure and is cooled by recirculating air. A flow
diagram of a vacuum regeneration system is shown in Fig. II-9.
The advantages of vacuum regeneration with indirect heating are that some
high-boiling-point VOC can be recovered without the use of superheated steam.
Also, since the desorbed VOC that are recovered are mostly free of water,
distillation may not be needed for separation of the water-soluble organics.
Efficiency and effluent concentration data for vacuum regeneration are limited.
Commercial vacuum units used for solvent recovery with high solvent concentration
have reported efficiencies of 90 to 99%, depending on the specific hydrocarbon
adsorbed and the regeneration conditions used.16
High boilers in the off-gas feed stream will be adsorbed on the carbon and will
not be removed during steam regeneration. This constant buildup of high boilers
in the heel will greatly reduce the operating capacity and require frequent
replacement of the carbon. Disposable carbon beds preceding the regular carbon
beds may be required to reduce the high-boiler content of the process off-gas
and thereby reduce the carbon replacement frequency of the main beds.
Achieving High Carbon Adsorption Efficiencies
High removal efficiencies require the close control of influent gas quality.
Performance can be impaired by particulates or a high water content in the inlet
stream or by high temperature in the inlet stream. "Unexpected" compounds
(those for which the adsorber was not designed) may pass through the carbon bed
without being removed or may accumulate in the bed and reduce the operating
capacity.
Prevention of premature breakthrough (unacceptable effluent concentration)
requires a favorable balance between the adsorption capacity dictated by the
mass flow rate of VOC and the speed and effectiveness with which the adsorber
can be desorbed, cooled, and dried.
To avert the discharge of VOC from a hot, wet adsorber, piping must be arranged
so that the adsorber can be dried and cooled and the drying cooling gas recycled
to an on-line adsorber. There must be sufficient time in the total adsorption
cycle for the bed to be dried and cooled.
-------
11-21
Fig. II-9. Vacuvim Regeneration System
-------
11-22
5. Safety Considerations
Spontaneous combustion of fixed beds of carbon can occur whenever the gas
stream contains oxygen and compounds easily oxidized in the presence of carbon,
such as ketones, aldehydes, and/or organic acids. Heat generated by adsorption
or by oxidation of VOC in the bed is usually transported from the bed by convec-
tion. If less convection heat is removed than is generated, the bed temperature
will rise. Higher temperatures will further increase the oxidation decomposition,
and hot spots exceeding the autoignition temperature of the carbon may develop
in the bed. The hot spots will develop in a shorter time and the condition
will be aggravated if a limited amount of steam is accidentally admitted to the
bed from a leak or from a valve being opened at the wrong time. A number of
bed fires have occurred after the adsorber was shut down for a long period and
then not regenerated sufficiently. When the VOC-laden stream was reintroduced,
bed combustion occurred. Hot spots may also form rapidly under abnormal bed
conditions, such as uneven bed depth due to carbon movement and stagnant bed
areas.14 When ketones, aldehydes, or organic acids are involved in the opera-
tion of a bed, safety precautions are especially important.
When the bed is adsorbing ketones, it should not be dried completely after
regeneration, because the water present provides a heat sink to dissipate the
heat of adsorption and oxidation. Bed fires are much more likely when the bed
is permitted to dry. To ensure safe operation with ketones it is necessary to
have an on-line monitoring of CO and C02 concentrations in the effluent stream.
At shutdown the bed should be regenerated and cooled before it is left idle.
The valves should be routinely inspected to ensure against steam leaks. Also,
the exclusion of oxygen from the bed will help to control hot spots. This
discussion does not imply that safe operation is impossible,- on the contrary,
there are several examples of ketones having been successfully recovered via
carbon adsorption. It does mean, however, that there are potential hazards
that should be considered.14
B. ALTERNATIVE CARBON ADSORPTION SYSTEMS
1. Fluidized-Bed Carbon Adsorption
Currently a fluidized-bed carbon adsorption process is commerically available
from Union Carbide Corporation, who licensed the process from a Japanese company.
-------
11-23
The carbon particles are designed to have a high attrition resistance so that
they can withstand the abrasive action in the fluidized bed. The carbon particles
are manufactured from shaped molten petroleum pitch. Being thermoplastic in
nature, the material is formed into microspherical particles by its own surface
tension. The particles are then carbonized and activated by steam. Because
they are formed from molten material, they are almost spherical and their
structure is homogeneous and strong.17
Figure 11-10 is a basic flow sheet for the fluidized-bed carbon adsorption
system. The system consists of a multistage countercurrent fluidized-bed
adsorption section, a pressure-sealing section, a moving-bed desorption system,
and another sealing section with carbon recycle. The regenerated carbon is
swept by carrier gas from the bottom to the top of the column. In the adsorp-
tion section the carbon is fluidized and moves across perforated plates and
down the column by a system of overflow weirs. The adsorption section design
allows the carbon to contact the gas homogeneously, resulting in high mass-transfer
efficiency. The pressure drop per stage normally ranges from 0.4 to 0.9 in.
H20, with six to eight stages required, depending on the application. The gas
velocity through the adsorption section is as high as 200 fpm, which is 2 to 4
times that required for fixed beds. This high gas velocity allows the cross-
sectional area of the bed to be smaller, with the pressure drop across the
entire bed being 2.4 to 7.2 in. H20.17
The regeneration section is a dense-phase gravity-flow bed with indirect heating.
The VOC are removed from the bed by an inert-gas regeneration fluid being
passed through the bed or by only direct steaming of the bed. The desorption
temperature is normally around 250°F but can be raised to 500°F to remove
high-boiling-point materials. By using a continuous system of regeneration no
heat is lost due to the bed being cycled; so the heating requirements are
reported to be less than those for fixed-bed adsorption systems.15
For the solvent recovery systems in commercial operation the treated gas effluent
concentration is typically around 50 ppm of VOC. Effluent concentration data
show that outlet levels of 10 ppm have been achieved for some applications.15
-------
11-24
TREATED AIR TO VEVJT
AD6CRSEWT FLOW
TRAY
GA5 UFT LI WE
RE
-------
11-25
2. Activated-Carbon Fiber Systems
Currently a fixed-bed carbon adsorption system that uses a fibrous activated
carbon instead of granular activated carbon is commerically available. Toyobo
New York, Inc., is involved in marketing the carbon adsorption equipment in the
United States. Their technology was developed and is currently being used in
Japan. The fibrous carbon can be supplied in various forms, such as mats,
corrugated paper, or honeycombs. The advantages of the fibrous carbon, as
stated by Toyobo, over granular activated carbon are a greater apparent surface
area, shorter adsorption paths, greater adsorption capacity, and lower pressure
drops. The reason given for these advantages is that the fibrous carbon has a
more uniform pore distributed with an average diameter in the range of 20 A .
The fibrous carbon can be used for such applications as recovery of solvents,
pollution control, and gas masks.
3. Rotary Carbon Adsorption Systems
Cargo Caire Engineering Corporation is currently developing a rotary carbon
adsorption system, which is designed to function as a concentrator of low-con-
centration high-flow VOC emissions. The system operates by passing a high
volume of low-concentration VOC stream through the carbon rotors. The carbon
rotor slowly turns into a regeneration section, where hot gas is passed through
the carbon rotor to desorb the organic. This lower volume regeneration gas
then can be sent to a smaller volume incinerator or fixed-bed adsorber.
-------
III-l
III. CONSIDERATIONS FOR INSTALLING CARBON ADSORPTION EQUIPMENT
A. NEW PLANTS
Carbon adsorption systems are not normally placed in a building for protection
from the elements of weather but are usually placed outside, near the process
vents. The units are usually put on foundations on the ground, but can be
elevated to accommodate other processing requirements. There should be enough
room around the units to allow for the replacement of the carbon when necessary.
Utilities must be supplied to the carbon adsorption site. Electricity is
needed for the blower motors, timers, relays, and recording equipment. Steam
is required at a specified pressure and flow rate. The steam requirements are
not continuous since steam is used for only part of the regeneration period.
The steam should not contain any material that will affect the adsorption
quality of the carbon or affect the recoverability of the organic. Cooling
water is required for condensing and cooling of steam and organic. The temp-
erature of the water must be low enough for the organic to be condensed, which
may require the use of two condensers. The valves for the carbon adsorption
unit are often automatic and require instrument air. Since adsorption units
are usually located outside, the instrument air must be dry to prevent condensa-
tion and freezing of water. After the condensed steam has been separated form
the organics, it may have to go to a wastewater treatment facility. The waste
load on the wastewater treatment facility will depend on the steam flow rate
and the amount of organics carried along with the condensed steam.
Carbon adsorption units are normally located in an area where solvent is used
and follow the building safety codes required for solvent use applications; no
additional safety precautions are normally necessary.
B. EXISTING PLANTS
All considerations for a new plant discussed here also apply to retrofitting
carbon adsorption units in an existing plant. However, installation costs may
be substantially higher since utility distribution systems and load capacities
may not be adequate to accommodate the adsorption unit. If an additional steam
boiler is required, it may be better to use hot inert-gas regeneration or
-------
III-2
vacuum regeneration. The cost and cost-effectiveness data presented in this
report are not intended to apply to retrofitted carbon adsorption systems. In
retrofitted systems additional costs may be encountered because of such items
as demolition requirements, crowded construction working conditions, construction
activities scheduled with production activities, and longer interconnecting
piping. These factors are site-specific and no attempt has been made to provide
costs. For specific retrofit cases rough costs may be obtained by using the
new-site data and adding as required for a specific retrofit situation.
-------
IV-1
IV. COST AND ENERGY IMPACTS OF CARBON ADSORPTION
A. BASE-CASE ADSORBER DESIGN SUMMARY
Results are given here of the cost and energy-effectiveness calculations for
the typical or base-case carbon adsorption systems discussed in the previous
section. Operating costs have been calculated for the combinations of variables
listed below and are itemized in the computer printouts attached to Appendix A.
The variables are based on standard conditions at 32°F.
Steam costs (per million Btu): $2.50, $5.00, $10.00; carbon requirement (Ib
of carbon/1000 scf): 0.10, 0.50, 1.00, 1.39, 2.00, 5.00, 6.96, 8.00, 10.00;
steam regeneration ratio (Ib of steam/lb of carbon): 0.3, 0.6, 1.0, 2.0;
credit: Five different recovery credits are costed. The amount of credit
depends on the pound of VOC recovered from each 1000 scf of off-gas and the
dollar value assigned to each pound and is expressed as $/1000 scf. The pounds
of VOC recovered are approximately equal to the VOC content into the adsorber
less the VOC content out of the adsorber (if the recovered VOC is insoluble in
water). The conversion from ppm to VOC content can be done conveniently with
the use of Fig. II-l. The method of calculating the credit value is shown in
the annual cost sample calculation in Appendix A. Off-gas flow (scfm): 300,
1,000, 5,000, 20,000, 50,000, 100,000. The fixed factors are as follows:
temperature, 100°F; gas velocity (superficial), 100 fpm; bed depth, 3 ft;
pressure drop, 6.5 in. H20/ft; carbon, 4 X 16 mesh BPL carbon, 30 lb/ft3; bed
configuration, see Sect. 1.7.A.2.1; all capital and operating costs other than
steam cost.
B. COST BASIS
The estimated capital costs for the carbon adsorption systems presented in this
section represent the total investment required for purchase and installation
of all equipment and material to provide a facility as described in Sect. II.
Included are all indirect costs such as engineering and contractors' fees and
overheads. These are battery-limits costs and do not include provision for
bringing utilities, services, or roads to the site, backup facilities, land,
research and development required, or process piping and instrumentation inter-
connections that may be required within the process generating the waste-gas
feed to the carbon adsorption system.
-------
IV-2
The method used to develop these estimated capital costs was based on applying
factors to the purchase prices of equipment to arrive at an installed capital
cost. The major portion of equipment and material costs was obtained from
Richardson Rapid Construction Cost Estimating System, 1978—1980 edition.
Ductwork purchase costs were obtained from Capital and Operating Costs of
Selected Air Pollution Control Systems by M. L. Kinkley and R. B. Neveril of
Gard, Inc. (EPA Report No. 450/3-76-014). Table IV-1 gives the factor ranges
used for factoring up the purchased price of equipment to the installed cost
and is based on historical data of IT Enviroscience. The expected accuracy of
the total installed cost with this degree of engineering detail using this
factor method is in the range of ±30%. This method of obtaining total installed
capital costs is suitable for study or screening estimates.
For carbon adsorption systems a 20% allowance was added to the major equipment
purchase cost to compensate for unspecified items. Adding 20% allowance to the;
estimated major equipment cost yielded the estimated equipment purchase cost (A).
This established the basis for the application of all installed capital cost
factors shown in Table IV-1.
The installation costs accounting for foundations, structures, equipment erection,
piping, insulation, paint, fire protection, and instruments were made approximately
2.1 to 2.3 times the total equipment purchase cost to arrive at the base cost (B).
Additional percentages were then applied to the base case as shown in Table IV--1
(sales tax, freight, contractor's fees, engineering, contingencies) to arrive
at a total installed cost. The initial carbon charge based on Sl.OO/lb was
added to this total to give a total battery-limit installed cost. The overall
ratio of total installed cost to major equipment purchase (excluding the 20%
allowance for unspecified items) is 3.8 for vertical package units and 4.3 for
the larger horizontal systems.
Capital costs of carbon adsorption systems are shown in Fig. IV-1. The curves
represent the total estimated capital cost based on a carbon adsorption system
with a superficial velocity of 100 fpm and a pressure drop of 6.5 in. H20/ft of
carbon bed at carbon bed depths of 1.5 and 3 ft. The basic pieces of equipment
as shown in Fig. 1-1 are carbon adsorption vessels, process-waste-gas and
ambient-air blowers, condenser, and decanter. Also included are the purchase
-------
IV-3
Table IV-1. Factors Used for Estimating Total Installed Costs
Major Equipment Purchase
Installation Costs
Foundations
Structures
Equipment Erection
Piping
Insulation
Paint
Fire Protection
Instruments
Electrical
Cost Plus 0.1 to 0.35 Allowance
0.06A + $100 X number of pumps
0.15A (no structures) to 0.30A (multideck structures)
0.15A to 0.30A (depending on complexity)
0.40A (package units) to 1.10A (rat's nest)
0.06A or 0.15 X piping (normal) to 0.30 X piping
(bulk hot or cold)
0.05A
0.01A to 0.06A (depending on requirements)
0.10A to 0.30A or 0.01A to 0.25A + $50,000 to
$300,000 for process control computer
0.15A or 0.05A + $500 per motor
Base Cost
Sales Tax
Freight
Contractor's Fees
.^————————-^———
C = Total Contract
a
Engineering
. b
Contingencies
A + Sum of Installation Costs
0.025A + 0.025B
0.16A
0.30 (B-A)
B + Taxes, Freight, and Fees
0.01C to 0.20C
0.15C
D = Process Unit Installed Cost C + Engineering + Contingencies
E = Total Subestimates
Sum of semidetailed subestimates (buildings, site
development, cooling towers, etc.). Each subesti-
mate should include taxes, freight, fees, engi-
neering and contingency, and should be escalated
to date of expenditure for that cost component.
Engineering costs, contingencies, and escalation
factors for these subestimates will vary according
to the type of job.
F = Total Project Cost
a
D + E
includes cost from capital project teams, process engineering, engineering,
purchasing, and other support groups.
Contingency should not be applied to any cost component that has been committed by
either purchase order or contract.
-------
2000
o
oc
UJ
m
S
UJ
O
UJ
Q
O
O
O
H
E
<
o
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1000
1 I T
r~TT
A- 2 beds, vertical:
B- 2 beds, vertical:
C- 3 beds, horizontal:
O 900 Ib of carbon; bed, 4-ft Ji -im by 3 ft deep
A 450 Ib carbon; bed, 4-ft diam by ij ft deep
O 4500 Ib of carbon; bed, S-ft diam by 3 ft deep
A 2250 Ib of carbon; bed, 8-ft diam by U ft deep
O 9000 Ib of carbon; bed, 8-ft diam, 15 ft long, 3 ft deep
A 4500 Ib of carbon; bed, 8-ft diam, 15 ft long, U ft deep
D- 3 beds, horizontal: O r>,500 Jb of carbon; bed, 11-ft diam, 26 ft long, 3 ft deep
A 11,250 Ib of carbon; bed, 11-ft diam, 26 ft long, 1} ft deep
E- 4 beds, horizontal: O 30,000 ]b of carbon; bed, 12-ft diam, 30 ft long, 3 ft deep
A 15,000 Ib of carbon; bod, 12-ft diam, 30 ft long, IJ ft deep
TT
E
100
0.3
1
1.0
Small skid-mounted units are
available for systems smaller
than 1,000 scfm. All larger
systems are costed as assembled
in place.
10
100
FLOW (1000 scfm)
Fig. IV-1. Installed Capital Cost of Carbon Adsorption Systems
-------
IV-5
costs of automatic butterfly valves, interconnecting ducts, and steam control
valves and a minimum allowance for piping or ducts required to get the vapors
and utilities to the system.
C. ANNUAL COSTS
Annual costs for various operating conditions are presented in Appendix A.
These costs are the bases for the cost-effectiveness graphs included in the
report. The parameters used in calculating these annual costs are defined in
Table IV-2. The capital cost of the carbon adsorption system was based on a
bed depth of 3 ft. Figures IV-2 through IV-5 represent the annual cost of
using a carbon adsorption system for four different steam regeneration require-
ments. The cost estimating variance for systems smaller than 1000 scfm (noted
on Fig. IV-1) causes a discontinuity at 1000 scfm for all curves shown on
Figs. IV-2 through IV-5. Table IV-3 shows the effect on annual cost of varying
the carbon life from 5 to 2 years and the cost of steam from $2.50/million Btu
to $5.00/million Btu.
D. COST AND ENERGY EFFECTIVENESS
The cost effectiveness and energy effectiveness were calculated by dividing the
annual cost for a particular option (Appendix A) or the fuel usage in Btu/yr by
the total annual amount of VOC removed with adsorption removal efficiencies
assumed as discussed in Sect. II.A.3. In this analysis the steam regeneration
rate of 0.3 Ib/lb of carbon will correspond to an effluent quality of 70 ppm^.
For steam regeneration rates of 1 Ib of steam/lb of carbon the corresponding
effluent quality will be 12 ppm . It is assumed that these effluent concentra-
tions will not change for different feed concentrations.
The cost effectiveness is given in Table IV-4 and the energy effectiveness in
Table IV-5. Figure IV-6 shows the relationship of flow rate vs cost effective-
ness for two carbon requirements* at two steam regeneration requirements.
Figures IV-7, 8, and 9 show the effect of increased steam regeneration rates at
different carbon requirements and various flow rates.
*For all cost-effectiveness calculations in this report a carbon operating
capacity of 0.10 Ib of VOC/lb of carbon is assumed. The carbon requirement
of waste gas is therefore dependent entirely on the VOC concentration in the
process waste gas.
-------
IV-6
Table IV-2. Annual Cost Parameters
Operating factor 8760 hr/yr
Fixed costs
Maintenance labor plus materials, 6% 1
Capital recovery, 18%* > 29% installed capital
Taxes, insurances, administration charges, 5% J
Utilities
Electric power $0.03/kWh
Steam $2,50, $5.00, and
$10.00/million Btu
Cooling water $0.10/1000 gal
Carbon adsorption cost (5-yr replacement) $1.17/lb
* _______ , .__ _______
Based on 10-year life and 12% interest.
-------
u
(0
tn
o
o
<
z
Ul
Carbon Requirement
(lb of carbon/1000 set
100
1,000 10,000
FEED FLOW RATE (scfm)
100,000
•-J
Fig. IV-2. Net Annual Cost vs Flow Rate for Carbon Adsorption at
a Steam Rate of 0.3 lb of Steam/lb of Carbon, No Credit for
Recovered VOC, and a Steam Cost of $2.50/Million Btu
-------
70
Carbon Requirement
lib of carbon/1000 scf
100
1,000 10,000
FEED FLOW RATE (scfm)
100,000
f
CD
Fig. IV-3. Net Annual Cost vs Flow Rate for Carbon Adsorption at a
Steam Rate of 0.6 Ib of Steam/lb of Carbon, Steam Cost of $2.50/Million Btu,
and No Credit for Recovered VOC
-------
70
Carbon Requirement
b of carbon/1000 set)
100
1,000 10,000
FEED FLOW RATE (scfm)
100,000
Fig. IV-4. Net Annual Cost vs Flow Rate for Carbon Adsorption at a
Steam Rate of 1 Ib of Steam/lb of Carbon, No Credit for Recovered VOC,
and a Steam Cost of $2.50/Million Btu
-------
NET ANNUAL COST ($/ scfm)
in
rt
(B
ft <
I
l_n
O •
HI
*^t
fD
& O §
Hi 3
Ql P
W O1
en rt ^
rt ro
"> S n
n> t3 U
S ^ W
3
en O
rt H,
•o> tr
ro O
o
Hi
O
n
w
rt HI
O pj
o
o
•n
m
m
o
o
o
o
H
m
O
•4t
3
o
"o
o
o
o
_o
"o
o
o
OT-AI
-------
IV-11
Table IV-3. Cost Effect of Varying Carbon Life and Steam Price
Fixed
Utilities
Total
rate of 5000 scfm.
Veam cost, $2.50/million Btu; carbon life, 5 years.
GSteam cost, $5.00/million Btu; carbon life, 5 years.
dSteam cost, $2.50/million Btu; carbon life, 2 years.
-------
Table IV-4. Cost Effectiveness of Carbon Adsorption for Removal of VOC
(Steam Cost, $2.50/Million Btu)
Cost Effectiveness (per Ib of VOC removed)
70-ppmv Effluent
Carbon Requirement Flow Rate
(Ib of carbon/1000 scf) (scfm)
0.5 (^359 ppuXy.) 300
1,000
5,000
20,000
50,000
100,000
1.393 (VLOOO ppmv)a 300
1,000
5,000
20,000
50,000
100,000
6.96 (^5000 ppnv)a 300
1,000
5,000
20,000
50,000
100,000
VOC
Removal
(lb/hr)a'b
0.72
2.41
12.07
48.30
120.75
241.50
2.33
7.77
38.86
155.43
388.57
777.16
12.36
41.20
206.00
823.96
2059.89
4119.78
VOC
Removal
(lb/hr)a'c
0.87
2.90
14.50
58.00
144.99
289.97
2.47
8.25
41.28
165.13
412.81
825.62
12.50
41.68
208.41
833.65
2084.12
4168.24
No VOC
Credit
$2.74
2.04
0.83
0.48
0.33
0.30
0.85
0.64
0.26
0.16
0.11
0.10
0.17
0.13
0.06
0.04
0.03
0.03
$0.05/lb
of VOC
Credit
$2.69
1.99
0.77
0.43
0.27
0.25
0.80
0.59
0.21
0.11
0.06
0.05
0.12
0.08
0.006
+0.01
+0.02
+0.02
$0.10/lb
of VOC
Credit
$2.64
1.94
0.72
0.38
0.22
0.20
0.75
0.54
0.16
0.05
0.01
+0.008
0.07
0.03
+0.04
+0.06
+0.07
0.07
12-ppmv Effluent0
No VOC
Credit
$2.29
1.73
0.71
0.43
0.30
0.27
0.83
0.63
0.27
0.17
0.12
0.11
0.19
0.15
0.08
0.06
0.05
0.05
$0.05/lb
of VOC
Credit
$2.24
1.68
0.66
0.37
0.25
0.22
0.78
0.58
0.22
0.12
0.07
0.06
0.14
0.10
0.03
0.01
+0.001
+0.004
$0.10/lb
of VOC
Credit
$2.19
1.63
0.61
0.32
0.20
0.17 <
0.73 w
0.53
0.17
0.07
0.02
0.01
0.09
0.05
+0.02
+0.04
+0.05
+0.05
-------
Table IV-4. (Continued)
Cost Effectiveness (per Ib of VOC removed)
b
70~ppmv Effluent
Carbon Requirement Flow Rate
(Ib of carbon/1000 scf) (scfm)
10 (V7180 ppm )a 300
1,000
5,000
20,000
50,000
100,000
VOC
Removal
(lb/hr)a'b
17.82
59.42
297.08
1188.3
2970.75
5941.50
VOC
Removal
(lb/hr)a'c
17.97
59.90
299.50
1198.00
2994.99
5989.97
No VOC
Credit
§ 0.12
0.09
0.04
0.03
0.02
0.02
$0.05/lb
of VOC
Credit
$ 0.07
0.04
+0.008
+0.02
+0.03
+0.03
$0.10/lb
of VOC
Credit
$ 0.02
+0.01
+0.06
+0.07
+0.08
+0.08
12-ppmv Effluent
No VOC
Credit
$ 0.14
0.11
0.06
0.05
0.04
0.04
$0.05/lb
of VOC
Credit
$ 0.09
0.06
0.01
+ 0.001
+0.007
+0.009
$0.10/lb
of VOC
Credit
$ 0.04
0.01
+0.04
+0.05
+0.06
+0.06
aAssumes a VOC molecular weight of 50 and carbon operating capacity of 0.10 Ib of VOC/lb of carbon.
bAssumes that a baseline effluent of 70 ppm can be achieved with 0.3 Ib of steam/lb of carbon.
CAssumes that a baseline effluent of 12 ppm can be achieved with 1 Ib of steam/lb of carbon.
-------
IV-14
Table IV-5 • Energy Effectiveness of Carbon Adsorption for VOC Removal
Steam Energy Usage
(Btu/scf) at
Energy Effectiveness a
(Btu/lb of VOC removed) at
Carbon Requirement 0.3 lb of steam/ 1.0 lb of Steam/ 0.3 lb of steam/ I.Q lb of Steam/
(lb of carbon/1000 scf) lb of Carbonb it, ofCarbonc lb of carbonb lb of Carbonc
0.5 (^359 ppmy.) d
1.393 (VLOOO ppm. ) d
6.96 (^5000 ppmv) d
10 CW180 ppm )d
0.146
0.405
2.03
2.91
0.485
1.35
6.75
9.70
3,627
3,127
2,957
2,939
10,035
9,809
9,722
9,716
Does not include power requirements for blower.
Assumes that a baseline effluent of 70 ppm can be achieved with 0.3 lb of steam/lb of
carbon.
"'Assumes that a baseline effluent of 12 ppm can be achieved with 1.0 lb of steam/lb of
carbon.
Assumes a VOC molecular weight of 50 and a carbon operating capacity of 0.10 lb of
VOC/lb of carbon.
-------
.70
Carbon Requirement
1.393 Ib of carbon/1000 scf)
Carbon Requirement
6.96 Ib of carbon /1000 scf
i i i i i i
0.3 Ib of steam/lb of carbon
1.0 Ib of steam/lb of
100
0.3 Ib of steam/lb of carbon)
1.0 Ib of steam/lb of carbon)
f
1,000 10,000
FEED FLOW RATE (scfm)
100,000
(For all cost-effectiveness calculations in this report a carbon capacity of 0.10
Ib of VOC/lb of carbon is assumed. The carbon requirement per scf of waste gas is
therefore dependent entirely on the VOC concentration in the process waste gas.
Adsorption effluent at 0.3 Ib of steam/lb of carbon = 70 ppm of VOC.
Adsorption effluent at 1.0 Ib of steam/lb of carbon = 12 ppmv of VOC.)
Fig. IV-6. Cost Effectiveness vs Feed Rate at 1.393 and 6.96 Ib of
Carbon/1000 scf and a Steam Cost of $2.50 per Million Btu
-------
^ 0.7
•o
0)
o
E
(U r* s*
o in t w CNJ *". o "'
3 6 0 0 0 °
a OOA *o qi /$) SS3N3AI103JJ3 JLSOO
.393
6.96
10
«
_ .
— "
_.
Carbon Requirement (see Fig.
(ib of carbon /1000 scf )
— ... - •-
•• "~
— —
—
-— — — — —
IV-6 Cap
—
— — — — —
tion)
>.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
STEAM USAGE (ib of steam/Ib of carbon)
Fig. IV-7. Cost Effectiveness vs Steam Regeneration Rates at
1000 scfm and a Steam Cost of $2.50/Million Btu
en
-------
0.7
^T
0)
> <-. e?
COST EFFECTIVENESS ($/ Ib of VOC remo
o o o o o ^ ?
0 ° "-*• M 'w "*• w rr °
— v^aruon
of carl
Require
jon /100C
0.5
1.393
6.96
10
I SCf)
• —
(See Fig
— •
j ,
IV-6 Ca
-_
• —
_
:>tion)
—
•.I,
in—
—
„——————-
• —
.
j[__
• — —
i
.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.C
f
STEAM RATE (Ib of steam/Ib of carbon)
Fig. IV-8. Cost Effectiveness vs Steam Regeneration Rates at 20,000 scfm
and a Steam Cost of $2.50/Million Btu
-------
U. f
'•o
0)
> 0.6
E
o
i_
0
0 0.5
"o
~ 0.4
CO
uj 0.3
Z
at
o
UJ 0.2
u.
UJ
CO
O 0.1
o
0
Cs
— (IB o
irbon Re
f carbon
0.5
1 393
6.96
10
quiremen
/1000 s
i
.
t (See F:
, \
Cf)
.
g. IV-6.
— —
Caption)
- —
.
H
f
M
oo
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8
STEAM RATE (tb of steam/Ib of carbon)
0.9
1.0
Fia. IV-9. Cost Effectiveness vs Steam Regeneration Rates at 100,000 scfm
and a Steam Cost of $2.50/Million Btu
-------
IV-19
Table IV-6 shows the effect that increasing the steam regeneration required
will have on cost and energy effectiveness. Data on cases not shown in the
cited tables and figures can be easily developed by use of Appendix A.
Table IV-6 also shows the percent change in cost effectiveness or energy effec-
tiveness that results when the VOC removal efficiency is increased by increasing
the steam regeneration usage from 0.3 Ib of steam/lb of carbon regenerated to
1.0 Ib of steam/lb of carbon regenerated for each waste-gas feed condition
listed. It is assumed that a 70-ppm effluent concentration is achieved at a
regeneration rate of 0.3 Ib of steam/lb of carbon and that a 12-ppmv effluent
concentration is obtained at a regeneration rate of 1.0 Ib of steam/lb of carbon.
This study does not quantitatively assess the impacts of the additional
operations required to recover or treat the materials removed from the carbon
adsorption system. When additional operations are required, secondary emissions,
as well as increased capital costs and energy consumption, will have to be
considered.
-------
IV-20
Table IV-6. Change in Cost Effectiveness and Energy
Effectiveness with increasing Regeneration Steam Usage
Carbon Requirement
(Ib of carbon/1000 scf)
0.5 (^359 ppiriy.)
1.393 CV'1000 ppmv)
6.96 Cv-5000 ppm )b
10 Cv/7180 ppmv)b
Change in
1,000 scfm
-15
-16
15
22
Cost Effectiveness
20,000 scfm 100
-10
6
50
67
a (%) at
,000 scfm
-7
10
67
100
Change in
Energy Effectiveness3
(%)
177
213
229
231
Change in regeneration steam requirement from 0.3 Ib of steam/lb of carbon to 1.0 Ifo of
steam/lb of carbon. The energy effectiveness (steam usage/lb of VOC removed) is indepen-
dent of waste-gas flow rate.
Assumes a carbon operating capacity of 0.1 Ib of VOC/lb of carbon.
-------
V-l
V. SUMMARY AND CONCLUSIONS
Carbon adsorption is a widely used control technique for VOC emissions. This
evaluation describes the limits and design principles of carbon adsorption. A
design criterion and design procedures are presented that allow for a pre-
liminary carbon adsorption design. A carbon adsorption system with two bed
depths and various steam regeneration rates is considered. Capital and operating
costs are developed, and the annual cost of carbon adsorption is calculated as
a function of the characteristics of the waste gas. Cost effectiveness and
energy effectiveness of two VOC removal efficiencies and regeneration levels
are developed.
The conclusions of the cost evaluation are as follows:
The feed flow rate is a highly sensitive variable in determining the annual
cost and cost effectiveness (see Fig. IV-6). Energy effectiveness is indepen-
dent of the flow rate. As the feed flow rate increases, the annual costs
increase but the annual cost per scfm decreases. The annual cost per scfm
decreases quickly between 300 and 5000 scfm. The ratio decreases moderately
between 5,000 and 50,000 scfm and is almost constant above 50,000 scfm. The
cost-effectiveness curve has the same shape as noted above.
The carbon requirement, wh.ch is established by the waste-gas VOC concentration
and the operating capacity of the carbon, is a very sensitive variable in
determining cost effectiveness (see Fig. IV-6). As the carbon requirement (VOC
content) increases, the annual cost decreases with a corresponding reduction in
the cost per pound of VOC removed. The energy effectiveness is fairly insensitive
to changes in carbon requirements.
The cost effectiveness is strongly dependent on the value of the recovered
material (see Table IV-3 and Appendix A). The fact that the VOC removed might
be recycled or burned as a fuel is an important factor when carbon adsorption
is considered as an emission control device candidate.
Annual cost and cost effectiveness are slightly sensitive to steam regeneration
requirements (see Fig.s IV-6 through IV-9). The effect of the steam requirement
-------
V-2
on VOC removal cost is dependent on the carbon requirement. The higher the
carbon requirement the more sensitive the steam regeneration rate is to VOC
removal costs. At very low carbon requirements (low concentration of VOC in
the process waste gas) a higher steam rate per pound of carbon may improve the
adsorber emission enough so that the cost per pound of VOC removed is reduced.
-------
VI-1
VI. REFERENCES
1. F. D. Hobbs, C. S. Parmele, and D. A. Barton, IT Enviroscience, Inc., Survey
of Industrial Applications of Vapor-Phase Activated-Carbon Adsorption for
Control of Pollutant Compounds from Manufacture of Organic Compounds, Contract
No. 68-03-2568, Task No. T7009, EPA, Cincinnati, OH (January 1981).
2. GCA Corporation, Bedford, MA, Handbook of Fabric Fiber Technology, PB 2001
648 (1970).
3. Card, Inc., Niles, IL, Capital and Operating Costs of Selected Air Pollution
Control Systems, EPA-450/3-76-014 (1976).
4. A.P.T., Inc., Riverside, CA, Entrainment Separators for Scrubbers, PB 241 189
(1974).
5. Calgon Corporation, Pittsburgh, PA, Basic Concepts of Adsorption on Activated
Carbon (unpublished).
6. S. Brunauer, P. H. Emmett, and E. Teller, "Adsorption Gases in Multimolecular
Layers," Journal of the American Chemical Society 60, 309 (1938).
7. MSA Research Corporation, Evans City, PA, Package Sorption Device System Study,
PB 221 138 (NTIS) (April 1973).
8. J. L. Kovach, "Gas-Phase Adsorption and Air Purification," Chap. 9 in Carbon
Adsorption Handbook, edited by D. N. Cheremisinoff and F. Ellerbusch, Ann
Arbor Science Publishers, Ann Arbor, MI, 1978.
9. M. Smisek and S. Cerny, Active Carbon, Elsevier, Amsterdam-London-New York,
1970.
10. R. J. Grant, M. Manes, and £. B. Smith, "Adsorption of Normal Paraffins and
Sulfur Compounds on Activated Carbon," Journal of the American Institute of
Chemical Engineers 8(3), 403—406 (1962).
11. Vic Manufacturing Company, Minneapolis, MN, Carbon Adsorption/Emission Control
Benefits and Limitations (unpublished).
12. R. R. Manzone and D. W. Oakes, "Profitably Recycling Solvents from Process
Systems," Pollution Engineering 5(10), 23, 24 (October 1973).
13. C. S. Parmele, W. L. OConnell, and H. S. Basdekis, IT Enviroscience, Inc.,
"Vapor-Phase Adsorption Cuts Pollution, Recovers Solvents," Chemical Engineering
86, 58—70 (Dec. 31, 1979).
14. W. M. Edwards and W. R. Anderson, Applicability and Cost of Carbon Adsorption
for Paint Spray Booth VOC Abatement, Contract No. 68-02-2619, Work Assignment
No. 8, EPA, Research Triangle Park, NC (Feb. 9, 1979).
15. J. Happel and D. G. Jordan, Chemical Process Economics, 2d ed. Marcel Dekker,
Inc., New York City, 1975.
-------
VI-2
16. Oxy-Catalyst/Research-Cottrell, West Chester, PA, Activated Carbon Adsorption
Vapor Recovery (unpublished) (November 1975).
17. Y. Sakaguchi, "Development on Continuous Solvent Recovery Technology Using
Activated Carbon," Chemical Economy and Engineering Review 8, 37 (December
1976).
^Usually, when a reference is located at the end of a paragraph, it refers to
the entire paragraph. If another reference relates to certain portions of
that paragraph, that reference number is indicated on the material involved.
When the reference appears on a heading, it refers to all the text covered by
that heading.
-------
APPENDIX A
ANNUAL COST DATA
-------
A-3
ANNUAL COST DATA
The annual costs of carbon adsorption systems are presented in the following
computer printouts showing costs for a specific carbon requirement and steam
regeneration rate at various flow rates, steam costs, and recovery credits. The
five credit levels shown correspond to the value of the VOC recovered at a
specific carbon requirement. With a carbon operating capacity of 10 Ib of
VOC/100 Ib of carbon assumed, the five credit levels correspond to $0.00/lb of
VOC, $0.05/lb of VOC, $0.10/lb of VOC, $0.20/lb of VOC, and $0.40/lb of VOC.
The following sample calculation is for a stream with a carbon requirement of
1.0 Ib of carbon/1000 scf, a steam regeneration rate of 0.3 Ib of steam/lb of
carbon, a flow rate of 5000 scfm, and a credit value of $0.05/lb of VOC at a
carbon capacity of 0.10 Ib of VOC/lb of carbon:
Capital cost = $273,000 (from Fig. IV-1) at 5000 scfm with a 3-ft-deep bed.
Fixed cost = ($273,000 X 0.29*) + carbon replacement cost ($2,106) =
= $81,276/yr.
Carbon replacement cost = ($1.17*/lb of carbon) X
(5000 scfm) X (3 ft deep) X (30 lb/ft3) X 2 beds = $2/106/yr_
(100 fpm) X (5*-yr replacement*)
Utilities = steam ($] 912) + electricity ($4,925) + cooling water
($331) = $7,167//r.
Steam = (0.3 Ib of sttam/lb of carbon) X (1 Ib of carbon/1000 scf) X
X (5000 scfm) X ($2.50*/million Btu) X (970 Btu/lb of steam) X
X (60 min/hr) X (8760 hr/yr) = $l,912/yr
Blower electricity = (19.2 in. H20) X [0.000157 hp/(in. H20)(scfm)] X
X (1/0.60 efficiency) X [0.746(kWh/hr)/hp] X (5000 scfm) X ($0.03*/kWh) X
X (8760 hr/yr = $4,925/yr.
Condenser cooling water = (4.2 gal/lb of steam) X (0.3 Ib of steam/lb
of carbon) X (1 Ib of carbon/1000 scf) X (5000 scfm) X ($0.10/1000 gal*) X
X (60 min/hr) X (8760 hr/yr) = $331/yr.
Credit = ($0.05/lb of VOC) X (1 Ib of carbon/1000 scf) X (0.10 Ib of
VOC/lb of carbon) X (5000 scfm) X (60 min/hr) X (8760 hr/yr) =
= $13,140/yr.
*See Table IV-2.
-------
A-4
Annual cost - fixed cost ($81,276) + utilities ($7,167) - credit ($13,140)
= $75,303/yr.
Net cost = annual cost ($75,303)/flow rate (5000 scfm) = $15.06/scfm.
-------
OFFGAS OARPON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAH/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.00054/1000 SCF
O.OOlOt/1000 SCF
0.0020$/1000 SCF
0.0040$/1000 SCF
OFFOAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
CAPITAL
COST
(000)
58.
144,
273.
594.
955.
1671.
58.
144,
273.
594,
955,
1671 .
58.
144.
273.
5V4.
955.
1671 ,
58.
144,
273.
594.
955.
1671 .
58.
144,
273.
594.
955.
1671.
OPERATING COST-OR-CRETUT
FIXFD UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81 .
179.
293.
513,
17 .
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17,
42.
81 ,
1 79.
293.
513.
17.
42,
81 .
179.
293.
513.
0,
1 .
5 ,
21 ,
51 .
103.
0,
] ,
5.
21 .
51 .
103.
0.
1 ,
5 ,
21 .
51 .
103.
0.
1 ,
U *
21 .
51 .
103.
0 ,
1 .
*J »
21 .
51 .
103.
0,
0.
0.
0,
0,
0,
0.
0,
1 .
5.
13,
26.
0.
1 .
3.
11 .
26,
53.
0.
1 .
5 ,
21 ,
53,
105.
1 .
2 ,
11 .
42.
105,
210.
NET
ANNUALIZEH
COST OR CREDIT(-)
(000)
17.
43.
86.
199 ,
344.
615 .
17.
43.
85,
194.
331 .
589.
17.
43.
84 .
189,
318.
563.
17,
42.
81 .
178,
291 .
510.
17.
41 ,
76,
157,
239,
405,
NET COST
OR S A UING P(
PER SCFM
$/SCFM
57.51
43.21
17.28
9.9'.
6.88
6, 15
57.25
42.94
17,02
9.69
6.62
5.89
56.99
42.68
16 .75
9,43
6.35
5.63
56,46
42.16
16.23
8.90
5,83
5.10
55.41
41.10
15.18
7. 85
4.78
4.05
-------
OFFGAS CARBON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO O.A LB STEAM/ L& CARBON
AT $2.50/MILLION BTU
CKEDTT
0.0000*/1000 SCF
0.0005$/1000 SCF
0.0010*/1000 SCF
0,0020$/1000 SCF
0.0040$/1000 SCF-
OFFOAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000 .
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000,
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
1 44 ,
273.
594,
955.
1671 .
58.
144.
273,
594,
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1 671 .
58.
144.
273.
594.
955.
1671.
OF'FRATING COST-OR-CREHIT NET
FIXED UTILITIES RECOVERY ANNUALIZEB
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179,
293.
513.
17.
42.
81 .
179.
293.
513.
17,
42.
81 .
179.
293.
513.
17,
42.
81 .
1 79.
293.
513.
17.
42,
81 .
179.
293.
513.
2 1
53,
107.
0.
t ,
5 <
21 ,
53.
107.
0.
1 .
5.
21 ,
53,
107.
0.
1 .
5,
21 ,
53.
1 07.
0.
21 .
53.
107.
0.
0.
0.
0,
0.
0.
0.
0.
1 .
5 .
13.
26.
0.
1 .
3.
1 ] .
26.
53.
