U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-77-071
Office of Research drd Development Laboratory e\-v^
Research Triangle Park. North C-irolma 27711 JUly 1977
HIGH-TEMPERATURE AND
HIGH-PRESSURE PARTICULATE
CONTROL REQUIREMENTS
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S.
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This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from
the effort funded under the 17-agehcy Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
environmentallycompatible manner by providing the necessary
environmental data and control technology. Investigations include
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and ecological effects; assessments of, and development of, control
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This document is available to the public through the National Technical
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EPA-600/7-77-071
July 1977
HIGH-TEMPERATURE AND
HIGH-PRESSURE PARTICULATE
CONTROL REQUIREMENTS
by
Richard Parker and Seymour Calvert
Air Pollution Technology, Inc.
4901 Morena Boulevard, Suite 402
San Diego, California 92117
Contract No. 68-02-2137
Program Element No. EHE623A
EPA Project Officer: Dennis C. Drehmel
Industrial Enironmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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ABSTRACT
High temperature and high pressure particulate cleanup
requirements of existing and proposed energy processes are
reviewed and evaluated. The intention of this study has been
to define specific high temperature and pressure particle
removal problems, indicate potential solutions, and identify
areas where current knowledge and data are inadequate.
Primary emphasis has been placed on the requirements of
processes now being proposed as clean methods for obtaining
energy from coal; that is, fluidized bed coal combustion,
coal gasification, and direct coal-fired gas turbines.
In addition, the cleanup requirements and experiences of
other high temperature and/or high pressure processes such
^as fluid bed catalytic cracking units, metallurgical furnaces,
geothermal power plants, high pressure pipelines, and magneto-
hydrodynamic power generation have been considered.
A review of current knowledge concerning turbine erosion,
corrosion, and deposition problems is also presented.
This report was submitted in partial fulfillment of
Contract No. 68-02-2137 by A.P.T.. , Inc..under the sponsorship
of the U.S. Environmental Protection Agency.
111
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TABLE OF CONTENTS
Abstract iii
List of Figures v
List of Tables vi
Acknowledgement viii
Sections
Summary and Conclusions 1
Conditions for Particulate Cleanup 2
Particulate Cleanup Requirements 4
Conclusions 7
Introduction 9
Fluidized Bed Coal Combustion Processes 12
Process Evaluation 14
Experimental Studies 19
Coal Gasification Processes 32
Fixed or Slowly Moving Bed Gasifiers 38
Dry Fluidized Bed Gasifiers 41
Ash Agglomerating Fluidized Bed 51
Slagging - Entrained Flow Gasifiers 54
Molten Bath Gasifiers 64
In-Situ Gasification 67
Direct Coal-Fired Gas Turbine Processes 70
Process Emissions and Cleanup Requirements 71
Miscellaneous High Temperature and/or High Pressure
Particulate Removal Applications 80
FCC Regenerator 81
Metallurgical Furnaces 84
MHD PoAver Generation 85
Particle Removal from High Pressure Pipelines 87
Geothermal Power Plants 89
i
Gas Turbine Particle Tolerances 91
Small Turbines for Military Use 92
Gas Turbines for Utility Use 93
Turbine Inlet Temperature 101
References 103
IV
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LIST OF FIGURES
No. Page
1 Pressurized fluidized bed boiler power plant .... 15
2 Adiabatic pressurized fluidized bed combustor in
combined-cycle power plant 16
3 Particle size distributions from Exxon batch and
miniplant fluidized bed coal combustors 20
4 Size distributions of particulate matter
collected in primary and secondary cyclones
at the Argonne bench-scale fluidized bed
combustion project 25
5 Particle size distribution penetrating the
cyclone in the PER fluidized bed combustor 30
6 Particle size distribution expected from the
Koppers-Totzek coal gasifier, before any
particle removal 57
7 Size distribution of char and ash from the BI-GAS
process effluent 60
8 Open cycle gas turbine 72
9 Closed cycle gas turbine 73
10 Particle size distributions from coal-fired
gas turbines 76
11 Fluid bed catalytic cracking unit 82
12 MHD power generation 86
13 Turbine tolerance for sodium as a function of
the concentration of chlorine and oxides of
sulfur 95
14 Particle capture efficiency for rotor blades
of a gas turbine 96
15 Particle emissions standards versus turbine
requirements for the fluidized bed combustion
of coal 100
16 Estimated industrial gas turbine inlet
temperatures 102
v
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LIST OF TABLES
No.
1 Conditions for High Temperature and Pressure
Particulate Collection
2 High Temperature and Pressure Particulate
Cleanup Requirements 5
3 Summary of FBC Particulate Cleanup Requirements. . . 13
4 Summary of Conditions for Particle Removal from
The Exxon Batch Plant and Miniplant Fluidized
Bed Coal Combustors 22
5 Summary of Conditions for Particle Removal from
the Argonne Bench-Scale Fluidized Bed Coal
Combustors 24
6 Summary of Conditions for Particle Removal from
the Combustion Power Company Fluidized
Bed Combustion Process 27
7 Classification of Coal Gasifiers 35
8 Summary of Particulate Cleanup Requirements
for Coal Gasification Processes 36
9 Raw Gas Composition for Lurgi Gasifier 39
10 Product Gas Composition for the Winkler Process. . . 42
11 Typical Gas and Char Compositions for Hydrane
Process 44
12 Gas Compositions from the Gasifier of the
Synthane Process 46
13 Gas Composition leaving the Hydrogasification
Reactor (oil free) for IGT Hygas Process 48
14 Effluent Gas Compositions from the C02
Acceptor Process 50
15 Typical Gas Composition for the U-Gas Process. ... 53
16 Typical Product Gas Composition from the
Koppers-Totzek Process 56
17 Typical Gas Compositions from the BI-GAS
Process Before and After Quenching 59
VI
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No. Page
18 Typical Gas Composition from the B.Y.U.
Entrained-Flow Gasifier 63
19 Typical Gas Composition for Kellogg Molten
Salt Gasifier 65
20 Typical Gas Composition for the Molten Iron
Gasification Process 66
21 Typical Gas Composition from In-Situ Coal
Gasification 69
22 Dust Emissions from Coal-Fired Gas Turbines 75
23 Coal, Coal Ash, and Turbine Ash Analyses 77
24 Size Distribution for Particulate Emitted from
FCC Regenerator Unit 83
25 Particle Collection Requirements for Coal-Natural
Gas Pipelines 88
26 Precipitator Design Specifications for Natural
Gas Pipelines 90
27 Size Distribution of Arizona Road Dust 92
28 Fly Ash Test Dust 98
VII
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ACKNOWLEDGEMENT
A.P.T., Inc. wishes to express its appreciation for
excellent technical coordination and for very helpful assist
ance in support of our technical effort to Dr. Leslie Sparks
of the EPA, and Dr. Dennis Drehmel, EPA Project Officer.
Vlll
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SUMMARY AND CONCLUSIONS
High temperature and high pressure (HTP) particulate clean-
up requirements of existing and proposed energy processes have
been reviewed and evaluated. The results are presented in this
final report. The intention of this study has been to:
1. define specific HTP particle removal problems,
2. indicate potential solutions, and
3. identify areas where current knowledge and data
are inadequate.
Primary emphasis has been placed on the requirements of
processes now being proposed as clean methods for obtaining
energy from coal. That is:
Fluidized Bed Coal Combustion
Coal Gasification
Direct Coal-Fired Gas Turbines
In addition, the cleanup requirements and experience of
other high temperature and/or high pressure processes, such as:
fluid bed catalytic cracking units,
metallurgical furnaces,
geothermal power plants,
high pressure pipelines, and
magnetohydrodynamic power generation
have been considered.
Fluidized bed coal combustion, coal gasification, and
direct coal-fired gas turbine processes all have been proposed
for use with industrial gas turbines. Particulate collection
is required at HTP to protect the turbine blades from excessive
wear. Temperature and pressure losses through the particle
collection equipment must be minimized to maintain a high tur-
bine efficiency. In all cases the particulate emissions from
the turbine must satisfy the applicable emissions standards.
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CONDITIONS FOR PARTICIPATE CLEANUP
The conditions for HTP particle collection are summarized
in Table 1. Temperatures range up to 1,100°C (2,000°F) and
could go higher as industrial gas turbine inlet temperatures
increase. Current maximum turbine inlet temperatures are near
1,200°C.
Fluidized bed coal combustion temperatures are typically
about 85Q°C. This temperature optimizes the removal of s^ulfur
in the fluidized bed and reduces the formation of nitrogen
oxides. Because this combustion temperature is relatively low
and because gas turbine efficiencies increase in proportion to
the turbine inlet temperature, temperature losses in the par-
ticulate collection equipment are very costly.
This problem is less important in coal gasification pro-
cesses because the gas releases heat when it is burnt prior to
entering the turbine. In this case, air injection is often re-
quired to reduce the gas temperature to the required turbine
inlet temperature.
Table 1 indicates that particle collection may be required
at pressures anywhere from near atmospheric to about 70 atm.
The most extreme pressures are encountered when pipeline qual-
ity gas is produced. It is generally more economical to operate
the gasification process at or above pipeline pressure (50 - 70
atm) than to compress the gas after it has been produced. When
pipeline pressures are not required, the processes normally are
not pressurized above about 20 atm; a pressure of 10 atm is
common. Particle collection is required at system pressure.
High pressure systems have the advantage that they are not as
sensitive to pressure drop across the collection equipment as
low pressure systems.
Gas and particle compositions are also shown in Table 1.
The gases are generally the products of combustion (N2, C02)
or of gasification (Ha, CO, COa). Moisture may be present from
a few percent up to as much as 20% (by volume). In the coal
gasification process, the product gas may be predominantly
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Table 1. CONDITIONS FOR HIGH TEMPERATURE AND PRESSURE PARTICULATE COLLECTION
PROCESS
TEMPERATURE
°C
PRESSURE
atm
TYPICAL GAS COMPOSITION
mol %
EXPECTED
PARTICULATE
COMPOSITION
O-l
Open cycle
coal-fired
gas turbine
Fluidized
bed coal
combustion
Coal gasifi-
cation
02 blown
Air blown
FCC regener-
ator
Metallurgical
furnaces
MHD power
generation
650-1,000
800-900
150-1,100
300-800
250-1,000
300-800
4-10
-1-20
1-70
83% N2 , 15% C02 , 2% 02,H20,
SOX , NOX, CO, and gaseous
hydrocarbons
801 N2 , 10% C02 , 6% 02 ,
4% H20, + S02 , NO, CO
30% H2, 25% CO, 15% C02,
20% H20, 3% CH,, , H2S, N2
50% N2 , 12% H2, 20% CO,
10% H20, 6% C02, + CHu,
H2S
681 N2, 5% CO, 3% 02,
8% C02, 16% H20, + NOX,
SOX, NH3, HCN, aldehydes,
hydrocarbons
N2, C02, 02
coal ash, unburnt
carbon
60 wt % ash, 30%
unburnt carbon,
10% sorbent
ash, unburnt
carbon, sorbent,
possibly tar
catalyst dust
depends on cata-
lyst type, commonly
silica and alumina
very fine metal
fume
K2C03 seed par-
ticles
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methane (after shift conversion and methanation), however par-
ticle removal would occur downstream of the gasifier and before
shifting. The gases at this stage of the process are the gasi-
fication products listed in Table 1.
Particulate composition depends on the process. For coal
processes, ash (principally silica, alumina, and iron oxide),
and unburnt carbon are usually present. Sorbent material (such
as limestone) used for sulfur removal during combustion or gas-
ification may also be present. Some of the lower temperature
gasification processes may also produce tar particles. Tar
particles are difficult to handle and can cause plugging prob-
lems in cyclone collectors. Wet scrubbers have been used suc-
cessfully for controlling tar emissions.
PARTICULATE CLEANUP REQUIREMENTS
The degree to which particles must be removed from HTP
processes depends on the application. Typical HTP particulate
cleanup requirements are presented in Table 2. In any case,
the final emissions to the atmosphere must satisfy all appli-
cable emissions standards. If necessary, this could be accom-
plished using conventional control equipment downstream from
the HTP process.
A potentially more stringent requirement is imposed on the
particle collection equipment when the cleaned gas is to be
passed through a gas turbine. A gas containing dust particles
can severely erode and corrode turbine blades and other internal
components. Also, deposition of dust particles on the turbine
blades can impair the aerodynamic performance of the turbine.
A large number of research investigations have been re-
ported which deal with turbine blade erosion and deposition
problems. Much of this work was done in connection with mili-
tary gas turbines for helicopter and ground tracked-vehicle
engines. Similar research has also been conducted with indus-
trial gas turbines. It is generally believed that large par-
ticles (over 2-5 ym diameter) cause severe erosion damage and
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Table 2. HIGH TEMPERATURE AND PRESSURE PARTICULATE CLEANUP REQUIREMENTS
PROCESS
Open cycle coal-fired
gas turbine ,
Pressurized fluidized
bed coal combustion,
and
Combined cycle low-BTU
coal gasification
High BTU coal
gasification
FCC catalyst
regenerator
Metallurgical furnaces
(in general)
Steel electric arc
furnaces
ALLOWABLE PARTICULATE LOADING
S.I. UNITS
2. 3 mg/m3
>2 ym
43 mg/MJ
<2 ym
4. 6 mg/m3
0.001 gram
of partic-
ulate per
gram of
coke
burnt off
50.4 mg/m3
11.9 mg/m3
ENGLISH UNITS
0.001 gr/SCF
>2 ym
0.1 lb/106BTU*
<2 ym
0.002 gr/SCF
0.001 Ib partic-
ulate per Ib
coke burnt off
0.022 gr/SCF
0.0052 gr/SCF
DETERMINING
FACTOR
Turbine
wear
Emissions
Pipeline
quality
Emissions
Emissions
Emissions
CONTROL DEVICE
USED OR PROPOSED
Cyclones, followed
by filters; hot
electrostatic pre-
cipitators, or gran-
ular bed filters
Cyclones followed
by high efficiency
scrubbers
Electrostatic pre-
cipitators, bag-
houses, scrubbers,
granular bed filters
Electrostatic pre-
cipitators, high
efficiency scrubbers,
and baghouses
*Current new source performance standards are 0.1 lb/106BTU, however a stricter standard
of 0.05 lb/106BTU has been proposed.
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must be removed. Particles under 1 - 2 ym diameter cause
much less erosion damage. However, there is a scarcity of
data concerning the tolerance of turbines for fine particles.
From the available data on turbine tolerances for partic-
ulate matter, it appears that effectively all particles larger
than about 2 ym must be removed from the gas. Fine particles
(<2 ym) must be removed sufficiently to satisfy the emissions
regulations.
When pipeline quality gas is the product the particulate
matter must be removed at high pressure and moderate tempera-
ture to provide a clean fuel for burning and to protect the
compressors used during pipeline transport.
The principal control devices used or proposed for HTP
particle cleanup are listed in Table 2. If the gas is not in-
tended for gas turbine use, high efficiency scrubbers are com-
monly used. They can serve the dual function of cooling the
gas, and removing the particulate matter. They also can con-
dense out pollutants which existed in the vapor state at high
temperature.
Usually all fine particle control equipment (scrubbers,
baghouses, electrostatic precipitators, and others) are pre-
ceded by a series of cyclone collectors. The principal purpose
of the cyclones is to reduce the particulate loading on subse-
quent collection equipment. The cyclones efficiently remove
large particles (greater than about 10 or 20 ym), and often
recycle them through the combustor or gasifier. This makes
more efficient use of the carbon contained in the feed coal,
but increases the loading of fine particles emitted from the
process.
Conventional scrubbers are not suitable for HTP particle
collection when the gas is to be expanded through a turbine
because they cool the gas being cleaned. High temperature
granu-lar bed filters, baghouses, and electrostatic precipita-
tors have been proposed for the final cleaning stage, but none
have been proven to have a sufficient collection efficiency to
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meet the turbine requirements. Development work is under way
with these devices.
Particle collection at HTP is much more difficult than at
standard conditions and the turbine may impose more stringent
requirements than normally encountered. Therefore it is pos-
sible that two stages of fine particle collection will be re-
quired. Demonstration of fine particle collection equipment
operating at HTP is lacking and is needed.
CONCLUSIONS
Particulate cleanup requirements for HTP processes vary
depending on the intended use of the gas. If it is to be vented
(as with the effluent from a secondary metals recovery furnace)
then the gas can be cooled and must be cleaned sufficiently to
meet the emissions standards. This can be done satisfactorily
with high efficiency scrubbers at the penalty of high energy
consumption.
