United States      Industrial Environmental Research EPA-60O/7-79-171
Environmental Protection  Laboratory         ju|y 1979
Agency        Research Triangle Park NC 27711
Summary of Gas Stream
Control Technology
for Major Pollutants
in Raw Industrial Fuel Gas

Interagency
Energy/Environment
R&D  Program Report

-------
                  RESEARCH REPORTING SERIES


Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional  grouping  was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:

    1. Environmental Health Effects Research

    2. Environmental Protection Technology

    3. Ecological Research

    4. Environmental Monitoring

    5. Socioeconomic Environmental Studies

    6. Scientific and Technical Assessment Reports  (STAR)

    7. Interagency Energy-Environment Research and Development

    8. "Special" Reports

    9. Miscellaneous Reports

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-agency  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 sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects;  assessments of,  and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental  issues.
                       EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for  publication. Approval does not signify that the contents necessarily reflect
the  views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.

This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.

-------
                                                EPA-600/7-79-171

                                                         July 1979
Summary of Gas Stream Control Technology
            for Major Pollutants in Raw
                  Industrial  Fuel  Gas
                               by

                   F. D. Hoffert, W. Y. Soung, and S. E. Stover

                        Hydrocarbon Research, Inc.
                    Lawrence Township, New Jersey 08648
                        Contract No. 68-02-2601
                       Program Element No. EHE623A
                     EPA Project Officer: William J. Rhodes

                   Industrial Environmental Research Laboratory
                    Office of Energy, Minerals, and Industry
                      Research Triangle Park, NC 27711
                            Prepared for

                  U.S. ENVIRONMENTAL PROTECTION AGENCY
                     Office of Research and Development
                         Washington, DC 20460

-------
                            ABSTRACT

          This report is a summary of coal gasification and clean-up
technology with emphasis on methods for producing a clean industrial
fuel gas as defined by agreement for study purposes.  The coal-derived
industrial fuel discussed is one which produces no more than 0.5 Ibs
of S00, O.lf Ibs of NO  and 0.1 Ibs of particulates per million Btu
     £.   -  .          X
of fuel gas.  In general, existing state-of-the-art control technology
will allow these emission guidelines to be met although the end use
for the fuel gas will strongly influence the choice of the pollution
control technology that is used.

          Many but not all important factors pertinent to control
technology application were considered.  Costs are an example of
an important factor which was not evaluated because the objective
was to first determine appropriate technology that could be applied.
Emissions other than the three major pollutants indicated were given
only a cursory treatment.  Nevertheless, a general overall background
of control technology for industrial fuel  gas has been covered.

-------
                             SUMMARY

          Industrial fuel gas, classified as a fuel  whose combustion
products exhaust directly to the atmosphere, logically fits into emission
guideline levels established by the Clean Air Act of 1971 even though
the S02 emission level was not specifically covered by that regulation.
For this reason, tentative guidelines for emissions of 0.5 Ibs S0?,
0.4 Ibs NO  and 0.1 Ibs of particulates per million Btu of coal-
derived gaseous fuel were selected for study purposes.  With worsen-
ing fuel shortages, the importance of industrial fuel gas is expected
to increase and its manufacture and control technology should be
examined.

          Commercially available gasification and clean-up technology,
as individually described, has promised, even if not yet demonstrated,
the availability of systems to convert coal into fuel gas while con-
trolling at least sulfur, nitrogen and particulates to levels satis-
factory for pipeline gas.  The less stringent standards for industrial
gas, as  illustrated by the lower percent removal of major pollutants,
are then within reach with some imaginative design because new or
previously rejected technology might be appropriate under such circum-
stances.  Since this  lowered clean-up requirement makes  it possible
to reconsider some old technology as well as modern processes, design
techniques and typical design for the use of  iron-oxide processes
have been made and compared to the Stretford  process.

          End use of  the fuel gas must also be considered.  If the
fuel is  used  in a cement kiln, clean-up  requirements might be minimal
because  SO. would be  removed  in the cement-making process and parti-
culate  control of process exhaust gas would preclude  the need for
                               ill

-------
particulate removal from fuel gas.  Carbon dioxide, which need not
be removed from industrial fuel, may lessen thermal NO  formation
due to cooler combustion.

          While sulfur removal is covered in some detail, the prob-
lems of nitrogen, tar and particulates also are considered.   High
levels of nitrogen compounds may deactivate or cause losses  in the
sulfur clean-up processes.  Consequently, when nitrogen levels are
high, HCN might be controlled by an HCN guard or polysulfide scrub-
bing and basic nitrogen compounds with acid scrubbing.  Use  or dis-
posal of tars require more study because of the high sulfur  and
nitrogen contents.  Combustion of a typical tar from coal gasifica-
tion would probably yield a flue gas exceeding NO  emission  guide-
lines.  By-product tar utilization  is, therefore, a fertile  field
for future research.  Particulate control technology demonstrates
capability to achieve at  least 0.0001 grains per SCF while the
industria] fuel guideline has been estimated to be 0.1 grains per
SCF.  Technology  is available and the proper control systems can
then be selected  to meet the particulate level required for  speci-
fic  industrial fuel use.

-------
                         TABLE OF CONTENTS
ABSTRACT                                                         ii
SUMMARY                                                         iii

Introduction                                                      1

Conclusions and Recommendations                                   6

Section A - Description of Gasification Systems                   8

          1.  Discussion of Basic Technology                      9
          2.  Koppers-Totzek Process                             15
          3-  Lurgi Process                                      21
          b.  Riley-Morgan Process                               27
          5.  WeiIman-Galusha Process                            30
          6.  Wilputte Process                                   35
          7.  Winkler Process                                    39
          8.  Woodall-Duckham/Gas Integrale Process              *»6

Section B - Description of Gas Clean-up Systems on
            Operating Gasifier Installations                     53

          1 .  Introduction                                       5^
          2.  Clean-up System for the Koppers-Totzek Gasifier    5$
          3.  Clean-up System for the Lurgi Gasifier             68
          k.  Wilputte Gas Clean-up System                       77
          5.  Clean-up System on Woodall-Duckham/Gas
              Integrale Gasifier Effluent                        80

Section C - Comparison of  Iron Based Clean-up  Processes and
            the Stretford  Process                                86

          1.  Introduction                                       87
          2.  Development  of Gas Clean-up Processes              89
          3.  Basic Chemistry                                    92
          4.  Design Basis and Assumptions                       97
          5.  Iron Oxide Sox Purifiers                           99
          6.  Liquid-phase Iron Oxide Processes                  lO^t
          7-  Stretford Process                                  108

Section D - Operational Evaluation  of Converter Output
            Control Systems                                      112

           1.  Typical  Clean-up Systems  for  Industrial Fuel       113
          2.  Dependency of  Clean-up on End Use of  Fuel Gas      116
          3.  Sulfur  Emission  Control with an  Industrial  Fuel    118

-------
          k.  Effect of Nitrogen Compounds on Chemical
              Clean-up Systems                                  121
          5.  Tar and Oil By-products                           123
          6.  Reduction of Particulates for Industrial Fuels    128

References                                                      130

Append i ces

          A.  Generalized Formula for Sulfur Removal From a
              Fuel to Meet a Specific Level of SO- Emissions    136

          B.  Sample Calculations of Clean-up Processes         138

          C.  Material Balances on Nitrogen and Sulfur
              Components for Riley-Morgan Gasification
              Systems                                           T*9
                                VI

-------
                         LIST OF TABLES
A-2.1     Gasification Plants Using the K-T Process      19

A-3.1     List of Lurgi Gasifiers                        25

A-7.1     Plant List - V/inkler Generators                H

A-8.1     WD Two-Stage Coal Gasification Plants          ^9

B-2.1     Koppers-Totzek Gasifier Gas Compositions       61

B-2.2     Koppers Coal Gasification - Water Analysis,
              Kutahya, Turkey                            &k
                                 vii

-------
                        LIST OF FIGURES


                                                        Page


A-l.l     Generalized Performance of Gasifiers           12

A-1.2     Generalized Performance of Gasifiers           13

A-2.1     Koppers-Totzek Gasifier                        16

A-3.1     Lurgi Pressure Gasifier                        23

A-4.1     Riley-Morgan Gas Producer                      29

A-5.1     WeiIman-Galusha Fuel Gas Generator             31

A-6.1     Wilputte Gasifier                              37

A-7.1     A Winkler Gasifier                             *4l

A-8.1     Two-Stage Gasification                         A8

B-l.l     Sulfur Removal Requirement for
               Industrial Fuel                            56

B-2.1     Koppers-Totzek Process - Gasification,
              Cooling and Particulate Removal            59

B-2.2     Gas Preparation for Synthesis                  60

B-3-1     Lurgi Process « Gasification and Ash
              Handling                                   69

B-3-2     Lurgi Process - Gas Cooling, Shift
              Conversion and Gas Liquor Processing       70

B-3-3     Rectisol Gas Clean-up and Methanation          71

B-5.1     WD/GI Process for Cold Desulfurized Fuel
              Gas                                        31

C-5-1     Iron Oxide Design Factor Chart (American
              Practice)                                 101
                               viii

-------
                    LIST OF FIGURES Continued
C-6.1     Flow Diagram of Liquid Iron Oxide Process
              for H2S Removal                                    105

C-7-1     Flow Diagram of Stretford Process                     109

D-3-1     Fuel Gas Desulfurization System Schematic
              Diagrams                                          120
                               ix

-------
INTRODUCTION

          Gas manufactured from coal (General Reference #6) was
first produced in the late 18th century by heating coal in the
absence of air.  To supply the necessary heat, additional coal
was burned outside of the vessel.  Combustion gases were segre-
gated from the air-deficient interior gas.  By 1812, the first
coal-gas company was chartered in London to distribute a product
used for lighting.  Four years later, the first U.S. company was
chartered in Baltimore.
          Initially, gas with a heating value ranging from
to 560 Btu per cubic foot (depending on the type of coal and
process conditions) was produced by destructive distillation of
coal.  Coke ovens, which manufacture coke mainly for steel  indus-
try use, produce an off-gas similar in composition.  This coke-
oven gas, where available, often supplemented the  supply of coal
gas made from plants involving the destructive distillation of
coal.  Unfortunately, about 70 percent of the feed coal  remains
as a solid residue  in these processes and disposal of the residue
was a  problem except in the coking- type operation  where  coke was
the primary product.  The solution to the disposal problem  for
the carbon-rich residue lead a step beyond  distillation  to  gasi-
fication of the residue.

          Coal gasification, which depending on  the  process may  in
the same vessel be  preceded by distillation,  involves  the subsequent
reaction of the solid with air or oxygen  and steam.   The distillation
step gases which  are first  released have  a  high  3tu  content because
methane and higher  hydrocarbons  contained  in  the coal  are among  the

-------
first components to emerge as the coal decomposes.  The gasification
step makes a gas with a much lower heating value because the gas
produced is essentially a mixture of carbon monoxide, carbon dioxide
and hydrogen.

          The gasification of coal follows two basic paths, using
either air or oxygen supported combustion to supply required heat.
This heat-producing step is necessary to maintain endothermic gasifi-
cation reactions.  Gasification with air produces a clean gas of low
(100-250 Btu/cu.ft.) heating value due to a significant concentration
of nitrogen introduced in the air supply.  To make a low inert content
gas suitable for synthesis, it is necessary to gasify with oxygen.
This second route produces clean gas of either medium (250-550 Btu/cu.ft.)
or high (950-1000 Btu/cu.ft.) heating value.  The latter case requires
additional process steps to reach the higher heat content and, as such,
is not pertinent to the basic objective of this overview which is limited
to the study of  industrial fuel.

          Industrial gaseous fuels can generally be classified as low
or medium Btu fuels that are burned in equipment designed to exhaust
the products of combustion through a chimney directly to the atmos-
phere.  On the other hand, pipeline or "towns-gas" quite often dis-
charge the products of combustion directly into a closed environment
such as a house or factory.  In such an environment, the combustion
products are com ing led wi th air and can be breathed by humans.  For
example, the typical household gas stove or oven  is often poorly
vented or not vented at all.  Hence, the products of combustion from
the gaseous fuel are breathed in a diluted form  in the home.  Conse-
quently, the sulfur content of pipeline gas is severly restricted to
accommodate this probability, and the maximum sulfur level permitted
in pipeline gas  is about 4 ppm (1/4 grain per 100 SCF).

-------
          Conversely, industrial fuel  gases used to fire kilns,
boilers, heat-treating furnaces, etc., are combusted in equipment
fitted with appropriate stacks for discharge of the products of
combustion directly to the atmosphere.  Therefore, it follows that
the pollution effects of the fuel-gas  can be assessed on a more
global basis, using criteria more related to ambient concentrations
of pollutants that can be expected at  ground levels.

          These assessments already have been made and the Clean
Air Act of 1971 specifies that the large-scale burning of fuels
conform to these New Performance Standards for units that started
construction after August 17, 1971.
                   BOILER EMISSIONS STANDARDS
             (HEAT INPUT GREATER THAN 250x1O6 BTU)
         Reference:  W.C. Wolfe, "Controlling  Industrial
            Boiler Emissions", PLANT ENGINEERING, 1/2AM
                                  lb/10  Btu   Approx. ppm
         Emiss ion       Fuel        Input         (dry)
       Particulate      All          0.1       (0.12 grains
                                                 per SCF)
                                                   550
                                                   520
                                                   165
                                                   227
                                                   525
so
£P
NO
X

Liquid
Solid
Gaseous
Liquid
Sol id
0.8
1.2
0.2
0.3
0.7

-------
          However, the Clean Air Act failed to specify the allowable
emissions of SCL when burning gaseous fuels, presumably because the
gaseous fuels then currently burned were of pipeline quality and
the resultant fuel-gases were innocuous.  The absence of a sulfur
specification for gaseous fuels should not be interpreted as re-
quiring zero pollutant emissions from such fuels.  A rational analysis
of the fuel substitution problem would suggest that permissable sulfur
levels in gaseous industrial fuels should be close to, but less than,
levels for liquid and solid fuels.  Lower sulfur levels in the gas
might be implied by analogy to the NO  level for a gas as compared
                                     J\
to liquid and solid fuels.

          It is, therefore, possible to infer permissable emissions
levels that would conform in principle with the Clean Air Act criteria.
For the purpose of conducting the study from which the summary of
control technology would be developed and to determine if control
technology required would be significantly reduced from that necessary
for pipeline gas, discussions with the Fuels Process Branch of the
EPA led to the following guideline pollutant levels for coal-derived
industrial fuel gas.  Although these emission specifications provide
a basis for study, no regulation by the EPA is implied or recommended
by their use.

          Pollutant      Maximum Emission Level
          Sulfur         0.5 Ibs SO, per 106 Btu
                                           6
          Nitrogen       0.*» Ibs NO  per 10  Btu
                         (measured as NO-)
          Particulates   0.1 Ibs per 10^ Btu
          Note that the suggested nitrogen level is twice the nitro-
gen level in the 1971 Clean Air Act.  This increase in the allowable

-------
nitrogen level  for industrial  fuel  gas recognizes the fact that
coal-derived fuel  gases may contain nitrogen compounds not normally
found in natural  gas.   As a consequence, the NO  that is formed during
combustion is derived  from fuel-bound nitrogen and also from the
thermal  fixation of atmospheric nitrogen itself.  Thus, the anticipated
NO  levels when burning coal-derived industrial fuel gas are higher
  /\
than the levels expected when combusting natural gas (which has no
fuel-bound nitrogen).

          Therefore, it can be said that industrial gas is a fuel that
can be expected to produce more pollutants than natural (pipeline) gas
when burned but less pollutants than liquid or solid fuels.  As the
natural  gas shortage worsens, the use of industrial gas to replace
natural  gas can be anticipated especially in  instances where liquid
or solid fuels are difficult or impossible to burn as substitutes.

          Suitable control technology for fuel converters producing
industrial fuel gases must be developed  in order to assure an
acceptable environment.  This is not to say that acceptable control
technology  is not available, but just that previous applications
either  lacked control or applied them to more  stringent standards
such as synthesis gas.  A  review of existing  gasification processes
that have had a history of successful commercial operation suggests
that operable systems have already been  developed  to  reduce and
control  the  particulate, sulfur and nitrogen  content of coal-derived
fuel gases  to meet process requirements.  Since  these  process
requirements are more stringent than  the emission  levels  discussed
previously  for  industrial  fuels, the  control  technology that they
use should  be satisfactory with a  little adaptation  to the guideline
levels.  The purpose,  then, of this overview  is  to discuss operable
gasification systems  to  cover clean-up  methodology,  and to suggest
improved methods  for  raw gas clean-up that will  result in an

-------
industrial fuel gas that meets the proposed guidelines.

          A review of many coal gasification systems that are capable
of producing an industrial fuel gas from coal is presented in the
following section of the report.  Only those systems which have some
degree of proven operability have been considered.  Economics were
not considered in choosing which processes should be included in
this review.

          Processes selected for review are as listed below:
                    Koppers-Totzek
                    Lurgi
                    Riley-Morgan
                    Wellman-Galusha
                    Wilputte
                    Winkler
                    Woodal1-Duckham/Gas Integrals
          Air-blown as well as oxygen-blown data are included where
available.

CONCLUSIONS AND RECOMMENDATIONS

°         The purpose of this overview was to assess the capability
for producing an industrial fuel gas that will meet the following
environmental guidelines:
                    Maximum 0.5 lb S02/MM Btu fuel gas
                    Maximum Q.k lb NO /MM Btu fuel gas
                                     /\
                    Maximum 0.1 lb particulates/MM Btu fuel gas
Technologies exist today that can meet these standards.  However,
the best choice of pollutant control systems is dependent upon the
type of coal gasifier, the coal utilized and the end use of the fuel
gas.

-------
o         Industrial fuel  gas standards are less stringent than
those required to produce a pipeline gas and this allows a wider
choice of systems.

o         The utilization of tars produced, the disposal of spent
liquors from acid gas removal, and the clean-up of waste water must
be considered when developing the appropriate processing sequence
for manufacture of environmentally acceptable industrial fuel gas.

o         Coals containing high nitrogen and sulfur will produce
tars which are too high in nitrogen and sulfur to permit the tars
to be burned directly as fuel and still meet the standards set by the
Clean Air Act of 1971 for liquid fuels.  A fertile field for future
development is to establish economic methods for removal of sulfur
and nitrogen from tar.

o         Only recently has much consideration been given to environ-
mentally acceptable methods for disposal of spent acid gas removal
liquors.  This is an area which requires additional development.

o         A significant cost  in producing  an acceptable  industrial
fuel  is the clean-up of the waste water  leaving  the particulates
removal system.  Therefore,  it  is  important to use methods for
particulates removal which minimize the  quantity of waste water.
                                -7-

-------
SECTION A - DESCRIPTION OF GASIFICATION SYSTEMS
            1.  Discussion of Basic Technology
            2.  Koppers-Totzek
            3.  Lurgi
            A.  R(ley-Morgan
            5.  WeiIman-Galusha
            6.  Wilputte
            7.  Winkler
            8.  Woodall-Duckham/Gas Integrale

-------
A. 1        Discussion of Basic Technology

          Means for the production of gaseous products from coal
have been known for many years, and commercial processes for coal
gasification are available.  Currently, considerable effort is
being expended to develop efficient means for producing gaseous
products from coal suitable for use as an energy source that meets
environmental regulations.

          Gasification of coal transforms a cumbersome, inconvenient,
dirty solid fuel  into a convenient, clean, gaseous fuel or  into
synthetic gas.  Some of the heating value of  the coal  is expended
to accomplish this transformation.

          Primary gasification of coal entails the treatment of
coal with air or oxygen and steam to yield a  combustible gaseous
product.  The product of  primary gasification obtained  from devolati-
lization of coal  and reaction of coal carbon  with the  gasifying  agent
is usually a mixture of H2> CO, C0_, CH.,  inerts  {such  as NZ),  and
minor amounts of  higher hydrocarbons (such as tar, C.H,, C_H. ,  etc.)
and  impurities  (for example,  H?S, NH, and  dust).  The  product gas
is called a  low Btu gas  if an  air-steam mixture  is used directly to
gasify  the coal and  it  contains nitrogen as  a major  component.   Low
Btu  gas  is suitable for use as an energy source  near its point  of
generation.   Intermediate Btu  gas  (synthesis  gas), which contains
only a  small amount of  nitrogen,  is  obtained  when an oxygen-steam
mixture is used to gasify the coal.   Intermediate Btu  gas can be
used either  as  an energy  source or  as  a  synthesis gas  for  the pro-
duction of chemicals and  synthetic  liquid  and gaseous  fuels.

