EPA-450/3-74-015
          December 1973
          FACTORS AFFECTING ABILITY
                 TO RETROFIT FLUE GAS
            DESULFURIZATION SYSTEMS
532
           U.S. ENVIRONMENTAL PROTECTION AGENCY
               Office of Air and Water Programs
            Office of Air Quality Planning and Standards
           Research Triangle Park, North Carolina 27711

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                                EPA-450/3-74-015
FACTORS AFFECTING ABILITY
    TO RETROFIT FLUE GAS
 DESULFURIZATION  SYSTEMS
                   by

              Radian Corporation
            8500 Shoal Creek Boulevard
                P.O. Box 9948
              Austin, Texas 78766
            Contract Number 68-02-0046
         EPA Project Officer: Robert T . Walsh
                Prepared for

        ENVIRONMENTAL PROTECTION AGENCY
          Office of Air and Water Programs
       Office of Air Quality Planning and Standards
         Research Traingle Park, N. C.  27711

                December 1973

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This report is issued by the Environmental Protection Agency to report technical
data of interest to a limited number of readers.  Copies are available free of charge
to Federal employees, current contractors and grantees, and nonprofit organizations
as supplies permit - from  the Air Pollution Technical Information Center, Environ-
mental Protection Agency, Research Triangle Park, North Carolina 27711, or from
the National Technical Information Service, 5285 Port Royal Road,  Springfield,
Virginia 22151.
This report was furnished to the Environmental Protection Agency by
the Radian Corporation, Austin, Texas, in fulfillment of Contract No. 68-02-0046.
The contents of this report are reproduced herein as received from the Radian
Corporation. The opinions, findings,  and conclusions expressed are those of
the author and not necessarily those of the Environmental Protection Agency.
Mention of company or product names is not to be considered as an endorsement
by the Environmental Protection Agency.
                             Publication No. EPA-450/3-74-015
                                      11

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                          ABSTRACT
          The report presents results of a study of application
of flue gas desulfurization technology to steam-electric power
plants and the rate at which systems may be installed.  The
report focuses on lime and limestone but also considers magnesium
oxide and sodium based scrubbing processes.  Factors to be con-
sidered in wide-scale application of flue gas cleaning processes
include the capability and willingness of vendors to supply the
systems, time requirements, labor availability, lead time equip-
ment delivery and the availability of capital and engineering
construction services.  Ground space for equipment in proximity
to the boiler and stack was found to be a key factor.  Flue gas
desulfurization process economics and cost estimates are pre-
sented showing how major factors including equipment require-
ments, plant load factor, plant operating life, mode of solid
waste disposal and byproduct revenues affect costs.  The infor-
mation was developed for power plants in the State of Ohio but
much of it is generally applicable to U.S. installations.

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                        TABLE OF CONTENTS

                                                         Page

1.0      INTRODUCTION	1
2.0      DESIGN FACTORS AFFECTING APPLICABILITY OF
         FLUE GAS CLEANING PROCESSES TO EXISTING
         BOILERS 	  4
         2.1  Flue Gas Cleaning Space Requirements ....  5
              2.1.1  Lime/Limestone Scrubbing	6
              2.1.2  Magnesium Oxide Scrubbing 	  9
              2.1.3  Regenerable Alkali Scrubbing (e.g.,
                     Wellman-Power Gas Process)	10
         2.2  Potential Retrofit Space Available at
              Typical Existing Boilers 	 10

3.0      RETROFIT PROCESS ECONOMICS	13
         3.1  Capital Investment 	 13
         3.2  Operating Costs	18
         3.3  Annualized Costs and Present Worth of
              Flue Gas Cleaning	23

4.0      APPLICATION OF TECHNICAL AND ECONOMIC FACTORS
         TO THE OHIO BOILER POPULATION	27
         4.1  Expected Retrofit Space Availability in
              Ohio	31
         4.2  Estimated Cost of Flue Gas Cleaning for
              Existing Ohio Boilers	34

5.0      FACTORS WHICH MAY LIMIT THE RATE OF APPLICATION
         OF FLUE GAS CLEANING IN OHIO	39
         5.1  Capital Requirements 	 40
         5.2  Power Availability 	 40
         5.3  Demand and Supply of Critical Labor
              Categories in Ohio	41
         5.4  Major Equipment Supplies 	 43

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                  TABLE OF CONTENTS (Cont.)

                                                           Page

         5.5  Tie-in Requirements	   46
         5.6  Availability of Engineering and Design
              Services	   47
         5.7  Vendor Capability	   47


6.0      SUMMARY	   49


         BIBLIOGRAPHY


         APPENDIX

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1.0       INTRODUCTION

          Air pollution control regulations adopted by the
State of Ohio call for reduction of sulfur oxides emissions
in certain high priority areas of the state to 1.8 milligrams or
less SOja per Kcal heat input (1 Ib S0a/million BTU) by July 1,
1975.  Sources in second and third priority regions must reduce
emissions to 2.9 and 5.8 milligrams SOS per Kcal (1.6 and 3.2 Ib
S0@/million BTU) by the same date.  Sources in all areas of
the state must meet the 1.8 milligram SOS standard by July 1,
1978.  These emission rates correspond to a coal sulfur content
of roughly .5-.6 percent by weight.  Flue gas cleaning systems
are the primary option for meeting this emissions standard.

          Although flue gas cleaning technology is now availaole
for general use, there are several limitations on both the extent
of practical application  and the rate at which systems may be
installed.  This is particularly the case for control of exist-
ing boilers .

          This study addresses the technical and economic factors
associated with application of flue gas cleaning systems to
existing coal-fired boilers in Ohio.  The present discussion
considers lime/limestone, magnesium oxide, and sodium based
scrubbing processes.  While catalytic oxidation is also con-
sidered a commercially available S03 control process, it is
generally more applicable to new boilers than existing boilers.
Particular attention is given to lime/limestone scrubbing
systems since these are presently regarded as most technically
advanced and widely applicable.  Major technical and economic
trends illustrated in the following sections are expected to
apply to each of these flue gas cleaning methods, however.

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          In Section 2.0, a general description of each process
is given.  Since technical and operational aspects of flue gas
cleaning systems will be discussed in related reports,  emphasis
is placed on the question of process applicability.  The con-
trolling factor appears to be availability of ground space for
equipment located immediately adjacent to the boilers and stacks

          Flue gas cleaning process economics are discussed in
Section 3.0.  Cost estimates are given which show how major
factors including capital investment, operating costs,  plant
load factor and operating life, and solid waste disposal costs
affect the economic viability of lime/limestone wet scrubbing
processes.  This discussion should provide a framework for
application of more specific economic information developed by
other contractors.

          Technical and economic information developed in
Sections 2.0 and 3.0 is applied specifically to the existing
Ohio boiler population in Section 4.0.  Boiler size, age, and
load factor distribution are discussed and used to estimate
flue gas cleaning applicability.  Estimated control costs are
presented as a function of degree of required retrofit.

          Section  5.0  addresses  additional  factors which
must be considered in wide-scale application of flue gas clean-
ing processes.  Included here are such things as the capability
and willingness of vendors to supply the systems during a given
time frame,  the effects of major construction projects on labor
markets, the availability and lead time for large manufactured
items such as pumps, fans, and grinding mills, the availability
of engineering/construction services, and the availability of
capital.  Although a considerable amount of flue gas cleaning
                              -2-

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capacity should be technically and economically reasonable in
Ohio, some or all of these factors may limit the rate of applica-
tion of the processes.  Some problems faced in Ohio can be
expected to be particularly troublesome since more than 12% of
all coal-fired generating capacity in the United States is
located in Ohio .

          In the concluding section,  technical and economic
limitations on flue gas cleaning application are briefly dis-
cussed in terms of the present Ohio emissions standards and
compliance schedule.
                                -3-

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2.0       DESIGN FACTORS AFFECTING APPLICABILITY OF FLUE GAS
          CLEANING PROCESSES TO EXISTING BOILERS

          There are three general classes of design problems
associated with flue gas cleaning systems.  These are:

             Process Design

             Process Control

             Mechanical Design

The first of these involves specification of process equipment
needed to prepare raw materials,  treat a given quantity of
flue gas, remove the required amount of SOs, and dispose of
resulting solid wastes.  The process design  is primarily con-
cerned with equipment sizes and is normally  based on limiting
criteria for plant performance (for example, 100% load  using
3.5% sulfur coal).  All objectives must be accomplished with a
reasonable degree of process reliability.

          The second design problem naturally arises when
operating conditions change from those specified as a "base
case".  Power plant boilers do not operate at constant  capacity
nor do they burn a constant quality fuel over the plant life.
Some form of process control system is required to maintain
system performance under varying or unusual  conditions.  A
common control objective in limestone scrubbing, for example,
is to maintain a certain slurry pH.  This may be done by adjust-
ing the rate of limestone added to the process.  Poor S03
removal will result from too little limestone; formation of
scale on equipment surfaces can be caused by too much.
                              -4-

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          Existing boiler operating parameters will definitely
affect process design and control problems and probably the
reliability of an installation.  There are no specific conditions
other than equipment space requirements,  however,  which would
actually prevent application of the three flue gas cleaning
processes considered.  For this reason, these aspects of flue
gas cleaning application will not be discussed here.

          Mechanical design will have a significant effect on
process applicability.  Technical limitations on flue gas trans-
port (primarily heat and pressure losses  associated with long
lengths of duct) require that certain pieces of process equip-
ment be physically located adjacent to the boiler  and stack.
This may not always be practical for a given existing unit.
Space requirements for flue gas cleaning  processes are discussed
in detail below.