If the gas is to be converted to a pipeline quality gas,
very efficient particle collection is required. However, final
temperatures are relatively low and scrubbers may be used.
The most difficult situation is where the hot gas is to be
expanded through a gas turbine. Very efficient collection is
required by the turbine, and it is desirable to do this at sys-
tem temperature and pressure.
The particle collection requirements for pressurized,
fluidized coal combustion and for low-BTU coal gasification
processes are very similar. They are primarily determined by
the gas turbine requirements and the emissions standards. The
conditions for particle collection, however, have some impor-
tant differences.
Gasifier exit temperatures can range from 150°C to over
1,100°C depending on the specific process. The low temperature
presents problems with tar emissions, but allows the use of
conventional control equipment (operating at system pressure).
The high temperatures present severe materials problems, as
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well as making particle collection more difficult (because the
gas is more viscous at high temperature). Temperature losses
in the collection equipment are not critical because the gas is
to be burnt (generating heat) before it passes into the turbine,
Hot gas cleanup, however, could be more economical. Corrosion
may be more of a problem with gasification than with combustion
because of the reducing atmosphere in the gasifier.
Pressurized fluidized bed coal combustion temperatures are
typically about 850°C. This is less severe than the maximum
gasifier temperature, however temperature losses during par-
ticle collection are critical and therefore scrubbers are not
suitable.
HTP particle collection devices need to be tested to de-
termine their collection efficiency and the cost to achieve a
given degree of particle removal.
Particle size distributions and mass loadings at HTP con-
ditions need to be measured for all processes for which HTP
particle collection is being considered. This information is
necessary in order to define the HTP cleanup requirements (i.e.,
the required collection efficiencies) and is essential in de-
veloping and evaluating collection equipment for specific pro-
cesses .
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INTRODUCTION
The commercial development of advanced energy processes,
such as pressurized fluidized bed coal combustion, and low-BTU
coal gasification, is hindered by the problem of removing dust
from hot, pressurized gases. In many cases the gas is to be
expanded from high temperature and pressure through a gas tur-
bine. Any temperature or pressure losses during the dust col-
lection stage will reduce the overall thermodynamic efficiency
of the process. Therefore it is desirable to clean the gas at
system pressure and at a temperature no lower than the desired
turbine inlet temperature.
Many industrial process effluent gas streams are at high
temperature and atmospheric pressure. Ordinarily it is econom-
ical to recover the sensible heat of the gas in a waste heat
boiler which can generate process heat, power, or steam. The
waste heat boiler cools the gas to a temperature just above
the dew point of any condensible vapors in the gas.
In some situations there is not sufficient need for pro-
cess heat or power to justify the expense of a waste heat
boiler. However, conventional dust cleaning equipment is
limited to relatively low temperatures and therefore the hot
effluent gas must be quenched before it is cleaned. If suit-
able high temperature particle collection equipment were avail-
able, it would be possible to clean the gas at high temperature
and exhaust it to the atmosphere, thereby saving the expense
of gas cooling.
There are also processes where high pressure and low tem-
perature particle collection is desirable. One example is the
production of pipeline quality gas from the gasification of
coal and subsequent methanation of the resulting coal gas. In
many proposed processes the gas is cooled and cleaned at low
temperature before being methanated and added to the supply of
pipeline gas. The whole process, including gas cleaning, is
9
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carried out at pipeline pressure. High pressure particle col-
lection has also been a problem in removing entrained particles
from natural gas pipelines.
High temperature and high pressure (HTP) particle collec-
tion is much more difficult than the collection of the same
particles would be at relatively low temperatures and pressures
(see Calvert and Parker, 1976). There is not only a severe
materials problem, but also the gas properties (especially vis-
cosity) at high temperature and pressure make the separation
of suspended solids from gases much more difficult.
Equipment for HTP particle collection has been under de-
velopment for more than thirty years but no generally satis-
factory solution to the problem has yet been proven. Some of
the earliest, efforts were in connection with the development
of a coal-fired gas turbine for locomotive use. Work was con-
ducted in the U.S.A. by the Locomotive Development Committee
of Bituminous Coal Research, Inc., between about 1945 and 1955,
and by the U.S. Bureau of Mines in the 1960s. Parallel devel-
opment programs were going on in Australia, Canada, and Great
Britain. Particle collection at HTP was needed to prevent ex-
cessive erosion of the turbine blades. High efficiency cyclones,
electrostatic precipitators, and filtration systems were tried
without success. Some variations in turbine blading reduced
erosion, but efficiency fell off so badly as to make the ap-
proach impractical.
Most current interest in HTP particle collection is in
relation to pressurized fluidized bed coal combustion and low-
BTU coal gasification. It has been proposed that these pro-
cesses be used in a combined cycle gas turbine/steam turbine
power generation system (Robson and Giramonti, 1972), where
HTP particle cleanup is required to protect the gas turbine
components. Also it is necessary that the processes meet all
federal and local standards that are imposed for particulate
emissions.
This report contains the results of a literature survey
10
-------
summarizing the HTP particle removal requirements of past, pres-
ent, and future energy processes. The information presented
here was obtained from published literature, government reports,
and personal communications with current researchers. Some
information was not available because it is proprietary, and
some information concerning the particulate emissions from the
processes is as yet unknown.
The particulate removal requirements for each process are
discussed in detail. Because the requirements are strongly
dependent on the particulate tolerance of gas turbines, a sepa-
rate section is presented which discusses current knowledge of
turbine erosion, corrosion, and deposition problems.
11
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FLUIDIZED BED COAL COMBUSTION PROCESSES
The fluidized bed combustion (FBC) of coal is a relatively
new combustion technique being developed in the U.S. to burn
sulfur-containing coals with an acceptably small emission of
sulfur oxides. Sulfur oxides are controlled by using limestone
or dolomite as a bed component. High heat transfer coefficients
between the fluidized bed and immersed steam generation surfaces
reduce the surface area requirements and also permit operation
at lower and more uniform bed temperatures (800-900°C). The
lower temperatures help to reduce nitrogen oxide emissions and
decrease steam tube corrosion. Lower grade coals can also be
burned because the bed temperatures are lower than their ash
slagging temperatures. Particulate emissions from the fluid-
ized bed must be controlled before the effluent gas is vented
or used in a power recovery turbine.
Fluidized bed combustors have been operated at atmospheric
pressure and at pressures as high as 10 atm. The pressurized
FBC processes are being designed for use in combined cycle power
plants, where high temperature and pressure particle removal will
be required to protect the turbine components. The atmospheric
FBC process has been developed to compete with conventional
boilers. High temperature particle removal is not necessarily
required for atmospheric systems.
Combustion temperatures in fluidized beds are much lower
than in conventional boilers because of the larger heat transfer
coefficients that may be obtained. Combustion temperatures can
range anywhere from 400°C to over 1,000°C. However, most FBC
processes operate near 850 - 900°C, in order to optimize sulfur
oxide removal in the fluidized bed.
Table 3 gives a summary of conditions after the secondary
cyclone for the major FBC systems under development. Each of
these systems will be discussed in more detail below.
12
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Table 3. SUMMARY OF FBC PARTICULATE CLEANUP REQUIREMENTS
Temperature, °C
Pressure, atm
Mass loading, g/Nm3
Mass loading, gr/SCF
Mass median diameter, ym
Geometric standard deviation
EXXON
820-950
5-10
1.8-2.8
0.8-1.2
4-8
2.7
ARGONNE
790-900
to 8
0.5-4.8
0.2-2.1
CPA*
760-980
3-7
0.09
0.04
1.2
1.9
NCB
750-950
1-5
3.0
1.4
PER
300-400
1
.2-1.7
.5-4
4.6
2
*waste-fired combustor
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PROCESS EVALUATION
Westinghouse Research Laboratories
The fluidized bed combustion process has been evaluated by
Westinghouse Research Laboratories and reported by Archer et al.
(1971) and Keairns et al. (1973, 1975) in a number of reports for
the EPA. Of all the systems studied, the pressurized FBC boiler
operating in a combined cycle (gas turbine/steam turbine) power
plant appeared to be the most effective process for satisfying
projected standards for sulfur oxide, nitrogen oxide, and par-
ticulate emissions. It also appears to be the most economical
process for electric power generation.
The pressurized fluidized bed boiler system is illustrated
in Figure 1. Compressed air is supplied at from 10% to 100%
excess air. Steam is generated in the fluidized bed. The hot
gas leaves the bed at high pressure and is expanded through a
gas turbine, passed through a heat recovery unit (boiler feed-
water preheat), and exhausted out the stack. Approximately 821
of the power is generated in the steam cycle, before any col-
lection equipment, and only 181 is generated in the gas turbine.
Keairns et al. (1975) report that cooling the gas and scrubbing
it at high pressure before the gas turbine might be economical
in this system under certain conditions, however it would not
be as economical as hot gas cleanup.
One alternative pressurized FBC system is the adiabatic
FBC system. This system is illustrated in Figure 2. The hot,
high pressure gases from the combustor are cleaned and passed
through a gas turbine where they are expanded to atmospheric
pressure. The hot gas leaving the gas turbine is passed through
a heat recovery boiler'to generate steam for one steam turbine.
High temperature and pressure particle removal is required to
clean the gas prior to passing it through the gas turbine. As
with the pressurized fluidized bed boiler system, it is econ-
omically desirable to clean the gas with a minimum loss of
temperature and pressure. However the adiabatic system is
14
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COMPRESSOR
GAS TURBINE
TERTIARY
COLLECTOR
SECONDARY
CYCLONE
FLUIDIZED
BED
BOILER
COAL AND
SORBENT
FEED
PRIMARY
CYCLONE
TO STEAM TURBINE
(82% OF POWER GENERATION)
:
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COMPRESSOR
COAL AND
SORBENT
FEED
GAS TURBINE
TERTIARY
COLLECTOR
(SECONDARY
CYCLONE
701 OF POWER
GENERATED
(3
PRIMARY
CYCLONE
J
-t>TO STACK
TO STEAM TURBINE
(~30% OF POWER
GENERATED)
WATER
HEAT
RECOVERY
BOILER
SOLIDS
RECYCLE
SPENT
SORBENT
Figure 2. Adiahatic pressurized fluidized bed
cycle power plant. From Keairns et
combustor in
al. (1975)
combined-
-------
more sensitive to temperature and pressure losses during par-
ticle removal because all power generation occurs downstream
of the particulate control equipment. High excess air (300 -
3601) is required with the adiabatic system to prevent over-
heating.
A third system reported by Westinghouse is the indirect
air cooled FBC system. This system maintains the bed tempera-
ture by passing excess air under pressure through an air cooled
heat exchanger in the bed. Approximately 70% of the air is
used in this manner and is later combined with the cleaned com-
bustion gas. The cycle performance will be somewhat lower than
the adiabatic system (depending on the efficiency of heat trans-
fer) . The advantage is that a smaller volume of gas needs to
be cleaned.
The Westinghouse design for the HTP particle collection
system in these cases consists of two stages of cyclones fol-
lowed by a tertiary collector. The primary cyclone would col-
lect large particles (including much of the unburnt carbon)
and recycle them to the fluidized bed. The secondary cyclone
would remove finer particles to reduce the dust loading to the
tertiary collector.
The tertiary collector would be an HTP granular bed filter,
ceramic fiber filter, or other high efficiency collection device.
It should be capable of collecting substantially all particles
greater than 2 ym, and should reduce the total mass loading to
within the anticipated EPA emissions regulations. This would
be roughly equivalent to a mass loading of 0.12 g/Nm3 (0.05 gr/
SCF) based on current regulations.
The flue gas composition at the high temperature and pres-
sure cleanup location would be predominantly nitrogen (80+%),
carbon dioxide (10-151), and oxygen. Westinghouse (Keairns et
al., 1975) has made an evaluation of an oxygen-blown atmospheric
pressure fluidized bed boiler and concluded that the high cost
of oxygen makes the process uneconomical for steam or power gen-
eration.
17
-------
The particulate loading leaving the pressurized fluidized
bed boiler is expected to be on the order of 16 g/Nm3 (7 gr/SCF)
The particulate matter should consist of about 60% ash, 30% un-
burnt carbon, and 10% sorbent, such as dolomite (CaC03-MgCOs)
or limestone (CaC03). The ash composition depends on the spe-
cific coal being burnt. A typical coal ash would contain mostly
silica, alumina, and ferric oxide, possibly with smaller amounts
of calcium oxide, magnesium oxide, titanium oxide, alkalies
(Na20, K20), and phosphorus pentoxide.
The particulate removal requirements will depend on the
concentration of particulate at the collection device, and on
the amount of excess air added to the system. Because of the
high excess air, the adiabatic system will have a significantly
lower concentration of particulate in the combustion gas. The
air cooled system will have a relatively large mass loading to
the collection equipment, but subsequent dilution with the ex-
cess air will reduce the loading to the turbine and environ-
ment. Thus the required particle removal efficiency will be
less stringent than with the pressurized FBC boiler system.
The particulate removal requirement for all FBC systems
will depend on the requirements of the gas turbine and the
source emissions standards. The turbine requirements are not
well established, but it is anticipated that dust loadings of
particles larger than 2 ym must be reduced below 2.7 mg/Nm3
(0.0012 gr/SCF) for satisfactory turbine life (Robson, 1976).
Larger dust loadings of fine particles (<2 ym) of the order
of 0.34 g/Nm3 (0.15 gr/SCF) may be acceptable for the turbine
(Westinghouse, 1974). The turbine requirements also depend
on gas and particle composition and on whether the concern is
for erosion or corrosion.
Particulate emissions from fluidized bed boilers also
will have to satisfy the Federal New Source Performance Stan-
dards for coal-fired boilers. This standard is currently at
43 mg/MJ (0.1 lb/106BTU). In the future, however, it will
probably be necessary to have more stringent standards in order
18
-------
to meet and maintain Ambient Air Quality Standards while not
severely restraining economic growth capacity. Therefore new
FBC systems should be developed with the capability of satisfy-
ing more stringent standards than currently are required. A
standard of 21 mg/MJ (0.05 lb/106BTU) has been suggested as
an anticipated future emissions standard.
The Westinghouse studies are primarily theoretical pre-
dictions based on anticipated emissions and design criteria.
There are not many data available to quantify the particulate
emissions from fluidized bed combustion processes. One reason
for this lack of data is that the FBC process is still in the
development stage. What data are available are for specific
test situations and are not necessarily representative of FBC
processes optimized for commercial applications. Also, HTP
sampling for particulate emissions is very difficult and ex-
pensive.
EXPERIMENTAL STUDIES
Exxon Research and Engineering Company
Fluidized bed combustion research is being conducted by
Exxon Research and Engineering Company. This work has been
reported by Nutkis (1975), Hoke (1975), Hoke et al. (1974,
1976), and in many previous reports to the U.S. EPA. Exxon
is working with a small, batch-fluidized bed pilot unit and
a larger, continuous pilot unit (miniplant) which operates at
flows up to about 25 Nm3/min (900 SCFM).
The miniplant is being used to study a regenerative lime-
stone process for the combustion and desulfurization of coal.
They also have taken a leading role in obtaining data to char-
acterize the particulate emissions from pressurized FBC pro-
cesses.
Representative size distributions of the particulate
matter emitted from the batch plant and miniplant are pre-
sented in Figure 3. Particulate leaving the secondary cyclone
19
-------
100
PRIMARY CYCLONE EXIT
SECONDARY CYCLONE EXIT
PRIMARY CYCLONE EXIT
SECONDARY CYCLONE EXIT
BATCH PLANT
MINIPLANT
30 40 50 60 70
WEIGHT % UNDERSIZE
Figure 3. Particle size distributions from Exxon batch and
miniplant fluidized bed coal combustors. From
Monthly Report #77, July 1976.
20
-------
at the miniplant has a mass median diameter (MMD) of 8 ym and
a geometric standard deviation (a ) of 2.7. Data for the batch
o
plant were obtained by microscopy, while data for the miniplant
were obtained by sieve and Coulter Counter analyses. Gas con-
ditions and particulate loading data are presented in Table 4.
The miniplant loading is much larger because the solids col-
lected in the primary cyclone are recycled to the combustor.
In the Exxon miniplant the current and proposed standards
for particulate emissions (0.1 and 0.05 lb/106BTU) correspond
to dust loadings of approximately 0.1 and 0.05 g/Nm3 (0.05 and
0.025 gr/SCF). Recent particulate emissions from the second
cyclone have been consistently in the range 1.8 to 2.8 g/Nm3
(0.8 - 1.2 gr/SCF) with mass median diameters from 4 to 7 ym
(Hoke, 1977). Therefore it can be seen that the cyclones will
not reduce the particle concentration sufficiently, and a
third stage, or tertiary cleanup, device is required.