-------
          Three basic reactor concepts have been developed for the
gasification of coal.  These are:

          1.  Fixed-bed or moving-bed (i.e., Lurgi reactor).
          2.  Fluidized-bed (i.e., Winkler reactor).
          3-  Suspension or entrained reactors (i.e., Koppers-Totzek)

In a moving-bed reactor, the gasifying medium is passed counter-
current to the coal with ash removal from the bottom and coal
addition at the top.  If the velocity of the gasifying medium
and the size of the coal particles are such that the bed behaves
as a fluid, the system is called a fluidized bed.  An entrained
system operates with pulverized coal particles carried by the
gasifying medium.

          Generally, a gasification reactor can be divided  into
three zones:  the devolatization, gasification and combustion zones.
In the devolitization zone, if the gasifier has one, coal is dried
and carbonized by hot gas.  Most of the volatile matter and moisture
of coal is distilled as CH., tar and aqueous compounds.  In the
gasification zone, carbon  in the coal reacts with steam and carbon
dioxide to produce carbon monoxide and hydrogen.  Both the devola-
tizat ion and gasification zones are endothemnic.  The third zone
is a combustion zone in which coal is oxidized to CO and CO..
The heat generated in the combustion zone sustains the chemical
reactions  in the gasification and devolatization zones.

          The principal components of the product gas are formed by
a combination of the following reactions:
                                10

-------
          (A)   Heat  generation  reactions

                    C  + 02  = C02  + Heat

                    C  + 1/2 02  =  CO + Heat

          (B)   Heat  consumption reactions

                    C  + H20 + Heat = CO  + H2

                    C  + C02 + Heat = 2 CO

          The compositions  of numerous producer gas products have
been examined to gain  a better understanding of the performance of
gas generating systems.  Data from various types of autothermic
noncyclic gas generators have been plotted in Figures A-1.1 and
A-1.2.  Yield patterns on air-blown as well as oxygen-blown systems
have been plotted.  The bulk of the data is from coal-based gasi-
fiers but some data is included from oil-based systems for comparison.
As would be expected,  the data from coal and oil-based units corre-
late separately because of different C/H ratios in the feed material.
Figure A-1.1 is a plot of the yield of CO + C02 vs. CO + H2-  These
data points follow a well-defined yield pattern and correlate well
considering the variety of feed coals and the wide range of system
pressures involved  in the correlation.   It should be emphasized
that this correlation applies  to noncyclic systems only.  Cyclic
systems, due to the separation of  the blow gas from the run product
gas, follow a different yield  pattern.  The ratio of CO + C0~ to
CO + H7  indicates the extent of  coal  combustion versus gasification
and  is  less than  1.0, as indicated by the slopes of the lines  in
                               11

-------
 ca
 ID
 ce.
  «M
 O
 CJ
 O
 o
      70  -i
      60  -
50  _
40  H
      30
      20
              LEGEND
                A  R!ley-Morgan
                ®  Wilputte
           20
          O  Winkler
          O  Woodall-Duckham
          A  Wellman-Galusha
          •  Koppers-Totzek
          9  Lurgt
          B  HRI Fluid-Bed  (Anthracite)
          O  Slagging Gasification
B Fixed Bed Generator  (Anthracite)
® Flesch-Demag Generator
ffl Ruhrgas Cyclone Gasifier
O Morgantown, W. V. Gasifier
                                        ©   yaw  0
                                             Oxygen-Blown  Gasifier
                  Air-Blown Gasifier
                        Q
                           Coal
HRI Kerosene Gasification
Texaco 051 Gasification

 Shell  Oil  Gasification
              —I	1	1	1	1	1	
              30        *»0       50        60        70        80
                                 CO + H2, % in Raw Gas
                 FIGURE A-l.l  GENERALIZED  PERFORMANCE OF  GASIFIERS
                                 —r
                                  90
   100
Source of Data:  Points calculated  from compositions  presented  in  many  of  the Appendix references,

-------
               LEGEND
       0.7  T
       0.6  -
 E
 c
o
0.5  -
   o
-4-
I
O
o  o
o  o
+  8
 C-J CD
8
o
o
       0.3  -
       0.2  _
       0.1  -
                  A   Ri ley-Morgan
                  ®   Wilputte
                  O   Winkler
                  D   Woodal 1-Duckham/Gas Integrale
                      Wei 1 man-Gal usha
                                                El  HRI Fluid-Bed (Anthracite)
                                                G>  HRI Kerosene Gasification
                                                
-------
Figure A-l.l.  This ratio obviously becomes infinitely large when
combustion reactions are complete, forming no carbon monoxide and
hydrogen.

          Figure A-1.2 shows a plot of the fraction of carbon that
undergoes combustion to supply heat for the endothermic gasification
reactions, in terms of CO«/(CO, + CO + CH. + C H )  vs. a ratio of
                         /    L          4    n m
H- and CO.  The curves also show the general  trends for bituminous
coal, anthracite and oil gasification processes.  As would be ex-
pected, the fraction of combusted carbon  increases when the H./CO
ratio increases.  When gasification reactions proceed to a greater
extent to produce more H. via the steam-carbon reactions, the system
must supply more heat by burning more carbon to sustain the endo-
thermic gasification reactions.

          Figures A-l.l and A-1.2 are, therefore, useful for check-
ing and predicting the performance of a gasifier.  This understanding
is a good prerequisite for sound environmental study.  If the data
from a specific gasifier do not fall in line with the general trends
of the curves shown in the figures, it would indicate that either
the data are not accurate (perhaps due to bad sampling or analysis)
or that the heat leak on the gasifier system is excessive.

-------
A.2       Koppers-Totzek Process

          The Koppers-Totzek gasifier is an entrained-bed producer,
operating at high temperature (3300 to 3500°F at the burner discharge
with an exit gas temperature of about 2700°F) and at near atmospheric
(5 to 7 psig) pressure.  Operation at high temperature results in
complete gasification of carbon and organic sulfur in the feed and
produces a nonreactive ash in the form of a molten slag.  The two-
headed gasifier is a refractory-lined, horizontal cylinder with
opposing coaxial burner heads at each end.  Capacity of each gasi-
fier unit is about 400 tons of coal per day for the two-headed gasi-
fier and over 800 tons per day with a four-headed gasifier.  Figure
A-2.1 shows a Koppers-Totzek unit.

          The coal is pulverized to 70% through 200 mesh using roller
or ball type wind-swept mill and dried to between 2% and 8% moisture
content.  Up to a capacity of 150 tons per hour roller mills are
used.  Ball mills are applied in the  150  to 250 tons per hour range.
Pulverizers are designed to use combustion gases tempered  to 800-900 F
as a drying medium.  Gas at this temperature  level keeps the coal
particle temperature at 180°F where there  is  no devolitization or
chemical reaction of the coal particles.  As  a  result the  evaporated
coal moisture, after particulate removal, can be discharged as a
vapor  to the atmosphere reportedly without detrimental  affects to
ai r  quality.

          The dried, pulverized coal  is conveyed with nitrogen to  gasifier
service bins and  continuously discharged  from twin variable-speed  screw
feeders  into a mixing  nozzle where  it is  entrained  in a mixture of oxy-
gen  and  low  pressure steam.  The  feed mixture is  then delivered  through
                                15

-------
                             FIGURE  A-2.1

                       KOPPERS  TOTZEK GASIFIER
   FEED
   BIN
                   FEED WATER
     SCREW FEEDER

PIV GEAR
             WATER
                                                 *H.P. STEAM
                                                   \
GAS OUTLET
FEED
BIN
                                                L.P. STEAM
                                                               ASH
                     Reference:  toppers Company Brochure
                                       16

-------
a transfer pipe to the burner head of the gasifier at a speed
higher than flame velocity.  Moderate temperature and h-igh burner
velocity prevent the reaction of the coal and oxygen until entry
into the gasification zone.  The gasifier designs either have two
or four gasifier heads with opposed inlets.  Alignment of in-flow
lines is offset to create a cyclone for effective mixing.  The
steam shrouds the high temperature reaction zone and protects burners
and refractories from excessive temperature in addition to its
principal role of supporting the gasification reactions.  Product
gas passes through a central, water-cooled vertical gas outlet.
Some ash (30% to 50%), in the form of a molten slag, leaves the
gasifier with the product gas; the balance (50% to 70%) is removed
from the bottom of the gasifier.

          The raw gas from the gasifier passes through  the waste
heat boiler where high pressure steam (up  to  1500  psig)  is pro-
duced.  After leaving the waste heat boiler,  the gas at 350 F  is
cleaned and cooled in a high energy scrubbing system.   Particulate-
laden water from the gas cleaning and cooling system  is piped  to a
clarifier.  The cool gas leaving  the gas cleaning  system  may contain
sulfur compounds which must be  removed to  meet gas specifications.

          A list of Koppers-Totzek units that have been built  is
given  in Table A-2.1.

          Process Characteristics:
           1.  Scale of Operation:  Commercial
           2.  Heat Supply:  Autothermic
           3-  Flow:   Concurrent
           *».  Gasifying Media:  Steam, Oxygen
                                17

-------
          5.  Ash Removal:  Molten Slag, Continuous, 30 to 50$
                    Bottom Ash Removal
          6.  Pressure:  Slight Positive Pressure
          7.  Temperature:  2700 to 3500°F
          8.  Product Gas:  300 Btu/SCF
Raw Gas Analysis of Major Components (dry basis)  - Volume %:
                    Western Coal    Illinois Coal   Eastern Coal
CO
CO
H2
N2

COS
Dried Feed Coal
C
H
N
S
0
Ash
Moisture
58.68
7.04
32.86
1.12
0.28
0.02
Analysis, Weight %:
56.76
4.24
1.01
0.67
13-18
22.14
2.00
55.38
7.04
34.62
1.01
1.83
0.12

61.94
4.36
0.97
4.88
6.73
19.12
2.00
55.90
7.18
35.39
1.14
0.35
0.04

69.88
4.90
1.37
1.08
7.05
13-72
2.00
Koppers-Totzek Reference #2:  Farnsworth, J.F.
                               18

-------
                             TABLE A-2.1
              GASIFICATION PLANTS USING THE K-T PROCESS


Location
Charbonnages de France,
Paris, France


Typpi Oy, Oulu
Finland
Nihon Suiso Kogyo Kaisha, Ltd.
Tokyo, Japan
Nitrogen Works in Puentes de
Garcia Rodriquez, Coruria, Spain
Typpi Oy, Oulu
Finland
S.A. Union Chimique Beige,
Brussels, Belfium
Amoniaco Portuguts S.A.R.L.,
Lisbon, Portugal
Government of the Kingdom of Greece
Ptolemais, Greece
Nitrogen Works in Puentes de
Garcia Rodriquez, CoruTia, Spain
Nitrogen Works of Societe' el Nasr d1
Number of
Gasif ier
Units
1



3

3

3

2

2

2

k

1

1 Engrai s 3
Capacity:
CO + H2
in 24 Hours
75,000-
150,000 Nm3
2,790,000-
5,580,000 SCF
HO, 000 Nm3
5,210,000 SCF
210,000 Nm3
7,820,000 SCF
242,000 Nm3
9,000,000 SCF
140, 000 Nm3
5,210,000 SCF
176,000 Nm3
6,550,000 SCF
169,000 Nm3
6,300,000 SCF
629,000 Nm3
23,450,000 SCF
175,000 Nm3
6,500,000 SCF
778,000 Nm3
Year
of
Order
19^9



1950

195^

195^

1955

1955

1956

1959

1961

1963
et d1Industries Chimiques, Attaka, Suez
United Arabian Republique

Chemical Fertilizer Company Ltd.,
Mae Moh, Lampang, Thailand

Azot Sanayii T.A.S., Ankara,
Kutahya Works, Turkey
28,950,000 SCF


   217,000 Nm3     1963
 8,070,000 SCF

   775,000 Nm3     1966
28,850,000 SCF
                                  19

-------
                         TABLE A-2.1 (Cont'd)


                                            Number of      Capacity:       Year
                                            Gasiffer        CO + H2         of
Location                                      Units       in 24 Hours     Order

Chemieanlagen Export-Import G.m.b.H.,           2          360,000 Nm3     1966
Berlin fur VEB Germania, Chemieanlagen und              13,400,000 SCF
Apparatebau, Karl-Marx-Stadt, Germany

Kobe Steel Ltd., Zambia, Africa                 1          214,320 Nm3     1967
                                                         7,980,000 SCF

Nitrogenous Fertilizers                         1          165,000 Nm3     1969
Industry S.A., Athens,                                   6,150,000 SCF
Ptolemais, Greece

The Fertilizer Corporation                      4        2,000,000 Nm3     1969
of India Ltd., New Delhi,                  0 of them   74,450,000 SCF
Ramagundam Plant, India                   as stand-by)

The Fertilizer Corporation                      4        2,000,000 Nm3     1970
of India Ltd., New Delhi,                  0 of them   74,450,000 SCF
Talcher Plant, India                      as stand-by)

Nitrogenous Fertilizers                         1          242,000 Nm3     1970
Industry S.A., Athens                                    9,009,000 SCF
Nitrogenous Fertilizers Plant
Ptolemais, Greece

The Fertilizer Corporation of India Ltd.,       4        2,000,000 Nm3     1972
New Delhi, Korba Plant, India              0 of them   74,450,000 SCF
                                          as stand-by)

AE & Cl Ltd., Johannesburg,                     6        2,150,000 Nm3     1972
Modderfonteln Plant, South Africa                       80,025,000 SCF

Indeco Chemicals Ltd.,                          1          220,800 Nm3     1974
Lusaka, Kafue Works, Zambia                              8,220,000 SCF

Indeco Chemicals Ltd.,                          2          441,600 Nm3     1975
Lasaka, Kafue Works, Zambia                             16,440,000 SCF
                                   20

-------
A.3       Lurgi Process

          The Lurgi producer is a moving-bed, intermediate pressure
gasifier with counter-current flow of coal and gas.  Dry ash is
removed from the bottom and gas exits from near the top.

          Coal of 1/4 to 1-3A inch is fed to the top of the gasi-
fier through a pressurized lock hopper.  Fine coal particles are
not acceptable in the feed; large particles are needed to permit
sufficient gas passage.  The coal, ideally nonagglomerating, flows
downward through the moving-bed gasifier.  A rabble arm levels the
coal on the surface of the bed.

          Steam and air or oxygen are  introduced at the bottom of
the reactor through a revolving grate; as these gases rise  through
the reaction zone, they react with residual carbon to produce heat
necessary to carry out the gasification  reactions.  To  insure com-
plete gasification, a sufficiently high  temperature must be main-
tained by control of the steam/oxygen  ratio.  This temperature
must be below  the ash fusion point but high enough to provide the
heat necessary in the endothermic gasification zone.

          The  moving bed has a layered temperature profile, which
increases as the coal proceeds downward  until  reaching approximately
2000°F  in the  bottom combustion  zone.  At the  top of the bed, feed
coal  is preheated, dried,  and heated up  to start devolati1ization.
Carbonization  products, such as  tar, oils, naphtha,  light  hydrocarbons,
phenols and ammonia, together with a mixture of hydrogen and carbon
monoxide are produced starting at about  900°F  to 950°F.   From a
temperature of 1150°F  to  1400°F  onward,  devolati1ization  is accom-
panied by gasification of  the  resulting  char.  The kinetics of  the
                                21

-------
devolatiIization and gasification reactions is related to the re-
activity of the coal and, thus, the minimum temperature at which
the reaction will proceed.  The approximate final reaction tempera-
tures at which the reaction rates of various coals approach zero
are:
                    Lignite            1200°F
                    Sub-bituminous     1350 F
                    Semi-anthracite    1450°F
                    Coke               1550°F
To achieve a good performance of the reactions, the minimum required
residence time of a coal grain at the desired temperature level of
H»00°F to 1600°F is about one hour.

          Gas leaving the bed contains, in addition to the carboni-
zation products, coal and ash particulates plus some hydrogen sul-
fide and carbony 1 sulfides.  The exiting gas temperature is at 700 F
to 1100 F depending on the type of coal.

          The relatively uncomplicated Lurgi gasifier design shown
in Figure A-3.1 utilizes a double-walled vessel with hot water or
boiling water between the walls.  Gasifiers of recent design are not
internally insulated.  The Lurgi design incorporates a mechanically-
driven grate at the bottom of the gasifier.  The grate supports the
fuel bed, removes the ash into a lock hopper, and allows introduction
of steam and air to the gasifier.  The ash> a granular, low-carbon
material, is discharged from the pressure reactor through an ash
lock chamber.  The literature indicates the physical limit to the
diameter of Lurgi gasifiers has been established by the need to
                               22

-------
               o
              FEED COAL
                        RECYCLE TAR
    DRIVE
GRATE
DRIVE &
 STEAM
 OXYGEN
\ :
                                       SCRUBBING
                                       COOLER
                                           GAS
                           WATER JACKET
                               Reference:
                                 Paul  F. H.  Rudolph, "The Lurgi
                                 Process The Route to SNG from
                                 Coal", Ath  Synthetic Pipeline Gas
                                 Symposium,  Chicago, Oct. 30 & 31 ,
                                 1972.
       LURGI  PRESSURE  GASIFIER
                        23
                                                FIGURE A-3.1

-------
maintain good distribution of gas through the downward moving bed
of coal.  When the size of the reactor becomes too great, perhaps
15 feet or more, it would be difficult to maintain good distribu-
tion of gas across that large a cross-sectional  area.   Capacities
up to 570 x 10  Btu of coal per hour are reported for  each Lurgi
gasifier uni t.

          A list of Lurgi gasifiers that have been built is given in
Table A-3-1-  Some of these units are no longer  operating.

          Process Characteristics:
          1.  Scale of Operation:  Commercial
          2.  Heat Supply:  Autothermic with externally heated
                    steam
          3.  Flow:  Counter-current
          4.  Gasifying Media:  Steam, air or oxygen
          5-  Ash Removal:  Dry-ash, continuous
          6.  Pressure:  10 to 30 atm.
          7.  Temperature:  1150-1600 F in gasification zone
          8.  Product Gas:  310 Btu/SCF (oxygen-blown)  - MO-180
                    Btu/SCF (air blown)
          9.  Heat Recovery:   Side wall

-------
A.A       Riley-Morgan Process

          The Riley-Morgan gas producer is a low-pressure (up to
kO inches of water gauge), stirred moving-bed gasifier.   The new
design is an improved version of the old Morgan gas producers of
which over 9,000 were sold through the 19^0's.   Improvements included
replacing castings with weldments, an outer gas and dust tight casing
for personnel  protection, water seals for higher operating pressure,
increased volume to handle the swelling tendency of certain coals,
a water-cooled agitator to handle caking coals, and automated con-
trols to reduce the number of operating personnel.

          Coal of I/A to 1-1/2 inch  is fed to the top of the gasi-
fier.  Both noncaking and caking coals can be gasified because the
deep bed agitator can break up agglomerated masses.

          The fuel bed is supported on an ash bed which,  in turn,
is supported on a rotating ash pan.  The pan, barrel and charge
all rotate together.  The fuel bed is smoothed out by leveler arms
and moves downward as the gasification of fuel  proceeds.  As the
ash level becomes too high, ash  is moved by a helical plow from
the bottom of the gasifier.

          Steam and air or oxygen are fed to the bottom of the
gasifier.  Air  is brought  in without a fan by an  injection system
which mixes and  inducts air by steam flow  in Venturis.

          Gases  leave the  top of  the reactor, pass through a cyclone
to remove dust, and are cooled first in an air condenser and then  in
a water  condenser.  Cooler condensate  is separated from  the gas which
                               27

-------
proceeds on to further processing as required by downstream gas
utili zation.

          A Ri ley-Morgan unit is shown in Figure A-**.!.

          A sulfur and a nitrogen balance for the Riley-Morgan
system is given in Appendix C.

          Process Characteristics:
          1.  Scale of Operation:  Two years full scale laboratory
                    test
          2.  Heat Supply:  Autothermic
          3.  Flow:  Counter-current
          4.  Gasifying Media:  Steam, air or oxygen (proposed)
          5.  Ash Removal:  Dry ash, intermittent
          6.  Pressure Atmospheric
          7.  Product Gas:  305 Btu/SCF (oxygen-blown)  - 160 Btu/SCF
                    (air-blown)

Raw Gas Analyses of Major Components (dry basis and sulfur-free basis)
Volume %:

                    Ai r-Blown          Oxygen-Blown
CO
H2
Ch\
C02
cnHm
N2
26.0
18.0
1.4
3.8
0.2
50.0
41.2
38.9
2.8
15.9
0.7
0.5
Approximate Analysis of Feed Coal (U.S. Eastern Bituminous Coal)
Moisture                        1.2%
Volatile Matter                34.4%
Fixed Carbon                   42.7*
Ash                            15.7*
Riley-Morgan Reference #3:  Rawdon, A.M., et al.
                               28

-------
                    FIGURE  A-A.l
              RiLEY-MORGAN CAS PRODUCER
GAS OUTLET
FIXED COVER
LEVELER BOX
COAL INLET
WATER COOLED LEVELERS

WATER COOLED AGITATOR

STATIONARY OUTER CASING
R6fRACTORY LINING
WATER SEAL

BLAST HOOD
ROTATING BARREL

BARBEL SUPPORT SPIDER

ROTATING ASH PAN
ASH PLOW
ASH HOPPER
EXTERNAL SUPPORT WHEELS
WATER SEAL

DRIVE GEAR

STRUCTURAL SUPPORTS

AIR AND STEAM INLET
Reference:   Riley-Morgan Brochure
                              29

-------
A. 5       WeiIman-Galusha Process

          The WeiIman-Galusha producer is a single-stage, low-temperature,
low-pressure gasifier with a fixed bed through which coal moves slowly
downward toward a revolving eccentric grate.  Gas flows upward counter-
current to the flow of coal.  Sizes of the water jacketed automatic
producers with revolving grates range from k2 inches to 10 feet in
inner diameter.  Capacities of these units are, respectively, 192 to
1600 Ibs per hour (*»0 million Btu/hr) using 3/16 to 5/16 inch anthra-
cite.  With an agitator, the capacity of the 10 feet diameter unit
is 2000 Ibs per hour for anthracite and 7000 Ibs per hour on 1-1/4
to 2 inch bituminous coal.  A high pressure unit (300 psi) has been
designed and built at the Bureau of Mines Research Center in Morgan-
town, West Virginia.  Figure A-5.1 illustrates a typical unit.