5,
21 .
53.
105.
1 .
T
1 1 .
42.
105.
210.
17.
43.
87.
200.
346.
620,
17.
43 .
85.
195.
333.
593.
17.
43.
84.
189.
320.
567.
17.
42.
81.
] 79.
294.
514.
17.
41 ,
76.
158.
241 .
409.
NET COST
OR SAVINGS (--)
PER SCFM
$/SCFM
57.56
43.25
17.33
10.00
6 . 92
6 .20
5"1 . 30
^ "\ t I^Q
17.06
6.66
5. "3
57.03
4 2 . "•' 3
16.80
9.47
6.40
5.6-7
56.51
42 . 20
16,27
8 . 95
5.87
5. 14
55 . 46
41.15
15.22
7.90
4.82
4.09
-------
OFFGAS CARBON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CKEDIT
0.0000*/1000 SCF
0.0005$/1000 SCF
0.0010$/1000 SCF
0,0020t/1000 SCF
0.0040*/1000 SCF
OFFGAS
FLOW
SCf-M
300.
1000.
5000.
20000.
50000,
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
CAPITAL
COST
(000)
58.
1 44.
273.
594,
955,
1671 ,
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671 .
144.
273.
594.
955.
1671.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17. 0. 0.
42. 1. 0,
61 . 6, 0.
179. 23. 0.
293. 56, 0.
513. 113. 0.
17. 0. 0.
42. 1 • 0>
81. 6. 1.
179, 23. 5.
293. 56. 13.
513. 113. 26.
17. 0. 0.
42. 1. i >
81. 6. 3.
179, 23, 11,
293. 56. 26,
513. 113. 53,
17. 0. 0.
42. 1. 1,
81 . 6. 5.
179. 23. 21.
:'93. 56. 53.
513. 113. 105.
17. 0. 1 .
42. 1. 2.
81. 6. 11.
179. 23. 42.
293. 56. 105.
, 513. 113. 210.
NET
ANNUALIZEti
COST OR CREDIT(-)
(000)
17.
43.
87,
201 ,
349.
626.
17.
43.
86,
196.
336.
599.
17.
43.
84.
191 .
323.
573.
17.
42.
82.
180.
297.
520.
17.
41 .
76.
159 .
244.
415.
NET COST
OR SAVINl3S(->
PER SCFM
t/SCFM
57.62
43.31
17,38
10 . 0 h
6.98
6.26
57.35
43.05
17,12
9.80
6.72
5.99
57 .09
42.79
16.86
9.53
6.46
5.73
56.57
42.26
16.33
9.01
5.93
5.20
55.52
41 ,21
15 ,28
7.96
4.88
4.15
-------
OFFGAS CARBON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
O.OOOSt/1000 SCF
0.0010$/1000 SCF
0,0020t/1000 SCF
O.Q040$/1000 SCF
0 F F G A S
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273 .
594,
955.
1671 ,
144.
273,
594,
955.
1671 .
58.
144,
273.
594 .
955.
1671 .
144.
273.
594.
955.
1671 .
58.
144.
273.
594,
955.
1671 ,
OPERATING CUST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
61 .
179.
293.
513.
17.
42,
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513,
17.
42.
81 ,
179.
293.
513.
17.
42.
81 .
179,
293.
513.
0.
1 ,
6.
26 .
64.
128.
0.
1 .
6.
26.
64.
128.
0.
1 .
6.
26.
64.
128,
0.
1.
6,
26,
64.
128.
0.
1 ,
6.
26.
64.
128.
0.
0.
0.
0.
0.
0,
0.
0.
1 .
5 »
13.
26,
0.
1 ,
3.
11 .
26 .
53.
0.
1 ,
5 .
2 1 .
53.
105.
11.
42,
105.
210.
17.
43.
88.
204.
357.
641 .
17.
43.
86.
199.
344.
614.
17.
43.
85.
194.
330.
588.
17.
42.
82.
193.
304.
535.
17.
41 .
77.
162.
252.
430.
NET COST
OR SfWINGS(-)
PER SCFM
$/SCFM
57.77
43.46
1 7.53
10 . 2 I
7,13
6.41
57.50
43.20
17.27
9.95
6.87
6.14
57.24
42 ,93
17,01
9 .68
6.61
5.88
56.72
42.41
16.48
9.16
6.08
5.35
55.66
41 .36
15.43
8. it
5.03
4.30
-------
OFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAH/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000*71000 SCF
0.0025*71000 SCF
0.0050*71000 SCF
0.0100*71000 SCF
0.0200*71000 SCF
OFFGAS
FLOW
SCFh
300.
1000.
5000.
20000,
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
144.
273.
594.
955.
1671 .
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671 .
58.
1 44.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTIIITIES RECOVERY
COST CREDIT
(000) (000) (000)
17. 0. 0.
42. 1. 0.
81. 6- <>•
179. 24. 0.
293. 60. 0.
513. 120. 0.
17. 0. 0.
42. 1. 1'
81. 6. 7.
179, 24. 26.
293. 60. 66.
513. 120. 131.
17. 0. 1.
42. 1. 3,
81. 6. 13.
]79, 24, 53.
293. 60. 131.
513, 120. 263.
17. 0, 2.
42, 1> ^•
81. 6. 26.
179. 24. 105.
293, 60. 263.
513, 120. 526.
17. 0. 3.
42. 1. 11.
81. 6. 53.
179. 24. 210.
293. 60. 526.
, 513, 120. 1051.
NET
ANNUALIZEti
COST OR CREDIT(-)
(000)
17.
43.
97.
203.
353.
633.
17.
42.
81 .
176.
287.
502.
17,
41 .
74.
150,
ITT
370.
16.
38.
61 .
98.
90.
107 .
14.
33.
35.
-8.
-173.
-418.
NET COST
OR SAVINGS^--)
PER SCFM
4/SCFM
57.69
43.39
17.46
10.13
7.06
6.33
56,38
42 . 07
16.15
8.82
5.75
5.02
55 .06
40.76
14,83
7.51
4.43
3.70
52.44
38.13
12.20
4.88
1.80
1 .07
47.18
32.8,'
6.95
-0.38
-3.45
-4.18
-------
OFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0025$/1000 SCF
0.0050$/1000 SCF
0.0100$/1000 SCF
0.0200$/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAF'ITAL
COST
(000)
144,
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
53.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671 .
58.
144.
273.
594,
955.
1671,
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
CUST CREDIT
(000) (000) (000)
17. 0. 0.
42. 1. 0.
81. 7. 0.
179. 29. 0.
293. 71. 0,
513. 143. 0.
17. 0. 0.
42. 1. 1 •
81. 7. 7.
179. 29. 26.
293. 71. 66.
513. 143, 131.
17. 0. 1 .
42. 1. 3.
81. 7. 13.
179. 29, 53,
293. 71. 131.
513. 143. 263,
17. 0. 2.
42, 1. 5-
81. 7. 26,
179. 29. 105,
293. 71. 263.
513. 143. 526.
17. 0. 3.
42. 1. 11.
81. 7. 53.
179. 29. 21.0.
293. 71. 526.
,513. 143. 1051.
NLT
ANNUALIZED
COST OR CREDIT(-)
(000)
17.
44 .
88.
207.
364.
655.
17.
42.
82.
181.
298.
524,
17.
41 ,
75.
155.
1>33.
393,
16.
38.
62 .
102.
101 .
130,
14,
33.
36.
— "^
-161 .
-396.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
57.92
43.61
17.69
10,36
7.28
6.55
56.60
42.30
16.37
9.04
5.97
5.24
55.29
40.9B
15.06
7,73
4.66
3.93
52. 6A
38,3'.;
12,43
5.10
2.03
1 .30
47.40
33,10
7. 17
-0.15
-3,23
-3.96
-------
OFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT f2.50/MILLION BTU
CREDIT
OFFGAS
FLOU
SCFM
CAPITAL
COST
(000)
FIXED
COST
(000)
OPERATING COST-OR-CREDIT
UTILITIES
(000)
NET
RECOVERY ANNUALIZED
CktniT COST OR CREHIT(-)
(000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
4/SCFM
0.00004/1000 SCF
0.00254/1000 SCF
0.00504/1000 SCF
0,01004/1000 SCF
0.02004/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
,500.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000,
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293,
513.
17.
4?.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513,
9.
35.
86.
173.
1 ,
n
9.
35,
86.
173,
1 .
2.
9.
35.
86.
173.
1 .
T
9.
35.
86.
173.
9.
35.
86.
173.
0. 17.
0- 44.
0. 90.
0. 213.
0. 379.
0. 685.
0. 17.
1. 43.
7. 83.
26. 1S7.
66. 313.
131. 554.
1. 17.
3. 41.
13. 77.
53. 161.
131. 248.
263. 423.
2. 16.
5. 39.
26. 64.
105. 108.
263. 116.
526. 160.
3. 14,
11. 33,
53. 37.
210. 3.
526. -146,
1051. -366,
b8.22
43,9 I
17,98
10,66
7,58
6.85
56.90
42.60
16.67
9. 34
6.27
5.54
55.59
41 .28
15.36
8.03
4.95
4.23
52.96
38.6 ',-J
12.73
5,40
2,33
1 .60
47,70
33.40
7.47
0.14
-2.93
-3.66
-------
OFFGAS CARBON REQUTREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAh/ LB CARBON
AT J2.50/MILLION BTU
CREDI T
0.0000*/1000 SCF
0.0025*/1000 SCF
0.00504/1000 SCF
0.0100*/1000 SCF
0.0200*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000,
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671 .
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955 .
1671.
58.
144.
273.
594.
955.
1671.
FIXED
OUST
(000)
17.
42 .
81 .
179.
293 .
513.
17.
42.
81.
179.
293.
513,
17.
42.
8] .
179.
293.
513.
17.
42.
81 .
179,
293.
513.
17,
42.
81 .
179.
293.
513.
OPERATING COST-UR-CRF-IHT
UTILITIES
(000)
1 .
2.
12.
50.
124.
248.
1 .
2.
12.
50.
124,
248,
1 .
O
12,
50.
124.
248.
1 .
2,
12.
50,
124.
248,
1 .
2,
12.
50.
124.
248.
NF.T
RECOVERY ANNUALIZELi
CREDIT COST OR CREDIT(-)
(000) (000)
0,
0,
0.
0.
0 .
0.
0.
1.
7.
26.
66.
131.
1.
3.
13.
53.
131.
263.
26.
105.
263.
526,
3.
11.
53.
210,
526.
1051.
18,
45.
94.
228.
417,
760.
17.
43.
87.
202.
351.
629.
17.
42.
81.
176.
285.
497.
16,
39.
67.
123.
154.
235.
15.
34.
41.
18.
-109.
-291.
NET COST
OR SAVINGS(->
PER SCFM
$/SCFM
58.96
44.66
18.73
11 .40
8.33
7.60
57,65
43.34
17.42
10.0-?
7.02
6.29
56.34
42.03
16.10
8.78
5.70
4.97
53. 71
39.40
13.47
6.1 *
3.07
2.35
48.45
34 . 1 4
8.22
0.89
-2.18
-2.91
-------
OFFGAS CARBON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAh/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000*71000 SCF
0.0050*71000 SCF
O.OlOOt/1000 SCF
0.0200*71000 SCF
0.0400*71000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273,
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
58.
1 44.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
0.
1.
7.
29.
71 .
143.
0.
1.
7.
29.
71 .
143.
0.
1 .
7.
29.
71 .
143.
0.
1.
7.
29.
71 .
143.
0.
1 .
7.
29.
71 .
143.
0.
0.
0.
0.
0.
0.
1 ,
3.
13.
53.
131.
263.
5.
26.
105.
263.
526.
3.
11 .
53.
210.
526.
1051.
6.
21 .
105.
420.
1051.
2102.
17.
44.
88.
207.
364.
655.
17.
41 .
75.
155.
233.
393.
16.
38.
62.
102.
101.
130.
14,
33.
36.
-3.
-161.
-396.
11 .
23.
-17.
-2)3.
-687.
-1447.
NET COST
OR SAVINGS(-)
PER SCFM
*7SCFM
57.9?
43.61
17.68
10.36
7.28
6*55
55.29
40.98
15.06
7.73
4.66
3.93
52.66
38.;<5
12.43
5.10
2.03
1 .30
47.40
33.10
7.17
-0.15
-3.23
-3.96
36.89
22.59
-3.34
-10,67
-13.74
-14.47
-------
OFFGAS CARBON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *2.50/HILLION BTU
CREDIT
0.0000*/1000 SCF
0.00504/1000 SCF
0.0100*/1000 SCF
0,0200*/1000 SCF
0.0400*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREHIT(-)
(000) (000) (000) (000)
17.
42.
81 ,
179.
293.
513.
17,
42.
81 .
179,
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179,
293.
,513.
1 .
2.
9.
38.
94.
188.
9.
38.
94.
188,
1 .
2 f
9.
38.
94.
188.
1.
2.
9.
39.
94.
188.
1 ,
2 t
9.
38.
94,
188.
0.
0.
0.
0.
0.
0.
1 ,
3.
13.
53.
131 .
263.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21 .
105.
420.
1051.
2102.
18.
44.
91.
216.
387.
700.
17.
41 .
78.
164.
255.
438.
16.
39.
64,
111 .
124.
175.
14.
34.
38.
6.
-139.
-351 ,
11 .
23.
-14.
-204.
-665.
-1402,
NET COST
OR SAYINGS(-)
PER SCFh
$/SCFM
58.37
44.06
18.13
10.81
7.73
7.00
55.74
41.43
15.50
8.18
5.10
4.38
53. 11
38.80
12.88
5.55
2.48
1 .75
47.85
33.55
7.62
0.29
-2. 78
-3.51
37.34
23.03
-2.89
-10.22
-13.29
-14.02
-------
OFFGAS CARPON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.00004/1000 SCF
0.0050*/1000 SCF
0.0100S/1000 SCF
0.0200$/1000 SCF
0.0400*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594 .
955.
1671 .
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955,
1671,
FIXED
COST
(000)
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
. 513.
OPERATING COST-OR-CREDIT
UTILITIES
(000)
12.
50.
124.
248.
12.
50.
124.
248.
1 .
11
12.
50,
124,
248.
1 .
2 t
12.
50.
124.
248.
1 .
i ^
12.
50.
124.
248.
NET
RECOVERY ANNUALIZED
CREDIT COST OR CREDIT(-)
(000) (000)
0. 18.
0. 45.
0. 94.
0. 228.
0. 417.
0. 760.
1. 17.
3. 42.
13. 81.
53. 176.
131. 285.
263. 497.
2. 16.
5. 39.
26. 67.
105. 123.
263. 154.
526. 235.
3. 15.
11. 34.
53. 41.
210. 18.
526. -109.
1051. -291.
6. 11.
21. 24.
105. -11.
420. -192.
1051. -635.
2102. -1342.
NET COST
OR SAVINGS(-)
PER SCFM
t/SCFM
58.96
44.66
18,73
11 .40
8.33
7.60
56.34
42.03
16.10
8,78
5. 70
4.97
53,71
39. 40
13.47
6.15
3.07
2.35
48.45
34.14
8.22
0.89
-2. 18
-2.91
37.94
23.63
-2.29
-9.62
-12.69
-13.42
-------
OFFGAS CARBON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $2.50/«ILLION BTU
CREDIT
0,0000*/1000 SCF
0,0050$/1000 SCF
0.0100*/1000 SCF
0.0200$/1000 SCF
0.0400$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671 .
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42,
81.
179.
293.
513.
17.
42 .
81 .
179.
293.
513.
17.
42.
8t .
179.
293.
513,
1 .
4.
20.
79.
199.
397.
1.
4.
20.
79.
199.
397.
1 .
4.
20.
79.
199.
397.
1.
4.
20.
79.
199.
397.
1 .
4.
20.
79.
199.
397.
0.
0.
0.
0.
0.
0,
1 .
3,
13.
53,
131 .
263,
5.
26.
105.
263.
526,
3.
11 .
53.
210.
526,
1051 .
6.
21 .
105.
420.
1051.
2102,
18.
46.
101 .
258.
491 .
910.
17.
44,
88.
205.
360.
647.
17.
41.
75.
153.
228.
384.
15.
36.
49,
48.
-34.
-142.
12.
25.
-4.
-162.
-560.
-1193.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
60.46
46.15
20.23
12.90
9.83
9. 10
57.83
43.52
17.60
10.27
7.20
6.47
55.20
40.90
14.97
7.64
4.57
3.84
49.95
35.64
9.71
2.39
-0.69
-1 .42
39.43
25. 13
-0.80
-8.i:>
-11.20
-11 .93
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT $2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0070*/1000 SCF
0.01394/1000 SCF
0.0279$/1000 SCF
0.0557*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000,
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) <000) <000) <000)
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
0.
2.
8.
32.
80.
161.
0.
21
8.
32.
80.
161.
8.
32.
80.
161 .
0.
2 ,
8.
32.
80.
161.
0.
2.
8.
32.
80.
161.
0.
0.
0.
0,
0.
0.
1.
4.
18.
73.
183.
366,
7.
37.
146.
366.
732.
4.
15.
73.
293.
732.
1464.
9.
29.
146.
586.
1464.
2929.
17.
44.
89.
211 .
373.
673.
16.
40.
71 .
137.
190.
307.
15.
36.
53.
64.
7.
-59.
13.
29.
16.
-82.
-359.
-791 .
9.
14.
-57,
-375.
-1091 .
-2256.
NET COST
OR SAVINGS(-)
PER SCFh
t/SCFM
58.09
43.7V
17.86
10.53
7.46
6.73
54.43
40.13
14.20
6.87
3.80
3.07
50.77
36.46
10.54
3.21
0.14
-0.59
43.45
29.14
3.22
-4.11
-7.IB
-7.91
28.81
14.50
-11 .43
-18.75
-21.83
-22.56
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT $2.50/MILLION BTU
CREDIT
0.00004/1000 SCF
Q.0070$/1000 SCF
0.0139$/1000 SCF
0.0279*/1000 SCF
0.0557$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
144,
273.
594,
955.
1671.
58.
144.
273,
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
1 .
2.
11.
45.
112.
223.
1 .
2.
11 .
45.
112.
223.
11.
45.
112.
223.
1 .
2.
11 .
45.
112.
223.
1 .
2.
11 .
45.
112.
223.
0.
0.
0.
0.
0.
0.
1,
4.
18.
73.
183.
366.
2.
7.
37.
146.
366.
732.
4.
15.
73.
293.
732.
1464.
9.
29.
146.
586.
1464.
2929.
18.
44.
92.
223.
404.
736.
17.
41,
74.
150.
221.
370.
15.
37.
56.
77.
38.
3.
13.
30.
19,
-70.
-328.
-729.
9,
15.
-54.
-363.
-1060.
-2193.
NET COST
OR SAYINGSC-)
PER SCFM
*/SCFM
58.72
44.41
18.49
11.16
8.08
7.36
55.06
40.75
14.82
7.50
4.42
3.70
51.40
37.09
Id . 16
3.84
0.76
0.03
44.07
29.77
3.84
-3.4ft
-6.56
-7.29
29.43
15.12
-10.80
-18,13
-21.20
-21.93
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *2.50/MILLION BTLI
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREIHT NET
FIXED UTILITIF-S RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAYINGS(-)
PER SCFM
$/SCFM
0.0000*/1000 SCF
0.0070*/1000 SCF
0.01394/1000 SCF
0.0279*/1000 SCF
0.0557$/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594,
955.
1671 .
58.
144.
273,
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
17.
42,
81 ,
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
1 .
3.
15.
61 .
153.
306.
1 .
3.
15.
61 .
153.
306.
1 .
3.
15.
61.
153.
306.
1 .
3.
15,
61 .
153.
306.
1 .
3.
15.
61.
153,
306.
0.
0.
0.
0.
0.
0.
1 .
4,
18.
73.
183.
366.
7.
37.
146.
366.
732.
4.
15.
73.
293.
732.
1464.
9.
29.
146.
586.
1464.
2929.
18.
45.
97.
240.
446.
819.
17.
42.
78.
167.
263.
453.
16.
38,
60,
93.
BO.
87.
13.
31 .
23.
-53.
-286.
-645.
9.
16.
-50.
-346.
-1018.
-2110.
59.55
45.24
19.32
11 .99
8.92
8.19
55.89
41 .58
15.66
8.37
5.26
4.53
52.23
37.91'
12.00
4.67
1 .60
O.B7
44.91
30.60
4.68
-2.65
-5.73
30.26
15.96
-9.97
-17.29
-20.37
-21.10
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0070*/1000 SCF
0.0139$/1000 SCF
0,0279*/1000 SCF
0.0557S/1000 SCF
OFFQAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300,
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58,
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZEB
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179,
293.
513.
17,
42.
81.
179.
293.
513.
17.
42.
81 .
179,
293.
513.
2,
5.
26.
103.
257.
515.
2.
5.
26.
103.
257.
515.
26,
103,
257.
515,
26.
103.
257.
515.
26,
103.
257.
515.
0.
0.
0.
0.
0.
0.
1 .
4,
13.
73.
183.
366.
2.
7.
37.
146.
366.
732.
4.
15.
73.
293.
732.
1464.
9.
29.
146.
586.
1464.
2929.
18.
47.
107.
282 ,
550.
1027.
17,
44,
89.
208.
367.
661.
16.
40.
70.
135.
184.
295.
14.
33.
34.
-11.
-182.
-437.
10.
18,
-39.
-304,
-914.
-1901.
NET COST
OR SAYINGS(-)
PER SCFM
$/SCFM
61 .63
47.33
21 .40
14.08
11.00
10.27
57,97
43.67
17.74
10.41
7.34
6.61
54.31
40.01
14.08
6.75
3.68
2.95
46.99
32.68
6.76
-0.57
-3.64
-4.37
32.35
18.04
-7.88
-15.21
-18.29
-19,01
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
FIXED
COST
(000)
OPERATING COST-OR-CREDIT
UTILITIES
(000)
NET
RECOVERY ANNUALIZEO
CREDIT COST OR CREDIT(-)
<000) (000)
NET COST
OR SAVINGS <--)
PER SCFM
t/SCFM
0.0000*/1000 SCF
0.0100$/1000 SCF
0.0200*/1000 SCF
0.0400$/1000 SCF
0.0800t/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300,
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671 .
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671,
58.
144.
273.
594.
955,
1671.
58.
144.
273,
594.
955.
1671.
17.
42.
81 .
179.
293.
513.
17.
42,
81.
179,
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293,
513.
17.
42.
81 .
179,
293.
, 513.
1.
2.
9.
38.
94.
188.
1 .
2,
9.
38.
94.
188.
9.
38.
94.
188.
9.
38.
94,
188.
1 .
2,
9.
38.
94.
188,
0.
0.
0.
0.
0.
0.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21.
105.
420.
1051 .
2102.
13.
42.
210.
841.
2102.
4205.
18.
44.
91 .
216.
387.
700.
16.
39.
64.
Ill .
124.
175.
14.
34.
38.
6.
-139.
-351 .
11 .
23.
-14,
-204.
-665.
-1402.
2,
-120.
-625.
-1716.
-3504.
58.37
44.06
18.13
10.81
7.73
7.00
53.11
38.80
12.88
5.55
2.48
1.75
47.85
33.55
7.62
0,29
-2.78
-3.51
37,34
23.03
-2.89
-10.22
-13.29
-14.02
16.32
2.01
-23.92
-31.24
-34.32
-35.04
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON/1000 SCF
STEAh REGENERATION RATIO 0.6 LB STEAH/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0100*/1000 SCF
0.0200*71000 SCF
0.0400*/1000 SCF
o.oeoot/iooo SCF
OFFGAS
FLOW
SCFH
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293,
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
1,
3,
14.
55.
139.
277.
1 .
3.
14.
55.
139.
277.
1.
3.
14.
55.
139.
277.
1.
3.
14.
55.
139.
277.
1.
3.
14.
55.
139.
277.
0.
0.
0.
0.
0.
0.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21,
105.
420.
1051 ,
2102.
13.
42.
210.
841.
2102.
4205.
18.
45.
95.
234.
431 .
790.
16.
40.
69.
129.
169.
264.
15.
34.
43.
24.
-94.
-261 .
11 .
24.
-10.
-186.
-620.
-1312.
5.
3,
-115.
-607.
-1671.
-3415.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFH
59.26
44.96
19.03
11.70
8.63
7.90
54,01
39.70
13.77
6.45
3.37
2.64
48.75
34.44
8.52
1.19
-1 .88
-2.61
38.24
23.93
-1.99
-9.32
-12.39
-13. 12
17.21
2.91
-23.02
-30.34
-33.42
-34. 15
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
O.OlOOt/1000 SCF
0.0200*/1000 SCF
0.0400*/1000 SCF
0.0800*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREIHT
FIXFD UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17. 1. 0.
42. 4. 0.
81. 20. 0.
179. 79. 0.
293. 199. 0.
513. 397. 0.
17. 1. 2.
42. •*. 5.
81. 20. 26.
179. 79. 105.
293. 199. 263.
513. 397. 526.
17. 1. 3.
42. 4. 11.
81. 20. 53.
179. 79. 210.
293. 199. 526.
513. 397. 1051.
17. 1. 6.
42. 4. 21.
81. 20. 105.
179. 79. 420.
293. 199. 1051.
513. 397. 2102.
17. 1. 13.
42. 4. 42.
81 . 20. 210.
179. 79. 841.
293. 199, 2102.
513. 397. 4205.
NF:T
ANNUALIZED
COST OR CREDIT<-)
(000)
18.
46.
101 .
258.
491 .
910.
17.
41 .
75.
153.
228.
384.
15.
36.
49.
48.
-34.
-142.
12.
25.
-4.
-162.
-560.
-1193.
6.
4.
-109 .
-583 .
-1611.
-3295.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
60,46
46. 15
20.23
12.90
9.83
9 . 10
55.20
40.90
14.97
7.64
4.57
3.84
49.95
35,64
9.71
2.39
-0.69
-1 .42
39.43
25.13
-0.80
-8.1?
-11.20
-11.93
18.41
4.10
-21.82
-29.15
-32.22
-32.95
-------
OFFGAS CARBON REQUIREMENT 2,00 LB CARSON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $2.50/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
0.0000$/1000 SCF
0.0100$/1000 SCF
0.0200$/1000 SCF
0.0400*/1000 SCF
0.08001/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000,
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671,
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
17,
42 ,
81 .
179.
293.
513.
17.
42,
81.
179.
293.
513.
17.
42,
81 .
179.
293.
513.
17.
42,
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
7.
35.
139.
348.
696.
2.
7.
35.
139.
348.
696.
7.
35.
139.
348.
696,
2.
7.
35.
139.
348.
696.
7.
35.
139.
348.
696.
0.
0.
0.
0.
0.
0.
2.
5.
26.
105.
263.
526.
3.
11 .
53.
210.
526.
1051 ,
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841 .
2102.
4205.
19.
49.
116.
318.
641 .
1209.
17.
44.
90.
213.
378.
683.
16.
39.
64.
108.
115.
158.
13.
28.
11 .
-103.
-410.
-894.
6.
7.
-94.
-523,
-1462.
-2996.
63.45
49. 14
23.22
15.89
12.82
12.09
58. 19
43.89
17.96
10.63
7.56
6.83
52.94
38.63
12.70
5.38
2.30
1 ,58
42.43
28.12
2. 19
-5.13
-8.21
-8.94
21
7
40
09
18.83
26,16
29.23
29.96
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT $2.50/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0250*/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREOIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42,
81.
179,
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
1.
3.
16.
64.
161 .
322.
1.
3.
16.
64.
161 .
322.
1.
3.
16.
64.
161.
322.
1 .
3.
16.
64.
161 .
322.
1.
3.
16.
64.
161.
322.
0.
0.
0.
0.
0.
0.
4,
13.
66.
263.
657.
1314.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
18.
45.
97.
243.
454.
835.
14.
32.
32.
-20.
-203.
-479.
10.
19.
-34.
-283.
-860.
-1793.
-7.
-165.
-808.
-2174.
-4421.
-14.
-60.
-428.
-1859.
-4802,
-9677,
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
59.71
45.40
19.48
12.15
9,08
8,35
46.57
32.26
6.34
-0.99
-4.06
-4.79
33.43
19.12
-6.80
-14.13
-17.20
-17.93
7,15
-7.16
-33.08
-40.41
-43.48
-44.21
-45.41
-59.72
-85.64
-92.97
-96.04
-96.77
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0250*/1000 SCF
0.0500$/1000 SCF
0.10004/1000 SCF
0.2000*/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58,
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17,
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 ,
179.
293,
513.
2.
5.
27.
109.
273.
547.
2.
5.
27.
109.
273.
547.
2.
5,
27,
109.
273.
547.
2.
5.
27.
109.
273.
547.
5.
27.
109.
273.
547.
0.
0.
0.
0.
0.
0.
4.
13.
66.
263.
657.
1314.
8.
26,
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
19.
48.
109.
288.
566.
1059.
15.
35.
43.
25.
-91.
-255.
11.
21.
-23.
-238.
-748.
-1569.
3.
-5.
-154.
-763.
-2062.
-4197.
-13.
-57.
-417.
-1814.
-4690.
-9453.
NET COST
OR SAUINGS(-)
PER SCFM
*/SCFM
61.95
47.65
21.72
14.40
11.32
10.59
48.81
34.51
8.58
1.26
-1 .82
-2.55
35.67
21.37
-4.56
-11 .88
-14.96
-15.69
9.39
-4.91
-30.84
-38.16
-41.24
-41.97
-43.17
-57.47
-83.40
-90.7:?
-93.80
-94.53
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT $2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0250*/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXEC UTILITIES RECOVERY ANNUALI7.E0
COST CREDIT COST OR CREDITC-)
(000) <000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
3.
8.
42.
169.
423.
846.
3.
8.
42.
169.
423.
846.
3.
8.
42,
169.
423.
846.
3.
8.
42.
169.
423.
846.
3.
8.
42.
169.
423.
846.
0.
0.
0.
0.
0.
0.
4.
13.
66.
263,
657.
1314.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
19.
51.
124.
348.
716.
1358.
16.
37.
58.
85.
59.
44.
12.
24.
-8.
-178.
-598.
-1270.
4.
-2,
-139.
-703.
-1912.
-3898.
-12.
-54.
-402.
-1755.
-4540.
-9154,
NET COST
OR SAUINGS(-
PER SCFM
*/SCFM
64.94
50.64
24.71
17.39
14.31
13.58
51.80
37,50
11.57
4.25
1.17
0.44
38.66
24.36
-1.57
-8.89
-11.97
-12.70
12.38
-1.92
-27,85
-35.17
-38.25
-38.98
-40.18
-54.48
-80.41
-87.73
-90.81
-91.54
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0250*/1000 SCF
O.OSOOt/1000 SCF
0.1000*/1000 SCF
0.2000$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREIHT
FIXEH UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513,
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
5. 0.
16, 0.
80. 0.
319. 0.
797. 0.
1593. 0.
5. 4.
16. 13.
80. 66.
319, 263.
797. 657.
1593. 1314.
5. 8.
16. 26.
80. 131,
319. 526.
797. 1314.
1593. 2628.
5. 16.
16. 53.
80. 263.
319. 1051.
797, 2628.
1593, 5256,
5.
16.
80.
319.
797.
1593.
32.
105.
526.
2102.
5256.
10512.
NET
ANNUALIZED
COST OR CREniT(-)
(000)
22.
58.
161.
497.
1089.
2106.
18.
45.
95.
234.
432.
792.
14.
32.
30.
-28.
-225.
-522.
6.
6.
-102.
-554.
-1539.
-3150.
-10.
-47.
-365.
-1605.
-4167.
-8406.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
72.42
58.11
32.19
24.86
21 .79
21.06
59.28
44.97
19.05
11.72
8.65
7.92
46. 14
31 .83
5.91
-1.42
-4.49
-5.22
19.86
5.55
-20.37
-27.70
-30,77
-31.50
-32.70
-47.01
-72.93
-80.26
-83.33
-84.06
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *2.50/HILLION BTU
CREDIT
0.0000*/1000 SCF
0.03484/1000 SCF
0,0696$/1000 SCF
0.1392*/1000 SCF
0.2784J/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
<000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955,
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
OF'EKATINfi COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
1 .
4.
21.
82.
205.
410.
1 .
4.
21.
82.
205.
410.
1 .
4.
21.
82.
205.
410.
1 .
4.
21.
82.
205.
410.
1 .
4.
21 .
82.
205.
410.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829.
11.
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
18.
46.
102.
261.
498.
923.
13.
28.
10.
-105.
-417.
-906.
7.
10.
-81 .
-471 ,
-1331.
-2735.
-4.
-27.
-264.
-1203.
-3160.
-6394.
-26.
-100.
-630.
-2666.
-6818.
-13710.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
60,59
46.28
20.36
13.03
9.96
9,23
42.30
27.99
2.07
-5.26
-8.33
-9.06
24.01
9.70
-16.22
-23.55
-26.62
-27.35
-12.57
-26.88
-52.81
-60.13
-63,21
-63.94
-85.74
-100.04
-125.97
-133.30
-136.37
-137.10
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAH REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0348$/1000 SCF
0.0696*/1000 SCF
0.1392*/1000 SCF
0.2784*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955,
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42,
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
2.
7.
36.
144.
361 .
722.
2.
7.
36.
144.
361.
722.
2.
7.
36.
144.
361,
722.
7.
36.
144.
361.
722.
2.
7.
36.
144.
361.
722.
0.
0.
0.
0.
0.
0.
5,
18,
91,
366.
915.
1829.
11 .
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633.
19.
49.
117.
323.
654.
1235.
14.
31 .
26.
-43.
-261 .
-594.
8.
13.
-66.
-409.
-1175.
-2423.
-3.
-24.
-248.
-1140.
-3004.
-6081 .
-25.
-97,
-614.
-2603.
-6662.
-13398.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
63.71
49.41
23.48
16.15
13.08
12.35
45.42
31.1?
5.19
-2.14
-5.21
-5.94
27.13
12.82
-13.10
-20.43
-23.50
-24.23
-9.45
-23.76
-49.68
-57.01
-60.08
-60.81
-82.61
-96.9?
-122.85
-130.17
-133.25
-133.98
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0348$/1000 SCF
0.0696*/1000 SCF
0.1392J/1000 SCF
0,2784*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
,513.
3.
11.
57.
228.
569.
1139.
3.
11.
57.
228.
569.
1139.
3.
11.
57.
228.
569.
1139.
3.
11.
57.
228.
569.
1139.
3.
11.
57.
228.
569.
1139.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829.
11 .
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
20.
54.
138.
406.
862.
1651.
15.
35.
47.
41 .
-52.
-178.
9.
17.
-45.
-325.
-967.
-2007.
-2.
-20.
-228.
-1057.
-2796.
-5665.
-24.
-93.
-593.
-2520.
-6454.
-12981.
NET COST
OR SfWINGS(-)
PER SCFM
$/SCFM
67.88
53.57
27.64
20.32
17.24
16.51
49.58
35.28
9.35
2.03
-1.05
-1.78
31.29
16.99
-8.94
-16.27
-19.34
-20.07
-5.29
-19.59
-45.52
-52.85
-55.92
-56.65
-78.45
-92.76
-118.68
-126.01
-129.08
-129.81
I
-------
OFF6AS CARBON REQUIREMENT 6,96 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $2.50/MILLION BTU
CREDIT
O.OOOOt/1000 SCF
0.0348*/1000 SCF
0.0696*/1000 SCF
0.1392*/1000 SCF
0.2784$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
7.
22.
109.
436.
1090.
2180.
7.
22,
109.
436.
1090.
2180.
7.
22,
109.
436.
1090.
2180.
7.
22.
109.
436.
1090.
2180.
7.
22,
109.
436.
1090.
2180.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829.
11 .
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633.
NET
ANNUALIZED
COST OR CREHIT(-)
(000)
23.
64.
190.
614,
1383.
2692.
18.
46.
99.
249.
468.
863.
13.
27,
7.
-117.
-447,
-966.
2.
-9.
-176.
-849.
-2276.
-4624.
-20.
-82.
-541 .
-2312.
-5934.
-11941.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
78.28
63.98
38.05
30.72
27.65
26.92
59.99
45.69
19.76
12.43
9.36
8.63
41 .70
27.39
1.47
-5.86
-8.93
-9.66
5.12
-9.19
-35.11
-42.44
-45.51
-46.24
-68.04
-82.35
-108.28
-115,60
-118.68
-119.41
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREIHT
0.0000*/1000 SCF
0.0400t/1000 SCF
0.0800t/1000 SCF
0.1600*/1000 SCF
0.32004/1000 SCF
OFFGAS
FLOW
SCFM
300,
1000.
5000.
20000.
50000.
100000.
300,
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955,
1671.
58.
144,
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
1 .
5.
23.
91.
228.
457.
23.
91.
228.
457.
1 .
5.
23.
91.
228.
457.
1 .
5.
23.
91.
228.
457.
1 ,
5.
23.
91.
228.
457.
0,
0.
0.
0.
0.
0.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
25.
84.
420.
1682.
4205.
8410.
50.
168.
841 .
3364.
8410.
16819.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
18.
47.
104.
270.
521.
970.
12.
26.
-1 .
-151.
-530.
-1133.
6.
5 .
-106.
-571 .
-1581.
-3235.
-7.
-37.
-316.
-1412,
-3684.
-7440.
-32.
-121.
-737.
-3094.
-7888.
-15850,
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
61 .06
46.75
20.82
13.50
10.42
9.70
40.03
25.73
-0,20
-7.53
-10.60
-11.33
19.01
4.70
-21.22
-28.55
-31.62
-32.35
-23.04
-37.35
-63.27
-70.60
-73.67
-74.40
-107.14
-121.44
-147.37
-154.69
-157.77
-158.50
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAh/ LB CARBON
AT $2.SO/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFh
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
<000) <000) (000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
t/SCFM
0.0000*71000 SCF
0.0400*71000 SCF
0.0800*71000 SCF
0.1600*71000 SCF
0.3200*71000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300,
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
38.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179.
293.
513,
17.
42.
81.
179.
293.
513.
17,
42,
81.
179.
293.
513.
17.
42.
81,
179.
293.
513.
17.
42.
81 .
179.
293.
513.
8.
41.
163.
408.
816,
2.
8.
41 .
163.
408.
816.
2.
8.
41 .
163,
408.
816.
2.
8.
41 ,
163,
408.
816.
2.
8.
41 .
163.
408.
816.
0.
0.
0.
0.
0.
0.
6.
21.
105.
420.
1051 .
2102.
13.
42.
210.
841 .
2102.
4205.
25.
84.
420.
1682,
4205.
8410.
50.
168.
841.
3364,
8410.
16819.
19.
50.
122.
342.
701 .
1328.
13.
29.
17.
-79.
-351 .
-774.
7.
8.
-88.
-499.
-1402.
-2876.
-6.
-34.
-298.
-1340.
-3504.
-7081.
-31 .
-118.
-719.
-3022.
-7709.
-15491.
64.65
50.34
24.41
17.09
14.01
13.28
43.62
29.32
3.39
-3.94
-7.01
-7.74
22.60
8.29
-17.63
-24.96
-28.04
-28,76
-19.45
-33.76
-59.68
-67.01
-70.08
-70.81
-103.55
-117.85
-143.78
-151.11
-154.18
-154.91
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1,0 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREniT
0,00004/1000 SCF
0.0400*/1000 SCF
0.0800*/1000 SCF
0.1600$/1000 SCF
0.3200J/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17,
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
4.
13.
65.
259.
647.
1294.
4.
13.
65.
259.
647.
1294.
4.
13.
65.
259.
647.
1294.
4.
13.
65.
259.
647.
1294.
4.
13.
65.
259.
647.
1294,
0.
0.
0.
0.
0.
0.
6.
21.
105.
420.
1051 .
2102.
13.
42.
210.
841.
2102.
4205.
25.
84.
420.
1682.
4205.
8410.
50.
168.
841 ,
3364.
8410.
16819.
21.
55.
146.
437.
940.
1807.
15.
34,
41 .
17.
-Ill .
-296.
8.
13.
-64.
-404.
-1163.
-2398.
-4.
-29.
-274,
-1244.
-3265.
-6603.
-30.
-113.
-695.
-2926.
-7470.
-15012.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
69.43
55.12
29.20
21.87
18.80
18.07
48.41
34.10
8. 17
0.85
-2.23
-2.96
27.38
13.08
-12.85
-20.18
-23.25
-23.98
-14.67
-28.97
-54.90
-62.22
-65.30
-66.03
-98.76
-113.07
-138.99
-146.32
-149.39
-150,12
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $2.50/MILLION BTU
CREDIT
O.OOOOt/1000 SCF
0.0400*/1000 SCF
0.0800t/1000 SCF
0.1600$/1000 SCF
0.3200$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300,
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
<000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) <000)
17.
42.
81.
179.
293,
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81.
179.
293,
513.
17.
42.
81.
179.
293,
513.
7.
25.
125.
498.
1245.
2491.
7.
25.
125.
498.
1245.
2491.
7.
25.
125.
498.
1245.
2491.
7.
25.
125.
498.
1245.
2491.
7.
25.
125.
498.
1245.
2491.
0.
0.
0.
0.
0.
0.
6.
21.
105.
420.
1051 .
2102.
13.
42.
210.
841.
2102.
4205.
25.
84.
420.
1682.
4205.
8410.
50.
168.
841.
3364.
8410.
16819.
NET
ANNUALIZED
COST OR CREDIT<->
(000)
24.
67.
206.
677.
1538.
3003.
18.
46.
101.
256.
487.
901.
12.
25.
-4.
-164.
-564.
-1202.
-1.
-17.
-215.
-1005.
-2667.
-5406.
-26.
-101.
-635.
-2687.
-6872.
-13816.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
81 .39
67.09
41 . 16
33.83
30.76
30.03
60.37
46.06
20.14
12.81
9.74
9.01
39.35
25.04
-0.89
-8.21
-11.29
-12.02
-2.70
-17.01
-42.94
-50.26
-53.34
-54.06
-86.80
-101.11
-127.03
-134.36
-137.43
-138.16
-------
OFFGAS CARBON REQUIREMENT 10.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT »2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0,2000*/1000 SCF
0.4000S/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81 .
179.
293,
513.
2.
5.
27.
109.
273.
547.
27.
109.
273.
547.
2.
5.
27.
t09,
273.
547.
2.
5.
27.
109.
273.
547.
27.
109.
273.
547.
0.
0.
0.
0.
0.
0.
8.
26,
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102,
5256.
10512.
63.
210.
1051 .
4205.
10512.
21024,
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
19.
48.
109.
288.
566.
1059.