Exxon is currently testing a Ducon granular bed filter
for this application. Preliminary experience indicates that
cleaning of the bed will be a very difficult problem. The
granular bed filter system has been redesigned to avoid the
problem of plugging the gas inlet screens. The particulate
matter appears to be very sticky (although dry) and agglomer-
ates easily. Because of the relatively low combustion temper-
atures, the particulate is most likely not formed by conden-
sation (fume). Exxon has estimated that the effective density
is 1.5 g/cm3 and has observed that the particles are not porous
but are irregular in shape.
Low temperature tests with the Ducon filter are currently
under way and high temperature and pressure tests are planned
for the near future. Exxon will also be testing a ceramic bag
filter and a high temperature and pressure electrostatic pre-
cipitator as possible tertiary collection devices.
21
-------
Table 4. SUMMARY OF CONDITIONS FOR PARTICLE REMOVAL
FROM THE EXXON BATCH PLANT AND MINIPLANT
FLUIDIZED BED COAL COMBUSTORS1
Temperature Range: 820 to 950°C
Pressure Range: 5 to 10 atm
Dust Loading: Batch Plant
Leaving Combustor2; 14 to 18 g/Nm3 (6 to 8 gr/SCF)
Leaving Primary Cyclone2; 0.9 to 2.3 g/Nm3
(0.4 to 1.0 gr/SCF)
Leaving Secondary Cyclone2; 0.2 to 1.4 g/Nm3
(0.1 to 0.6 gr/SCF)
Dust Loading: Miniplant (with solids recycle)
Leaving Combustor3; 70 to 700 g/Nm3 (30 to 300 gr/SCF)
Leaving Primary Cyclone3; 9 to 23 g/Nm3
(4 to 10 gr/SCF)
Leaving Secondary Cyclone2; 0.9 to 4.6 g/Nm3
(0.4 to 2 gr/SCF)
Composition of Effluent Gas Stream (typical):
Component Vol.%
C02 8-10
02 8-12
H20 3-4
N2 77-78
'From Exxon monthly report to the EPA, July 1976
2Data from measured samples.
3Estimated loading.
22
-------
Argonne National Laboratories
Fluidized bed combustion studies also are being conducted
at Argonne National Laboratories. This work has been reported
by Vogel et al. (1974, 1975). They use a 15 cm (six-inch)
diameter fluidized bed bench-scale unit. Particulate loadings
and gas conditions are presented in Table 5. The particulate
loadings are for various test conditions and may not be rep-
resentative of what could be achieved under optimized condi-
tions. The test variables include temperature, fluidizing
velocity, and the calcium/sulfur ratio.
The particulate emissions were observed to increase with
the fluidizing velocity and the calcium/sulfur ratio. No
general trends in the effect of temperature on particulate
emissions were reported.
Size distributions of the particulate matter collected in
the primary and secondary cyclones are shown in Figure 4 to
have an MMD='l. 6 ym and o =2. The data were taken by Coulter
O
Counter. The cyclones v/ere not optimized for particle col-
lection and thus their efficiencies are not necessarily repre-
sentative of the best attainable.
The gas leaving the cyclones was passed through one or
two stages of filters. Size analysis of the particulate on
the filter was not available, however subsequent tests showed
that from 0.12 to 0.20 g/Nm3 (0.051 to 0.089 gr/SCF) was pene-
trating the first filter stage. Approximately 60 to 801 of
this particulate was smaller than 2 ym (by Brink impactor an-
alysis). Therefore, emissions of fine particles (<2 ym) can
at least be the order of 0.1 g/Nm3 (0.05 gr/SCF).
Once again, it should be emphasized that the data reported
here (from Vogel et al., 1974) are not necessarily representa-
tive of the loadings and particle size distributions that would
be obtained in a commercial unit with an optimally designed
system for the high-temperature removal of fine particulate
matter from the flue gas.
23
-------
Table 5 . SUMMARY OF CONDITIONS FOR PARTICLE REMOVAL
FROM THE ARGONNE BENCH-SCALE FLUIDIZED BED
COAL COMBUSTOR1
Temperature Range: 790 to 900°C
Pressure Range: up to -8 atm
Dust Loading:
Leaving Combustor2; 9 to 55 g/Nm3 (4 to 24 gr/SCF)
Leaving Primary Cyclone2; 1.1 to 10.8. g/Nm3
(0.5 to 4.7 gr/SCF)
Leaving Secondary Cyclone2; 0.5 to 4.8 g/Nm3
(0.2 to 2.1 gr/SCF)
Dust Emissions:
Leaving Combustor2; 3 to 17 g/MJ (7 to 39 lb/106Btu)
Leaving Primary Cyclone2; 0.3 to 3.2 g/MJ
(0.8 to 7.4 lb/106Btu)
Leaving Secondary Cyclone2; 0.2 to 1.4 g/MJ
(0.5 to 3.3 lb/106Btu)
Composition of Effluent Gas Stream:
Component Vol.%
C02 . 15-17
02 ~3
N2 80-82
SO2 120-850 ppm
NO 140-270 ppm
CO 30-760 ppm
'From Vogel et al. (Sept, 1974)
2Data from measured sample. Estimated accuracy is ±10%.
24
-------
50
40
SECONDARY
CYCLONE
10
20
30 40 50 60 70
WEIGHT \ UNDERSIZE
80
90
95
98
Figure 4. Size distributions of particulate matter collected
in primary and secondary cyclones at the Argonne
bench-scale fluidized bed combustion project. Data
were replotted from data presented by Vogel et al.
(Sept. 1974).
25
-------
Argonne National Laboratories is constructing a larger
(0.8 to 3.1 equivalent MWe) fluidized bed combustion component
test and integration unit (CTIU) under E.R.D.A. sponsorship.
This facility will have the capability of testing alternative
hot gas cleanup systems. The conceptual design for this fa-
cility was reported by Carls and Podolski (1975). This facil-
ity will be a pressurized CTIU as opposed to the Morgantown
CTIU which operates at atmospheric pressure.
Combustion Power Company
The Combustion Power Company has developed the CPU-400
fluidized bed combustor and gas turbine system. It was origin-
ally designed to generate electric power from the combustion of
municipal waste (Combustion Power Company, 1969-1974). More
recently it has been used with dolomite additive to burn high
sulfur coal.
The solid waste or coal is burnt at temperatures ranging
from about 760°C to 980°C, and at pressures from atmospheric
to about 7 atm. These data are summarized with the gas compo-
sition and particulate emissions in Table 6. The size distri-
bution for the particulate leaving the secondary cyclone from
the combustion of municipal waste is also given in Table 6.
Approximately 0.07 g/Nm3 (0.03 gr/SCF) were smaller than 2 ym.
As a tertiary cleanup device, Combustion Power has devel-
oped a moving bed granular bed filter (dry scrubber), reported
by Wade (1975). A high temperature and high pressure model of
the granular bed filter was built but the unit had materials
problems which resulted in mechanical failure. Current devel-
opment work is being conducted at low temperature under ERDA
sponsorship.
The burning of municipal waste may be a more difficult
problem than burning coal because of the variety of gases and
particulate pollutants that are emitted. For example, aluminum
condensation particles are difficult to collect and may increase
the potential for turbine blade corrosion from particulate de-
26
-------
Table 6. SUMMARY OF CHARACTERISTICS OF PARTICLE
REMOVAL FROM THE COMBUSTION POWER COMPANY
FLUIDIZED BED COMBUSTION PROCESS1
Bed Temperature: 760 to 980°C
Turbine Inlet Temperature: 690 to 750°C
Pressure: 3 to 7 atm
Dust Loading: Waste-fired combustor:
Leaving Secondary Cyclone; 0.09 g/Nm3 (0.04 gr/SCF)
Smaller than 2 ym; 0.07 g/Nm3 (0.03 gr/SCF)
Composition of Effluent Gas Stream:
Waste-Fired
Vol.1 Coal-Fired
Component
C02
02
CO
CHx
SO 2
N0x
HC1
N2 + Other
icle Size Di
low pressure high pressure Vol.%
5.8
13.4
<30 ppm
<20 ppm
139 ppm
161 ppm
-81
stribution:
Particle diameter, ym
5.0
4.0
3.0
2.5
2.0
1.2
2
5.2 3.5-6.7
16.1 13-16
<30 ppm
2 ppm
35 ppm
100 ppm
63 ppm
-81 80.5
Waste-fired combustor:
Wt % undersize
99.5
98.5
95.1
90.1
82.7
SO2
C.P.C. Report to the EPA, Sept. 1974.
2Extrapolated from log-normal distribution.
27
-------
posits. Combustion Power also has had trouble with cyclones
plugging up with large, sticky particles.
National Coal Board
The National Coal Board of London, England has conducted
experimental pilot plant tests of atmospheric and pressurized
fluidized bed coal combustors. This work has been reported
by Hoy (1970), Williams (1970), the National Coal Board (1970,
1972), Wright (1973), Locke et al. (1975), and Highley (1975).
Their combustion temperatures ranged from about 750°C to
950°C. Atmospheric pressure was used for most of the earlier
tests, with some pressurized tests conducted at 5 atm. Oper-
ating pressures up to 10 or 15 atm are being considered. A
typical effluent gas composition is: 15% C02, 3% 02, and 821
Na, with trace amounts of SOa.
Particulate emissions downstream of the secondary cyclone
ranged from about 0.2 to 1.4 g/Nm3 (0.1 to 0.6 gr/SCF). This
is equivalent to about 1 to 5% of the noncombustible material
in the feed. In the pressurized combustor, a third cyclone
was used which reduced the dust loading to about 0.1 to 0.2
g/Nm3 (0.05 to 0.1 gr/SCF). When the fumes from the primary
cyclone were recycled to the combustor, the participate emis-
sions from the secondary cyclone increased to more than 3 g/Nm3
(1.4 gr/SCF).
The particulate emissions consisted of unburnt carbon,
ash, and sorbent additives. When the fines collected in the
primary cyclone were recycled, 5 to 15% of the feed coal, and
80 to 100% of the ash and additives were elutriated from the
bed.
Particulate emissions increased approximately in proper^
tion to the feed rate of ash plus additive. The increased
elutriation at faster fluidizing velocities was found to be
balanced by an increased cyclone collection efficiency at the
higher inlet velocity. No size distribution data for the par-
ticulate emissions were reported.
28
-------
Pope, Evans, and Robbins
Pope, Evans, and Robbins, Inc. (PER) has studied an at-
mospheric pressure fluidized bed boiler. Their work has been
reported by Ehrlich (1970), Robison et al. (1970, 1972), and
Pope (1975) as well as many other reports.
The PER development work involved pilot scale (50 kg coal/
hour) and full scale module (363 kg coal/hour) tests at combus-
tion temperatures ranging from 800°C to 1,000°C. The combus-
tors operate at near atmospheric pressure and the flue gas
leaves the boiler at about 300°C to 400°C. Particulate emis-
sions are removed by cyclones and possibly an electrostatic
precipitator. Particle removal must be sufficient to meet the
new source performance standards for coal-fired boilers. It
is not necessary that the particulate matter be removed at high
temperature.
Unburnt carbon is oxidized in a carbon burnup cell opera-
ting near 1,100°C. The carbon burnup cell is a section of the
fluidized bed boiler. Particle carryover is recycled via the
cyclones to the burnup cell which is at a higher temperature
than the primary boiler bed. The lower temperature in the pri-
mary bed is necessary to optimize sulfur removal by the sorbent.
Particulate emissions penetrating the cyclones are on the
order of 0.4 to 3.4 g/MJ (1 to 8 lb/106BTU). Therefore, to
satisfy an emissions standard of 21 mg/MJ (0.05 lb/106BTU), ap-
proximately 95 to 99+% collection efficiency will be required.
The size distribution of the effluent dust, as reported by
Robison et al. (1970), is shown in Figure 5. The MMD was 4.6
ym and a was approximately 2.
O
The PER atmospheric FBC process has been used as a basis
for the design of an 800 MWe, multicell utility steam gener-
ating system by PER and Foster Wheeler. This design was re-
ported by Gamble (1975).
29
-------
e-
w
Q
ex.
30
20
10
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»
^»
x
x1
x
_
^
^
«
/
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= = = = = = = = == ==! = = = = ; OF EQ
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ICAL PARTICLES
UAL DENSITY) == = j«
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;;;;;;;;::;;::|||::; ACTUAL
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C
X
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01
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X
-^
UN
_x*
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T
10 20 30 40 50 60 70 80
PERCENT UNDERSIZE
90 95
98
Figure 5. Particle size distribution penetrating the cyclone
in the PER fluidized bed combustor. Data from
Robison et al. (1970)
-------
MERC Atmospheric FBC
Another atmospheric pressure fluidized bed combustion
component test and integration unit (CTIU) with a capacity of
6 MWe is to be built at the E.R.D.A. Morgantown Energy Research
Center. This facility will have the capability of testing al-
ternative hot gas cleanup systems. The conceptual design has
been described by Wilson and Gillmore (1975).
31
-------
COAL GASIFICATION PROCESSES
Coal gasification processes are being developed as poten-
tial methods for obtaining clean energy from coal. They can be
classified as either low-BTU or high-BTU processes. The low-
BTU process produces a gas with a low energy content (princi-
pally carbon monoxide and hydrogen) which can be used as a fuel
for a gas turbine. It can also be burnt directly in a boiler
or can be used as a synthesis gas for the production of pipeline
gas, ammonia, or methanol. However, it is not economical to
transport low-BTU gas in a pipeline. High-BTU processes con-
vert the synthesis gas into methane to produce a pipeline qual-
ity gas.
The basic gasification process converts solid coal into a
combustible gaseous fuel by reacting it with air, oxygen, steam,
carbon monoxide, hydrogen or mixtures of these gases in a re-
ducing environment. The product gas leaves the gasifier at high
temperature (up to 1,500°C) and often at high pressure (up to 70
atm). The gas generally contains a large concentration of en-
trained particulate matter (mostly ash and unburnt carbon). In
some of the lower temperature processes (below about 500°C), the
gas may also contain a large amount of tar. Also, corrosive
contaminants such as alkali metals, mercury, and chlorides may
be present in the ash. The particulate matter and tar must be
removed from the gas before the gas can be used as a fuel for a
gas turbine, or can be upgraded to a pipeline quality gas.
There is no current New Source Performance Standard (NSPS)
for advanced fossil-fuel conversion processes, although the EPA
plans to use the NSPS approach for controlling these emerging
industries (Durham, 1975). In order to allow for industry growth
while maintaining regional air quality standards, it will prob-
ably be necessary to control particulate emissions from new
sources more stringently than current standards. The NSPS for
particulate emissions from advanced fossil fuel conversion
32
-------
processes will most likely be at least as stringent as the an-
ticipated new standards for boilers, that is, <0.05 lb/106BTU
(21.5 mg/MJ), or at least be based on BACT (best available
control technology).
In many situations it would be advantageous for economic
reasons to clean the gas as it leaves the gasifier, at high
temperature and pressure. If the gas is to be used as a fuel,
it is desirable to use it at or near the temperature at which
it is produced. When the gas is to be used as a synthesis gas,
shift conversion of the gas is required to increase the ratio
of Ha to CO. Particle removal at a temperature suitable for
the shift reaction (400 to 500°C) is desired.
High temperature particle collection is much more diffi-
cult than low temperature collection not only because of ma-
terials problems, but also because conventional collection
equipment is significantly less efficient at high temperatures
(Calvert and Parker, 1977). No high temperature and pressure
particle removal equipment except cyclones has yet been proven
satisfactory for commercial operation, and cyclones are not
efficient enough to meet the cleanup requirements. Therefore
many of the designs currently proposed for coal gasification
processes include a waste heat boiler for cooling the gas be-
fore it is cleaned. The gas is then cleaned at high pressure
and relatively low temperature. When pipeline gas is being
produced, it is convenient to operate the gasifier (and hence
the particle collection equipment) at pipeline pressures (50
to 70 atm). This increases the production of methane in the
gasifier, and eliminates the need for compression of the gas
after production. Gasifier pressures used for the production
of low-BTU gas for industrial or utility use normally are much
lower (20 atm or less).