          A two-compartment fuel bin, at the top of the producer,
feeds crushed and dried coal to the downward moving bed.  A slowly
revolving horizontal arm, which spirals vertically below the surface
of the fuel bed, retards channeling and maintains a uniform bed.
The producer can gasify anthracite and coke but, when bituminous
coal is used, an agitator is required to avoid channeling and caking
(agglomerating) of coal particles.  The bed is supported by a slowly
revolving eccentric grate through which dry ash is continuously
ejected into an ash hopper.

          Gas flow  is upward through the gasifier.  Steam, generated
in the water jacket surrounding the gasifier, and air or oxygen are
introduced through the revolving grate.  Depending on the type of
gas required, CO^ can be substituted for the steam.  This procedure
would avoid formation of hydrogen from the steam in order to make
                               30

-------
                          FIGURE A-5.1
  WATER JACKET


     AGITATOR


   COMBUSTION
      ZONE
                        TYPICAL RUILDirir,
                        AND FUEL  CLF.VATOR
                             OUTLINE
                                                  FUEL DIM



                                                  VALVES CLOSED

                                                  LOCK HOPPER
.HATER SEAL
 AMD DUST
COLLECTOR

•GASIFICATION
    ZONE
                     WELLMAN-GALUSHA FUEL, GAS GENERATOR.
Reference:   WeiIman-Galusha Brochure

-------
a gas with improved burning characteristics.  Raw gas containing
particulates, tars and oils leaves the top of the producer at a
temperature between 1000 F and 1250 F depending on the type of
coal.
          After the reactor, the gas may pass through a waste heat
recovery section.  Ash, carried over by the gas, and tar are removed
by scrubbing.  The cooled gas is then compressed and further pro-
cessed if pipeline gas is to be made.

          Process Characteristics:
          1.  Scale of Operation:  Commercial
          2.  Heat Supply:  Autothermic with externally heated
                    steam
          3-  Flow:  Counter-current
          4.  Gasifying Media:   Steam, oxygen or air
          5.  Ash Removal:  Dry-ash, continuous
          6.  Pressure:  Atmospheric
          7.  Temperature:  1000° to 1250°F (normal off-take
                    temperature of the gas)
          8.  Product Gas:  260 Btu/SCF (oxygen-blown)  - 160 Btu/SCF
                    (ai r-blown)
          9.  Heat Recovery:  Sidewall
                             32

-------
Raw Gas Analysis of Major Components (Unspecified Coal)
                               Mol
Component           High-Btu           Low-Btu
   CO                 29-6               26.0
   COz                12.3                3-0
   H2                 30.3               13.9
   H20                25.3                8.3
   CHJL                 0.7                2.5
   N2                  1.1               1*5.6
   02                  0.1
   H2S/COS             0.6                0.7

           Total      100.0               100.0
Higher Heating Value
     (dry basis) , Btu/SCF 263
 General  Reference  #1
                               33

-------
Raw Gas Analysis of Major Components (dry and sulfur-free basis)

Vo1ume %:
                                           Bituminous A
                                   Coke        W. Va.
                                   31.0        15.0
                                    0.6
                                   54.1        28.6
                                   11.3         3.4
                                    0.4         2.7
                                    2.6        50.3
Anthracite







Feed

H2
°2
CO
C02
CH/,
N2
Coal :
PA
41.0
0.1
40.0
16.5
0.9
1.5

Proximate Analysis, W%




Moisture
Ash
Volatile Matter
Fixed Carbon
6.4
10.2
4.5
78.9
Ultimate Analysis, W&






C
H
N
0
S
Ash
78.7
2.4
0.7
7.4
0.6
10.2
                                    5.0         3-7
                                   11.9         3-5
                                               36.3
                                   83.1        56.5
                                   84.1
                                    1.8
                                    0.8
                                    1.8
                                    0.6
                                   10.9
WeiIman-Galusha References #3 and #7-
                               34

-------
A.6       Wilputte Process

          The Wilputte producer is a moving-bed gasifier,  operating
at atmospheric pressure.  The producer is equipped with a  rotating
grate and ash pan assembly which rests on roller supports.  A sta-
tionary ash plow removes the ash from the ash pan and discharges the
ash into an ash trough.  The producer is supported above the rotating
grate and ash pan assembly by columns from the floor and is sealed
by water in the ash pan.  The producer can gasify either bituminous
or lignite coal with air or oxygen.  A rotating rabble arm (agitator)
is used to mix and break up the agglomerates when a caking coal  is
gas i f ied.

          The crushed coal of less than k inches  is fed through the
top of the gasifier.  Moist air or oxygen flows upward through a
rotating grate.  The fresh coal is pyrolyzed to expel volatile hy-
drocarbon products at the upper portion of the fuel bed, and the
carbon residue from pyrolyzed coal is burned and  gasified with air
and steam to carbon dioxide, carbon monoxide and  hydrogen.  The
product gas leaves the  producer at about 1100-1200 F.

          The  raw product gas contains coal tar,  light oil, hydrogen
sulfide and particulates.  The gas  is passed through a cyclonic dust
collector to a waste heat boiler  that lowers the temperautre of the
gas stream to about 800  F.  The gas  is then quenched with an aqueous
liquor and further scrubbed with  the  liquor  in a  packed tower to
remove light oil, tar  and particulates.  When operating on a low-
sulfur coal, the  scrubbed gas  can be  used at  this point as a fuel
without additional  processing.   If high-sulfur coal  is  used, or
complete  sulfur  removal  is  required,  the gas  stream  is  further
                                 35

-------
purified by a secondary scrubber and by an electrostatic precipitator
before entering the sulfur removal system.  The Holmes-Stretford
process may be used for the removal of hydrogen sulfide.  A system
to remove HCN from the gas stream prior to entry into the Holmes-
Stretford unit is not required because the HCN content of the gas is
so low that fouling of the absorbent solution with thiocyanates is
not a serious problem.

          The heating value of the producer gas is affected by the
volatile content of the feed material.  Bituminous coal  and lignites
will  produce a fuel  gas with a heating value of 160-170 Btu/SCF.
The HHV of gas from anthracite or coke will be somewhat lower.

          Process Characteristics:
          1.  Scale of Operation - Commercial
          2.  Heat Supply - Autothermic
          3.  Flow - Counter-current
          k.  Gasifying Media - Moist air or oxygen
          5.  Ash Removal  - Dry ash, continuous
          6.  Pressure - Atmospheric
          7.  Product Gas - 165 Btu/SCF (air-blown) - 300 Btu/SCF
                    (oxygen-blown)
          8.  Heat Recovery - Sidewall
              A Wilputte gasifier is illustrated in Figure A-6.1.

-------
                  FIGURE A-6.1
               WILPUTTE  GASIFIER
     COAL /-etc
                                       WATCH COOLtO
                                       AOITATO* 4
                                       COVA/£C7M/6 MM
  SHELL
SU/fOKT-
CQLUUH
Reference:   Wilputte Co.  Brochure
                        37

-------
                 Purified Gas
              Composition, V % (l)        Air-blown
H2
CHI,
N2
0
CO
co0
16.6
3.6
51.0
0.2
22.7
5.9
Feed Coal:  U.S. Eastern Bituminous Coal.



NOTE:  1)  After Purification by Stretford Process


Wilputte Reference #1
                                   38

-------
A.7       Winkler Process

          The Winkler producer is a f1uidized-bed gasifier,  operating
at low (up to 3 psig) pressure.  The Winkler generator was initially
designed to make producer gas from coal with air and steam gasification.
The gas was used as an industrial fuel  for  both direct combustion and
use in stationary internal combustion engines.  A proposed recent ver-
sion of the Winkler gasifier has been designed to operate at a pressure
of about 125 psi.  Operation at this proposed pressure level is said
to improve the economics of both the oxygen-blown and the air-blown
models of this system.

          Coal is normally crushed in the range of 0 to 3/8-inch and
dried.  Past operating experience has indicated that the coal feed
need be dried only if surface moisture is present and the coal can-
not be handled without plugging screens, conveyors, etc.  Generally,
coals with moisture contents of up to 13% can be handled and gasi-
fied without drying.

          Coal enters the producer through a variable-speed screw
feeder.  The screws,  in addition to providing control on the coal
feed rate, serve to seal  the producer preventing steam from wetting
the coal feed and blocking the feed line.

          The primary supply of steam and oxygen (or air) enters the
bottom of the gasifier.   Coal  reacts with oxygen and steam  to pro-
duce a gas rich  in carbon monoxide and hydrogen.  A secondary blast
of steam and oxygen or air above the fluidized bed converts unreacted
carbon  in the gas-entrained particles and raises the bed to maximum
temperature.
                                39

-------
          Gasification reactions  in the Winkler gasifier are primarily
a combination of combustion and water-gas reaction at temperatures of
1500°F to 2000°F depending on the type of coal.  The high temperature
reacts all tars and heavy hydrocarbons.  Before leaving the gasifier,
the gas is cooled by a radiant heat boiler section to prevent ash
particles from melting and forming deposits  in the exit duct.

          As a result of high fluidization gas velocity, the ash
particles are segregated according to size and specific gravity.
The larger, heavier ash particles fall down  through the fluidized
bed and pass into the ash discharge unit at  the bottom of the gasi-
fier while the lighter particles are carried up and out of the fuel
bed by the product gas.  Experience has shown that approximately
30% of the ash leaves at the bottom while 70% is carried overhead.
An auxiliary unit provides a hot bed of coal for initial start-up.

          Raw gas leaving the gasifier is passed through a further
waste heat recovery section.  Fly ash is removed by cyclones followed
by a wet scrubber and finally, if appropriate for the application, an
electrostatic precipitator.  The gas may then be compressed and
shifted if continuing on to pipeline gas.  The gas coming from the
shift converter is purified, methanated, dehydrated, and compressed
further if necessary to produce pipeline quality.

          The ash removed in the dry state is conveyed pneumatically
to an ash bunker.  That which is removed wet is recovered as a slurry
in a settler and then mixed with the warm dry ash where the contained
water cools the ash and wets it to prevent dusting problems during
ultimate disposal.

          A Winkler unit is shown in Figure A-7.1.

-------
                        FIGURE A-/.1

                     A WINKLER GASIFIER
     PURGE £ INERT GAS LINES
        WITUT
          FUEL BURNER
      TO STACK
    WATER COOLED
       SHAFT
/M/VVWVW
         RATCHET DRIVE
           STEAM
                 GASIFIER
                                                               GAS TO DUST
                                                           V-^-COLLECTOR £
                                                               WASTE HEAT BOILER
                                          o o
                                                         STEEL SHELL

                                                         REFRACTORY LINING
WATER JACKETED
SCREW CONVEYOR
                                                        SCRAPER FOR ASH
                                                           REMOVAL
                  OXYGEN OR
                  ENRICHED
                    AIR
                                       RATCHET DRIVE
                                       WATER COOLED
                                         SHAFT
                                      ASH
                                      RECEIVER
                 WATER
                 JACKETED
                 SCREW CONVEYOR
          Reference:  Davy Powergas,  Inc.

-------
          A list of Winkler gasifiers that have been built is given
 in Table A-7.1-  Not all of the units are still operating.

          Process Characteristics:
          1.  Scale of Operation:  Commercial
          2.  Heat Supply:  Autothermic with externally heated steam
          3-  Flow:  Counter-current
          4.  Gasifying Media:  Steam, oxygen or air
          5.  Ash Removal:  Dry-ash, continuous
          6.  Pressure:  Atmospheric (up to 8 psig)
          7.  Temperature:  1500-2000°F
          8.  Product Gas:  270 Btu/SCF (oxygen-blown, German Coal)
                            105 Btu/SCF (air-blown, German Coal)
          9.  Heat Recovery:  External

 Raw Gas Analysis of Major and Sulfur Components (Coal Unspecified):

                              MoU
 Component
    H2
    CO
    C02
    H20
    CHl,
    N2
    H2S
    COS
          Total      100.0              100.0

Higher Heating Value
   (dry basis), Btu/SCF 275             118
General Reference #1
High-Btu
32.2
25.7
15.8
23.1
2.4
0.8
2500 ppm
400 ppm
Low-Btu
11.7
19.0
6.2
11.5
0.5
51.1
1300 ppm
200 ppm

-------
Raw Gas Analysis of Major Components (dry basis) - Volume %;


                                       Oxygen-Blown


          H2                               38.5
          CO                               35.3
          C02                              21.8
          CHij                               1.8
          N2                                1.1
          H2S                               1.5


Ultimate Analysis of Feed Coal (German Brown Coal):


                                            W  %
          Moisture                           8.0
          Ash                               15.4
          C                                 54.6
          H                                  4.1
          N                                  0.6
          S                                  3-3
          0                                 14.0
Winkler  Reference #4.
                                43

-------
                                   TABLE A-7-1
                         PLANT LIST -  WINKLER GENERATORS
Capacity Per Generator
Normal Maximum
Plant
No.
1

2

3

k

5

6

7

8

9

Plant
Leuna-Werk
Leuna, Germany
Braunkohle-Benzin AG
Boh 1 en, Germany
Braunkohle-Benzin AG
Magdeburg, Germany
Yahagi
Japan
Braunkohle-Benzin AG
Zeitz, Germany
Da i -N i hony 1 nzo-H i ryo
Japan
Nippon Tar
Japan
Toyo-Koatsu
Japan
Sudetenlandische

Year
1926-
1930
1936

1936

1937

1938

1938

1938

1939



Product
Fuel Gas
Water Gas
Water Gas

Water Gas

Water Gas

Water Gas

Synthesis Gas

Water Gas

Synthesis Gas


1000
NM3/hr
60
30
27.6

27.6

8.75

22.5

14

14

15


1000 1000 1000
SCFH NM3/hr SCFH
2240 100 3730)
1120 50 1870)
1030 30 1120

1030 33 1230

330

840

520

520

560 20 750


No.
Ger


3

3

1

3

2

2

2


         Treibstoffwerke
       Brux, Czechoslovakia

*10    Fabrika Azotnih
         Jendinjenja
       Gorazde, Yugoslavia

 11    Calvo Sotelo
       Puertollano, Spain

 12    Union Rheinische
         Braunkohlen
       Wesseling, Germany
1943  Water Gas
1953  Synthesis Gas
1954  Water Gas
27.6   1030



 5      190


 9-5    350
1956  Synthesis Gas   12
30   1120   5



            j


            1
        450     17    630   1
                                                           (Continued)
                                        44

-------
                              TABLE A-7-1  (Cont'd)
Plant
 No.

 13
*15
*16
        Plant

Calvo Sotelo
Puertollano, Spain

Azot Sanyyi i TAS
Kutahya, Turkey

Neyveli  Li gni te
  Corporation
Madras,  India

Union Reinische
  Braunkohlen
Wesseling, Germany
                                                    Capacity Per Generator
                                                     Normal        Maximum
                      1000   1000   1000   1000  No.
Year     Product     NM3/hr  SCFH  NM3/hr  SCFH  Gen.
                             I960  Synthesis Gas   12
1957  Synthesis Gas    9-5    350
                             1959  Synthesis Gas   12
                             1959  Synthesis Gas   k].6   1550
                              ^450
            1
                                      18    670   2
17    630   1
* Presently operating

-------
A.8       Woodall-Duckham/Gas  Integrale Process

          The Woodall-Duckham/Gas  Integrale process  is a two-stage,
moving-bed gas producer.  The  producer consists of a distillation
retort surmounting a gasification shell.  The producer is top fed,
operating at atmospheric pressure with ash continuously withdrawn
through a grate at the bottom  of the producer.  The  lower portion
of the producer is water jacketed and the upper portion is made of
hollow refractory tile.

          Coal of 3A to 2-3/4  inch is fed to the top of the producer
and descends in the distillation retort (first stage) through gradually
Increasing temperature zones.  All volatile matter is expelled until
only carbon and ash (distillation coke) remain to enter the gasifica-
tion zone (second stage).

          In the gasification  zone air and steam enter through a
rotating grate at the base of  the producer and the carbon in the
distillation coke is gasified.  A part of the hot producer gas
(called clear gas) travels upward through the fresh coal  in the
upper portion of the producer while the sensible heat of the gas is
used to distill off the volatile matter of the fresh coal.  The
producer gas mixes with distillation vapors to leave the retort as
mixed gas at temperatures of 210 F to 300°F.  The mixed gas consists
of 60-75% water gas (CO & Hj,), with the balance being coal distilla-
tion gas, tar, light oils and  unreacted steam.  The remaining part
of the clear gas (a mixture of CO, H_, CO-, CH.  and N_ and completely
free from oil and tar) leaves  the gasifier through a blast gas out-
let at a temperature of 800 F  to 1000 F.  The producer cannot handle
a highly caking coal.

-------
         Refer to Figure A-8.1  for a WD/GI illustration.

         A list of WD/GI gasifiers is given in Table A-8.1.

         Process Characteristics:
         1.  Scale of Operation:  Commercial
         2.  Heat Supply:  Autothermic
         3.  Flow:  Counter-current
         4.  Gasifying Media:  Steam, oxygen or air
         5.  Ash Removal:  Dry-ash, continuous
         6.  Pressure:  Atmospheric
         7.  Product Gas:  340 Btu/SCF  (oxygen-block)  -  175 Btu/SCF
                    (ai r-blown)
         8.  Heat Recovery:  Sidewall
         Raw Gas Composition of  Major Components  (dry  and  sulfur-free)
                    - Vo 1 ume %:

                        Air-Blown

H2
02
CO
CO,
CHjJ
C H
M11 ^
o
Cont i nuous
17.0
Nil
28.3
4.5

3-0
47.2
Cycl ic
50-56
0.1-0.3
26-31
6-10

5-8
2-6
Oxygen-Bl
38.4
0.0
37.5
18.0
3.5
0.4
2.2
          Proximate Analysis of Coal, W%
          Moisture                   11.0
          Volatile Matter            35.4
          Fixed Carbon               44.9
          Ash                         8.7
Woodall Duckham/Gas Integrale References # 2 £ # 3
                               47

-------
       drying zone
       low temperature
       distillation zone
       gasification zone
      ash
              FIGURE A-8.1
           Two Stage Gasification
Reference: Wooda!1-Duckham Brochure

-------
                                TABLE  A-8.1
                  WD TWO-STAGE COAL GASIFICATION PLANTS
The WD Two-Stage process has been in commercial  use as a cyclic medium-Btu gas
generator since the 1920's and as a continuous air-blown fuel  gas generator since
19^2.  Over 100 units have been built in Europe alone.  The following lists are
confined to plants built since 1946.