2.1       Flue Gas Cleaning Space Requirements

          Information on flue gas cleaning space requirements
may be developed from general process design criteria.  Com-
parison of required and existing space for a large number of
existing boilers will then indicate the degree of  retrofit
which might be reasonable from a purely technical  standpoint.
While total ground space requirements for different flue gas
cleaning processes vary somewhat, the three scrubbing methods
considered here all require essentially the same equipment in
the critical area adjacent to the boiler  and stack.  Since
other portions of the system may be located in peripheral areas,
the overall space needed is not as significant to  the retrofit
problem.  The fact that the scrubbing processes are roughly
                                -5-

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equal with respect to retrofit space requirements must be
distinguished from process applicability, however.  Many factors
not discussed here enter into process selection.
2.1.1     Lime/Limestone Scrubbing

          The basic principles of all lime/limestone scrubbing
processes are essentially the same.  An alkaline additive, lime
or limestone, is introduced to the system as a solid to form a
slurry which is used as the scrubbing liquor.  The reaction with
SOS from the flue gas takes place in the liquid phase to form
a waste product mixture of CaS03 *%HaO and CaS04'2H80 solids
which precipitate from the liquid phase.  Major process equip-
ment includes the scrubber  where contact between the flue gas
and slurry is promoted, a mist eliminator for removal of entrained
liquid from the S0s-lean gas, a hold or delay tank where addi-
tional lime/limestone dissolution and solid product precipitation
occurs, and a solids separation device to reduce the amount of
liquid waste leaving the process.  Partial reheating of the flue
gas may also be required to avoid plume "droop" and high ambient
S0a levels.  In addition to the equipment listed above, several
other items are needed.  Storage bins for the alkaline-additive
are needed.  Slurry tanks and slurry pumps are also required.
For the limestone process,  ball mills are necessary for grinding
the raw limestone to the proper mesh size.  A waste sludge han-
dling area is required for both the lime and limestone systems.
Depending on whether on-site solids disposal is planned, equip-
ment in this area could include a clarifier or thickener,  vacuum
filters or sludge fixation equipment.  Space may also be needed
for intermediate or "live" sludge storage.
                               -6-

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          Space required for the scrubbing section of this
process is the major concern for retrofit since this equipment
must be placed adjacent to the powerhouse and stack.  Process
equipment outside of the scrubber area is of less concern to
the retrofit problem since it can be located on the peripheral
areas of the plant.

          The most important parameter to consider when sizing
the scrubber area is gas velocity through the scrubber(s).
Typical gas velocities for S0a absorption in a spray tower,  for
example, are about 2.9 M/sec (9.5 ft/sec).  This may vary some-
what with the vendor and type of scrubber.  Assuming each scrubber
handles 765,000 M3/hr (450,000 ACFM),  a gas velocity of 2.9  M/sec
(9.5 ft/sec) corresponds to a scrubber cross-sectional area  of
about 74 square meters (800 square feet) or scrubber dimensions
of 6.1 meters by 12.2 meters (20 feet  by 40 feet).

          Hold tank volume depends on  the rate of sulfur-solids
precipitation required.  For a boiler  burning 3.5% sulfur coal,
a 765,000 M3/hr (450,000 ACFM) scrubber module designed to meet
the 1978 Ohio standard of 1 lb S03 emitted per million BTU heat
input would require a hold tank of approximately 15 meters (50
feet) in diameter and 17 meters (55 feet) high.  The recommended
tank size could vary considerably from vendor to vendor and  may
also change as new process information and designs are developed.
The mist eliminator size is of little  concern to ground space
requirements but may present some problems with vertical spacing.
It is usually placed above the scrubber and typically is about
twice the height of the scrubber.
                               -7-

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           As an example of the total  ground  space  requirements
 for the scrubbing section of a lime/limestone unit, consider a
550 Mw boiler with four scrubbers and four hold tanks with the
dimensions mentioned above.  The hold tanks are placed beneath
the scrubbers to conserve ground space.  If 4.6 meters (15 feet)
between the hold tanks and 2.3 meters (7.5 feet) from the hold
tanks to the pump houses are allowed and if the pump houses are
assumed to be 9.2 meters (30 feet) by 18.4 meters (60 feet),
a total ground space of 57.9 MX 39.6 M (190 ft x 130 ft) or 2295
square meters (24,700 square feet) will be required.  This can
be expressed as an area per megawatt,  giving about 4.2 square
meters/Mw (45 square feet/Mw).

          The area of the scrubbing section can be reduced by
placing the hold tanks at some peripheral area instead of be-
tween the powerhouse and the stack or by reducing their size
to fit completely under the scrubbers.  For the scrubber dimen-
sions listed above and with allowances of 4.6 (15 feet) between
scrubbers and 3 meters (10 feet) between the scrubbers and the
pump houses, a total area of about 1217 square meters (13,100
square feet) or 2.2 square meters/Mw (23.8 square feet/Mw) will
be required.

          The above estimate of scrubber area per megawatt not only
represents the space requirements for a 550 Mw plant but is
relatively independent of plant size.   It can be roughly applied
to all boilers burning coal with similar heat and sulfur content.
The ground space needed for the scrubbing section is directly
proportional to the size of the plant since scrubber cross-sectional
area design is proportional to the flue gas flow rate.

          Obviously space requirements are subject to some
variation.  The scrubber-hold tank modules may be crowded closer
together than assumed here.  This would depend upon the indivi-
dual plant situation.  Also, variations in scrubber and hold
tank designs may allow the retrofit to be made in a slightly
smaller area, again depending upon the plant characteristics.
                              -8-

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2.1.2     Magnesium Oxide Scrubbing

          This process utilizes a slurry of MgO and recycled
MgS03 and MgS04 solids as the absorbing liquor.  After being
cooled in the air preheater, flue gas enters the scrubber and
contacts the slurry.  The effluent from the scrubber is thickened
to remove fly ash, then sent to a crystallizer and centrifuge
where hydrated crystals of MgS03 and MgS04 and unreacted MgO
are separated from the mother liquor.  The liquor is recycled
to the scrubber and the centrifuged wet cake is dried in a
rotary kiln.  Dried anhydrous crystals may be sent to an off-
site plant where they are calcined to recover MgO and S08.  The
regenerated MgO is reslurried to maintain S0a sorption in the
scrubber.  The S0a gas is used for sulfuric acid or sulfur manu-
facture.  Major process equipment includes the scrubber, slurry
tank, fly ash separator, crystallizer, centrifuge, and drying
kiln.

          The major pieces of equipment which are placed in the
scrubbing area are the  S0a absorbers, MgO slurry tank, mother
liquor tank, and  flue gas ducts.  The scrubbing section will
require  essentially the same ground  space as in the lime-lime-
stone scrubbing section.  Since the  scrubber ground space
required is directly proportional to the flue gas flow rate, as
in the lime/limestone scrubbers, the area required should not
change significantly on a per megawatt basis.
                               -9-

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2.1.3     Regenerable Alkali Scrubbing (e.g., Wellman-Power Gas
          Process)

          In this process, flue gas from boilers is washed by
a prescrubber to remove the greater part of solids and S03 in
the gas.  A concentrated solution of NaaS03 and NaHS03 is used
as the scrubbing liquor.  Exiting the scrubber, the absorbent
is heated with steam to yield 9070 SOa gas and NaaS03 crystals
which are recycled.  The high purity, high concentration S0a gas
can be further processed to liquid S0a, sulfur, or HaS04.  In
Japanese installations of this process, waste water from the
prescrubber is filtered, oxidized by air and a small quantity
of H8S04, and neutralized with slaked lime before being discharged
as a 10% NaaS04 solution.  However, additional treatment may be
required for application in the United States.  Major process
equipment for this process includes the scrubber, mix tank, evap-
orator-crystallizer, and the centrifuge separator.  An acid or
sulfur plant is generally required on the site to treat the off
gas from the evaporator-crystallizer.

          The space for the scrubber section of this process
should not be different from the other two processes since the
scrubber area is again proportional to the flue gas flow rate.
2.2       Potential Retrofit Space Available at Typical
          Existing Boilers

          In order to examine the retrofit problem from a
technical viewpoint, the required space estimated in Section 2.1
must be compared to the existing space at power plants.  In
1972, the M. W. Kellogg Company reported results for a survey
of available retrofit space at 103 plants across the United
States in both urban and rural areas (KE-083).   Visits by
                              -10-

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Kellogg personnel were made to the power plants,  and available
sparp was determined from plot plans of each power station.

          In Section 2.1 it was shown that a minimum area of
2.2 square meters/Mw (24 square feet/Mw) is required for retrofit
installation of  S0a scrubbing equipment, although this number is
subject to some variation.  For the purposes of this discussion,
it is assumed that any unit with available area of less than
1.9 Ma/Mw (20 fta/Mw) can be retrofitted only with great diffi-
culty.  Using this criterion size and age distributions for
retrofittable capacity surveyed by Kellogg were calculated.
These distributions are shown in Figure 2-1.

          The overall impact of the Kellogg survey is clearly
indicated.  A high percentage of large, new boilers have suffi-
cient space for flue gas cleaning systems.   More  than 87% of
the surveyed units ten years old or less may be retrofitted.
About 85% of capacity in existing units larger than 500 Mw have
sufficient space.

          In terms of total capacity, about 70% can be
retrofitted by including only boilers less than 20 years old
or greater than 100 Mw capacity.  Since small, old units are
less likely to have space  and do not account for a significant
portion of total capacity, little additional overall control
could be gained by extending flue gas cleaning beyond these
limits.  About 74% of the total capacity surveyed had scrubber
area space equal to or greater than the estimated 1.9 Ma/Mw
(20 fta/Mw) required.
                              -11-

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              0
                            Total
                            Fraction
                                        Total
                                        Retrofit
                                        Fraction
                        £30  £20
                  Boiler Age (years)
                                           2:100 *200  *300      ^500
                                                Boiler Size (Mw)
          FIGURE  2-1 -  FRACTION OF TOTAL RETROFITTABLE CAPACITY IN U. S. VERSUS AGE AND SIZE

                        (Based on Space Requirements)

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3.0       RETROFIT PROCESS ECONOMICS

          In Section 2.0, technical factors limiting the
application of flue gas cleaning processes to existing units
were discussed.  The availability of space was shown to be
of primary importance.  In this section, the economics of flue
gas cleaning are considered.  In addition to capital investment
and annual operating costs, expected operating life and load
factor (annual power produced by a unit divided by the rated
output) for a boiler have a major impact on the overall econom-
ics of flue gas cleaning.  Economic factors discussed below,
like technical considerations shown in Section 2.0, make overall
process feasibility a strong function of boiler size and age.
3.1       Capital Investment

          Installation costs for flue gas cleaning system on
an existing boiler are dependent on three major design parameters
These are:

             unit size (essentially proportional to
             gas flow rate),

             required S08 removal rate,

             difficulty of retrofit installation.

Many capital cost estimates for flue gas cleaning processes
have appeared in the literature.  A recent detailed cost esti-
mate for a typical limestone scrubbing process was prepared for
EPA by Catalytic, Incorporated and reported in January of 1973
(CA-107).  Rochelle (RO-082) has presented recent estimated and
                               -13-

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installed capital costs for eight flue gas cleaning methods
including both regenerative and non-regenerative processes.