There are many different processes for gasifying coal, and
the gaseous and particulate emissions vary from one process to
another. The most common classification of gasification proces-
ses is classification according to the flow of the gas relative
33
-------
to the coal. The four basic types of gasifiers, classified in
this manner, are:
1. fixed or slowly moving beds of solids
2. entrained solids
3. fluidized beds
4. molten baths.
Gasifiers also may be classified with regard to the ash re-
moval method. At temperatures below ~1,000°C the mineral matter
in the ash remains dry. At temperatures somewhat higher the ash
becomes tacky and tends to agglomerate. At even higher tempera-
tures the ash melts. Molten ash usually becomes free-flowing at
temperatures of about 1,500°C to'l,600°C. Therefore, coal gasi-
fiers can be classified as dry bottom, ash agglomerating, or
slagging gasifiers with respect to ash removal. Gasifiers can
also be classified as to pressure level, number of reaction stages,
and the source of oxygen (either air blown or oxygen blown).
In general, particulate emissions are greater for entrained
bed and fluidized bed dry bottom type gasifiers. Particulate
emissions are fewer for ash agglomerating and molten bath gasi-
fiers. Table 7 summarizes the important types of coal gasifiers
and the developers of each process.
A review and evaluation of coal gasification processes has
been conducted by the National Academy of Engineering (1973,
1974). A review of coal conversion processes for potential use
by the electric utilities industry was reported by Katz et al.
(1974). A number of gasification processes have been evaluated
with respect to their pollution control needs by Exxon Research
and Engineering Company. These reports will be cited with the
individual processes discussed below. An assessment of the
environmental impact of coal gasification has been reported by
Robson et al. (1976), and the status of high temperature par-
ticle cleanup has been reviewed by Zabolotny et al. (1974) and
by Fulton and Youngblood (1975).
Table 8 summarizes the particulate removal requirements
for the coal gasification processes considered in this review.
34
-------
Table 7. CLASSIFICATION OF COAL GASIFIERS
GASIFIER TYPE
DEVELOPER
Fixed or Slowly Moving Bed
Lurgi
U.S. Bureau of Mines
Fluidized Bed (Dry)
Winkler
E.R.D.A. (HYDRANE)
E.R.D.A. (SYNTHANE)
Institute of Gas Tech. (HYGAS)
Consolidation Coal Company
(C02 ACCEPTOR)
Bituminous Coal Research
Ash Agglomerating
Fluidized Bed
Battelle Memorial Institute
Institute of Gas Tech. (U-GAS)
Westinghouse Electric Company
Slagging - Entrained Flow
Koppers-Totzek
Bituminous Coal Research (BIGAS)
Combustion Engineering
Foster Wheeler
Brigham Young University
Texaco
Molten Bath
Atomics International
M.W. Kellogg
Applied Technology, Inc
In-Situ Gasification
E.R.D.A.
-------
Table 8. SUMMARY OF PARTICULATE CLEANUP REQUIREMENTS
FOR COAL GASIFICATION PROCESSES
Process
I Fixed Beds
Lurgi
USBM Stirred Bed
II Dry Fluidized Beds
Winkler
USBM Hydrane
USBM Synthane
IGT Hygas
C02 Acceptor -
Gasifier
COa Acceptor -
Regenerator
BCR Fluidized Bed
III Ash Agglomerating
Fluidized Bed
Battelle-
Union Carbide
IGT U-Gas
Westinghouse
Gasifier Exit
Temperature
°C
400-600
500-650
800-1,000
900
400-750
300
800-850
1,000
1,000-1,150
1,100
1,000
750-900
Gas Cleanup
Temperature
°C
200
150-200
500
250
200
1,000
650
--
400
--
Pressure
o +m
a. L.111
20-30
7
1
70
20-70
70-100
10
10
20-50
7
20-70
10-15
Mass Loading
g/Nm3 gr/SCF
24
24
--
20
18
10
10
--
8.8
7.8
Control Devices
Used or
Anticipated
scrubbers
scrubbers
cyclones,
scrubbers,
electrostatic
precipitators
cyclones
scrubber
series
cyclones
venturi
scrubber
cyclones, sand
bed filters
cyclones
proprietary
process
rotary flow
cyclones, gran-
Remarks
tars present
tars present
pulverized coal in fuel
tars and heavy hydro-
carbons present
ular bed filters
1
-------
Table 8. Continued
Process
IV Slagging-Entrained
Flow
Koppers-Totzek
BCR Bi-Gas
Combustion
Engineering
Foster Wheeler
BYU
Texaco
V Molten Bath
M.W. Kellogg
ATC Molten Iron
Atomics Inter-
national
VI In-Situ
LERC
Gasifier Exit
Temperature
°C
1,200-1,300
900
900
1,000
650-1,300
1,400
900
1,100
950
--
Gas Cleanup
Temperature
°C
200
600
350
150
100
300
--
--
250-350
Pressure
atm
1
80-100
80-100
10
30
1
15
80
1-70
5
2-7
Mass Loading
g/Nm3 gr/SCF
40
230
10
--
~ "
--
--
--
--
17.5
100
5
--
__
--
--
Control Devices
Used or
Anticipated
two disintegra-
tor or venturi
scrubbers in
series
cyclone scrubber
sand bed filters
scrubber
scrubber
_ «
--
--
scrubbers
Remarks
MMD~ 1,000 urn
0 ~15
g
MMD-300 urn
Vs
bench scale develop-
ment
alkali metal fumes
present
tars present
OJ
-------
The information presented was obtained from available literature
and personal correspondence with researchers.
The individual processes are discussed in more detail in
the remainder of this section. Some information concerning
particulate emissions and control devices was not reported be-
cause data were not available, or because the information is
proprietary. In general it may be concluded that more data
concerning particulate mass emissions and size distributions
are needed before the specific cleanup requirements can be
determined with good accuracy.
FIXED OR SLOWLY MOVING BED GASIFIERS
Lurgi Process
The Lurgi gasification process has been described by Krieb
(1973), Katz et al. (1974), and in numerous other publications
and reviews. The pollution control needs of the Lurgi process
have been reviewed and evaluated by Shaw and Magee (1974). The
Lurgi process uses either a fixed or a slowly moving counter-
current bed on non-caking coal. Gasification may be either air
blown or oxygen blown. The gasification pressure is about 20
atm for the production of low-BTU process fuel gas (air blown),
and about 30 atm or more for the production of intermediate-BTU
(oxygen blown) synthesis gas. Pipeline gas is produced from
the synthesis gas by shift conversion and methanation.
The exit temperature of the gas leaving the gasifier ranges
from about 400°C to 600°C. The gas contains coal dust, oil,
naphtha, phenol, ammonia, tar, ash, and char. Approximately 5%
of the ash is char. The hot gas generally goes through a scrub-
o
bing and cooling tower, and then through a waste heat boiler.
It leaves the waste heat boiler at about 200°C and is used di-
rectly as a process fuel, or is converted to methane for use as
a pipeline gas. Typical raw gas compositions for oxygen blown
and air blown Lurgi gasifiers are listed in Table 9.
The composition of the particulate matter emitted from the
gasifier is expected to be similar to that emitted from stoker-
38
-------
Table 9. RAW GAS COMPOSITION FOR LURGI GASIFIER
COMPONENT
H2
C02
CO
CH,
C2H4
H2S
C2H6
N2 + Other
TOTAL
Higher Heating Value
MOL \
OXYGEN BLOWN AIR BLOWN
38.8
28.9
. 19.6
11.1
0.4
0.3
0.3
0.6
100
-11 MJ/Nm3
(300 BTU/SCF)
24.7
5.0
18.8
6.4
0.3
0.4
44.4
100
-7 MJ/Nm3
(180 BTU/SCF)
-------
type boilers; that is, approximately 40% silica, 30% alumina,
and 10% iron oxide. The mass emissions of particulate matter
are expected to be on the order of 2 g/MJ (5 lb/106BTU) which
would be equivalent to about 24 g/Nm3 (10 gr/SCF) based on a
heating value of 300 BTU/SCF. No quantitative data have been
reported to verify these predictions.
To meet the current emissions regulations for coal-fired
boilers (43 mg/MJ or 0.1 lb/106BTU), approximately 98% collec-
tion efficiency would be required. To meet the more stringent
standards being proposed (21.5 mg/MJ or 0.05 lb/106BTU), approx-
imately 99% collection efficiency would be necessary. Particle
collection occurs at high pressures (20 to 30 atm) and relatively
low temperatures (~200°C). Wet scrubbers are typically used to
remove the tar and oils as well as the ash and coal dust.
The most unique problem associated with the Lurgi process
is that the gasification temperature is too low to eliminate tars
from the effluent gas. Therefore it is necessary to remove the
tar by quenching and scrubbing the gas as it leaves the gasifier.
The condensed tar is then returned to the gasifier. This severe-
ly limits the ability to make use of the sensible heat of the gas
stream. The cleaned gas must be reheated to about 400°C or 500°C
for the shift conversion process when synthesis gas is being pro-
duced .
The Lurgi process has been proposed and used primarily for
the production of synthesis gas, and low-BTU gas for the genera-
tion of process heat in conventional boilers. It would be pos-
sible to use the product gas as the principal fuel in a combined-
cycle gas turbine-steam turbine power generation plant. In this
case, the gas turbine would require more efficient particle re-
moval (>99.9%) for particles larger than a couple of micrometers
in diameter. The turbine inlet requirements are discussed in
more detail in a later section of this report.
U.S. Bureau of Mines Stirred-Bed Process
The U.S. Bureau of Mines in Morgantown, West Virginia (now
40
-------
the Morgantown Energy Research Center of the E.R.D.A.), has de-
veloped a stirred-bed gasifier. The stirring device agitates
the coal bed to prevent agglomeration and caking. This work has
been reported by McGee (1966), and reviewed by Lewis et al. (1973)
and Katz et al. (1974).
The gasifier operates at a pressure of about 7 atm, and tem-
peratures from about 500°C to 650°C. Essentially, the stirred-
bed gasifier is a modification of the Lurgi gasifier allowing for
the use of strongly caking coals. The major problem, as with the
Lurgi process, is that the gasifier temperature is relatively low
and therefore large quantities of oil and tar are present in the
gas. The oils and tars may be removed by quenching and scrubbing,
however this limits the ability to recover sensible heat for the
process.
The gas and particulate emissions and cleanup requirements
should be similar to the Lurgi process as discussed above.
DRY FLUIDIZED BED GASIFIERS
Winkler Process
The Winkler gasification process has been described by Ban-
chik (1973), Katz et al. (1974), and by the National Academy of
Engineering (1974). The pollution control aspects of the Wink-
ler process have been reviewed and evaluated by Jahnig (1974).
The Winkler gasifier is a dry bottom, single stage fluidized
bed gas generator which operates at atmospheric pressure with
either air or oxygen. The gasification temperature is kept be-
tween about 800°C and 1,000°C, which is hot enough to cause the
cracking of tars and heavy hydrocarbons. The dust laden gases
are cooled in heat exchangers to produce process steam. Then
they are partially cleaned in a cyclone at about 150°C to 200°C,
and further cleaned in a scrubber followed by an electrostatic
precipitator.
Typical gas compositions from the air blown and oxygen
blown Winkler process are shown in Table 10. The particle emis-
41
-------
Table 10. PRODUCT GAS COMPOSITION FOR THE WINKLER PROCESS
COMPONENT
H2
C02
CO
CH,,
H20
N2
H2S
TOTAL
Higher Heating Value
MOL %
OXYGEN BLOWN AIR BLOWN
32.2
15.8
25.7
2.4
23.1
0.5
0.3
100
-10 M.J/Nm3
(275 BTU/SCF)
11.7
6.2
19.0
0.5
11.5
51.0
0.1
100
~4 MJ/Nm3
(120 BTU/SCF)
42
-------
sions have not been quantified. High temperature and pressure
particle removal is not required for this process. However, if
high temperature cleanup equipment were available, it might be
beneficial to clean the gas before it passes through the heat
exchangers.
HYDRANE Process
The HYDRANE process is a dry, fluidized bed coal gasifica-
tion process originally developed by the U.S. Bureau of Mines
and now under development by E.R.D.A. It is based on the
reaction of raw coal with hydrogen to form methane directly.
This process has been described by Feldmann et al. (1972),
Yavorsky (1973), and by Katz et al. (1974).
A two-stage reactor is used and operates at approximately
70 atm and 900°C. The products are a methane-rich gas and
char. The char is used in a fluidized bed synthesis gasifier
to produce hydrogen. Typical gas and char compositions are
shown in Table 11.
Some information concerning particle collection require-
ments was obtained from Chambers (1976). Particle removal would
be required before the product gas could be used as a pipeline
gas, or used as a fuel for a gas turbine. Particle removal is
expected to occur at about 500°C and 70 atm. Pulverized coal
is the fuel for the process, and entrained particulates are ex-
pected to be fairly small (15 ym or smaller). A cyclone filter
device is being considered for particle collection. There are
not yet any data describing particulate mass emissions per pro-
duct gas volume, nor are there any size distribution data.
SYNTHANE Process
The SYNTHANE process is a fluidized bed, coal gasification
system developed by the U.S. Bureau of Mines for the production
of pipeline quality gas. It has been described by Forney et al.
(1973) , the National Academy of Engineering (1974) , and Katz et
al. (1974). The pollution control aspects of the SYNTHANE pro-
43
-------
Table 11. TYPICAL GAS AND CHAR COMPOSITIONS FOR HYDRANE PROCESS
PRODUCT GAS
COMPONENT WT. %
H2
CH4
C2H6
CO
C02
N2
TOTAL
27.9
68.6
0.1
1.4
0.6
1.4
100
CHAR
COMPONENT WT. %
C
H
0
N
S
Ash
TOTAL
66.0
1.6
7.0
0.9
0.7
23.8
100
44
-------
cess have been reviewed and evaluated by Kalfadelis and Magee
(1974).
In the SYNTHANE process, the gas leaving the gasifier un-
dergoes cleaning, shift conversion, and methanation to obtain a
pipeline gas. To increase the production of methane in the gas-
ifier, and to avoid the need to compress the gas to pipeline
pressure, the gasifier is operated at high pressure (about 70
atm). The temperature at the gasifier exit is between 400°C
and 750°C. At this temperature it passes through cyclone col-
lectors. Then it passes through a cold-water scrubber (probably
a venturi scrubber) at approximately 250°C, and near 70 atm.
The gasifier output contains tars, heavy hydrocarbons, coal
dust and ash. The gas composition leaving the gasifier is shown
in Table 12. Particle mass emissions and size distribution data
have not been quantified.
The HTP particle collection is required to clean the gas
so that it is suitable for pipeline use, and also to prevent
plugging and contamination in the shift conversion and methana-
tion steps. .
Although the SYNTHANE process was developed for the produc-
tion of pipeline gas, the process could be modified to produce
low-BTU synthesis gas for a combined cycle power system. In
this case, particle cleanup would be required to meet the gas
turbine inlet loading requirements as well as the applicable
mass emissions regulations. The gasification pressure (and
hence the pressure during particle cleanup) would probably be
much lower (maybe 20-30 atm).
IGT Process
The Institute of Gas Technology (IGT) has developed a four-
stage, fluidized bed coal gasification process trade-named the
"HYGAS Process." It has been described by Schora et al. (1973),
and by Katz et al. (1974). The pollution control aspects of the
IGT HYGAS process were reviewed and evaluated by Jahnig (1974) .
The HYGAS process was designed to produce pipeline quality
45
-------
Table 12. GAS COMPOSITION FROM THE GASIFIER
OF THE SYNTHANE PROCESS
COMPONENT
CO
COa
H2
CHu
H20
H2S
N2
Other
TOTAL
Higher Heating Value
MOL %
10.5
18.2
17.5
15.4
37.1
0.3
0.5
0.5
100
-15 MJ/Nm3
(400 BTU/SCF)
46
-------
gas through direct hydrogenation of coal at high pressures (70
to 100 atm).
The synthesis gas leaves the gasifier at about 300°C. Char
is formed in the second stage of the gasifier and reacted with
oxygen and steam in the fourth stage to produce hydrogen for the
process. The hydrogen-rich synthesis gas goes directly into the
gasifier and therefore does not need to be cleaned. Two air-
based processes for hydrogen production have also been developed:
the electrothermal process, and the iron-steam process.
Representative gas compositions leaving the gasifier are
shown in Table 13. The gas leaving the gasifier is purified
and methanated. Purification removes most of the C02 and H2S.
In addition, any coal dust, oils, or ash must be removed before
the gas can be conveyed through a pipeline. Series cyclones
have been proposed for particulate removal.