11 .
21 .
-23.
-238.
-748.
-1569.
3.
-5.
-154 .
-763.
-2062.
-4197.
-13.
-57.
-417.
-1814.
-4690.
-9453.
-44.
-163.
-943.
-3917.
-9946.
-19965.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
61.95
47.65
21 .72
14.40
11.32
10.59
35.67
21.37
-4.56
-11.88
-14.96
-15,69
9.39
-4.91
-30.84
-38, 16
-41.24
-41.97
-43.17
-57.47
-83.40
-90.72
-93.80
-94.53
-148.29
-162.59
-188.52
-195.84
-198.92
-199.65
-------
OFFGAS CARBON REQUIREHENTIO,00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000$/1000 SCF
0,0500*/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
0.4000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000,
50000.
100000,
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81,
179.
293.
513.
17.
42,
81 ,
179.
293.
513.
17.
42.
81.
179.
293.
513.
17,
42.
81.
179,
293.
; 513.
3.
10.
50.
199.
498.
995.
3.
10.
50.
199.
498,
995.
3.
10.
50.
199.
498.
995.
3.
10.
50.
199.
498.
995.
3.
10.
50.
199.
498.
995.
0.
0,
0,
0.
0.
0.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051.
4205.
10512.
21024.
20.
52.
131.
378.
790.
1508.
12.
26.
-0.
-148.
-524.
-1120.
4.
-0.
-132.
-674,
-1838.
-3748.
-12.
-53.
-395.
-1725.
-4466.
-9004.
-43.
-158.
-920.
-3827.
-9722.
-19516.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
66.44
52.13
26.21
18.88
15.81
15.08
40.16
25.85
-0.07
-7.40
-10.47
-11.20
13.88
-0.43
-26.35
-33.68
-36.75
-37.48
-38.68
-52.99
-78.91
-86.24
-89.31
-90.04
-143.80
-158.11
-184.03
-191.36
-194,43
-195.16
-------
OFFGAS CARBON REQUIREMENT10.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0500$/1000 SCF
0.1000*/1000 SCF
0.20004/1000 SCF
0.40001/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CfiEDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17,
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
5.
16.
80.
319.
797.
1593,
5.
16.
80.
319.
797.
1593.
5.
16.
80.
319.
797.
1593.
5.
16.
80,
319.
797,
1593.
5.
16.
80.
319.
797 .
1593.
0.
0.
0.
0.
0.
0.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051.
4205.
10512.
21024.
22.
58.
161 .
497.
1089.
2106.
14.
32.
30.
-28.
-225.
-522.
6.
6.
-102.
-554.
-1539.
-3150.
-10.
-47.
-365,
-1605.
-4167,
-8406.
-41 .
-152.
-890.
-3708,
-9423.
-18918.
NET COST
OR SAVINGS!-)
PER SCFM
*/SCFh
72.42
58.11
32.19
24.86
21 .79
21.06
46. 14
31.83
5.91
-1.42
-4.49
-5.22
19.86
5.55
-20.37
-27.70
-30.77
-31.50
-32.70
-47.01
-72.93
-80.26
-83.33
-84.06
-137.82
-152.13
-178.05
-185.38
-188.45
-189.18
-------
OFFGAS CARBON REQUIREMENTIO.OO LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $2.50/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0500*/1000 SCF
0.1000$/1000 SCF
0.2000$/1000 SCF
0.4000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CRECHT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
9.
31.
154.
618.
1544.
3089.
9.
31.
154.
618.
1544.
3089.
9.
31.
154.
618.
1544.
3089.
9.
31.
154.
618.
1544.
3089.
9.
31.
154.
618.
1544.
3089.
0.
0.
0.
0.
0.
0.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051.
4205.
10512.
21024.
26.
73.
236.
796.
1837.
3601.
18,
47.
104.
271.
523.
973.
10.
21.
-27.
-255.
-791 .
-1655.
-5.
-32.
-290.
-1306.
-3419.
-6911.
-37.
-137.
-815.
-3408.
-8675.
-17423.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
87.37
73.07
47. 14
39.82
36.74
36.01
61 .09
46.79
20.86
13.54
10.46
9.73
34.81
20.51
-5.42
-12.74
-15.82
-16.55
-17.75
-32.05
-57.98
-65.30
-68.38
-69.11
-122.87
-137. 17
-163.10
-170.42
-173.50
-174.23
-------
OFFOAS CARBON REQUIREMENT 0,10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *5.00/MILLir)N BTU
CREDIT
0.0000*/1000 SCF
0.0005*/1000 SCF
0.0010*71000 SCF
0.0020*/1000 SCF
0.0040*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZEC
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293,
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
0.
1.
5.
21.
53.
106.
0.
1.
5.
21.
53.
106.
0.
1 .
5.
21 .
53.
106.
0.
1.
5.
21.
53.
106.
0.
1.
5.
21.
53.
106.
0.
0.
0.
0.
0.
0.
0.
0.
1.
5.
13.
26.
0.
1.
3.
11.
26.
53.
0.
1.
5.
21.
53.
105.
1 ,
2.
11 .
42.
105.
210.
17.
43.
97.
200.
346.
619.
17.
43.
85.
195.
333.
593.
17.
43.
84.
189.
320.
566.
17.
42.
81 .
179.
293.
514.
17.
41 .
76.
158.
241.
409.
NET COST
OR SAVINGS(-)
PER SCFM
t/SCFM
57.55
43.24
17.32
9.99
6.92
6.19
57.29
42.98
17.06
9,73
6,66
5.93
57.03
42.72
16.79
9.47
6.39
5.66
56.50
42.19
16.27
8.94
5.87
5.14
55.45
41,14
15.22
7.89
4.82
4.09
-------
OFFGAS CARBON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *5.00/MILLION BTll
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
t/SCFM
O.OOOOt/1000 SCF
0.0005$/1000 SCF
0.0010*/1000 SCF
0.0020$/1000 SCF
0.0040*/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
0.
1.
6.
23.
57.
115.
0.
1.
6.
23.
57.
115.
0.
1,
6.
23.
57.
115.
0.
1.
6.
23.
57.
115.
0.
1.
6.
23.
57.
115.
0.
0.
0.
0.
0.
0.
0.
0.
1 .
5.
13.
26.
0.
1.
3.
11.
26.
53.
0.
1 .
5.
21,
53.
105.
1 .
2,
11.
42.
105.
210.
17.
43.
87.
202.
350.
627.
17.
43.
86.
196.
337.
601 .
17.
43.
84.
191.
324.
575.
17.
42.
82.
180.
298.
522.
17.
41.
76.
159.
245.
417.
57.63
43.33
17.40
10.08
7.00
6.27
57.37
43.06
17.14
9.81
6.74
6.01
57.11
42.80
16.88
9.55
6.48
5.75
56.58
42.28
16.35
9.02
5.95
5.22
55.53
41 .2:1
15.30
7.97
4.90
4.17
-------
OFFGAS CARBON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT $5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0005$/1000 SCF
0.0010*/1000 SCF
0.0020*/1000 SCF
0.0040*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58,
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES
"
(000)
(000)
17.
42.
81.
179.
293.
513.
17.
42,
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
0.
1.
6.
25.
63.
126,
0.
1.
6.
25.
63.
126.
0.
1.
6.
25.
63.
126.
0.
1.
6.
25.
63.
126.
0.
1.
6.
25.
63.
126.
NET
RECOVERY ANNUALIZED
CREDIT COST OR CREDIT(-)
<000) (000)
0.
0.
0.
0.
0.
0.
0.
0,
1.
5.
13.
26.
0.
1.
3.
11.
26.
53.
0.
1 .
5,
21.
53.
105.
1 .
2.
11.
42.
105.
210,
17.
43.
88.
204.
356.
638.
17.
43.
86.
198.
342.
612.
17.
43.
85.
193.
329.
586.
17.
42.
82.
183.
303.
533.
17.
41.
77.
162.
250.
428.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
57.75
43.44
17.51
10.19
7.11
6.38
57.48
43.18
17.25
9.92
6.85
6.12
57.22
42.9t
16.99
9.66
6.59
5.86
56.69
42.39
16.46
9.13
6.06
5.33
55.64
41.34
15.41
8.08
5.01
4.28
-------
OFFGAS CARBON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $5.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAVINGS<->
PER SCFM
*/SCFM
0.0000*/1000 SCF
0.0005*/1000 SCF
0.0010*/1000 SCF
0.0020*/1000 SCF
0.0040*/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58,
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179,
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81.
179.
293.
513.
0.
2.
8.
31.
77.
153.
0.
2.
8.
31.
77.
153.
0.
2.
8.
31.
77.
153.
0.
2.
8.
31.
77.
153.
0.
2.
8.
31.
77.
153.
0.
0,
0.
0.
0.
0.
0.
0,
1.
5.
13.
26.
0.
1.
3.
11 .
26.
53.
0.
1.
5 *
21 .
53.
105.
1.
2.
11.
42.
105.
210.
17.
44.
89.
209.
369.
666.
17.
43.
88.
204.
356.
640.
17.
43,
86.
199.
343.
613.
17.
43.
84.
188.
317.
561.
17.
42.
78.
167.
264.
456.
58.02
43.72
17.79
10.46
7.39
6.66
57.76
43,45
17.53
10.20
7.13
6.40
57.50
43.19
17.26
9.94
6.86
6.13
56.97
42.66
16.74
9.41
6.34
5.61
55,92
41.61
15.69
8.36
5.29
4.56
-------
OFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0025*/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200t/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREIHT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17,
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
0.
1.
7.
28.
70.
]40.
0.
1.
7.
28.
70.
140.
0.
1,
7.
28,
70.
140.
0.
1.
7.
28.
70.
140.
0.
1.
7.
28.
70.
140.
0.
0.
0.
0.
0.
0.
0.
1.
7.
26.
66.
131.
1.
3.
13.
53.
131.
263.
2.
5.
26,
105.
263.
526,
3.
11.
53.
210.
526.
1051.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
17.
44.
88.
206.
363.
652.
17.
42.
82.
180.
297.
521.
17.
41.
75.
154.
231.
389.
16.
38.
62.
101.
100.
127.
14.
33,
36.
-4.
-163.
-399.
NET COST
OR SAYINGS(-)
PER SCFM
t/SCFM
57.88
43.58
17.65
10.32
7.25
6.52
56.57
42.26
16.34
9.01
5.94
5.21
55.26
40.95
15.02
7.70
4.62
3.89
52.63
38.32
12.39
5.07
1.99
1.27
47.37
33.06
7. 14
-0.19
-3.26
-3,99
-------
OFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0025*/1000 SCF
0.0050$/1000 SCF
0.0100$/1000 SCF
0.0200$/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300,
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58,
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
1 .
2.
9.
36.
91 .
181.
1.
2.
9.
36.
91.
181.
1.
2.
9.
36.
91.
181.
1,
2.
9.
36.
91.
181.
1.
2.
9.
36.
91.
181.
0.
0.
0.
0.
0.
0.
0.
1.
7.
26.
66.
131.
1 .
3.
13.
53.
131.
263.
2.
5.
26.
105.
263.
526.
3.
11 .
53.
210.
526.
1051.
17.
44.
90.
215.
383.
694.
17.
43,
84.
189.
318.
562.
17.
41 .
77.
162.
252.
431.
16.
39.
64.
110,
121 .
168.
14.
33.
38.
5.
-142,
-357.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
58.30
43.99
18.07
10.74
7.67
6.94
56.99
42.68
16.75
9.43
6.35
5.62
55.67
41 .36
15.44
8.11
5.04
4.31
53.04
38.74
12.81
5.48
2.41
1.68
47.79
33.48
7.55
0.23
-2,85
-3.57
-------
OFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0025*/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200J/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955,
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
1 .
2.
12.
47.
118.
237.
12.
47.
118.
237.
12.
47.
118.
237.
12.
47.
118.
237.
1.
2 t
12.
47.
118.
237.
0.
0.
0.
0.
0.
0.
0.
1 ,
7.
26.
66.
131.
1 .
3.
13.
53.
131.
263.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
18.
45.
93.
226.
411 .
749.
17.
43.
87.
200.
345.
618.
17.
42.
80.
173.
280.
486.
16.
39.
67.
121 .
148.
224.
15.
34.
41 .
16.
-115.
-302,
NET COST
OR SAVINGS*-)
PER SCFM
*/SCFM
58.85
44.55
18.62
11.29
8.22
7.49
57.54
43.23
17.31
9.98
6.91
6.18
56.23
41.92
15.99
8.67
5.59
4.86
53.60
39.29
13.36
6.04
2.96
2.24
48.34
34.03
8.11
0.78
— 2,29
-3.02
-------
OFFGAS CARBON REQUIREMENT 0,50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *5,00/MILLION BTU
CREDIT
0,0000*/1000 SCF
0.0025$/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955,
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42,
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81,
179.
293.
513.
1 .
4.
19.
75.
188.
375.
1.
4.
19.
75.
188.
375,
1.
4,
19.
75.
188.
375.
1.
4.
19.
75,
188.
375.
1.
4,
19.
75,
188.
375.
0.
0.
0.
0.
0.
0,
0.
1 .
7.
26.
66.
131.
1 .
3.
13.
53.
131 .
263.
5.
26.
105,
263.
526.
3.
11.
53.
210.
526.
1051.
18.
46.
100.
254.
480.
888.
18.
45,
93.
227.
415.
756.
17.
43.
87.
201 .
349.
625.
16.
41.
74.
148.
217.
362.
15.
35.
47,
43.
-45.
-164.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
60.24
45.93
20.01
12.68
9.61
8.88
58.92
44,62
18.69
11.37
8.29
7.56
57.61
43.30
17.38
10.05
6.98
6.25
54.98
40.68
14.75
7.42
4.35
3.62
49.73
35.42
9.49
2.17
-0.91
-1 .64
-------
OFFGAS CARBON REQUIREMENT 1,00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT tS.OO/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200$/1000 SCF
0.0400*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREHIT COST OR CREIHT(-)
(000) (000> (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42,
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
1.
2.
9.
36.
91 .
181.
1.
2.
9.
36,
91.
181.
1 .
2.
9.
36.
91 .
181 .
1.
2.
9.
36.
91.
181 .
1.
1
9.
36,
91.
181.
0.
0.
0.
0.
0.
0,
1 .
3.
13.
53.
131.
263.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21 .
105.
420.
1051.
2102.
17.
44.
90.
215.
383.
694.
17.
41 .
77.
162.
252.
431 .
16.
39.
64.
110.
121.
168.
14.
33.
38.
5.
-142.
-357.
11 .
23.
-15.
-206.
-668.
-1409.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
58.30
43.99
18.07
10.74
7.67
6.94
55.67
41 .36
15.44
8.11
5.04
4.31
53.04
38.74
12.81
5.48
2.41
1.68
47.79
33.48
7.55
0.23
-2.85
-3.57
37.28
22.97
-2.96
-10.28
-13.36
-14.09
-------
OFFGAS CARBON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200$/1000 SCF
0.0400$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300,
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81,
179.
293.
513.
1.
3.
13.
53.
132,
264.
1.
3.
13.
53,
132.
264.
1.
3.
13.
53.
132.
264.
1.
3.
13.
53.
132.
264.
1 .
3.
13.
53.
132.
264.
0.
0.
0.
0.
0.
0.
1 .
3.
13.
53,
131 .
263.
5.
26.
105.
263.
526.
3.
11 .
53.
210,
526.
1051.
6.
21.
105,
420.
1051.
2102.
18.
45.
94.
231 .
425.
777,
17.
42.
81 .
179.
293.
514.
16.
40.
68.
126.
162.
251.
15.
34.
42.
21.
-101 .
-274.
11.
24.
-11 .
-189.
-626.
-1326,
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
59.13
44.82
18.90
11 .57
8.50
7.77
56.50
42.20
16.27
8.94
5.87
5.14
53.87
39.57
13.64
6.32
3.24
2.51
48.62
34.31
8.39
1,06
-2.01
-2.74
38. 11
23.80
-2. 13
-9.45
-12.53
-13.26
-------
OFFGAS CARBON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1,0 LB STEAM/ LB CARBON
AT $5,00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.00504/1000 SCF
0.0100$/1000 SCF
0.0200$/1000 SCF
0.0400t/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671,
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
OPERATING COST-OR-CREPIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513,
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
61 .
179.
293.
513.
1.
4.
19.
75.
188.
375.
1 .
4,
19.
75.
188.
375.
1.
4.
19.
75.
188.
375.
1 .
4.
19.
75.
188.
375.
1.
4.
19.
75.
188.
375.
0.
0.
0.
0.
0.
0.
1.
3.
13.
53.
131.
263.
5.
26.
105.
263.
526.
3.
11 .
53.
210.
526.
1051.
6.
21 .
105.
420.
1051.
2102.
18.
46.
100.
254.
480.
888.
17.
43.
87,
201.
349.
625.
16.
41 .
74.
148.
217.
362.
15.
35.
47.
43.
-45.
-164.
12.
25.
~ \J *
-167.
-571 .
-1215.
NET COST
OR SAYINGS(-)
PER SCFM
*/SCFM
60.24
45.93
20.01
12.68
9.61
8.88
57.61
43.30
17.38
10.05
6.98
6.25
54.98
40.68
14.75
7.42
4,35
3.62
49.73
35.42
9.49
2.17
-0.91
-1 .64
39.21
24.91
-1 .02
-8.34
-11.42
-12.15
-------
OFFGAS CARBON REQUIREMENT 1,00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $5.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREIHT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAYINGS(-)
PER SCFM
$/SCFM
0.0000*/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200$/1000 SCF
0.0400$/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000,
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513,
17,
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
2.
7.
33.
130.
326.
652.
2.
7.
33.
130.
326.
652.
2.
7.
33.
130.
326.
652.
2.
7,
33,
130.
326.
652.
2.
7.
33.
130,
326,
652.
0.
0.
0.
0.
0.
0.
1.
3.
13.
53.
131,
263.
2.
5.
26.
105.
263.
526.
3.
11.
53,
210.
526.
1051 ,
6.
21.
105.
420.
1051 ,
2102.
19.
49.
114.
309.
619.
1165.
18.
46.
101 .
256.
487.
902.
17.
43,
88.
204.
356.
639.
16.
38.
61.
99.
93.
113.
13.
28.
9.
-112.
-432.
-938.
63.01
48.70
22.78
15.45
12.37
11 .65
60.38
46.07
20.15
12.82
9.75
9.02
57.75
43.45
17.52
10.19
7.12
6.39
52.50
38.19
12.26
4.94
1 .86
1.13
41 .98
27.68
1 .75
-5.58
-8.65
-9.38
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0,3 LB STEAM/ LB CARBON
AT tS.OO/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0070*/1000 SCF
0.0139*/1000 SCF
0.0279*/1000 SCF
0.0557$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREUIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513,
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
1.
2.
11.
43.
107.
214.
1.
2.
11.
43.
107.
214.
11 .
43.
107.
214.
1 .
2.
11 .
43.
107.
214.
1 .
2,
11 .
43.
107.
214.
0.
0.
0.
0.
0.
0.
1 .
4.
18.
73.
183.
366.
2.
7.
37.
146.
366.
732.
4.
15.
73.
293.
732.
1464.
9.
29.
146.
586.
1464.
2929.
18.
44.
92.
221.
400.
726.
16.
41 .
74.
148.
217.
360.
15.
37.
55.
75.
34.
-6.
13.
30.
19.
-72,
-333.
-738.
9.
15.
-54.
-364.
-1065,
-2202.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
58.63
44.32
18.39
11 .07
7.99
7.26
54.96
40.66
14.73
7.41
4.33
3.60
51.30
37.00
11.07
3.75
0.67
-0.06
43.98
29.68
3.75
-3.58
-6.65
-7.38
29.34
15.03
-10.89
-18.22
-21.29
-22.02
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT »5.00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0070$/1000 SCF
0.0139*/1000 SCF
0.0279*/1000 SCF
0.0557*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17. 1. 0.
42. 3. 0.
81, 16. 0.
179. 66, 0.
293. 165. 0.
513. 330. 0.
17. 1. 1.
42. 3. 4.
81. 16. 18.
179. 66. 73.
293. 165. 183.
513. 330. 366.
17. 1. 2.
42. 3. 7.
81. 16. 37.
179. 66. 146.
293. 165, 366.
513. 330. 732.
17. 1. 4.
42. 3. 15.
81. 16. 73,
179. 66. 293.
293, 165. 732.
513. 330. 1464.
17. 1, 9.
42. 3. 29.
81. 16. 146.
179. 66. 586.
293, 165. 1464.
513. 330. 2929.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
18.
45.
98.
244.
458.
842.
17.
42.
79.
171.
274.
476.
16.
38.
61.
98.
91 .
110.
14.
31.
25.
-48.
-275.
-622.
9.
16.
-49.
-341.
-1007.
-2087.
NET COST
OR SAWINGS(-)
PER SCFM
*/SCFM
59.78
45.48
19.55
12.22
9. 15
8.42
56. 12
41 .82
15.89
8.56
5.49
4.76
52.46
38.15
12.23
4.90
1.83
1 .10
45.14
30.83
4.91
-2.42
-5.49
-6.22
30.50
16.19
-9.74
-17.06
-20.14
-20.87
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0070*/1000 SCF
0.0139$/1000 SCF
0.0279*/1000 SCF
0.0557$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000,
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81,
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
1.
5.
24.
97.
242.
484.
1 .
5,
24.
97.
242.
484.
1.
5.
24.
97.
242.
484.
1.
5.
24.
97.
242.
484.
1.
5.
24.
97.
242.
484.
0.
0.
0.
0.
0.
0.
1 .
4.
18.
73.
183.
366.
2.
7.
37.
146.
366.
732.
4.
15.
73.
293.
732.
1464.
9.
29.
146.
586.
1464.
2929.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
18,
47.
105.
275.
535.
996.
17.
43.
87.
202.
352.
630.
16.
40.
69.
129.
169.
264.
14.
32.
32.
-18.
-197.
-468.
10.
18.
-41 .
-310.
-930,
-1932,
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
61.33
47.02
21 .09
13.77
10.69
9.96
57.67
43.36
17.43
10.11
7.03
6.30
54.00
39.70
13.77
6.45
3.37
2.64
46.68
32.38
6.45
-0.88
-3.95
-4.68
32.04
17.73
-8.19
-15.52
-18.59
-19.32
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAh REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
FIXED
COST
(000)
OPERATING COST-OR-CREDIT
UTILITIES
(000)
NET
RECOVERY ANNUALIZED
CREDIT COST OR CREDIT(-)
(000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
J/SCFM
0.0000$/1000 SCF
0.0070$/1000 SCF
0.0139*/1000 SCF
0.0279$/1000 SCF
0.0557$/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81 .
179,
293.
513.
17.
42,
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513,
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
. 513.
3.
9.
43.
174,
435.
870.
3.
9.
43.
174.
435.
870.
3.
9.
43.
174.
435.
870.
3.
9.
43.
174.
435.
870.
3.
9.
43.
174.
435.
870.
0.
0.
0.
0.
0.
0.
1.
4.
18.
73.
183.
366.
2.
7.
37.
146.
366.
732.
4.
15.
73,
293.
732.
1464.
9.
29.
146.
586.
1464.
2929.
20.
51 .
125.
353.
728.
1382.
16.
47,
106.
279.
545.
1016.
17.
44.
88.
206.
362.
650.
15.
36.
52.
60.
-5.
-82.
11 .
22.
-22.
-233.
-737.
-1546,
65.19
50.88
24.95
17.63
14.55
13.82
61 .52
47.22
21.29
13,97
10.89
10.16
57.86
43.56
17.63
10.30
7.23
6.50
50.54
36.24
10.31
2.96
-0.09
-0.82
35.90
21 .59
-4.33
-11.66
-14.73
-15.46
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0100*/1000 SCF
0.0200*/1000 SCF
0.0400*/1000 SCF
0.0800*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CRFDIT(-)
(000) (000) <000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81,
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293,
, 513.
1 .
3.
13.
53.
132.
264.
1 .
3.
13.
53.
132.
264.
1 .
3.
13.
53.
132.
264.
1.
3.
13.
53.
132.
264.
1.
3.
13.
53.
132.
264.
0.
0.
0.
0.
0.
0.
2.
5,
26.
105.
263.
526.
3.
11 .
53.
210.
526.
1051.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841 .
2102.
4205.
18.
45.
94.
231.
425.
777.
16.
40.
68.
126.
162.
251.
15.
34,
42.
21.
-101 .
-274,
11 .
24,
-11.
-189.
-626.
-1326.
5.
3.
-116.
-610,
-1678.
-3428.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCF«
59.13
44.82
18.90
11 .57
8.50
7.77
53.87
39.57
13.64
6.32
3.24
2.51
48.62
34.31
8.39
1.06
-2.01
-2.74
38.11
23.80
-2.13
-9.45
-12.53
-13.26
17.08
2.78
-23,15
-30.48
-33.55
-34.28
-------
OFFGAS CARBON REQUIREMENT 2,00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0100$/1000 SCF
0.0200*/1000 SCF
0.04004/1000 SCF
0.0800$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
<000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREniT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) <000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
1.
4.
22.
86.
215.
430,
1 ,
4.
22.
86.
215.
430.
1 .
4.
22.
86,
215.
430.
1 .
4.
22,
86.
215,
430.
1.
4.
22.
86.
215.
430.
0.
0.
0.
0.
0.
0.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21.
105,
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
18.
46.
103.
265.
508.
943.
17,
41 .
77.
160.
245.
417.
15.
36.
50.
54.
-18.
-108.
12.
25.
-2.
-156.
-543.
-1159.
6.
4.
-107.
-576.
-1594.
-3262.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
60,79
46.49
20.56
13.23
10. 16
9.43
55.54
41 .23
15.30
7.98
4.90
4.17
50.28
35.97
10.05
2.72
-0.35
-1 .08
39.77
25.46
-0.46
-7.79
-10.86
-11.59
18.74
4.44
-21.49
-28.81
-31.89
-32.62
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON/1000 SCF
STEAH REGENERATION RATIO 1.0 LB STEAH/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0,0000*71000 SCF
0.0100*71000 SCF
0.0200*71000 SCF
0.0400*71000 SCF
0.0800*71000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
<000)
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671,
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) <000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17,
42,
81.
179.
293.
513.
17.
42.
81.
179.
293.
> 513,
2.
7.
33.
130.
326.
652.
2.
7.
33.
130.
326.
652.
2.
7.
33.
130.
326.
652.
2.
7.
33.
130.
326,
652.
2.
7,
33,
130.
326.
652.
0.
0.
0.
0.
0.
0.
5.
26.
105.
263,
526.
3.
11 .
53.
210.
526.
1051.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841,
2102.
4205,
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
19.
49.
114.
309.
619.
1165.
17.
43.
88.
204.
356.
639.
16.
38.
61 .
99.
93.
113.
13.
28.
9.
-112.
-432.
-938.
6.
7.
-96.
-532.
-1484.
-3040.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
63.01
48.70
22.78
15.45
12.37
11.65
57.75
43.45
17.52
10.19
7.12
6.39
52.50
38.19
12.26
4.94
1.86
1.13
41.98
27.68
1.75
-5.58
-8.65
-9.38
20.96
6.65
-19.27
-26.60
-29.67
-30.40
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0100*/1000 SCF
0.0200$/1000 SCF
0.0400*/1000 SCF
0.0800*/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513,
17.
42.
81 .
179.
293.
513.
4.
12.
60.
241.
603.
1206.
4.
12,
60.
241.
603.
1206.
4.
12.
60.
241.
603.
1206.
4,
12.
60.
241.
603.
1206.
4.
12.
60.
241.
603.
1206.
0.
0.
0.
0.
0.
0.
2,
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21.
105.
420.
1051 .
2102.
13.
42.
210.
841.
2102.
4205.
21.
54.
142.
420.
896.
1719.
19.
49.
115.
315.
633.
1193.
17.
44.
89,
210,
370,
667,
14,
33,
36,
-1.
-155.
-384.
8.
12.
-69.
-421.
-1207.
-2486.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
68.55
54.24
28.32
20.99
17.91
17.19
63.29
48.99
23.06
15.73
12.66
11 .93
58.04
43.73
17.80
10.48
7.40
6.67
47.52
33.22
7.29
-0.04
-3.11
-3.84
26.50
12.19
-13.73
-21.06
-24.13
-24.86
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAh/ LB CARBON
AT $5.00/MILLION BTU
CREDIT
O.OOOOt/1000 SCF
0.0250*/1000 SCF
0.0500*/1000 SCF
0.1000*71000 SCF
0.2000*71000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000,
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58,
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIX£D UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
2.
5.
26.
103.
257.
514.
2.
5.
26.
103.
257.
514,
2.
5.
26.
103.
257.
514.
2.
5.
26.
103.
257.
514.
2.
5.
26.
103.
257.
514.
0.
0.
0.
0.
0.
0.
4.
13.
66.
263.
657.
1314.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
18.
47.
107.
281.
550.
1026.
15.
34.
41.
18.
-107.
-288.
11.
21 .
-24.
-244.
-764.
-1602.
3.
— 5.
-156.
-770.
-2078.
-4230.
-13.
-58.
-419.
-1821 .
-4706.
-9486,
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
61.62
47.32
21.39
14.06
10.99
10.26
48.48
34.18
8.25
0.92
-2.15
-2.88
35.34
21.04
-4.89
-12.22
-15.29
-16.02
9.06
-5.24
-31.17
-38.50
-41.57
-42.30
-43.50
-57.80
-83.73
-91.06
-94.13
-94.86
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
0.0000$/1000 SCF
0.0250*/1000 SCF
0.0500*/1000 SCF
0,1000*/1000 SCF
0.2000*/1000 SCF
300.
1000.
5000.
20000.
50000.
100000,
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
, 513.
3.
9.
46.
186.
464,
929.
3.
9.
46.
186.
464.
929.
3.
9.
46.
186.
464,
929.
3.
9.
46.
186.
464.
929.
3.
9.
46.
186,
464.
929.
0.
0.
0.
0.
0.
0.
4.
13.
66.
263.
657.
1314.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
20.
51.
128.
364.
757.
1442.
16.
38,
62.
102.
100.
128.
12.
25.
-4.
-161 .
-557.
-1186.
4.
-1.
-135.
-687.
-1871 .
-3814.
-12.
-54.
-398.
-1738.
-4499.
-9070.
65.78
51 .47
25.55
18.22
15.14
14.42
52.64
38.33
12.41
5.08
2.00
1.28
39.50
25.19
-0.73
-8.06
-11.14
-11.86
13.22
-1.09
-27.01
-34.34
-37.42
-38.14
-39.34
-53.65
-79.57
-86.90
-89.98
-90.70
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0250*/1000 SCF
0.0500t/1000 SCF
0.10004/1000 SCF
0,2000$/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671 .
58.
144.
273.
594.
955.
1671 .
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
> 513.
4.
15.
74.
297 .
741 .
1483.
4.
15.
74.
297.
741.
1483.
4.
15.
74,
297.
741.
1483.
4.
15,
74.
297.
741 ,
1483.
4.
15.
74.
297.
741,
1483.
0.
0.
0.
0.
0.
0.
4.
13.
66.
263.
657.
1314.
8.
26.
131.
526.
1314.
2628.
16.
53,
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
21 .
57.
155.
475.
1034.
1996.
17.
44.
90.
212.
377.
682.
14.
31.
24.
-50.
-280.
-632,
6,
4.
-107.
-576.
-1594.
-3260.
-10.
-48.
-370.
-1627.
-4222.
-8516.
NET COST
OR SAVINGS(-)
PER SCFM
t/SCFM
71.32
57.01
31.09
23.76
20.68
19.96
58. 18
43.87
17.95
10.62
7.54
6.82
45.04
30.73
4,81
- ° * 52
-5.60
-6.32
18.76
4.45
-21.47
-28.80
-31.88
-32.60
-33.80
-48. 11
-74.03
-81 .36
-84.44
-85.16
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0,0250*/1000 SCF
0.0500$/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58,
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955,
1671.
58.
144.
273.
594.
955,
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293,
513.
17,
42.
81,
179,
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293,
513.
17,
42.
81,
179.
293,
513,
9,
29.
143.
574.
1434.
2868.
9.
29.
143.
574.
1434.
2868.
9.
29.
143.
574.
1434.
2868.
9.
29.
143.
574.
1434.
2868.
9.
29.
143.
574.
1434.
2868.
0.
0.
0.
0.
0.
0.
4.
13.
66.
263.
657.
1314.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051 .
2628.
5256.
32,
105.
526.
2102.
5256.
10512.
26.
71.
225.
752.
1727.
3381.
22.
58.
159.
489.
1070.
2067.
18.
45.
93.
227.
413.
753.
10.
18.
-38.
-299.
-901 .
-1875.
-6.
-34.
-301.
-1350.
-3529.
-7131.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
85.17
70.86
44.93
37.61
34.53
33.81
72.03
57.72
31.79
24.47
21.39
20.67
58.89
44.58
18.65
11.33
8.25
7.53
32.61
18.30
-7,63
-14.95
-18.03
-18.75
-19.95
-34. 2*
-60.19
-67.51
-70.59
-71.31
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAM REOENERATION RATIO 0,3 LB STEAM/ LB CARBON
AT $5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0348*/1000 SCF
0.0696*/1000 SCF
0,1392*/1000 SCF
0.2784J/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000,
300.
1000.
5000,
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREIHT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179,
293.
513.
17,
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
2.
7.
34,
135.
338.
676.
2.
7.
34.
135.
338.
676.
2.
7.
34,
135.
338.
676.
2.
7.
34.
135.
338.
676.
2.
7,
34,
135.
338,
676.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829.
11.
37.
183.
732.
1829.
3658.
22.
73,
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633.
19.
49.
115.
314,
631.
1189.
13.
31.
24.
-52.
-284.
-640.
8.
12.
-68.
-418.
-1198.
-2469,
-3.
-24.
-251.
-1149.
-3027.
-6127.
-25.
-97,
-617,
-2613,
-6685,
-13444,
NET COST
OR SAUINGS(-)
PER SCFM
$/SCFM
63.25
48.95
23.02
15.69
12.62
11.89
44.96
30.65
4.73
-2,60
-5.67
-6.40
26.67
12.36
-13.56
-20.89
-23.96
-24.69
-9.91
-24.22
-50.14
-57.47
-60.54
-61.27
-83.08
-97.38
-123.31
-130.63
-133.71
-134.44
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0,0000$/1000 SCF
0.0348*/1000 SCF
0.0696S/1000 SCF
0.1392*/1000 SCF
0,2784*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
,513.
4.
13.
63.
251.
627.
1255.
4.
13.
63.
251.
627.
1255.
4.
13,
63.
251.
627.
1255.
4.
13.
63.
251.
627.
1255.
4.
13.
63.
251.
627.
1255.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829.
11.
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927,
7316.
14633.
21.
55.
144.
430.
920.
1767.
15.
36.
53.
64.
6.
-62.
10.
18,
-39.
-302.
-909.
-1891.
-1 .
-18.
-222.
-1034.
-2738.
-5549.
-23.
-92.
-588.
-2497.
-6396.
-12865.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
69.04
54.73
28.80
21 .48
18.40
17.67
50.74
36.44
10.51
3.19
0.11
-0.62
32.45
18.15
-7.78
-15.11
-18. 18
-18.91
-4.13
-18.43
-44.36
-51.69
-54.76
-55.49
-77.29
-91.60
-117.52
-124.85
-127.92
-128.65
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 BCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0348*/1000 SCF
0.0696*/1000 SCF
0.1392t/1000 SCF
0.2784$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
> 513.
6.
20.
101.
405.
1013.
2026.
6.
20.
101.
405.
1013.
2026.
6.
20.
101.
405.
1013.
2026.
6.
20.
101.
405,
1013.
2026.
6.
20.
101 .
405.
1013,
2026.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829.
11.
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633.
23.
62.
183.
584.
1306.
2538.
18.
44.
91 .
218.
391.
709.
12.
26.
-0.
-148.
-523.
-1120.
1 ,
-11.
-183.
-880.
-2352.
-4778.
-21.
-84.
-549.
-2343.
-6011.
-12094,
PER SCFM
*/SCFM
76.75
62.44
36.51
29.19
26.11
25.38
58.46
44,15
18.22
10.90
7.82
7.09
40.16
25.86
-0.07
-7.39
-10.47
-11.20
3.58
-10.72
-36.65
-43.98
-47.05
-47.78
-69.58
-83.89
-109.81
-117.14
-120.21
-120.94
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
<000)
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
NET COST
OR SAVINGS(-)
PER SCFM
»/SCFM
0,0000*/1000 SCF
0.0348*/1000 SCF
0.0696*/1000 SCF
0.1392*/1000 SCF
0.2784$/1000 SCF
300.
1000.
5000.
20000.
50000.
100000,
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000,
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955,
1671.
17.
42.
81,
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513,
12.
40.
198.
791.
1977.
3954.
12.
40.
198.
791.
1977 .
3954.
12.
40.
198.
791.
1977.
3954.
12.
40.
198.
791.
1977.
3954.
12.
40.
198.
791.
1977.
3954.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829.
11.
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927,
7316.
14633.
29.
82.
279,
969.
2270.
4466.
23.
63.
188.
604.
1355.
2637.
18.
45.
96.
238.
441 .
808.
7.
9.
-87.
-494.
-1389.
-2850.
-15.
-65.
-453.
-1957.
-5047.
-10166.
96.03
81.72
55.79
48.47
45.39
44.66
77.73
63.43
37.50
30.18
27.10
26.37
59.44
45.14
19.21
11 .88
8.81
8.08
22.86
8.56
-17.37
-24.70
-27.77
-28.50
-50.30
-64.61
-90.53
-97.86
-100.93
-101,66
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT tS.OO/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0400*/1000 SCF
0.0800*/1000 SCF
0.1600*/1000 SCF
0.3200*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293,
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
2.
8.
38.
153.
381.
763.
2.
8.
38.
153.
381.
763.
2.
8.
38.
153.
381.
763.
2.
8.
38.
153.
381 .
763.
8.
38.
153.
381.
763.
0.
0.
0.
0.
0.
0.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
25.
84.
420.
1682.
4205.
8410.
50.
168.
841.
3364.
8410.
16819.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
19.
50.
119.
331.
674.
1275.
13.
29.
14.
-89.
-377.
-827.
7.
8.
-91.
-510.
-1428.
-2929.
-6.
-34.
-301.
-1351.
-3531.
-7134.
-31 ,
-118.
-722.
-3033.
-7735.
-15544.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
64.12
49.81
23.88
16.56
13.48
12.75
43,09
28.79
2.86
-4.47
-7.54
-8.27
22.07
7.76
-18. 16
-25.49
-28.57
-29 ,29
-19.98
-34.29
-60.21
-67.54
-70.61
-71.34
-104.08
-118.38
-144.31
-151.64
-154.71
-155.44
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0400*/1000 SCF
0.0800$/1000 SCF
0.1600*/1000 SCF
0.3200*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) <000) (000) <000)
17.
42.
81.
179.
293.
513.
17.
42.
81,
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
4.
14.
71.
286.
714.
1428.
4.
14.
71.
286.
714.
1428.
4,
14.
71.
286.
714.
1428.
4.
14.
71.
286.
714.
1428.
4.
14.
71.
286.
714.
1428.
0.
0.
0,
0.
0.
0.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
25.
84.
420.
1682.
4205.
8410.
50.
168.
841.
3364.
8410.
16819,
21.
56.
153.
464.
1007.
1940.
15.
35.
48.
44.
-45.
-162.
9.
14.
-58.
-377.
-1096.
-2265.
-4.
-28.
-268.
-1218.
-3198.
-6469.
-29.
-112.
-688,
-2900.
-7403.
-14879,
NET COST
OR SfWINGS(-)
PER SCFM
$/SCFM
70.76
56.46
30.53
23.20
20.13
19.40
49.74
35.43
9.51
2.18
-0.89
-1.62
28.72
14.41
-11.52
-18.84
-21.92
-22.65
-13.33
-27.64
-53,56
-60.89
-63.97
-64.69
-97.43
-111.73
-137.66
-144.99
-148.06
-148.79
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *5,00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0400*/1000 SCF
0.0800*/1000 SCF
0.1600*/1000 SCF
0.3200$/1000 SCF
OFFGAS
FLOW
SCFh
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293,
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
7.
23.
116.
463.
1157.
2314.
7.
23.
116.
463.
1157.
2314.
7.
23.
116,
463.
1157,
2314.
7.
23.
116.
463.
1157.
2314.
7.
23.
116.
463.
1157.
2314.
0.
0.
0.
0.
0.
0.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
25.
84.
420.
1682.
4205.
8410.
50.
168.
841.
3364.
8410.
16817,
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
24.
65.
197.
641.
1450.
2827.
18.
44,
92.
221.
399.
724,
11.
23.
-13.
-200.
-653.
-1378.
-1 .
-19.
-224.
-1041.
-2755.
-5583.
-27.
-103.
-644.
-2722.
-6960.
-13993.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
79,63
65.32
39.39
32.07
28.99
28.27
58.60
44.30
18.37
11.04
7.97
7.24
37.58
23.27
-2.65
-9.98
-13.05
-13.78
-4.47
-18.78
-44.70
-52.03
-55.10
-55.83
-88.56
-102.87
-128.80
-136. 12
-139.20
-139.93
-------
OFFGAS CARBON REQUIREMENT 8,00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0400J/1000 SCF
0.0800t/1000 SCF
0.1600J/1000 SCF
0.3200*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671 .
58.
144.
273,
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955,
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42,
81.
179.
293.
513.
17.
42.
81.
179.
293,
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
14.
45.
226.
906.
2265,
4530.
14,
45.
226.
906.
2265.
4530.
14.
45.
226.
906.
2265.
4530.
14.
45.
226.
906.
2265.
4530.
14.
45.
226.
906.
2265.
4530,
0.
0,
0.
0.
0.
0.
6.
21.
105.
420.
1051.
2102,
13.
42.
210.
841.
2102,
4205.
25.
84.
420,
1682.
4205.
8410.
50.
168.
841.
3364.
8410.
16819.
31 .
87.
308.
1085.
2558.
5042.
24.
66.
203.
664.
1506.
2940.
18.
45.
98.
244.
455.
838.
5.
3.
-113.
-597.
-1647.
-3367.
-20.
•-81.
-533.
-2279.
-5852.
-11777.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
101.79
87.48
61.55
54.23
51 .15
50.42
80.76
66.46
40.53
33.20
30.13
29.40
59.74
45.43
19.51
12.18
9,11
8.38
17.69
3.38
-22,54
-29.87
-32.94
-33.67
-66.41
-80.71
-106.64
-113.96
-117.04
-117.77
-------
OFFGAS CARBON REQUIREMENTIO.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT $5,00/MILLION BTU
CREDIT
O.OOOOt/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
0.4000t/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293,
, 513.