          For purposes of discussion,  a quantitative breakdown
of capital costs estimated by Catalytic for a  limestone scrubbing
unit is summarized below.
                            TABLE 3-1
    Typical Capital Investment for a Limestone Scrubbing Unit
          Basis
   Equipment
Classification
   I and II
     III
     IV
     V
     VI

     VII
     VIII
     IX
(Including Particulate  Removal)
 New 500 Mw Boiler,  3.5%  Sulfur  Coal
                             Total Installed  Cost
        Function            (Thousands  of  Dollars)
                                   1,522
Limestone Preparation
and Handling
Flue Gas Scrubbing System
Fans, Ducts,  and  Dampers
Flue Gas Reheat
Sludge Handling and
Disposal
Mist Elimination
Major Electrical Equipment
Miscellaneous Field Costs

  Total Installed Cost
                                    7,124
                                    2,809
                                      550
                                    6,255

                                      342
                                      451
                                    1,041

                                  $20,094
Certain portions of these system costs are sensitive to the three
major design parameters listed above.
                              -14-

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          As discussed in Section 2.0, the size of equipment in
contact with the flue gas stream is directly proportional to the
volume of gas being scrubbed.  Thus, the size of Equipment Groups
III, IV, V, and VII are proportional to the size of the boiler
being retrofitted.  Equipment in these groups accounts for 5270
of the total installed cost.  Equipment sizes in Groups I, II,
and VI are proportional to the amount of SOS  being removed.  This
is in turn dependent on the amount of sulfur in the fuel , the
size of the boiler, and the degree of control required.  These
equipment groups account for 377o of the total system cost.

          Other process equipment included in Groups VIII  and IX
may have varying relationships to the unit size and the amount of
S02 removal.

          Equipment costs are generally less than directly pro-
portional to equipment size.  That is, some savings in terms of cost
per unit size is realized in construction of larger pieces of equip-
ment.  This savings no longer applies, however, when equipment
reaches a maximum feasible unit size.  Many of the pieces of equip-
ment used in flue gas scrubbing systems are subject to such "modular"
size limitations.

          There are many factors dictating maximum sizes for equip-
ment.  Examples include difficulty in shipping and field erection
as well as technical limitations in manufacturing.  Variations in
maximum available equipment sizes complicate cost engineering and
estimating for flue gas cleaning systems.  Expected effects of unit
size and fuel sulfur content on capital investment for limestone
scrubbing are summarized in Figure 3-1.  These were estimated using
appropriate cost versus size factors for equipment groups  shown in
the previous table.  A substantial savings in capital investment
on a per kilowatt basis is seen for large plants.   The cost varia-
tions due to fuel sulfur content are substantial,  but less pronounced

                              -15-

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4-1
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100

 90

 80

 70


 60


 50



 40




 30
                  5%

                  3.5%

                  2% Sulfur Coal
                    100
                                200
500
                300


            Unit Size  - Mw

               Figure 3-1

Effect of Unit Size and Coal Sulfur Content

 on Limestone Scrubbing Capital Investment

               (Retrofit)
1000

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than the size effect since a smaller percentage of the equipment
is affected by the amount of S0a removal,.

           In  addition to  the amounts of flue gas  treated and S02
removed,  the  location and layout of existing boilers exert a
major influence on  installed capital costs.  Installed costs of
Equipment  Groups III, IV, V, and VII in the example estimate are
sensitive  to  availability of space and difficulty of installation.
These portions of the system account for approximately 50% of the
total system  capital cost.  The total system cost may thus increase
considerably  in a particularly difficult retrofit situation.

           The Catalytic, Inc. cost estimate referenced above in-
cludes a  comparison between new and retrofit installation costs
for  the same  unit design.  For the retrofit installation, in-
creased piping and  duct work combined with more complicated lay-
out  and structural  problems leads to an increased cost of six
million dollars over the original 20 million dollar estimate.
          A comparison between two recently installed limestone
 scrubbing units by  the same vendor (Babcock and Wilcox) serves as
 an additional  illustration of costs of retrofit versus new in-
 stallations.   The installed cost for Commonwealth Edison's 177 Mw
 Will County Station was 13.3 million dollars  or$75/kw.  This unit
 is regarded as a difficult retrofit on a relatively small boiler.
 A large new system  at Kansas City Power and Light's LaCygne
 Station (820 Mw) is reported to have cost 32.5 million dollars or
 $40/kw.  Using the  cost versus size dependence shown in Figure 3-1
 to compare these systems, the actual cost increase due to retrofit
 at Will County appears to have been about 23% over the installed
 cost of a similar new plant.  This compares quite well with the
 30% increase predicted by the Catalytic estimate.
                               -17-

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          The above discussions of limestone scrubbing capital
costs applies equally well to lime scrubbing since these processes
are substantially the same.  Capital investment estimates for other
processes which may be available for application in Ohio are also
given by Rochelle.  Magnesium oxide scrubbing (Chemico) and sodium
sulfite scrubbing (Wellman-Power Gas) are both regenerative pro-
cesses producing an enriched SQS stream as a by-product.  If this
off-gas were converted to sulfur, capital investment for these
processes would be comparable to that required for limestone
scrubbing for a given application.

3.2       Operating Costs

          Flue gas cleaning systems incur a number of significant
operating expenses.  Detailed operating costs will be discussed
only for the case of limestone scrubbing processes.  This method
of flue gas cleaning is most likely to be generally applicable
within the time frame necessary to satisfy Ohio's implementation
plan.  Since a considerable portion of flue gas cleaning costs
arise from fixed capital charges, operating costs for regenerative
processes such as magnesium oxide and sodium sulfite scrubbing
are in many cases quite comparable to those of limestone or lime
scrubbing.  Investment, utility, and raw material costs may be
slightly higher for the regenerative methods, but these can be
offset by credit for by-products and greatly reduced waste dispo-
sal requirements.

          Rochelle has summarized comparative economics of re-
generative and non-regenerative processes in the previously cited
paper.  These are listed below for a 500 Mw plant burning 3.5%
sulfur coal with a 60% load factor.  Waste disposal charges for
the limestone process were assumed to be $3.3/metric ton ($3/ton)
of wet sludge.  Sulfur credit for the regenerative processes was
$16.5/metric ton ($15/ton).

                               -18-

-------
          Process                         Annual Cost
                                          (Mills/kwh)

   Throwaway
     Lime Scrubbing                           2.40
     Limestone Scrubbing                      2.45
   Regenerative
     Magnesium Oxide                          2.40
     Sodium Sulfite (Wellman Power Gas)        2.65
          Operating costs for a flue gas cleaning process may be
broken down into three groups:  (1) standing plant costs such as
labor and maintenance costs, payroll and plant overhead, and
fixed charges incurred regardless of whether the plant is operat-
ing or not; (2) utility costs such as process water, electricity
and steam; and (3) chemicals and raw material costs such as lime-
stone, magnesia, caustic, and solid waste disposal costs.

          Among the standing plant costs, the cost of operating
labor can be calculated given an estimate for the number of men
per shift necessary to operate the equipment and an estimate for
labor wages in dollars per man-hour.  The cost of supervision is
taken as 157o of the operating labor cost.  According to standard
cost engineering techniques, the cost of maintenance labor and
materials can be estimated as 4% of the capital investment,
while plant supply costs are approximately 15% of the maintenance
labor and material costs (PE-059).   Payroll overhead is estimated
as 20% of the cost of operating labor and supervision, while plant
overhead is estimated as 50% of the sum of the first four standing
plant costs.  Fixed charges include depreciation, taxes, insurance,
and return on investment.  Annual fixed charges for the utility
                                -19-

-------
industry are normally about 17-19% of fixed capital investment.
If a scrubber were installed on an older existing plant and
depreciated over the remaining life of the plant, this  charge
would be considerably higher.  A summary of typical standing
plant costs is listed in Table 3-2.

          The second group of operating costs  includes  the cost
of utilities  consumed only during  process operation.  Assumed
costs for  these utilities are listed in Table 3-3.  In order to
estimate the  yearly utility cost,  it is first necessary to
establish  a utility consumption rate for each of the processes.
This was done by consulting a number of literature sources for
operating  cost breakdowns which listed utility consumption for
limestone  scrubbing processes.  The principal sources of this
type of information were GR-009, KE-063, and CA-107 .   Consumption
rates of each utility were estimated on a "per ton of coal burned"
basis since this is a good indicator of the amount of flue gas to
be treated by the scrubber.  The consumption rates may then be
multiplied by the amount of coal burned by a given boiler to cal-
culate utility costs in dollars per year.  Table 3-3 also lists
these utility consumption rates.

          The third and final group of operating costs is that of
raw materials and waste disposal.  As in utility cost estimates,
the consumption rates of raw materials have been estimated from
the literature and from Radian's own limestone scrubbing process
design experience.  In this case, however, consumption is estimated
on a "per ton of sulfur removed" basis since consumption rate is
a function of the amount of sulfur in the coal as well  as the firing
rate.  Four tons of limestone are required and 5.2 tons of solid
waste (dry basis, not including fly ash) are produced per ton of
sulfur treated.
                               -20-

-------
                                              TABLE 3-2
                            BASIS FOR ESTIMATING STANDING PLANT COSTS FOR
                                 FLUE GAS DESULFURIZATION PROCESSES
                    Cost
i
N3
Direct Operating Labor
Supervision
Maintenance Labor and Materials
Plant Supplies
Payroll Overhead
Plant 'Overhead
Fixed Charges (as a  percentage  of
  fixed  capital  investment)
    Cost  of  Capital
    Insurance
    Interim  Replacement
    Federal  Taxes
    State  and  Local  Taxes
    Depreciation (straight line
      over useful life of plant)
Abbreviation
    DOL
    Su
    ML&M
    PS
    PaO
    P10
    FC
                                                                       Basis
2 men/shift, $5/hour each
15% of DOL
4% of Fixed Capital Investment
15% of ML&M
20% of (DOL + Su)
50% of(DOL + Su + ML&M + PS)


 8%
 .25%
 .35%
 3.16%
 2.33%
 FCI/Operating Life  (years)  x  100%

-------
                           TABLE 3-3

               ESTIMATED UTILITY CONSUMPTION RATES

           AND COSTS FOR A LIMESTONE SCRUBBING PROCESS
 UTILITY

Process Water
    CONSUMPTION
     COST
541 liter/metric ton coal   $.066/1000 liters
Electricity
 65 kwh/tnetric ton coal
$6.75/1000 kwh
Clean Fuel (Oil
or Natural Gas)     152,000 Kcal/metric ton     $3.17/million Kcal
                                 coal
                              -22-

-------
          The delivered cost of limestone is a strong function
of plant location as is the cost of solid waste disposal.  These
factors are discussed in related reports prepared for EPA.  Typi-
cal costs of $5.5/metric ton ($5/ton) of limestone and $5.5/metric
ton ($5/ton) of dry sludge disposal will be assumed for purposes
of the following discussion.