It has been proposed that agglomeration of the ash in the
fluidized bed will reduce fly ash carryover. However, no quan-
titative data describing the particle mass emissions or size
distributions have been obtained.
The C02 Acceptor Process
The COa Acceptor Process is a fluidized bed coal gasifica-
tion process developed by Consolidation Coal Company to produce
pipeline gas from lignite or sub-bituminous coal. This process
has been described by Fink (1973) and Katz et al. (1974). The
pollution control aspects of the process were reviewed and eval-
uated by Jahnig and Magee (1974). Additional particle removal
requirements have been obtained from McCoy (1976) .
The gasifier operates at about 10 atm pressure and at tem-
peratures from about 800°C to 850°C. Limestone or dolomite is
used as the "acceptor" to remove COa from the gas prior to meth-
anation. Particle removal is required from the effluents of
both the gasifier and the dolomite (or limestone) regenerator.
The process gas leaves the gasifier, passes through a se-
ries of cyclones at about 800°C and 10 atm, and then is cooled
47
-------
Table 13. GAS COMPOSITION LEAVING THE HYDROGASIFICATION
REACTOR (OIL FREE) FOR IGT HYGAS PROCESS
COMPONENT
CO
CO 2
H2
H20
CH,
C2H6
H2S
Other
TOTAL
MOL %
ELECTROTHERMAL OXYGEN STEAM- IRON
21.3
14.4
24.2
17.1
19.9
0.8
1.3
1.0
100
18.0
18.5
22.8
24.4
14.1
0.5
0.9
0.8
100
7.4
7.1
22.5
32.9
26.2
1.0
1.5
1.4
100
48
-------
in a waste heat boiler. Final cleaning of the gas is done in a
venturi scrubber operating at 10 atm and about 200°C. Particu-
late emissions are expected to be about 20 g/Nm3 (8.8 gr/SCF).
No size distribution data have been reported. The gas composi-
tions for the gas leaving the gasifier and the regenerator are
shown in Table 14.
The dolomite regenerator operates at about 1,000°C. The
effluent gas is expected to be cleaned by a series of cyclones,
or other hot gas cleaning equipment which may be developed, at
10 atm and 1,000°C. Energy recovery could be obtained by ex-
panding the clean, HTP gas through a gas turbine. The particu-
late mass emissions from the regenerator are expected to be
about 18 g/Nm3 (7.8 gr/SCF). In order to meet the current fed-
eral New Source Performance Standards for coal-fired boilers
(0.1 lb/106BTU), the particulate emissions must be reduced to
about 180 kg/hr (400 Ib/hr). This is equivalent to approxi-
mately 99.71 collection efficiency.
Several stages of cyclones, and sand bed filters, are being
considered for hot gas cleanup. A reliable and efficient system
for removing dust from the regenerator flue gas has yet to be
demonstrated.
In a typical commercial operation, the regenerator flue gas
cleanup could be done at lower temperature if the gas were not
to be passed through a gas turbine. In this case, high tempera-
ture and pressure gas cleanup (550°C to 650°C, 10 atm) would
still be required to allow operation of an expander which would
be used to drive the regenerator air compressor (McCoy, 1976).
BCR Fluidized Bed Gasifier
Bituminous Coal Research, Inc. (BCR) is developing a multi-
ple stage fluidized bed coal gasification process for the pro-
duction of low-BTU gas. This process has been described briefly
by Katz et al. (1974).
High temperature cyclones (1,000°C to 1,150°C) will be used
to recycle unburnt coal and large ash particles after each stage
49
-------
Table 14. EFFLUENT GAS COMPOSITIONS FROM THE
C02 ACCEPTOR PROCESS
COMPONENT
H2
CO
C02
CFK
NH3
N2
Other
TOTAL
MOL t
GASIFIER REGENERATOR
70.9
15.2
6.9
6.1
0.7
0.2
100
0.1
2.5
32.1
64.1
1.2
100
50
-------
of the gasifier. The synthesis gas will leave the final stage
at about 650°C. The gasifier pressure will depend on the final
use of the synthesis gas (20 to 50 atm).
Particle collection probably will be necessary before the
synthesis gas is used. The collection requirements will depend
on the use. Gasification can be with air and steam, oxygen and
steam, or carbon dioxide. Gasification with carbon dioxide will
yield a carbon monoxide rich gas which could be suitable for MHD
power generation.
ASH AGGLOMERATING FLUIDIZED BED
Battelle-Union Carbide Gasifier
Battelle Memorial Institute, Columbus, under sponsorship of
Union Carbide, has developed an agglomerated-ash fluidized bed
coal gasification process. This process has been described by
Corder et al. (1973, 1974), and by Katz et al. (1974).
Pulverized coal is fed to the gasifier which will operate
at pressures up to about 7 atm, and temperatures to about 1,000°C.
Future applications may require operation at higher pressures.
The gas goes from the gasifier to an agglomerating ash, char
burner at about 1,100°C.
The high temperature bed promotes agglomeration of the ash
(especially as the ash fusion temperature is approached), and
presumably this will significantly reduce the particulate emis-
sions from the gasifier. It is believed that the ash agglom-
erating fluidized bed is capable of reducing emissions to about
0.1 g/Nm3 (0.05 gr/SCF). Ultrafine particles may not be cap-
tured in the agglomerating bed.
Exit gases from the burner pass through a high temperature
and pressure cyclone which captures the coarse particles and ag-
glomerated ash that may be blown from the bed. Other more effi-
cient collection equipment may be required if the fine particle
emissions are in excess of the emissions regulations. It is ex-
pected that the particles will be small enough not to erode gas
turbine blades. Data to support this have not been reported yet.
51
-------
U-GAS Process
The Institute of Gas Technology (IGT) has developed the
"U-GAS" fluidized bed, ash agglomerating gasification process.
This process has been described by Loeding and Tsaros (1973),
and by Katz et al. (1974). The pollution control aspects of
this process have been reviewed and evaluated by Jahnig (1974) .
The U-GAS process operates at a gasification temperature
of about 1,000°C and a pressure of about 20 atm when producing
low-BTU gas for combined cycle power generation, and a pressure
of about 70 atm for the production of a pipeline gas. The gasi-
fier is air blown. Typical gas compositions for gasification
pressures of 20 atm and 70 atm are shown in Table 15.
Particle removal occurs in two stages of cyclones. The
first cyclone is in the gasifier exit and operates at near the
gasification temperature and pressure. The secondary cyclone
operates at a slightly cooler temperature (about 850°C). The
particulate emissions are expected to be minimized by the ash
agglomerating characteristics of the fluidized bed.
The IGT Meissner Process is a proprietary process being
developed to remove sulfur and fine particles from the fuel gas
at high temperature and pressure. It operates at about 400°C,
and near the gasification pressure.
Westinghouse Advanced Gasifier
Westinghouse Electric Corporation, under E.R.D.A. sponsor-
ship, is developing an advanced coal gasification system for
electric power generation. Early stages of the development of
this process were reported by Archer et al. (1973), Katz et al.
(1974) , and in numerous Westinghouse reports to the Office of
Coal Research and the E.R.D.A. (1972-1976). More recent infor-
mation concerning the particulate removal problems of this pro-
cess has been obtained from Lancaster (1976) and Ciliberti (1976)
The Westinghouse process uses a multi-stage fluidized bed
operating at 10 to 15 atm pressure. The bottom stage operates
at 1,000°C to 1,100°C to agglomerate the ash and thereby reduce
52
-------
Table 15. TYPICAL GAS COMPOSITION FOR THE U-GAS PROCESS
COMPONENT
CO
CO 2
H2
H20
ci-u
N2
TOTAL
Higher Heating Value
MOL \
20 ATM 70 ATM
17.8
9.2
12.1
8.5
4.3
48.1
100
~5.5 MJ/Nm3
(153 BTU/SCF)
12.5
12.6
11.6
8.5
7.1
46.7
100
-6 MJ/Nm3
(164 BTU/SCF)
-------
particulate emissions. The upper stages will operate at lower
temperatures (750°C to 900°C). No tars or condensable hydrocar-
bons are expected to be present in the effluent gas.
Particle removal from the effluent gases is achieved using
two stages of cyclone separators. High efficiency rotary flow
cyclones (Aerodyne, Tanjet) have been tried and their perfor-
mance in high temperature and pressure conditions was found to
be unsatisfactory. Granular bed filtration is currently being
considered as a tertiary cleanup device.
The degree of particle removal required is determined by
balancing the turbine inlet requirements against the emissions
regulations. It is anticipated that effectively all particles
larger than 1-2 ym in diameter will have to be removed to pro-
tect the turbine blades. Some particles smaller than 1-2 ym
may have to be removed in order to satisfy the emissions (or
opacity) regulations.
Westinghouse is running a process development unit at Waltz
Mill, Pennsylvania. No particulate emissions data are available
yet.
SLAGGING-ENTRAINED FLOW GASIFIERS
Koppers-Totzek Process
The Koppers-Totzek gasification process uses a single stage
entrained flow, ash slagging gasifier operating slightly above
atmospheric pressure. This process was developed by Koppers Co.,
Inc., and has been described by Farnsworth et al. (1973) and
Katz et al. (1974). The pollution control aspects of the Kop-
pers-Totzek process have been reviewed and evaluated by Magee et
al. (1974). Recent information concerning the particulate emis-
sions and removal requirements has been obtained from McGurl
(1976).
The Koppers-Totzek Process operates near atmospheric pres-
sure and at temperatures up to over 1,500°C. Water sprays at
the gasifier exit reduce the temperature of the gas to about
1,200°C-1,300°C. Pulverized coal is fed into the side of the
54
-------
slag. The gas leaving the gasifier is cooled to about 200°C in
a waste heat boiler, before it is cleaned by a high efficiency
scrubber (either a disintegrator or a high efficiency venturi
scrubber).
A typical gas composition is shown in Table 16. The gas
generally contains most of the unburnt carbon and about half
the ash in the coal. The composition of the ash depends on the
coal, but usually will contain mostly silica, alumina, and fer-
ric oxide, with possibly some calcium oxide, magnesium oxide,
titanium oxide, alkalis (Na20, K20), sulfur trioxide, and phos-
phorus pentoxide. The particulate matter will contain varying
amounts of ash and carbon depending on the feedstock. If lig-
nite is used, the part.iculate matter will be mostly ash, while
if petroleum coke is used the particulate could be almost pure
carbon. In the latter case the particulate may be recycled to
the gasifier.
Particulate concentrations prior to cleanup will depend on
the ash content of the coal, and on the degree of carbon con-
version. For a 12% ash coal with 95% carbon conversion, about
40 g/Nm3 (17. 5 gr/SCF) wet is the particulate loading before
cleanup (McGurl, 1976). The size distribution is as shown in
Figure 6, with approximately one percent by weight smaller than
one micron, a MMD of about 1,000 ym and a a of 15. Therefore
o
the loading of submicron particles would be approximately 0.4
g/Nm3 (0.175 gr/SCF). Submicron particles are thought to be
too small to damage turbine blades, but in these concentrations
there are enough of them to exceed the emissions regulations,
even if all particles larger than 1 ym were removed. That is,
if the proposed new source performance standard for coal-fired
boilers (0.05 lb/106BTU) and an average higher heating value
of 11 MJ/Nm3 (300 BTU/SCF) are used, the emissions regulation
would be equivalent to about 0.2 g/Nm3 (0.04 gr/SCF). If the
heating value of the coal feedstock were used, the emissions
regulations would be even more stringent.
The current particulate removal system used by Koppers
55
-------
Table 16. TYPICAL PRODUCT GAS COMPOSITION
FROM THE KOPPERS-TOTZEK PROCESS
COMPONENT
CO
C02
H2
H20
N2 + Ar
H2S
COS
TOTAL
MOL %
46.2
8.8
30.8
12.3
1.0
0.85
0.05
100
56
-------
100
80
!! ! Illlllllll
50 40 30 20 10 5 21 0.5
WT % UNDERSIZE
Figure 6. Particle size distribution
expected from the Koppers-
Totzek coal gasifier, before
any particle removal.
57
-------
Company consists of a direct spray type washer-cooler followed
by two rotary, squirrel cage type disintegrators in series. High
energy venturi scrubbers have been proposed for application at
pressures above atmospheric. Two venturi scrubbers in series
would be required to decrease the loading below 0.004 g/Nm3
(0.002 gr/SCF), which has been found by Koppers to be adequate
for most uses.
The critical components requiring particle removal are the
turbine blades when the gas is to be used to fuel a gas turbine
and the compressor blades if the gas is to be compressed for
pipeline transport. If the gas is to be compressed to greater
than about 30 atm pressure, the particulate loading may need to
be reduced even lower than the required loadings mentioned above
BI-GAS Process
Bituminous Coal Research, Inc. has developed the BI-GAS
process for producing pipeline quality gas. This process has
been described by Grace (1973), and by Katz et al. (1974). The
pollution control aspects of the BI-GAS process were reviewed
and evaluated by Jahnig (1975) . Recent information concerning
the particulate emissions and control requirements was obtained
from Grace (1976).
The BI-GAS process uses a two-stage, high pressure (80 to
100 atm) entrained flow gasifier. The bottom stage operates at
about 1,500°C, to allow much of the ash to be removed as molten
slag, and to provide devolatilization of the coal and thermal
cracking of oils and tars. The second stage completes the gas-
ification process at about 900°C. The synthesis gas and en-
trained char leave the gasifier at 80 to 100 atm pressure and
about 900°C. A typical synthesis gas composition for this pro-
cess is shown in Table 17.
The raw gas is cleaned in a cyclone-scrubber to remove the
char and recycle it to the gasifier. The gas leaves the cyclone
at 600°C and process pressure. A typical char size distribution
is shown in Figure 7 with a HMD of 300 ym and a o of 5. The
o
58
-------
Table 17. TYPICAL GAS COMPOSITIONS FROM THE BI-GAS
PROCESS BEFORE AND AFTER QUENCHING
COMPONENT
C02
CO
H2
CH,(
N2
H2S
H20
TOTAL
MOL \
BEFORE QUENCH AFTER QUENCH
15.7
22.9
30.4
6.8
0.5
0.5
23.2
100
12.0
17.5
23.3
5.2
0.4
0.4
41.2
100
-------
1,000,
500
w
H
W
w
I-J
o
100
50
10
10 20 30 40 50 60 70 80
WT % UNDERSIZE
90
Figure 7. Size distribution of char and ash from the
BI-GAS process effluent. Data from Grace
(1976).
60
-------
char is 86-89% fixed carbon, 2-1% volatile matter, and 12-10%
ash. The amount of char entrained in the gas is about 4,400
kg/hour. The inlet loading to the cyclone is about 230 g/Nm3
(100 gr/SCF). The cyclone is approximately 95% efficient so
the cyclone exit loading should be about 10 g/Nm3 (5 gr/SCF)
If Figure 7 is extrapolated, about 0.01% of the particulate
matter appears to be smaller than 1 ym.
After leaving the cyclone, the gas is quenched to about
350°C in a gas washer, and then passed through two sand bed
filters in parallel. The sand filters are used to remove fine
particles that can plug the fixed bed of the shift conversion
catalyst. The sand filters are cleaned alternately by a re-
verse flow of gas, which returns the reentrained dust to the
gasifier. The ash eventually leaves the system as molten slag.
The gas composition entering the sand filters is shown in
Table 17. The principal advantage to using sand filters in-
stead of a high efficiency scrubber is that it is possible to
clean the gas at a high enough temperature to prevent water
condensation, so that the steam present in the gas will be
available for the shift conversion process.
Combustion Engineering Gasifier
Combustion Engineering, Inc. has designed an atmospheric
pressure, entrained-flow type coal gasification system suitable
for generating low-BTU gas for electric power generation. The
gasification temperature is about 900°C, with a 1,600°C stage
for ash slagging and removal. This process has been described
by Katz et al. (1974) .
The gas leaving the gasifier is cooled to about 150°C by
a series of waste heat boilers before the gas is cleaned by
cyclone separators and a water scrubber. Condensing tars may
present a problem in plugging the particle removal equipment.
Long range plans are being considered for operating this pro-
cess at 10 atm pressure, for use in a combined cycle power gen-
eration system.
61
-------
Foster Wheeler Gasifier
Foster Wheeler Corporation has designed a demonstration
plant to gasify coal at 30 atm pressure in an air-blown, en-
trainment-type gasifier. The gas is to be used to fuel a gas
turbine and a gas-fired steam boiler. This gasification system
is described by Katz et al. (1974).