3.
9.
46.
186.
464.
929.
3.
9.
46.
186,
464.
929.
3.
9.
46.
186.
464.
929.
3.
9.
46.
186.
464.
929.
3.
9.
46.
186.
464.
929,
0.
0.
0.
0.
0.
0.
8.
26.
131 .
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051,
4205,
10512.
21024.
20.
51.
128.
364.
757.
1442.
12.
25.
-4.
-161.
-557.
-1186.
-1,
-135.
-687,
-1871 ,
-3814.
-12.
-54.
-398.
-1738.
-4499.
-9070.
-43.
-159.
-923.
-3840,
-9755.
-19582.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
65.78
51.47
25.55
18.22
15.14
14.42
39.50
25,19
-0.73
-8.06
-11.14
-11.86
13.22
-1.09
-27.01
-34.34
-37.42
-38.14
-39.34
-53.65
-79.57
-86.90
-89.98
-90.70
-144.46
-158.77
-184.69
-192.02
-195.10
-195.82
-------
OFFGAS CARBON REQUIREMENTIO.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0500*/1000 SCF
0.1000$/1000 SCF
0,2000*/1000 SCF
0.4000$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
1.44.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
5.
18.
88.
352.
880.
1760.
5.
18.
88.
352.
880.
1760.
5.
18.
88.
352.
880.
1760.
5.
18.
88.
352.
880.
1760.
5.
18.
88.
352.
880.
1760.
0.
0.
0.
0.
0.
0.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051.
4205.
10512.
21024.
22.
60.
169.
531.
1173.
2273.
14.
34.
38.
5.
-141.
-355.
6.
7,
-94.
-521.
-1455.
-2983.
-9.
-45.
-356.
-1572.
-4083.
-8239.
-41.
-150.
-882,
-3674.
-9339.
-18751.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
74.09
59.78
33.85
26.53
23.45
22.73
47.81
33.50
7.57
0,25
-2.83
-3.55
21 .53
7.22
-18.71
-26.03
-29. 11
-29.83
-31.03
-45.34
-71.27
-78.59
-81.67
-82.39
-136. 15
-150.46
-176.39
-183,71
-186.79
-187.51
-------
QFFGAS CARBON REQUIREMENT!0.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
0.4000t/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
> 513.
9.
29.
143.
574.
1434.
2868.
9.
29.
143,
574.
1434.
2868.
9.
29.
143.
574,
1434.
2868.
9.
29.
143.
574.
1434.
2868.
9.
29.
143.
574.
1434.
2869.
0.
0.
0.
0.
0.
0.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051.
4205.
10512.
21024.
26.
71.
225.
752.
1727.
3381.
18.
45.
93.
227.
413.
753.
10.
18.
-38.
-299.
-901 .
-1875.
-34.
-301.
-1350.
-3529.
-7131.
-38.
-139.
-827.
-3453.
-8785.
-17643.
NET COST
OR SAYINGS(-)
PER SCFM
$/SCFM
85.17
70.86
44.93
37.61
34.53
33.81
58.89
44.58
18.65
11.33
8.25
7.53
32.61
18.30
-7.63
-14.95
-18.03
-18.75
-19.95
-34.26
-60.19
-67.51
-70.59
-71.31
-125.07
-139.38
-165.31
-172.63
-175.71
-176.43
-------
OFFGAS CARBON REQUIREHENTIO.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *5.00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0500*/1000 SCF
0.1000$/1000 SCF
0,2000*/10QO SCF
0.40001>/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671,
58.
144.
273,
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) <000) (000) (000)
17.
42.
81.
179.
293,
513.
17,
42.
81.
179.
293.
513.
17,
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
56.
282.
1128.
2819.
5638.
17.
56.
282.
1128.
2819.
5638.
17.
56.
282.
1128.
2819.
5638.
17.
56.
282.
1128,
2819.
5638.
17.
56.
282.
1128.
2819,
5638.
0.
0.
0.
0.
0.
0,
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051 .
4205.
10512,
21024.
34.
99.
363.
1306.
3112.
6150.
26.
72.
232.
781.
1798.
3522.
18.
46.
100.
255.
484.
894.
2.
-7.
-162.
-796.
-2144.
-4362.
-29.
-112.
-688.
-2899.
-7400.
-14874,
NET COST
OR SAUINGS(-)
PER SCFM
*/SCFM
112.87
98.56
72.63
65.31
62.23
61 .50
86.59
72.28
46.35
39.03
35.95
35.22
60.31
46.00
20.07
12.75
9.67
8.94
7.75
-6.56
-32.49
-39.81
-42.89
-43.62
-97.37
-111.68
-137.61
-144.93
-148,01
-148.74
-------
OFFGAS CARBON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0,3 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0005*/1000 SCF
0.0010*/1000 SCF
0.0020t/1000 SCF
0.0040*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
[-OST CREDIT COST OR CREDIT(-)
(000) (000) <000) <000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
v 513.
0.
1.
6.
23.
57.
114.
0.
1.
6.
23.
57.
114.
0.
1.
6.
23.
57.
114.
0.
1.
6.
23.
57.
114.
0.
1.
6.
23.
57.
114.
0.
0.
0.
0.
0.
0.
0.
0.
1.
5.
13.
26.
0.
1.
3.
11.
26.
53.
0.
1 .
5.
21.
53.
105,
1.
2.
11.
42.
105.
210.
17,
43.
87.
201.
350.
627.
17.
43.
86.
196.
337.
600.
17.
43.
84.
191.
323.
574.
17.
42.
82.
180.
297.
521.
17.
41.
76.
159.
245.
416.
NET COST
OR SAYINGS(-)
PER SCFM
*/SCFM
57.63
43.32
17.40
10.07
6.99
6.27
57.36
43.06
17.13
9.81
6.73
6.00
57. 10
42.80
16.87
9.54
6.47
5.74
56.58
42.27
16.34
9.02
5,94
5.21
55.53
41.22
15.29
7.97
4.89
4.16
-------
OFFGAS CARBON REQUIREHENT 0.10 LB CARBON/1000 SCF
STEAH REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
<000>
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAVINGS(-)
PER SCFH
*/SCFM
0.0000*/1000 SCF
0.0005*/1000 SCF
0.0010$/1000 SCF
0.0020*/1000 SCF
0.0040*/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513,
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
0.
1,
6.
26.
65.
130.
0.
1.
6.
26.
65.
130.
0.
1.
6.
26.
65.
130.
0.
1,
6.
26.
65.
130.
0.
1.
6.
26.
65.
130.
0.
0.
0.
0,
0.
0.
0.
0,
1.
5.
13.
26.
0.
1.
3.
11.
26.
53.
0.
1.
5.
21.
53.
105.
1.
2.
11 .
42.
105.
210.
17.
43.
88.
205.
358.
643.
17.
43.
86.
199.
345.
616.
17.
43.
85.
194.
331.
590.
17.
42.
83.
184.
305.
537.
17.
41.
77.
163.
253.
432.
57.79
43.48
17.55
10.23
7.15
6.43
57.52
43.22
17.29
9.97
6.89
6.16
57.26
42.95
17.03
9.70
6.63
5.90
56.74
42.43
16.50
9.18
6.10
5.37
55.68
41.38
15.45
8.13
5.05
4.32
-------
OFFGAS CARBON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0005*/1000 SCF
O.OOlOt/1000 SCF
0.0020*/1000 SCF
0.0040*/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
0.
2.
8.
30.
76.
151.
0.
2.
8.
30.
76.
151.
0.
2.
8.
30.
76.
151.
0.
2.
8.
30.
76.
151.
0.
2.
8.
30.
76.
151.
0.
0.
0.
0.
0.
0.
0.
0.
1.
5.
13.
26.
0.
1.
3.
11.
26.
53.
0.
1.
5.
21.
53.
105.
1.
2,
11.
42.
105.
210.
17.
44.
89.
209.
368.
664.
17.
43.
88.
204.
355.
638.
17.
43.
86.
198.
342.
611.
17.
43.
84.
188.
316.
559.
17.
42.
78.
167.
263.
454,
NET COST
OR SAVINGS(-)
PER SCFM
t/SCFM
58.00
43.69
17.77
10.44
7.37
6.64
57.74
43.43
17.50
10.18
7.10
6.38
57.47
43.17
17.24
9.92
6.84
6.11
56.95
42.64
16.72
9.39
6.32
5.59
55.90
41.59
15.66
8.34
5.26
4,54
-------
QFFGAS CARBON REQUIREMENT 0.10 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
<000> <000> (000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
0.00004/1000 SCF
0.0005t/1000 SCF
0.0010$/1000 SCF
0.0020$/1000 SCF
0.0040*/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81,
179.
293.
, 513.
1,
2.
10.
41.
102.
204.
1.
2.
10.
41.
102.
204.
1.
2.
10.
41.
102.
204.
1 .
2.
10.
41.
102.
204.
1.
2.
10.
41,
102.
204.
0.
0.
0.
0.
0.
0.
0.
0.
1.
5.
13.
26.
0.
1.
3.
11.
26.
53.
0.
1.
5»
21.
53.
105.
1.
2.
11 .
42.
105.
210.
18.
44.
91 .
219.
395.
717.
17.
44.
90,
214.
382.
691.
17.
44.
89.
209.
369.
664.
17.
43.
86.
198,
342.
612.
17.
42.
81.
177.
290.
507.
58.53
44.23
18.30
10.97
7.90
7.17
58.27
43.96
18.04
10.71
7.64
6.91
58.01
43.70
17.77
10.45
7.37
6.64
57.48
43. 17
17.25
9.92
6.85
6.12
56.43
42.12
16.20
8.87
5.80
5,07
-------
OFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAH REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAUINGS(-)
PER SCFM
$/SCFM
0.0000*/1000 SCF
0.0025*/1000 SCF
0.0050«/1000 SCF
0.0100*/1000 SCF
0.0200*/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300,
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
1 .
2.
9.
36.
89.
178.
1 .
2.
9.
36.
89.
178.
1.
2.
9.
36.
89.
178.
1.
2.
9.
36.
89.
178.
1.
2.
9.
36.
89.
178.
0.
0.
0.
0.
0.
0.
0.
1.
7.
26.
66.
131.
1.
3.
13.
53.
131.
263.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
17.
44.
90.
214.
382.
690.
17.
43.
84.
188.
316.
559.
17.
41.
77.
162.
250.
428.
16.
39.
64.
109.
119.
165.
14.
33.
38.
4.
-144.
-361.
58.27
43.96
18.03
10.71
7.63
6.90
56.95
42.65
16.72
9.39
6.32
5.59
55.64
41.33
15.41
8.08
5.01
4.28
53.01
38.70
12.78
5.45
2.38
1.65
47.75
33.45
7.52
0.20
-2.88
-3.61
-------
OFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
0,0000$/1000 SCF
0.0025*/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200t/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671,
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
, 513.
1 .
3.
13.
52.
129.
258.
1 .
3.
13.
52.
129.
258.
1,
3.
13.
52.
129.
258.
1 .
3.
13.
52.
129.
258.
1 .
3.
13.
52.
129.
258.
0.
0.
0.
0.
0.
0.
0.
1.
7.
26.
66.
131.
1 .
3.
13.
53.
131 .
263.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
18.
45.
94.
230.
422.
770.
17.
43.
88.
204.
356.
639.
17.
42.
81 .
178.
290.
507.
16.
40.
68.
125.
159.
245.
15.
34.
42.
20.
-104.
-281.
59.06
44.76
18.83
11.50
8.43
7.70
57.75
43.44
17.52
10.19
7.12
6.39
56.44
42.13
16.20
8.88
5.80
5.07
53.81
39.50
13.58
6.25
3.17
2.45
48.55
34.25
8.32
0.99
-2.08
-2.81
-------
QFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0,0025*/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200t/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT<->
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
1.
4.
18.
73.
182.
364.
1.
4.
18.
73.
182.
364.
1.
4.
18.
73.
182.
364.
1 ,
4.
18.
73.
182.
364.
1.
4.
18.
73.
182.
364.
0.
0.
0.
0.
0.
0.
0,
1.
7.
26.
66.
131.
1 .
3.
13.
53.
131.
263.
2.
5.
26.
105.
263.
526.
3.
11 .
53.
210.
526.
1051.
18.
46.
99.
251.
475.
877.
18.
45.
93.
225.
409.
745.
17.
43.
86.
199.
343.
614.
16.
41.
73.
146.
212.
351.
15.
35.
47.
41.
-51.
-175.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
60.13
45.82
19.89
12.57
9.49
8.77
58.81
44.51
18.58
11.25
8.18
7.45
57.50
43. 19
17.27
9.94
6.87
6.14
54.87
40.56
14.64
7.31
4.24
3.51
49.62
35.31
9.38
2,06
-1.02
-1.75
-------
OFFGAS CARBON REQUIREMENT 0.50 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
O.OOOOt/1000 SCF
0.00251/1000 SCF
0,0050*/1000 SCF
0.0100*/1000 SCF
0.0200*/1000 SCF
OFF6AS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955,
1671 .
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
(-OST CREDIT COST OR CREDIT(-)
(000) <000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17,
42.
81.
179.
293.
513.
2.
6.
31 .
126.
315.
630,
2,
6.
31.
126.
315.
630.
2.
6.
31 .
126.
315.
630.
2.
6.
31.
126.
315.
630.
2.
6.
31.
126.
315.
630.
0.
0.
0.
0,
0.
0.
0.
1.
7.
26.
66.
131.
1.
3.
13.
53.
131.
263.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
19.
48.
113.
305.
608.
1143.
18.
47.
106.
278.
542.
1011.
18.
46,
100.
252.
476.
880.
17.
43.
86.
199.
345.
617.
16.
38.
60.
94.
82.
91.
NET COST
OR SAYINGS(-)
PER SCFM
*/SCFM
62.79
48.48
22.55
15.23
12.15
11.43
61 .47
47.17
21.24
13.91
10.84
10.11
60. 16
45.85
19.93
12.60
9.53
8.80
57.53
43.22
17.30
9.97
6.90
6.17
52.28
37.97
12.04
4.72
1.64
0.91
-------
OFFGAS CARBON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200*/1000 SCF
0.0400*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT<->
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81.
179.
293.
, 513.
1.
3.
13.
52.
129.
258.
1.
3.
13.
52.
129.
258.
1.
3.
13.
52.
129.
258.
1.
3.
13.
52.
129.
258.
1.
3.
13.
52.
129.
258.
0.
0.
0.
0.
0.
0.
1.
3.
13.
53.
131.
263.
2.
5.
26.
105.
263.
526.
3.
11 .
53.
210.
526.
1051.
6.
21.
105,
420.
1051.
2102.
18.
45.
94.
230.
422.
770.
17.
42.
81,
178.
290.
507.
16.
40.
68.
125.
159.
245.
15.
34.
42.
20.
-104.
-281.
11 .
24.
-11.
-190.
-630,
-1332,
NET COST
OR SAYINGS(-)
PER SCFM
*/SCFM
59.06
44.76
18.83
11.50
8.43
7.70
56.44
42.13
16.20
8.88
5.80
5.07
53.81
39.50
13.58
6.25
3.17
2.45
48.55
34.25
8.32
0,99
-2.08
-2.81
38.04
23,73
-2.19
-9.52
-12.59
-13.32
-------
OFFGAS CARBON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0050t/1000 SCF
0.0100*/1000 SCF
0.0200$/1000 SCF
0.0400*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREIUT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
1,
4.
21 .
83.
209.
417.
1.
4.
21,
83.
209.
417.
1.
4,
21.
83.
209.
417.
1.
4,
21.
83.
209,
417.
1.
4.
21 .
83.
209.
417.
0.
0,
0,
0.
0.
0.
1.
3.
13.
53.
131.
263.
2.
5.
26.
105.
263.
526.
3,
11.
53.
210,
526.
1051.
6.
21.
105.
420.
1051 .
2102.
18.
46.
102.
262.
501 .
930.
17.
44.
89.
209.
370.
667.
17.
41.
76.
157.
239.
404.
15.
36.
50.
52.
-24.
-121.
12.
25.
-3.
-158.
-550.
-1173.
NET COST
OR SAYINGS(-)
PER SCFM
$/SCFM
60.66
46.35
20.43
13.10
10.03
9.30
58.03
43.72
17.80
10.47
7.40
6.67
55.40
41.10
15.17
7.84
A,77
4.04
50.15
35.84
9.91
2.59
-0.49
-1.21
39.64
25.33
-0.60
-7.92
-11.00
-11.73
-------
OFFGAS CARBON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1,0 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.00004/1000 SCF
0.0050*/1000 SCF
0.0100$/1000 SCF
0.0200*/1000 SCF
0.0400*/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
OPERATING COST-OR-CREIUT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81,
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293,
513.
6.
31.
126.
315,
630.
2.
6.
31 ,
126.
315.
630.
2.
6.
31.
126.
315.
630.
2.
6.
31.
126.
315.
630.
2.
6.
31.
126.
315.
630.
0.
0.
0.
0.
0.
0.
1.
3.
13.
53.
131.
263.
2.
5.
26,
105,
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21 .
105.
420.
1051,
2102.
19.
48.
113.
305.
608.
1143.
18.
46.
100.
252.
476.
880.
17.
43.
86,
199.
345.
617.
16.
38.
60.
94.
82.
91.
13.
27.
8.
-116.
-443.
-960.
NET COST
OR SAVINGS(-)
PER SCFM
t/SCFM
62.79
48.48
22.55
15.23
12.15
11.43
60. 16
45.85
19,93
12.60
9.53
8.80
57.53
43.22
17.30
9.97
6.90
6.17
52.28
37.97
12.04
4.72
1.64
0.91
41.76
27.46
1.53
-5,80
-8.87
-9.60
f
-------
OFFGAS CARBON REQUIREMENT 1.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0050*/1000 SCF
0.0100*/1000 SCF
0.0200*/1000 SCF
0.0400*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671 .
58.
144.
273,
594.
955.
1671 .
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
3.
12.
58.
232.
581 .
1162.
3.
12.
58.
232.
581.
1162.
3.
12.
58.
232.
581.
1162.
3.
12.
58.
232.
581 .
1162.
3.
12.
58.
232.
581 .
1162.
0.
0.
0.
0.
0.
0.
1 ,
3.
13.
53.
131.
263.
2.
5.
26.
105.
263.
526.
3.
11.
53,
210.
526.
1051.
6.
21.
105.
420.
1051.
2102.
20.
54,
139,
411,
874.
1674.
20.
51.
126.
358.
742.
1412.
19.
49.
113.
306.
611 .
1149.
17.
43.
87.
201.
348.
623.
14.
33.
34.
-10.
-178.
-428.
NET COST
OR SAMINGS(-)
PER SCFM
*/SCFM
68.11
53.80
27.87
20.55
17.47
16.74
65.48
51 .17
25.25
17.92
14.85
14.12
62.85
48.54
22.62
15.29
12.22
11.49
57.59
43.29
17.36
10.04
6.96
6.23
47.08
32.78
6.85
-0.48
-3.55
-4.28
-------
OFFGAS CARHON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0,0000*/1000 SCF
0.0070«/1000 SCF
0.0139$/1000 SCF
0.0279*/1000 SCF
0.0557*/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
56.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) <000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
1.
3.
16.
64.
160.
320.
1.
3.
16.
64.
160.
320.
1.
3.
16.
64.
160.
320.
1 .
3.
16.
64.
160.
320.
1 .
3.
16.
64.
160.
320.
0.
0.
0.
0.
0.
0.
1 .
4.
18.
73.
183.
366.
2.
7.
37.
146.
366.
732.
4.
15.
73.
293.
732.
1464.
9.
29.
146.
586.
1464.
2729.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
18.
45.
97.
243.
453.
833.
17.
42.
79.
169.
270.
467.
16.
38.
61.
96.
87.
101.
14,
31.
24.
-50.
-279.
-631.
9.
16.
-49.
-343.
-1011 ,
-2096.
NET COST
OR SAUINGS(-)
PER SCFM
$/SCFM
59.69
45.38
19.46
12.13
9.06
8.33
56.03
41.72
15.80
8.47
5.40
4.67
52.37
38.06
12.14
4.81
1.74
1.01
45.05
30.74
4.82
-2.51
-5.59
-6.31
30.40
16.10
-9.83
-17.15
-20.23
-20,96
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0070*/1000 SCF
0.0139*/1000 SCF
0.0279*/1000 SCF
0.0557*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
<000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81,
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81,
179,
293.
513.
17.
42.
81.
179.
293.
513.
5.
27.
109.
271.
543.
2.
5.
27.
109.
271.
543.
2.
5.
27.
109.
271.
543.
2.
5.
27,
109.
271.
543.
5.
27.
109.
271.
543.
0.
0.
0.
0.
0.
0.
1.
4.
18.
73.
183.
366.
2.
7.
37.
146.
366.
732.
4.
15.
73,
293.
732.
1464.
9.
29.
146.
586.
1464,
2929,
19.
48.
108.
287.
564.
1055,
17.
44.
90.
214.
381 .
689.
16.
40.
72.
141.
198.
323.
14.
33.
35,
-6.
-168.
-409.
10.
18.
-38.
-299.
-900.
-1873.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
61.91
47.61
21.68
14.35
11.28
10.55
58.25
43.95
18.02
10.69
7.62
6.89
54.59
40.29
14.36
7.03
3.96
3.23
47.27
32.96
7.04
-0.29
-3.36
-4.09
32.63
18.32
-7.61
-14.93
-18.01
-18.73
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT tlO.OO/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0070*/1000 SCF
0.0139*/1000 SCF
0.0279*/1000 SCF
0.0557*/1000 SCF
OFFGAS
FLOW
SCFh
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
<000)
58.
144.
273.
594.
955,
1671.
58.
144.
273,
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CKEDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
<000> (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
> 513.
3.
8.
42.
168.
419.
839.
3.
8.
42.
168.
419.
839.
3.
8.
42.
168.
419.
839.
3.
8.
42.
168.
419.
839.
3.
8.
42.
168.
419.
839,
0.
0.
0.
0.
0.
0.
1 .
4,
18.
73.
183.
366.
2.
7.
37.
146.
366.
732,
4.
15.
73,
293.
732.
1464.
9.
29.
146.
586.
1464.
2929.
19.
51.
123.
346.
712.
1352.
18.
47.
105.
273.
529.
985.
17.
43.
87.
200.
346.
619.
15.
36.
50.
54.
-20.
-113.
11.
21.
-23.
-239.
-752.
-1577.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
64.88
50.57
24.64
17.32
14.24
13.52
61.22
46.91
20.98
13.66
10.58
9.85
57.56
43.25
17.32
10.00
6.92
6. 19
50.23
35.93
10.00
2.68
-0.40
-1.13
35.59
21.28
-4.64
-11.97
-15.04
-15.77
-------
OFFGAS CARBON REQUIREMENT 1.39 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0070$/1000 SCF
0.0139*/1000 SCF
0.0279*/1000 SCF
0.0557$/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58,
144.
273.
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
58.
144.
273,
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
<000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
5.
16.
79.
316.
790.
1580.
5.
16.
79.
316.
790.
1580.
16.
79,
316.
790.
1580.
5.
16.
79.
316.
790.
1580.
5.
16.
79,
316.
790.
1580.
0.
0.
0.
0.
0.
0.
1.
4,
18.
73.
183.
366.
2.
7.
37.
146.
366.
732.
4,
15,
73.
293,
732.
1464.
9.
29.
146.
586.
1464.
2929.
22.
58.
160.
495.
1083.
2093.
21.
54.
142.
421.
900.
1726.
19.
51.
124.
348.
717.
1360.
17.
43.
87,
202.
351 .
628.
13.
29.
14.
-91 .
-382.
-836.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
72.29
57.98
32.05
24.73
21.65
20.93
68.63
54.32
28.39
21.07
17.99
17.26
64.97
50.66
24.73
17.41
14.33
13.60
57.64
43.34
17.41
10.08
7.01
6.28
43.00
28.69
2.77
-4.56
-7.63
-8.36
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
O.OOOOt/1000 SCF
0.0100*/1000 SCF
0.02001/1000 SCF
0.0400*/1000 SCF
0.0800*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000,
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955,
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREOIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) <000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
1.
4.
21.
83.
209.
417.
1 .
4.
21.
83.
209.
417.
1 .
4.
21.
83.
209.
417.
1.
4.
21.
83.
209.
417.
1 .
4.
21.
83.
209.
417.
0.
0.
0.
0.
0.
0.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841.
2102,
4205.
18.
46.
102.
262.
501.
930.
17.
41,
76.
157.
239.
404.
15.
36.
50.
52.
-24.
-121.
12.
25.
-3.
-158.
-550.
-1173.
6.
4.
-108.
-579.
-1601.
-3275.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
60.66
46.35
20.43
13.10
10.03
9.30
55.40
41,10
15.17
7.84
4.77
4.04
50.15
35.84
9.91
2.59
-0.49
-1.21
39.64
25.33
-0.60
-7.92
-11.00
-11.73
18.61
4.30
-21.62
-28.95
-32.02
-32.75
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON71000 SCF
STEAM REGENERATION RATIO 0,6 LB STEAM7 LB CARBON
AT *10.007MILLION BTU
CREDIT
0.0000*71000 SCF
0.0100*71000 SCF
0.0200*71000 SCF
0.0400*71000 SCF
0.0800*71000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955,
1671.
58.
144.
273.
594,
955.
1671.
OPERATING COST-OR-CREIHT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513,
17.
42.
81.
179.
293.
513.
17.
42,
81.
179.
293,
513.
17.
42.
81.
179.
293.
513.
17,
42.
81 .
179,
293.
513.
2.
7.
37.
147.
368.
736.
2.
7.
37.
147.
368.
736.
2.
7.
37.
147.
368.
736.
2.
7.
37.
147,
368.
736.
2.
7.
37.
147.
368.
736.
0.
0.
0.
0.
0.
0.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21.
105,
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
19.
50.
118.
326.
661 .
1249.
18.
44.
92.
221.
398.
723.
16.
39.
66.
116.
135.
198.
13.
29.
13.
-95.
-390.
-853.
7.
7.
-92.
-515.
-1441,
-2956.
NET COST
OR SAVINGS(-)
PER SCFh
*/SCFM
63.85
49.54
23.62
16.29
13.22
12.49
58.59
44.29
18.36
11.04
7.96
7.23
53.34
39.03
13.11
5.78
2.71
1.98
42.83
28.52
2.59
-4.73
-7.81
-8.53
21.80
7.50
-18.43
-25.76
-28.83
-29.56
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAh/ LB CARBON
AT $10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0100*/1000 SCF
0.0200*/1000 SCF
0.0400*/1000 SCF
0.0800*71000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
> 513.
3.
12.
58.
232.
581.
1162.
3.
12.
58.
232.
581.
1162.
3.
12.
58.
232.
581.
1162.
3.
12.
58.
232.
581 .
1162.
3.
12.
58.
232.
5B1.
1162.
0.
0.
0.
0.
0.
0.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
20.
54.
139.
411.
874.
1674.
19.
49.
113.
306.
611.
1149.
17.
43.
87.
201.
348.
623.
14.
33.
34.
-10.
-178.
-428.
8.
12.
-71.
-430.
-1229,
-2530.
NET COST
OR SAVINGS(-)
PER SCFM
$/SCFM
68.11
53.80
27.87
20.55
17.47
16.74
62.85
48.54
22.62
15.29
12.22
11.49
57.59
43.29
17.36
10.04
6.96
6.23
47.08
32.78
6.85
-0.48
-3,55
-4.28
26.06
11.75
-14.17
-21.50
-24.57
-25.30
-------
OFFGAS CARBON REQUIREMENT 2.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREBIT(-)
<000) (000) (000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
0.0000*/1000 SCF
0.0100*/1000 SCF
0.0200*/1000 SCF
0.0400*/1000 SCF
0.0800*/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671,
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
7.
22.
111.
445.
1113.
2226.
7.
22.
111.
445.
1113.
2226.
7.
22.
Ill .
445.
1113.
2226.
7.
22.
Ill .
445.
1113.
2226.
7.
22.
111.
445.
1113.
2226.
0.
0.
0.
0.
0,
0.
2.
5.
26.
105.
263.
526.
3.
11.
53.
210.
526.
1051.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
941.
2102.
4205.
24.
64,
193.
624.
1406.
2738.
22.
59.
166.
519.
1143.
2213.
20.
54.
140.
413.
880.
1687.
17.
43.
87.
203.
354.
636.
11 .
22.
-18.
-217.
-697.
-1467.
78.74
64.44
38.51
31.19
28.11
27.38
73.49
59.18
33.26
25.93
22.86
22.13
68.23
53.93
28.00
20.67
17.60
16.87
57.72
43.41
17.49
10.16
7.09
6.36
36.70
22.39
-3.54
-10.86
-13,94
-14.67
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0250*/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0.2000t/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
3.
9.
45.
179.
448.
896.
3.
9.
45.
179.
448.
896.
3.
9.
45.
179.
448.
896.
3.
9.
45.
179.
448.
896.
3.
9.
45.
179.
448.
896.
0.
0.
0.
0.
0.
0.
4.
13.
66.
263.
657.
1314.
8.
26.
131 .
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
20.
51.
126.
358.
741.
1408.
16.
38.
60.
95.
84.
94.
12.
25.
-5.
-168.
-573.
-1220.
4.
-1.
-137.
-693.
-1887.
-3848.
-12.
-54.
-400.
-1745.
-4515,
-9104.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
65.45
51.14
25.21
17.89
14.81
14.08
52.31
38.00
12.07
4.75
1.67
0.94
39. 17
24.86
-1.07
-8.39
-11.47
-12.20
12.89
-1.42
-27.35
-34.67
-37.75
-38.48
-39.67
-53.98
-79.91
-87.23
-90.31
-91.04
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0250*/1000 SCF
0.0500*/1000 SCF
0.1000$/1000 SCF
0.2000*/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
<000)
58.
144.
273.
594.
955.
1671.
58,
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREBIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42,
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42,
81.
179.
293.
< 513.
5.
17.
85.
339.
847.
1694.
5.
17.
85.
339.
847.
1694.
5.
17.
85.
339.
847.
1694.
5.
17.
85.
339.
847.
1694.
5.
17.
85.
339.
847.
1694.
0.
0.
0.
0.
0.
0.
4,
13.
66.
263.
657.
1314.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
22.
59.
166.
517.
1140.
2206.
18.
46.
100.
255.
483.
892.
14.
33,
35.
-8.
-174.
-422.
6.
7.
-97.
-534.
-1488.
-3050.
-10.
-46.
-360.
-1585.
-4116.
-8306.
NET COST
OR SAVINGS(-)
PER SCFM
«/SCFM
73.43
59.12
33.19
25.87
22.79
22.06
60.29
45.98
20.05
12.73
9.65
8.92
47.15
32.84
6.91
-0.41
-3.49
-4.22
20.87
6.56
-19.37
-26.69
-29.77
-30.50
-31.69
-46.00
-71.93
-79.25
-82.33
-83.06
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *iO.OO/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0250*/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000,
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273,
594.
9S5.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) <000)
17,
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513,
17.
42,
81.
179.
293.
513.
16.
54.
271.
1083.
2709.
5417.
16.
54.
271.
1083.
2709.
5417.
16.
54.
271.
1083.
2709.
5417.
16.
54.
271,
1083.
2709.
5417,
16.
54.
271.
1083.
2709.
5417.
0.
0.
0.
0.
0.
0.
4.
13.
66.
263.
657.
1314.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051,
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
33.
96.
352.
1262.
3001 .
5930.
29.
83.
286,
999.
2344.
4616.
25.
70.
221.
736.
1687.
3302.
17.
44.
89,
211.
373.
674.
2.
-9.
-173,
-840,
-2255.
-4582.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
110.66
96.35
70.43
63.10
60.03
59.30
97.52
83.21
57,29
49.96
46.89
46.16
84.38
70.07
44.15
36.82
33.75
33.02
58.10
43.79
17.87
10.54
7.47
6.74
5.54
-8.77
-34.69
-42.02
-45.09
-45.82
-------
OFFGAS CARBON REQUIREMENT 5.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREDIT
0.0000*71000 SCF
0.0250*/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) <000) <000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
8.
28.
138.
552.
1379.
2758.
8.
28.
138.
552.
1379.
2758.
8.
28.
138.
552.
1379.
2758.
8.
28.
138.
552.
1379.
2758.
8.
28.
138.
552.
1379.
2758.
0.
0.
0.
0.
0.
0.
4.
13.
66.
263.
657.
1314.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526,
2102.
5256.
10512.
25.
70.
219.
730.
1672.
3270.
21 .
57.
153.
467.
1015.
1956.
17.
43.
88.
204,
358.
642.
9.
17.
-44.
-321.
-956,
-1986.
-6.
-35.
-306.
-1372.
-3584.
-7242.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
84.06
69.76
43.83
36.50
33.43
32.70
70.92
56.62
30.69
23.36
20.29
19.56
57.78
43.48
17.55
10.22
7.15
6.42
31.50
17.20
-8.73
-16.06
-19.13
-19.86
-21.06
-35.36
-61.29
-68.62
-71.69
-72.42
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREtUT
0.0000*/1000 SCF
0.0348*/1000 SCF
0.0696*/1000 SCF
0.1392*/1000 SCF
0.2784S/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
4.
12.
60.
242.
604.
1209.
4.
12,
60.
242.
604.
1209.
4.
12.
60.
242.
604.
1209.
4.
12.
60.
242.
604.
1209.
4.
12.
60.
242.
604.
120?.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829,
11 .
37.
183,
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633.
21.
54.
142.
420.
897.
1721.
15.
36.
50.
54.
-17.
-108.
10.
18.
-41.
-311.
-932.
-1937.
-1 .
-19.
-224.
-1043.
-2761.
-5595.
-23.
-92.
-590.
-2506.
-6419.
-12911,
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFh
68.57
54.27
28.34
21.02
17.94
17.21
50.28
35,98
10.05
2.72
-0.35
-1.08
31.99
17.69
-8.24
-15.57
-18.64
-19.37
-4.59
-18.90
-44.82
-52.15
-55.22
-55.95
-77.75
-92.06
-117.99
-125.31
-128.39
-129.11
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT tlO.OO/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CREIUT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
0.0000*/1000 SCF
0.0348*/1000 SCF
0.0696*/1000 SCF
0.1392$/1000 SCF
0.2784*/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
7.
23.
116.
464.
1160.
2319.
7.
23.
116.
464.
1160.
2319.
7.
23.
116.
464.
1160.
2319.
7.
23.
116.
464.
1160.
2319.
7.
23.
116.
464.
1160.
2319.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829.
11.
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633.
24.
65.
197.
642.
1452.
2832.
IB.
47.
106.
277.
538.
1003.
13.
29.
14.
-89.
-377.
-826.
2.
-8.
-169.
-821.
-2206.
-4484.
-20.
-81.
-534.
-2284.
-5864.
-11801.
79.68
65.37
39.45
32.12
29.05
28.32
61.39
47.08
21.16
13.83
10.76
10.03
43.10
28.79
2.87
-4.46
-7.53
-8.26
6.52
-7.79
-33.72
-41.04
-44.12
-44.84
-66.65
-80.95
-106.88
-114.21
-117.28
-118.01
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000$/1000 SCF
0.0348S/1000 SCF
0.0696*/1000 SCF
0.1392t/1000 SCF
0.2784*/1000 SCF
OFFGAS
FLOU
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT<->
(000) (000) (000) (000)
17,
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
• 11.
38.
190,
760.
1900.
3800.
11.
38.
190.
760.
1900.
3800.
11.
38.
190.
760.
1900.
3800.
11 .
38.
190.
760.
1900.
3800.
11.
38.
190.
760.
1900.
3800.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829.
11 .
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633,
28,
80.
271.
939.
2193.
4313.
23.
62.
180.
573.
1278.
2484.
17.
44.
88.
207.
364.
655.
6.
7.
-95.
-525.
-1465.
-3004.
-16.
""OO *
-460.
-1988.
-5124.
-10320.
NET COST
OR SAYINGS(-)
PER SCFM
*/SCFM
94.49
80.18
54.26
46.93
43.86
43.13
76.20
61.89
35.97
28.64
25.57
24.84
57.91
43.60
17.67
10.35
7.27
6.55
21.33
7.02
-18.91
-26.23
-29.31
-30.04
-51.84
-66.14
-92.07
-99,40
-102.47
-103.20
-------
OFFGAS CARBON REQUIREMENT 6.96 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREIHT
OFFGAS
FLOW
SCFM
CAPITAL
COST
<000>
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
0.0000*/1000 SCF
0,0348$/1000 SCF
0.0696*/1000 SCF
0.1392*/1000 SCF
0,2784*/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
• 23,
75.
375.
1500.
3751.
7502.
23.
75.
375.
1500.
3751.
7502.
23.
75.
375.
1500.
3751.
7502.
23.
75.
375.
1500.
3751.
7502.
23.
75.
375.
1500.
3751.
7502.
0.
0.
0.
0.
0.
0.
5.
18.
91.
366.
915.
1829,
11.
37.
183.
732.
1829.
3658.
22.
73.
366.
1463.
3658.
7316.
44.
146.
732.
2927.
7316.
14633.
39.
117.
456.
1679.
4044.
8015.
34.
99.
365.
1313.
3129.
6186.
28.
81.
273.
947.
2215.
4357.
18.
44.
91.
216.
386.
698.
-29.
-275.
-1248.
-3273.
-6618.
131.51
117.20
91.28
83.95
80.88
80.15
113.22
98.91
72.99
65.66
62.59
61.86
94.93
80.62
54.70
47.37
44.29
43.57
58.35
44.04
18.11
10.79
7.71
6.98
-14.82
-29.12
-55.05
-62.38
-65.45
-66.18
-------
OFF6AS CARBON REQUIREMENT 8,00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
OFFGAS
FLOW
SCFM
CAPITAL
COST
<000)
OPERATING COST-OR-CREDIT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) (000) (000)
NET COST
OR SAVINGS(-)
PER SCFM
t/SCFM
0.0000$/1000 SCF
0.0400*/1000 SCF
0.0800t/1000 SCF
0.1600*/1000 SCF
0.3200J/1000 SCF
300.
1000.
5000.
20000.
50000.
100000.
300.
1000,
5000.
20000,
50000,
100000,
300.
1000.
5000,
20000,
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000,
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
4.
14.
69.
275,
687.
1375.
4.
14,
69.
275.
687.
1375.
4,
14.
69.
275,
687.
1375.
4.
14.
69.
275.
687.
1375.
4.
14.
69,
275.
687.
1375.
0,
0.
0.
0.
0.
0.
6.
21.
105,
420,
1051.
2102.
13.
42.
210.
841,
2102.
4205.
84.
420.
1682.
4205.
8410.
50.
168.
841 .
3364.
8410.
16819,
21 .
56.
150.
453.
980.
1887.
15,
35,
45.
33,
-71 .
-215.
8.
14.
-60.
-387.
-1122.
-2318.
-4.
-28.
-270.
-1228.
-3225.
-6522.
-29.
-112.
-691 .
-2910.
-7430.
-14932,
70.23
55.93
30.00
22.67
19.60
18.87
49.21
34.90
8.98
1.65
-1.42
-2.15
28.19
13.88
-12.05
-19,37
-22.45
-23.18
-13.86
-28.17
-54.09
-61.42
-64.50
-65.22
-97.96
-112.26
-138, 19
-145.52
-148.59
-149,32
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0,00004/1000 SCF
0.0400*/1000 SCF
0.0800*/1000 SCF
0.1600*/1000 SCF
0.32004/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
8.
27.
133.
530.
1326.
2651.
8.
27.
133.
530.
1326.
2651,
8.
27,
133.
530.
1326.
2651.
8.
27.
133.
530.
1326.
2651.
8.
27.
133.
530,
1326.
2651.
0.
0.
0.
0.
0.
0.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
25.
84.
420.
1682.
4205.
8410.
50.
168.
841.
3364.
8410.
16819.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
25.
69.
214.
709.
1618.
3164.
19.
48.
109.
288.
567.
1061.
12.
27.
4.
-132.
-484.
-1041.
-0.
-15.
-207.
-973.
-2586.
-5246.
-26.
-99.
-627.
-2655.
-6791.
-13655.
NET COST
OR SAYINGS(-)
PER SCFM
*/SCFM
83.00
68.69
42.77
35.44
32.37
31.64
61.98
47.67
21.74
14.42
11.34
10.61
40.95
26.64
0.72
-6.61
-9.68
-10.41
-1. 10
-15.40
-41.33
-48.66
-51.73
-52.46
-85.19
-99.50
-125.43
-132.75
-135.83
-136.55
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT tlO.OO/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0400$/1000 SCF
0.0800*/1000 SCF
0.1600*/1000 SCF
0.3200t/1000 SCF
DFFGAS
FLOW
SCFh
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58,
144.
273.
594.
955.
1671.
58.
144.
273.
594,
955.
1671,
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293,
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293,
513.
17.
42.
81.
179.
293.
, 513.
13.
44.
218.
871.
2177.
4353.
13.
44.
218.
871.
2177.
4353.
13.
44.
218.
871.
2177.
4353.
13.
44.
218.
871.
2177.
4353.
13.
44,
218.
871.
2177.
4353.
0.
0.
0.
0.
0.
0.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
25.
84.
420.
1682.
4205.
8410.
50.
168.
841.
3364.
8410.
16819.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
30.
86.
299.
1049.
2469.
4866.
24.
65.
194.
629.
1418.
2763.
17.
44.
89.
208.
367.
661 .
5.
2.
-122.
-633.
-1735.
-3544.
-20.
-82.
-542.
-2315.
-5940.
-11953.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
100.02
85.71
59.79
52.46
49.39
48.66
79.00
64.69
38.76
31.44
28.36
27.63
57.97
43.67
17.74
10.41
7.34
6.61
15.92
1.62
-24.31
-31.63
-34.71
-35.44
-68. 17
-82.48
-108.40
-115.73
-118.80
-119.53
-------
OFFGAS CARBON REQUIREMENT 8.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT 410.00/MILLION BTU
CREDIT
0.00004/1000 SCF
0.04004/1000 SCF
0.08004/1000 SCF
0.16004/1000 SCF
0.32004/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000,
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
V55.
1671.
OPERATING COST-OR-CREIUT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT(-)
(000) (000) <000) <000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81.
179.
293.
513.
26.
86.
430.
1722.
4304.
8609.
26.
86.
430.
1722.
4304.
8609.
26.
86.
430.
1722.
4304.