3.3       Annualized Costs and Present Worth of Flue Gas Cleaning

          The cost information presented in Sections 3.1 and 3.2
may be used to illustrate several important trends in flue gas
cleaning economics.  Table 3-4 compares annualized costs of flue
gas cleaning by limestone scrubbing for three assumed cases.

          Boiler A is a small, older unit with 75 Mw capacity.
It is operated only 3500 hours per year (40% load factor) since
boilers installed before about 1950 are considerably less efficient
than newer units.  Of the total annual operating cost of 2.2 million
dollars, 86% represents fixed charges incurred whether or not the
unit is in operation.  The annual cost of sulfur removal is $570/
metric ton ($518/ton) or 8.3 mills/kwh of electricity produced.

          Boiler B is a small newer unit operated 80% of the time.
Fixed charges represent 6970 'of annual operating costs for this
unit.  The high load factor, however, reduces annual pollution
charges to $357/metric ton ($324/ton) sulfur or 4.5 mill/kwh.

          Boiler C is a large newer unit also with a relatively
high load factor of 80%.  The annual operating cost of a flue gas
scrubber on this boiler is about 10 million dollars, 6470 of which
are fixed costs.  In this case, the annual cost of sulfur oxides
control is $236/metric ton ($215/ton) sulfur or roughly 40% of
that for the small older unit.
                               -23-

-------
                                                                                         TABLE 3-4
Boiler Size (mi)
Boiler Age (years^
Annu.il Operating Hours
Annual Coal Burned (metric  tons  at  5555 cal/g)
Sultur Content (wt.7. S)
Degree oC Control (Equivalent S Content)

Limestone Scrubbing Capital Investment
  Raw Material (Limestone)
  Utilities
    Water
    Electricity
    Fuel

Labor, Maintenance, and Overhead
Sludge Disposal (Dry Basis)
Fixed Charges

              TOTAL ANNUAL COST
               $/metric  ton  Sulfur Removed
              Hllls/kwh




'K)



15
AMNUALIZED COSTS
Boiler A
75
30
3500 (40X)
127,000
3.5
0.5
$5.5 million
,273 tons/yr at $5.5/ton
68,887,000 i/yr at $.066/1000 1
9,100,000 kwh at $6.75/1000 kwh •
19,400xlO« Kcal $3.17/pilllon Kcal -

19
24



.
,818 tons/yr at $5.5/ton
.IX o£ Capital Investment - 1
$2


FOR THREE LIMESTONE SCRUBBING INSTALLATIONS
Boiler B







$84,000
4,500
61,400
61,600
547,000
109,000
,326,000
,173,500
570
8.3
75
20
7000 (807.)
218,000
3.5
0.5
$5.5 million
30.545 tons/yr at $5.S/tons -$168,000
137,774,000 */yr at $.066/1000 * - 9,100
18,200,000 kwh at $6.75/1000 kwh - 122,800
38,808x10* Kcal at $3.17Mllion Kcal- 123,200
- 547,000
39,636 tons/yr at $5.5/ton - 218,000
19,11 of Capital Investment - 1,050,000
$2.338,100
357
4.5
Boiler C
500
5
7000 (807.)
1,445,000
3.5
0.5
$26 million
173,636 tons at $5.S/tons








- $955,000
760,606,000 i/yr «c $.066/1000 I . 50,200
103,000,000 kwh at $6.75/1000 kwh - 695,000
220,500x10* Kcal at $3.17ndllion Kcal- 700,000

225,454 tons/yr at $5.5/ton
16.951 of Capital Investment



- 1,977,000
- 1,240,000
- 4,410,000
$10,027,200
236
2.9
All tonnages are metric  tons.

-------
          Actually, a realistic comparison of flue gas cleaning
costs between these three cases must consider the remaining operat-
ing life of the boilers.  If the useful life of each boiler is
assumed to be 40 years, then the sulfur removal benefits for Case
A will extend for ten additional years, those of Case B for twenty
years, and Case C for thirty-five years.
          A common method of considering the total cost of projects
extending over a long time span is to calculate the "present worth"
of the venture.  This method simply "discounts" money spent for
operation in future years by a factor which considers the time
value of money.  For example, if $10,027,200 are required to
operate Unit C in 1983, then 4.2 million dollars invested at 8%
interest in 1973 would provide for this operating expense.  The
total amount of money which, invested immediately, would finance
the life of the project is the actual "present cost11 of pollution
control.

          Present costs calculated for Boilers A, B, and C are
given in Table 3-5.  On this basis, the total cost of pollution
control on a small old boiler is more than  five times that re-
quired for a large newer boiler. A small boiler operated at a high
load over a 20-year life, however, requires a pollution control
expenditure only 2.2 times that for the large new boiler.

          The  cost penalty resulting  from a short operating life
at low load is far more significant than that  due solely to unit
size.
                               -25-

-------
                            TABLE 3-5

               PRESENT COST OF POLLUTION CONTROL


                          Boiler A      Boiler B      Boiler C

Capital Investment, $     5.5 million   5.5 million   26 million


Annual Operating Cost, $  2.17 million  2.34 million  10.03 million


Present Cost of Total
  Expenditure, $          20.05 million 28.65 million 143 million


Cost of Pollution Control
  $/metric ton sulfur     526           219           95

  Mills/kwh                 7.6           2.7          1.2
                                -26-

-------
 4.0       APPLICATION OF TECHNICAL AND ECONOMIC FACTORS
           TO THE OHIO BOILER POPULATION

           The impact of technical and economic factors governing
 retrofit of flue gas cleaning processes in Ohio may be examined
 by considering the size, age,  and load factor distribution of
 the coal-fired boiler population in Ohio.   Previous investiga-
 tors (MO-067)  have identified  twenty-six power plants which
 consumed 97% of the total coal burned for public power produc-
 tion in Ohio in 1970.  Pertinent data for these plants compiled
 from 1971 FPC reports are summarized in the Appendix.

           The age and size distributions of coal-fired generat-
 ing capacity in Ohio were calculated from these data.  This in-
 formation is summarized in Figure 4-1.  About eighty percent of
 the 1971 Ohio generating capacity is less than twenty years old.
 Eighty-five percent of the total capacity is accounted for by
 boilers of 100 megawatts or more each.

           Load factors for Ohio generating capacity were also
 estimated using 1971 F.P.C. data.  Here, load factor is defined
 as the reported annual heat input to a unit divided by its design
 annual  input.   These  results should  correspond  in most  cases  to the
 fraction of  time  (annually) during which the  units  were operated. Fig-
 ures 4-2 and 4-3  show load  factor versus age  and size respectively.

          Figure 4-2 shows that annual load factors for boilers
 less than twenty-five years old normally range from about 50%
 to 85%.  The total load factor for this group of boilers is 70%.
With the exception of two units, boilers older than twenty-five
years have load factors ranging from only 10% up to 55%.  The
average load factor for this group is around 35%.  The reason for
this marked difference in operating time between old and new units  is
                             -27-

-------
I
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00
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        4-1
        O
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1.0


 .9



 .8



 .7



 .6



 .5



 .4



 .3



 .2



' .1



  0
                        Age  (yrs)
                                          >100  >200 >300

                                                     Size
                                                                           >500
                                               FIGURE 4-1


                                  Age and Size Distributions of Total

                                       Ohio Generating  Capacity

                                       (Source -  1971 FPC Data)

-------
VO
                   gl.O

                   H  .9
                   w  .8
                   3  .7
                   CD
                   S3
                   a
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                   H
                      .6
                      .5
                      .4
                      .3
                   9  -2
                   o
                      .1

                       0
                         0
 I
10
I
                          I
I
                        40
            20           30
           Boiler Age  (yrs)
              FIGURE 4-2
LOAD FACTOR VERSUS AGE FOR OHIO BOILERS
       (Source - 1971 FPC Data)
            50

-------
PL,

S3
S3
O
g 1.0




   .9




   .8




   .7




   .6




   .5




~  .4

o
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PL,

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   .1




    0
               *••   .
            1     • I
               I       •  %

               1   *•
      0      100     200     300    400     500     600     700


                                Boiler Size  (Mw)



                                   FIGURE  4-3



                    LOAD FACTOR VERSUS SIZE  FOR OHIO BOILERS

                             (Source - 1971 FPC  Data)
                                                                  800
900

-------
that new boilers are significantly more efficient than those
constructed before about 1950.  To minimize operating costs, a
utility will use old units only during periods of peak capacity
demand.

          Figure 4-3 relates load factor and unit size for Ohio
generating capacity.  Since there is a strong correlation between
boiler age and size, boilers having low load factors are primarily
those with less than 100 Mw capacity.  However, many small
units are used extensively while many old units were not.
Boiler size is not necessarily an indicator of probable load
factor.

          The above description of Ohio coal-fired generating
capacity may be combined with the space availability data pre-
sented in Section 2.0 to estimate the applicability of  flue gas
cleaning systems for sulfur oxide control in Ohio.
4.1       Expected Retrofit Space Availability in Ohio

          Space requirements for flue gas cleaning equipment were
discussed in Section 2.0.  A minimum ground area of approximately
1.9 Ma/Mw adjacent to the boiler house and stack appears to be
required for installation of control equipment without unreason-
able engineering and construction effort.  Although space avail-
ability can be determined only by inspection of actual plant lay-
outs, the overall technical applicability of flue gas cleaning
retrofit in Ohio may be estimated.
                               -31-

-------
          The retrofit factors derived in Section 2.0 were
applied to the size and age distribution in Figure 4-2 to esti-
mate retrofit space availability for the Ohio boiler population.
The fraction of boiler capacity in a given size or age group
that could be retrofitted according to the Kellogg data was
multiplied by the fraction of total Ohio capacity which is
accounted for by the same size or age group to arrive at the
probable applicability of flue gas cleaning in Ohio.  These
results are shown in Figure 4-4.  The maximum expected applica-
bility of flue gas cleaning systems represents about 70% of total
existing 1971 Ohio capacity.  About 6070 of the total capacity
may be retrofitted if application is limited to boilers twenty
years old or less.  Application of flue gas cleaning to units
100 Mw and larger would also be practical for about 6070 of the
total 1971 Ohio generating capacity.  These applicability fac-
tors are slightly lower than those indicated in the Kellogg survey
since the Ohio boiler population includes a larger fraction of
capacity in the smaller boiler size ranges.