The gasification process is similar to the BI-GAS process,
with gasification at 1,000°C in the upper stage. The bottom,
ash slagging stage operates at 1,500°C. Char is removed from
the gas at near gasifier temperature and pressure by a series
of cyclones and is recycled to the gasifier. Waste heat boilers
are used to recover sensible heat downstream of the cyclones.
The final particulate removal stage is a water scrubber opera-
ting at about 100°C and system pressure.
B.Y.U. Gasifier
Brigham Young University is developing an entrained flow
type gasification process which uses the flow of gas and solids
in a downwards direction. This research has been described by
Katz et al. (1974).
Their bench scale tests operated at atmospheric pressure
and at temperatures from 650°C to over 1,300°C. The gasifier
is oxygen blown. A typical gas composition from this process
is shown in Table 18.
Texaco - Partial Oxidation Process
Texaco, Inc. has developed a partial oxidation gasifier
which has been used commercially for the production of hydrogen
for the synthesis of ammonia. This process has been described
by Katz et al. (1974) .
The gasifier operates at 15 atm pressure and about 1,400°C.
A pebble-bed heat exchanger is used to cool the effluent gas
and to preheat the air used for gasification. Most of the ash
is removed from the bottom of the gasifier. Some may also be
collected in the pebble-bed. The gas entering the pebble-bed
62
-------
Table 18. TYPICAL GAS COMPOSITION FROM THE
B.Y.U. ENTRAINED-FLOW GASIFIER
COMPONENT
CO
C02 '
H2
ci-u
C2 HU
H20
TOTAL
iligher Heating Value
MOL %
37.5
5.0
39.0
2.0
1.5
15.0
100
-12.5 MJ/Nm3
(340 BTU/SCF)
-------
is at about 1,300°C and leaves at about 300°C. The gas pressure
is at 15 atm.
MOLTEN BATH GASIFIERS
M.W. Kellogg Gasifier
The M.W. Kellogg Company has developed a molten salt gasi-
fication process which was described by Cover and Skaperdas
(1973) and by Katz et al. (1974).
The process uses a bath of molten sodium carbonate with
injection of steam and oxygen. Gasification occurs at about
900°C and 80 atm pressure. Ash is retained in the bath, and
there are no tars present. No particle emissions problem is
expected. A typical gas composition is shown in Table 19.
Molten Iron Process
The Applied Technology Corporation is developing a molten
bath process which uses crushed coal and limestone dissolved
in a bath of molten iron to generate a low-BTU synthesis gas.
The bath retains both the sulfur and the ash from the coal. Air
or oxygen is injected into the bath to gasify dissolved carbon
to carbon monoxide. This process has been described by LaRosa
(1973).
If air is used for the gasification process, the process
is called the "2-stage" process and generates a hot, low-BTU
gas for combustion in boilers or gas turbines. If oxygen is
used, the process is called the "PATGAS" process and the gas
is used as a synthesis gas. If the synthesis gas is upgraded
to pipeline quality, the process is called the "ATGAS" process.
Typical gas compositions for the three processes are shown in
Table 20.
The applicability of these processes for electric utility
and industrial boiler facilities has been studied by Jain and
Hixson (1972) . They noted that the amount of particulate emis-
sions had not been definitely established. LaRosa (1973) noted
that a 95 to 97% efficient electrostatic precipitator would be
64
-------
Table 19. TYPICAL GAS COMPOSITION FOR
KELLOGG MOLTEN SALT GASIFIER
1
COMPONENT
CO
C02
H2
CFU
H20
H2S
N2
TOTAL
Higher Heating Value
MOL %
26.0
10.3
34.8
5.8
22.6
0.2
0.3
100
-12 MJ/Nm3
(330 BTU/SCF)
65
-------
Table 20. TYPICAL GAS COMPOSITION FOR THE MOLTEN
IRON GASIFICATION PROCESSES
COMPONENT
CO
H2-
N2
TOTAL
MOL %
2 -STAGE PATGAS
30
IS
55
100
63.5
36.0
0.5
100
66
-------
necessary to reduce particulate emissions to a level that would
satisfy EPA performance standards.
The product gas temperature in the 2-stage process is about
1,100°C, and the pressure is slightly above atmospheric. In
some applications (ATGAS, synthesis PATGAS) the product gas may
be cooled in a waste heat boiler and then cleaned by water scrub-
bing. When the gas is to be used to produce pipeline gas (ATGAS),
the process is pressurized to about 70 atm.
Atomics International Gasifier
Atomics International is developing a molten salt gasifica-
tion process. This process has been described by Katz et al.
(1974). The process consists of the oxidation of carbon to CO
and partial pyrolysis and distillation of volatile matter in a
bed of molten sodium carbonate, sulfide, and sulfate.
The gasification takes place at 950°C and 5 atm pressure.
No tars are produced, and all the ash is retained in the bed.
The gas is expected to be clean enough for direct use in a gas
turbine.
One problem is the presence of alkali metal fumes in the
gas which may cause serious corrosion damage in the turbine.
IN-STTU GASIFICATION
The in-situ, underground gasification of coal is being
studied by the E.R.D.A. Laramie Energy Research Center. This
work has been reported by Nadkarni et al. (1973), Campbell et
al. (1974), Fischer et al. (1975), Schrider et al. (1975), and
Brandenburg et al. (1975). Recent information concerning the
particle emissions and control requirements has been obtained
from Schrider (1976).
In underground coal gasification, air is injected into
the well and the coal is ignited (usually by firing with a gas
fuel such as propane). The gasification process produces hy-
drogen, carbon monoxide, and various hydrocarbons. The gas
may be used as a low-BTU fuel gas for electric power genera-
67
-------
tion, or upgraded to a pipeline quality fuel gas. A typical
gas composition is shown in Table 21. The gas also contains
1 to 3% coal tar vapors.
The gas temperature at the surface can range from 250°C
to 350°C, at a pressure of about 2 atm. Pressures up to 7 atm
are possible in a large scale plant, but this would depend on
the depth of the coal seam.
Tests are under way to determine particulate mass emis-
sions, size distributions, and trace metal concentrations. No
data are available yet.
Scrubbing units are proposed for gas cleanup and no unique
problems are anticipated. At the relatively low surface temper-
atures and pressures, particle removal is expected to be much
easier than in low-BTU gas surface plants. Condensation of
tars may be a problem.
-------
necessary to reduce particulate emissions to a level that would
satisfy EPA performance standards.
The product gas temperature in the 2-stage process is about
1,100°C, and the pressure is slightly above atmospheric. In
some applications (ATGAS, synthesis PATGAS) the product gas may
be cooled in a waste heat boiler and then cleaned by water scrub-
bing. When the gas is to be used to produce pipeline gas (ATGAS),
the process is pressurized to about 70 atm.
Atomics International Gasifier
Atomics International is developing a molten salt gasifica-
tion process. This process has been described by Katz et al.
(1974). The process consists of the oxidation of carbon to CO
and partial pyrolysis and distillation of volatile matter in a
bed of molten sodium carbonate, sulfide, and sulfate.
The gasification takes place at 950°C and 5 atm pressure.
No tars are produced, and all the ash is retained in the bed.
The gas is expected to be clean enough for direct use in a gas
turbine.
One problem is the presence of alkali metal fumes in the
gas which may cause serious corrosion damage in the turbine.
IN-STTU GASIFICATION
The in-situ, underground gasification of coal is being
studied by the E.R.D.A. Laramie Energy Research Center. This
work has been reported by Nadkarni et al. (1973), Campbell et
al. (1974), Fischer et al. (1975), Schrider et al. (1975), and
Brandenburg et al. (1975). Recent information concerning the
particle emissions and control requirements has been obtained
from Schrider (1976).
In underground coal gasification, air is injected into
the well and the coal is ignited (usually by firing with a gas
fuel such as propane). The gasification process produces hy-
drogen, carbon monoxide, and various hydrocarbons. The gas
may be used as a low-BTU fuel gas for electric power genera-
67
-------
tion, or upgraded to a pipeline quality fuel gas. A typical
gas composition is shown in Table 21. The gas also contains
1 to 3% coal tar vapors.
The gas temperature at the surface can range from 250°C
to 350°C, at a pressure of about 2 atm. Pressures up to 7 atm
are possible in a large scale plant, but this would depend on
the depth of the coal seam.
Tests are under way to determine particulate mass emis-
sions, size distributions, and trace metal concentrations. No
data are available yet.
Scrubbing units are proposed for gas cleanup and no unique
problems are anticipated. At the relatively low surface temper-
atures and pressures, particle removal is expected to be much
easier than in low-BTU gas surface plants. Condensation of
tars may be a problem.
-------
Table 21. TYPICAL GAS COMPOSITION FROM
IN-SITU COAL GASIFICATION
COMPONENT
CO
C02
H2
CH,
N2
Ar
H2S
H20
Other Hydrocarbons
TOTAL
Higher Heating Value
MOL \
13.4
11.3
15.7
3.0
46.4
0.5
0.1
9.1
0.5
100
~4 MJ/Nm3
(-120 BTU/SCF)
-------
DIRECT COAL-FIRED GAS TURBINE PROCESSES
The removal of particulate matter from high temperature and
pressure gas streams has been a problem since the 1940s, when a
great deal of effort was expended in an attempt to develop a di-
rect coal-fired gas turbine for locomotives, and for power gen-
eration. Removal of fine fly ash from the combustion products
to the extent needed to avoid turbine-blade erosion proved to
be very difficult. No fully satisfactory solution to this prob-
lem has yet been reported in the more than thirty years of world-
wide development.
Much of the early work was sponsored by the Australian
government, and has been reported by Wisdom (1958), Morley and
Wisdom (1964), Atkin (1969) , and other reports from the Austra-
lian Aeronautical Research Laboratory. They used a 900 kW (1,200
horsepower) Ruston and Hornsby gas turbine fired with pulverized
coal. Fly ash was collected at temperatures from 650°C to over
750°C and at pressures up to a few atmospheres. Two stages of
multiple cyclones were used and turbine life appeared to be ac-
ceptable when firing brown coal (lignite) but was unacceptably
short when firing bituminous coal. Even with brown coal, how-
ever, turbine blade erosion and ash deposition problems were
severe. It was necessary to reduce the turbine inlet temper-
ature to about 650°C in an attempt to prevent the formation of
hard ash deposits.
In the U.S.A., the Locomotive Development Committee (LDC)
of Bituminous Coal Research, Inc. directed a program to develop
a coal-fired gas turbine locomotive. This work was conducted
during the period 1945 to 1958, and was reported in numerous pub-
lications authored by Yellott and Broadley. Turbine blade ero-
sion remained a major obstacle to their coal-burning turbine de-
velopment when they terminated their experimental work in 1959.
In the 1960s, the U.S. Bureau of Mines continued tests on
the LDC coal-fired turbine. They investigated new blade designs
70
-------
and high temperature and pressure particle removal techniques.
Their interest was in developing a coal-fired gas turbine for
power generation. No satisfactory solution to the turbine blade
erosion problem was achieved. The turbine blade life was limited
to less than 20,000 hours for rotating blades and 5,000 hours for
the stator blades. This was not sufficient to justify commercial
development. The work done at the Bureau of Mines has been re-
ported by Smith et al. (1966, 1967). Their coal-fired gas tur-
bine development program was terminated around 1970.
Coal-fired gas turbines were also developed in Great Brit-
ain and Canada. British development was reported by Fitton and
Voysey (1955). They developed open- and closed-cycle gas tur-
bines burning pulverized coal. The open- and closed-cycle sys-
tems are illustrated in Figures 8 and 9. In the open-cycle the
combustion products pass directly through the turbine. In the
closed-cycle only the cycle air, which flows in an entirely
closed circuit, passes through the turbine.
In the open-cycle turbine erosion of turbine blades was se-
vere. High temperature and pressure ash separators (cyclones) were
found to be unsatisfactory. Although the turbine is a poor col-
lector of ash, a very small amount of ash adhering to the blades
was found to significantly upset their aerodynamic form and re-
duce their efficiency. Corrosion resulting from ash deposition
was not very noticeable. More discussion of the turbine toler-
ance for particles is presented in a later section of this report.
Canadian development concentrated on a semi-closed-cycle
railroad locomotive gas turbine. This did not require elaborate
high temperature and pressure ash separators. This work has
been reported by Mordell (1957).
PROCESS EMISSIONS AND CLEANUP REQUIREMENTS
There are four basic methods by which coal might be fired
to an open-cycle gas turbine: pulverized coal, the gas producer,
the cyclone burner, and the spreader stoker. These methods have
been described, and their dust emissions have been characterized
7]
-------
COMBUSTION
CHAMBER
FUEL
COMPRESSOR
AIR
IN LEI-
DUST COLLECTOR
(~700°C)
TURBINE
Figure 8. Open cycle gas turbine,
72
-------
BURNER
AIR
HEATER
COMPRESSOR
COMBUSTION
CHAMBER
TURBINE
WATER COOLER
Figure 9. Closed cycle gas turbine
73
-------
by Hazard (1955). His results are summarized in Table 22. In
all cases, the dust loading was too large to allow satisfactory
turbine life. Only the gas producer would have satisfied current
emissions standards for coal-fired boilers (43 mg/MJ or 0.1 lb/
106BTU), and no method would satisfy the proposed future stan-
dards (21 mg/MJ or 0.05 lb/106BTU). The particle size distribu-
tions for these emissions are shown in Figure 10.
Dust removal for coal-fired gas turbines would be at the
maximum allowable turbine inlet temperature. At the time much
of the work was done (1950s) industrial turbine inlet tempera-
tures were on the order of 600 to 700°C. Current industrial tur-
bines can operate with inlet temperatures in excess of 1,000°C.
Pressures for coal-fired gas turbines are on the order of 4 to
10 atm (60 to 150 lb/in2).
The particulate emissions are predominantly ash and unburnt
carbon. The unburnt carbon may be recycled from the dust col-
lector to the combustor to increase efficiency. A reducing at-
mosphere should be maintained in the cyclones to prevent the un-
burnt carbon from igniting and burning in the dust collectors.
Common coal, coal ash, and turbine ash composition analyses are
presented in Table 23 (from Smith et al., 1966).
The gaseous emissions from an open-cycle coal-fired gas
turbine should be the same as for similar coal combustion in
a boiler. That is usually 83% nitrogen, 15% carbon dioxide,
2% oxygen, and trace amounts of sulfur oxides, nitrogen oxides,
unburnt gaseous hydrocarbons, and carbon monoxide.
Many ash removal devices were tried during the thirty years
of coal-fired gas turbine development. Parent (1946) and Yellott
and Broadley (1955) reported tests of cyclone and multiclone
separators at 5 atm pressure and 700°C. Overall efficiency de-
creased from about 95% to 86% as the temperature was raised from
room temperature to 700°C. At 540°C (1,000°F) and atmospheric
pressure the collection efficiency was only about 50% for parti-
cles smaller than 10 vim. The mass loadings had no significant
influence on the collection efficiency for both high and low
74
-------
Table 22. DUST EMISSIONS FROM COAL-FIRED GAS TURBINES (From Hazard,1955)
FIRING METHOD
Pulverized Coal:
Non-slagging, fine pulverization
Non- slagging, coarse pulverization
Non- slagging, coarse pulverization
Slagging
Spreader Stoker:
With ash reinjection
Without ash reinjection
Cyclone Furnace
Cyclone Furnace:
With dust collector
Gas Producer, fixed bed
Gas Producer, Pulverized:
Coal-fired vortex
ASSUMED
COMBUSTION
EFFICIENCY
%
95
95
90
98
98
94
100
100
100
100
COAL-FIRED
g/s
570
570
603
555
555
578
542
542
542
542
Ib/hr
4,520
4,520
4,780
4,400
4,400
4,580
4,300
4,300
4,300
4,300
TOTAL SOLIDS
DISCHARGED
WITH GAS
g/106J
4.8
4.8
6.6
2.2
1.3
3.4
0.6
0.6
0.3
1.7
lb/106BTU
11.2
11.2
15.4
5.2
3.1
7.9
1.4
1.4
0.7
4.0
DUST
COLLECTOR
EFFICIENCY
%
70
85
85
70
0
96
821
95. 52
90
80
DUST TO TURBINE
g/106J
1.5
0.7
1.0
0.7
1.0
0.1
0.4
0.1
0.03
0.3
lb/106BTU
0.7
1.7
2.3
1.6
2.4
0.3
0.9
0.3
0.07
0.8
1. Cyclone alone.
2. Cyclone + secondary multiple cyclone.
-------
100
80
60
40
a 20
w
m
o 10
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IM=
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::::::::*: 7 - :::: ::: ::
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10 20 30 40 50 60 70 80
WT % UNDERSIZE
90
95
98
Figure 10.