8609.
26.
86.
430.
1722,
4304.
8609.
26.
86.
430.
1722.
4304.
8609.
0.
0.
0.
0.
0.
0.
6.
21.
105.
420.
1051.
2102.
13.
42.
210.
841.
2102.
4205.
25.
84.
420.
1682.
4205.
8410.
50.
168.
841.
3364.
8410.
16819.
43.
128.
512.
1900.
4597.
9121.
36.
107.
407.
1480.
3546.
7019.
30.
86.
301.
1059.
2495.
4916.
18.
44.
91.
218.
392.
712.
-8.
-40.
-329.
-1464.
-3813.
-7698.
NET COST
OR SAVINGS(-)
PER SCFM
4/SCFM
142.57
128.27
102.34
95.01
91 .94
91.21
121.55
107.24
81.32
73.99
70.92
70.19
100.53
86.22
60.29
52.97
49.89
49.16
58.48
44, 17
18.24
10.92
7.84
7.12
-25.62
-39.93
-65.85
-73.18
-76.25
-76.98
-------
OFFGAS CARBON REQUIREMENT 10.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.3 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0500*/1000 SCF
0.1000$/1000 SCF
0.2000*/1000 SCF
0.4000t/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST
(000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81 .
179.
293.
, 513.
5.
17.
85.
339.
847.
1694.
5.
17.
85.
339.
847.
1694,
5.
17.
85.
339.
847.
1694.
5.
17.
85.
339.
847.
1694.
5.
17.
85.
339.
847.
1694.
CREDIT
(000)
0.
0.
0.
0.
0.
0.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051.
4205.
10512.
21024.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
22.
59.
166.
517.
1140.
2206.
14.
33.
35.
-8.
-174.
-422.
6.
7.
-97.
-534.
-1488.
-3050.
-10.
-46.
-360.
-1585.
-4116.
-8306.
-41.
-151.
-885.
-3687.
-9372.
-18818.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
73.43
59.12
33.19
25.87
22.79
22.06
47.15
32.84
6.91
-0.41
-3.49
-4.22
20.87
6.56
-19.37
-26.69
-29.77
-30.50
-31.69
-46.00
-71.93
-79.25
-82.33
-83.06
-136.81
-151.12
-177.05
-184.37
-187.45
-188.18
-------
OFFGAS CARBON REQUIREMENTIO.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 0.6 LB STEAM/ LB CARBON
AT $10.00/MILLION BTU
CREDIT
O.OOOOt/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
0.4000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
10.
33.
164.
658.
1645.
3289.
10.
33.
164.
658.
1645.
3289.
10.
33.
164.
658.
1645.
3289.
10.
33.
164.
658.
1645.
3289.
10.
33.
164.
658.
1645.
3289.
0.
0.
0.
0.
0.
0.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051.
4205.
10512.
21024.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
27.
75.
246.
836.
1937.
3S02.
19.
49.
114.
311.
623.
1174.
11 .
23.
-17.
-215.
-691 .
-1454.
-5.
-30.
-280.
-1266.
-3319.
-6710.
-36.
-135.
-805.
-3368.
-8575.
-17222.
NET COST
OR SAUINGS(-)
PER SCFM
*/SCFM
89.38
75.08
49.15
41.82
38.75
38.02
63.10
48.80
22.87
15.54
12.47
11.74
36.82
22.52
-3.41
-10.74
-13.81
-14.54
-15.74
-30.04
-55.97
-63.30
-66.37
-67.10
-120.86
-135.16
-161.09
-168.42
-171.49
-172.22
-------
OFFGAS CARBON REQUIREMENTS.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 1.0 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
O.OOOOt/1000 SCF
0.0500*/1000 SCF
0.1000$/1000 SCF
0.2000*/1000 SCF
0.4000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
(000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144,
273.
594,
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955,
1671.
OPERATING COST-OR-CREDIT
FIXED UTILITIES RECOVERY
COST CREDIT
(000) (000) (000)
17.
42.
81 .
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179,
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
> 513,
• 16.
54.
271.
1083.
2709.
5417.
16.
54.
271.
1083.
2709.
5417.
16.
54.
271.
1083.
2709.
5417.
16.
54.
271.
1083.
2709.
5417.
16.
54.
271.
1083.
2709.
5417.
0.
0.
0.
0.
0.
0.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051 .
4205.
10512.
21024.
NET
ANNUALIZED
COST OR CREDIT(-)
(000)
33.
96.
352.
1262.
3001.
5930.
25.
70.
221.
736.
1687.
3302.
17.
44.
89.
211.
373.
674.
2.
-9.
-173.
-840.
-2255.
-4582.
-30.
-114.
-699.
-2943.
-7511.
-15094.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
110.66
96.35
70.43
63.10
60.03
59.30
84.38
70.07
44.15
36.82
33.75
33.02
58.10
43.79
17.87
10.54
7.47
6.74
5.54
-8.77
-34.69
-42.02
-45.09
-45.82
-99.58
-113.89
-139,81
-147.14
-150.21
-150.94
-------
OFFGAS CARBON REQUIREMENTIO.00 LB CARBON/1000 SCF
STEAM REGENERATION RATIO 2.0 LB STEAM/ LB CARBON
AT *10.00/MILLION BTU
CREDIT
0.0000*/1000 SCF
0.0500*/1000 SCF
0.1000*/1000 SCF
0.2000*/1000 SCF
0.4000*/1000 SCF
OFFGAS
FLOW
SCFM
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
300.
1000.
5000.
20000.
50000.
100000.
CAPITAL
COST
<000)
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
58.
144.
273.
594.
955.
1671.
OPERATING COST-OR-CREIHT NET
FIXED UTILITIES RECOVERY ANNUALIZED
COST CREDIT COST OR CREDIT<->
(000) (000) (000) (000)
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
513.
17.
42.
81.
179.
293.
, 513.
32.
107.
537.
2147.
5368.
32.
107.
537.
2147.
5368.
*****
32.
107.
537.
2147.
5368.
*****
32.
107.
537.
2147.
5368.
*****
32.
107.
537.
2147.
5368.
*****
0.
0.
0.
0.
0.
0.
8.
26.
131.
526.
1314.
2628.
16.
53.
263.
1051.
2628.
5256.
32.
105.
526.
2102.
5256.
10512.
63.
210.
1051.
4205.
10512.
21024.
49.
150.
618.
2326,
5661.
11249.
41 .
123.
487.
1800.
4347.
8621.
33.
97.
355.
1275.
3033.
5993.
18.
44.
92.
223.
405.
737.
-14.
-61.
-433.
-1879.
-4B51.
-9775.
NET COST
OR SAVINGS(-)
PER SCFM
*/SCFM
163.85
149.54
123.62
116.29
113.22
112.49
137.57
123.26
97.34
90.01
86.94
86.21
111.29
96.98
71.06
63.73
60.66
59.93
58.73
44.42
18.50
11.17
8.10
7.37
-46.39
-60.70
-86.62
-93.95
-97.02
-97.75
-------
2-i
REPORT 2
CONTROL DEVICE EVALUATION
CONDENSATION
D. G. Erikson
IT Enviroscience
9041 Executive Park Drive
Knoxville, Tennessee
Prepared for
Emission Standards and Engineering Division
Office of Air Quality Planning and Standards
Environmental Protection Agency
Research Triangle Park, North Carolina
December 1980
D103R
-------
2-iii
CONTENTS OF REPORT 2
I. INTRODUCTION 1-1
A. General 1-1
II. SYSTEM DESCRIPTION II-l
A. General II-l
B. Condensation Equipment II-l
III. FACTORS INFLUENCING PERFORMANCE AND MODEL SYSTEMS III-l
A. System Efficiencies III-l
B. Base Case Model Condenser System III-4
IV. DESIGN CONSIDERATIONS IV-1
A. General IV-1
B. Capital Cost Parameters IV-1
C. Operating Cost Parameters IV-2
V. COST AND ENERGY IMPACTS OF CONDENSER SYSTEMS V-l
A. Capital Cost Estimates V-l
B. Annual Costs V-6
C. Cost Effectiveness and Energy Effectiveness V-6
VI. SUMMARY AND CONCLUSIONS VI-1
VII. REFERENCES VII-1
APPENDICES OF REPORT 2
A. BREAKDOWN OF CAPITAL COSTS FOR CONDENSER SECTION AND REFRIGERATION UNIT
B. SAMPLE CALCULATIONS
-------
2-v
TABLES OF REPORT 2
Number
III-l Parameters for Condenser System Recovery Efficiencies III-3
V-l Capital Cost Summary for Complete Condenser Systems V-2
V-2 Annual Cost Summary for 50% VOC Removal v'7
V-3 Annual Cost Summary for 80% VOC Removal v~8
V-4 Annual Cost Summary for 95% VOC Removal v"9
V-5 Annual Cost Parameters v~17
\7 1 ft
V-6 Cost-Effectiveness Summary
V-7 Energy-Effectiveness Summary V-25
-------
2-vii
FIGURES OF REPORT 2
Number
II-l Schematic Diagram of a Shell and Tube Surface Condenser
II-2 Schematic Diagram of a Contact Condenser
II-3 Basic Surface Condenser System
III-l Vapor Pressures of Selected Compounds vs Temperature
V-l Installed Capital Cost vs Flow Rate for Complete Condenser
System with a VOC Removal Efficiency of 50%
V-2 Installed Capital Cost vs Flow Rate for Complete Condenser
System with a VOC Removal Efficiency of 80%
V-3 Installed Capital Cost vs Flow Rate for Complete Condenser
System with a VOC Removal Efficiency of 95%
V-4 Annual Cost vs Flow Rate for Complete Condenser System with
VOC Recovery Efficiency of 50% and No VOC Recovery Credit
V-5 Annual Cost vs Flow Rate for Complete Condenser System with
VOC Removal Efficiency of 80% and No VOC Recovery Credit
V-6 Annual Cost vs Flow Rate for Complete Condenser System with
VOC Removal Efficiency of 95% and No VOC Recovery Credit
V-7 Net Annual Cost vs Flow Rate for Complete Condenser System with
50% VOC Removal and $0.10/lb Credit for Recovered VOC
V-8 Net Annual Cost vs Flow Rate for Complete Condenser System with
50% VOC removal and $0.20/lb Credit for Recovered VOC
V-9 Net Annual Cost vs Flow Rate for Complete Condenser System with
95% VOC Removal and $0.10/lb Credit for Recovered VOC
V-10 Net Annual Cost vs Flow Rate for Complete Condenser System with
95% VOC Removal and $0.20/lb Credit for Recovered VOC
V-ll Cost Effectiveness vs Flow Rate for Condenser System with
50% VOC Removal Efficiency and No VOC Recovery Credit
V-12 Cost Effectiveness vs Flow Rate for Condenser System with 50%
VOC Removal Efficiency and $0.10/lb Credit for Recovered VOC
V-13 Cost Effectiveness vs Flow Rate for Condenser System with 50%
VOC Removal Efficiency and $0.20/lb Credit for Recovered VOC
V-14 Cost Effectiveness vs Flow Rate for Condenser System with 95%
VOC Removal Efficiency and No VOC Recovery Credit
V-15 Cost Effectiveness vs Flow Rate for Condenser System with 95%
Removal Efficiency and $0.10/lb VOC Recovery Credit
V-16 Cost Effectiveness vs Flow Rate for Condenser System with 95%
Removal Efficiency and $0.20/lb VOC Recovery Credit
A-l Installed Capital Cost vs Condenser Area for Various Materials
of Construction for a Complete Condenser Section
A-2 Installed Capital Costs vs Refrigeration Capacity at Various
Coolant Temperatures for a Complete Refrigeration Section
II-2
II-2
II-4
III-2
V-3
V-4
V-5
V-10
V-ll
V-12
V-13
V-14
V-15
V-16
V-19
V-20
V-21
V-22
V-23
V-24
A-4
A-5
-------
1-1
I. INTRODUCTION
A. GENERAL
Condensation is an operation in which one or more volatile components of a
vapor mixture are separated from the remaining vapor by being changed to the
liquid phase through extraction of the heat of condensation. In a two-com-
ponent vapor stream, where one of the components is considered to be noncon-
densible (e.g., air), condensation occurs when the partial pressure of the
condensible component (e.g., VOC) is equal to the component's vapor pressure.
To achieve this condition the system pressure may be increased at a given
temperature or the temperature of the vapors may be reduced at constant pressure.
Condensation as an emission control method is often used with auxiliary air
pollution control equipment.1* For example, condensers can be located before
(upstream of) absorbers, incinerators, or carbon beds to reduce the VOC load on
the more expensive control device, thereby possibly reducing the size and cost
of the other control device. The condenser can also remove vapor components
that might adversely affect the operation of other equipment or cause corrosion
problems or can be used to simply recover valuable material that would otherwise
be destroyed. When condensers are used alone, as in gasoline vapor control
from bulk terminals, refrigeration is often employed to obtain the low tempera-
tures necessary for acceptable VOC removal efficiencies.
The suitability of condensation for VOC emission control is generally dependent
on the following factors: the VOC concentration in the inlet (usually above
1%); the VOC removal efficiency required; the recovery value of the contained
VOC; and the condenser size required for handling the gas flow rate.
*See Sect. VII for the references cited in this report.
-------
II-l
II. SYSTEM DESCRIPTION
A. GENERAL
When a condenser is used to control emissions, it is usually operated at the
constant pressure of the control source, which is normally atmospheric. This
report is limited to the evaluation of condensation as a VOC control method at
atmospheric pressure.
B. CONDENSATION EQUIPMENT
The two most common types of condensers that operate at atmospheric pressure
are surface and contact condensers.
I. Surface Condensers
Most surface condensers are of the shell and tube type shown in Fig. II-l.2
The coolant ususally flows through the tubes, and the vapors condense on the
outside (shell) tube surface. The condensed vapor forms a film on the cool
tube and drains away to a collection tank for storage or disposal.
The coolant used depends on the temperature required for condensation. Chilled
water, brine, and refigerants are normally used in surface condenser operation.
Air-cooled surface condensers are also available and are usually constructed
with extended surface fins. When the cool air passes over the finned tubes,
the vapors condense inside the tubes.
2. Contact Condensers
In contrast to surface condensers, where the coolant does not contact the
vapors or the condensate, contact condensers usually cool the vapor by spraying
an ambient-temperature or slightly chilled liquid directly into the gas stream.
The coolant is usually water, although in some situations a material used in
the process can be used as the coolant. These devices are relatively uncompli-
cated, as is shown by the typical design in Fig. II-2.2 Most contact condensers
are simple spray chambers that are usually baffled to ensure good contact.
3. Comparison of Surface and Contact Condensers
Both devices have advantages and disadvantages for a given operation. Final
selection will usually be based on the following comparative information.
-------
II-2
COOLANT
INLET
VAPOR
OUTLET
VAPOR
INLET
COOLANT
OUTLET
CONDENSED
VOC
Fig. II-l. Schematic Diagram of a Shell and Tube Surface Condenser
VAPOR INLET
VAPOR OUTLET
WATER
INLET
CONDENSATE
OUTLET
Fig. II-2. Schematic Diagram of a Contact Condenser
-------
II-3
1. Contact condensers are more flexible, are more simple in design, and are
less expensive to install than surface condensers. They have advantages
in corrosive situations, when particulates have to be removed, and when
the coolant is the process liquid condensed.
2. Contact condensers can be more efficient than surface condensers in remov-
ing VOC from a vent gas stream because they act as an absorber as well as
a condenser when the VOC is soluble in the coolant.
3. Spent coolant from contact condensers cannot usually be reused directly
and therefore can be a secondary emission source or a wastewater disposal
problem.
4. The coolant from surface condensers is not contaminated and normally can
be recycled.
5. Surface condensers may be equipped with more auxiliary equipment, such as
a refrigeration unit, to supply the coolant and consequently generally
require more maintenance than contact condensers.
6. Surface condensers can be used to directly recover valuable and marketable
VOC from the gas stream.
Although contact condensers can be highly efficient in removing VOC from a
vapor stream, as in vacuum jet service, they can create additional wastewater
emission control problems downstream. Unless the VOC-contaminated water discharged
from the condenser is treated (e.g., stripped, absorbed, extracted), secondary
emissions will result from evaporation. Because of this liability, only surface
condensers are evaluated in this report.
4. Condenser System Flow Sheet
Figure II-3 illustrates one of the configurations that can be utilized for a
surface condenser as an emission control device. The coolant is supplied to
the condenser by a refrigeration unit. Temperatures as low as -80°F may be
required in order to obtain the high VOC removal efficiencies needed. The
major equipment required for the condenser system includes a she11-and-tube
heat exchanger, a coolant supply, a recovery tank for the condensed VOC, and a
pump to discharge the recovered VOC to storage or disposal.
-------
II-4
INCOMING
VAPOR
CONDENSER
COOLANT
RETURN
« £&
RECOVERY
TANK
COOLANT
SUPPLY
REFRIGERATION
UNIT
VENT
©
RECOVERED VOC
TO STORAGE
PUMP
Fig. II-3. Basic Surface Condenser System
-------
III-l
III. FACTORS INFLUENCING PERFORMANCE AND MODEL SYSTEMS
A. SYSTEM EFFICIENCIES
The VOC removal efficiency of a condenser system is determined by the amount of
reduction in the VOC partial pressure in the gas stream as it passes through
the condenser. This is accomplished by reducing the temperature of the gas
stream and condensing out some of the VOC.
Any component of any vapor mixture can be recovered (condensed) if brought to
equilibrium at a low enough temperature. The temperature necessary to obtain a
particular VOC vapor concentration or removal efficiency is dependent on the
vapor pressure of the components. When a two-component vapor mixture, in which
one of the components is considered to be noncondensible, is to be cooled,
condensation will begin when the temperature reached is such that the vapor
pressure of the volatile component is equal to its partial pressure. The point
at which condensation first occurs is called the dew point. As the vapor is
cooled further, condensation continues as long as the partial pressure stays equal
to the vapor pressure. The less volatile a compound, that is, the higher the
normal boiling point, the smaller the amount that can remain as vapor at a
given temperature. Figure III-l3 shows the vapor pressure dependence on tempera-
tures for selected compounds.
Table III-l4 gives the estimated temperatures required to reduce the VOC vapor
pressures in the gas stream to obtain 50, 80, and 95% removal efficiencies at
VOC concentrations of 20, 10, 5, 2, 1, and 0.5 vol % in the gas inlet stream at
saturation conditions. The temperature and vapor pressure values represent the
pressure and temperature relationships of the aliphatic and halogenated aliphatic
hydrocarbon families of the synthetic organic chemicals manufacturing industry
and were the basis for condenser and refrigeration system sizing for this
report. A temperature of 80°F was selected for the gas stream feed to the
condenser.
The calculation methods for a gas stream containing multiple VOCs are complex,
particularly when there are significant departures from the ideal behavior of
gases and liquids. As a simplification, the temperature necessary for control
-------
III-2
1000.0
100.0 —
tn
x
E
ui
K
I
UJ
ee
e.
0.1 —
0.01
441
141
55.2 -9 -59
TEMPERATURE(°F)
•99
-131.7
Fig. III-I. Vapor Pressures of Selected
Compounds vs Temperature
-------
Table III-l. Parameters for Condenser System Recovery Efficienciesa'
VOC Concentration
(vol %)
20
10
5
2
1
0.5
Vapor
Feed to
Condenser
152
76
38
15.2
7.6
3.8
Pressure (mm Hg) Required for
50%
Removal
76
38
19
7.6
3.8
1.9
80%
Removal
30.4
15.2
7.6
3.0
1.5
0.8
95%
Removal
7.6
3.8
1.9
0.8
0.4
0.2
Temperature (°F) Required for
Feed to
Condenser
80.0
80.0
80.0
80.0
80.0
80.0
50%
Removal
53.6
55.6
56.7
57.9
59.4
60.3
80%
Removal
24.1
26.2
28.8
31.5
33.6
36.9
95%
Removal
-15.9
-11.9
-8.0
-2.4
1.8
5.0
These vapor pressure and temperature relationships represent the aliphatic hydrocarbon family and were used because
they represent an average model compound in the SOCMI. £j
See ref 4. w
-------
111-4
by condensation can be roughly approximated by the weighted average of the tem-
peratures necessary for condensation of each condensible VOC in the gas stream
at concentrations equal to the total organic concentration.
If water is present in the treated gas stream or if the VOC has a high freezing
point (e.g. benzene), normal design practice will require the use of an intermit-
tent heating cycle for removal of ice or frozen hydrocarbons in a continuous
system operated at low temperatures. Intermittently operated systems may simply
be allowed to heat up, with ambient heat used for de-icing.
B. BASE-CASE MODEL CONDENSER SYSTEM
Condenser design calculations are based on heat transfer that is affected by
the overall heat transfer coefficient, on the temperatures of the coolant and
the gas stream, and on the surface area. A mathematical solution to the problem
is usually achieved by the expression
Q = UA AT
where
Q = total heat transferred (Btu/hr),
U = overa]! heat transfer coefficient [Btu/(hr)(ft2)(°F)],
A = heat transfer surface area (ft2),
AT = mean temperature Difference between coolant and gas stream (°F).
m
In condenser design calculations A is the unknown parameter to be solved for or
determined as follows:
A = -2- '
A UAT
m
For the base-case design of the condenser and refrigeration systems used in
this report the following conditions were assumed:
1. The temperature of the initial gas stream entering the condenser is 80°F,
and the stream contains only VOC and air (two components).
2. The gas stream outlet temperatures are those shown in Table III-l for
specific VOC concentrations and removal efficiencies.
-------
II1-5
3. The air specific heat is 0.24 Btu/(Ib)(°F); the VOC specific heat is 0.50
Btu/(lb)(°F); and the VOC latent heat is 200 Btu/lb.
4. The molecular weight of the VOC is 60.
5. The overall heat transfer coefficient is 5.0.
6. The coolant inlet temperature is 10°F less than the gas stream final
temperature.
7. The coolant temperature rise through the condenser in all cases is 25°F.
8. The system heat losses, which are dependent on insulation thickness,
length of pipe, and ambient temperature, were assumed to be negligible.
The major variables evaluated for the base-case model condenser system in this
report are as follows:
1. Flow rates of 100, 500, 1000, and 2000 cfm were selected as representative
of the normal or typical range for condenser emission-control-device
applications. Flows in excess of 2000 cfm of primarily noncondensible
gases require prohibitively large-size condenser systems.
2. Removal efficiencies used were 50, 80, and 95%. An efficiency of 50% can
normally be expected when the condenser system is used in conjunction with
(usually before) another control device. An efficiency of 80% is an
average or typical efficiency reported in the literature5 and 95% is close
to the maximum efficiency reported.5
3. VOC concentrations in the gas stream to the condenser at 20, 10, 5, 2, I,
and 0.5% were chosen. High concentrations of 10 and 20% VOC would most
likely occur from intermittent operations such as loading or unloading to
or from storage facilities. The annual operating time for only these two
concentrations was estimated to be just 20% of the total annual operating
time.6 Other VOC concentrations were selected to enable cost comparisions
with the other control devices evaluated in similar reports. The applica-
tion of condensers on streams with less than 0.5% of VOC would be very
limited.
-------
IV-1
IV. DESIGN CONSIDERATIONS
A. GENERAL
The design of an optimum condenser system for a given emission control applica-
tion is relatively complex. An optimum design requires the selection of a
combination of equipment and operating conditions that will satisfy emission
control requirements at minimum overall cost. Often a change that reduces the
cost of one element (i.e., condenser size) must be balanced against the effect
it has on other costs (i.e., refrigeration requirements). Although detailed
design procedures are beyond the scope of this report, some of the more signi-
ficant design considerations and the relationships between them are discussed
briefly in this section. For simplicity, these factors are discussed specifi-
cally as they apply to a condenser system using a surface condenser with a
mechanical refrigeration unit designed to control VOC emissions at various
concentrations in air. All design and cost considerations apply to condensa-
tion as a method of VOC emission control, and may not be proportionately appli-
cable to condensation used as part of the normal operating process.
B. CAPITAL COST PARAMETERS
1. Condenser
The capital cost of condensers is primarily a function of the total heat transfer-
red and the temperature required. When the heat-transfer coefficients and the
required temperature remain relatively constant, the required areas will be
approximately proportional to the required heat-transfer rates and to the
corresponding flow rates, which in turn are functions of the emission flow rate
and the amount of VOC to be condensed.
2. Refrigeration Unit
The capital cost of the refrigeration unit is primarily a function of the
heat-transfer rates and the temperatures required. The type of coolant chosen
' for a refrigeration unit depends on the minimum temperature required: chilled
water is normally used for temperatures as low as 40°F; brine is normally used
for temperatures of -30°F; and direct-expansion coolants such as Freons are
used at temperatures below -30°F.
-------
IV-2
3. Recovery Tank
The capital cost of the VOC recovery tank primarily depends on the gas stream
flow rate and VOC composition.
4. Other Capital Requirements
Most of the other capital items to be considered, including piping, instrumen-
tation, and pumps, are independent of other design considerations.
C. OPERATING COST (CREDIT) PARAMETERS
Certain operating costs are determined by the equipment design for condenser
systems, and are briefly discussed.
1. Electrical Power
Electrical power is used mainly for the refrigeration unit that provides coolant
to the condenser and for the pumps. The power required for the refrigeration
unit is determined by the amount of refrigeration (tons) needed and the coolant
temperatures required. These are, in turn, a function of heat transfer rate
and temperatures required. Electrical power usage must be considered in arriv-
ing at the optimum condenser system design.
The power required for pump operation will be roughly proportional to the gas
flow rate through the system and will therefore vary with the concentration
and removal efficiencies selected. For the purpose of this evaluation, electri-
cal power requirements for pump operations were considered to be negligible,
compared with those for the refrigeration unit.
2. Product Recovery Credits
Product recovery credit is a function of the amount of VOC recovered and its
value. The VOC recovered is a function of the emission stream size, the VOC
concentration, and the recovery efficiency. The value of the VOC recovered is
process specific. In this study values of $0.10/lb and $0.20/lb were assumed
as typical product values for the synthetic organic chemicals manufacturing
industry.
-------
IV-3
3. Operating Labor
The only other operating cost of significance is labor. Operating labor is
relatively constant regardless of the size of the system, and consists mainly
of monitoring the operation of the condenser and refrigeration systems. Operat-
ing labor is estimated to be 10% of the total operating time, or 876 hr annually,
and probably represents a higher or maximum value.
-------
V-l
V. COST AND ENERGY IMPACTS OF CONDENSER SYSTEMS
A. CAPITAL COST ESTIMATES
1. General
The estimated capital costs for a complete condenser system such as that de-
scribed in Sect. II represent the total investment, including all indirect
costs such as engineering and contractors' fees and overheads required for the
purchase and installation of all equipment and material to provide a facility
as described. These are battery-limit costs and do not include provisions for
bringing utilities, services, or roads to the site; backup facilities; land;
required research and development; or process piping interconnections that may
be required within the process generating the waste gas flow to the condenser
system.
The estimated costs are based on a new-plant installation,- retrofit costs are
not included. Such costs are usually higher than those for a new-site instal-
lation for a similar system and include, for example, demolition, crowded
construction working conditions, scheduling construction activities with pro-
duction activities, and longer runs of interconnecting piping. These factors
are so site specific that no attempt was made to provide costs. For specific
cases rough costs can be obtained by using the new-site cost data and adding
additional costs as required for a specific retrofit situation.
Capital cost estimates represent the total installed capital costs for the
condenser section and its refrigeration unit (see Appendix A for the breakdown
of these costs). These costs are based on IT Enviroscience experience adjusted
to a December 1979 basis. In addition to the capital costs a contingency
allowance of 30% is included in the overall capital cost estimates.
2. Model Systems
Estimated capital costs for the complete condenser system described in Sect. II
are given in Table V-l. The installed capital cost, shown in Figs. V-l through
V-3, were developed for the model system illustrated in Fig. II-3, in which the
condenser is a common she11-and-tube type with a mechanical refrigeration
system for providing the coolant.
-------
Table V-l. Capital Cost Summary for Complete Condenser Systems
Capital
20*
Cost (10 S) at VOC Concentrations
of
10%
At Gas Flow Rates (cfrn)
Equipment
sn» \JTV- .-<.n*-,ir:i'l
Condenser section
Refrigeration unit
Total
80% VOC removal
Condenser section
Refrigeration unit
Total
95* VOC removal
Condenser section
Total
100
77.
5.
82.
70.
10.
80.
63.
26.
89.
.0
.4
.4
.0
.7
.7
.0
.0
.0
500
195.
18.
.0
.0
213.0
175.
37.
212
158.
87
245
.0
.0
.0
.0
.0
.0
1000
302 .
32.
334.
270.
2000
0
0
0
0
62.0
332.
240.
145.
385.
0
0
0
0
475.
52.
527.
0
0
0
420.0
107.0
527.
380.
250.
63O.
0
0
0
0
100
59.0
3.8
62.8
53.0
7.0
60.0
50.0
15.8
65.8
500
145.0
11.5
156.5
127.0
24.0
151.0
118.0
57.0
175.0
1000
222.0
20.0
242.0
192.0
36,0
230.0
179.0
90.0
269.0
of
2000
342.
32.
.0
.0
374.0
300.
67.
367
275.
165
440
.0
.0
.0
.0
.0
.0
Capital Cost (10
5»
2%
At Gas
100
47.0
3.
50.
43
4
47
41.
11
52
.8
.8
.0
.5
.5
.0
.1
.1
500
110.0
8.0
118.0
98.0
15.4
113.4
94.0
• 36.5
130.4
1000
165.0
13.0
178.0
145.0
26.2
172..2
140.0
63.0
203.0
2000
254.
21.
.0
.0
275.0
225.
44.
269
.0
.0
.0
215.0
107.0
322
.0
100
38.0
3.8
41.8
36.0
4.5
40.5
36.0
8.7
44.7
500
85.0
5.3
90.3
77.0
11.7
88.7
76.0
31.7
107.7
1000
125.0
8.7
133.7
115.0
20.0
135.0
112.0
49.8
161.8
2000
190
15
205
171
34
205
170
84
254
.0
.1
.1
.0
.3
.3
.0
.8
.8
100
35.
3.
.0
.8
38.8
33,
3.
36
34.
7
41
.0
.8
.8
.0
.2
.2
3 S) at VOC
1%
Flow Rates (<
500
75.0
4.1
79.1
69.0
9.8
78.8
70.0
22.6
92.6
1000
111.
7.
118.
102.
17.
0
2
2
.0
,3
119.3
103.
38
141
.0
.1
.1
2000
170.
12.
182.
100
0
4
4
150.0
28
178
.3
.3
151.0
64.8
215
.8
34.
3.
37.
32.
3.
35.
0
8
8
.0
.8
.8
32.0
6.0
38
.0
0.5*
500
72.0
3.8
75.8
64.0
8.3
72. 3
65.0
18.9
83.9
1000
105.0
6.0
111.0
94.0
13.6
107.6
96.0
32.8
128.8
2000
158.0
10.2
168.2
140.0
. 23.4
163.4
145.0
56.6
201.6
f
(0
-------
700
=5- 600
c
o
(/>
1
I- 500
O
O
t! 300
r-
o>
-------
700
600
c
o
(/>
o
500
g- 400
O
T3
c
en
CT>
0>
E
0)
300
200
100
20%VOC
10%VOC
5%VOC
2% VOC
1%VOC
0.5% VOC
_L
j L
200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400
Gas Flow to Condenser (scfm)
Fig. V-2. Installed Capital Cost vs Flow Rate for Complete Condenser
System with a VOC Removal Efficiency of 80%
f
-------
700
•$ 600
c
o
tn
3
O
H 500
g-400
O
•g
300
200
s
20% VOC
10% VOC
5% VOC
2% VOC
1%VOC
0.5% VOC
J L
200
Fig. V-3.
400 600 800 1000 1200 1400 1600
Gas Flow to Condenser fecfm)
1800 2000 2200 2400
Installed Capital Cost vs Flow Rate for Complete Condenser
System with a VOC Removal Efficiency of 95%
f
Ul
-------
V-6
Costs were developed for the model system for gas flow rates of 100, 500, 1000,
and 2000 scfm, for VOC removal efficiencies of 50, 80, and 95%, for VOC concen-
trations in the gas stream of 20, 10, 5, 2, 1, and 0.5 vol %, and for the tem-
perature—vapor-pressure relationships given in Table III-l.
3. Criteria and Limitations
Costs for other system configurations and special requirements, including cor-
rosive conditions and high humidity, can be estimated by the procedures that
were used in the development of these estimates. If corrosive conditions were
present, more stringent materials of construction would be required and the
capital costs would be correspondingly higher. Sample calculations are shown
in Appendix B.
B. ANNUAL COSTS
Annual costs for various operating conditions are given in Tables V-2 through
V-4 and Figs. V-4 through V-10. These costs were the basis for all the cost-
effectiveness graphs included in this report. The basis for calculating annual
costs is defined in Table V-5.
Product recovery values used in the calculation of net annual cost were zero,
IOC, and 20C per pound of VOC recovered.
C. COST EFFECTIVENESS AND ENERGY EFFECTIVENESS
The cost effectiveness and energy effectiveness were calculated by dividing the
annual cost for a particular operating condition (Tables V-2, 3, and 4) or
energy consumption (e.g., electrical power) by the total annual amount of VOC
recovered with the indicated removal efficiencies.
Typical cost-effectiveness values are presented in Table V-6 and in Figs. V-ll
through V-16, and energy effectiveness values are given in Table V-7. Values
for conditions that are not given in the cited tables or graphs can be deter-
mined by the methods given in Appendix B.
-------
Table V-2. Annual Cost Summary for 50% VOC Removal
Fixed costs (29% of capital)
Electricity (50.03/kWh)
Labor (515/hr)
Total annual cost
VOC recovery credit
8 SO.lO/lb
9S0.20/lb
8 SO.lO/lb
3 S0.20/U)
100
23.9
0.1
13.1
37.1
16.6
33.3
20.5
3.8
20ta
500 1000 2000
61.8 96.9 152.8
0.5 1.0 2.0
13.1 13.1 13.1
75.4 111.0 167.9
83.2 166.4 332.9
166.4 332.9 665. fl
(7.8) (55.4) (165.0)
(91.0) (211.9) (497.9)
Annual Cost
At
100
18.2
0.1
13.1
31.4
8.3
16.6
23.1
14.3
(103 S) at VOC Concentrations of
Gas Flow
500
45.4
0.3
13.1
58.8
41.6
83.2
17.2
(24.4)
Annual Cost (103 S)
Fixed costs (29% of capital)
Electricity ($0.03/kwh)
labor ($15/hr)
VOC recovery credit
9 SO.lO/lb
§ $0.20/lb
9 SO.lO/lb
9 $0.20/lb
100
12.1
0.1
13.1
8,3
16.6
16.9
8.6
2*
500 1000 2000
26.2 38.8 59.5
0.5 0.9 1.8
13.1 13.1 13.1
41.6 83.2 166.4
83.2 166.4 332.9
(1.8) (30.4) (92.0)
(43.4) (113.6) (258.5)
At
100
11.3
0.1
13.1
4.2
8.3
20.2
16.1
Gas Flow
500
22.9
O.3
13.1
20.8
41.6
15.5
(5.3)
10%a
Rates (cfin) of
1000
70 t2
0.5
13.1
83.8
83.2
166.4
0.6
(82.6)
2000 100
108.5 14.7
1.1 0.2
13.1 • 13.1
122.7 28.0
166.4 20.8
332.9 41.6
(43.7) 7.2
(200.2) (13.6)
5%
500 1000 2000
34.2 51.6 79.8
0.8 1.6 3.2
13.1 13.1 13.1
48.1 66.3 96.1
104.0 208.1 416.1
208.1 416.1 832.2
(55.9) (141.8) (320.0)
(160.0) (349.8) (736.1)
<
1
at VOC Concentrations of
1%
Rates (cfm) of
1000
34.3
0.6
13.1
41.6
83.2
6.4
(35.2)
2000 100
52.9 11.0
1.3 0.1
13.1 13.1
83.2 2.1
166.4 4.2
(15.9) 22.0
(99.1) 19.9
0.5»
500 1000 2000
22.0 32.2 48.8
0.3 0.6 1.1
13.1 13.1 13.1
10.4 20.8 41.6
20.8 41.6 83.2
25.0 25.1 21.4
14.6 4.3 (20.2)
Based on 1752-hr/yr operation.
-------
Table V-3. Annual Cost Summary for 80% VOC Removal
t»,«/* ^nct-c r?q* of caoital)
Electricity (S0.03A«M
Labor (515/hr)
Total annual cost
VOC recovery credit
a SO.lO/lb
3 $0.20/lb
9 $0.10/lb
g 50.20/lb
Fixed costs (29t of capital)
Electricity ($0.03/kWh)
Labor (S15/hr)
VOC recovery credit
8 50.10/lb
ia S0.20/lb
Net annual cost (credit)
9 $0.10/lb
a $0.20/lb
20»a
100 500 1000 2000
23.4 61.5 96.3 152.8
0.2 1-1 2-2 4-5
13 1 13.1 13.1 13.1
36.7 75.7 111.6 170.4
26.6 133.2 266.3 532.6
53.3 266.3 532.6 1065.2
1Q.1 (57.5) (154.7) (362.2)
(16.6) (190.6) (421.0) (894.8)
2*
100 500 1000 2000
11.7 25.7 39.2 59.5
0.2 1.2 2.4 4.8
13.1 13.1 "-I I3'1
25.0 40.0 54.7 77.4
13.3 66.6 133.2 266.3
26.6 133.2 266.3 532.6
H.7 (26.6) (78.5) (188.9)
(1.6) (93.2) (211.6) (455.2)
Annual Cost (103 $1
At Gas Flow
100 500
17.4 43.8
0.1 0.6
13.1 13.1
30.6 57.5
13.3 66.6
26.6 133.2
17.3 (9.1)
4.0 (75.7)
Rnnual Cost (10 5)
ftt Gas Flow
100 500
10.7 22.9
0.1 1.0
13.1 13.1
23.9 37.0
6.7 33.3
13.4 66.6
17.2 3.7
10.5 (29.6)
10%a
Rates (cfm) of
1000
66.7
1.3
13.1
81.1
133.2
266.3
(52.1)
(185.2)
5»
2000 100 500 1000 2000
106.4 13.8 32.9 49.9 78.0
2.5 0.4 2.0 3.9 7.8
13.1 13.1 13.1 13.1 13.1
122.0 27.3 48.0 66.9 98.9
266.3 33.3 166.4 332.9 665.8
532.6 66.6 332.9 665.8 1331.6
(144.3) (6.0) (118.4) (266.0) (566.9)
(410.6) (39.3) (284.9) (598.9) (1232.7)
f
00
at VOC Concentrations ot
1% 0-5*
Rates (cfm) of
1000
34.6
1.9
13.1
48.9
66.6
133.2
(17.7)
(84.3)
2000 100 500 1000 2000
51.7 10.4 21.0 31.2 47.4
3.5 0.2 0.8 1.5 3.1
13.1 13.1 13.1 13.1 13-1
68.6 23.7 34.9 45.8 63.6
133.2 3.3 16.6 33.3 66.6
266.3 6.6 33.3 66.6 133.2
(64.6) 20.4 18.3 12.5 (3.0)
(197.7) 17.1 1.6 (20.8) (69.6)
-------
Table V-4. Annual Cost Summary for 95% VOC Removal
100
Fixed costs (29% of capital) 25.8
Electricity ($0.03/kwh) o.S
Total annual cost 39.4
VOC recovery credit
3 $0.10/Lb 31.6
@ S0.20/lb 63.3
Net annual cost (credit)
8 SO.lO/lb 7.8
& $0.20/lb (23.9)
100
Fixed costs (29* of capital) 13.0
Electricity <$0.03Avrti) 0.7
Total annual cost 26.8
VOC recovery credit
3 $0.10/lb 15.8
9 $0.20/lb 31.6
§ SO.lO/lb 11.0
? S0.20/Lb (4-8)
20%a
500 1000 2000
71.1 111.7 182.7
2.7 5.4 10.8
13.1 13.1 13.1
86.9 130.2 206.6
158.1 316.2 632.5
316.2 632.5 1T65.0
(71.2) (186.0) <425.9)
(229.3) (502.3) (1058.4)
2*
500 1000 2000
31.2 46.9 73.9
3.4 6.7 13.4
13 1 13.1 13.1
47.7 66.7 100.4
79.1 158.1 316.2
158.1 316.2 632.4
(31.4) (91.4) (215.9)
(110.4) (249.5) (532.0)
Annual Cost (103 $) a
At Gas Flow
100 500
19.1 50.8
0.3 1.6
13.1 13.1
32.5 65.5
15.8 79.1
31.6 158.1
16.7 (13.6)
0.9 (92.6)
Annual Cost (103 $)
At Gas Flov
100 500
11.9 26.8
0.5 2.7
13.1 13.1
25. S 42.6
7.9 39.5
15.8 79.1
17.6 3.1
9.7 (36.5)
,t VOC Concent
10*a
Rates (cfm) o
1000
78.0
3.2
13.1
94.3
158.1
316.2
(63.8)
(221.9)
at VOC Co nee r
1%
rf Rates (cfm)
1000
40.9
5.4
13.1
59.4
79.1
158.1
(19.7)
(98.7)
rations of
5»
f . ___ —
2000 100 500 1000 2000
127.6 15.1 37.8 58.9 93.4
6.4 1.0 5.1 10.2 20.5
13 1 ' 13.1 13.1 13-1 I'-l
147.1 29.2 56.0 82.2 127.0
316.2 39.5 197.6 395.3 790.6
632.4 79.1 395.3 790.6 1581.2
(169.1) (10.3) (141.6) (313.1) (663.6)
(485.3) (49.9) (339.3) (708.4) (1454.2)
f
U)
itrations of
0.5%_
of -
2000 100 500 1000 2000
62.6 11.0 24.3 37.4 58.5
10.7 0.5 2.4 4.7 9.4
11 i n.l 13.1 13.1 13-1
86.4 24.6 39.8 55.2 81.0
158.1 4.0 19.8 39.5 79.1
316.2 7.9 39.5 79.1 158. 1
(71.7) 20.6 20.0 15-7 1.9
(229.8) 16.7 0.3 (23.9) (77.1)
BaseJ on 1752-hr/yr operation.