A.    Industrial Fuel Gas Plants

     These units all employ a continuous air/steam blast as gasffication agent.
     Different numbers of standard sTze gasffiers (there are several  standard
     sizes) are used to obtain the required output.  A variety of coal  types
     are used, as indicated.  Mixtures of different coals have also been
     successfully employed.  Gas purffication is included on some plants.
     Client and Location

     Austrian-American Magnesia Co.,
         Radenthein, Austria

     VOEST Steelworks, Linz, Austria

     Cellulose & Paperworks,
         Frantschach, Austria

     Reforming Plant, Wels, Austria

     Gas Utility Co.,Graz, Austria

     Coke Plant, Strasbourg, France

     Coke Plant, Drocourt, France

     Steelworks, Audincourt, France

     Steelworks, Firminy, France

     English Steel Corp.,
         Sheffield, England

     Weldless Steel Tube Co.,
         Wednesfield, England
Coal Type

Bituminous


Lignite/Bituminous

Ligni te


Ligni te

Ligni te

B iturn!nous

B i t urn i nous /Coke

Bi turn!nous

Bi turn!nous

Bituminous


Bituminous
No. of Units
   3

   1


   1

   1

   3

   3

   1

   1

   7
                                                               (Cont inued)

-------
                     TABLE A-8.1  (Cont'd)
Client and Location

Ziar Aluminum Works,
    Czechoslovakia

Chomutov Tube Works
    Czechoslovakia

Istanbul Gas Utility Co.,
    Tu rkey

Australian Consolidate
    Industries Ltd., Sydney,
    Australia

Melbourne Gas Works
    Melbourne, Australia

Elgin Fireclay Ltd.,
    Springs, South Africa

Vaal Potteries Ltd.,
    Meyerton, South Africa

Union Steel Corp.,
    Johannesburg, South Africa

Stewards & Lloyds Steelworks
    South Africa

Masonite, Escault,
    South Africa

SAAPI, Mandini, South Africa

Rand Water Board,
    Vereeniging, South Africa

Drlefontein, Carltonville,
    South Africa

Vereeniging Refractories
    South Africa
Coal  Type

Bituminous


Lignite


Lignite


Bituminous



Bituminous/Brown Coal


Bituminous


Bituminous


Bituminous


Bituminous


Bituminous


Bituminous

Bituminous


Bituminous


Bituminous
 No. of Units
       3


       3


       2

       1


       2


       2


(Continued)
                              50

-------
                           TABLE A-8.1  (Cont'd)



B.   Publ ic Utility Gas Plants

     The following plants employ the same type of gasifiers, Including coal
     and ash handling systems, as the Industrial  Fuel  Gas Plants, but operate
     in a  cyclic mode so as to produce  a gas with a very low nitrogen content.
     The calorific value of the product gas is from 330 to 500 Btu/cu. ft.,
     depending on the extent of enrichment, e.g.  by carburation with distillate
     or residual  oil, or by enrichment  with LPG.


             Location of Utility                         No. of Units

             St. Poelten, Austria                             2

             Naples, Italy                                    2

             Rome,  Italy                                      5

             Trieste,  Italy                                   2

             Milan,  Italy                                     2

             LaSpezia,  Italy                                  1

             Como,  Italy                                      1

             Genoa,  Italy                                     *»

             Vierzon,  France                                  2

             Dijon,  France                                    2

             Kensal  Green,  England                             1

             Gloucester,  England                               1

             Ulm,  West Germany                                2

             Freiburg, West Germany                           2

             Zagabria, Yogoslavia                              '

             Prague, Czechoslovakia                           6

             Warsaw, Poland                                   3

             Thorn, Poland                                     2

             Tokyo, Japan                                     5

              Posen, Poland                                    3

                                    51                           (Continued)

-------
                                   TABLE A-8.1  (Cont'd)
C. Synthesis Gas and Water Gas Plants

   The manufacture of ammonia or methanol requires a low level  of methane in
   the synthesis gas.  Synthesis gas from coal  is produced in WD plants  by
   cyclic operation, including autothermic reforming of hydrocarbons,  or by
   continuous gasification with oxygen or an oxygen/air mixture.  If coke is
   specified as the feed, the upper (distillation) section of the gasifier is
   omitted.
   Client and Location

   OSW Fertilizer Plant
        Linz, Austria

   Vetrocoke, Porto Marghera,
        Italy

   Montecatini, Crotone,  Italy

   Montecatini, St.  Giuseppe
        di  Cairo, Italy

   I.M.A.D.,  Naples, Italy
   State Works,  Semtin,
        Czechoslovakia

   D.  Swarovski  Co.,
        Wattens, Austria

   Edison S.p.A., Milan, Italy

   Marconi  S.p.A.,  Aquila,  Italy

   Public Utility,  Paris,  France

   Public Utility,
        Fuerth,  West  Germany
   Mode

Oxygen Blown


Bituminous Coal ,
   Cyclic

Oxygen Blown

Oxygen Blown
Bituminous Coal,
   Cyclic

Coke, Cyclic
Coke, Cyclic


Coke, Cyclic

Coke, Cyclic

Coke, Cyclic

Coke, Cyclic
No. of Units
     2

     2

     2
     1

     1

     3

     1
                                       52

-------
SECTION B - DESCRIPTION OF GAS CLFAN-UP SYSTEMS
            ON OPERATING GAS IF IER INSTALLATIONS


            1 .  Introduction

            2.  Koppers-Totzek

            3.  Lurg!

            k.  Wilputte

            5.  Woodal1-Duckham/Gas  Integrals
                        53

-------
B.I        Introduction
          Particulates, sulfur and nitrogen are  the three pollutants
 in  industrial gases that have received the most  attention due to
 their potential environmental and health effects.  Their removal has
 been standard practice for decades in the manufactured and natural
 gas industry.  Perhaps more attention has been paid to the removal
 of particulates and sulfur than to nitrogen.  It is only recently
 that health effects of nitrogen oxides have begun to be given seri-
 ous consideration.  Much of the need to remove particulates  is associ-
 ated with potential problems in compressing and/or burning dirty
 gases.

          Raw coal-derived gases also contain tars along with sulfur
 compounds, and good removal of tars and particulates was a practical
 necessity in the early days of manufacturing and distributing coal-
 derived fuel gases.  Hence, many years ago, means were developed to
 remove tars and particulates from raw gas streams.  These methods
 may not be sophisticated in today's world but they served the purpose
 in their day.  Many of these methods were dual-purpose schemes.  For
 example, the dry box hydrated iron-oxide process removes essentially
 all hydrogen sulfide from the gas stream and will also remove traces
 of tar.  Furthermore, in the event of an upset in the tar scrubbing
 system, the boxes will capture a slug of material.  Although not
 specifically intended as such, the iron-oxide boxes were effective
 in preventing tars from entering the gas distribution system.

          Because the industrial gas is burned in vented equipment
 (as compared to household gas which is frequently burned in nonvented
equipment), the pollutant levels in industrial fuel can be somewhat

-------
higher than permitted in pipeline gas.   It would appear reasonable
to assume that industrial  fuel  gas should have about the same,  or
perhaps, as previously suggested, lower levels of contaminants  as
any alternative liquid fuel  would have that complies with the
Clean Air Act of 1971.  Consequently, a basis can be established
to evaluate and develop pollution control systems for the generation
and use of industrial fuel gas  from coal.

           If a sulfur emission  criterion of 0.5  Ibs of SC^ per  10
Btu is used as a guide, application of this specification to a  typi-
cal air-blown gasifier product  shows that the degree of sulfur  removal
required for industrial fuel gas  is substantially different from that
required for pipeline gas.  This  difference can  be clearly seen in
Figure B-l.l which has been prepared to show, in a generalized way,
the effect of coal sulfur content on the degree  of sulfur removal
required to meet the proposed level.  The chart  has been based on
calculations for a low heating value feed (lignite), a  typical
bituminous coal with a heating value of  12,500 Btu/lb,  and the
following  assumptions:
           a.  75% gasification efficiency
           b.  80% of  the  sulfur  in  the coal appears  in  the raw
              product gas.
For other  coals, a generalized formula for sulfur  removal  is given
 in the  Appendix.  The  sulfur removal curve for  pipeline gas  looks
as if  it were a vertical  straight line because  all  the  values are
so close  to  100%, but  some  of  the points  as  calculated  follow:
                               55

-------

-------
          % Sulfur in Coal              % Removal  for Pipeline Gas
                 0.2                              99-79
                 0.5                              99-92
                 1.0                              99-96
                 2.0                              99.98
                 5.0                              99-99
                10.0                              99.996
While pipeline gas requires just about complete sulfur removal, the
chart shows that a 1.^5% sulfur coal with a 12,500 Btu/lb heating
value would require only 30% removal from the raw product gas to
meet the 0.5 lb S02 per 10^ Btu level.  Even when processing coals of
a high sulfur content, there is a great difference  in the required
removal efficiency for the two gases.  These generalized curves are
of  importance because they show the great difference  in sulfur re-
moval requirements to prepare an  industrial fuel as compared to pipe-
line gas.  This difference man ifests itself  in sulfur  removal process
selection and the design criteria for  these processes.

          The technology of the past  two decades has  been developed
and  improved from the point of view of  essentially  total sulfur
removal from gases as would be required  for the pipeline  industry
and  the chemical  industry.  This  currently  practiced  technology
of  almost  total sulfur  removal is examined  in this  section  in  con-
sideration of  its proven capability,  but a  new  look at  partial re-
moval of sulfur  is  recommended.   The  ability  to achieve a  level of
removal exceeding  industrial fuel requirements  suggests that partial
removal might be  easier and more  economical.
                                57

-------
B.2       Clean-up System for the Koppers-Totzek Gas ifier

          Gasification:

          The Koppers-Totzek gasifier and a proposed clean-up system
for producing clean, desulfurized utility gas or synthesis gas
is shown schematically in Figures B-2.1 and B-2.2.  Oxygen, steam
and coal react in the gasifier, converting the coal volatile matter
and carbon into gas and the coal ash into molten slag.  About 50
to 70% of this slag leaves the gasifier through the bottom and
solidifies upon contact with water in the quench tank situated
beneath the gasifier.  The remainder of the slag, along with any
ungasified carbon, is entrained with the gas leaving the top of
the gasifier.  If necessary, water sprays freeze any slag droplets
prior to entry into the waste heat boiler to prevent solidification
on the tubes.  In the waste heat boiler, steam up to 1500 psig is
generated.

          A typical composition for the gasifier outlet gas before
any clean-up is given in Table B-2.1.  As shown, the gas may have
about 12 grains/SCF of particulates, 0.2-0.3% HgS and COS, and about
0.2% nitrogen compounds including ammonia, cyanides and oxides of
nitrogen.  Due to the high reaction temperature, phenols, pyridenes,
tar, oil or other condensable hydrocarbons are not contained in the
gas.
                                 58

-------
                      FIGURE B-2.1
                  KOPPERS-TOTZEK PROCESS
          GAS IFI CAT I ON, COOLING & PARTICULATE REMOVAL
Coal     BFW
 LJ
Gasi f ier
1
Steam
Slag
<

> i
Quench
Tank


N Spray
Washe
Coole


Wash
Water
>

\
l\ ^
1
99 99
Granular Slac
to Mine


i
r
r
Gas
»
The! sen
Di si ntegra-
tors


Overflow
Water
*


El
Cool ing
J^ater

-<-J

Slurry
Gas
i
Mist
imi nator
l
Gas
»
Electrostat i c
Preci pi tator
— ^-
-^-

-^-
<
Cool ing
Tower
-1
Blow DC
Treatm<
Clarif
Wate

Ian f ier
>lu Ige Fi
1 '
Fi ter
1

                   Gas to Chemical
                      Clean-up
Fi 1ter Cake
  to Mine
                           59

-------
                           FIGURE B-2.2
                   GAS PREPARATION FOR SYNTHESIS
       Gas from
Koppers-Totzek Process
          I
     Compressor
Rectisol
Sulfur
Remova1
          1
     Compressor
  Shift
Conversion
                                    I
                                 Rectisol
                                   C02
                                 Remova1
                                 Ni trogen
                                   Wash
                               To Synthesis
                                  Process
                               60

-------
                          TABLE  B-2.1


           KOPPERS-TOTZEK  GASIFIER  GAS  COMPOSITIONS
                      (Coal  Unspecified)



                                      Volume Percent
                                               To Compression  &
      Component             Gasifier  Outlet      Acid Gas  Removal

         CO                    37-36                49.50
         C02                    7-13                 3-k2
         CHij                    0.08                 0.11
         H2                    25.17                33-35
         N2                     0.30(1)               0.40
         H2S                    0.23                 0.30
         COS                  178 ppmv             235 ppmv
         HCN                  288 ppmv             300 ppmv
         NH,                    0.17                 0.22
         H20                   29.19                 6.20
         Ar                    0.32                   0.42
         S02               '    22 ppmv              15 ppmv
         NO                     7 ppmv               7 ppmv
Particulates (grs/SCF)          11.57               <0.002


NOTE:  (1) Possible Sources of Nitrogen With Oxygen-Blown Gasifica-
           tion includes Impurity in Feed Oxygen and Conversion of
           Fuel-Bound Nitrogen
Reference:  Farnsworth, J.F., Mitsak, D.M., Kamody, J.F.,
            "Clean Environment with K-T Process", presented
            at EPA Meeting: Environmental Aspects of Fuel
            Conversion Technology, May, 1974.
                             61

-------
          Gas  Cooling with Participate Removal:

          The  next  two or three process steps  reduce the participates
 in  the gas  to  very  low levels.  The effluent stream from the waste
 heat boiler enters  a washer-cooler where sprays of water cool the
 gas from 350°F to about  100°F while simultaneously removing 90$ of
 the entrained  particles.  Then two Theisen-type irrigated disinte-
 grators  in  series reduce the dust loading to about 0.002 grains per
 SCF.   If the gas is to be compressed to high pressures for chemical
 synthesis or for the production of high Btu gas, wet-type electro-
 static precipitators are used to reduce particulates to 0.0001 grains
 per SCF.  For  compression up to 175 psi, precipitators may not be
 necessary and  the gas, after passing through a mist eliminator and
 fan, would be manifolded into the suction of the gas compressors.
 The composition of  the gas at this point may also be seen in Table
 B-2.1.

          When Koppers (U.S.A.) first undertook design of Koppers-
 Totzek gasification units, they introduced the venturi scrubbers
 as a substitute for the washer-cooler and The!sen disintegrator
 system.  Since no units had been built that way, the German Koppers
 Company took a conservative position and suggested a return to
 the original design proposal.  While the venturi system does consume
 power, use of the disintegrator units requires  even more power con-
 sumption.  Each of the two Theisen units would require 700 HP for
gas from one ^-headed or two 2-headed gasifiers.  With the venturi
 system, the gasifier is operated at slightly increased pressure
 to provide the 50 inches of water pressure loss in the venturi
 scrubbers.   The first unit that might be installed in the U.S.A.
 is likely to have Theisen units because the designers will  look
                             62

-------
favorably on the proven approach.   However,  in the future,  venturi
scrubbers might be a good alternate choice.   For blast furnace appli-
cations, venturi scrubbers are now being installed rather than Theisen
disintegrators.

          Cooling Water Clean-up:

          Particulate-laden waters from gas cleaning and cooling plus
overflow from  the quench tank are piped to a clarifier.  Thickened
clarifier sludge  is filtered, and the filtrate  is returned to the
clarifier.  Filter cake and granular solids removed from the quench
tank by means  of a scraper-conveyor assembly are  loaded  into  rail-
road cars for  disposal at the mine site.  Clarified water  is pumped
to a cooling tower and recirculated to  the gas  cooling/cleaning and
the solids quench systems.

          Water  recirculation permits the build-up of  many chemicals
in the water.  Analyses at various steps  in the process  have  been
reported from  a  plant  in  Kutahya, Turkey.  The  data given  in  Table
B-2.2 show the order of magnitude of the  chemical concentrations and
identify some  possible contaminants.  Although  not  reported  in  the
Kutahya washer-cooler  analysis, dissolved hLS might be expected and
therefore stripped out by air  in  the cooling  tower.   If  all  the
dissolved H_S  were stripped  into  the air, the discharge  air  concen-
tration would  be 1-2  ppm  by  volume.  While  this is  far above  the odor
threshold,  Koppers  Company experience  shows  that  there is  no odor
problem.  A  previous  Environmental  Protection Agency  study verifies
this  finding  (K-T Reference  #6).   Appreciable bioxidation, common
 in  the  cooling water  circuit,  may account for  the indicated  analytical
 results and  Koppers'  observations.
                                63

-------
                                    TABLE  B-2.2
                             KOPPERS COAL  GASIFICATION

                          WATER ANALYSES.  KUTAHYA,  TURKEY(l)
Sample Location

pH Value
Conductivity

Total Hardness
CaO
MgO
Ma
K
Zn
Fe
NH/,
N02
N03
P0|,  Total
Cl
S0{,
KMnO/t  Consumed
COD
Si02
Suspended Solids
Hot Residue, 800°C
Stripped Residue
Hot Residue, 800°C
Cu
mho/cm

0 dH
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
8.8
7.6
10-*
20.8
78
97
17-5
5.6
0.01
0.05
0.32
0.02
58.2
1.89
18
42
0.26


8
14
14.8
14
4
568
268
0.01
8
1
10
33
101
161
17
8
0
0
157
0
3
0
85
216
0


9
18
16
4612
3918
812
550
0
.8
.8
-3
.5


.5
.8
.03
.22

.13
• 32
.81


.52




.0




.01
8
2
10
36
78
194
17
10
0
1
184
4
13
1
96
155
12


400
128
14
5084
4356
940
588
0
• 9
.0
-3
.8


.5
.0
.02
• 95

.47
.7
.21


.5




.8




.01
7
9

22
85
102
17
6
0
0
25
5
34
1
53
147
7
r»z»
Uc
14
18
30
278
134
606
366
0
.5
.7
-4
.8


.5
.8
.03
.26

.34
.0
.69


.0
+ ar~i
teci


.6




.06
8
1
10
34
135
145
17
8
0
0
137
0
24
0
57
255
1
•orl

11
16
19
3072
2690
706
526
0
.8
.8
-3
.0


.5
.0
.02
.20

.24
.7
.81


.4




.8




.01
8.
1.
10-
34.
179
113
17-
8.
0.
0.
122
4.
22.
2.
46
109
14.


145
63
42.
50
46
724
512
0.
9
8
3
8


5
0
02
64

37
9
70


0




6




06
8.9
1.7
10-3
35.2
179
129
17-5
7-9
0.02
0.24
72
23.7
42.0
2.41
36
153
0.7



60
30.6
58
42
828
534
0.27
1)  Cooling water to gasifier seal pot.

2)  Water from the gasifier seal pot.

3)  Wash water after washer-cooler.

4)  Wash water after Theisen washer.
                              5)  Water into clarifier.

                              6)  Water out of clarifier.

                              7)  Water out of cooling tower,
NOTE:  I)  Process Water Streams Circulated within Process Unit.  Any purge
           Stream from the System Would Require Treatment before Discharge.

Reference:  Farnsworth, J.F., Mitsak, D.M., Kamody, J.F., "Clean Environment
            with K-T Process", presented at EPA Meeting: Environmental Aspects
            of Fuel Conversion Technology, May, 1974.
                                          64

-------
          An additional cooling tower effluent is the drift loss of
mist from the cooling tower.  The mist will contain dissolved and
suspended solids, which will result in deposits on the ground and on
nearby equipment.  To minimize solids build-up in the cooling tower
circulation and the intensity of its attendant problems, blowdown
is necessary.  Acceptable stream standards must be met by treatment
of the blowdown, principally to destroy HCN and NH^ through chemical
chlorine oxidation and pH adjustment.  Evaporation, windage and blow-
down water losses at the cooling tower, plus moisture in the filter
cake from clarifier sludge and in slag, necessitate the addition of a
small quantity of make-up water to this system.   If water  is at a
premium, air cooling may be used for cooling down to  1^0 F  in certain
applications and the cooling tower can be  reduced  in  size  to provide
only the final trim  in water temperature.

          Gas Clean-up: .

          The cool,  clean gas  leaving  the  gas  cleaning  system con-
tains sulfur compounds which must be  removed  to  meet  gas specifica-
tions.  The  type of  system  chosen depends  upon the end  uses  and
pressure of  the  product gas.   For  low  pressures  (up  to  150  psig)  and
low  Btu gas  application,  there are  the chemical  reaction processes,
such as amine and  carbonate systems.   At  higher  pressures,  the  physi-
cal  absorption  processes, such as  Rectisol, Purisol  and Selexol,
are  recommended.   The  choice of  the  process  is also  dependent upon
the  desired  purity of  the product  gas  and the  desired selectivity
with respect to the concentrations  of  carbon  dioxide and sulfides.

           There are several  acid  gas  removal  processes  with the
capability  of  reducing the  sulfur content in  the gas to 5  ppm by
                                65

-------
volume.  The  processes are based  on  absorption  in  solution and subse-
quent  stripping of  the acid gases, H2S  and  CQ-2,  from  the solution.
The physical  absorption  processes, which operate at pressures of
300-400 psig, exhibit the greatest selectivity with respect  to
hydrogen sulfide and carbon dioxide  removal.  Since no  chemical
reactions occur, these processes  do  not form stable compounds, such
as thiosulfates and thiocyanates.  Some chemical reaction processes,
such as carbonate and atnine, which form the aforementioned stable
compounds, can be used but will require periodic dumping of  the
solution in order to maintain removal efficiency.  Dumped solution
will require  treatment to meet permissible discharge  limitations.
The choice of process is dependent upon economics,  environmental
control, purity of product gas, and  desired acid gas  selectivity.
A plant can be designed  to reduce sulfur in product gas to 5 ppm
by volume, control the H2S level  in  carbon dioxide to 10 ppm by
volume, and control the  liquid effluent to zero  pollutants.