Particle size distributions from coal-fired gas
turbines. From Hazard (1955).
76
-------
Table 23. COAL, COAL ASH, AND TURBINE ASH ANALYSES (from Smith et al., 1966)
COAL CONSTITUENT
WEIGHT
CONSTI
TUENT
Si02
A1203
Fe203
Ti02
P205
CaO
MgO
Na20
K20
S03
PERCENT
COAL
ASH
39.2
23.1
17.8
1.7
0.8
5.9
1.8
1.6
1.2
6.9
H20 Ash
1.1 6.4
ASH FROM
SEPARATOR3
30.1
19.5
34.0
0.7
0.7
7.9
1.4
2. 3
0.8
2.4
S
2. 3
ASH
INLET
GASa
44.8
31.6
5.2
1.3
0.8
6.2
1.9
2.0
1.7
4.5
H2
5.2 1
ANALYSES
Ash
EXHAUST
GASa
40.3
29.5
7. 7
1.3
1.4
6. 3
1.3
2.2
1.8
8.2
N2 Total C 02 HEATING VALUE,
BTU/lb
.3 77.8
in Turbine
5.9
ON FIRST STAGE
BLADESb STATORS
27.3
21.9
6.2
1.6
3.7
5.6
1.9
3.3
4.6
19.8
28.3
23.1
5.9
1.9
3.6
6.7
1.8
2.6
4.3
19.6
14,143
LOOSE
ASHC
41.0
27.1
7.5
2.1
1.0
5.5
0.9
2.3
1.6
6.8
Contained 12 to 25 percent unburned carbon, depending on
the condition of the combustors. Does not include analyses
for constituents other than those shown.
Average analysis of ash deposits on the first and fifth-
stage stator and rotor blades.
cLoose ash in turbine, not hard deposits on blades.
-------
temperature tests. To maintain an overall efficiency of about
95%, the pressure drop had to be increased from about 3 inches
to 10 inches of water column. At best, cyclone efficiencies are
not high enough to adequately protect the critical turbine com-
ponents .
High temperature and pressure electrostatic precipitators
were developed for coal-fired gas turbines during the 1950s and
1960s. This work has been reported by Koller and Fremont (1950),
Thomas and Wong (1958), Shale et al. (1963, 1964, 1965, 1967,
1969), Robinson (1967, 1969), and Brown and Walker (1971). These
studies dealt primarily with the problems of corona generation
and the current voltage characteristics of electrostatic precip-
itators at high temperature and pressure. Although Brown and
Walker demonstrated the feasibility of electrostatic precipita-
tion up to 900°C and 7 atm the collection efficiency was signi-
ficantly reduced at high temperature (for the same precipitator
field strength).
It is not clear how far above 900°C it is possible to oper-
ate electrostatic precipitators. At higher temperatures , thermal
ionization will play an important role in limiting the precipi-
tator operating temperature. Strength of materials, thermal ex-
pansion, thermal ionization, and the prevention of explosion are
all potential problem areas that need to be resolved before high
temperature and pressure electrostatic precipitation can be com-
mercially feasible. Also, further investigation is required to
understand the interrelationship between gas pressure and gas
temperature at temperatures above 700 or 800°C.
The Bureau of Mines coal-burning turbine research also in-
volved studies of high temperature filtration. First et al.
(1956) and Kane et al. (1960) demonstrated the use of aluminum
silicate filters operating at 980°C. Filter efficiencies greater
than 99% were obtained with a composite filter of 20 pro, 8 ym,
and 4 pm fibers, operating at 760°C and about 13 cm W.C. pres-
sure drop. Designing a large flow rate, high temperature and
pressure baghouse, and developing means for cleaning the bags
78
-------
at high temperature and pressure are problem areas still requir-
ing further development.
Direct coal-fired gas turbine research was terminated
largely because of the turbine erosion problem. If effective
high temperature and pressure particle collection equipment is
developed and proven, then coal-fired turbines may become at-
tractive again. However current standards would require sulfur
dioxide control to be incorporated into the process, unless only
very low sulfur coals are used.
79
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MISCELLANEOUS HIGH TEMPERATURE AND/OR HIGH PRESSURE
PARTICULATE REMOVAL APPLICATIONS
The removal of particulate matter from hot gases at near
atmospheric pressure is a common problem among many industries.
Effluent gas from incinerators, fossil fuel fired boilers, met-
allurgical furnaces, cement and lime kilns, glass furnaces, and
many chemical processes can reach 700°C - 800°C or more if they
are uncontrolled.
As mentioned in earlier sections, it is often useful to re-
cover this heat in a waste heat boiler, and then clean the ef-
fluent gas at much lower temperatures. High temperature particle
collection, however, would protect the waste heat boiler from
fouling of the heat exchanger surfaces and reduce corrosion and
erosion problems. In some cases there is no need for waste heat
recovery, and the waste heat boiler is needed only to cool the
gas for particle cleanup. Therefore high temperature particle
removal would be advantageous.
Another major requirement for high temperature and pressure
particle collection is the control of emissions from catalyst
regenerators in fluid catalytic cracking units used in the petro-
leum industry.
There are also some particulate control applications where
high pressure particle removal is required at relatively low tem-
peratures. Many of the high-BTU gasification processes discussed
above propose venturi scrubbers operating at high pressure and
low temperature downstream of the waste heat boiler. The removal
of lube fume from natural gas pipelines also involves high pres-
sure and low temperature particle collection.
In this section, some of the above applications of high tem-
perature and high pressure particle collection will be discussed
There is not sufficient space to thoroughly discuss the clean-up
requirements of all processes with potentially hot effluent gases
In general, however, the requirements will depend on the appli-
80
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cable emissions regulations, the effluent gas temperature, and
the particle size, concentration, and composition.
If high temperature particle collection equipment could be
developed to operate at an efficiency and cost competitive with
that for low temperature collection, it is likely that high tem-
perature cleanup would be advantageous in many other applications.
FCC REGENERATOR
The fluid bed catalytic cracking (FCC) process is commonly
used in the petroleum industry to convert selected heavy frac-
tions of crude oil into gasoline. The conversion takes place
over a powdered catalyst at fairly high temperature (~500°C) and
moderately high pressure (2 to 4 atm).
The catalyst activity is reduced by the formation of a car-
bonaceous deposit on the catalyst. The catalyst is regenerated
by combustion in the regenerator. The regenerator discharges
gases and entrained dust to a flue gas line at temperatures rang-
ing from 600 to 700°C and at 2 to 4 atm pressure.
A schematic of an FCC unit is shown in Figure 11. The par-
ticulate cleanup equipment is shown downstream of the waste heat
boiler where the temperature has been reduced to about 300°C.
Some installations have proposed using a power recovery gas tur-
bine before the waste heat boiler. In this case, particulate
cleanup is necessary before the turbine at a temperature of 700 -
800°C.
Particulate emissions from FCC units have been reported by
many investigators including Wilson (1967), Vandegrift et al.
(1970), and Kalen and Zenz (1973). Generally two stages of cy-
clones are used before the final cleanup device. Typical mass
loadings leaving the second stage cyclones range from 0.23 to
2.3 g/Nm3 (0.1 to 1.0 gr/SCF). Typical size distribution ranges
are given in Table 24.
Particulate removal in the cyclones reduces the mass loading
to the third stage collector as well as limits the catalyst
losses from the system. Final stage collection must be suffi-
81
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CYCLONES
REGENERATOR
FCC PRODUCT
REACTOR
OIL IN £>
t
WASTE HEAT
BOILER
STACK
PARTICULATE
CLEANUP
AIR IN frl *
Figure 11. Fluid bed catalytic cracking unit
82
-------
Table 24. SIZE DISTRIBUTION FOR PARTICULATE
EMITTED FROM FCC REGENERATOR UNIT
From Wilson (1967)
PARTICLE DIAMETER, ym WT % IN SIZE RANGE
+40
20 - 40
10 - 20
4-10
2-4
0-2
3 -
23 -
22 -
7 -
1 -
.4 -
16
54
34
28
8
4
-------
cient to meet the emissions regulations (currently -0.03 grain/
SCF). Thus the final collector must have an efficiency up to
approximately 971. More stringent requirements would be neces-
sary if a power recovery turbine were being used.
The most common cleanup devices for FCC regenerators are
electrostatic precipitators and baghouses. Wet scrubbers and
granular bed filters have also been used successfully.
METALLURGICAL FURNACES
The open hearth furnace is a major heat source for steel
production. High temperature, atmospheric pressure particle
cleanup for open hearth furnaces has been discussed by Silverman
(1955) and Spaite et al. (1961). The particulate emissions con-
sist primarily of very fine iron oxide particles. The particles
range from 0.001 urn to over 1 ym in diameter, with the mass me-
dian diameter less than 0.5 ym. Mass loadings generally can
range from 0.23 to 4.6 g/Nm3 (0.1 to 2.0 gr/SCF).
Particle removal may occur either before or after the waste
heat boiler. In the waste heat boiler the gas temperature is
cooled from about 700°C to 250°C. If process steam is not needed,
the waste heat boiler may be just an additional cost to the par-
ticulate control equipment. In this case high temperature par-
ticulate control would save the cost of the waste heat boiler.
Another advantage to cleaning directly at high temperature is
that it minimizes fume deposition on heat recovery surfaces and
thus allows improved heat transfer and reduced maintenance and
cleaning problems.
The effluent gas must be cleaned sufficiently to satisfy
emissions and opacity regulations. The average mass loadings
are approximately 1.1 to 2.3 g/Nm3 (0.5 to 1 gr/SCF). The
allowable emission is of the order of 2.3 g/Nm3 (0.05 gr/SCF).
Thus at least 90-95° collection efficiency will be required.
Similar high temperature, atmospheric pressure particulate
cleanup problems exist in other metallurgical furnaces. Gray
-------
iron cupolas emit submicron fumes at temperatures ranging from
500 - 1,100°C. The fume is mostly iron oxide, with 20 to 30% by
weight smaller than 5 urn. Mass loadings are often about 2.3 g/
Nm3 (1.0 gr/SCF).
Brass furnaces emit lead oxide and zinc oxide fumes at tem-
peratures up to about 1,000°C. The size of the particles ranges
from 0.03 to 0.3 ym, with a representative mass loading of about
3.2 to 10.3 g/Nm3 (1.4 to 4.5 gr/SCF).
Secondary metals recovery furnaces emit high temperature
effluent gases which generally must be cooled before cleaning.
Stack temperatures can range from 500 - 800°C, with mass loadings
of 2.3 to 23 g/Nm3 (1 to 10 gr/SCF). Mass median diameters are
often smaller than 0.5 ym.
The fumes emitted from metallurgical furnaces are very dif-
ficult to control because the particle size is so small, with
MMDs often smaller than 1 ym. Collection efficiencies of 90 to
99% may be required to meet the emissions regulations. At low
temperature, this is usually accomplished using high efficiency
venturi scrubbers, electrostatic precipitators, or baghouses.
MHD POWER GENERATION
Magnetohydrodynamic (MHD) generation of electricity from
coal is being studied for possible use in large coal-burning
power plants. A simplified sketch of an MHD system fueled with
coal is shown in Figure 12. Powdered coal mixed with seed (a
reaction-promoting material) is burned in the combustor produc-
ing highly ionized gases in excess of 2,760°C (5,000°F).
An electric current is induced as the ionized gases from
the combustor pass through the magnetic field at high speed.
The electric current can then be tapped from the generator. The
hot gases leaving the generator are used to preheat the combus-
tion air, and then go to a conventional steam power plant.
Because the seed (K2C03) is relatively expensive, it is
removed from the product gases and reused. Approximately 901
recovery is desired at temperatures from 300 - 800°C. Cyclones
85
-------
BURNER
SLAG
ELECTRICITY
MHD
GENERATOR
-------
may be sufficient for seed recovery, although this has not been
demonstrated yet. Conventional flue gas cleanup downstream of
the steam power plant still will be required.
PARTICLE REMOVAL FROM HIGH PRESSURE PIPELINES
Coal-Natural Gas Pipeline
Spencer et al. (1965) reported the particulate removal
needs of pipelines proposed for the simultaneous transport of
pulverized coal and natural gas. The basic objective was to
lower the cost of transporting energy and to expand markets for
coal and gas.
Separation of solids is required at the line terminal or
market delivery points and at compressor stations along the
way. The gas is at high pressure and low temperature and con-
tains 2 - 5 kg coal/kg gas. They anticipated solids removal to
0.0009 g/Nm3 (0.002 gr/SCF) for suitable use by consumers.
Thus effectively 100% separation of the coal and gas was re-
quired. The cleanup conditions and requirements are summarized
in Table 25. The proposed separation system consisted of a
first stage of cyclones followed by a bag filter or possibly an
electrostatic precipitator.
Removal of_ Oil Fume from Natural Gas Pipeline
The removal of submicron lube fume from natural gas pipe-
lines has been shown to raise the line efficiency (Hall et al.,
1968 and Eaton, 1969). The pipeline pressure is about 50 atm,
and the temperature is about 40°C.
Lubricating oil fume appeared to act as condensing and
concentrating nuclei for dissolving lighter hydrocarbons. The
hydrocarbons drop out and cause a deterioration in line effi-
ciency.
The particle mass concentration is very low (-10"" gr/SCF)
and.the particles range from 0.1 to 1 ym in diameter. Gas flow
rates are on the order of 7,000 Nm3/min (250,000 SCFM).
Design specifications for the electrostatic precipitator
87
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Table 25. PARTICLE COLLECTION REQUIREMENTS
FOR COAL - NATURAL GAS PIPELINES
FACTOR
Gas Composition:
Gas Temperature:
Gas Pressure:
Particulate:
Particle Size
Distribution:
Particle Density:
Electrical Resistivity:
Gas Flow Rate:
Solids Concentration:
Required Concentration
of Delivered Gas:
Overall Efficiency:
TYPICAL SPECIFICATION
941 methane, negligible moisture
16 - 38°C
40 - 55 atm
Pulverized bituminous coal
70 - 80% <74 urn
50 - 60% <40 pro
20 - 30% <10 urn
1.3 - 1.5 g/on3
Low
300 mVmin (-10,000 ACFM)
2 - 8 kg coal/kg gas
0.0046 g/Nm3 (-0.002 gr/SCF)
>99.9999%
88
-------
reported by Hall et al. (1968) are given in Table 26. The pre-
cipitator was found to be suitable, however development was
discontinued because recent reductions in required throughput
in pipelines have eliminated the economic advantage of removing
the oil fume.
GEOTHERMAL POWER PLANT
A geothermal power plant, producing steam at 350°C and 50 -
80 atm was reported by Krikorian (1972). Silica particles en-
trained in the steam can erode and/or scale the turbine blades.
The maximum permissible silica concentration in steam with 80
atm of steam pressure at the turbine inlet is about 0.05 ppm
(2.6 x 10-5gr/SCF).
If geothermal steam is to be used directly in turbine oper-
ations at high pressures, it is likely that it will need puri-
fication to prevent inefficient turbine operation. One method
is to scrub the steam with high-purity water before passing it
through the turbine. Unfortunately such a process cools the
steam, degrades its energy, and lowers the efficiency. Also,
after scrubbing, the steam is saturated and, if used in the tur-
bine, could lead to erosion of the turbine blades by impinging
drops of water.
Solid phase scrubbers (for example, limestone) have been
considered.
89
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Table 26. PRECIPITATOR DESIGN SPECIFICATIONS
FOR NATURAL GAS PIPELINES
From Hall et al. (1968)
FACTOR
DESIGN SPECIFICATION
Gas Composition:
Gas Temperature:
Gas Pressure:
Gas Viscosity (basis
of CHO :
Gas Flow Rate at
Standard Conditions:
Collection Efficiency:
Particle Size of Oil
Fume:
Particle Concentration
Natural Gas - 94% methane
30 - 50°C
55 atm
-1.2 x 10"" poise
-7,000 Nm3/min
(208,000 - 278,000 SCFM)
-991 (by weight)
Est. 0.1 to 1.0 micron diameter
0.03 g/Nm3 (0.07 gr/SCF)
90
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GAS TURBINE PARTICLE TOLERANCES
In many high temperature and pressure energy processes the
effluent gas is used to drive a gas turbine and thereby generate
electric power. The useful life of the gas turbine depends on
the extent of erosion and corrosion damage to the internal com-
ponents of the turbine. The extent of damage depends upon the
concentration and size of particulate matter suspended in the
gas, and upon the chemical composition of the gas and particu-
lates.