-------
300
5%VOC
2%VOC
1%VOC
0.5%VOC
200
400
600
800
1000 1200 1400
Gas Flow to Condenser (scfm)
1600
1800
2000
2200
2400
Fig V-4. Annual Cost vs Flow Rate for Complete Condenser System with
VOC Recovery Efficiency of 50% and No VOC Recovery Credit
-------
300
250
o
Q)
200
TJ
I
O
.C
150
o
o
§ 100
c
c
50
JL
_L
20%VOC
10%VOC
5%VOC
2%VOC
1%VOC
0.5%VOC
±
J_
0
200 400 600 800 ' 1000 1200 1400
Gas Flow to Condenser (scfm)
1600
1800
2000
2200
2400
Fig. V-5. Annual Cost vs Flow Rate for Complete Condenser System with
VOC Removal Efficiency of 80% and No VOC Recovery Credit
-------
300
250
200
•o
o
to
o
150
-------
W. I/)
O O
0) 0
at
o
O
200
100
— 0
100
200
300
400
500
600
700
800
J_
_L
0.5% VOC
1% VOC
10% VOC
2% VOC
20% VOC
5% VOC
0 200 400 600 800 1000 1200 1400 1600
Gas Flow to Condenser (cfm)
1800
2000
Fig. V-7. Net Annual Cost vs Flow Rate for Complete Condenser System with
50% VOC Removal and $0.10/lb Credit for Recovered VOC
j_
f
2200 2400
-------
200
400
600
800 1000 1200 1400 1600
Gas Flow to Condenser (cfm )
1800 2000 2200 2400
Fig.
V-8. Net Annual Cost vs Flow Rate for Complete Condenser System with
50% VOC Removal and $0.20/lb Credit for Recovered VOC
f
-------
200
1000
f
M
Ul
200
400
600
800 1000 1200 1400 1600
Gas Flow to Condenser (cfm)
1800 2000 2200 2400
Fig V-9. Net Annual Cost vs Flow Rate for Complete Condenser System with
95% VOC Removal and $0.10/lb Credit for Recovered VOC
-------
O
TJ
100
200
300
400
500
8 600
o
f 700
**
~ 800
o
^ 900
o
| 1000
•5 1100
2
1200
1300
1400
1500
1600
10% VOC
2% VOC
20% VOC
5% VOC
I
I
I
I
I
I
200 400 600 800 . 1000 1200 1400 1600
Gas Flow to Condenser (cfm)
1800
2000 2200
f
2400
Fig. V-10. Net Annual Cost vs Flow Rate for Complete Condenser System with
95% VOC Removal and $0.20/lb Credit for Recovered VOC
-------
V-17
Table V-5. Annual Cost Parameters
Operating factor for 0.5, 1.0, 2.0 and 5.0%
VOC streams
Operating factor for 10.0 and 20.0% VOC streams
Operating labor
Fixed costs
Maintenance labor plus materials, 6%
c
Capital recovery 18%
Taxes, insurance, administrative charges, 5%
Utilities
Electric power
8760 hr/yra
1752 hr/yrb
$15/man-hour
29% installed capital
$0.03/kWh
Process downtime is normally expected to range from 5 to 15%. If the hourly
rate remains constant, the annual production and annual VOC emissions will be
correspondingly reduced. Control devices will usually operate on the same
cycle as the process. From the standpoint of cost-effectiveness calculations
the error introduced by assuming continuous operation is negligible.
bHigh concentrations of VOC, i.e., 10 and 20%, would most likely occur from
intermittent operations such as loading and unloading into and from storage
facilities. Total annual operating time for these operating conditions was
estimated to be 20% of the year, or 1752 hr.
°Based on 10-year life and 12% interest.
-------
Table V-6. Cost-Effectiveness Summary
Cost Effectiveness
(S/lb) of VOC Removed at VOC
20%a
Recovery Credit
@ 95 * recovery
No credit
SO.lO/lb
S0.20/lb
@ 80% recovery
No credit
SO.lO/lb
S0.20/lb
@ 50% recovery
No credit
$0.10/lb
?0.20/lb
Recovery Credit
@ 95% recovery
No credit
SO.lO/lb
S0.20/lb
a ao% recovery
No credit
$0.10/lb
S0.20/lb
@ 50% recovery
Ho credit
SO.lO/lb
S0.20/lb
100
0.125
0.025
(0.076)
0.138
0.038
(0.062)
0.223
0.123
0.023
100
0.169
0.070
(0.030)
0.188
0.088
(0.012)
0.303
0.203
0.103
500
0.055
(0.045)
(0.145)
0.057
(0.043)
(0.143)
0.091
(0.009)
(0.109)
500
0.060
(0.040)
(0.140)
0.060
(0.040)
(0.140)
0.096
(0.004)
(0.104)
1000
0.041
(0.059)
(0.159)
0.042
(0.058)
(0.158)
0.067
(0.033)
(0.127)
2%
1000
0.042
(0.058)
(0.158)
0.041
(0.059)
(0.159)
0.063
(0.037)
(0.137)
2000
0.032
(0.067)
(0.167)
0.032
(0.068)
(0.168)
0.050
(0.050)
(0.150)
2000
0.032
(0.068)
(0.168)
0.029
(0.071)
(0.171)
0.045
(0.055)
(0.155)
100
0.206
0.106
0.006
0.230
0.130
0.030
0.377
0.278
0.178
Cost Effectiveness
100
0.322
0.223
0.123
0.359
0.258
0.158
0.586
0.485
0.387
At Gas
500
0.083
(0.017)
(0.117)
0.086
(0.014)
(0.114)
0.141
0.041
(0.059)
(S/lb)
At Gas
500
0.108
0.008
(0.092)
0.111
0.011
(0.089)
0.174
0.075
(0.025)
io%a
Flow Rates (cfm) of
1000
0.060
(0.040)
(0.140)
0.061
(0.039)
(0.139)
0.101
0.001
(0.099)
of VOC Removed at VOC
1%
Flow Rates (cfm) of
1000
0.075
(0.025)
(0.125)
0.073
(0.027)
(0.127)
0.115
0.015
(0.085)
Concentrations
2000
0.047
(0.053) •
(0.153)
0.046
(0.054)
(0.154)
0.074
(0.026)
(0.120)
Concentrations
2000
0.055
(0.045)
(0.145)
0.052
(0.049)
(0.148)
0.081
(0.019)
(0.119)
of
100
0.074
(0.026)
(0.126)
0.082
(0.018)
(0.118)
0.135
0.035
(0.065)
of
100
0.622
0.521
0.422
0.712
0.613
0.514
1.158
1.057
0.957
500
0.028
(0.072)
(0.172)
0.029
(0.071)
(0.171)
0.046
(0.054)
(0.154)
500
0.201
0.101
(0.002)
0.210
0.110
0.010
0.340
0.240
0.140
5%
1000
0.021
(0.079)
(0.179)
0.020
(0.080)
(0.180)
0.032
(0.068)
(0.168)
0.5%
1000
0.140
0.040
(0.060)
0.138
0.038
(0.062)
0.221
0.121
0.021
2000
0.016
(0.084)
(0.184)
0.015
(0.085)
(0.185)
0.023
(0.077)
(0.177)
1
oo
2000
0.102
0.002
(0.098)
0.096
(0.005)
(0.105V
0.151
0.051
(0.049)
Based on 1752-hr/yr operation.
-------
f
M
vo
0
200
400
600 800 1000 1200 1400 1600
Gas Flow Rate to Condenser (cfm)
1800
2000 2200
Fig. V-ll. Cost Effectiveness vs Flow Rate for Condenser System with
50% VOC Removal Efficiency and No VOC Recovery Credit
-------
TJ
1
&
O
o>
)
0>
o
o
1.2
1.1
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
— 0
0.2
0.3
VOC
"0.5%
f
_L
J L
J I i I
200 400 600 800 1000 1200 1400 1600
Gas Flow Rate to Condenser (cfm)
1800 2000
2200
Fig. V-12. Cost Effectiveness vs Flow Rate for Condenser System with
50% VOC Removal Efficiency and $0.10/lb Credit for Recovered VOC
-------
1.1 I—
f
200
400
600 800 1000 1200 1400 1600
Gas Row Rate to Condenser (cfm)
1800 2000 2200
Fig. V-13. Cost Effectiveness vs Flow Rate for Condenser System with
50% VOC Removal Efficiency and $0.20/lb Credit for Recovered VOC
-------
0.70
f
0
200
400
600 800 1000 1200 1400
Gas Flow Rate to Condenser (cfm)
1600
1800 2000 2200
Fig. V-14. Cost Effectiveness vs Flow Rate for Condenser System with
95% VOC Removal Efficiency and No VOC Recovery Credit
-------
f
M
CO
200
400
600 8OO 1000 1200 1400 1600
Gas Flow Rate to Condenser (cfm)
1800
2000 2200
Fig. V-15. Cost Effectiveness vs Flow Rate for Condenser System with
95% Removal Efficiency and $0.10/lb VOC Recovery Credit
-------
0.5
0.4
0.3
O Oo
o u^
>
0.1
in
w
II
.
TJ
O)
o o 1
o
0.2
5°/c
I I 1
I I _L
200 400 600 800 1000 1200 1400 1600 1800 2000 2200
Gas Flow Rate to Condenser (cfm)
<:
to
Fig. V-16. Cost Effectiveness vs Flow Rate for Condenser System with
95% Removal Efficiency and $0.20/lb VOC Recovery Credit
-------
Table V-7. Energy-Effectiveness Summary
Energy Effectiveness (Btu/lb of
VOC Concentrations of
VOC Removal Efficiency
50%
80%
95%
20%
67.0
95.9
194.7
10%
72.9
108.9
229.4
5%
86.9
133.4
294.5
2%
123.3
206.0
483.5
VOC) at
1%
176.9
324.9
773.0
0.5%
311.0
529.3
1359.7
-------
VI-1
VI. SUMMARY AND CONCLUSIONS
Condensation as an emission control method is currently most widely used as a
preliminary or auxiliary step for other control devices. When condensation
only is used for control of VOC emissions at atmospheric pressures, it is done
in conjunction with a refrigeration unit to supply coolant at temperatures that
will allow acceptable VOC recovery efficiencies.
The suitability of condensation as a VOC emission control method compared to
other alternatives (primarily carbon adsorption and thermal oxidation) depends
on the concentration of the VOC in the treated stream, the flow rate of the
treated stream, and the value of the recovered VOC components.
Estimates of capital costs, operating costs, and cost effectiveness were de-
veloped for a number of combinations of conditions or variables to illustrate
the effects that changes in these variables would have on the costs. Some of
the conclusions derived from the cost evaluation are as follows:
1. At low VOC concentrations the cost effectiveness of condensation is very
sensitive to the gas flow rate.
2. In general condensation systems are economical as an emission control
provided that the gas stream contains high concentrations of VOC that have
a value of at least $0.1Q/lb.
3. The cost effectiveness of condensation at low flow rates and low VOC
concentrations is usually uneconomical regardless of the recovery effi-
ciencies achieved.
-------
VI I-1
VII. REFERENCES*
1. Control Techniques for Volatile Organic Emissions from Stationary Sources, EPA,
OAQPS, Research Triangle Park, NC, Final Draft (February 1978).
2. J. H. Danielson, Air Pollution Engineering Manual, 2d ed., Air Pollution Control
District, County of Los Angeles.
3. Control of Volatile Organic Emissions from Existing Stationary Source.
Vol. 1. Control Methods for Surface-Coating Operations. Guideline Series,
EPA-450/2-76-028 (OAQPS No. 1.2-067) (November 1976).
4. Robert R. Dreisbach, Pressure-Volume-Temperature Relationships of Organic
Compounds, 3d ed., Handbook Publishers, Inc., Sandusky, OH, 1952.
5. Control of Hydrocarbons from Tank Truck Gasoline Loading Terminals, Guideline
Series, EPA-450/2-77-026 (OAQPS No. 1.2-082) (October 1977).
6. Marine Hydrocarbon Vapor Recovery Units for Loading Gasoline Into: Tankers,
Barges, and Fixed Roof Storage Tanks, Edwards Engineering Corp., Pompton
Plains, NJ.
*When a reference number is used at the end of a paragraph or on a heading,
it usually refers to the entire paragraph or material under the heading.
When, however, an additional reference is required for only a certain portion
of the paragraph or captioned material, the earlier reference number may not
apply to that particular portion.
-------
APPENDIX A
BREAKDOWN OF CAPITAL COSTS FOR
CONDENSER SECTION AND REFRIGERATION UNIT
-------
A-3
BREAKDOWN OF CAPITAL COSTS FOR CONDENSER SECTION AND REFRIGERATION UNIT
The installed capital costs for the condenser section, which includes a shell-
and-tube condenser, a storage tank, a pump and the necessary piping and instru-
ments, are plotted in Fig. A-l as a function of the condenser area, with the
tank, pump, pipes, and instruments sized accordingly. A 30% allowance for
contingencies is included in these costs. The installed capital costs for the
refrigeration unit, which includes the compressor, the condenser expension
valve, the evaporator, controls, foundations, and all auxiliary components
except extensive runs of piping for the product or coolant lines, are plotted
in Fig. A~2 as a function of the amount of refrigeration required (tons) at
coolant temperatures ranging from +40°F to -60°F.
The costs plotted in Fig. A-l are for carbon steel, type 304 stainless steel,
and Monel, but the equipment cost estimates given in Sect. V are based on the
use of carbon steel construction throughout.
Other criteria used in the selection of equipment parameters and cost estimates
are as follows:
1. Condensers: carbon steel; 150 psig; fixed-tube sheet; l-in.-diam tubes
8 ft long; piping, same material as tubes and shell,- include foundation or
share of structure
2. Storage tank: 50 psi vertical type, ASME; concrete foundation,- platform,
dike, and transfer piping at tank
3. Pump.- ductile iron, single-stage centrifugal pump, includes 200 ft of
conduit run, standard valuing, and 100 ft of carbon steel; suction plus
discharge piping
4. Instruments: temperature indicator, temperature transmitter, control
valve, and level transmitter with hi-lo start-stop operation of pump
-------
A-4
10,000
10
100 1,000
Condenser System Area (Ft2)
10,000
Fig. A-l. Installed Capital Cost vs Condenser Area for Various
Materials of Construction for a. Complete Condenser Section
-------
December 1979 Installed Capital (8 Thousand)
H-
O t£)
01 >
O I
H- to
ft •
O pJ H
3 ft 3
^0 in
H < rt
CD pi p)
rt H H
CD P- M
O CD
(D in
Hi O
HOP)
H- 0 'O
GQ 0 p-
CD M rt
H pi P)
QJ 3 \—I
rt rt
H- O
O H O
3 CD in
3 rt
en n3 in
CD CD
o n <
rt pi in
!-•• rt
O c;
-------
APPENDIX B
SAMPLE CALCULATIONS
-------
B-3
SAMPLE CALCULATIONS
The following sample calculations are based on a vent gas stream flowing at a
rate of 1000 cfm and having a VOC content of 1.0%. The recovery rate required
is 95%. The cost effectiveness is determined for a recovered-product value of
$0.10/lb.
Capital cost
$141,000 (from Fig. V-3)
Fixed cost
Capital cost X 0.293 = $141,000 X 0.29 = $40,900
Labor cost
(876 hr X 15 $/hr)a = $13,100
Power cost
In order to estimate the power cost for refrigeration the total heat transfer (Q)
required must be determined. The total heat transfer required is a summation
of the specific heat of air, the specific heat of the VOC, and the latent
heat of vaporization of the VOC at the temperatures required for 95% recovery
efficiency.
Material Balance:
Gas flow = 1000 cfm -r 379 ft3/lb-mole X 60 min/hr = 158.311 Ib-moles/hr
VOC = 158.311 Ib-moles/hr X 1.0% = 1.583 Ib-moles X 60 AMWT = 95 Ib/hr
Air = 158.311 Ib-moles/hr X 99% = 156.73 Ib-moles X 29 AMVT = 4,550 Ib/hr
Energy Balance:
Total heat transferred (Q) = air specific heat + VOC specific heat +
VOC latent heat ,
Air = 4,550 Ib/hr X 0.24 Btu/(lb)(°F)C X (80°F - 1.8°F) = 85,400 Btu/hr
VOC = 95 Ib/hr X 0.50 Btu/(lb)(°F) X (80°F - 1.8°F) = 3,710 Btu/hr
VOC = 95 Ib/hr X 200 Btu/lb° X 95% recovered = 18,040 Btu/hr
Q = 85,400 Btu/hr + 3,710 Btu/hr + 18,040 Btu/hr = 107,150 Btu/hr
aSee Table V-2.
Average molecular weight.
CBased on assumptions given in Sect. III-B.
dSee Table III-l.
-------
B-4
r, ^ • Q 107,150 Btu/hr „ n ^ ,,
Refrigeration = 12fOQ0 (Btu/hr)/ton = 12,000 (Btu/hr)/ton = 8'9 tOns/hr
Power = — 8.9 tons/hr X 2.23 hp/ton6
0.85 compressor efficiency X 0.85 motor efficiency
=27.4 hp/hr X 0.746 kWh/hp X 8760 hr/yr = 179,058 kWh/yr
= 179,058 kWh/yr X $0.03/kWha = $5,400/yr
Credit
Ib of VOC recovered X $0.10/lb
Flow = 1000 cfm = 158.311 Ib-moles/hr
= 158.311 Ib-moles/hr X 1.0% = 1.583 Ib-moles of VOC X 60 AMW*3 = 95 Ib/hr
= 95 Ib/hr X 95% X 365 days/yr X 24 hr/day = 790,590 Ib/yr
= 790,590 Ib/yr X $0.10/lb = $79,100
Net annual cost
$40,900 + $13,100 + $5,400 - $79,100 = $19,700 (credit)
Cost effectiveness
$19,700 4- 790,590 Ib = $0.025/lb (credit)
6See Fig. A-2.
-------
3-i
REPORT 3
CONTROL DEVICE EVALUATION
GAS ABSORPTION
R. L. Standifer
IT Enviroscience
9041 Executive Park Drive
Knoxville, Tennessee
Prepared for
Emission Standards and Engineering Division
Office of Air Quality Planning and Standards
ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park, North Carolina
October 1980
D96A
-------
3-iii
CONTENTS OF REPORT 3
I. INTRODUCTION I~1
II. SYSTEM DESCRIPTION IJ~
A. Absorption Equipment
B. Solvent Requirements
TT — ft
C. System Flowsheets
III. SYSTEM EFFICIENCIES III-l
, III-l
A. General
B. System with Once-Through Solvent Usage III-6
C. Systems with Solvent Recycle III-6
TV-1
IV. DESIGN CONSIDERATIONS
A. General
IV-1
B. Capital Costs Parameters
C. Operating Cost (Credit) Parameters IV~3
V. COST AND ENERGY IMPACTS OF GAS ABSORPTION SYSTEMS V-l
V-l
V-29
V-l
A. Capital Cost Estimates
B. Annual Costs
C. Cost Effectiveness and Energy Effectiveness v"31
VI. SUMMARY AND CONCLUSIONS VI"1
APPENDICES OF REPORT 3
A ADDITIONAL CAPITAL AND COST SUMMARY CASES AND COST-EFFECTIVE TABLES A-l
B-l
B SAMPLE CALCULATIONS
-------
3-v
TABLES OF REPORT 3
Number Page
V-l Capital Cost Summary for Absorber and Stripper Systems V-2
V-2 Annual Cost Parameters V-30
V-3 Cost Effectiveness Summary V-32
V-4 Energy Effectiveness Summary V-33
A-l Capital Cost Summary for 99% VOC Removal and with Stripping A-3
A-2 Capital Cost Summary for 99.9% Removal and No Stripping A-4
A-3 Capital Cost Summary for 90% VOC Removal and No Stripping A-5
A-4 Capital Cost Summary for 99% VOC Removal and No Stripping A-6
A-5 Annual Cost Summary for 99% VOC Removal and No Stripping A-7
A-6 Annual Cost Summary for 99.9% VOC Removal and No Stripping A-8
A-7 Annual Cost Summary for 90% VOC Removal and No Stripping A-9
A-8 Annual Cost Summary for 99% VOC Removal, with Stripping and A-10
Steam Ratio of 0.1
A-9 Annual Cost Summary for 99% VOC Removal, with Stripping and A-ll
Steam Ratio of 0.2
A-10 Cost Effectiveness Summary for 99% VOC Removal for Tray Column, A-12
with Water Discharged without Stripping and No VOC Recovered
A-ll Cost Effectiveness Summary for 99.9% VOC Removal for Tray Column, A-13
with Water Discharged without Stripping and No VOC Recovered
A-12 Cost Effectiveness Sumi!i.~r} for 90% VOC Removal for Absorber, A-14
with Water Discharged without Stripping and No VOC Recovered
A-13 Cost Effectiveness Summary for 99% VOC Removal and Steam Ratio A-15
of 0.1
B-l Flooding Constants, C^ B-7
B-2 Constants for Use in Determining Gas Film's Height of B-13
Transfer Units
B-3 Diffusion Coefficients of Gases and Vapors in Air at 25°C and B-15
1 atm
B-4 Constants for Use in Determining Liquid Film's Height of B-17
Transfer Units
B-5 Diffusion Coefficients in Liquids at 20°C B-18
B-6 Pressure-Drop Constants for Tower Packing B-21
-------
3-vii
FIGURES OF REPORT 3
Number
II-l Schematic Diagram of a Packed Tower II-2
II-2 Common Tower Packing Materials II-4
II-3 Schematic Diagram of a Bubble-Cap Tray Tower II-5
II-4 Simple Absorption System II-9
II-5 Absorption System with Stripping Tower (Once-Through Solvent 11-10
Usage)
II-6 Absorption System with Stripping Tower (Solvent Recycled to 11-12
Absorber)
III-l
III-2
III-3
V-l
V-2
V-3
V-4
Typical Vapor-Liquid Equilibrium Curve for an Absorption System
Number of Transfer Units in an Absorption Column for Constant
mVLM
Number of Theoretical Plates in an Absorption Column for
Constant mG__/L,,
M M
Installed Capital Cost vs Flow Rate for Complete Absorption
System (No Stripper) with a VOC Removal Efficiency of 90.0%
Installed Capital Cost vs Flow Rate for Complete Adsorption
System (No Stripper) with a VOC Removal Efficiency of 99.0%
Installed Capital Cost vs Flow Rate for Complete Absorption
System (No Stripper) with a VOC Removal Efficiency of 99.9%
Installed Capital Cost vs Flow Rate for Complete Absorption
III-2
III-3
III-4
V-3
V-4
V-5
V-6
System (No Stripper) with a Solute-Solvent System Having an
Equilibrium Curve Slope of 2.0
V-5 Installed Capital Cost vs Flow Rate for Complete Absorption and V-7
Stripping System with a VOC Removal Efficiency of 99.0%
V-6 Annual Cost vs Flow Rate for Absorber Only (No Stripper) with V-8
5.0 wt % VOC in Waste Gas and 99% VOC Removal Efficiency
V-7 Annual Cost vs Flow Rate for Absorber Only (No Stripper) with V-9
0.5 wt % VOC in the Waste Gas and 99% VOC Removal Efficiency
V-8 Annual Cost vs Flow Rate for Absorber Only (No Stripper) with V-10
0.05 wt % VOC in the Waste Gas and a VOC Removal Efficiency of
99.0%
V-9 Annual Cost vs Flow Rate for Absorber Only (No Stripper) with a V-ll
Solute-Solvent System Having an Equilibrium Curve Slope of 2.0
and 99% VOC Removal Efficiency
V-10 Annual Cost (Excluding BOD Surcharge) vs Flow Rate for Absorber V-12
Only (No Stripper) with a Solute-Solvent System Having an
Equilibrium Curve Slope of 2.0
-------
3-ix
V-ll Annual Cost (Excluding BOD Surcharge) vs Flow Rate for Absorber V-13
Only (No Stripper) with 99.9% VOC Removal Efficiency
V-12 Annual Cost (Excluding BOD Surcharge) vs Flow Rate for Absorber V-14
Only (No Stripper) with 99% VOC Removal Efficiency
V-13 Annual Cost (Excluding BOD Surcharge) vs Flow Rate for V-15
Absorber Only (No Stripper) with 90% VOC Removal Efficiency
V-14 Annual Cost (Excluding BOD Charge and VOC Recovery Credit) vs V-16
Flow Rate for Absorber and Stripper with 99.0% VOC Removal
Efficiency.
V-15 Annual Cost vs Flow Rate for Absorber and Stripper with 99% VOC V-17
Removal and $0.10/lb Credit for Recovered VOC.
V-16 Annual Cost vs Flow Rate for Absorber and Stripper with 99% V-18
VOC Removal and Zero Credit for Recovered VOC
V-17 Cost Effectiveness vs Flow Rate for Absorber and Stripper with V-19
99% VOC Removal and Zero Credit for Recovered VOC
V-18 Cost Effectiveness vs Flow Rate for Absorber and Stripper with V-20
99% VOC Removal Efficiency and $0.10/lb Credit for Recovered VOC
V-19 Cost Effectiveness vs Flow Rate for Absorber and Stripper with V-21
99% VOC Removal Efficiency and $0.20/lb Credit for Recovered VOC
V-20 Cost Effectiveness vs Flow Rate for Absorber Only (No Stripper) V-22
with 99.9% VOC Removal Efficiency
V-21 Cost Effectiveness vs Flow Rate for Absorber Only (No Stripper) V-23
with 99% VOC Removal Efficiency
V-22 Cost Effectiveness vs Flow Rate for Absorber Only (No Stripper) V-24
with a Solute-Solvent System Having an Equilibrium Curve
Slope of 2.0
V-23 Cost Effectiveness vs Flow Rate for Absorber Only (No Striper) V-25
with 90% VOC Removal Efficiency
B-l Number of Theoretical Plates in an Absorption Column for B-5
Constant mG /L
B-2 Correlation for Flooding Rate in Randomly Packed Towers (from B-9
ref 4)
B-3 Packing Factors for Raschig Rings and Saddles B-10
B-4 Number of Transfer Units in an Absorption Column for Constant B-12
B-5 Tray-Spacing Constants to Estimate Bubble-Cap Tray Tower's B-26
Superficial Vapor Velocity
B-6 Sample Flowsheet, Material Balance, and Energy Balance B-31
-------
1-1
I. INTRODUCTION
Gas absorption is an operation in which one or more soluble components of a gas
mixture are separated from the mixture by selective dissolution in a liquid,
termed the solvent. The reverse operation, termed stripping or desorption, is
frequently used for recovery of the absorbed components from the solvent. Gas
absorption is widely used within the chemical industry for the separation and
purification of gaseous process streams and is treated extensively in basic
chemical engineering textbooks.1—4
Gas absorption as an emission control method is currently most widely used for
the removal of water-soluble inorganic contaminants (e.g., sulfur dioxide,
hydrogen sulfide, hydrogen chloride, and ammonia) from air streams, with water
being the most common solvent or scrubbing fluid used. Water may also be used
for the absorption of organic compounds that have relatively high water solu-
bilities (e.g., most alcohols, organic acids, aldehydes, ketones, amines, and
glycols). For organic compounds that have low water solubilities, other solvents
(usually organic liquids with low vapor pressures) are used. The suitability
of gas absorption as a VOC emission control method is generally dependent on
the following factors: (1) availability of a suitable solvent (solvent properties
are discussed in Sect. II-C), (2) VOC removal efficiency required, (3) recovery
value or terminal disposal cost of the contained VOC, (4) capacity required for
handling vapors, and (5) VOC concentration in the inlet vapor (absorption is
usually considered when the VOC concentration is above 200—300 ppmv). Once it
is determined that absorption is technically feasible, it can be compared (for
efficiency and cost effectiveness) with other VOC controls (primarily carbon
adsorption and thermal oxidation).
1T. K. Sherwood and R. L. Pigford, Absorption and Extraction, McGraw-Hill, New
York, 1952.
2R. E. Treybal, Mass Transfer Operations, 2d ed., McGraw-Hill, New York, 1968.
3R. H. Perry and C. H. Chilton, Chemical Engineers Handbook, 5th ed., McGraw-Hill,
New York, 1973.
4W. L. McCabe and J. C. Smith, Unit Operations of Chemical Engineering, 2nd ed.,
McGraw-Hill, New York, 1967.
-------
II-l
II. SYSTEM DESCRIPTION
A. ABSORPTION EQUIPMENT
1. General
Gas absorption equipment is designed to provide thorough contact between the
gas and the liquid solvent in order to permit interphase diffusion of the
material. The rate of mass transfer between the two phases is largely dependent
on the surface area exposed. Other factors governing the absorption rate, such
as the solubility of the gas in the particular solvent and the degree of chemical
reaction, are characteristic of the constituents involved and are more or less
independent of the equipment used. The types of equipment that are commonly
used for gas-liquid contact operations include packed towers, plate or tray
towers, spray chambers, venturi absorbers, and vessels with sparging equipment.
The use of venturi absorbers, spray chambers, and sparging is generally limited
to the control of particulate matter and highly soluble gases requiring very
few transfer units. They are infrequently used for the control of VOC emissions
in dilute concentration. The following discussion is therefore limited to
packed and tray towers.
2. Packed Towers
A schematic diagram of a typical packed tower is shown in Fig. II-l.1 The
packing is designed to expose a large surface area. When the packing surface
is wetted by the solvent, it presents a large area of liquid film for contact
by the solute gas.
Usually the flow through a packed column is countercurrent, with the liquid
introduced at the top to trickle down through the packing while gas is intro-
duced at the bottom to pass upward through the packing. This results in the
highest possible efficiency, since, as the solute concentration in the gas
stream decreases as it rises through the tower, fresher solvent is constantly
available for contact. Consequently maximum average driving force is obtained
for the diffusion process throughout the entire column.
1J. A. Danielson, Air Pollution Engineering Manual, 2d ed., Air Pollution
Control District, County of Los Angeles.
-------
II-2
, GAS OUT
LIQUID-
IN
LIQUID DISTRIBUTOR
LIQUID
RE-DISTRIBUTOR
PACKING SUPPORT
GAS IN
LIQUID OUT
Fig. II-l. Schematic Diagran of a Packed Tower (from ref 1).
-------
II-3
The packing used should be able to provide a large surface area, should be
shaped to give a large void space when packed, should be strong enough to be
handled and installed without excessive breakage, and should be chemically
inert and inexpensive. Although materials such as rock, gravel, and coke are
occasionally used, most packing consists of various manufactured shapes. The
most common type is Raschig rings, which consist of hollow cylinders having an
external diameter equal to their length. Other shapes include Berl saddles,
® ® ®
Intalox saddles, Pall rings, Hypak, and spiral-type rings. Although slotted
rings such as Pall rings or Hypak are generally higher in unit cost than
Rashchig rings, their superior performance may permit the use of smaller columns
with correspondingly lower capital costs. Figure II-21 shows several of these
common shapes.
3. Plate or Tray Tower
In contrast to packed towers, where gas and solvent are in continuous contact
throughout the packed bed, plate towers employ stepwise contact by means of a
number of trays or plates that are arranged so that the gas is dispersed through
a layer of liquid on each plate. Each plate is more or less a separate stage,
and the number of plates required is dependent on the difficulty of the mass-
transfer operation and the degree of separation required.
The bubble-cap plate or tray has been the most common type used in the past, and
most general references deal primarily with it in discussions of plate towers.
Other types of plates, including perforated trays and valve trays, are currently
being widely used in new installations because they are less expensive and
their performance is about equal to bubble-cap tray performance.
A schematic section of a bubble-cap tray tower is shown in Fig. II-3.1 Each
plate is equipped with openings (vapor risers) surmounted by bubble caps. The
gas rises through the tower and passes through the openings in the plate and
through slots in the periphery of the bubble caps which are submerged in liquid.
The liquid enters at the top of the tower and then flows across each plate and
downward from plate to plate through down spouts. The depth of liquid on the
plate and the liquid flow patterns across the plate are controlled by various
weir arrangements.
-------
II-4
BERL SADDLE
RASCHIG RING
PALL RING
INTALOX SADDLE
TELLERETU
Fig. II-2. Common Tower Packing Materials (from ref 1),
-------
II-5
SHELL —
TRAY
DOWNSPOUT
TRAY
SUPPORT RING
TRAY
STIFFENER-
~-LI QUID IN
BUBBLE CAP
INTERMEDIATE
FEED
,- LIQUID OUT
Fig. II-3. Schematic Diagram of a Bubble-Cap Tray Tower (from ref 1).
-------
II-6
4. Comparision of Packed and Plate Tower
While devices such as sparged vessels, spray chambers, and venturi absorbers
have limited application for gas absorption, the choice of equipment is usually
between a packed tower and a plate tower. Both devices have advantages and
disadvantages for a given operation, depending on many factors, such as gas and
liquid flow rates and degree of corrosiveness of the streams. Final selection
will usually be based on the following comparative information:
1. Packed towers are generally less expensive than plate towers when the
materials of construction must be corrosion resistant.
2. Packed towers have a smaller pressure drop than plate towers designed for
the same throughput and thus are more suitable for vacuum operation.
3. Packed towers are preferred for foamy liquids.
4. The liquid holdup is usually less in a packed tower.
5. Plate towers are preferable when the liquid contains suspended solids
since they can be more easily cleaned. Packed towers tend to plug more
readily.
6. Plate towers are preferable for large diameters, to minimize channeling
and reduce weight. Channeling may be corrected in tall, large-diameter
packed towers by the installation of redistribution trays at given in-
tervals .
7. Plate towers are more suitable when the operation involves appreciable
temperature variation since expansion and contraction due to temperature
change may crush the packing.
8. Plate towers are superior when the heat of solution must be removed at an
intermediate location in the tower. The liquid downflow can be collected,
cooled externally, and returned more simply in a plate column.
9. Mass-transfer capabilities of packed towers can be predicted with less
accuracy than plate towers, often requiring larger safety factors with
correspondingly higher capital costs.
10. With other conditions being equal, economic considerations generally favor
packed towers of diameters of up to 2 ft and plate towers with diameters
of greater than 4 ft.
-------
II-7
B. SOLVENT REQUIREMENTS
1. Treybal2 lists some important aspects that should be considered in selecting
absorption solvents:
1. The gas solubility should be relatively high so as to enhance the rate of
absorption and decrease the quantity of solvent required. Solvents chemi-
cally similar to the solute generally provide good solubility.
2. The solvent should have relativly low volatility so as to reduce solvent
loss. (This is particularly important in emission control applications as
solvent losses may result in additional VOC emissions.)
3. If possible, the solvents should be noncorrosive so as to reduce con-
struction costs of the equipment.
4. The solvents should be inexpensive and readily available.
5. The solvent should have relatively low viscosity for suitable
mass-transfer rates and flooding characteristics.
6. Ideally, the solvent should be nontoxic, nonflammable, and chemically
stable and have a low freezing point.
When applicable, water offers certain distinct advantages over other solvents.
Because the actual cost of the solvent is very low, water can frequently be
used on a once-through basis, with the effluent water being discharged to
wastewater treatment either directly from the absorber or after a subsequent
stripping operation. The discharge of absorber effluent water without stripping
is usually practiced only when the absorbed VOC components are present in very
low concentrations and/or have little or no recovery value. It is not considered
to be an acceptable practice if significant secondary emissions or degradation
in the quality of discharged water results.
When water is stripped before being discharged to wastewater treatment, once-
through use may result in less stringent stripping requirements than those
involved with solvent recycle. (When the solvent is recycled, incomplete
stripping reduces subsequent absorption efficiency.) Once-through use of water
also usually reduces cooling requirements and the corresponding heat-exchanger
capital costs.
2R. E. Treybal, Mass Transfer Operations, McGraw-Hill, New York, 1955.
-------
II-8
An additional advantage in using water as a solvent compared to the use of
organic solvents is that solvent losses do not result in additional VOC
emissions or organic concentration in wastewater. Although organic solvents
are selected to minimize these losses (i.e., low vapor pressure), some losses
will result.
C. SYSTEM FLOWSHEETS
Absorption system requirements for VOC control applications and the corresponding
equipment configurations may vary significantly, depending on specific applica-
tions and control requirements. The flow sheets discussed below illustrate
several examples.
Figure II-4 illustrates the simplest configuration, in which the solvent
(usually water) is used on a once-through basis and is then either discharged
to a waste-water treatment system or introduced as a process water stream. The
possibility of using organic solvents on a single-pass basis may exist in those;
few situations where fresh solvent is available in large quantity as a process
raw material or fuel. For instance, a small vent stream might be scrubbed with
oil on a single-pass basis before being burned as fuel. With this system the
only major equipment items required in addition to the absorption tower are,
possibly, a blower to provide for tower pressure drop and a pump to discharge
the effluent solvent.
In the system shown in Fig. II-5 the solvent (usually water) is used on a
single-pass basis but is stripped before being discharged. Additional major
equipment items, compared to those shown in Fig. II-4, include a stripping
tower, an additional pump, and a number of heat exchangers. Heat exchangers
may include a feed-effluent exchanger, a steam-heated feed preheater, and a
water-cooled reflux condenser. The effluent liquid from the absorber is usually
preheated to near its boiling point before it is introduced into the stripping
tower. The feed-effluent heat exchanger reduces steam requirements in the
steam preheater and cools the stripped solvent to well below its boiling point
before it is discharged. As is shown, the heat required for vaporization in
the stripper may be introduced by steam being directly sparged into the base
and the condensed steam being discharged with the stripped solvent.
-------
.AlP.
iULET"
II-9
CR
SCUVE.KJT
"E.FFLUEU"
PUMF
Fig. II-4. Simple Absorption System.
-------
Alp
AB<60i=eEH
( PACKED OR
TPA^ COLUMKI)
AIR
GOLVEkit
6TEAVA
PUMP
FEED' EFFIVJEKTT
HEAT
SOLVE SAT
STEAM
6T«PP£D
C PA.CKE-P OK
CDLUMKJ")
H
H
I
M
O
Fig. II-5. Absorption System with Stripping Tower (Once-Through Solvent Usage).
-------
11-11
The last flow sheet (Fig. II-6) depicts a typical absorption-stripping system
that uses an organic-liquid solvent and recycles the stripped solvent to the
absorber. Additional equipment items required (compared to those in Fig. II-5)
include a steam-heated reboiler and a water-cooled solvent cooler. Because
solvent usage and losses must be minimized, both absorber and stripper operating
requirements are generally more stringent than when water is used, with correspond-
ingly higher capital and operating costs. For example, in order to attain very
low VOC concentration in the air discharged from the absorber, the equilibrium
concentration of residual VOC in the recycled solvent must be reduced to a very
low level. With once-through usage of water as the solvent the initial equilibrium
VOC concentration of the solvent is nil, and the stripping efficiency has no
effect on absorber performance.
Other absorption-stripping system variations (not shown) that may significantly
affect capital and operating costs include requirements for low-temperature
conditions (requiring refrigeration equipment and additional heat exchangers),
vacuum stripping, and operation at elevated pressures. Corrosive conditions,
if present, will result in more stringent construction material requirements
and in correspondingly higher capital costs.
-------
PL'Mf
HEAT S/.CHAV^S~
COklCEN^ATC.
6TR'.?PED
CCLUhAKi)
PUMP
H
H
Fig. II-6. Absorption System with Stripping Tower (Solvent Recycled to Absorber)
-------
III-l
III. SYSTEM EFFICIENCIES
A. GENERAL
The VOC removal efficiencies of absorption systems are limited by the driving
force available to transfer the VOC from the gas stream to the liquid solvent.
The available driving force at each point within a countercurrent absorption
tower is determined by the difference between the actual VOC concentrations in
the gas stream and solvent at that point and the corresponding equilibrium
concentrations. The equilibrium relationships are unique for each VOC-solvent
system, and the equilibrium values at various concentrations are generally
determined experimentally and displayed as an equilibrium curve. Figure III-l
shows a typical equilibrium curve, in which x, the concentration of VOC in the
solvent, expressed as the mole fraction, is plotted versus the corresponding
equilibrium concentration (mole fraction) in the gas. As is illustrated by
Fig. III-l, the equilibrium curve typically approximates a straight line
(constant slope, m) near the origin, where VOC concentrations in the solvent
and the gas are low, and increasingly diverges from a straight line at increas-
ing concentrations.
The relationships between attainable VOC removal efficiency, the equilibrium
curve slope, and the required liquid-gas mole ratio and/or the corresponding
absorption tower height (number of transfer units in a packed column or
theoretical trays in a tray column) are shown by Figs. III-2 and III-3 respec-
tively.
Figure III-2, which applies to packed columns, is based on the following
equation:x
In
NOG
1 -
(III-l)
XA. P. Colburn, Trans. Am. Inst. Chem. Engrs. 3§, 211 (1939) (cited in:
"Absorption and Extraction," T. K. Sherwood and R. L. Pigford, p 133, Chemical
Engineering Series, McGraw-Hill, New York, 1952).
-------
III-2
M
•rH
0.10
0.9 _
0.08 _
0.07 _
•H % 0.06 _
r-
o ft
Tj o
" i
(TJ ">
.M M-l
fa o
3 w
^ 0)
O i
S o
0.05 —
Equilibrium Curve
0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09
x (Mole Fraction VOC in Solvent)
Fig. III-l. Typical Vapor-Liquid Equilibrium
Curve for an Absorption System .
-------
Number of Transfer Units, N
OG
tr
w
0
hi
I—
O
O
0
tr
CD
o
Hi Hi
0
M i-3
H
O fa
0 3
3 tn
01 Hi
rt CD
pJ h{
rio
^ 3
H-
rt
O
in
H
H
Ul
-------
H
H
H
OJ
Number of Theoretical Plates, N
H
H
-------
III-5
The terms used in Eq. (III-l) and Fig. III-2 are defined below:
N-_ = number of overall gas-phase transfer units,
OG
m = slope of equilibrium curve,
G = superficial molar mass velocity of gas, lb-moles/(hr)(ft2),
M
L = superficial molar mass velocity of liquid, lb-moles/(hr)(ft2),
yt = mole fraction of VOC in inlet gas,
y2 = mole fraction of VOC in outlet gas,
xx = mole fraction of VOC in effluent liquid,
x2 = mole fraction of VOC in inlet liquid.
The analagous equation for tray columns,1 which is the basis for Fig. III-3, is
as follows:
In
(III-2)
"P ~ In (LM/mGM)
in which N is the number of theoretical trays. All other terms in Eq. (III-2)
and Fig. III-3 are the same as those used in Eq. (III-l) and Fig. III-2.
The relationships shown in Figs. III-2 and III-3 apply to the condition of
constant mG /L (the equilibrium curve is a straight line). This condition is
n M
usually approached closely only with dilute solutions, and more complex and
accurate calculations are usually necessary for actual design requirements.
However, the relationships shown are useful for order-of-magnitude estimates
and for illustrating the relationships between variables.
Equation (III-l) or Fig. III-2 may be used to estimate the number of transfer
units required in a packed tower. In order to estimate the total packed height
required, the equivalent height of a transfer unit must also be determined.