          The tappers Company, it is understood, is proposing the
use of MOEA (methyl dlethanolamtne)  for selective  removal of H2S.
This chemical has sufficient selectivity to provide about a 22%
H2$ concentration in the acid gas to the Claus plant.  The acid
gas removal facilities consist of a  COS hydrolysis column followed
by an absorber.  Within  the COS hydrolysis column, the gas is con-
tacted with hot circulating MDEA solution to promote  hydrolysis of
COS to H2S in order to facilitate a high degree of sulfur removal
withtn the absorber.  The acid gases are stripped  from the MDEA
absorbent and sent to Claus units.  Gas leaving each  H?S absorber
contains approximately 115 ppm of HjS, plus COS, or 0,076 pounds
of S02 equivalent per million Btu of gross heat content of the fuel
gas.
                              66

-------
          At the African Explosives and Chemical  Industries  Ltd.
ammonia plant in South Africa,  where coal  is gasified using  the
Koppers-Totzek process, gas is  cleaned up  with the Rectisol  process.
First a methanol wash at -36°F  and 30 atm. desulfurizes the  gas.
Then carbon dioxide is removed, following  the CO shift conversion,
by washing with methanol at -72 F and 51 atm.  Finally, residual
CO, argon and methane are removed by washing with liquid nitrogen
at -310°F (K-T Reference #10).
          The acid gas stream, containing a minimum of I1* volume
percent HjS, is catalytically converted to elemental molten sulfur
in a Claus unit.  The tail gases exiting the Claus unit contain S02
and can be treated to catalytically reduce the S02 to H2$•  Scrubbing
with an amine solution absorbs the H.S, and subsequent stripping
yields an HjS stream which is recycled to the Claus unit.  This
combination results  in overall sulfur recovery of 99+%.
                                67

-------
B.3       Clean-up System for the Lurgi Gasifier

          Gas ificat ion:
          The Lurgi gasifier and its clean-up system for producing
SNG has been carefully studied and, therefore, is illustrated in Figures
B-3.1, B-3.2 and B-3.3  The proposed El Paso Burnham Coal Gasification
Complex exemplifies such an application for the Lurgi process when used
for pipeline gas.  Industrial gas, as explained in the Introduction,
would require less stringent control of pollutants and thus, would pro-
vide more flexibility in the control methods for pollutants.

          Coal entering from lock hoppers reacts with a mixture of
oxygen and process steam introduced into the bottom of the gasifier.
About 86% of the coal  fed to the gasifier is gasified and the remaining
lk%, which is mostly carbon, is burned in the combustion zone.  Ash,
bearing only a very small amount of unburned carbon, passes down through
the grate, out of the gasifier through an ash lock hopper, and into an
                                                              •
ash bin where ash is cooled by water quenching.  The ash is separated
from quench water in a clarifier and sent to the mine site for disposal.
It is estimated that 1.k% of the DAF coal  is not consumed and leaves
with the ash.

          Gas Quenching:
          Raw gas leaves  the gasifier at about 850°F containing
carbonization products such as tar, oil, naphtha, phenols, ammonia,
and traces of coal and ash dust.  On an oil-free and dry-gas basis,
the gas leaving the gasifier will  have the following approximate
composi tion:
                                 68

-------
                  FIGURE  B-3.1
                  LURGI  PROCESS
          GASIFICATION AND  ASH HANDLING
                 Coal
   Coal
Lock Hopper
                                    Vent  Gas  to
                                    Gas Cool ing
Steam
               Gasi fier
                  i
    Ash
Lock Hopper
                 Ash
                Quench
               Clari fier
                      Gasifier Outlet Gas
                        to Gas Cool ing
                                    Vent Gas to
                                    Gas Cool ing
                            Water
                            Ci rculation
               Ash  to  Mine

-------
                      FIGURE B-3.2
                      LURGI PROCESS
 GAS COOLING, SHIFT CONVERSION AND GAS LIQUOR PROCESSING
        Gasi fier
       Outlet Gas
         Spray
         Wash
         Coo 1e r
           100 psig Steam
       Waste Heat
         BoiIer
         Raw
         Gas
i
  Shift
Convers ion
    Gas
  Cool ing
                                Steam
                                I
Waste Heat
  Boiler
                           Gas
                         Cool ing
        Gas  to Acid  Gas  Removal


                            70
           H
                                                Compressor
                                               Gas Liquor
                                                 Flash
                                               Separation
    Tar
 Separat ion
Gas Liquor
Treatment

                                          Treated  Effluent  Liquor
                                          to  Biological  Treatment
                                                                    Tar to
                                                                    Storage
Phenol


Ammon i a

-------
                              FIGURE B-3.3
                  RECTISOL GAS CLEAN-UP AND METHANATION
     Synthesis Gas
     Refr.
                                Naphtha
                                                  Water to
                                                 Gas Liquor
                                                 Treatment
                            t
      Prewash
      Tower and
      Flash Tank
Methanol
               i
                       Naphtha
             Methan'oJ | Extractor &
                       Azedtrope
                       Tower
            Methanol-
            Water
            Column
      Gas
Acid Gas to
Claus Unit
H2S
Absorber
                   Methano    Flash
                              Regenerator
Recovered
Methanol
            Hot
            Regenerator
                             Compressor
                             1st Stage
                                               Compressor
                                               2nd Stage
                                                          SNG
                                     71

-------
                    C02       28.6 MoU
                    CO        20.2
                    H2        37.9
                    Chi,       ll.it
                    C2H6         .62
                    H2S + COS    .1*9
                    N2 + A       .33

          This crude gas is then cooled rapidly to AGO F by quenching
 in  the spray washer with gas liquor, an aqueous phase condensed from
 the gas.  Further cooling in the waste heat boilers drops the temperature
 down to about 360°F to 370°F while generating 100 psig steam.  As higher
 boiling tar fractions are condensed, coal  and ash dust are bonded to the
 tar.  Some of the liquid condensed in the waste heat boilers is recycled
 to the wash coolers, and the excess is drawn off to gas liquor separation.

          Gas liquor from the spray washer and the gas cooling area is
 flashed to atmospheric pressure  in an expansion vessel to remove dis-
 solved gases.  Heavy tar is separated out  in another vessel and sent to
 storage.  The mixture of tar and dust is returned to the gasifier for
 cracking and gasification.   The detarred liquor is sent to the gas liquor
 treatment area to remove dissolved phenol  and ammonia.

          Shift Conversion  and Gas Cooling:
          Raw gas leaving the gasifier section is divided into two
streams; one is sent to shift conversion where the hydrogen content
 is increased and the other goes directly to gas cooling.  Crude gas
vented from the cyclic operation of the coal lock hoppers, the expansion
gas from gasification, and small quantities  of recycle gas from other
areas are compressed and injected into the stream which goes directly
 to the gas cooling area.

          The crude gas bypassing shift conversion is cooled in a
series of units comprised of the following:   a waste heat boiler

                               72

-------
generating 60 psig steam,  a low pressure  steam  generator,  an  air
cooler and possibly a water trim cooler.   Gas  liquor  and  tar  from  the
first two units are transferred to the  primary  gas  liquor separator.
The remaining condensate streams, comprised of  gas  liquor and a tar
oil naphtha mixture, are separated in a second  gas  liquor separator.

          Converted gas is cooled by the  following  series:  exchange
with boiler feedwater, generating low pressure  steam, boiler  feedwater
deaeration, and finally air and water trim cooling.  The  two  gas streams
are combined into a single stream before  acid gas removal.  Gas  liquor
and condensate from the first three steps are cooled  and  combined  with
condensate streams from subsequent cooling.  The total stream is  then
sent to the gas liquor separator where separation of  the  tar  oil  naphtha
mixture from gas liquor will occur.  Gas liquor will  be pumped to  the
gas liquor treatment area and the tar oil  mixture will be  transported
to storage.

          Gas  Liquor Treatment:
          Gas  liquor condensed  in coal gasification and gas processing
contains  phenols, ammonia, carbon dioxide, hydrogen sulfide and caustic
effluent.  The Lurgi Phenosolvan  Process can be used to  recover the
phenols.  Ammonia  is  recovered  in aqueous  solution.  The other con-
taminants are  removed  from  the  liquor by heating and stripping.

           Incoming  gas  liquor entering the Phenosolvan Process is
filtered  in  gravel  filters  to  remove suspended matter.  The  filtered
liquor  is  then mixed with  an organic solvent (isopropyl ether) in
the extractors where  phenols are dissolved in  the  solvent.  The
phenol-rich  solvent extract  is  collected  for feed  to  the solvent
distillation  column, where  crude phenol  is recovered  as  the  bottoms
product and  solvent as  the  overhead product.   Recovered  solvent is
                                 73

-------
 separated from the  water  by  settling  and  then, with  some make up of
 fresh  solvent, recycled to the extractors.

           Before being heated  and  steam stripped,  the  lean  liquor
 (rafflnate)  from the extractors  is stripped with fuel  gas to remove
 traces of solvent which are  picked up in  the extraction step.  The
 resulting solvent-laden fuel gas is scrubbed with  crude phenol to
 recover the  solvent.  The phenol-solvent mixture is  then fractionated
 in  the solvent recovery stripper to produce the crude  phenol product
 and collect  the solvent for  recycle to the extraction  step.

          Solvent-free liquor is heated and steam stripped to remove
 carbon dioxide, hydrogen  sulfide and  ammonia.- The carbon dioxide
 and hydrogen sulfide are  removed separately from the ammonia and
 returned  to  the process for sulfur recovery.

          Ammonia is stripped from the liquor and  condensed as an
 aqueous solution of about 25 weight percent NHj.   In the event that
 a market  does  not develop for this  product, the wet ammonia vapor
 can be consumed as plant  fuel provided NOX emissions are within
 limits.

          Treated effluent liquor  from the ammonia stripper is cooled
and delivered  to the biological treatment plant for further reduction
of  contaminants to render it suitable for use as cooling tower make-up.
Before biological  treatment,  the effluent contains less than 20 ppm
phenols and  less than 60 ppm free  ammonia.  Afterward, the effluent
meets  the regulations for disposal  of waste liquor.

-------
          Gas  Clean-up and Methanation:
          For  SNG manufacture,  the gas purification plant  is  designed
to remove h^S  and COS to a total  sulfur concentration of 0.1  ppm by
volume using the Lurgi Rectisol  Process.   After methanation and
first-stage compression, the gas  is washed to reduce C02 content.
Because of the low operating temperatures (down to -50°F),  all
hydrocarbons heavier than G£ are  removed, leaving a very clean  gas
stream for the methanation section.

          The mixed gas is chilled before entering the prewash  tower
where water and naphtha are removed by cold methanol wash.   Naphtha
is recovered from methanol and water by means of the naphtha extractor.
Naphtha recovery is maximized by recycling the naphtha-methanol mix-
ture through the azeotrope column.  The methanol is  recovered by
distillation in the methanol-water column.

          The naphtha-free gas enters the h^S absorber where H2$ and
COS are removed down  to 0.1 ppm by volume total sulfur by cold methanol
wash first used for C02 absorption.  Heat of absorption is removed
by refrigeration.  Some of the absorbed acid gases are  removed from
the methanol wash by  multi-flash  in the flash generator.  The  remain-
ing acid gases are completely stripped in a second regenerator operating
at a higher temperature.  All the  acid gas streams are  combined and
delivered  to the sulfur  recovery  plant.

           The sulfur-free synthesis gas  leaves  the Rectisol  Unit
absorber,  exchanges  heat with returning methanated gas  to  save on
refrigeration,  and moves  on  to the methanation  unit.  The  returned
methanated  gas  enters the  CO. absorber.   The C02 content of  the gas
 is  reduced  by  regenerated  cold methanol wash.   The heat of absorption
                               75

-------
is removed by a refrigerant.  The high Btu purified dry gas is warmed
and sent to the second-stage compression unit.

          The mechanical compression refrigeration unit provides
refrigeration at two temperature levels.  The high temperature
level refrigeration (32°F)  is used to condense most of the water
out of the mixed gas and the methanation product gas.  The remaining
water vapor in the gases is prevented from freezing by methanol in-
jection.  The low temperature level refrigeration (about -50°F) is
used to achieve the low temperature required for effective methanol
wash.

-------
B.4          WMputte Gas  Clean-up System


             The Wilputte  gasifier is  a moving-bed  gasifier,  operating
at atmospheric pressure.   The operating principles  are  described in
Wilputte Bulletin No. 7662.  as quoted  below:
                       "The gasification process is  counter current.
                  Thus, the coal  is fed downward and the gas flow
                  is upward.  Moist air flows upward through an ash
                  zone to the cumbustion zone, in which the carbon
                  residue from pyrolyzed coal is burned to carbon
                  dioxide (the water in the air does not enter
                  this reaction).  Various reactions occur in the
                  bottom of the coal bed which lays  directly above
                  the combustion zone.   The carbon reacts with the
                  carbon dioxide to form carbon monoxide or with
                  water to form hydrogen and carbon monoxide or
                  carbon dioxide.   In the middle of the coal bed,
                  carbon reacts with carbon dioxide to from carbon
                  monoxide.  In the top of the coal  bed, coal is
                  pyrolyzed to form a carbon residue and volatile
                  hydrocarbon products.  The coal in the top of the
                  charge passes through a plastic state when it be-
                  comes heated to about 850°F if the coal  is a coking
                  coal.  A rotating rabble arm  is used to mix and
                  break up this plastic layer so as to get a uniform
                  distribution for  the upward flow of gas."
             An example of the gas clean-up system used on Wilputte

gasifiers  is the  installation at the Holston Defense Corporation in

Tennessee.  This  plant consists of 12 gasifiers each having a diameter

of 9'-2".  Each unit is rated at 2k T/D of coal feed.  The plant was
built  in  19^5.  Two gasifiers at any one time are in operation using
a metallurgical grade of bituminous coal having a sulfur content of
less than  1%.  These gasifiers have had an excellent maintenance re-

cord.  The original brick lining in the gasifier is still  in use.
                                  77

-------
             A  very  simple and straightforward gas clean-up system  is
 used  on  the  Holston  gasifier  installation.  Raw gas leaves the gasifier
 at  a  temperature of  about MOO F and enters a refractory lined cyclonic-
 type  separator  that  removes larger sized entrained particles.  The gas
 then  flows to a "primary gas  cooler" through a collector main.  Hot
 liquor  is sprayed  into the main reducing the gas temperature to about
 200 F and removing the bulk of the tar prior to entry into the cooler.
 No  waste heat is recovered from the gasifier effluent stream.
             The "primary gas cooler" is packed tower that is irrigated
with cooled liquor.  Condensed tars and wash liquor from the collector
main and the gas cooler flow by gravity to a sump where separation of
liquor and tar occurs.  The tar has a specific gravity of about 1.15 and
therefore settles to the bottom of the sump.  This material  is pumped
to storage for subsequent use as a boiler fuel.  Solids are periodically
raked from the sump.

             Liquor from the sump is pumped and recirculated in a
split-flow arrangement.  Part of the liquor is returned directly to
the collector main as"hot" liquor while the remaining part is cooled
via water exchange to enter the top of the cooler.  Excess liquor is
treated by sand filters and carbon absorption to produce an acceptable
effluent stream.

             Overhead has from the "primary gas cooler", which actually
is a counter-current gas scrubber, flows to an exhauster that boosts
the scrubbed gas to a fuel gas header pressure of about 10 psi.   The
gas then flows to the individual  burners for combustion without  a
sulfur removal  step.
                                78

-------
             As  can be seen,  the  clean-up  system  is  extremely  simple,
comprising no moving parts  other  than  the  tar  and  liquor  pumps  and  the
exhauster.  Over 30 years of operation of this  gas  clean-up  system  is
ample proof of its basic operability  and simplicity.  Unfortunately,
this simplicity  cannot be maintained  if the  plant  were tooperateon
a high-sulfur coal and would,  therefore,  require  sulfur clean-up
on the gas product.  Nevertheless,  the existing gas  clean-up system
used at the Holston installation  is a  working  example  of  a  simple,
pratical  approach to removing tar,  dust and  some  ammonia  from a
coal gasifier effluent so that the  product gas can be  properly burned
as an industri al fuel.
                                 79

-------
B.5       Clean-up System on Woodal1-Duckham/Gas  Integrals Gasffier
          Effluent

          The principle of Woodal1-Duckham/Gas  Integrale (WD/Gl) two-
stage coal gasification is to separate the volatile matter of the
coal before subjecting the remainder of the coal to the high tempera-
tures of the gasification reactions.  As the coal descends through
the fixed-bed gasifier, the coal is dried, then evolves gas, light
hydrocarbons and tar, and reaches the bottom of the upper part of
the gasifier as semi-coke, or char  if the coal  is a nonagglomerating
coal such as sub-bituminous or lignite.

          The semi-coke or char now passes into the gasification
zone, where temperatures rise from about 1200°F at the side gas
off-take to typically 2200°F at the final combustion stages.

          The gasification agent converts the semi-coke into carbon
monoxide, carbon dioxide, hydrogen, some undecomposed steam and nitrogen.
This product Is termed clear gas.  About half the clear gas is with*
drawn at 1200°F via the side gas off-take, the remainder passing
overhead to dry and devolatilize the coal.

          This split-flow system, together with a very low gas off*-
take velocity, keeps fines carryover to a very low level.   Very low
fines carryover is one of the features of two-stage gasification
which distinguish it from single-stage gasifiers.  Figure B-5.1
shows how two-stage gasification lends itself to a simple and effec-
tive gas clean-up.  No direct contact scrubbing Is used.  The top
gas at 250°F, containing all the coal  volatile matter, is  electro-
statically detarred, indirectly cooled, and passed through a second
                                80

-------
                             •GASIFICATION SECTION
                           •DESULFURIZATION SECTION-
oo
                vCool
                                     ^Steam       Tar        Oil
                                              Precipitator  „ Precipitator     H2S
                                                                     Absorber
/F0TW
r  CW|    r
    &,
                                                                       K
                                                                       x
                                                                       E
                         ,, Gasifier
                        Ash
Vacuum
 Filter
                                              n
                                   Air Blower    Tar& Oil  Aqueous
                                  (or O2 supply)    Tank   Effluent
                             Pumping Air  Oxidiser  Sulfur
                              Tank  Blower       foam tank
                                                                                                           Fuel
                                                                                                           Gas
                e
                                                        JSulfur
                                                         Cake
                                                          Fuel
                                                          Oil
                e
                                      wryci PROCESS FOR COLD DESULFURIZED  FUEL GAS
                                                       FIGURE B-5.1

-------
 precipitator  to  ensure  full  demisting.

          The clear gas at  1200°F,  containing  no volatile matter,
 ts dedusted and  cooled  in a  combination of waste heat  boiler and
 tubular cooler.

          The combined gas can be desulfurized by several well-known
 processes, such  as the Stretford process,  A Stretford unit in simpli-
 fied schematic form is shown  in Figure C-7-1,  and this process has
 been used to  desulfurize gas from WD/GI gasifiers to produce a sul-
 fur cake.

          Host of the sulfur contained in the  coal feed will be in
 the product gas, mainly as H2S with 5 to 10? of the sulfur appear-
 ing as COS and CS_,  The H.S is easily removed in a Stretford unit
 to give a final product gas which can comply with SO.  emission re-
 quirements for industrial fuel gas.  For low-sulfur coals, HgS
 removal may not be necessary.  Due  to the low  temperature pre-
 distillation of the coal obtained in the two-stage process, the
 product contains only traces of hydrogen cyanide (a few ppm), unlike
many gases obtained from coal.  This simplifies and reduces the cost
of the Stretford unit.

          The cooling of the sulfur-bearing gases prior to entry
 into the sulfur removal system produces a contaminated aqueous
stream.  An important feature of the process is that by using
 indirect cooling the volume of contaminated aqueous effluent is
sharply reduced compared to direct contact cooling.  This minimizes
the cost of effluent disposal and,  indeed, often makes simple
 incineration as attractive as biological treatment of this aqueous
stream.  Recycle of this stream to the gasifier has been practiced,
                                82

-------
but further development work is  required before  WD/G1  feels  it  is
appropriate to offer this process  variant on  future  plants.

           It should be emphasized that each  feedstock coal  presents
differing operating problems.  Therefore, the gas clean-up system
would normally be tailored to the specific type  of feedstock and
may not be the same for each plant.  The flow sheet  shown in Figure
B-5.1 does represent a design that has been reduced  to practice (in
South Africa).  Specific gas analyses are not available, but the pro-
duct gas should meet all proposed EPA guidelines for the following reasons.

           Part iculates:
           Solids removal is effected by cyclones, electrostatic precipi-
tators and finally by  scrubbing with the acid-gas removal liquid (Stretford
solution).   It is highly unlikely that the fuel  gas, after these successive
processing steps, would exceed the particulates emission limit of 0.1 Ibs per
10  Btu of gas, and  it  most  probably contains a small  fraction of this amount,
Particulates  formed  during  the combustion  step  for  low Btu  gaseous fuels
are  generally  known  to be far less than  0.1  Ibs  per  10  Btu; hence,  the
sum  of the ash particles plus the  soot  particles  should be  less than 0.1
Ibs  per  10   Btu.