Erosion damage results from the inertial bombardment of
particles onto the stator and rotor blades of the gas turbine.
The erosion damage is proportional to the kinetic energy of the
particulate matter striking the turbine blades. Therefore the
damage is more severe when larger, more massive particles are
present in the gas stream. Large concentrations of very small
particles may be even less harmful than their total mass would
imply because their trajectories would tend to follow the gas
streamlines and thus would be less likely to impact the turbine
blades.
Corrosion damage depends on the amount of particulate that
adheres to the turbine surfaces as well as the chemical compo-
sition of the gas and particulate. In general, the most cor-
rosive compounds, are those containing sodium and potassium.
Liquid deposits of such compounds can form inside the turbine
at temperatures between about 500°C and 1,000°C. These molten
films attack the protective oxide scale on the blade material,
and thus initiate accelerated oxidation of the turbine compo-
nents .
The buildup of particulate deposits on the turbine blades
also can significantly impair the aerodynamic performance of
the blades. Furthermore, large agglomerates can break off
from such deposits and cause additional erosion damage.
91
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SMALL TURBINES FOR MILITARY USE
Turbine blade erosion by entrained dust has been a problem
with turbine engines used in military helicopters and tracked
ground vehicles (tanks). An extensive study of sand and dust
erosion in gas turbine engines was performed for the U.S. Army
(reported by Smeltzer et al., 1970a,b). Their principal results
are summarized below.
Erosion per particle is directly proportional to particle
kinetic energy.
Erosion ceases for fine particles (£20 ym) below about
30 - 60 m/s. This suggests that a certain minimum particle
energy is necessary to cause erosion.
Corner-oriented particle impacts cause the preponderance
of erosion damage.
The energy absorbed by the target is translated into both
metal deformation and metal removal. The metal deformed
is typically 300 - 400 times greater in volume than that
eroded.
These tests were conducted using Arizona road dust (70% Si02)
with a size distribution as shown in Table 27.
Table 27. SIZE DISTRIBUTION OF ARIZONA ROAD DUST
Diameter, ym Weight %
0-5 39±2
5-10 . 18±3
10-20 16±3
20-40 18±3
40-80 9±3
Tests on an air cleaner for the U.S. Army Overland Train
Mark II were reported by the Donaldson Company (1964). They
obtained an overall efficiency of 851 with their cyclone-type
dust collector. A concentration of 0.02 g/Nm3 (0.01 gr/SCF) was
found to be satisfactory to extend the turbine life from 200 hours
to well over 460 hours (no significant damage after 460 hours).
92
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Thomas (1968) reported tests of a cyclone air cleaner on a
small, general-purpose military gas turbine. The unprotected
turbine failed after 6 hours and 50 minutes. The turbine life
was extended to 132 hours with the cyclone air cleaner (O.Olg/m3
dust loading).
The requirements for air cleaners for Army uses were ex-
pressed by Barnett (1976). Military helicopter turbine engines
have limited duty cycles and therefore can survive with 80 - 90%
overall particle removal. Tracked ground vehicles using gas
turbine engines require 99 - 99.51 removal of the standard Ariz-
ona road dust (Table 27). Reciprocating engines require a
similar degree of particle removal.
Other work performed for the Army was reported by Wood and
Hafer (1966). They studied the mechanisms of dust erosion and
the sintering of dust at high temperatures. They found that the
erosion rate is proportional to the impact velocity squared.
Using a 901 Si02 dust, they found that fusion and adherence to
the target began at about 950°C and increased as the temperature
approached 1,100°C.
Erosion of turbine blades in steam and metal vapor turbines
has been investigated under NASA sponsorship (Spies et al., 1968,
and Pouchot et al., 1971). They were concerned with turbine
erosion resulting from the impingement of condensed drops of
potassium or mercury in metal vapor turbines used for space
power systems. The erosion damage was found to be proportional
to the kinetic energy of the impinging drops. The condensate
particles were so small that less than 51 impinged on the tur-
bine blades.
GAS TURBINES FOR UTILITY USE
Corrosion
To successfully operate a gas turbine on the exit gases of
a high temperature and pressure energy process, it is necessary
to limit the concentration of alkali-metal compounds. Particu-
lates must be limited to levels low enough that excessive de-
-------
position, hot corrosion, and erosion of turbine components do
not occur. Westinghouse Electric Corporation has studied these
problems in connection with their fluidized bed combustion pro-
cess evaluation (Keairns et al., 1975), and their coal gasifi-
cation process development (Chamberlin et al., 1976).
The concentration of alkali-metal compounds must be suffi-
ciently low to prevent the formation of liquid films of sulfates
and chlorides which can initiate the hot corrosion of turbine
components. The turbine tolerance for sodium is shown in Fig-
ure 13 (from Keairns et al., 1975), assuming sodium is the only
alkali metal present.
The tolerance for sodium is reduced by a factor of about
four when potassium is present. The reason is that the sodium
sulfate-potassium sulfate (Na2S04 - KaSOi.) eutectic melt has a
lower melting point (832°C) than the Na2SO,, alone (884°C) . The
presence of potassium and sodium chlorides permits a four-
component eutectic of even loi\:r melting point (514°C).
Deposition
If the alkali-metal compound tolerances are met, liquid
films should not be present on either the turbine hardware or
on the surface of the particles. Deposits resulting from the
impaction and dry sintering of fine particles can occur, es-
pecially at high temperature. These deposits can break off
and cause erosion damage or can build up and impair the aero-
dynamic performance of the turbine blades. At temperatures
below 667°C (1,250°F) erosion rather than deposition is the
factor expected to limit turbine life. At higher temperatures
deposition should become more important.
Figure 14 shows the capture efficiency of a gas turbine
rotor blade as a function of particle diameter. Approximately
101 of the submicron particles are captured by the turbine
blades. Experimental work by MacFarlane and Foster (1972)
indicates that the capture efficiency reaches zero for about
0.5 ym diameter particles and then increases very slowly be-
94
-------
4,00q|j||so GONC.,ppm
X
20 40 60 80 100
CHLORINE CONG., ppm
120
Figure 13.
Turbine tolerance for sodium as a function
of the concentration of chlorine and oxides
of sulfur, for fluid bed combustor.
From Keairns et al. (1975)
System pressure:
Oxygen:
Water vapor:
10 atm
1.7%
8.51
95
-------
100
u
w
i i
u
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i
U
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immmmmm
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mmmmmmmmmmmmmmf tmmmmmmmmmmm '
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0 i! i! i' ii Ill
0 i ;! i'!i ;; ; i
n IIIIHIIillllllll ;;,;,,; | | ; J ; S 1 iiiilllillili
'
: : PARTICLE DENSITY i
= ' Opp - 1.5 g/cm3 ;; :
A P « 2.5 g/cm3 ;;
3 4 5 6 78 9 10 11 12 13
PARTICLE DIAMETER, ym
Figure 14. Particle capture efficiency for rotor
blades of a gas turbine.
From Chamberlin et al..(1976)
96
-------
cause of diffusion. The capture efficiency rises to about 1%
for 0.01 ym particles and 25% for 0.001 ym particles.
MacFarlane also noted that significant deposition on the
trailing edge of the blade upset the boundary layer and caused
separation of flow to occur earlier on the blade surface. This
caused a decrease in turbine efficiency.
The above discussion indicates that particle deposition
can be a substantial problem. However, more quantitative work
must be done in order to specify realistic tolerances for par-
ticle deposition in utility size gas turbines.
Erosion
Large gas turbines for utility use show less erosion damage
than small gas turbines. This is partly because the larger tur-
bines have larger blade chords and thicker edges. Also, as the
passage through the turbine shrinks relative to the dust size,
the number of impacts increases, the impact velocity decreases
slightly, and the impact occurs at more damaging impact angles.
Taking these into account, Keairns et al. (1975) predict that
a full-scale turbine would erode about 80% of the rate of a
half- linear-scale turbine.
The Australian gas turbine experience has been reported by
Morley and Wisdom (1964), Duke (1968), and Brasinikas (1970).
They found no erosion for particles smaller than 5 or 6 ym in
diameter. They found that the erosion rate is proportional to.
the "n" power of the velocity. The exponent "n" ranged from 2
to 5 depending on the ash and blade material. Black coal ash
appeared to be about 10% as erosive as silica dust. Erosion
damage was noted on the turbine shroud as well as the blades.
Morley and Wisdom (1964) noticed a serious deposition prob-
lem in addition to erosion. They found that at high tempera-
tures (700°C) about 25% of the ash deposits in the turbine.
U.S. Coal-fired gas turbine experience was reported by
McGee et al. (1969). They used a fly ash test dust with a size
distribution as shown in Table 28. They found a dust loading
97
-------
of 0.023 g/Nm3 (0.01 gr/SCF) to be excessive for allowing com-
merically acceptable blade wear (at 650°C). They anticipated
that the dust loading will need to be as low as 0.002 g/Nm3
(0.001 gr/SCF).
Table 28. FLY ASH TEST DUST
(From McGee et al., 1969)
Diameter, ym Weight %
30-35 2
20-30 5
15-20 22
10-15 19
7-10 31
5-7 15
5 6
Robson et al. (1975) have reported that a total dust load-
ing of 4 ppm (0.0012 gr/SCF) would allow a suitable turbine
life. In a typical application, this would require that ef-
fectively all particles larger than 2 urn would have to be col-
lected. Also 90?d collection of particles smaller than 2 ym
would be required.
There is still some disagreement as to the potential harm
to turbines ingesting fine particles. Some authors have sug-
gested that turbine requirements should be specified in two
size ranges. Westinghouse (1974) suggested an allowable con-
centration of 0.34 g/Nm3 (0.15 gr/SCF) with no more than 0.023
g/Nm3 (0.01 gr/SCl:) larger than 2 ym. A recent Program Oppor-
tunity Notice from the l-.R.D.A. Fossil Energy Program (PON FE-7,
July 26, 1976) requests potential developers of high temperature
and pressure electrostatic precipitators. They suggest that re-
ducing the dust loading to below about 1.7 g/Nm3 (0.75 gr/SCF)
for particles in the 0 - 2 ym range, and to below 0.002 g/Nm3
(0.001 gr/SCF) for particles in the 2 - 6 ym range would be suf-
ficient to protect the turbine.
98
-------
Much of the literature is in agreement that at some diam-
eter (1 to 5 ym) particles no longer cause significant erosion
damage. The reason is that the particles are smaller, are
slowed down in the boundary layer, and impact with insufficient
kinetic energy to erode the blade material. Also the capture
efficiency is much lower for small particles (at least down to
0.01 ym). However, as discussed above, particle deposition may
still be a problem even when direct erosion is insignificant.
The problems of particle deposition, corrosion, and ero-
sion of turbine components are far from settled. There is some
uncertainty as to the minimum allowable particle diameter and
the maximum tolerable concentration of fine particles. Data
are lacking, and theory is inadequate to determine this infor-
mation. Therefore it would be prudent to design high temperature
and pressure particle collection equipment to meet the required
mass concentration reduction for all particle sizes.
Emissions Requirements
In any case, the particulate emissions from the gas turbine
must satisfy the requirements of the Federal New Source Perfor-
mance Standards. If the particle size distribution is suffi-
ciently small, it is possible to exceed the mass emissions stan-
dards (or possibly the opacity standards) while still allowing
satisfactory turbine life. In this case, additional particulate
removal equipment might be needed downstream of the turbine be-
fore the effluent gas could be exhausted to the atmosphere.
As an example, Figure 15 illustrates the relative importance
of the turbine inlet requirements and emissions standards for
emissions from a fluidized bed combustion process. The solid
lines represent emissions standards while the dashed line rep-
resents the turbine requirements.
The curves were obtained using the size distribution re-
ported by Exxon Research and Engineering Co. (1976) as leaving
the second cyclone. Curve 2 is for the current new source per-
formance standard for particulate emissions from a coal-fired
99
-------
o
o
u
w
(X,
w
2
O
ii
E-i
CJ
,-J
.-J
O
BASIS FOR CURVES
MMD = 8 ym
a = 2.7
n r /
p = 1.5 g/cm
= l-exp(-Ad*a)
EMISSIONS STANDARD
EMISSIONS STANDARD ft
= 0.05 lb/106BTU
A = 0.50
^ iff mt ffiiiMi^'yiirtWHJ
pi ffli Tftt W - fi'f rtS tHfinr i:/
t- ' I J^-l -* i I*1"! --* r ^1 * - -J ,-( f-^t » »«-»-- -T«-f4 - - n
TURBINE REQUIREMENTS
t 0.0012 grain/SCF >2ym
0.15 grain/SCF <2ym
E A = 3.0 >2um
I A = 0.06 <2um
1.0 1.5 2.0
PARTICLE DIAMETER, pm
Figure 15. Particle emissions standards versus turbine requirements
for the fluidized bed combustion of coal.
-------
boiler (<0.1 lb/106BTU). Curve 1 shows what the effect would
be if the standard were reduced by half (to 0.05 lb/106BTU).
In both cases, the turbine requirements (curve 3) are less
stringent for particles smaller than 2 ym, and more stringent
for particles larger than 2 ym.
Figure 15 was obtained using the "cut diameter" approxima-
tion for performance of particulate control equipment presented
by Calvert et al. (1974). Figure 15 should not be taken as an
accurate design criterion, but rather as an illustration of the
relative importance of the emissions standards and turbine re-
quirements as a function of particle size.
TURBINE INLET TEMPERATURE
The efficiency of a gas turbine is directly related to the
turbine inlet temperature. As inlet temperatures for industrial
gas turbines increase, it is likely that particle collection
will be required at higher temperatures than at present.
Figure 16 shows a projection of industrial turbine inlet
temperatures taken from Hedley (1974). This prediction is
based on trends in commercial and military aircraft engines and
assumes that sufficient R§D money is available to maintain
steady progress.
Gas turbine inlet temperatures may be increased by improv-
ing the cooling techniques for the turbine blades, or by find-
ing materials which maintain satisfactory strength at extreme
temperatures. It has been suggested that ceramics can be used
for much of the internals of the turbine (burners, seals, noz-
zles), and may eventually be suitable as turbine blades. Ceramic
lined turbines would enable inlet temperatures approaching
1,400°C to 1,500°C.
Therefore it is conceivable that future high temperature
particle collection equipment could be needed at significantly
higher temperatures than currently required.
101
-------
w
1,800
1,600
1,400
1,200
g 1,000
800
600
1950
1960 1970
CALENDAR YEAR
1980
1990
Figure 16. Estimated industrial gas turbine inlet
temperatures. From Medley (1974).
102
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112
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TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-071
2.
3. RECIPIENTS ACCESSION-NO.
4. TITLE ANDSUBTITLE
High-temperature and High-pressure Particulate
Control Requirements
5. REPORT DATE
July 1977
6. PERFORMING ORGANIZATION CODE
7.;AUTHOR(S)
B. PERFORMING ORGANIZATION REPORT NO.
Richard Parker and Seymour Calvert
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Air Pollution Technology, Inc.
4901 Morena Boulevard, Suite 402
San Diego, California 92117
10. PROGRAM ELEMENT NO.
E HE 62 3 A
11. CONTRACT/GRANT NO.
68-02-2137
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final: 5/76-5/77
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES JERL-RTP project officer for this report is Dennis C. Drehmel,
Mail Drop 61, 919/541-2925.
16. ABSTRACT
The report reviews and evaluates high-temperature and high-pressure
particulate cleanup requirements of existing and proposed energy processes. The
study's aim:? are to define specific high-temperature and high-pressure particle
removal problems, to indicate potential solutions, and to identify areas where
current knowledge and data are inadequate. Primary emphasis is on the requirements
of processes now being proposed as clean methods for obtaining energy from coal;
that is, fluidlzed-bed coal combustion, coal gasification, and direct coal-fired gas
turbines. Also considered are the cleanup requirements and experience of other
high-temperature and/or high-pressure processes such as fluid-bed catalytic crack-
ing units, metallurgical furnaces, geothermal power plants, high-pressure pipelines,
and magnetohydrodynamic power generation. Current knowledge concerning turbine
erosion, corrosion, and deposition problems is also presented.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Gro'i"
I3B 21D~
11G
14B
Air Pollution Coal
Dust Fluidized Bed
High Pressure Tests Processing
High Temperature Tests
Energy Conversion Coal Gasification
Techniques Gas Turbines
Air Pollution Control
Stationary Sources
Particulate
10A
13H,07A
13G
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
119
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
113
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