Similarly, in order to estimate the actual number of trays required in a tray
tower from the number of theoretical trays predicted by Eq. (III-2) or Fig. III-3,
the tray efficiency must be estimated. Sample calculations that illustrate the
estimation of transfer-unit height and tray efficiency are given in Appendix B.
Examples that illustrate the use of Fig. III-3 to estimate VOC removal efficiency
are given in Sects. III-B and III-C.
-------
III-6
B. SYSTEM WITH ONCE-THROUGH SOLVENT USAGE
As is discussed in Sect. II, for systems in which the solvent is used on a
once-through basis (Figs. II-4 and II-5), which is frequently the case when the
solvent is water, the initial VOC concentration of the solvent is usually nil
and VOC stripping efficiency has no effect on the VOC removal efficiency of the
absorber. Referring to Figs. III-2 and III-3, with once-through solvent usage
x2 becomes 0 and the ordinate (yx - mx2)/(y2 - mx2) becomes simply yj7y2. The
VOC removal efficiency in percent is then expressed as (1 - y2/yi) X 100. As
an example, if a plate absorption column containing 16 theoretical plates is
operated with a gas/liquid mole ratio (GM/L ) of 0.35 and if the equilibrium
curve slope, m, for the VOC solvent system is approximately 2.0 over the operat-
ing range, the value of ">GM/LM becomes 0.7 (i.e., 2.0 X 0.35). Then, referring
to Fig. III-2, the corresponding value of (yx - mx2)/(y2 - mx2) is read as
approximately 1000 and the corresponding VOC removal efficiency is estimated as
(1 - 1/1000) X 100, or 99.9%.
C. SYSTEMS WITH SOLVENT RECYCLE
Systems that utilize organic liquids as solvents usually include the stripping
and recycle of the solvent to the absorber (Fig. II-6). In this case the VOC
removal efficiency of the absorber is dependent on the solvent stripping effi-
ciency.
Based on the same criteria used in the example in Sect. III-B (i.e., m = 2.0,
GM/LM = 0.35, and 16 theoretical plates), on a concentration of 1.0 mole % VOC
in the inlet gas, and on a solvent stripping efficiency of 98.0%, the value of
(Y! - mx2)/(y2 - mx2) is again determined as 1000 from Fig. III-2; however, in
this case the VOC removal efficiency is less because the mole fraction of VOC
in the inlet solvent, x2, is greater than 0. The value of x2 must be determined
to solve for y2 in the expression
Yi - m*2
= 1000. (HI-3)
y2 - mx2 '
The value of x2 may be determined from a VOC material balance across the absorber
expressed as
-------
III-7
-------
III-?
then Xj = 0.00352, and x2 = 0.0000703.
This example illustrates the effect of the stripping efficiency on the VOC
removal efficiency.
-------
IV-1
IV. DESIGN CONSIDERATIONS
A. GENERAL
The actual design of an optimum absorption or absorption-stripping system for a
given emission control application is relatively complex. An optimum design
requires the selection of a combination of equipment and operating conditions
that will satisfy emission control requirements at minimum overall cost. Often
a change that reduces the cost of one element must be balanced against the
effect it has on other costs. Although detailed design procedures are beyond
the scope of this report, some of the most significant design considerations
and the relationships between them are discussed briefly in this section.1 For
simplicity, these factors are discussed specifically as they apply to absorp-
tion-stripping systems using plate or tray towers and designed to control VOC
emissions at relatively low concentrations in air, with water used as the
solvent on a once-through basis (flowsheet, Fig. II-5).
B. CAPITAL COSTS PARAMETERS
1. Absorber
The diameter of the absorber is primarily a function of the total gas flow
rate, and the height is determined primarily by the number of trays required.
The number of trays is, in turn, determined by the solvent/gas mole ratio used,
the slope of the equilibrium curve for each specific VOC-solvent system, and
the VOC removal efficiency required. Thus the combination of the tower height
and the solvent rate selected must be balanced for optimum operation. The
relationships between the number of trays, the solvent-gas ratio, the operating
curve slope, and the VOC removal efficiency are shown by Fig. III-2.
2. Stripping Tower
As with the absorber, the height of the stripper is determined primarily by the
number of trays required. The number of trays is, in turn, determined by the
relative volatilities of the solvent and the contained VOC (equilibrium curve
slope), the reflux ratio used, and the degree of separation (or stripping
efficiency) required. A relationship of variables for the stripper similar to
iFor a detailed study of wet scrubber systems see: S. Calvert et al., Wet
Scrubber System Study. Vol.1. Scrubber Handbook, PB—213 016, NTIS (July 1972)
-------
IV-2
that described for the absorber exists (see Fig. III-2); however, because more con-
centrated gas mixtures occur, the deviation of the actual equilibrium curve from
a straight line generally becomes much greater and the assumption of constant
mG /L introduces greater error. As with the absorber, the combination of
stripping tower height and reflux ratio must be balanced for optimum cost.
The required tower diameter is primarily a function of the vapor flow rate.
The vapor flow rate is, in turn, determined by the reflux ratio used and by the
solvent flow rate from the absorber. Therefore the required diameter becomes
dependent on the height selected, and, as the liquid rate is dependent on the
absorber design parameters, the absorber and stripper parameters become inter-
dependent and must be balanced for optimum cost.
3. Blower
Blower capital costs are primarily dependent on horsepower requirements. The
required horsepower is determined by the air flow rate and by the pressure
increase (AP) that must be developed to overcome the pressure drop through the
absorber and inlet duct. The absorber pressure drop is roughly proportional to
the number of trays in the absorber tower, and therefore the effect of changes
on blower capital costs and energy requirements must be considered in selecting
the optimum number of trays in the absorber. (The pressure drop is usually
significantly less in packed towers than in tray towers and may be a significant
factor in the type of tower selected).
4. Heat Exchangers
a. General The capital cost of heat exchangers is primarily a function of the
heat-transfer surface area required. For a specific application in which the
heat-transfer coefficients and the required temperatures remain relatively
constant, the required areas will be approximately proportional to the required
heat-transfer rates and to the corresponding flow rates of fluids that are
heated, cooled, vaporized, or condensed.
b. Feed-Effluent Heat Exchanger The required areas and the corresponding capital
costs are primarily dependent on the solvent flow rates.
c.
Steam Preheater The capital cost primarily depends on the solvent flow rate.
-------
IV-3
d. Stripper Condenser The capital cost primarily depends on the vapor rate in
the stripper, which in turn is determined by the solvent flow rate and the
reflux ratio selected.
5. Other Capital Requirements
Most of the other capital items to be considered, including piping and instrumen-
tation, are either relatively minor, remain relatively constant, or are indepen-
dent of other design considerations.
C. OPERATING COST (CREDIT) PARAMETERS
1. General
Certain operating cost components are interdependent with the equipment design
parameters and must be considered in arriving at an optimum design for an
absorption-stripping system. Following is a brief discussion of primary operat-
ing cost components.
2. Solvent Cost
For the flow sheet shown in Fig. II-5 in which the solvent (water) is used on a
once-through basis, the cost of using process water must be considered in the
design of the absorber tower. The combination of the number of trays, or the
height of the absorber tower, and the corresponding liquid rate required must
be balanced for optimum cost.
3. Electrical Power
Electrical power is used primarily for operation of blowers and pumps. Blower
power requirements are primarily determined by the quantity of gas passing
through the absorber and by the absorber-tower pressure drop. Since pressure
drop is primarily dependent on the type of tower selected (plate or packed) and
on the number of plates or height of packing required, electrical power usage
must be considered in arriving at the optimum absorber tower design.
Power requirements for pump operation are generally relatively small compared
to requirements for blower operation. The power required for pump operation
will be roughly proportional to the liquid rate through the system and will
therefore vary with the liquid/gas ratio selected.
-------
IV-4
4. Process Steam
Steam is used for heating the stripper feed (feed preheater) and for vapori-
zation in the stripper tower, by direct injection or by means of a reboiler.
Preheater steam requirements are determined primarily by the liquid flow rate
to the stripper.
The quantity of steam for vaporization is determined primarily by the liquid
flow rate and by the reflux ratio selected in the design of the stripping
tower, and thus vaporization steam usage is influenced by both absorber and
stripper design.
5. Cooling Water
The primary use of cooling water is in the stripper condenser. The quantity
used will depend on the liquid flow rate and on the stripping-tower reflux
ratio.
6. Wastewater Treatment
Wastewater treatment costs are usually dependent on both the quantity of waste-
water discharged and the VOC concentration (usually measured as BOD or COD). For
a once-through absorber-stripper system in which the solvent (water) is dis-
charged to wastewater treatment, treatment costs will be dependent on the
liquid flow rate to the absorber and on the VOC removal efficiency obtained by
the stripper. Treatment costs will therefore be influenced by the design of
both the absorber and the stripper.
7. Product Recovery Credits
Product recovery credits will be determined by the volume of gas treated and
the corresponding VOC concentration, by the unit value of the specific organic
compounds (either as process materials or as fuel), and by the removal effi-
ciencies of the absorber and stripping towers. As removal efficiencies are
influenced by specific design parameters (e.g., tower height, reflux ratio)
they must be considered in the design of an optimum system.
-------
V-l
V. COST AND ENERGY IMPACTS OF GAS ABSORPTION SYSTEMS
A. CAPITAL COST ESTIMATES
1. General
Estimated capital costs for total system combinations are presented here (Table
V-I) and in Appendix A. The estimated costs represent the total investment,
including all indirect costs such as engineering and contractors' fees and
overheads, required for the purchase and installation of all equipment and
material to provide a facility as described. These are battery-limit costs and
do not include provisions for bringing utilities, services, or roads to the
site; backup facilities; land; required research and development; or process
piping interconnections that may be required within the process(es) that generate
the waste gas fed to the absorber systems.
The estimated costs are based on a new-plant installation; no retrofit cost
considerations are included. Such costs are usually higher than those for a
new-site installation for a similar system and include, for example, demoli-
tion, crowded construction working conditions, scheduling construction activi-
ties with production activities, and longer interconnecting piping. These
factors are so site-specific that no attempt has been made to provide costs.
For specific cases, rough costs can be obtained by using the new-site data and
adding as required for a specific retrofit situation.
Capital cost estimates were developed by the summation of installed capital
costs for the major individual components of each system. These installed
capital costs are based on IT Enviroscience experience adjusted to a December
1979 basis. In addition to the sum of the itemized capital costs an allowance
of 30% is included in overall capital cost estimates to cover the cost of
miscellaneous items that were not included in the simplified flowsheets used.
2. Model Systems
The capital cost, annualized cost, and cost-effectiveness curves given in
Figs. V-l through V-23 were developed for two model systems illustrated by the
process flow sheets of Figs. II-4 and II-5, in which the solvent is used on a
once-through basis, either without (Fig. II-4) or with (Fig. II-5) a stripping
step included.
-------
\bsorber Conditions:
Stripper Conditions:
Table V-l. Capital Cost Summary for Absorber and Stripper Systems
VOC removal, 99%; L_M/mGM = 1.4; VOC in air = 0.05, 0.5, and 5.0 wt %.
Organic removal, 99%; steam ratio * 0.2 mole of steam/mole of air in.
Capital Cost
0.28
(10 $) at Equilibrium Curve
2.02
At Air Flow Rates (cfm X 10 )
Equipment
Absorber System
Tower and trays (packing)
Blower
Duct
Pump
Piping
Instrumentation
Stripper system
Tower and trays (packing)
Pump
Piping
Instruments
Heat exchangers
Feed-effluent
Steam preheater
Stripper condenser
Subtotal capital cost
Total capital cost (+30%)
1.0
33.6
29.7
8.0
5.7
1.0
14.8
9.1
5.7
3.0
14.8
11.5
1.5
13.7
152.1
197.7
10
133.8
100.2
16.0
5.7
1.0
14.8
28.8
5.7
3.0
14.8
55.1
5.7
65.8
450.4
585.5
100
741.1
293.5
27.5
9.7
3.4
14.8
151.7
9.7
10.2
14.8
308.1
25.0
315.5
1925
2502.5
1.0
42.2
34.5
8.0
5.7
1.0
14.8
11.9
5.7
3.0
14.8
52.3
5.0
17.8
216.7
281.7
10
165.6
117.4
16.0
8.7
3.4
14.8
41.2
8.7
10.2
14.8
290.2
21.3
85.3
197.6
1037
103
870.9
358.0
27.5
25.5
9.7
14.8
266.1
25.5
29.1
14.8
1752.9
103.7
507.8
4006.3
5208
Slopes (m)
of
1.0
48.2
37.8
8.0
6.0
1.6
14.8
20.5
6.0
4.8
14.8
125.0
13.8
37.7
339.0
440.7
of
5.74
10
188.2
129.4
16.0
12.8
4.5
14.8
76.5
12.8
135
14.8
755.0
66.4
199.3
1504
1955
100
965.8
403.5
27.5
45.6 f
KJ
17.4
14.8
452.7
45.6
52.2
14.8
4560
381.1
1204
8185
10640
-------
V-3
1.5
1.0
a
-u
0.5
Slope of equil. curve, 5.74
Slope of equil. curve, 2.02
Slope of equil. curve, 0.28
1000
10,000 100,000
Waste-Gas Flow Rate (scfra)
Fig. V-l. Installed Capital Cost vs Flow Rate for Complete Absorption
System (No Stripper) with a VOC Removal Efficiency of 90.0%.
-------
V-4
2.0
1.5
o
-------
December 1970 Installed Capital ($ Million)
H-
s
O
fD
ft
CD H
ft
fu
» O
(D M H1
3 *rJ (D
o fl" &
fu O O
Hi *< ft
Hi l/l p)
H- rt H
O (D
p- 3 O
fD ' O
^S^
y- O
O cn w
H- H
s i
(D
H »
-p,
« (D
H-
ft Hi
3- O
H
fu
f
Ul
-------
V-6
2.0
99.9% VOC Removal Efficiency
99.0% VOC Removal Efficiency
90.0% VOC Removal Efficiency
1000
10,000 100,000
Waste-Gas Flow Rate (sct'm)
1,000,000
Fig. V-4. Installed Capital Cost vs Flow Rate for Complete
Absorption System (No Stripper) with a Solute-SoIvent
System Having an Equilibrium Curve Slope of 2.0.
-------
V-7
10.0
8.0
6.0
Slope of equil. curve, 5.7-3
Slope of equil. curve, 2.02
Slope of equil. curve, 0.28
loou
10,000
Waste-Gas Flow Rate (scfm)
100,000
1,000,000
Fig. V-5. Installed Capital Cost vs Flow Rate for Complete Absorption and
Stripping System with a VOC Removal Efficiency of 99.0%.
-------
V-8
JJ
0)
0
u
20.0
16.0
12.0
3.0
4.f
0
Slope of equil. curve, 5.74
I Slope of equil. curve, 0.28
1000
10,000 100,000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-6. Annual Cost vs. Flow Rate for Absorber Only (No Stripper)
with 5.0 wt % VOC in Waste Gas and 99% VOC Removal Efficiency.
-------
V-9
5.0
lope of equil. curve, 5.74
Slope of equal, curve, 2.02
Slope of equil. curve, 0.28
1000
10,000 - " 100<000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-7. Annual Cost vs Flow Rate for Absorber Only
(No Stripper) with 0.5 wt % VOC in the Waste Gas and
99% VOC Removal Efficiency.
-------
V-10
slope of eauxl. curve. 2.02
Slope of equil. curve, 0.28
10,000 100,000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-8. Annual Cost vs Flow Rate for Absorber Only
(No Stripper) with 0.05 wt % VOC in the Waste Gas and a
VOC Removal Efficiency of 99.0%
-------
Annual Cost ($ Million/Year)
ON
o
ft)
3
W
hQ
H-
^
H- <
c; en i
§ rt
< 0) 3
CD H 3
O H-
W rt n
CD 3- O
M
O ft) Ct
Hi
en <
w O en
rt H
CD O
I £
vD H ft>
O < rt
tfP CD CD
o o
o en n
K
V M >
CD ft cr
g CD en
030
M H-
H, 3 O
Hi LQ 3
H- M
O <<
H-
CD
3
O
s -
m c
01 o
If O
c
i
o
o
- 8
g
n
-------
V-12
2.0
o
u
1.5
1.0
0.5
1000
99.9% VOC Removal Efficiency
99.0% VOC Removal Efficiency
90.0% VOC Removal Efficiency
10,000
Waste-Gas Flow Rate (scfm)
Fig V-10. Annual Cost (Excluding BOD Surcharge) vs Flow Rate for
Absorber Only (No Stripper) with a Solute-Solvent System Having an
Equilibrium Curve Slope of 2.0.
-------
Slope of equil. curve, 2.02
Slope of equili. curve, 0.2
10,000 100,000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-ll. Annual Cost (Excluding BOD Surcharge) vs Flow Rate for
Absorber Only (No Stripper) with 99.9% VOC Removal Efficiency.
-------
V-14
2.5
Slope of equil. curve, 5.74
Slope of equil. curve, 2.02
Slope of equil. curve, 0.28
1000
10,000
Waste-Gas Flow Rate (scfm)
Fig V-12 Annual Cost (Excluding BOD Surcharge) vs Flow Rate for
Absorber Only (No Stripper) with 99% VOC Removal Efficiency.
-------
V-15
2.0
1.5
1.0
Q
O
ca
o
X
a
o
o
0.5
Slope of equil. curve, 5.7
Slope of equil. curve, 2.02
Slope of equil. curve, 0.28
1000
10,000 100,000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-13. Annual Cost (Excluding BOD Surcharge) vs Flow Rate for
Absorber Only (No Stripper) with 90% VOC Removal Efficiency.
-------
V-16
Slope of equil. curve, 5.74
Slope of eouil. curve. 2.0
Slope of equil. curve, 0.28
1000
10,000 100,000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-14. Annual Cost (Excluding BOD Charge and VOC Recovery Credit)
vs Flow Rate for Absorber and Stripper with 99.0% VOC Removal Efficiency.
-------
V-17
5.0 wt % VOC, slope, 5.74
5.0 wt % VOC, slope, 2.02
5.0 wt * VOC, slops, 0.23
Waste-Gas Flow Rate (seta)
Fig V-15. Annual Cost vs Flow Rate for Absorber and Stripper with
99% VOC Removal and $0.10/1* Credit for Recovered VOC.
-------
Annual Cost ($ Million/Year)
f
M
00
-------
V-19
10.0
slope of oquil. cur
slope of equil. cu
slope of equil. cur
u.i
slope of equil. cur1
slope of equil. cur'
slope of equil. cur1
5.0 wt % VOC in was
Slope of equil. cur
Slope of equil. cu
Slope of equil. cur
10,000
Waste-Gas Flow R.itu (scfm)
Fig V-17 Cost Effectiveness vs Flow Rate for Absorber and
Stripper with 99% VOC Removal and Zero Credit for Recovered VOC
-------
V-20
3.0
}. 5 wt * VOC 1 -l w.ib
slope of equ.il. ^ur'
slope of equil. cur^
Slope Of CqUll. C'-LT'
5.0 wt 4 VOC xn was
e gas
Slope of equil. cur-
Slope of equil. cur
•e 5.74
2.08
03 Slope of equll. curve 0.28
6.0
2.0
1000
10,000 100,000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-18. Cost Effectiveness vs Flow Rate for Absorber and
Stripper with 99% VOC Removal Efficiency and
$0.10/lb Credit for Recovered VOC.
-------
V-21
11.0
10. n
As. 0.05 wt * VOC in wa
AI: slope of equll. cur
A..: :;lope OL eqUll.. CU
Aa. slope o( 'jqull. fur
te qas
a, S.74
K, 2.08
0.28
Bi: slope of equll. cur
B^: slope of equil. cur
33: slope of equll. cur1
-C3. 5.0 wt % VOC in was
Cj: slope of equll. cur
C;; slope of equll. cur
C3: slope of equil. cur
e gas
5.74
2.08
0.28
8.0
6.0
. C2lC3
10,000 100,000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-19. Cost Effectiveness vs Flow Rate for Absorber and Stripper with
99% VOC Removal Efficiency and $0.20/lb Credit for Recovered VOC.
-------
V-22
AI —A3 :
Al
A2
Aj
BI S3
%
B2
0.05 wt 1. VOC in WJ|
slope of equil. cur
Slope of equil. cur
Slope or equil. cur:
0.5 wt ^ VOC in was
slope of equil. cur
slope of equil. cur
slope of equxl. cur
5.0 wt % VOC in was;e-gas
slope of equil. cur/e, 5.74
te-gas
ue, 5.74
•e, 2.02
vs, 0.28
:e-gas
/e, 5.74
/e, 2.08
/e, 0.28
4.0
slope or equil. cur
slope of equil. cur
2.08
0.28
3.0
1.0
BI
B2
B3
Cl.C2.C3
10,000 11)0,000
Waste-Gas Flow Rate (^cfm)
Fig. V-20. Cost Effectiveness vs Flow Rate for Absorber Only
(No Stripper) with 99.9% VOC Removal Efficiency.
-------
V-23
0.05 wt % VOC in wa
slope of equil. cur
slope of equil. cur
slope of equil. cur
;te gas
•e, 5.74
•e, 2.02
•e, 0.28
0.5 wt % VOC in waste gas
slope of equil. curve, 5.74
slope of equil. cur
slope of equil. cur
5.0 wt % VOC in was'
slope of equil. cur-
lope 01 equi.
slope of equil. cur-
1.0
1000
10,000 100,000
Waste-Gas Flow Rate (scfm)
Fig. V-21. Cost Effectiveness vs Flow Rate for Absorber Only
(No Stripper) with 99% VOC Removal Efficiency. -
-------
V-24
4.0
3.0
u
§
2.0
1.0
0.05 wt % VOC in wab
99.9% VOC removal ef
99% VOC removal effi
90% VOC removal effi
:e gas
Eiciency
;iency
lency
0.5 wt % VOC in wast
99.9% VOC removal ef
99% VOC removal effi
90% VOC removal effi
^ gas
ficiency
=iency
~iency
5.0 wt % VOC in wast
99.9% VOC removal ef
99% VOC removal effi
-gas
iciency
iency
90% VOC removal effi
100U
10,000
100,000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-22. Cost Effectiveness vs Flow Rate for Absorber Only
(No Stripper) with a Solute-Solvent System Having and Equilibrium
Curve Slope of 2.0.
-------
V-25
4.0
3.0
1—A3:
-B3:
0.05 wt % VOC in wast
AI: slope of equil.
A2: slope of equil.
A3: slope of equil.
0.5 wt % VOC in waste
B-L: slope of equil.
B2: slope of equil.
83: slope of equil.
e gas
curve, 5.74
curve, 2.08
curve, 0.28
gas
curve, 5.74
curve, 2.08
curve, 0.28
wt % VOC in waste
slope of equil
slope of equil.
slope of equil.
gas
:urve_, 5. 74
:urve, 2.02
:urve, 0.28
2.0
w
4J
01 1.0
o
o
A2
Bl
1000
10,000 100,000
Waste-Gas Flow Rate (scfm)
1,000,000
Fig. V-23. Cost Effectiveness vs Flow Rate for Absorber Only
(No Stripper) with 90% VOC Removal Efficiency.
-------
V-26
Costs were developed for both models for gas flow rates of 1,000, 10,000, and
100,000 scfm, for VOC removal efficiencies of 90.0, 99.0, and 99.9%, and for
values of m (equilibrium curve slope) of 0.28, 2.02, and 5.74. These slopes
correspond respectively to those for methanol-water, acetone-water, and acet-
aldehyde-water systems.
3. Criteria and Limitations
The primary absorption and stripping tower parameters (height, diameter, and
liquid/gas ratio) and corresponding capital costs are dependent on the in-
dividual vapor/liquid equilibrium relationships for the specific VOC-solvent
systems and cannot readily be presented in simple generic terms (i.e., expres-
sed in terms of simply defined and measurable physical, chemical, or thermo-
dynamic properties). To illustrate the effect of the variations in the vapor/
liquid equilibrum relationships and to permit the curves to be used for order-
of-magnitude estimates of costs for VOC-solvent systems for which vapor/liquid
data are available, the curves were developed for three specific VOC-solvent
systems that span a comparatively wide range of relative volatilities: metha-
nol-water, acetone-water, and acetaldehyde-water. The effect of the vapor/
liquid equilibrium relationship is presented in simplified terms as the slope
of the equilibrium curve for very dilute solutions, at ambient temperature and
pressure.
The estimated tower parameters (height, diameter, and liquid/gas ratio) were
obtained by use of simplified calculations in which it is assumed that the
value of m is constant within the operating range of the tower (i.e., the
equilibrium curves are straight lines). Although this assumption generally
holds reasonably well for dilute solutions, rigorous calculations requiring
complete vapor-liquid equilibrium data for the specific system are generally
required for actual design calculations; so the cited cost curves should be
used only for order-of-magnitude estimates or comparisons.
The calculated absorber-tower parameters (height, diameter) are based on a
value of 0.7 for mG /L . This value, although commonly assumed in making
M M
first-pass design calculations for economic studies, is not necessarily optimum.
Optimum design requires the balancing of mGM/LM with the corresponding required
tower parameters for minimum overall cost.
-------
V-27
Cost calculations and the corresponding curves were based on the following
criteria for selecting the type of tower to be used (packed or tray): a dia-
meter of less than 2 ft for packed towers and a diameter of greater than 4 ft
for tray towers. When tower diameters between 2 and 4 ft were required, cost
calculations were made for both types of towers and the lower cost alternative
was used.
All equipment cost estimates were based on the use of carbon-steel construction
throughout. For applications in which corrosive conditions are present (vapor
or solvent) corrosion-resistant construction materials may be required, with
correspondingly higher capital costs. Other criteria used in the selection
of equipment parameters and cost estimates are the following:
a. Towers Tray spacing, 18 in.; packing, 1-in. porcelain Raschig rings;
overall height for <2.5-ft-diam towers, add 4X diameter to tray or packed
tower height; for 2.5- to 4-ft-diam towers, add 3X diameter,- for >4-ft-diam
towers, add 2X diameter,- operating pressure, atmospheric (50 psig design pressure)
b. Inlet Duct Carbon steel, 150-ft long, 1/8 in. in wall thickness, flanged,
4 ells, 1 damper or valve and control, 1 expansion joint.
c. Piping Welded carbon-steel pipe with normal number of fittings per 100 ft.
d- Blowers (Compressors) Electric drive,- installation complete, including
inter- and after-coolers if required; includes prorata building if required.
e- Pumps Ductile iron, single-stage centrifugal pumps,- includes 200 ft of
conduit run, standard valving, and 100 ft of steel suction plus discharge
piping.
f- Heat Exchangers Carbon steel, 150-psig, fixed tube sheet; 1-in. tubes 8
ft long; piping, same materials as tubes and shell, includes foundation or
share of structure.
-------
V-28
4. System Variations
a. General The most common variations from the model absorption systems include
the use of organic liquids as solvents, the use of refrigerated coolers or
condensers, the use of vacuum stripping, and requirements for corrosion-resis-
tant materials. These variations and their effects on costs and cost effec-
tiveness are discussed briefly in the following sections.
b. Organic Solvents Absorption systems that are used for the removal of VOC
components having low water solubilities typically require the use of organic
solvents. The contained VOC is generally stripped from the solvent and the
solvent is recycled to the absorber (see Fig. II-6). Capital and operating
costs are generally somewhat higher than for the model systems because of the
following factors:
1. More complete stripping is usually required, resulting in higher stripper
capital costs and/or steam requirements.
2. The solvent usually must be cooled to a lower temperature before recycle,
requiring greater heat exchanger capacity and cooling water usage than
when the solvent is discharged.
3. Solvent losses in the outlet gas must be much lower, which may require
greater absorber capacity and possibly refrigerated cooling of the
solvent.
4. Solvent unit costs are higher.
5. Residual VOC in the solvent recycled to the absorber will require higher
solvent usage and/or higher absorber capacity than with once-through
solvent usage for the same absorber VOC removal efficiency.
c. Refrigerated Coolers and Condensers Mechanical refrigeration equipment may be
required to attain temperatures necessary for adequate solubility of VOC in the
solvent and/or to minimize the loss of organic solvent from the absorber or the
stripper. Cost data on refrigerated systems are presented in a separate report.
Requirements for refrigerated coolers or condensers will usually result in
higher capital and operating costs because of the following factors-.
*D. G. Erikson, Control Device Evaluation. Condensation (July 1980) (EPA/ESED
report, Research Triangle Park, NC).
*- i
-------
V-29
1. The cost of refrigeration compressors and auxiliary equipment (i.e.,
condensers, heat exchangers) will increase capital costs significantly.
2. The power required for compression will increase operating costs.
d- Vacuum Stripping Vacuum stripping is frequently used as an alternative to
steam stripping for reducing VOC concentration in wastewater. The generally
higher capital costs of vacuum stripping systems (e.g., additional costs of
vacuum-producing equipment, larger-diameter towers) may be offset by lower
operating costs resulting primarily from a reduction in steam requirements.
Vacuum stripping may also be preferable when VOC components that have high
boiling points are stripped.
e- Corrosion-Resistant Materials Corrosive conditions requiring the use of
special corrosion-resistant materials will usually result in significantly
higher capital costs compared to the cost of carbon steel equipment. Corro-
sive conditions occur most frequently in absorption systems used for VOC
emission control when the VOC components include halogenated organic compounds,
organic acids, and amines and in systems that provide concurrent scrubbing
of corrosive inorganic components (e.g., inorganic acid vapors, acid, and salt
particulates).
A few of the many specific materials used for corrosion control include a
variety of stainless steels, Monel , the Hastelloys®, nickel, and a variety of
plastics used for the fabrication or lining of equipment and piping. Compara-
tive capital costs for condensers fabricated from Monel, type 304 stainless steel,
and carbon steel are presented in a separate report.1 These costs exemplify
the effect that special material requirements may have on capital costs.
B. ANNUAL COSTS
Annual costs for various operating conditions are presented in Appendix A.
These costs were the basis for all the cost-effectiveness graphs included in
the report. The basis used in calculating annual costs is defined in Table
V-2.
-------
V-30
Table V-2. Annual Cost Parameters
Operating factor
Operating labor
Fixed costs
Maintenance labor plus materials, 6%
Capital recovery, 18%
Taxes, insurances, administrative charges, 5%.
Utilities
Electric power
Steam
Wastewater treatment
Cooling water
8760 hr/yr
$15/man-hour
29% installed capital
$0.03/kWh
$2.50/M Btu
$0.25/1000 gal +
$0.10/lb of BOD
$0.10/1000 gal
aprocess downtime is normally expected to range from 5 to 15%. If the hourly
rate remains constant, the annual production and annual VOC emissions will be
correspondingly reduced. Control devices will usually operate on the same
cycle as the process. From the standpoint of cost-effectiveness calculations,
the error introduced by assuming continuous operation is negligible.
Based on 10-year life and 12% interest.
-------
V-31
C. COST EFFECTIVENESS AND ENERGY EFFECTIVENESS
The cost effectivenss and energy effectiveness are calculated by dividing the
annual cost for a particular option (Appendix A) or energy consumption (e.g.,
steam or electric power) by the total annual amount of VOC, with the assumed
removal efficiencies.
Typical cost-effectiveness values are given in Table V-3, and the corresponding
values for energy effectiveness are presented in Table V-4. Additional cost-
effectiveness values for other conditions are given in Appendix A. Values for
other conditions that are not given in the cited tables or graphs can be deter-
mined by the methods described in Appendix B.
-------
Table V-3. Cost Effectiveness Summary
Absorber Conditions: VOC removal, 99%; LM/mGM = 1.4.
Stripper Conditions: Organic removal, 99%; steam ratio =0.2 mole of steam/mole of air in.
Cost Effectiveness (10
Operating Parameters
VOC recovery credit = 0 for
air containing -.
0.05 wt % VOC
0.50 wt % VOC
5.0 wt % VOC
VOC recovery credit = $0.10/lb
air containing
0.05 wt % VOC
0.50 wt % VOC
5.0 wt % VOC
VOC recovery credit = $0.20/lb
air containing
0.05 wt % VOC
0.50 wt % VOC
5.0 wt % VOC
1.
12.
1.
0.
for
12.
1.
(0.
for
12.
0.
(0.
0
4
24
13
2
03
09)
0
82
31)
0.28
10
4.41
0.44
0.046
4.19
0.22
(0.17)
3.97
0.01
(0.39)
$/Mg of VOC) at Equilibrium Curve Slopes
2.02
At
100
3.34
0.34
0.036
3.12
0.12
(0.18)
2.90
(0.10)
(0.40)
Air Flow Rates (cfm X 1Q3)
1.0
16.1
1.61
0.16
15.9
1.39
(0.06)
15.6
1.17
(0.27)
10
6
0
0
6
0
(0
6
0
10
.78
.68
.07
.56
.46
.15)
.34
.24
.37)
100
4.66
0.47
0.049
4.45
0.25
(0.17)
4.23
0.03
(0.39)
of
1.0
23.6
2.36
0.24
23.3
2.14
(0.02)
23.1
1.92
(0.20)
5.74
10
12.1
I. 21
0.12
11.8
0.99
(0.10)
11.62
0.77
(0.31)
(m) of
100
8.71
0.87
0 089
8.48
0.65
(0.13)
8.27
0.44
(0.35)
OJ
(O
-------
Table V-4. Energy Effectiveness Summary
Absorber Conditions:
Stripper Conditions:
VOC removal, 99%; LM/mGM = 1.4-
Organic removal, 99%; steam ratio =0.2 mole of steam/mole of air in.
Enerqy Effectiveness (10 Btu/Mg of VOC) at Equilibrium Curve Slopes (m) of
Operating Parameters
For air containing
0.05 wt % VOC
0.50 wt % VOC
5.0 wt % VOC
0.28
1.0 10
622.1 623.3
62.2 62.3
6.2 6.2
At Air
100 1.0
615.8 773.0
61.6 77.3
6.2 7.7
2.02
Flow Rates
10
771.9
77.2
7.7
(cfm X 103) of
100 1.0
763.9 1084.1
76.4 108.4
7.6 10.8
5.74
10
1086.4
108.6
10.9
100
1079.2
107.9
10.8
f
-------
VI-1
VI. SUMMARY AND CONCLUSIONS
Gas absorption as an emission control method is currently most widely used for
the removal of water-soluble compounds from air streams, with water as the
solvent or scrubbing fluid. When absorption is used for the control of VOC
components that have low water solubility, other solvents (primarily organic
liquids with very low vapor pressures) are used.
The suitability of gas absorption as a VOC emission control method compared to
other alternatives (primarily thermal oxidation and carbon adsorption) is
dependent on the availability of a suitable solvent, the concentration of VOC
in the treated steam, and the value of the recovered VOC components.
Estimates of capital costs, operating costs, and cost effectiveness were dev-
eloped for a number of combinations of conditions or variables to illustrate
the effects of changes in these variables on costs. Some of the conclusions
derived from the cost evaluations are as follows.-
1. At low VOC concentrations the cost effectivenss of absorption is very
sensitive to the vapor equilibrium properties of the VOC-solvent system
used (expressed as m, the equilibrium curve slope)
2. Compared to other control methods, cost effectiveness of absorption is
relatively insensitive to the degree of control attained within the ranges
explored (90% to 99.9% VOC removal)
3. The incremental cost effectiveness of stripping absorber effluent water
before it is discharged is very sensitive to the volume of gas treated and
the concentration of VOC. From the standpoint of cost effectivensss alone
the discharge of absorber effluent water without stripping may well appear
to be preferable for control of emission sources containing low VOC concen-
trations; however, the effect on secondary emissions and water quality
must also be considered.
-------
APPENDIX A
ADDITIONAL CAPITAL AND COST SUMMARY CASES AND
COST-EFFECTIVE TABLES
-------
Table A-l. Capital Cost Summary for 99% VOC Removal and with Stripping
Absorber Conditions:
-------
Table A-2. Capital Cost Summary for 99.9% Removal and No Stripping
Absorber Conditions: L /mG = 1.4; VOC in air = 0.05, 0-5, 5.0 wt %.
M M
Capital Cost (10° $) at Equilibrium Curve Slopes (m) of
0.28
2.02
5.74
At Air Flow Rates (cfm X 10 ) of
Equipment
Absorber system
Tower and trays (packing)
Blower
Duct
Pump
Piping
Instrumentation
Subtotal capital cost
Total capital cost (+30%)
1.0
44.1
35.6
8.0
5.7
1.0
14.8
109.2
142.0
10
172.9
121.5
16.0
5.7
1.0
14.8
331.9
431.5
100
901.2
373.6
27.5
9.7
3.4
14.8
1330.2
1729.3
1.0
56.6
42.4
8.0
5.7
1.0
14.8
128.5
167.1
10
219.9
146.5
16.0
8.8
3.4
14.8
409.4
532.2
100
1103.2
468.3
27.5
25.5
9.7
14.8
1649.0
2143.7
1.0
65.4
47.3
8.0
6.0
1.6
14.8
143.1
186.0
10
254.0
164.8
16.0
12.8
4.5
14.8
466.9
607.0
100
1253.9
537.9
27.5
45.6 *?
s±
17.4
14.8
1897.1
1466.2
-------
Table A-3. Capital Cost Summary for 90% VOC Removal and No Stripping
Absorber Conditions: LM/mGM = 1'4; VOC in air = °-05' °-5' 5-° wt
Capital Cost (103 $)
0.28
at Equilibrium Curve
2.20
At Air Flow Rates (cfm X 103 )
Equipment
Absorber system
Tower and trays (packing)
Blower
Duct
Pump
Piping
Instrumentation
Subtotal capital cost
Total capital cost (+30%)
1.0
22.7
23.8
8.0
5.7
1.0
14.8
76.0
98.8
10
94.5
79.1
16.0
5.7
1.0
14.8
211.1
274.4
100
558.3
213.8
27.5
9.7
3.4
14.8
857.5
1114.8
1.0
26.5
25.9
8.0
5.7
1.0
14.8
81.9
106.5
10
108.0
86.4
16.0
8.8
3.4
14.8
237.4
308.6
100
639.5
241.3
27.5
25.5
9.7
14.8
958.3
1245.8
Slopes (m) of
of
1.0
29.0
27.2
8.0
6.0
1.6
14.8
86.6
112.6
5.74
10
116.7
91.2
16.0
12.8
4.5
14.8
256.0
332.8
100
673.1
259.5
27.5
45.6
17.4
14.8
1037.9
1349.3
-------
Absorber Conditions:
Table A-4. Capital Cost Summary for 99% VOC Removal and No Stripping
= 1.4; VOC in air = 0.05, 0.5, 5.0 wt %.
Capital Cost (10 J $) at Equilibrium Curve
0.28
2.02
Slopes (m)
of
5.74
At Air Flow Rates (cfm X 10 ) of
Absorber System
Tower and trays (packing)
Blower
Duct
Pump
Piping
Instrumentation
Subtotal capital cost
Total capital cost (+30%)
1.0
33.6
29.7
8.0
5 7
1.0
14.8
92.8
120.6
10
133.8
100.2
16.0
5.7
1.0
14.8
271.5
353.0
100
741.1
293.5
27.5
9.7
3.4
14.8
1090.0
1417.0
1.0
42.2
34.5
8.0
5.7
1.0
14.8
106.2
138.1
10
165.6
117.4
16.0
8.7
3.4
14.8
325.9
423.7
100
870.9
358.0
27.5
25.5
9.7
14.8
1306.4
1698.3
1.0
48.2
37.8
8.0
6.0
1.6
14.8
116.4
151.3
10
188.2
129.4
16.0
12.8
4.5
14.8
365.7
475.4
100
965.8
403.5
27.5
45.6
17.4
14.8
1474.6
1917.0
cr>
-------
Table A-5. Annual Cost Summary for 99% VOC Removal and No Stripping
Absorber Conditions: 99% VOC Removal; LM/mGM = 1.4; VOC in air = 0.05, 0.5, 5.0 wt %.
Annual Cost
Fixed costs (29% of capital)
Process water ($0.25/1000 gal)
Electricity ($0.03/kWh)
Steam ($2.50/1000 Ib)
Wastewater treat. ($0.25/1000 gal)
Cooling water ($0.10/1000 gal)
Operating Labor ($15/hr)
Total annual cost excluding BOD
surcharge and recovery credit
BOD Surcharge
0.05 wt % VOC in air
0.50 wt % VOC in air
5.0 wt % VOC in air
Net annual cost (credit)
VOC recovery credit = 0 for
air containing
0.05 wt % VOC
0.5 wt % VOC
5.0 wt % VOC
1.0
35.0
0.3
3.6
0.3
13.1
52.3
1.9
19.3
193
54.2
71.6
245.3
0.28
10
102.4
2.9
36.0
2.9
13.1
157.3
19.3
193
1930
176.6
350.3
2087.3
At
100
410.9
28.8
302.8
28.8
13.1
784.4
193
1,930
19,300
977.4
2,714.4
20,080
do3 $)
Air Flow
1.0
40.0
2.1
4.6
2.1
13.1
61.9
1.9
19.3
193
63.8
81.2
254.9
at Equilibrium Curve Slopes (m) of
2.02
Rates (cfm X 103)
10 100
122.9 492.5
20.7 207.2
47.2 416.1
20.7 207.2
13.1 13.1
224.6 1,336
"
19.3 193
193 1,930
19,300
243.9 1,529
417.6 3,266
2154.6 20,640
of
1.0
43.9
5.9
5.5
5.9
13.1
74.3
—
1.9
19.3
193
76.2
93.6
267.3
5.74
10
137.9
58.9
56.7
58.9
13.1
325.5
_
19.3
193
1930
344.8
518.5
2255.5
100
555.9
588.7
510.8
S
588.7
13.1
2,257
193
1,930
19,300
2,450
4,187
21,560
-------
Table A-6. Annual Cost Summary for 99.9% VOC Removal and No Stripping
Absorber Conditions: LM/mGM = 1.4;_VOC in air = 0.05, 0.5, 5.0 wt %.