          It should be noted that these factors can only be
confidently applied in a statistical sense to a large sample of
coal-fired generating capacity.  Applicability of flue gas
cleaning to individual boilers or plants may be determined only
by actual inspection of the site.
                              -32-

-------
          1.0
I
u>
u>
i
       o
       cd
       IX
       «
       o

       TD
       0)
       CO
       c
cd
4-»
o
H

M-l
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c
o
•H
•u
o
cd
.9



.8



.7



.6



.5



.4



.3



.2



.1
                 <40  <30  <20  <

                    Boiler Age  (yrs)
                                             >100   >200 >300     >500

                                                   Boiler Size (Mw)
                                            FIGURE 4-4
                                  Age and Size  Distribution of

                             Retrofittable Ohio Generating Capacity

-------
4.2      Estimated Cost of Flue Gas Cleaning for Existing
         Ohio Boilers

         The economic factors outlined in Section 3.0 show that
flue gas cleaning costs are somewhat sensitive to unit size and
fuel sulfur content, and depend to a greater extent on boiler
load factor and operating life.  An overall cost for applying a
process such as limestone scrubbing in Ohio may be estimated
from information describing the size,  age, load factor,  and
retrofitability of 1971 Ohio generating capacity.   Table 4-1
summarizes such an estimate.

         For each of the boiler age groups, the expected retro-
fit capacity is shown along with the average unit size,  operating
life and load factor.  An average fuel sulfur content of 3.33
weight percent was calculated from 1971 FPC data for Ohio units.
The degree of control is equivalent to an emission of 1.8 Mg S02/
Kcal (1 Ib. S0s/million BTU) heat input (the 1978 Ohio standard).
Fuel consumption was calculated using typical boiler heat rates
and a heating value of 6110 cal/gm coal (10,000 BTU/lb coal).
Total investment, annual operating charges, and total present
cost are shown for each age group.

         The total investment cost associated with flue  gas
cleaning in Ohio is shown in Figure 4-5a as a function of the
fraction of total capacity retrofitted.  Since smaller units
require greater investment per unit capacity, the required invest-
ment increases disproportionally as small, older units are
included.   The retrofitable 70% of total capacity would require
a short term capital investment of approximately seven hundred
thirty million dollars.  Corresponding investment in terms of
total present cost of flue gas cleaning are shown in Figure 4-5b.
                              -34-

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TABLE 4-1
ESTIMATED
COSTS FOR
CONTROL OF RETROFITABLE
EXISTING
1971 OHIO GENERATING CAPACITY
Boiler Age
Group (Years)
Retrofittable
Ohio Capacity (Mw)
Number of Units
Averaee Size (Mw)
Useful Operating
Life (Years)
Annual Operating
Hours
Annual Coal Burned
(million metric tons /year
at 6110 Cal/gm)
Sulfur Content (wt 7.)
Degree of Control
(equivalent sulfur)
Sulfur Removed
(1000 metric tons /year)
Capital Investment
Average ($/kw)
Total ($ million)
Annual Costs ($ million)
Raw Material
(limestone)
Utilities
Water
Electricity
Fuel
Labor, Maintenance,
Overhead
Sludge Disposal
Fixed Charges
TOTAL ANNUAL COST
($ million)
Present Cost of
Total Expenditure
($ million)
Cost of Pollution Control
S/metric ton sulfur
Mills /kwh
0-10
6600
12
540
35
6000
15.0
3.33
.55
417
50
330
9.18

.53
6.58
7.23
24.93
11.93
55.90
116.28
1690
116
1.24
11-20
4200
25
170
25
6000
10.7
3.33
.55
298
65
273
6.56

.38
4.70
5.16
23.34
8.53
49.40
98.07
1320
117
2.07
21-30
1400
21
66
15
4725
3.2
3.33
.55
89.0
75
105
1.96

.11
1.40
1.54
10.84
2.54
21.78
40.17
449
336
4.58
                                        31-40
                                        300
                                          5
                                         60
                                          5

                                       2900

                                           .43

                                          3.33

                                           .55

                                         11.2

                                         75
                                         22


                                           .25

                                           .02
                                           .19
                                           .21

                                          2.37
                                           .32
                                          7.50
                                         10.86

                                         65.3

                                       1167
                                         15.0
 -35-

-------
c
o
•l-l
4-1
C

8
4J
CO
cu
(0
4-1
•H
a
cfl
o
800



700

600



500

400


300


200


100
         0   .1    .2   .3   .4   .5    .6    .7    .8    .9   1.0

         Fraction of Total 1971 Ohio Capacity Retrofitted


                            FIGURE 4-5a

         Total Investment Cost Versus Capacity Retrofitted
c
o
4-J
CO
O
c
cu
CO
cu
Jj
    300C-
    200C -
     100C-
            71   .2   .3   .4   .5~   ^6    T7    T8    T9   T.O

        Fraction of Total 1971 Ohio Capacity Retrofitted


                            FIGURE 4-5b

         Total Present Cost Versus Capacity Retrofitted
                                  -36-

-------
            The incremental cost trends illustrated in Figures
4-6a and 4-6b are perhaps more important with respect to the
applicability of flue gas cleaning in Ohio.   The combination of
higher unit investment costs, low load factor, and short
operating life results in a dramatic increase in "incremental"
control costs with the degree of retrofit.   Incremental costs
are those associated with adding controls to additional plants
moving from large new units to small old units.  That is, each
additional ton of sulfur removal becomes more expensive because
of the factors discussed in Section 3.0.  Since 60%'of'the Ohio
capacity is less than twenty years old or greater than 100 Mw
in unit size, the incremental present cost of flue gas cleaning
remains below two mills/kwh for these units.  As small, older
boilers are included in further retrofit capacity, incremental
control costs increase rapidly.  This cost increase would presumably
make low sulfur fuel purchases or unit shutdown more attractive
than flue gas cleaning.  While the absolute magnitude of pollution
control costs shown here are somewhat uncertain, the illustrated
trends are significant effects of relatively firm economic factors.

            Summarizing the trends shown here, both capital
investment and pollution control costs per unit of electric power
or unit of sulfur removal increase inordinately as controls are
applied beyond certain practical limitations.  The technical and
economic factors discussed in previous sections of this report
combined with the size and age distribution of Ohio generating
capacity lead to a predicted sharp increase in the cost of
pollution control beyond application to 60-70% of existing
capacity.
                              -37-

-------
4J
C
O
o

U-l
o

4-1
CO
O
o

4-1
C
CU
CO
CU
5-1
PL|
co
4-1
C
cu
S
cu
!-i
O
C
CO
•r-l
e
 13

 12

 11

 10

  9

  8

  7

  6

  5

  4

  3

  2

  1

  0
   0   .1    .2    .3    .4    .5   .6    .7   .8   .9    1.0

   Fraction of Total  1971  Ohio Capacity Retrofitted

                       FIGURE 4-6a

Incremental Cost  of Control Versus Capacity Retrofitted
4-1
C
O
o
4J  x-\
CO  h
O  3

   r-l
4J  3
C  (/)
CU
CO  C
cu  o
J-i  H

   •CO-
C
cu
 O
 C
   1000-
   900-
   800-
   700-
   600-
   500-
   400-
   300-
   200-
   100-
      oL
       0    .1   .2   .3   .4    .5    .6    .7    .8   .9   1.0

       Fraction of Total 1971 Ohio Capacity  Retrofitted

                          FIGURE 4-6b

    Incremental Cost of Control Versus Capacity Retrofitted

    •if
    Units  are U.S. short tons  (1 U.S. short ton = .909 metric tons)
                                 -38-

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5.0       FACTORS WHICH MAY LIMIT THE RATE OF APPLICATION
          OF FLUE GAS CLEANING IN OHIO

          The discussion in previous sections was primarily
concerned with the technical and economic applicability of flue
gas cleaning in Ohio.  The retrofittability of existing boilers
was estimated and expected costs for pollution control presented.
Conclusions reached from this type of information can deal only
with whether or not flue gas cleaning is a feasible control
alternative.  The information below is related to the actual rate
at which flue gas cleaning may be applied to existing and new
capacity.

          Since the factors considered here are highly uncertain,
no attempt is made to derive an implementation schedule from
them.  Rather, the intent of this section is merely to demonstrate,
using specific data where possible, which of these may become
a problem within the time frame specified by the Ohio Air Pollu-
tion Regulations.

          The first and most obvious limitation on flue gas
cleaning is normal lead time required for engineering, procure-
ment, construction, and start-up of such a large, complex unit.
This is generally acknowledged to be a minimum of 24 months from
the purchase date.  The other factors discussed below are those
which may cause this normal lead time to be extended.

          The situation may become particularly severe in Ohio
since a significant fraction (13.570) of the total U.S. sulfur
emissions from coal-fired generating capacity is accounted for
by Ohio boilers.  A high level of  flue gas cleaning investment
is thus needed.  One must also consider that expanding control
activities in neighboring states will compete for capital,
labor, vendors, and equipment.
                             -39-

-------
 5.1       Capital Requirements

            The total annual capital investment of the electric
utility industry in the State of Ohio for 1972 was $706 million
 (from Public Utility Commission of Ohio).  The estimated cost
 for retrofitting 70% of the existing 1971 boiler capacity in
Ohio as presented in Section 4.0 is $730 million.  In addition
 to retrofitting existing boilers, new plants will have to be
controlled during the same time period.  New generating capacity
is normally added at an annual rate of 7%.  These new boilers
will require control systems with an average cost of $40/kw.
This new investment in pollution control will be about $50
million/year in Ohio.   If pollution control  is applied in
Ohio from 1973 to 1975, the total investment for S0a  control
for existing and new units would be about $830,000,000.   For
a five-year period,  the total cost is about  $980,000,000.

          A pollution control investment of this magnitude
 represents an  increase in capital expenditures nearly 60% over
 that of a normal two-year period or 287o over that for a five-
year period beginning at the end of 1973.

          Some considerations need obviously be given to the
 source of such a large increase in capital expenditures.

 5.2       Power Availability

          The  installation of sulfur removal equipment dictates
 that additional electrical power be generated to run this
 equipment.  In a report by Processes Research, Inc., entitled
Flue Gas Cleaning Process Commercial Availability (PR-048), it
is estimated that 2  to 7% of the power output of the boilers fitted
with SOS removal equipment is required to run the equipment.
Most power companies do not have sufficient reserve capacity to
                               -40-

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supply this additional power.  In a report by the Sulfur Oxide
Control Technology Assessment Panel entitled Projected Utiliza-
tion of Stack Gas Cleaning Systems by Steam-Electric Plants
(SU-031), it is noted that the Federal Power Commission states
that reserves of about 20% of peak load are essential to avoid
sporadic power curtailments.  Also in this report, the actual
reserve capacity for the National Power Survey Region in which
Ohio is located (East Central) is given as 16.5% of the esti-
mated peak summer load as of June 27, 1972.   Since  excess  power
is not available in Ohio, the retrofit of  12,500 Mw capacity
(representing 70% of existing 1971 capacity) would require at
least an additional 750 Mw of new capacity  to power the retro-
fit  installations in order  to avoid power  curtailments  to  the
customers.  Assuming a cost of $250/kw for  the new capacity, as
in the Process Research report (PR-048), this would add an
additional $190 million investment for new  generating capacity
to the cost of retrofit flue gas cleaning  in Ohio.