           Sulfur  Dioxide:
           About 90% of the sulfur-containing gas in  the raw  fuel
gas  is H.S,  the  remaining 10% being  COS  and  CS_  with  traces of
mercaptans.   The Stretford  unit  removes  essentially all  of  the
H_S  but  does not  remove COS, CS_  and the mercaptans.   If it is
assumed  that 85% of the sulfur  in a  feed coal containing 3% sulfur
appears  in the gas  product, then  this  10% of "organic" sulfur  that
 is not removed will produce nearly 0.5 Ibs of S02 per 10  Btu  when
 this fuel  is burned.  Therefore}  given the suggested EPA guideline
                                 33

-------
of a maximum of 0.5  Ibs of S0_ per  10  Btu for  industrial gas, it
appears that coal of up to 3% sulfur can be converted to fuel gas
of acceptable quality using the equipment as shown In Figure B-5.1.
Use of coals higher  than 3% sulfur may require  the partial removal
of organic sulfur compounds (in addition to removal of H-S) in order
to meet the emissions requirement guideline.  Some processes are
available to meet this requirement.

          The NOX content of combusted gas is determined mostly by
flame temperature, excess air and the chemically-bound nitrogen in
the fuel itself.  Because the theoretical flame temperature of the
WD/GI fuel gas is some 200°F colder than high-Btu (natural) gas,
the thermal fixation of N0x should be reduced.  Fuel-bound nitrogen,
if present, should exist in the converter effluent gas as HCN and
NH, with only traces in the HCN form.  NH^ will probably be found
in varying amounts, depending on the quality of the coal, time-
temperature history of the coal particle, and hydrogen partial pres-
sure.  Not all  of this ammonia will end up as NO  because some
                                                J\
ammonia is removed by the gas clean-up as an aqueous condensate and
various studies show limited combustion of the remainder to NOX.
Thus, ?t is believed that NO  formation from this fuel gas will be
substantially below the guideline emission level of 0,4 Ibs of NO
      6                                                          x
per 10  Btu.

          The presence of water vapor in a gas  is also known to lower
the formation of NO  during the combustion process due to a cooler
                   y»
flame.  WD/GI gas normally contains an appreciable amount of water
vapor because it is saturated with water at about 100 F or higher.
Therefore, the beneficial  effect of decreased NO  formation is generally
                                                ^
realized when this gas is burned.
                                 84

-------
          Commercial Operations:
          The commercial operations of several WD/GI units to produce
synthesis gas for ammonia or methanol synthesis are further proof
that gas clean-up methods have been developed to adequately purify
coal-derived gases to a degree of purity higher than required by
industrial fuel gas.  The sulfur and particulate contents of
synthesis gas must be essentially zero in order to avoid the poison-
ing of catalysts; hence, gas clean-up to less stringent criteria
would appear to be demonstrated.  This is not to say that significant
improvements cannot be made, but coal-derived gases can be purified.
                                  85

-------
SECTION C - COMPARISON OF IRON-BASED CLEAN-UP PROCESS AND
            THE STRETFORD PROCESS

            1.  Introduction
            2.  Development of Gas Clean-up Processes
                2.1  Iron Oxide Box Purifiers
                2.2  Liquid-phase Iron Oxide Processes
                2.3  Stretford Process
            3,  Basic Chemistry
                3J  Iron Oxide Box Process
                3.2  Liquid-phase Iron Oxide Processes
                3-3  Stretford Process
            A.  Design Basis and Assumptions
            5.  Iron Oxide Box Purifiers
                5.1  Design Based on American Practice
                5.2  Design Based on European Practice
                5.3  Discussion
                5.4  Advantages and Disadvantages
            6.  Liquid-phase Iron Oxide Processes
                6.1  Process Description
                6.2  Process Requirements
                6.3  Advantages and Disadvantages
            7.  Stretford Process
                7,1  Process Description
                7.2  Process Requirements
                7,3  Advantages and Disadvantages
                      86

-------
C. I        Introduction

          Recent interest in gas clean-up has  generally been directed
toward the use of processes which almost completely remove pollutants
because of the stringent standards necessary for pipeline gas or
synthesis gas.  With revived interest in industrial gas generation,
a new prospect to be considered is a reexam5nation of old technology.
This type of process may not be so complex or  costly and may be applied
if a lower percentage of sulfur removal  is satisfactory as is the
case of industrial fuel  compared to pipeline gas.  Processes possibly
falling into this category are those based on  iron oxide and a great
deal of information on both the iron oxide box and liquid versions
are given in Kohl and Riesenfeld's text (iron Oxide Process Reference
#3).  This section, therefore, will consider the old and new techno-
logies that might be applied to make industrial gas by comparing
designs of older  iron oxide processes with the Stretford process
as the representative of modern day development.  Either way, the
sulfur level can be brought within the guideline level of 0.5 Ibs
of S0_ per 10  Btu for industrial fuels while making elemental sulfur
directly without a Claus unit.

          Iron oxide boxes are one of the oldest methods for gas
purification still  in industrial  use.  The engineering design of
units for industrial gas clean-up  is possible from publicly available
sources of  information.  American and European practices differ and
the  results of both are  presented.

           Improvements of  the  iron oxide  process to save on space
requirements  and  labor and  to  recover sulfur  resulted  in  the develop-
ment of a continuous  liquid-phase sulfur  clean-up  system.   The
economic  factors  that promoted  this  development  are still valid
                                 87

-------
today when cleaning industrial gas.  Thus, a generalized combination
of the Ferrox, Gluud and Manchester iron-oxide-based liquid-phase
processes was used for a process design comparison case.

-------
C.2       Development of  Gas  Clean-up  Processes

          2.1   Iron Oxide Box Purifiers

          The  iron oxide  process  was  introduced  in  England  around
the middle of  the 19th century.   Before  that time,  a  wet purification
process utilizing calcium hydroxide as the active agent was used.
Although iron  oxide processes are still  used on  a large scale for
treatment of coal gases,  recently developed wet  purification pro-
cesses have gradually been replacing oxide box purifiers.

          A simple form of the dry-box process utilized for the first
batch-type installations completely removed hydrogen sulfide with
hydrated ferric oxide.  At the completion of a cycle, ferric sulfide
formed  in the reaction is oxidized to elemental  sulfur and ferric
oxide by exposure to air.  Hydrogen sulfide is oxidized  to elemental
sulfur  and water  in  the overall chemical  reaction.  The  cycle  is
repeated until sulfur fills most of the pores and coats most surfaces
with  tar and sulfur.  Then the bed is less active, pressure drop
increases and the bed must be removed from the box for cleaning.
The oxide was often  reused after the  sulfur had been removed.  Any
current applications of  this process must dispose of the tar and
sulfur  laden spent oxide  not  suitable  for  regeneration  in a way com-
patible with present environmental standards.

          More economical  revivification  methods were  discovered
later.   In one,  the  iron is  revivified  continuously  by  addition
of small amounts  of  air  or oxygen  to  the  purification  plant  inlet
gas.   The other  method  involves  a  cyclic  in situ revivification
by circulation of oxygen-containing gas after the  bed  has  been
fouled.  Eventually, the iron oxide bed must  be  removed  to avoid
                                89

-------
 excessive back  pressure and  to maintain good gas contact.  Benefits
 of  the  revivification  improvements were a savings due to reduced
 frequency of  loading and unloading and the achievement of a higher
 level of sulfur content before  it was necessary to dispose of the
 iron oxide batch,

          2,2  Liquid-phase  Iron Oxide Processes

          Since the main disadvantages of dry  iron oxide purification
 are large ground space requirement, high labor costs of the purifica*-
 tion plants and the disposal of a large quantity of spent iron oxide,
 a search for  more efficient methods for hydrogen sulfide removal
 from the gases  was undertaken.  This search-resulted in the develop-
 ment of the liquid-phase iron oxide processes.  A logical step employed
 liquids in regenerative cycles and utilized reaction between iron
 oxide and hydrogen sulfide followed by conversion of iron sulfide
 to  iron oxide and elemental sulfur.  Starting with the work of
 Burkheiser shortly before the first World War, several processes
 which were developed in Europe and the United States used iron oxide
 suspended in  alkaline aqueous solutions.  The Koppers Company of
 Pittsburgh introduced the Ferrox process in the 1920's,  Gluud intro-
 duced a similar process in Germany.  In England, a more recent modi-
 fication of the Ferrox process, known as the Manchester process,
was introduced.

          Use of these processes has been diminishing to some extent.
At present the  Burkheiser process is not in commercial use although
a new proposal  for a novel coal-gas purification scheme has been
made.   While  a  few Ferrox plants are still  operating in the United
States, most  have been replaced by more modern systems.   The Gluud
process still finds some use.  In Great Britain, where the Manchester
                                  90

-------
process was popular, the Stretford process covered later in this
section is replacing it.

          2.3  Stretford Process

          The Stretford process was developed in the early 1960's
by the Western Gas Board and the Clayton Aniline Company for removal
of hydrogen sulfide from coal gas.  Initially, an alkaline solution
containing the sodium salt of 2-6 and 2-7 anthraquinone disulfonic
acid (ADA) absorbed H2S and converted it to sulfur.  Due to the
excessively long reaction time between f-LS and ADA, equipment sizes
were large and the solution had an excess dissolved salt accumulation.
The discovery of adding vanadate salts to the alkaline  ADA solution
reduced the reaction time.  The vanadium salt participates as an
oxidizing agent which ADA later restores  to the oxidized form.
                                91

-------
C.3         Basic Chemistry

            3.1  Iron Oxide Box Process

            The following equations illustrate the chemistry involved
in iron oxide purification:
            Absorption:   Fe2°3^H2°^x + 3 H2S = Fe2S3 + ^x+3^ H2° + heat
            Revivifying:  2 Fe2S3 + 3 QZ + x H20 = 2 Fe,/) (H20) + 6 S + heat
            Overall Reaction:  2 H^ + 02 - 2 H20 + 2 S + heat

            Depending on operating conditions, a large number of
other  reactions may occur.  The reaction mechanism is principally
influenced by temperature, moisture content, and pH of the purifying
material.

            Both, mixed and unmixed, iron oxides are used for gas-
purifying materials.  Both types contain iron oxide that may be
prepared by the air oxidation of iron borings in the presence of
water and lime.  The make-up of each class follows:
            Unmixed oxide - pure hydrated ferric oxide and sometimes
                            fibrous materials such as those occurring
                            in natural iron oxides ores.
            Mixed oxide -   artifically prepared by supporting finely
                            divided iron oxide on materials of large
                            surface and loose texture such as wood
                            shavings and granulated or crushed slags.

Mixed oxides have the following advantages:
            Control of bulk density, iron oxide content, moisture
            and pH.

-------
            Reduced tendency to cake.
            Free passage of gas.
            Higher final sulfur loading

            Capacity and activity are  two important aspects  in the
selection of purifying materials.  In  theory, 0.61* Ib of hydrogen
sulfide will react with 1 Ib of anhydrous ferric oxide, but  only
up to about 0.56 Ib sulfur/lb ferric oxide has been achieved in
operations.  Capacity decreases progressively with every cycle
after the first.

3-2         Liquid-phase Iron Oxide Processes

            The chemistry involved in the liquid-phase processes  is
based on the reaction of H S with either sodium carbonate or ammonia
and the subsequent  reaction of the hydrosulfide formed with iron oxide.
Regeneration follows by.aerating the  iron sulfide and  converting  it to
iron oxide  and elemental sulfur.  The  reaction mechanism for the
process using  iron  oxide suspended in an alkaline aqueous solution
is shown by the following equations:
            H2S +  Na2C03 =  NaHS  + NaHCO
            Fe20-3  .  3 H20 +  3  NaHS +  3 NaHCO  = Fe2$   '  3 H,0  +
               3KJ A ^ O -i-  O LJ  ft
               I"i a w \j  i  j n  u
            2  Fe2S3 '  3 H20  +  3  02 =  2 Fe20   '  3 H20 + 6 S

            Several, mostly  undesirable, side reactions  occur  depending
on the  operating  conditions  and  the composition of  the gas  to  be  treated.
Some  thiosulfate  formation  is  inevitable and it has  been  reported that
sometimes it may even be desirable  to  completely convert  to  thiosulfate
as follows:
                               93

-------
             2 NaHS + 02 = Na2S2°3 * H2°
             Na2S + 1-* 02 + S  - Na2S203
             Another  undesirable  side  reaction  occurs when  hydrogen
 cyanide  absorbed  in  the  alkaline material  is converted  to  thiocyanate.
 The mechanism  first  involves  formation of  sodium cyanide which  is
 then oxidized  by elemental sulfur as  follows:
             HCN + Na2CO  = NaCM  + MaHCO
             NaCN + S » NaSCN
 Not all of the HCN is converted  because a  majority  Is stripped  from
 solution by  regeneration air.

             Significant concentrations of  hydrogen  cyanide  in the gas
 can possibly lead to a mechanism in which  the  iron oxide reaction
with hydrogen  sulfide is Inhibited.  Noticeable color changes have been
observed in  the solution when treating a gas in which hydrogen  cyanide
approaches 10% of the hydrogen sulfide concentatfon.  Oxidized  solution
has a blue coloration due to the  presence of ferric-ferrocyanide com-
plexes which become pale yellow  in the fouled condition.  While reaction
between iron oxide and hydrogen sulfide  is quite slow, the blue
complexes support rapid conversion of hydrogen sulfide to sulfur.  It
 Is hypothesized that the reactions involve oxidation of H_S by  con-
version of the ferric-ferrocyanide complex to ferrous ferrocyanfde.
Ferric-ferrocyanide Is reestablished in the regeneration step.  The
reactions can be represented by the following equations:
            2 H2S + Fe(t(Fe(CN)6)   + 2 Na2CO  -
                  2 Fe.Fe(CN), + Na, Fe(CN), + 2 H,0 + 2 CO, + 2 S
                      Z      0     *t      o      Z        i
            2 Fe2Fe(CN)6 -f Na^FefCN)^ 02 + 2 H2C03 -
                  Fe^(Fe(CN)6)  + 2 Na^Oj + 2 HjO

-------
Iron, lost with the sulfur as iron cyanide compounds, is replenished
with a dissolved solution of iron sulfate.

3.3       Stretford Process

          Hydrogen sulfide is absorbed into a solution consisting
mainly of sodium metavanadate, sodium anthraquinone disulfonate  (ADA),
sodium carbonate and sodium bicarbonate in water.  Sodium carbonate
reacts with the H_S to produce sodium hydrosulfide as follows:
          H2S + Na2CO. 	*• NaHS + NaHCO-3
Free sulfur is formed by oxidation with sodium metavanadate.  Vanadium
in  this  reaction  is reduced as shown:
          HS" + 2 V5+	+• 2V   + S  + H+
The  full  reaction equation  is:
          2 NaHS + *» NaVO- + H20 	+• Na2V^°9 +  2  S +  **  NaOH
Vanadium is reoxidized by  reacting with ADA  in the oxidizer as  follows:
          2 \l^+ ADA (oxidized) 	*•  2V5+ +  ADA  (reduced)
or:
          Na^Og + 2 NaOH + H20 + 2 ADA	*k  NaVO  + 2 ADA  (reduced)
Unused caustic  (k moles  formed in  the vanadium reduction equation  and
only 2 moles are  consumed  in the previous equation)  reacts  with sodium
b icarbonate:
          2(NaOH  + NaHCO. 	»•  Na2C03 + H20)
The reduced form  of ADA  is  oxidized  by air blowing:
          2 ADA  (reduced)  +  02	*•  2 ADA + 2  H20
Overall, the above combination of  reactions  reduces  to:
          2 H2S + 02 	*• 2  S + 2 H20
Side reactions  include oxidation  of  sodium hydrosulfide to thiosulfate,
conversion  of  hydrogen cyanide  to  sodium  thiocyanate, and  formation of
sodium  sulfite and sulfate from  SO..

-------
2 NaHS + 2



2 HCN + 2 NaHS + QZ	*• 2  NaCNS + 2




S02 + 2 Na2C03 + H20	^ Na2$03 + 2




2 Na2S03 -i- 02	^2  Na^O^

-------
C.A       Design Basis and Assumptions

          As a comparison of requirements to remove hydrogen sulfide
from product gas of a typical  gasifier, the following calculation
basis and assumptions have been made:
                    q
          1.  Ax 10  Btu/day  capacity of coal gasification plant.
          2.  Heating value of gasification product gas is 175 Btu/SCF.
          3-  Assume particulate and tars in the product gas have
              been removed before the gas enters into a hydrogen
              sulfide removal  system.
          A.  Use 3.0 W % sulfur coal .
          5-  Assume all sulfur in coal appears mole for mole in
              the product gas  (conservative assumption).
          6.  Assume thermal efficiency of a gasification process
              is 80%.
          7.  Assume heating value of coal  is 12,500 Btu/lb.

Calculation of sulfur content of product gas:
          12,500 Btu/lb of coal x 80% =  10,000 Btu  in product gas/lb coal
          k,000,000,000/10,000 = AOO.OOO Ibs of coal/day
                               = 200.0 tons of coal/day
          10,000/175 =  57-1*» SCF product gas/lb of  coal
          0.03  lb sulfur  in coal/32 Ib/mole = 0.0009375 moles sulfur
                                              compounds  in gas  (assuming
                                               100%  recovery of  sulfur in
                                              coal)
                                            = 0.3562 SCF  of sulfur  com-
                                               pounds  in  gas per lb  of
                                               feed  coal
                                            =  0.619 V  %  concentration of
                                               sulfur  compounds  in  product
                                               gas
                                            = 6190  ppm by volume
                                97

-------
k,000,000,000/175 - 22,857,000 SCFD of product  gas
                  - 952,380 SCFH
0.03 1b sulfur x 7000 grains/lb « 210 grains  sulfur  compound
                                  in gas  per  57 SCF  product gas
                                » 368 grains/100 SCF of unpuri-
                                  fied product  gas
                     98

-------
C.5       Iron Oxide Box Purifiers


          5.1  Design Based on American Practice

          Bed Size Estimation -

          Empirical rules, for the most part,  provide the process

design method for iron oxide bed purifiers.  The Steere Engineering

Co. has proposed the most commonly used method in the United States,

The formula  is expressed by the following equation:
                               GS
                          3,000 ( D + C )

where:
          A = cross-sectional area of gas flow through any one box,
              in series, of a set.

          G = maximum gas rate, SCF/hr.
          S = correction factor determined by the hydrogen sulfide
              content of the inlet gas.
          D = total depth of oxide in feet through which the gas will
              pass in the purifier set.   In split flow designs where
              half the gas volume passes  through each layer, the gas
              flow area  is twice the cross-sectional area of the box,
              while D is the depth of one layer of oxide.
          C = factor determined by the number of boxes as follows:
              A for 2 boxes; 8 for 3 boxes; and 10 for k boxes.

The values of the S correction factor are:

                    Grains H2S/100 SCF
                    of Unpurified Gas     Factor
                        1000  or more         720
                         900                 700
                         800                 675
                         700                 6*»0
                         600                 600
                         500                 560
                         kOO                 525
                         300                 500
                         200  or  less
                                99

-------
The  influence of H2S  loading may be observed from the graphical pre-
sentation of this data  in  Figure C-5.1.
          Estimated Box  Purifier Design  -
          Detailed calculations are given  in the Appendix.
               No. of iron oxide boxes    10
               Unit Size:  Square        37 ft x 37 ft x  10 ft high
                           Circular      k\ ft I.D. x 10  ft high
               Gas Volume  (Inlet)        22.86 million cu ft/day
                                          (4 x 109 Btu/day)
               1*2$ Content (inlet)       368 grains/100 SCF gas
                           (Outlet)        29 grains/100 SCF gas

          5.2  Design Based on European  Practice
          Bed Size Estimation -
          The space velocity through one box, known at the R ratio,
governs European oxide-purifier design.  Selected values of R may
be applied in the space velocity equation  given below to design
box size.
                 _     cubic feet of gas per hour
               R
                    cubic feet of oxide  in one box
R values can be varied from  15 for a conservative design to as high
as 100 for some installations.  Good design practice for systems
operating at essentially atmospheric pressure and with revivification
in situ use an R ratio of 20 to 50.