Annual Cost (1Q3 $) at Equilibrium Curve
Equipment
Fixed costs (29% of capital)
Process water ($0.25/1000 gal)
Electricity ($0.03/kWh)
Steam ($2.50/1000 Ib)
Wastewater treat ($0.25/1000 gal)
Cooling water ($0.10/1000 gal)
Operating labor ($15/hr)
Total annual cost exluding BOD
surcharge and recovery credit
BOD surcharge
0.05 wt % VOC in air
0.50 wt % VOC in air
5.0 wt % VOC in air
Net annual cost (credit)
VOC recovery, credit = 0 for
air containing
0.05 wt % VOC
0.5 wt % VOC
5.0 vt % VOC
1.0
41.2
0.3
4.9
0.3
13.1
59.8
1.9
19.5
194.6
61.7
79.3
254,4
0.28
10
125.2
2.9
49.3
2.9
13.1
193.4
19.5
194.6
1946
212.9
388.0
2739,4
At
100
501.5
28.8
435.8
28.8
13.1
1,008.0
194.6
1,946
19,460
1,202.6
2,954
20 , 470
2.02
Slopes (m) of
5.74
Air Flow Rates (cfm X 10 ) of
1.0
48.5
2.1
6.6
2.1
13.1
72.4
1.9
19.5
194.6
74.3
91.9
267.0
10
154.3
20.7
67.0
20.7
13.1
275.8
19.5
194.6
1946
295.3
470.4
2221.8
100
621.7
207.2
613.9
207.2
13.1
1,663.1
194.6
1,946
19,460
1,857.7
3,601.9
21,120
1.0
54.0
5.9
8.0
5.9
13.1
86.9
1.9
19.5
194.6
88.8
106.4
281.5
10
176.1
58.9
81.9
58.9
13.1
388.9
19.5
194.6
1946
408.4
583.5
2334.9
100
715.2
588.7
762.3
588.7 I
13.1
2,668
194.6
1,946
19,460
2,862.9
4,614.0
22,130
-------
Table A-7. Annual Cost Summary for 90% VOC Removal and No Stripping
Absorber Conditions: LM/mGM = 1.4; VOC in air = 0.05, 0.5, 5.0 wt %.
Annual
0.28
Cost
(io3 $)
at Equilibrium
2.02
... .. At Air Flow Rates (cfm
Fixed costs (29% of capital)
Process water ($0.25/1000 gal)
Electricity ($0.03/kWh)
Steam ($2.50/1000 Ib)
Wastewater treat. ($0.25/1000 gal)
Cooling water ($0.10/1000 gal)
Operating labor ($15/hr)
Total annual cost excluding BOD
surcharge and recovery credit
BOD surcharge
0.05 wt % VOC in air
0.50 wt % VOC in air
5.0 wt % VOC in air
Net annual cost (credit)
VOC recovery credit = 0 for
air containing
0.05 wt % VOC
0.5 wt % VOC
5.0 wt % VOC
1.0
28.6
0.3
2.4
0.3
13.1
44.7
1.8
17.5
175.3
46.5
62.2
220.0
10
79.5
2.9
24.1
2.9
13.1
122.5
17.5
175.3 1,
1753 17,
140.0
297.8 2,
1875.5 18,
100
323.3
28.8
184.3
28.8
13.1
578.3
175.3
753
530
753.4
331.1
110
1.0
30.8
2.1
2.8
2.1
13.1
50.9
1.8
17.5
175.3
52.7
68.4
226.2
10
89.5
20.7
28.7
20.7
13.1
172.7 1,
17.5
175.3 1,
1753 17,
190.2 11,
348.0 2,
1925.7 18,
Curve
X 10 )
100
361.3
207.2
230.5
207.2
13.1
019.1
175.3
753
530
944
772.1
550
Slopes (m)
of
1.0
32.7
5.9
3.1
5.9
13.1
60.7
1.8
17.5
175.3
62.5
78.2
236.0
of
5.74
10
96.5
58.9
32.9
58.9
13.1
260.3
17.5
175.3
1753
277.8
435.6
2013.3
100
391.3
588.7
272.7
588.7 >
VO
13.1
1,854.5
175.3
1,753
17,530
2,029.8
3,607.5
19,380
-------
Table A-8. Annual Cost Summary for 99% VOC Removal, with
Stripping and Steam Ratio of 0.1
Absorber Conditions: LM/mGM = 1.4; VOC in air = 0.05, 0.5, 5.0 wt %.
Stripper Conditions: Steam ratio =0.1 mole of steam/mole of air in.
Annual Cost
0.28
(10 $) at Equilibrium Curve Slopes (m) of
At Air Flow Rates
Fixed costs (29% of capital)
Process water ($0.25/ra gal)
Electricity ($0.03/kWh)
Steam ($2.50/1000 Ib)
Wastewater treat ($0.25/1000 gal)
Cooling water ($0.10/1000 gal)
Operating labor ($15/hr)
Total annual cost excluding BOD
Surcharge and recovery credit
BOD surcharge
0.05 wt % VOC in air
0.50 wt % VOC in air
5.0 wt % VOC in air
Net annual cost: (credit)
VOC recovery credit - 0
0.05 wt % VOC
0.5 wt % VOC
5.0 wt % VOC
VOC recovery credit - $0.10/lb
0.05 wt % VOC
0.50 wt % VOC
5.0 wt % VOC
VOC recovery credit - $0.20/lb
0.05 wt % VOC
0.50 wt % VOC
5.0 wt % VOC
1.0
55.7
0.3
j.8
6.5
0.4
0.7
32.9
100.3
0.02
0.2
1.9
100.3
100.5
102.2
98.4
81.4
(88.7)
96.5
62.3
'270 6)
\t. i j •
-------
Table A-9. Annual Cost Summary for 99% VOC Removal, with
Stripping, and Steam Ratio of 0.2
Annual Cost (10 5) at Equilibrium Curve Slopes
I qui pp^rn.t
Fixed costs (29% of capital)
Process water ($0.25/m gal)
tlcctrxcity ($0.03/kWh)
Steam ($2.50/1000 Ib)
Wastewater treat ($0.25/1000 gal)
Cooling water ($0.10/1000 gal)
Operating labor ($15/hr)
Total annual cost excluding BOD
surcharge and recovery credit
BOD surcharge
0.05 wt % VOC in air
0.50 wt % VOC in air
5.0 wt % VOC in air
Net annual coat (credit)
VOC recovery credit 0
0.05 wt % VOC
0.5 wt t VOC
5.0 wt % VOC
VOC recovery credit $0.10/lb
0.05 wt % VOC
0.50 wt % VOC
5.0 wt % VOC
Voc recovery credit $0.20/lb
0.05 wt * VOC
0.50 wt 1 VOC
5.0 v,t % VOC
1 .0
57.3
0.3
3.8
12.5
0.4
1.5
32.9
108.7
0.02
0.2
1.9
108,7
108.9
110.6
106.8
89.8
(80.3)
104.9
70.7
(271.7)
0.28
10
169.
2.
36.
125.
4.
14.
32.
385.
0.
1.
19.
385.
387.
404.
366.
196.
(1504.
347.
5.
(3412)
8
9
2
0
3
5
9
6
2
9
3
8
5
9
7
6
1)
6
8
100
725.7
28.8
304.0
1,250
433.0
145.1
32.9
2,919.5
1.9
19.3
193
2,921.4
2,938.8
3,112.5
2,730.5
1,030
(15,980)
2,539
(878.2)
(35,060)
At Air
1.0
81.7
2.1
4.8
15.4
2.2
1.5
32.9
140.6
0.02
0.2
1.9
140.6
140.8
142.5
138.7
121.7
(48.4)
136.8
102.6
(239.2)
2.02
(m) of
5.74
Flow Rates (cfm X 10 ) of
10
300.7
20.7
48.0
153.7
22.2
14.5
32.9
592.7
0.2
1.9
19.3
592.9
594.6
612.0
573.8
403.7
(1297.0)
554.7
212.9
(3205)
100
1,510
207.2
424.5
1,537
221.7
145.1
32.9
4,078
1.9
19.3
193
4,079.9
4,097.3
4,271
3,889
2,188.3
(14,820)
3,698.2
280.3
(33,900)
1.0
127.8
5.9
5.7
21.9
6.0
5.8
32.9
206.0
0.02
0.2
1.9
206.0
206.2
207.9
204.1
187.1
(17.0)
202.2
168.0
(173.8)
10
567.
58.
59.
219.
60.
58.
32.
1,055
0.
1.
19.
1055.
1056.
1074.
1036,
0
9
1
0
3
0
9
2
9
3
.2
9
,3
.1
866.0
(834
1017
675
.7)
.0
.2
(2742)
100
3086
589
534.5
2,190
603
580
32.9
7,615.4
1.9
19.3
193
7,617
7,635
7,808
7,416
5,726
(11,280)
7,235
3,818
(30,360)
-------
Table A-10. Cost Effectiveness Summary for 99% VOC Removal for
Tray Column with Water Discharged without stripping and No VOC Recovered
Absorber Conditions:
L /mG = 1.4; VOC in air = 0.05, 0.5, 5.0 wt %.
M M
Cost Effectiveness (10 $/Mg
0.28
of VOC) at
2.02
Equilibrium Curve Slopes (m) of
T,
5.74
At Air Flow Rates (cfm X 10 ) of
1.0
10
100
1.0
10
100
1.0
10
100
VOC Recovery Credit = 0
0.05 wt
0.50 wt
5.0 wt \
% VOC
% VOC
fe VOC
6.19
0.82
0.28
2.02
0.40
0.24
1.12
0.31
0.23
7.29
0.93
0.29
2.79
0.48
0.25
1.75
0.37
0.24
8.71
1.07
0.31
3.94
0.59
0.26
2.80
0.48
0.25
I
— — • i— •
(O
-------
Table A-ll. Cost Effectiveness Summary for 99.9% VOC Removal for Tray Column, with
Water Discharged without Stripping and No VOC Recovered
Absorber Conditions: L /mGM = 1.4; VOC in air = 0.05, 0.5, 5.0 wt %.
M M
Cost Effectiveness (10 $/Mg
0.28
of VOC) at
2.02
Equilibrium Curve Slopes (m) of
1
5.74
At Air Flow Rates (cfm X 10 ) of
VOC Recovery
0.05 wt %
0.50 wt %
Credit = 0
VOC
VOC
5.0 wt % VOC
1.0
6.99
0.90
0.29
10
2.41
0.44
0.24
100
1.36
0.33
0.23
1.0
8.42
1.04
0.30
10
3.35
0.53
0.25
100
2.10
0.41
0.24
1
10
1
0
.0
.1
.21
.32
10
4.63
0.66
0.26
100
3.24
0.52
0.25 f
M
-------
Table A-12. Cost Effectiveness Summary for 90% VOC Removal for
Absorber, with'Water Discharged without Stripping and No VOC Recovered
Absorber Conditions: VOC removal, 90%; LM/mGM = 1.4; VOC in air = 0.05, 0.5, 5.0 wt %.
0.28
1.0 10
VOC Recovery Credit = 0
0.05 wt % VOC 5.85 1.76
0.50 wt % VOC 0-78 0.37
5.0 wt % VOC 0.28 0.24
Cost
100
0.95
0.29
0.23
(10 $) at Equilibrium Curve Slopes
At Air
1.0
6.63
0.86
0.28
2.02
Flow Rates (cfm
10
2.39
0.44
0.24
3
x 10 ) of
100
1.50
0.35
0.23
(m) of
1.0
7.86
0.98
0.30
5.74
10 100
3.49 2.55
0.55 0.45
0.25 0.24
-------
Table A-13. Cost Effectiveness Summary for 99% VOC Removal and Steam Ratio of 0.1
Absorber Conditions: VOC removal, 99%; L^/mG^ - 1.4%; VOC in air - 0.05, 0.5, 5.0 wf %.
Stripper Conditions: Organic removal, 99%; steam ratio =0.1 mole of steam/mole of air in.
Cost Effectiveness (10
VOC
0.
0.
5.
VOC
0.
0.
5.
VOC
0.
0.
5.
%
Recovery Credit = 0
05 wt % VOC
50 wt % VOC
0 wt % VOC
Recovery Credit = $0.10/lb
05 wt % VOC
50 wt % VOC
0 wt % VOC
Recovery Credit = $0.20/lb
05 wt % VOC
50 wt % VOC
0 wt % VOC
1
11
1
0
11
0
(0
11
0
(0
.0
.5
.15
.12
.3
.93
.10)
.0
.11
.32)
10
3.
0.
0.
3.
0.
(0.
3.
(0.
(0.
0.28
At Air
50
35
037
28
13
18)
06
08)
40)
3 $/Mg of
Flow Rates
100
2.05
0.21
0.023
1.84
(0.01)
(0.20)
1.62
(0.23)
(0.41)
VOC) at Equilibrium
(cfm X
1
15
1
0
14
1
(0
14
1
(0
103) of
.0
.1
.51
.15
.9
.29
.07)
.7
.08
.28)
Curve Slopes
2.
10
5.
0.
0.
5.
0.
(0.
5.
0.
(0.
02
88
59
061
67
37
16)
45
15
38)
(m) of
100
3.78
0.38
0.039
3.56
0.16
(0.18)
3.34
(0.06)
(0.40)
Ul
-------
APPENDIX B
SAMPLE CALCULATIONS
-------
B-3
SAMPLE CALCULATIONS
I . Capital Cost Parameters
Basis
10,000 SCFM of air at 25 °C containing 0.5 wt % acetone.
VOC (acetone) removal efficiency of absorber, 99.0%.
Solvent: water at 25 °C, single-pass usage.
A. Tray-Column Parameters
1. Liquid Rate
For a dilute solution (ref 1) :
m - _ (6.7) (229 mm)
~~ ~ ~ -2.02,
where
m = equilibrium curve slope,
y = activity coefficient of acetone at 25 °C,
PI = pure component vapor pressure, mm Hg, at 25 °C,
P = total pressure, mm Hg;
if we let
mG
M
where
LM
—- = liquid-to-gas mole ratio,
GM
= PV _ (14.7) (10,000) (60) _ 1534 Ib-moles of air
M RT (10.71) (460 + 77) ~ hr ;
then
L = 1.4 mGM = (1.4) (2.02) (1534) - 434° lb-mo^s o£
M M hr
-------
B-4
or
(4340) (18)
(8.33) (60)
2. Number of Theoretical Trays, Np
Using Fig. B-I to estimate the number of theoretical trays required, at a VOC
removal efficiency of 99%, Y^Y;, = 100 and ™GM/LM = 0.71. From Fig. B-l,
N =10.0, where YI = mole fraction of VOC in scrubber inlet gas, Y2 = mole
p
fraction of VOC in scrubber outlet gas, and Np = number of theorectical plates
required.
3. Tray Efficiency
9
The tray efficiency can be expressed as
0.377 0.377
Eo " /mM p /p \OJ209 [(2.02) (18) (1.0) /62.4] 0 .20 9
\ L L L )
where
E = tray efficiency,
m = equilibrium curve slope,
M = molecular weight of liquid,
L
y = viscosity of liquid, centipoise ,
L 3
p = density of liquid, Ib/ft .
L
4. Actual Number of Trays, N
o
5. Tower Diameter
The superficial gas velocity in a bubble-cap tray tower at flooding is estimated
by3
-------
W
I
Number of Theoretical Plates,
Q
h
0
HI
§ s
rt
rt H-
s s
w
3
O
3
ro
W
o
CO
en
rt
H-
O
3
O
0
-------
B-6
where
V = superficial flooding velocity, fps,
p = liquid density, Ib/ft ,
L 3
p = gas density, Ib/ft ,
G
C = a constant determined by the following equation
F
C =
_
F = [S 10g (WG-) (PG/PL)0'5 +
where
a and b = constants whose values are given in Table B 1, in which t, the
tray spacing, is given in inches,
(LVG') :
= (4340 X 18) /(1534 X 29) X [ (0.0749/62.4)]°'5
= 0.0608.
From Table B-l, with a tray spacing of 18 in., a = (0.041 X 18) + 0.0135 = 0.0873,
and b = (0.0047 X 18) + 0.068 = 0.1526; then with a surface tension of 72.0
an = . . .
/ 1 i / 72 0
dynes/cm (water at 250C) , Cp = ^0.0873 log ^^g + 0.1526J -- = 0.334,
and
_ 0 334 (62.4- 0.0749- =
p - U.JJt ^ 0.0749 / ^
Assuming the actual superficial vapor velocity to be a conservative 50% of
flooding velocity, V = (0.5) (9.63) = 4.82 fps, the tower cross -sectional area
= 10,000 cfm X (min/60 sec) X min X (sec/4.82 ft) = 34.5 ft2, and the diameter
= [ (4 X 34.5)/n]°'5 = 6.63 ft.
6. Tower Height
With 18-in. tray spacing the overall height = [18 X (ft/12 in.) X no. of trays +
(2 X diam) = 18 X 24)/(12) + (2 X 6.6) = 49.2 ft.
7. Tower Pressure Drop
With a Ap of 3 in. H20 per tray the total tower pressure drop = (3 X 24) =
72.0 in. H20.
-------
B-7
Table B-l. Flooding Constants,
0.01-0.03 use values
at 0.03
0.03-0.2
0.2-1.0
Flooding constant C
Range of
0.01-0.1 use values
at 0.1
0.1-1.0
aFrom ref 3.
0.0041t + 0.0135
0.0068t + 0.049
Perforated Trays
0.0062t + 0.0385
0.0047t + 0.068
0.0028t + 0.044
0.00253t + 0.05
-------
B-8
B. Packed-Column Parameters
Basis : 1-in. porcelain Raschig rings; other criteria the same as those for
the tray column.
1. Tower Diameter
Using the correlation shown in Fig. B-2, we calculated the factor (L'/V") X
c
(PG/PI,)°° , where L' = liquid flow rate, Ib/hr, V^ = gas flow rate, Ib/hr, p
gas density, lb/ft3 , and pL = liquid density, lb/ft3, to be:
(4340) (18) /0.0749\ °'5 _
(1534) (29) l~6274~/ ~ °-0608-
Then, from Fig. B-2,
.2
where
G = gas flow rate at flooding conditions, lb/sec-ft2 tower cross-section,
A/e3 = packing factor from Fig. B-3 = 170,
o
PQ = gas density, lb/ft ,
PL = liquid density, lb/ft3,
\i' - liquid viscosity, centipoises,
gc = gravitation constant, 32.2 ft/sec2:
G' =
(0.13) (32.2) (0.0749) (62.4)
(170) (1.0)0-2
Designed for 60% of flooding velocity the design rate, G _, = (0.6) (0.339)
0.204 lb/sec-ft2.
The tower cross-sectional area is
1534 Ib-moles 29 Ib sec-ft2 hr 2
hr Ib-moles 0.204 Ib 3600 sec
-------
0 1
0 01
B-9
0 001
0 01
0 I
U' 'V
I 0
10 0
Fig. B-2. Correlation for Flooding Rate
in Randomly Packed Towers (from ref 4)
-------
B-10
000
100
50
40
30
20
10
\
, U
\\
V.
\
\
X
\\
\\J
\*
^
,V^
PACKING FACT3P FOR 1 m IN
SJSDOLES ? <' 90
0 (
"^~ '
"^>^
ALOX
^^-~-^
~---^_
5 to IS 2025 30 3 '
NOMINAL PACKING SIZE (in.)
Fig. B-3. Packing Factors for Raschig Rings and Saddles
-------
B-ll
The tower diameter was then calculated as
F(60.6) (4)
D =
n
To.s
- =8.8 ft.
2. Number of Transfer Units, NQG
Using Fig. B-4 to estimate the number of transfer units required, at a VOC removal
efficiency of 99.0%, y.,/y2 = 100, and mG /L = 0.71: N0r
=
3. Height of a Transfer Unit
The height of a transfer unit, H , is obtained by the following relationships
between H (the height, in feet, of a gas-transfer unit) and H (the height, in
feet, of a liquid-transfer unit) :
G \
H = H + m -^ H
where
\PGPG
and
in which
m = equilibrium curve slope,
n
G = superficial gas rate, Ib/hr-ft ,
L = superficial liquid rate, Ib/hr-ft ,
a -a packing constant from Table B-2,
g = a packing constant from Table B-2,
y = a packing constant from Table B-2,
n
y,, = a gas viscosity, Ib/hr-ft
u
pG = gas density, Ib/ft ,
ry
DG = gas diffusivity, ft /hr
-------
B-12
10,000
y2-mx2
Fig. B-4. Number of Transfer Units in an
Absorption Column for Constant mG /LM
-------
B-13
Table B-2. Constants for Use in Determining Gas Film's
Height of Transfer Units
Packing
Raschig rings
3/8 in.
1 in
JL -LJ.I •
1-1/2 in.
2 in.
Berl saddles
1/2 in.
1 in.
1-1/2 in.
3-in. partition rings
Spiral rings (stacked
staggered)
3 in. single spiral
3 in. triple spiral
Drip-point grids
No. 6146
No. 6295
Packing Constants
a
2
7
6
17
2
3
32
0
1
5
650
2
15
3
4
.32
.00
.41
.30
.58
.82
.40
.81
.97
.05
.38
.60
.91
.56
P
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
45
39
32
38
38
41
30
30
36
32
58
35
38
37
,17
Y
0.47
0.58
0.51
0.66
0.40
0.45
0.74
0.24
0.40
0.45
1.06
0.29
0.60
0.39
0.27
Mass
200
200
200
200
200
200
200
200
200
200
150
130
200
130
100
Flow Rates [lb/(hr)
Gas
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
(ft2)]
Liquid
500
800
600
700
700
800
700
700
800
1,000
900
700
1,000
1,000
1,000
500
400
500
500
1,500
500
500
1,500
400
400
3,000
3,000
500
3,000
2,000
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
1,500
500
4,500
1,500
4,500
4,500
1,500
4,500
4,500
4,500
10,000
10,000
3,000
6,500
11,500
Adapted from ref 4.
-------
B-14
(values for the group known as the Schmidt number are given in Table B-3)
yT = liquid viscosity, Ib/hr-ft,
LI
<}> = a packing constant from Table B-4,
H = a packing constant from Table B-4,
PL = liquid density, Ib/ft ,
DL = liquid diffusivity, ft2/hr
(the values for the group U/pLDL , the Schmidt number, are given in Table B-5).
The values for the group UG/PGDG, als° kn°Wn aS th& Schmidt number' are 9iven in
Table B-3; the values for the group y/PLDL are given in Table B-5; and the values
for G and L are, respectively,
1534 Ib-moles 29 Ib 1 = 734 ^
hr Ib-mole 60.6 ft2
and
4340 Ib-moles _18 Ib 1 _ 1289 i
hr Ib-mole 60.6 ftz
Then
-s (1.60)0*5 = 1.82 ft.
(1289.1)
and
H =
= (0.01)
il V"" (767)°-5 = 1.13 ft,
0.894)y ^ /
HOG " 2° ' = 2'63
-------
B-15
Table B-3. Diffusion Coefficients of Gases and Vapors
in Air at 25 °C and 1 atm
Substance
Ammonia
Carbon dioxide
Hydrogen
Oxygen
Water
Carbon disulfide
Ethyl ether
Methanol
Ethyl alcohol
Propyl alcohol
Butyl alcohol
Amyl alcohol
Hexyl alcohol
Formic acid
Acetic acid
Propionic acid
i-Butyric acid
Valeric acid
i-Caproic acid
Diethyl amine
Butyl amine
Aniline
Chlorobenzene
Chlorotoluene
Propyl bromide
Propyl iodide
Benzene
Toluene
Xylene
Dif fusivity
o
(cm /sec)
0.236
0.164
0.410
0.206
0.256
0.107
0.093
0.159
0.119
0.100
0.090
0.070
0.059
0.159
0.133
0.099
0.081
0.067
0.060
0.105
0.101
0.072
0.073
0.065
0.105
0.096
0.888
0.084
0.071
Schmidt No. ,
PD
0.66
0.94
0.22
0.75
0.60
1.45
1.66
0.97
1.30
1.55
1.72
2.21
2.60
0.97
1.16
1.56
1.91
2.31
2.58
1.47
1.53
2.14
2.12
2.38
1.47
1.61
1.76
1.84
2.18
-------
B-16
Table B-3 (Cont'd)
Substance
Ethyl benzene
Propyl benzene
Diphenyl
n-Octane
Mesitylene
b
Acetone
Dif fusivity
(cm /sec)
0.077
0.059
0.068
0.060
0.067
Schmidt No. ,
~D
2.01
2.62
2.28
2.58
2.31
1.60 32 °F
a
LAdapted from ref 4.
-------
B-17
Table B-4. Constants for Use in
Determining Liquid Film's Height of
Transfer Unitsa
Packing
Raschig rings
3/8 in.
1/2 in.
1 in.
1-1/2 in.
2 in.
Berl saddles
1/2 in.
1 in.
1-1/2 in.
3- in. partition rings
Spiral rings (stacked
staggered)
3 in. single spiral
3 in. triple spiral
Drip-point grids
No. 6146
No. 6295
0
0
0
0
0
0
0
0
0
0
0
0
0
*
.00182
.00357
.0100
.0111
.0125
.00666
.00588
.00625
.0625
.00909
.0116
.0154
.00725
n
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
Liquid Mass Flow Rate
[lb/(hr) (ft2)]
46
35
22
22
22
28
28
28
09
28
28
23
31
400
400
400
400
400
400
400
400
3,000
400
3,000
3,500
2,500
to
to
to
to
to
to
to
to
to
to
to
to
to
15,
15,
15,
15,
15,
15,
15,
15,
14,
15,
14,
30,
22,
000
000
000
000
000
000
000
000
000
000
000
000
000
Adapted from ref 4.
-------
B-18
Table B-5. Diffusion Coefficients in
Liquids at 20°Ca
b
Solute
°2
C02
N2O
NH3
CI2
Br2
H2
N2
HC1
H2S
H2SO4
HNO3
Acetone
Acetylene
Acetic acid
Methanol
Ethanol
Propanol
Butanol
Allyl alcohol
Phenol
Glycerol
Pyrogallol
Hydroquinone
Urea
Resorcinol
Urethane
Lactose
Maltose
Glucose
D X 10 5
(cm2 /sec) X 10s
1.80
1.77
1.51
1.76
1.22
1.20
5.13
1.64
2.64
1.41
1.73
2.60
1.56
0.88
1.28
1.00
0.87
0.77
0.93
0.84
0.72
0.70
0.77
1.06
0.80
0.92
0.43
0.43
0.60
V-
PD
558
559
665
570
824
840
196
613
381
712
580
390
c
767
645
1,140
785
1,005
1,150
1,310
1,080
1,200
1,400
1,440
1,300
946
1,260
1,090
2,340
2,340
-
-------
B-19
Table B-5. (Cont'd)
Solute
Mannitol
Raffinose
Sucrose
Sodium chloride
Sodium hydroxide
cod
Phenol
Chloroform
Phenol6
e
Chloroform
Acetic acid
Ethylene dichloride
D X 105
(cm2 /sec) X 105
0.58
0.37
0.45
1.35
1.51
3.40
0.80
1.23
1.54
2.11
1.92
2.45
y
po
1,730
2,720
2,230
745
665
445
1,900
1,230
479
350
384
301
Adapted from ref 4.
Solvent is water except where indicated.
GValue calculated by method in ref 5.
Solvent is ethanol.
Solvent is benzene.
-------
B-20
4. Tower Height1*
The packed height, Z, = N_ X IT = (11.8) (2.63) = 31.0 ft. The total tower
UG OG
height, Z + (2. X diam), = 31.0 + (2) (8.8) = 48.6 ft.
5. Tower Pressure Drop, AP (ref 4.)
10 " ^ 'PS
where
AP = pressure drop, Ib/ft,
Z = packed height of tower, ft,
m = pressure drop constant (Table B-6),
r\ = pressure drop constant (Table B-6),
o
L^ = superficial mass-liquid velocity, Ib/hr-ft ,
n
G" = superifical mass-gas velocity, Ib/hr-ft ,
p = liquid density, Ib/ft ,
J-i
PG = gas density Ib/ft .
Then
AP = (32.1)
or
AP = 38.0 Ib/ft2
= 16.9 in. H20-
II. Stripping Tower Parameters
Basis
Absorber — 10,000 scfm of air at 25 °C containing 0.5 wt % acetone; VOC (acetone)
removal efficiency, 99.0%; solvent, water; single-pass usage, mGj4/LM =0.7
Stripper- — VOC (acetone) removal efficiency from water, 99.0%; heat supplied by
direct injection of steam (no reboiler) ,- steam usage, 0.1 mole of steam/mole of
air treated in absorber.
-------
B-21
Table B-6. Pressure-Drop Constants for Tower Packing'
Packing
Raschig rings
Berl saddles
Intalo,x saddles
Drip-point grid
tiles
Nominal
Size
(in.)
1/2
3/4
1
1-1/2
2
1/2
3/4
1
1-1/2
1
1-1/2
No. 6146
continuous
flue
Cross flue
No. 6295
continuous
flue
Cross flue
m
139
32
32
12
11
60
24
16
8
12
5
1
1
1
1
.90
.10
.08
.13
.40
.10
.01
.01
.44
.66
.045
.218
.088
.435
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
n
.00720
.00450
.00434
.00398
.00295
.00340
.00295
.00295
.00225
.00277
.00225
.00214
.00227
.00224
.00167
Liquid Mass
Flow Rate
[ (lb/(hr)(ft2)]
300
1,800
360
720
720
300
360
720
720
2,520
2,520
3,000
300
850
900
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
8,600
10,800
27
18
21
14
14
78
21
14
14
17
17
13
12
,000
,000
,000
,100
,400
,800
,600
,000
,400
,000
,500
,500
,500
Range
of P/Z
tlb/(ft2)(ft)]
0 to
0 to
0 to
0 to
0 to
0 to
0 to
0 to
0 to
0 to
0 to
0 to
0 to
0 to
0 to
2.6
2.6
2.6
2.6
2.6
2.6
2.6
2.6
2.6
2.6
2.6
0.5
0.5
0.5
0.5
"Adapted from ref 4.
-------
B-22
A. Tray Column Parameters
1. Number of Theoretical Trays (Np)
Estimating N by the equation*5
NP =
in
where
N = number of theoretical plates,
P
m = slope of equilibrium curve at liquid-discharge conditions,
L = liquid rate, mole/hr,
G = vapor rate, mole/hr,
M
x = mole fraction of VOC in liquid in,
x = mole fraction of VOC in liquid out,
y = mole fraction of VOC in vapor in.
With sparged steam as the inlet vapor Y2 is 0 and at a removal efficiency of
99.0%, x /x is 100.
For a dilute aqueous solution of acetone at 212°F, the value of m at the origin
is 36.9 (ref 5). Then
LM = 4340 Ib-moles/hr of water (from absorber calculation),
[ Ib-moles of air \ / Ib-mole of stearin ,,--,„,,_ i 4. „ n,^.
GM = 1534 ) 10.1 —rr ; 7 : )= 153.4 Ib-moles steam/hr,
M \*->Jt h / \ Ib-mole of air /
This equation assumes straight-line equilibrium and operating lines, conditions
that are generally approached closely only with very dilute solutions. The equation
can generally be used only for determining the number of plates in the stripping
section in actual design calculations. (Other calculations are used for determin-
ing the number of plates in the enriching section.) However, as most of the trays
are usually required in the stripping section, the equation can be used for rough
estimates of the total number of trays, which are of sufficient accuracy for the
purposes of this report.
-------
B-23
and
(4340) \ (-LOO] ( (4340)
InLV1" (36.9) (153.4) / V 1 I +\(36.9) (153.4)/| =11<9<
NP " ~~ "(36.9) (153.4)
ln (4340)
2. Number of Actual Trays
From Fig. 15-10 of ref 2, in which yp =0.28 cp and Y = V/x is conservatively
assumed to be 36.9, E0 = 0.27, where E0 = tray efficiency and Y = relative
volatiles of key components:
N g
N = — = — = 44 trays.
E0 0.27
3. Tower Diameter
6
The equation
V = K
PL - PG
PG
where
V = superficial vapor velocity, fps,
2
pL = liquid density, Ib/ft ,
Q
PG = vapor density, Ib/ft ,
K = empirical constant determined from Fig. B-5,
is used to determine the superficial gas velocity that will prevent excessive
entrainment.
From Fig. B-5, using 18-in. tray spacing and a liquid seal depth of 1 in., K = 0.14
and
/59.8 - 0.0373V'5 , , f
v = °-i4i~T^B—; =5-6 fps-
-------
B-24
0 12
10 12 U 16
IBM SP'ClhG (t I i in.)
Fig. B-5, Tray-Spacing Constants to Estimate
Bubble-Cap Tray Tower's Superficial Vapor Velocity
(from ref 4)
-------
B-25
The volumetric vapor flow rate is
1534 Ib-moles 18 Ib 26.8 Ib hr = 20 6 cfs
hr Ib-mole ft3 3600 sec
The cross-sectional area is
sec
sec 5.6 ft
The tower diameter is
^ (3.68) '
= 2.16ft.
4. Tower Height
With 18-in. tray spacing and 44 trays the total height is
44 X v^ + (4 X 2.16 ft) = 74.6 ft.
5. Tower Pressure Drop
With a AP of 3 in. H2O per tray the total tower presure drop = (3) (44) = 132 in. HzO.
B. Packed-Column Parameters
The types of calculations used to determine the parameters for packed stripping
towers are essentially the same as those used to determine packed absorber
parameters (using the same conditions and physical properties that were used to
determine plate-stripping-tower parameters); specific sample calculations for
packed-stripping-tower parameters are not included.
C. Absorber Inlet Air Duct*
Basis
Approximate linear gas velocity = 4000 fprn; flow-rate = 10,000 cfm at 77°F; duct
components = 150-ft duct, 4 ells, 1 butterfly valve, and 1 expansion joint.
*The remaining sample calculations will be given for the plate tower example only,
as the calculation methods for the packed-column case are the same.
-------
B-26
1. Duct Diameter, D
10,000 ft3 min = 2 5 ft2
min 4000 ft
D = IfLJL} — (41 I = 1>
ft (use 20-in. duct)
2. Pressure Drop
3.36 X 10 6 fLW2 V
Ap =
where
Ap = pressure drop, psi,
f = friction factor,
L = length of pipe, ft,
W = rate of flow, Ib/hr,
V = specific volume, ft
d = internal diameter, in.
P\TM 14 7 Ib 10,000 ft 60 min
•C V J- -I _4_ T • / J-J-^ -»- V JT v V
and
46077
V - ^ - 10>71 X (460 + 77) = 3/lb>
V ~ PM ~ 14.7 X 29
To determine f
6.31 w
Re = — ,
dp
where Re = Reynolds number and y = viscosity, centipoise.
_ (6.31) (44,470) =
Re "" (20) (0.018)
-------
B-27
From ref 7, the friction factor, f, is 0.0137.
The values of the equivalent lengths, L, are as follows:
No._ L/D L (ft)
Straight-run pipe = 150.0
Elbows 4 20 = 133.3
Butterfly valve 1 18 = 30.0
•Expansion joint (est.) 1 50 = 84.0
Entrance and exit loss 1 109 = 183.0
Total 580-°
AP
(3.36 X 10 6) (.0137) (580) (44470) 2 (13.5) = Q 22 ._ *
20s
D. Blower Requirements
Basis
Efficiency =0.7
Ib „
hp = AP ^--2X f' Xflow rate — X ^-^ X -550 ft_lb
hp = 0.00623 (AP psi) (flow scfm)
144 in 2 ft3 min „ sec-hp 1
144' — X - X - X
Absorber tower AP = 72 in. H20 X 27-7 H20 = 2"6
inlet duct AP = 1.0 psi
total AP = 3.6 psi
hp = (0.00623) (3.6) (10,000) = 224.
E. Pump Requirements
Basis
Efficiency = 0.65, AP = 30 psi.
*From thir^cIlcTOation the duct pressure drop was found to be relatively small
compared to the plate-tower pressure drop, and a constant conservative estimate
of 1-psi duct AP was used for all cases.
-------
B-28
gpm X psi X 56 156 X 30 X 1.0 . .
Horsepower = gPP .65 = 1715 X .65 = 4'2'
F. Heat Exchangers
Basis
The criteria used to estimate heat exchanger requirements are summarized in the
accompanying combined flowsheet and heat and material balance, Fig. B-6.
2. Feed Effluent Heat Exchanger
Q = UA Atm,
where
Q = heat transfer rate, Btu/hr,
U = overall heat transfer coefficient Btu/(hr) (ft2) (°F),
A = heat exchanger surface area, ft ,
= log mean temperature difference, °F.
- (100 " 77) - (212 - 193)
m ~ 100 - 77
In
212 - 193
hr
Btu/hr.
(50.0) (20.9)
3. Steam Preheater
At - (267 - 193) - (267 - 212)
m ~ 267 - 193 b4'U *
267 - 212
Q = (78,300 Ibj _ = 1>5 x 1Q6 Btu/hr.
\ hr /
Q_ = 1.5 X 10° = 2
~ UAtm (100) (64.0)
-------
99<7o VOC p.EMOVAl
VOC
QI ~
\>\OO
_^.7=-n°F
ZLiT'
"ESD- E
To, 500 \b|hr
R£ HEATER
EFFUWEUT
T-120T
/ X'.
CO-'JHtj')
W
I
Fig. B-6. Sample Flowsheet, Material Balance, and Energy Balance
-------
B-30
4. Stripper Condenser
(135 - 80) - (135 - 120)
i 135 - 80
ln 135 - 120
= 30.8°F.
2760 Ib of steam \( 1000 Btu\ _ _, v in6 Btu
- II - I = *- • /D A 1U ~ -
hr y\ Ib / hr
2'76
(100) (30.8)
G, Piping Requirements
Piping diameter basis = approx. 10-fps velocity.
80,000 Ib ft3 hr sec _ 2
Approximate cross-sectional area = - ^ - X 6Q lb X 36QO sec X 1Q ffc - O.OJ/ tt
Diameter
- 0.037 ft2 X ^^ X | =2.6 in.
(Use 3-in. sch. 40 pipe.)
H. Capital Cost Estimates
Capital costs for all components were estimated from the parameters as calculated
in the previous sections and from IT Enviroscience installed cost data expressed in
terms of these parameters. Coat data compiled from previous years were adjusted
to a December 1979 basis.
II. Annual Cost
A. Process Water
Basis^
$0.25/1000 gal
156 gal 60 min 8760 hr $0.25
Annual Cost = —^~ * — ^~ * ~£ - X iQOO gal
B. Electricity
Basis
$0.03/kWh.
Total hp required = 224 (blower) +4.2 (pump) =228.
-------
B-31
Annual cost = 228 hp X "'^ nr X 1 ^ hr, X ~f^ = $44,700/yr.
C. Wastewater Treatment
Basis
1 Ib of BOD/lb of organics in wastewater; 0.05 wt % VOC in untreated air; 99.0%
VOC removal in absorber; 99% organic removal in stripper.
Treatment cost = $25/1000 gal + $0.10 Ib/BOD.
44,500 Ib of air 8760 hr
BOD cost = '- X
hr yr AJ->
80,900 Ib gal „ 8760 hr $0.25 .
Wastewater cost = '— X 0 ., .,, X X - • • • = $21,270/yr.
nir o. o o J~D yi J.L/UU y O.JL
Total annual treatment cost = $21,270 + $190 = $21,460/yr.
D. Steam Cost
Steam Requirements
Q = We,, At = '-
p
1.48 X 106 Btu v Ib . 3
. , . v .
Steam required = - - - X 100Q Btu = 1.48 X 10 —
Stripper = 2760 Ib/hr.
Steam Preheater
Total steam requirements = 1.48 X 103 + 2.76 X 103 = 4.24 X 103 ~
i <- 4.24 X 103 Ib 8760 hr $2.50
Annual cost = - — - X — ^ - X 10QO lb = $92,900/yr.
E. Cooling Water
Basis
$0.10/1000 gal
Cooling water requirements for stripper condenser:
w = _^_ = 2.76 X 106 Btu lb_!F 1_^ =
c AT hr 1 Btu (120 - 80) °F
-------
B-32
4 lb gal 8760 hr $0.10 e-7">cr> /
Annual cost = 6.9 X 104 — X ^-^ X -^j— X 555^5; = $7260/yr.
F. Operating Labor
Basis
$15/man-hour; 25% of one operator's time required.
Annual cost = hr X X 0.25 = $32,900/yr.
III. Cost Effectiveness
Cost effectiveness is defined as the net annual cost per unit (Mg) of VOC
emissions removed.
Basis
10,000 cfm of air containing 0.05 wt % VOC; 99% VOC removal by absorber system;
$0.10/lb recovery credit for recovered VOC.
From Table A-8, the net annual cost is $495,000.
The annual VOC removed is:
44,500 "r , 0.0005 X 0.99 X ^ X ^_ - 37.7 ^
and the cost effectivenss is -Q1 ^ Mg = $5650/Mg.
-------
B-33
REFERENCES
1. Perry and Chilton, Chemical Engineers' Handbook, 5th ed., pp 14 and 15.
2. M. S. Peters, and K. D. Timmerhaus, Plant Design and Economics for Chemical
Engineers, 2d ed., p.2.
3. R. E. Treybal, Mass Transfer Operations, 2d ed., pp 131—135, McGraw-Hill,
New York, 1968.
4. J. A. Danielson, Air Pollution Engineering Manual, 2d ed., Air Pollution Control
District, County of Los Angeles.
5. T. K. Sherwood and R. L. Pigford, Absorption and Extraction , pp 135—140 McGraw-Hill,
New York, 1952.
6. Ibid., p 225.
7. Crane Co., Flow of Fluids Through Valves, Fittings, and Pipe, Technical Paper
No. 410, 1965.
-------
TECHNICAL REPORT DATA
(Please read Instructions or, the revere before completing)
EPA-45Q/3-8Q-027
4 7. , _£ AND SUBTITLE
Organic Chemical Manufacturing
Volume 5: Adsorption, Condensation, and Absorption
Devices
7 A'JTHOR(S)
H. S. Basdekis D. G. Erikson
C. S. Parmele R. L. Standifer
a PERFORMING ORGANIZATION NAME AND ADDRESS
IT Enviroscience, Inc.
9041 Executive Park Drive
Suite 226
Knoxville, Tennessee 37923
12. SPONSORING AGENCY NAME AND ADDRESS
DAA for Air Quality Planning and Standards
Office of Air, Noise, and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
December 1980
f
6. PERFORMING ORGANIZATION CODE 1
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO. j
11. CONTRACT/GRANT NO.
68-02-2577 j
13. TYPE OF REPORT AND PERIOD COVERED j
Final 1
14. SPONSORING AGENCY CODE I
!,
EPA/200/04 |
!lE SUPPLEMENTARY NOTES — -|
EPA is developing new source performance standards under Section 111 of
the Clean Air Act and national emission standards for hazardous air pollutants
under Section 112 for volatile organic compound emissions (VOC) from organic
chemical manufacturing facilities. In support of this effort, data were gathered
on chemical processing routes, VOC emissions, control techniques, control costs
and environmental impacts resulting from control. These data have been analyzed
and assimilated into the ten volumes comprising this report.
_ This volume covers the following devices that can be used to control VOC
emissions: carbon adsorbers, condensers, and absorbers.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS C. COSATI Held/Group
13B
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