5.3       Demand and Supply of Critical Labor Categories in
          Ohio

          Various skilled labor categories have been identified
as important to timely construction of flue gas cleaning facilities.
Boilermakers and pipe fitters are probably the most critical of
these (PR-048).  There are 2113 boilermakers in the State of
Ohio, which represents 7.16% of the United States total (1970
census).  Data on pipe fitters are not available, but it is
probable that the State of Ohio has 7% or less of the pipe fit-
ters in the United States since it has only 5.86% of the plumbers
and pipe fitters combined (1970 census).
                               -41-

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           As stated in Section 5.1, the total flue gas cleaning
capital expenditure estimated for a two-year application period
is $830 million and for a five-year program is $980 million.
As stated in the report by Processes Research, Inc. (PR-048),
pipe fitter and boilermaker man-hours per $1000 investment in
flue gas cleaning are estimated as 10.0 for retrofit and 7.5  for
new plant construction.  The total boilermaker and pipe fitter
man-hours worked in the U.S. in 1971 are also estimated as 318
million.  Using these data, the significance of labor require-
ments for widespread application of flue gas cleaning in Ohio
can be estimated.  The total pipe fitter and boilermaker man-
hours required for sulfur removal for two years of retrofit
plus new capacity is about eight million or four million man-
hours per year.

          This annual man-hour requirement for the two year
flue gas cleaning application period is about 1.3% of the
total 1971 boilermaker and pipe fitter man-hours worked for
the entire United States.  To provide the additional labor,
the boilermaker and pipe fitter labor force in Ohio would have
to increase by nearly 20%.

          If the retrofit (plus new capacity) construction
were extended over a five-year period, the total man-hours
required for sulfur removal are reduced to 1.8 million/yr.
This is less than .6% of the 1971 boilermaker and pipe fitter
man-hours worked in the United States and corresponds to a
required 8% increase in the Ohio boilermaker and pipe fitter
labor force.
                              -42-

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           In  telephone  conversations on June 12,  1972, between
 Processes  Research,  Inc.,  and  the Boilermakers and Pipe Fitters
 Unions,  the labor  situation  was  discussed.  It was found  that
 at  that  time  boilermakers  were nearly  fully employed and  unable
 to  obtain  sufficient apprentices to replace employees who
 either retire or die.   However,  some expansion can be realized
 by  retaining  men with related  skills such as welders and  iron-
 workers, although  this  is  at least a two-year program.  The
 Pipe  Fitters  Union reported  that they  could increase the  work
 force by five to ten percent through retraining men from  related
 fields such as  ironworkers,  welders, and boilermakers.  They
 pointed  out that overall labor efficiency for such an expanded
 work  force might be  lowered, however.

 5.4        Ma .lor Equipment  Supplies

           In  Section 4.0 it was  estimated that about 60 boilers
 in Ohio could be feasibly  retrofitted.  Should this massive
 retrofit be implemented, the increased demand for long-lead-time
 manufactured  items such as fans, pumps, and grinding mills may
 cause significant  construction delays.

           There are  three  major  producers of large induced-
 draft fans in the  United States  (Green Fuel Economizer Co.,
 Buffalo Forge, and Westinghouse).  Each of these companies were
 contacted  and it was estimated that if only the fans required
 for Ohio were ordered in excess  of the normal market, then these
 fans  could be available within two years.  However, flue  gas
.cleaning retrofit  probably will  take place across the entire
 United States.  In the previously cited report by Processes
 Research,  Inc., the  factors  affecting retrofit for 450 boilers
 across the Nation  were studied.  It is noted in this report
 that  all three of  the major  induced-draft fan manufacturers
                              -43-

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confirm that if the retrofit construction period for these 450
boilers is five years or more, there should be no problems in
delivering the required number of fans.  Thus, since the demand
for large induced-draft fans probably will increase across the
United States, delays in the normal two-year construction period
for S0a control processes may be expected.

           Procuring the large centrifugal pumps required for
transporting the scrubbing liquor may also present problems
causing significant construction delays.  The number of pumps
required can be estimated as follows.  Typically a boiler pro-
duces 5100 actual cubic meters per hour (3000 ACFM) of flue, .gas
per megawatt generating capacity.  For a scrubber liquid-to-gas
ratio of 8 liters/cubic meter (60 GPM/1000 ACFM) the total rate
at which scrubbing liquor must be pumped can be estimated.  In
Section 4.0 it is estimated that 70% of the existing 1971 gene-
rating capacity can be retrofitted.  This corresponds to approxi-
mately 12,400 Mw.  New capacity at a rate of 7% annually must also
be controlled, bringing the total controlled generating capacity
for 1975 to about 16,400 Mw.  This would require a total of
11,166,000 liters/minute (2,950,000 GPM) of scrubbing slurry to be
pumped.  The total for 1978 is 13,626,000 liters/minute (3,600,000
GPM).

           Three of the major manufacturers of large rubber-lined
centrifugal pumps were contacted to determine what size pumps are
available and to determine how the increase in demand for these
pumps would affect the market.  Rubber-lined pumps are generally
preferred for transport of abrasive slurries.  Denver Equipment
Company is the only manufacturer of those contacted which makes
rubber-lined pumps with a 75,700 liter/min (20,000 GPM) capacity,
although the Galigher Company is currently considering producing
this type of pump with a capacity as high as 52,990 liter/minute
(14,000 GPM).  Both Ingersoil-Rand and Galigher Company currently
                              -44-

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have the capability to manufacture rubber-lined pumps with
capacities of 26,500-30,280 liters/minute (7-8,000 GPM).  If the
retrofit operations required for Ohio were to be completed in two
years and 75,700 liters/minute (20,000 GPM) pumps were used, about
150 of these pumps would be required.  If 30,280 liters/minute
(8,000 GPM) pumps were used, approximately 370 would be needed in
the next two years.  Denver Equipment Company optimistically esti-
mates that they can manufacture about 65 rubber-lined pumps of
75,700 liters/minute (20,000 GPM) capacity in two years.  This is
only about 40% of the total required for the two-year retrofit
program.

            One of the vendors, Ingersoll-Rand, currently manu-
factures about 200 rubber-lined pumps [30,280 liters/minute (8,000
GPM capacity)] per year.  To supply only one-fourth of the pumps
required for a two-year flue gas cleaning application period in
Ohio, they would have to increase their production by about 25%.
This is only for the pumps required in Ohio.  The demand for
these pumps should increase across the United States, thus making
the production of the required number of pumps even more difficult.
These figures indicate that it would be extremely difficult to
manufacture the required number of pumps for a two-year retrofit
program.

            If the time period for retrofit operations were
extended to five years, the total required number of 75,700 liters/
minute (20,000 GPM) capacity pumps is about 180.  If 30,280 liters/
minute (8,000 GPM) capacity pumps are used, the total number re-
quired is about 450.  Vendor data indicate that there should be
no problems producing this number of pumps over a five-year
period.

            At least one other major piece of equipment, grinding
mills, requires a long lead time for manufacture.  These mills
                              -45-

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are used to grind raw limestone for the limestone wet scrubbing
process.  Two manufacturers of ball mills were contacted (Allis-
Chalmers and Denver Equipment Company).   These companies indicate
that there should be no problems in manufacturing their share of
the ball mills required over a two-year retrofit period.
 5.5       Tie-In Requirements

           Although most of the construction of retrofit sulfur
 removal equipment can be accomplished independent of boiler
 operation, some down-time will be realized for connecting the
 system to the existing equipment.  Typically,  electric power
 demands peak in the winter and summer seasons  due to the extreme
 temperatures encountered then.  Thus, any down-time for retro-
 fit operations would have to be scheduled for  the off-peak fall
 and spring months.  A typical generating plant is scheduled for
 routine maintenance at least once a year.  This usually requires
 1-3 weeks of down-time.  The Sulfur Oxide Control Technology
 Assessment Panel Report (SU-031) states that by all estimates
 this would not be a long enough period for installation of even
 a pre-assembled sulfur-oxide removal system.  This panel also
 reports, however, that once every 4-5 years, a plant is scheduled
 for maintenance requiring 5-8 weeks, which should be adequate
 time for tying in a scrubbing system if scheduling is carefully
 planned.  Thus, on the average, a maximum of 207o of the generating
 capacity could be retrofitted in one year.  This panel also states
 that due to probable increases in construction time early in the
 expansion of the S0a control industry, it is likely that less
 than 20% of the generating capacity can be retrofitted in any
 one year.
                              -46-

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5.6       Availability of Engineering and Design Services

          In a report by Catalytic, Inc., entitled Preliminary
Problem Definition SOX Control Process Utilization (JA-054),
the effect of increased demand for retrofit flue gas cleaning
over the United States on engineering and design firms was ex-
amined.  Since engineering design is independent of the location
of the actual construction, this study should be applicable  to
the retrofit situation in Ohio.

          It was estimated in this study that the projected
volume of total industrial construction for 1972 to 1975 is
$74 billion.  It was also estimated that the total installed
costs of flue gas desulfurization for the entire United States
would be four billion.  Ten percent of this total was assumed
to be for design costs and the remaining $3.6 billion for
construction costs.  It was concluded that since this $3.6 billion
was only five percent of the projected industrial construction,
it was achievable by normal construction contactor growth.

          The 10% assumed for design costs represents only a
3% increase in the business volume for 1972-1975 of the leading
design firms as reported by Catalytic, Inc.  It was concluded
that this additional growth could be realized through the normal
growth of design firms.