          Minimum standards of the oxide-purifier design require an
oxide bed to be at least 10 feet deep to produce sufficient pressure
drop for proper gas distribution over the entire cross-sectional
area.  Also, vessel diameter should limit deposition to a maximum
of 15 grains/square foot of cross-sectional area of bed per minute.
                               100

-------
                                        K-C  '0 * '0 TO THE CENTIMETER  16 x Jb CM
                                        *C  KEUFFEL & ESSER CO. M»OE IN U 5 »
46 1513
L...L- -

-------
          Estimated Box Purifier Design -
          Detailed calculations are given in the Appendix.
               No. of iron oxide purifiers     k
               Unit Size:  Square              35 ft x 35 ft x 10 ft high
                           Circular            39 ft I.D. x 10 ft high
               R Factor                        20
               Gas Volume (inlet)              22.86 million cu ft/day
                                               (*» x 109 Btu/day)
               H2S Content (inlet)             368 grains/100 SCF gas
                           (Outlet)             29 grains/100 SCF gas

          5-3  Discussion:  Dry Iron Oxide Process
          The iron oxide box purification process provides reliable
and effective hydrogen sulfide removal.  Its space requirement, however,
may be excessive and the operation produces a considerable quantity of
spent iron oxide (when revivification is not effective) which must be
disposed.  The limiting factor in the iron oxide process is that it
requires a large ground space.  This may rule out many large existing
plants.

          Hydrogen sulfide removal in iron oxide box purification is
a surface reaction.  Dust, light oils, naphthalene, and tars should
be removed before purification since these materials coat the iron
oxide and render it unreactive.  For optimum operation of the process,
the gas should not contain more than 0.4 grain per 100 cubic feet of
tars, oils and dust.  This low tar loading requirement may limit the
application of the iron oxide purification process to some gasification
processes since they produce significant amounts (about 10 W %)  of
tars and light oils per pound of feed coal.
                                102

-------
5.**  Advantages and Disadvantages of the Dry Iron Box
     Process
Advantages -
1.  Completely removes small  to medium concentrations of
    hydrogen sulfide without  removing carbon dioxide.
2.  Equally effective at any  operating pressure.
3-  Removes mercaptans or converts them to disulfides.
k.  Produces a final product  in elemental sulfur form.
5.  Well proven commerical process.
Disadvantages -
1.  A batch process, requiring duplicate installations or
    flow interruption of process gas.
2.  Requires large ground space for large gas plants.
3.  Hydrogen cyanide reacts irreversibly with iron oxide
    causing a  loss of purifying material.
k.  The  iron oxide sponge bed may  become coated with  en-
    trained oil,  tar or distillates and  require more
    frequent changing.  Thus,  it may  be  necessary  to
    wash the gas with oil (e.g., benzene scrubber) before
    iron oxide box purification.
5-  High  labor cost.
6.  Disposal of a  large quantity of  iron oxide  sponge
    from spent beds  is necessary.
                      103

-------
C.6       Liquid-phase  Iron Oxide Processes

          6.1  Process  Description
          The schematic flow diagram of a liquid-phase iron oxide
process is shown in Figure C-6.1.  The system consists of a packed
column (absorber) and a regenerator.  Scrubbing solution, normally
containing 3.0 W % Na.CO. and 0.5 W % ferric hydroxide, is pumped
to the top of the absorber where it is counter-currently contacted
with the raw product gas fed into the bottom of the vessel.  The
liquid is circulated at such a rate that a two to threefold excess
of ferric hydroxide over the stoichiometric quantity necessary for
the complete reaction with hydrogen sulfide is present.

          The hydrogen sulfide-contain ing solution flows from the
bottom of the absorber to the regenerator.  Elemental sulfur, formed
in the regenerator by contact of the solution with air, accumulates
as a froth on the liquid surface, flows to the slurry tank, and is
pumped from there to a filter where excess liquid is removed.  A
part or all of this liquid may be discarded, thereby purging undesir-
able salts from the system.  Oxidized solution is pumped from the
regenerator back to the absorber to complete the cycle.  Foul gas
from the oxidizer is vented to either a boiler or a washer.

          6.2  Process Requirements
          The estimated sizes of the equipment for treating k x 10^ Btu
per day of low-Btu gas (175 Btu/SCF) are:
          Packed Tower -
               Packed Column:      9 ft 3 in I.D. x 50 ft overall  height
               Packing Height:     26 ft
               Packing Material:   2" Intalox saddles with Fp - 
-------
                                                    FIGURE C-6.1

                              FLOW DIAGRAM OF LIQUID IRON OXIDE PROCESS FOR H9S REMOVAL
              Absorber
                                                                                               Vent
                          Purified Product Gas
    Mist
 Eliminator
   Liquid
Distributor
   Liquid
Distributor
  packing

   Raw   _
 Product"1*
  Gas
  From
Gasifier
                                                          Regenerator

f////W/S



A/NAA
\
/
X
/
X
u u u u
\
x
\

/
/



— —
\
/


\
\



-~-y






















H20
Na








-£
^
iCQi
ZUU3
1


Fe(
r


Makeup
Chemical s
Storage
Tank

•^
i

i
— (•









i





CD
T3
0)
I/I
V)

O
C
o
'

")
•**.
^ /




























\J W













/
y
	 (
_ ^
                                                                         Air
                                                                                  Filtrate
                                                                                  Storage
                                                                                   Tank
                                                                                                 Recr  red
                                                                                                  Su   r
                                                                               -{X—

-------
          Regenerator -
               Total Volume Required:  777 ft3, i.e., 7-0 ft x 20 ft
                                       high (for example)
          Pressure Drop Through Packed Tower -
               0.5 in H20 per ft of packed bed
          Flow Rates -
               Product Gas:  952,380 SCFH or 22.86 x 106 SCFD
               Solution Circulation Rate:  165 Ib/sec or 1161 gpm
               Air Requirement:  815 SCFM (2x stoichiometric amount)
Detailed calculations are shown in the Appendix.

          6.3  Advantages and Disadvantages of the Liquid-phase Iron
               Oxide Process
          Advantages -
          1.  Continuous gas clean-up process, using inexpensive
              chemicals.
          2.  Small ground space requirement.
          3-  Flexible to accommodate the variations of hydrogen
              sulfide content of the raw gas.  Easy to control
              the process operation.
          k.  Selective removal of H2$ from C02-
          5.  Operates over wide pressure ranges.
          6.  Low labor cost; little supervision required.
          7.  Elemental sulfur is produced as a final product.
          8.  Well proven commercial process.
          Disadvantages -
          1.  Scrubbing chemicals react with HCN irreversibly to pro-
              duce thiocyanates and to form thiosulfates by side
              reactions, causing a loss of active purifying material.
          2.  Requires pumping a large amount of recycle liquid to
              the absorber and air to the regenerator.
          3.  H£S is not always completely removed; however, the I^S
              removal efficiency of the process is adequate to meet
              projected EPA air pollution control  guidelines for
              industrial gas users.
                                106

-------
k.  Like any other liquid-phase h^S removal  process,
    the corrosion problems must be surmounted.
5.  Bleed-off liquid streams must be treated before
    discharge.   The streams contain sodium thiocyanate,
    thiosulfates, sodium carbonates and ferric  hydroxide.
6.  Does not remove most organic sulfur compounds.
7.  Operates at low temperatures, ambient to 100°F.
                      107

-------
C.7       The Stretford Process

          7-1  Process Description
          As shown in Figure C-7-1, feed gas to be purified is scrubbed
in an absorber by a counter-current flow of an alkaline solution at
about 80°F to 100°F.  The solution, containing a vanadium salt along
with an  anthraquinone derivative, oxidizes H2$ into elemental sulfur
while the vanadium is reduced.  To insure complete precipitation of
sulfur, a delay tank beneath the absorber retains the Stretford solu-
tion for 10 to 20 minutes.  The solution reaches an equilibrium with
respect to the carbon dioxide in the gas and only relatively small
amounts of CO- are removed by the process.

          Liquor from the absorber is fed to oxidizers to restore
vanadium to the oxidized form through a mechanism involving oxygen
transfer via the anthraquinone derivative.  Air blown through the
oxidizer also separates sulfur by froth flotation.  The scum pro-
duced is either filtered or centrifuged, washed, and melted into
high-quality sulfur.

          7-2  Process Requirements
               H2S removed from raw product gas to meet the study
               basis guideline (952,380 SCF/hr gas, 3-68 gr H2S/SCF,
               S2% removal):
                             0.128 Ib H2S/sec
               Stoichiometric Na.CO. requirement to convert H.S
                   CO- + H2S - NaHS + NaHCO.):
                             3.U8 Ib Na2CO-/lb H2$
                                      or
                             0.399 Ib Na2C03/sec
                               108

-------
            Absorber
                       .*~ Purified Gas
Liquid
Distributor
    packing
 Raw
 Product
 Gas
                                                                                      Vent
           Reaction
             Tank
                         Oxidfzer
                       (Regenerator)   Sulfur   Foul
                                       Troth    Air
                                Regenerated
                                Solution
Makeup
Chemical
                      tl
      Makeup
      .Water
                                  Pump
                                  Surge
                                  Tank
I
                                                        v  v v/
                                          p
I iItrate
ank
                                        Air
                                         Discharge
                                                                                    Sulfur
                                                                                    Cake
                                              FIGURE C-7.1
                                    FLOW DIAGRAM OF STRETFORD PROCESS

-------
          Practical  Na_CO_ requirement (usually two to three times

          theoretical;  using 3):
                         1.197 lb Na2CO-/sec

          Amount of  scrubbing solution required (sodium carbonate:

          0.1  N; sodium bicarbonate:   0.3 N, or equivalent  Na~CO_
          solution of 0.505% by weight):

                         237.1 lb solution/sec

                                 or

                         1625 gpm @ 65.5  lb/ft3
          Process Unit Summary -

               Raw Gas Rate:   22.86 x 10^ cu ft/day

               H2S in, grains/100 SCF:   368

               H-S out, grains/100 SCF:   29 (to meet  EPA guidelines
                                         of 0.5 Ibs S02 per  10^  Btu)
               Absorber
                 Overall  Height
                 Diameter
                 Packing  Type
                 Packing  Height
                 Reaction (Holding)  Tank
               Circulation Pump


               Oxidizer


               Air Blower

               Filter
85 ft (about)
10 ft I.D.
2" saddles with Ff
2 sections each H
   ko
.5 ft
Bottom section of absorber
    27 ft high

2 Units (one stand-by),
    1625 gpm

14 ft 6 in I.D. x 20 ft high
    (25 ft overall  height)

60,000 ct ft/hr

Vacuum Rotary
Detailed calculation estimates are given in the Appendix.
                               110

-------
7-3  Advantages and Disadvantages of the Stretford Process
Advantages -
1.  Well proven commercial process.
2.  H^S removal to below  1 ppm possible.
3.  Can recover H.-S as pure saleable sulfur.
^4.  Insensitive to h^S/CO,, ratio.
5.  Operates over wide pressure ranges  (0 psig -  1000 psig)
6.  Accepts process fluctuations.
7.  Primarily mild steel  construction.
8.  Little supervision and maintenance  required.
Disadvantages -
1.  Does not remove most  organic compounds.
2.  Requires preprocessing for feeds which  contain  large
    quantititles of SO™,  HCN  or  heavy hydrocarbons.
3.  Produces a  large  purge stream  containing  a  vanadium
    compound, ADA, thiocyanates  and  thiosulfates.
!*.  Operates at low temperatures  (ambient  to  120  F) .
5.  Probably  less  economic for  treating streams with  an
    acid gas concentration greater than 15% H«S than  some
    other processes.
                     Ill

-------
SECTION D - OPERATIONAL EVALUATION OF CONVERTER OUTPUT

            CONTROL SYSTEMS
            1.  Typical Clean-up Systems Applied to Industrial
                Fuel

            2.  Dependency of Clean-up on End Use of the Fuel
                Gas
            3.  Sulfur Emission Control with an Industrial
                Fuel

            k.  Effect of Nitrogen Compounds on Chemical
                Clean-up Systems

            5.  Tar and Oil  By-products

            6.  Reduction of Particulates for Industrial
                Fuels
                    112

-------
D.1        Typical  Clean-up Systems Applied to Industrial  Fuel

          The clean-up systems covered in Section B illustrate
representative applications for each of the particular gasifier
systems examined.   Some utilize simple clean-up techniques and
others are complex, but basically they all have a means to quench
or cool the gas and knock out the particulate matter.  Further
steps required depend on the type of coal being gasified, the
process conditions, and the end use of the gas.

          The same considerations are, for the most part, necessary
for  industrial gas as for synthesis gas.  Particulates and tars will
have  to be removed.  Gas cooling, along with waste heat  recovery
for energy efficiency, would be appropriate.  Sulfur and  nitrogen
removal may be necessary, although  the reduction  in sulfur and
nitrogen  levels need not be complete  to  reach the proposed EPA
guidelines on  industrial gas.  These  levels  as suggested  by the
EPA  are:
               Sulfur - 0.5  Ibs of  SO,, per 10  Btu.
               Nitrogen - 0.1*  Ibs of  NO   per  106  Btu  (as  NOJ.
                                       x     6
               Particulates  -  0.1  Ibs per  10  Btu.
The  sulfur limit may be reached through  the  use of the processes
already discussed.  Nitrogen  in the form of  gaseous  compounds  is,
more or less,  controlled  by  sulfur  removal processes as  discussed
later.  Organically bound  nitrogen, in  the tars and oils  knocked
out  in  the particulate and  tar removal  portion of the  gasification
systems must  be given  consideration to  prevent pollution and  this
aspect  is also considered  later.
                                 113

-------
          Carbon dioxide removal, which is required in the manufacture
of pipeline gas, is not necessary for industrial fuel  gas.  The lower
heating value of the fuel as a result of leaving carbon dioxide in
the industrial gas is not likely to adversely affect most applications.
In fact, a beneficial effect due to the lower flame temperature would
result from a decrease in the thermal fixation of nitrogen.  Of course,
if a high concentration of nitrogen compounds such as  hydrogen cyanide
or ammonia were contained in the gas, they might have to be controlled
to prevent the formation of NO .
                              X

          Considering the point that the subject of this outline is
control technology for industrial fuel, the ability of the illustrated
systems to clean-up gas for the high standards necessary to make pipe-
line or synthesis gas suggests the possibility that the more tolerant
requirements for industrial  gas can be more easily met.  The simpler
systems appear to be directly applicable for industrial gas clean-up
but, where inadequate, the complex systems would be able to provide
the necessary performance with a relaxation of design  specifications
for the clean-up system.   Examples of this decreased demand on acid
gas clean-up requirements for industrial gas manufacture may be con-
veniently illustrated by  calculating the effect of changed operating
conditions on H2$ removal with a cold methanol  wash.  The following
three cases are estimates of an H2$-bearing gas flowing in contact
and at equilibrium with a cold methanol wash.
Case
1
3
2
Pressure
psia
500
500
14.7
Temperature
°F
-80
-60
-25
Approximate
Methanol Circulation
moles/mole H2S
3200
3200
130
Gas H2S
Level
ppm
0.1
0.25
520

-------
The first case shows  the methanol  circulation  ratio  that  is  necessary
per mole of absorbed  H.S in order  to establish  equilibrium with a
gas containing 0.1  ppm of hLS.   To clean-up a  gas  for  methanation,
acid gas removal  down to 0.1 ppm level  would be appropriate.   The
effect of a refrigeration loss,  as might occur  due to  a  process upset
from the loss of  a  compressor, would be to raise the gas  hLS  content
above the desired level.  Case 2 illustrates the equilibrium H-S
level attained in the gas for an arbitrary was  temperature  rise to
-60°F.  While this  might be an undesirable level  for a methanation
feed gas, it would  still be more than adequate for an  industrial
fuel gas.  Case 3 is, then, an example of how  acid gas removal design
criteria could be relaxed to deliver a product satisfactory  for  indust-
rial fuel gas as  compared to methanation feed  gas.  A  175 Btu per
SCF higher heating  value industrial fuel gas with a sulfur  level of
0.5 Ibs of S02 per  million Btu would have about 520 ppm of  HLS.  A
methanol wash at  atmospheric pressure and -25°F would  be in equilibrium
with this gas using a circulation  of 130 moles per mole of absorbed
H2S.

          Adapting  high performance systems, capable of removing
pollutants to low levels, for industrial gas clean-up may be accomp-
lished  in two ways.  Naturally,  one could clean up a fraction of
the gas stream while bypassing the remainder in an amount such that
the recombined stream would meet guidelines for an  industrial fuel
gas.  Although such a procedure would require a somewhat smaller
capacity clean-up unit  (compared to treating the whole stream for
synthesis),  there  is a good possiblity  that a process  design for
treating the entire flow to meet requirements for an  industrial  gas
might be advantageous.  Such a consideration should be given a thorough
evaluation by  the designer  contemplating  a  unit for industrial fuel
manufacture.   Not only  is  there a whole new set of design parameters for
clean-up processes, but many older processes might once again be con-
s idered.
                                 15

-------
D.2       Dependency of Clean-up Systems on the End Use of the Fuel Gas

          In the final analysis, the clean-up methods used to condition
the raw-gas from a gasifier are more a function of the end use for the
fuel gas than  it is of a particular gasification system.  For example,
the firing of  a hot, dusty, sulfur-laden fuel gas into a cement kiln
should be quite satisfactory because the cement-making process itself
requires a dust control system and the limestone in the kiln feed will
remove substantially all of the sulfur in the fuel.  In a sense, the
process provides the gas cleaning step on the raw fuel-gas and a gas
of high purity is not required.

          An example of an end use that is intolerant of dust is the
combustion of  coal-derived gas in a gas-turbine.  For this application,
the fuel must be extremely clean, in the order of one ppm by weight
of solids.  However, complete removal of sulfur is not required and
the degree of sulfur removal would be dependent on local regulations
governing S0» emissions.

          An example of a gas requiring an intermediate degree of
cleanliness with respect to dust is the mixture of coke-oven gas and
blast-furnace gas that is normally used in steel mills to fire soaking
pits, reheating furnaces, coke-ovens, etc.  This gas is normally cleaned
to a solids level of 15-30 ppm (by weight).  Experience has shown that
this level of cleanliness is satisfactory for distribution of gas
throughout the steel mill.

          Any gas containing hydrogen and carbon oxides that is to
be methanated  (perhaps for Btu adjustments) using a nickel catalyst
must be essentially sulfur-free or contain no more than 0.1 ppm
(volume) of sulfur-bearing compounds.  As mentioned earlier, some
                                116

-------
industrial  gas is burned without sulfur removal;  hence,  sulfur removal
requirements can vary from no removal  to complete removal  in the
event that  catalytic processing is involved.   Such a wide  variance
demonstrates quite clearly that the end use of a  fuel-gas  determines
the degree  of clean-up that is required provided, of course, that
the final emissions meet the required EPA guidelines.  This example,
plus the three cases cited previously on differences in dust levels
in fuel gases, confirms the importance of end use of the gas vis-a-vis
the clean-up system(s) used on a given gasifier effluent.

          The systems studied in Section B show this end use dependency
For the Wilputte unit, a very simple system is described because low-
sulfur coal is used and the product gas is then immediately applied
as a fuel.   The end use in the WD/GI example, while also intended
for direct  use as a fuel, would tolerate medium-sulfur coals because
the Stretford process was employed to remove sulfur.  The Koppers-
Totzek and Lurgi cases make use of the Rectisol process because fur-
ther processing  into ammonia and pipeline gas required a high degree
of clean-up.
                                117

-------
D.3       Sulfur Emission Control with an Industrial Fuel

          The easiest way to limit the amount of sulfur dioxide
formed when combusting a coal -derived fuel gas is, perhaps, to
gasify a coal sufficiently low in sulfur that the product  gas,
when burned, will conform to the guideline limit of 0.5 Ibs of
sulfur per 10  Btu.  Unfortunately, this method would require a
feed coal containing approximately 0.25% sulfur and such coals are
too rare to be of real significance.  Nevertheless, the gasification
of a low-sulfur fuel such as wood or wood refuse does produce a fuel
gas low in sulfur, and such plants have been built and operated
successfully for commercial ventures in Africa and elsewhere.

          The use of low sulfur fuels such as wood is recognized
by the EPA.  Recently an amendment to the New Source Performance
Standards was made which will affect large steam generators by
allowing wood residue as a fuel supplement.  The heat content of
the wood residue (defined as bark, sawdust, slabs, chips,  shavings,
mill trim and other wood products) would be used for determining
compliance with the standards so long as there is no increase in
sulfur or nitrogen oxide emissions as a result.  The impact of
the amendment on particulate emissions has not yet been defined,
and information on this subject is currently being gathered.  The
amendment appeared in the Federal Register on November 22, 1976
    FR 51397).
           In Section C, some old clean-up systems used primarily for
the removal of sulfur are examined and compared to a modern process.
While these old systems may not compete when synthesis gas standards
are required, a design is presented for comparison purposes in the
manufacture of industrial gas.  Depending on the particular situation
                                 118

-------
under consideration, it appears from equipment requirements that
the old processes might be economically attractive for some indus-
trial gas applications.