5.7       Vendor Capability

          The number of vendors offering large-scale flue gas
cleaning systems is limited.  The  Sulfur Oxide Control Technology
Assessment Panel Report  (SU-031)  states  that there are approxi-
mately fifteen scrubbing system vendors.  However, it also
states that there are only three  or four of these vendors with
                             -47-

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sufficient experience, manpower, and corporate backing to expand
rapidly.  Mr. George A. Jutze, President  of Pedco-Environmental,
has talked with representatives of three of the major scrubbing
system vendors (Combustion Engineering, Chemical Construction Co.,
and Cottrell Environmental Systems) about the availability of
their systems.  He reports that they feel that they only can
produce 3-5 systems/year each.  Mr. Jutze also stated that the
three vendors felt they could only have a combined total of 30
systems on line in Ohio within three years after contract award.
This represents slightly less than 50% of the existing 1971
boilers in Ohio which can be feasibly retrofitted as stated in
Section 4.0.
                              -48-

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6.0       SUMMARY

          Although flue gas cleaning technology is now available
for general use there are several limitations on both the extent
of practical application and the rate at which systems may be
installed.  The technical and operational aspects of flue gas
cleaning systems are not discussed in this report as they are
covered in related reports; therefore, this paper places the
emphasis on process applicability.  The controlling factor ap-
pears to be the availability of ground space for equipment lo-
cated immediately adjacent to the boilers and stacks.  A minimum
ground area of approximately 1.9 M^/Mw (20 ft2/Mw) adjacent to
the boiler house and stack appears to be required for installa-
tion of control equipment without unreasonable engineering and
construction effort.  Although space availability can be deter-
mined only by inspection of actual plant layouts, the overall
technical applicability of flue gas cleaning retrofit in Ohio
may be estimated.

          The retrofit factors were derived and applied to the
size and age distribution in Figure 4-2 to estimate retrofit
space availability for the Ohio boiler population.  The fraction
of boiler capacity in a given size or age group that could be
retrofitted according to the Kellogg data was multiplied by the
fraction of total Ohio capacity which is accounted for by the
same size or age group to arrive at the probable applicability
of flue gas cleaning in Ohio.  These results show that the maxi-
mum expected applicability of flue gas cleaning systems repre-
sents about 70% of existing 1971 Ohio capacity.  About 60% of the
total capacity may be retrofitted if application is limited to
boilers twenty years old or less.  Application of flue gas clean-
ing to units 100 Mw and larger would also be practical for about
60% of the total 1971 Ohio generating capacity.
                             -49-

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          The economic factors outlined in this paper show that
flue gas cleaning costs are somewhat sensitive to unit size and
fuel sulfur content and depend to a greater extent on boiler
load factor and operating life.  An overall cost for applying a
process such as limestone scrubbing in Ohio may be estimated
from information describing the size,  age, load factor,  and retro-
fittability of 1971 Ohio generating capacity.   Table 6-1 sum-
marizes such an estimate.

          For each of the boiler age groups, the expected retro-
fit capacity is shown along with the average unit size,  operating
life, and load factor.   An average fuel sulfur content of 3.33
weight percent was calculated from 1971 FPC data for Ohio units.
The degree of control used to estimate capital and operating
costs is equivalent to an emission of 1.8 mg S03/Kcal [1 Ib.
SOS/million BTU heat input or an average of 8570 removal of
S02].   Fuel consumption was calculated using typical boiler
heat rates and a heating value of 5,555 cal/gm coal (10,000 BTU!
Ib coal).  Total investment, annual operating charges, and total
present cost are shown for each age group.


          These data point out that the cost for pollution con-
trol increases rapidly for older, smaller boilers.  While the
absolute magnitude of pollution control costs here are somewhat
uncertain, the illustrated trends are significant effects of
relatively firm economic factors.

          As dicussed, there are no technical or economic fac-
tors that inhibit the application of flue gas cleaning systems
to some 60-70% of the boiler population of  Ohio.  There are  other
outside factors that will certainly affect the rate of applica-
tion of these systems in Ohio.  These factors are:
                              -50-

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   TABLE 6-1
ESTIMATED
Boiler Age
Group (Years)
Retrofittable
Ohio Capacity (Mw)
Number of Units
Average Size (Mw)
Useful Operating
Life (Years)
Annual Operating
Hours
Annual Coal Burned
(million metric tons/year
at 6110 Cal/gm)
Sulfur Content (wt %)
Degree of Control
(equivalent sulfur)
Sulfur Removed
(1000 metric tons/year)
Capital Investment
Average ($/kw)
Total ($ million)
Annual, Costs ($ million)
Raw Material
(limestone)
Utilities
Water
Electricity
Fuel
Labor , Maintenance ,
Overhead
Sludge Disposal
Fixed Charges
TOTAL ANNUAL COST
($ million)
Present Cost of
Total Expenditure
($ million)
Cost of Pollution Control
S/metric ton sulfur
Mills /kwh
COSTS FOR CONTROL OF RETROFITABLE
1971
0-10
6600
12
540
35
6000
15.0
3.33
.55
417
50
330
9.18

.53
6.58
7.23
24.93
11.93
55.90
116.28
1690
116
1.24
OHIO GENERATING CAPACITY
11-20
4200
25
170
25
6000
10.7
3.33
.55
298
65
273
6.56

.38
4.70
5.16
23.34
8.53
49.40
98.07
1320
117
2.07
EXISTING
21-30
1400
21
66
15
4725
3.2
3.33
.55
89.0
75
105
1.96

.11
1.40
1.54
10.84
2.54
21.78
40.17
449
336
4.58
                                          31-40
                                          300

                                            5
                                           60
                                            5


                                         2900


                                             .43


                                            3.33


                                             .55


                                           11.2


                                           75

                                           22




                                             .25


                                             .02

                                             .19
                                             .21



                                            2.37

                                             .32

                                            7.50

                                           10.86



                                           65.3



                                         1167

                                           15.0
-51-

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1.   Normal lead time required for engineer-
    ing, procurement, construction,  and
    startup (Generally a minumum of 24 months
    from the purchase date).   The situation
    may become particularly severe in Ohio
    since a significant fraction (13.5%)
    of the total U.S. sulfur emissions from
    coal-fired generating capacity is ac-
    counted for by Ohio boilers.   A dis-
    proportionate level of flue gas  cleaning
    investment is thus needed.   One must
    also consider that expanding control
    activities in neighboring states will
    compete for capital, labor, vendors,
    and equipment.

2.   Power availability.  Boilers fitted with
    S03 removal equipment will require 6%
    of the power output to run the control
    equipment.  Thus, the application of
    these systems will result in a decrease
    in the net power generation of the
    station.

3.   Capital requirement.  The pollution control
    investment required for retrofitting  70% of
    the existing 1971 boiler capacity repre-
    sents an increase in capital expenditures
    nearly 60% over that of a normal two-year
    period and 28% over that for a five year
    period beginning at the end of 1973.
                   -52-

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Demand and supply of critical labor
categories in Ohio.  The total pipe
fitter and boilermaker man-hours re-
quired for sulfur removal for two
years of retrofit plus new capacity
is about eight million or four million
man-hours per year.  This annual man-
hour requirement for the two year flue
gas cleaning application period is about
1.3% of the total 1971 boilermaker and
pipe fitter man-hours worked for the en-
tire United States.  To provide the
additional labor, the boilermaker and
pipe fitter labor force in Ohio would
have to increase by nearly 20%.

If the retrofit  (plus new capacity) con-
struction were extended over a five-year
period, the total man-hours required for
sulfur removal are reduced to 1.8 million/
yr.  This is less than 16% of the 1971
boilermaker and pipe fitter man-hours worked
in the United States and corresponds to a
required 8% increase in the Ohio boiler-
maker and pipe fitter labor force.

Major equipment supplies.  In this paper it
was estimated that about 60 boilers in Ohio
could be feasibly retrofitted.  Should this
massive retrofit be implemented, the in-
creased demand for long-lead-time manu-
factured items such as fans, pumps, and
grinding mills may cause significant con-
struction delays.

             -53-

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           6.   Tie-in requirements.   The Sulfur Oxide
               Control Technology Assessment Panel Report
               (SU-031) states that  1-3 weeks would not
               be a long enough period for installation
               of even a pre-assembled sulfur-oxide
               removal system.  This panel also reports,
               however, that once every 4-5 years, a plant
               is scheduled for maintenance requiring 5-8
               weeks, which should be adequate time for
               tying in a scrubbing  system if scheduling
               is carefully planned.  Thus, on the average,
               a maximum of 20% of the generating capacity
               could be retrofitted  in one year.   This
               panel also states that due to probable in-
               creases in construction time early in the
               expansion of the S02  control industry, it
               is likely that less than 20% of the generating
               capacity can be retrofitted in any one year.
           All of these data indicate that some 70% of the 1971
Ohio generating capacity can be controlled by flue gas desul-
furization and that a massive program to accomplish this in
Ohio would be difficult to accomplish by 1978.
                             -54-

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                        BIBLIOGRAPHY
CA-107     Calvin, E. L., A Process Cost Estimate for Limestone
                Slurry Scrubbing .of Flue Gas.  2 Pts, EPA-R2-73-
                K18a,b., Charlotte, N.C., Catalytic, Inc., 1973.

GR-009     Gressingh, L. E., et al., The Development of New and/
                or Improved Aqueous Processes for the Removal
                of_ S02 from Flue Gases, Final Report Vol. 1,
                Contract No. PH-86-68-77, Azusa, Ca., Aerojet-
                General Corp., Envirogenics Div., 1970.

JA-054     Jain, L. K., et al., Preliminary Problem Definition
                SO, Control Process Utilization. EPA Contract
                68-02-0241, Charlotte, N.C., Catalytic, Inc.,
                1972.

KE-063     Kellogg, (M.W.) Co., Research and Engineering Develop-
                ment Evaluation of SO?.-Control Processes, Task
                #5, Final Report, PB 204 711, Piscataway, N. J.,
                1971.

KE-083     Kellogg, (M.W.) Co., Applicability of S0a-Control
                Processes to Power Plants, EPA R2-72-100, Piscat-
                away, N. J., 1972.

MO-067     Morrison, Ray, EPA, NERC-RTP, Personal Communication,
                August 1973.

PE-059     Peters, Max S., Plant Design and Economics for Chemical
                Engineers, 2nd Edition, New York, McGraw-Hill,
                1968.
                              -55-

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PR-048     Processes Research, Inc., Industrial Planning and
                Research, Flue Gas Cleaning Process Chemical
                Availability, Final Report, Cincinnati, Ohio,
                1972.

RO-082     Rochelle, Gary T., "Economics of Flue Gas Desulfuriza-
                tion", Presented at the Flue Gas Desulfurization
                Symposium, New Orleans, Louisiana, 14-17 May
                1973.

SU-031     Sulfur Oxide Control Technology Assessment Panel
                (SOCTAP), Projected Utilization £f Stack Gas
                Cleaning Systems by Steam-Electric PIants,
                Final Report, April 1973.
                              -56-

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APPENDIX

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                                                              SOURCE:  1971 Fl'C Da I a
Power System
Cincinnati Gas and
Electric







Cleveland Electric
Illuminating Co.















Power Plant Stack
Beckjord 1
2
3
4
5
Miami Fort 1
2
3
4
Ashtabula 1-3
4
Avon Lake 1-4
5
6
7
8
East Lake 1
2
3
4
5
Lakshore 1
2
3
4
5
Existing
Generators
1
2
3
4
(I
1
(I
(I
6
1-4
5
1-5
6
7
8
9
1
2
3
4
5
14
15
16
17
18
No. of
Boilers
1
1
1
1
1
1
3
3
2
2
2
1
6
1
8
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Capacity
(Mw)
115
112
125
163
245
461
60
60
65
65
100
163
200
256
190
86
86
233
680
123
123
123
208
680
60
60
69
69
2?6
Age
21
20
19
15
':i
48
47 I
35 *
31 1
24 /
13
43
15
47
24
24
14
3
20
20
19
17
1
32
32
22
22
11
1971 T
Fuel Burned
Coal /Oil /Gag
272-491
289/113
319/584
458/811
1759/651

96/76
305/197
485/55
303
667
60
230
235
591
1782
396
325
395
655
1752*
113
131
184
201
661
Approximate
Load Factor
Coal /Oil /Gas
.48/.01
.62/<.01
.62/.01
.66/.01
•66/<.01

.17/<.01
.41/<.01
.77/<.01
.36
.63
.06
.58
.59
.64
.73
.82
.68
.82
.81
.73
.40
.46
.56
.61
,64
Co.nl
Sulfur
2.9
2.9
2.9
2.9
2.9

3.7
3.7
3.7
3.3
3.3
2.6
2.6
2.6
2.6
2.6
3.0
3.0
3.0
3.0
3.0
2.9
2.9
2.9
2.9
2.9
Tons S03
Emitted
15,026
16,004
17,662
25,347
97.264

6,650
21,142
33,589
19,000
41,812
2/184
11,380
11,632
29,177
88,019
22,569
18,450
22,501
37,333
99,860
6,214
7,228
10,115
11,074
36,427
1972 consumption
* Coal consumption in 1000 tons/year
  Oil consumption  in  1000 gallons/year
  Gas consumption  in  million  ft  /year

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                                                                                                                                          Pnp.e 2
Power System Power Plant Stack
Columbus and Southern Conesville
Ohio Electric 1
2
3
Pic way 6
7
8
9
Poston i
2
Existing
Generators
r 1
I 2
3
4
1.2
3
4
5
f 1
I 2
r 3
I 4
No. of
Boilers
1
1
1
1
1
1
1
1
1
1
1
1
Capacity
(Mw)
147
147
174
842
24
35
35
105
50
50
77
71
Age
14
16
11
0
38
28
24
18
24 1
23 J
"I
19 J
1971
Fuel Burned
Coal/Oil/Gas
[ 826
430
2457*

303

225
410
Approximate
Load Factor
Coal/Oil/Cas
.68
.60
.78

•v.,33

.48
.69
Coal
Sulfur
4
4
4

3

2
2
.5
.5
.5

.7

.1
.1
Tons SOB
Emitted
70,
36,
210,

22,

8,
16.
614
552
074

400

976
357
Dnyton Power and
Light
Walnut


Hutchings
                                                                             75
                         Stuart
                        Tait
Ohio Edison
Burger
1
2
1
3
1
2
1
2
3
4
1
2
3
4
5
(I
{I
(I
i
2


4
5
1
2
3
4
5
1
I
1
1
1
1
1
1
2
2
1
1
2
2
2
1
1
69
69
69
69
69
69
610
610
75
75
147
147
62
62
100
159
159
25 I
24 /
22 /
211
20 /
3
2
36
33
15
14
29
26
23
18
18
261//34
3467/53
289//S7


100//304
92 //23
4527/8
366/714
131
135
213
445
456
.45//<-01 1.2
.60//<-01 1.2
.54//<.01 1.2
3.5-5.0
3.5-5.0
.30//.04 1.6
.28//<-01 1.6
.81//<.01 1.6
.66//<.01 1.6
.47 3.2
.48 3.2
.47 3.2
•73 3.2
•75 3.2
5,957
7,899
6,599


3,041
2,796
13,750
11,129
7.994
8,177
12,930
27,059
27,721

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Page 3
Power System Power Plant Stack
Ohio Edison (cont.) Edgewater 2
3
Gorge 2
3
Nlles 1
2
Sa ranis
1
2
3
4
Toronto 1
2
3
4
5
7
8
12
Ohio Power Cardinal 1
2
Muskingum 1
2
3
5
Existing
Generators
2,3
4
6
7
1
2
u
c
(i
7
1-4






(i
1
2
1
2
c
5
No. of
Boilers
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Capacity
175
105
44
44
125
125
185
185
185
185
317
623
623
140






44
66
66
590
590
213
213
225
225
591
&ge_
24
16
30
25
19
19
14 -I
13 /
121
11 /
M
4 /
2
45






" 1
24
24 J
6
6
20
19
161
15 /
5
1971
Fuel Burned
Coal/Oil/Gas
105
234
109
129
313
321
850
1061
1261
710







468
1294 1 4150
1290 J
658/134
621/143
1187/298
1726/1386
Approximate
Load Factor
Coal /Oil /Gas
.13
.58
.54
.64
.63
.64
.38
.72
.37
.32







.54
.59/<.01
.59/<.01
• 70/-C.01
.66/<.01
.60/<.01
.73/<.01
Coal
Sulfur
2.9
2.9
3.5
3.5
2.8
2.8
2.7
2.7
2.7
2.7







2.4
2.9
2.9
4.9
4.9
4.9
4.9
Tons S0a
Emitted
5,779
12,914
7,261
8,584
16,665
17,059
43,610
54,422
64,676
36,408







21,352
71,319
71,119
61,242
57,845
110,477
160,707

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Power System Power Plant Stack
Ohio Power (cont.) Philo 2,3
4
5
6
Tidd 1,2
3
Ohio Valley Electric Kyger Creek
2
3
Toledo Edison Acme 16
4
Bay Shore 1
2
3
4
Existing
Generators
3
4
5
6
1
2
11
3
ft
2
c
1
2
3
4
No. of
Boilers
3
1
1
1
1
1
1
1
1
1
1
1
3
2
1
1
1
1
Capacity
(Mw)
~100
80
80
125
111
111
217
217
217
217
217
72
270
225
140
140
140
218
A£e_
44
32
31
16
28
25
18-
18
18
18
18 •
22
321
24 /
18
17
10
5
1971 Approximate
Fuel Burned Load Factor
Con 1 /Oil /Gas Coal/Oil/Ca
147 .29
294
293
226
260
318

3122

155
228
341
361
391
460
.72
.72
.42
.54
.67

.71

.46
.10
.66
.70
.83
.63
Coal
s Sulfur
3
3
3
3
3
3
3
3
3
3
3
2
2
2
2
2
2
.9
.9
.9
.9
.0
.0
.9
.9
.9
.9
.9
.6
.6
.1
.1
.1
.1
Tons S0a
Emitted
10
21
21
16
14
18

243

7
11
13
14
15
18
,858
,762
,680
,716
,848
,145

,000

.656
,360
,620
,378
,611
,339
*  1972 data.

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                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
 1. REPORT NO.
  EPA-450/3-74-015
                              2.
                                                           3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
   Factors Affecting Ability  to Retrofit Flue Gas
   Desulfurization Systems
                                                           5. REPORT DATE
                                                               8 December 1973
                                      6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
   NA
                                                           8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
   Radian Corporation
   8500 Shoal Creek Boulevard
   P.  0.  Box 9948
   Austin, Texas  78766
                                                           10. PROGRAM ELEMENT NO.
                                      11. CONTRACT/GRANT NO.
                                         No. 68-02-0046
 12. SPONSORING AGENCY NAME AND ADDRESS

   U.  S.  Environmental  Protection Agency
   Research Triangle  Park,  North Carolina
                                      13. TYPE OF REPORT AND PERIOD COVERED
                                           Final  Report	
                                      14. SPONSORING AGENCY CODE
                       27711
 15. SUPPLEMENTARY NOTES
 16. ABSTRACT
       The report presents  results of a study of  application of flue gas
  desulfurization technology to steam-electric power plants and the rate
  at which systems may  be  installed.  The report  focuses on lime and lime-
  stone but also considers  magnesium oxide and sodium based scrubbing
  processes.  Factors to  be considered in wide-scale application of flue
  gas cleaning processes  include the capability and  willingness of vendors
  to supply the systems,  time requirements, labor availability, lead time
  equipment delivery, and  the availability of capital  and engineering
  construction services.   Ground space for equipment in proximity to the
  boiler and stack was  found to be a key factor.   Flue gas desulfurization
  process economics  and cost estimates are presented showing how major
  factors including  equipment requirements, plant load factor, plant
  operating life, mode  of  solid waste disposal, and  byproduct revenues
  affect costs.  The information was developed for power plants in the
  State of Ohio but  much  of it is generally applicable to U. S. installations,
17.
                                KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
                                              b.IDENTIFIERS/OPEN ENDED TERMS
                                                    c. COSATI Field/Group
 Air Pollution
 Sulfur Dioxide
 Coal
 Sulfur
 Limestone
 Calcium Oxides
Combustion Products
Sludge Disposal
Installing
Boilers
Cost Estimates
Magnesium Oxides
Sodium Inorganic  Compounjds
Air Pollution  Control
Electric Power Plants
13B
18. DISTRIBUTION STATEMENT
        Unlimited
                                              19. SECURITY CLASS (ThisReport)
                                                  Unclassified
                                                                         21. NO. OF PAGES
                                              20. SECURITY CLASS (Thispage)
                                                  Unclassified    -
                                                                         22. PRICE
EPA Form 2220-1 (9-73)

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                                                         INSTRUCTIONS

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        To be published  in, Supersedes, Supplements, etc.

    16.  ABSTRACT
        Include a brief ^200 words  or less) factual summary of the most significant information contained in the report. If the report contains a
        significant bibliography or  literature survey, mention it here.

    17.   KEY WORDS AND DOCUMENT ANALYSIS
        (a) DESCRIPTORS - Select from the Thesaurus of Engineering and Scientific Terms the proper authorized terms that identify the major
        concept of the research and are sufficiently specific and precise to be used as index entries for cataloging.

        (b) IDENTIFIERS AND OPEN-ENDED TERMS - Use identifiers for project names, code names, equipment designators, etc. Use open-
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        jority of documents are multidisciplinary in nature, the Primary Field/Group assignment(s) will be specific discipline, area of human
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EPA Form 2220-1 (9-73) (Reverse)

-------