          The most practical  way to remove sulfur (mostly H«S)  from
coal-derived fuel gas is, of  course, to use a one-step process  that
directly converts the hLS to  elemental sulfur.  Section C gives
examples of some one-step processes.  Two-step processes that
selectively remove a stream rich in H?S for subsequent processing
to form sulfur in a Claus-type unit are also commonly used.  These
two-step operations are more complex, and the tail gas from a Claus
unit  introduces an additional pollution stream to be cleaned-up.
An  idea of the difference in the complexity of the one-step versus
the  two-step systems can be noted  in schematic flowsheets  shown  in
Figure D-3-1.  Nevertheless,  the economics of two-step processing
might be suitable for a  large  installation.

          The removal of sulfur from coke-oven gas  (which  can be
considered a special type of industrial fuel) has historically
favored the one-step systems.  The  older  liquid-phase  sulfur removal
systems, such as Thylox, Ferrox and Manchester,  and  the  solid-phase
 iron  oxide boxes are one-step  processes that  were so used.  More
 recently developed  one-step  processes  that are  in use  removing  sulfur
 from coke-oven gases are:
                     Stretford
                     Holmes-Stretford
                     G i amma rco-Ve t rocoke
                     Takahax.

           The Stretford  process  is  also being applied  with modern
 processes.   In  Japan,  H,>S  is being removed  from  large volumes  of
 low-Btu  gas  produced in  the  operation of  a  Flexicoker.
                               119

-------
                           FIGURE D-3.1

        FUEL GAS DESULFURIZATION SYSTEM SCHEMATIC DIAGRAMS
A.  ONE-STEP SYSTEM
         Purified Gas
Impure
              Vent
 Gas
          Rich Solution
B.  TWO-STEP SYSTEM

         Purified Gas
Impure
                                                 Sour Gas
 Gas
                                                            Claus Unit
                     Reducing Gas
          Reactor
\
I
          Heater
                                                  Off-Gas
                                To Incinerator
           Cool ing
            Tower.
                                                 Lean
               Am me
              Absorber
                                                                    I
                                                                  Sulfur
                                     Stripper
                                         Rich  Amine
         Condensate to
      Sour Water  Stripper
                               120

-------
D. k       Effect of  Nitrogen  Compounds  on  Chemical  Clean-up Systems

          The nitrogen content of coal, which  generally  runs  in  the
range of 0.6 to 2.0  percent,  can lead to problems when coal  is gasi-
fied.  Not only is there a risk of excessive environmental  contamin-
ation, but an impact on sulfur clean-up processes may  also  be found.
During gasification  nitrogen  compounds  such as ammonia,  cyanides,
oxides of nitrogen and pyridenes may, depending on  conditions,  be
included in the raw  product gas.  High  temperature, for  example,
favors HCN but no pyridene formation.

          Unfortunately, hydrogen cyanide reacts in most chemical
clean-up processes to form undesirable chemicals which precipitate
out of the treatment solution or are removed by purging a part of the
circulating stream.    In the Stretford process, almost all of the HCN
will be converted to sodium thiocyanate as shown in the following
equations:
          HCN + Na-CO	> NaCN + NaHCO
          NaCN +  NaHS + 1/2 0^	> NaCNS + NaOH
          NaHC03  +  NaOH—yNa^Oj +  H20
or  overal1:
          HCN +  NaHS  +  1/2 0^	>NaCNS +  H20
The effluent  stream  purged from  the  process,  containing  thiocyanate,
thiosulfate,  vanadium and anthraquinone disulfonic acid, has  in the
past been considered  an  innocuous  stream  for  disposal, but now, to
meet current  requirements, other methods  such as recovery or  biodegrad-
at ion  must  be evaluated.   In  the MEA treating  process, HCN can  react
and partially deactivate  the  solution.   Activity of the solution can
be  reclaimed  by treatment with sodium  carbonate or caustic soda.
Activated  hot potassium  carbonate almost  completely absorbs  HCN.
However,  the  hot potassium carbonate solution is not  degraded by  HCN
                               121

-------
since it is removed from the solution along with C0_ and KLS.

          When high levels of HCN are encountered, removal from the
process stream may be necessary by scrubbing with a polysulfide
solution.  Scrubber efficiencies of over 37% can be achieved,  and
the HCN content of the gas can be reduced to under 30 ppm by volume.
Disposal of the sodium thiocyanate, formed in the reaction between
HCN and polysulfide, is necessary.  As indicated for the purge solu-
tion in the previous paragraph, alternates to discarding this  chemi-
cal stream must now be considered.

          Ammonia dissolves in Stretford solution and can be stripped
from solution during regeneration.  When feed gas concentrations are
above approximately 300 ppm, special precautions are necessary to
prevent ammonia from being released to the atmosphere by the stripping
action of regeneration air.  The basic nature of ammonia makes it
amenable to removal from gasifier gas in those instances of excessive
ammonia concentrations.  Removing ammonia from coke-oven gas by water
or acid scrubbing has been the practice historically.  Pyridene bases
may also be scrubbed out of the gas with an acid absorbent.
                                122

-------
D.5          Tar and Oil  By-products

             The tar/oil  yields on coal  gasification systems  are
determined, to a large extent, by the intrinsic nature of the gas-
ification system.  Moving-bed counter-flow systems,  such as  the  Lurgi,
WD/Gl and Wilputte gasifiers, all produce an appreciable amount  of by-
product liquids.  On the other hand,  high temperature entrained  co-
current gasifiers, such as Koppers-Totzek, produce no tars.   The  yield
of these tars from the counter-flow systems, including the light-oils,
represents about 4-12 wt % of the coal  feed.  Because  the heating
value of the tar/oils is higher than the heating value of the coal,
the  percentage of the heating value of the feed coal appearing in
the  tar/oil  is even greater.

              If  the tar/oil  is to be burned as a fuel,  there may be
problems in meeting sulfur,  nitrogen and  particulate specifications.
Tars produced by gasification processes generally have  a  reduced
sulfur content compared to the feed coal  but have about  the  same
nitrogen contents as the coal.   A typical tar  from  a gasification
system having a  heating value of 16,500 Btu/lb requires  a maximum
sulfur content of 0.66 wt %  to meet a specification of  0.8 Ibs of
S07  per  10   Btu.  Such sulfur contents are  typical  of tars produced
from low to  medium  sulfur coals,  but tars produced  from high sulfur
coals may  have  trouble meeting an emission  level of  0.8 Ibs  of S00
      g                                                           t-
per  10   Btu  when burned.

              Information on  the  properties  of  tars  produced  by various
gasfication  systems  is  limited.   Therefore,  it is appropriate to  review
data from  systems or  equipment  that  simulate  the  conditions  in a  moving-
bed  counter-flow gasifier.   Such a simulation  is  found  in assay  tests.
                                123

-------
Assay tests for coal that distill (carbonize) coal give a clue to the

sulfur content of tars as related to the sulfur content of the coal.


             Assay tests on a number of different coals indicate that
the sulfur content of the tar is invariably less than for the coal.

These data are listed below.


               DISTILLATION/CARBONIZATION ASSAY
  Coal Source

Pennsylvania
Kentucky
V i rg i n i a
Maryland
Alabama
Pennsylvania
111inois
British Columbia
Pennsylvania
Alabama
West Virginia
West Virginia
West Virginia
Alabama
Utah
Pennsylvania
             Some data has been found on actual gasification systems
and the data tabulated below is derived from the Sythane gasification
of coal (fluid-bed pressurized gasification).
(Bureau of Mines - Monograph 5)
1 S in
Tar Product
0.65
0.5
0.5
0.75
0.7
0.7
0.5
a 0.55
0.6
0.6
0.5
0.55
0.85
0.4
0.6
0.6
% S in
Coal Feed
1.1
0.6
0.6
1.5
0.8
1.0
0.8
0.6
1.3
1 .1
0.6
0.9
1.8
0.7
1.0
1.3
S in Tar
as % of
S in Coal
59
83
83
50
87
70
62
92
46
55
83
61
47
57
60
46
                               124

-------
                       SYNTHANE  GASIFICATION
Coal Source
Pittsburgh Seam
111 inofs No. 6
Montana Sub-bit.
N. Dakota Lignite
% S in
Tar Product
0.8
2.7
0.5
1.0
% S in
Coal Feed
1.5
3.5
0.6
1.1
S in Tar
as % of
S in Coal
53
77
83
91
          As  can be seen from all  data,  the sulfur content  of the
tar is appreciably lower than for  the coal.  In view of this in-
formation, it is reasonable to conclude  that tars produced  by any
gasification  process generally would have a reduced sulfur  content
compared to the feed coal.

          Nitrogen poses a  somewhat more difficult problem.  The
Clean Air Act of 1971  specifies that new, large boilers have an
emission level for NO  of less than 0.3 Ibs. per 10  Btu when firing
                     X
liquid fuels.  This level  may be difficult tomeetwhen firing tars
produced from gasifiers.  Most American coals contain 0.6-2.03; nitrogen,
and the tars  produced from gasifiers will have about the same amount
of nitrogen.

          The nitrogen contents of tars produced from most  coal
processing systems appear to be similar, regardless of the  exact
processing mechanism.  This can be see from the comparison  noted
below.
                                125

-------
  Type of Processing     % N  In Coal
Pressurized Fluid-Bed

(Synthane)
  1.1
    % N in

By-Product Tar



     1.1
In Situ Underground

Gasification with Air

(Hanna, Wyoming)
0.6-0.7
  0.7*1-0.79
Carbonization of

111inois Coal @

1000°C (U.S. Bureau

of Mines
  \.k
     1.1
          When the tars are combusted, a portion of this fuel-bound


nitrogen is converted to NO  and, from experiments, the general
                           X

relationship  between NO  and the fuel nitrogen has been determined


as shown in the graph below.
               TJ
              x c
             o 3
             •Z. O
               CQ
              cn i

             — «
              ut 3
              m LL.
              
-------
          One source of data, based on the combustion  of  fuel  oil,
indicates that a fuel nitrogen content in the order of 0.35  wt %
would be required to meet an emission level  of 0.3  Ibs of MO   per
  6                                                         x
10  Btu.  This is about one-third of the nitrogen content of typical
tars produced from gasification systems.  If this data is assumed to
apply to the combustion of tar (a reasonable assumption), then tars
produced in any large scale gasification project may require a hydro-
genation pretreatment for the partial removal of nitrogen before the
tars are burned.  Such a pretreatment would also remove part of the
sulfur.

          An alternate disposal method would involve blending  the
tar into a low-nitrogen, low-sulfur fuel-oil so that the  mixture, when
burned, would produce pollutants at acceptable levels.

          The sale of by-product tar  to  recover valuable chemicals
obviates, of course, all of the problems associated with  the combustion
of tar.  Such an ideal route  for the disposal of tar may  not always be
avai1able.

          The combustion of by-product  tars has been practiced by
 industry for many years.  Special attention must be paid to the burner
design  because  the  tars will  frequently  contain erosive  ash particles
and other solids that can plug mechanical atomization  devices.  Stream-
atomized and  rotary-cup burners are  generally believed to be  the most
trouble-free  type of burner when combusting by-product tars.
                                127

-------
D.6
Reduction of Participates for Industrial Fuels
          The previous sections have shown a great variety of devices
employed in the removal of particulates from gasifier output.  In
most cases, a combination of such units is used depending on the gas
end use.  Examples of such equipment are cyclones, spray washers,
coolers and waste heat boilers  (which trap tars and/or particulates
in condensate), packed scrubbers, and sometimes (as  in the case of
iron oxide boxes) the sulfur purification process.   Usually, where very
low particulate levels must be  achieved for applications such as
synthesis gas, additional high  energy removal units  are also neces-
sary.  These applications might use disintegrators,  venturi scrub-
bers or electrostatic precipitators.
          Generally, data on the  levels of particulate reduction
accomplished through each system are not covered in the source
literature.  Koppers-Totzek  information was an exception and parti-
culate reduction through the various units is reported as follows:
   IJnit Operation
Gasifier

Wash-Cooler

Theisen-Irrigated
Disintegrators
Venturi Scrubber

Wet-type Electrostatic
Precipitator
                Particulate Level
                  (grains/SCF)
                        12
                       1.2
                     0.002
                0.002-0.003
                     0,0001
       Remarks
50-70% slag leaves bottom
of gasifier; remainder is
entrained.
90$ removal of entrained
particles.
As currently recommended
by Koppers Co,
Possible alternate to
disintegrators.

For production of high-Btu
gas.
                              128

-------
In the examples presented for the other units,  it may  be  inferred
that the participate removal  systems utilized are adequate for the
discussed applications.

          To put particulate removal necessary  to meet EPA guidelines
for an industrial fuel gas in perspective, the 0.1 Ibs per 10  Btu
may be converted to 0.12 grains/SCF for a 175 Btu fuel gas.  While
a definition of particulate removal operations necessary  to meet
the guideline  is not specifically covered in the literature, some
generalizations can be observed.  Gasifier, waste heat boiler or
wash-cooler outlet particulate levels are higher than the limit,
but high energy systems are excessive for the purpose of making
industrial fuel gas.  Possibly some combination of a cyclone, spray
washer and/or packed scrubber would, in some cases, provide the
necessary clean-up of particulates.  In other cases, a venturi scrub-
ber design with decreased performance requirements compared to syn-
thesis gas might be appropriate.  Depending on the Btu content of
the gas made and assuming that combustion of the fuel gas adds only
a negligible amount of particulates from soot formation, the clean-up
system that  is selected will have to remove particulates down to
approximately 0.1 grain per SCF.
                                129

-------
                            REFERENCES


GENERAL

1.  Bodle, W. W., and K. C. Vyas.  Clean Fuel from Coal.  Oil and Gas
    Journal, August 26, 1974.

2.  Boyd, N. F.  Coal Conversion Processes Loom Big as a Source of
    Hydrocarbon Fuels.  Mining Engineering, September 197**.

3.  C6EN Staff.  Coal Gasification Development is Languishing.  Chemical
    6 Engineering News, November 1, 1976.

4.  Fieldner, A. C., and J. D. Davis.  Gas, Coke and Byproduct-Making
    Properties of American Coals and Their Determination.  American
    Gas Association - 1934.

5.  Musick, James K., and Fred W. Williams.  Hopcalite Catalyst for
    Catalytic Oxidation of Gases and Aerosols.  Naval Research Laboratory,
    Washington, DC 20375-

6.  Perry, H.  The Gasification of Coal.  Scientific American, March 1974,
    Volume 230, No. 3-

7.  U. S. Steel.  The Making, Shaping and Treating of Steel.  Eighth Edition
    1964.


KOPPERS-TOTZEK PROCESS

1.  Farnsworth, J. F., D. M. Mitsak and J.  F. Kamody.  Clean Environment
    with K-T Process.  Presented at the EPA meeting on Environmental
    Aspects of Fuel Conversion Technology,  St. Louis, May 1974.

2.  Farnsworth, J. F.  Coal Gasification System Could Ease Energy Supply
    Punch.  33 Magazine, The Magazine of Metal Producing, August 1973.

3.  Farnsworth, J. F., et al.  Production of Gas from Coal by the
    Koppers-Totzek Process.  Presented at Clean Fuels from Coal Symposium
    at Institute of Gas Technology, Chicago, September 10-14, 1973.

4.  Gas Manufactured.  Kirk-Othmer Encyclopedia of Chemical Technology.
    Second Edition.  Volume 10.  pp. 353-442.

5.  Loeding, J. W., and J.  G. Patel.  Coal  Gasification Review.  Presented
    at ASME Joint Power Generation Conference, Portland, Oregon, September
    1975.
                                130

-------
 KOPPERS-TOTZEK  PROCESS  (Continued)

 6.   Magee,  E.M., C.E. Jahnig and H.  Shaw.  Evaluation of Pollution
     Control  in  Fossil Fuel Conversion Processes; Gasification; Section 1:
     Koppers-Totzek  Process.  PB-231-&75, EPA-SSO/Z-y^-OOSa, January 1971*.

 7.   Mitsak,  D.M., J.F.,  Farnsworth and  R.  Wintrell.  Economics of the
     K-T  Process.  Koppers  Company,  Inc., Pittsburgh, August 6,
 8.   Mitsak,  D.M., H.J.   Michaels and J.F.   Kamody.  Koppers-Totzek
     Economics  and  Inflation.   Presented at  the Third Annual  International
     Conference on Coal  Gasification and Liquefaction,  Pittsburg, August
     1976.

 9.   Mitsak,  D.M.  Phone  conversation with  authors,  March  17,  1977-

10.   Partridge, L.J.,  South  Africa  Firm Gets Operating  Exeprience with
     1100-ton/day  Coal-based Ammonia  Plant.   Oil  and Gas  Journal, November
     2k,  1975.

11.   Wintrell,  R.   The K-T Process; Koppers  Commercially  Proven  Coal  and
     Multi-fuel Gasifier for Synthetic  Gas Production  in  the  Chemical  and
     Fertilizer Industries.   Presented  at   AlChE  National  Meeting,  Salt
     Lake City, Utah,  August 1971*.

 LURGI PROCESS
 1.  Application of El  Paso Natural  Gas Co.  before the Federal  Power
     Commission, Dated November 7, 1972.

 2.  Gallagher, J.T.  The Lurgi Process State of the Art.  Presented at
     the Coal Gasification and Liquefaction  Symposium, Pittsburgh,  August
     197**.

 3.  Hatten, J.L.  Plant to Get Pipeline-Quality Gas from Coal.  Oil and
     Gas Journal, January 20,  1975.

 k.  Hendrickson, T.A.  (Compiler).  Synthetic Fuels Data Handbook.
     Cameron Engineers,  Inc.   1975-

 5-  Huebler,  J. Coal Gasification:  State of the Art.  Heating/Piping/
     Air  Conditioning,  T*9-155  (1973)  January.

 6.  Loeding,  J.W., and  J.G.   Patel.   Coal Gasification  Review.  Presented
     at ASME Joint  Power Generation Conference, Portland, Oregon,  September
     1975
                                    131

-------
 LURGI  PROCESS (Continued)

 7.   Lowry, H.H.  (Editor).   Chemistry of Coal  Utilization,  Supplementary
     Volume, Chapter 20,  John Wiley 6 Sons,  Inc.,  New  York,  1963.

 8.   Moe, J.M.  SNG from  Coal Via the Lurgi  Gasification  Process.   Fluor
     Engineers and Constructors,  Inc., Los Angeles.

 9.   Robson, F.L., et at.   Technology and Economic Feasibility  of Advanced
     Power Cycles and Methods of  Producing Nonpolluting  Fuels  for Utility
     Power Stations.  Prepared by United Aircraft  Corp.  for  National Air
     Pollution Control  Administration.  Final  report,  December  1970.

10.   Rudolph, P.F.H. Coal  Gasification - A Key process for  Coal  Conversion.
     Presented at Conference on Synthetic Hydrocarbons at the AI ME  1973
     Annual Meeting, Dallas.

II.   Rudolph, P.F.H. Gas  from Coal.  Chemical  Economy  6  Engineering
     Review, October 1973,  Volume 5, No. 10  (No.  66).

12.   Rudolph, P.F.H.  The  Lurgi Process The  Route  to SNG  from  Coal.
     Presented at the Fourth Synthetic Pipeline Gas  Symposium,  Chicago,
     October 1972.

13-   Rudolph, P.F.H.  The  Lurgi Process Route  Makes  SNG  from Coal.  90-92
     (1973) January 22.

14.   Shaw, H., and E.M. Magee.  Evaluation of  Pollution Control   in Fossil
     fuel Conversion Processes; Gasification;  Section  1:   Lurgi  Process.
     PB-237-634,  EPA-650/2-74-009-C, July 1974.

 RILEY  MORGAN PROCESS

 1.   Kohl, A. and Riesenfeld, F., Gas Purification,  2nd  Ed., 1974,  Gulf
     Publishing Co., Houston, Texas.

 2.   Private  communication with  Riley Stoker  Co.

 3-   Rawdon, A.H., Lisauskas, R.A.  and Johnson,  S.A.,  "NO  Formation  in
     Low and Intermediate Btu Coal  Gas Turbulent-Diffusioft  Flames",
     The Proceedings of the NO  Control  Technology Seminar,  San Francisco,
     Ca., EPRI, February,  1976?

 4.   Walsh, T.F., The Riley-Morgan  Gasifier.   Presented at Third Annual
     International Conference on  Coal Gasification and Liquefaction,
     Pittsburgh,  PA, August 1976.


 WELLMAN-GALUSHA PROCESS


 1.   Gas Generator Research and Development.   Survey and  Evaluation Phase
     One, Volume  2, R & D  Report  No. 20.  Prepared for Office of Coal  Research,
     Department of the Interior,  March 1965.
                                   132

-------
WELLMAN-GALUSHA PROCESS (Continued)

2.  Hamilton, G.M.  Gasification of Solid Fuels.   Cost  Eng.  8  (3),
    4-11, 1963-

3.  Hendrickson, T.A.  (Compiler).  Synthetic Fuels Data Handbook.
    Cameron Engineers, Inc.,  1975.

4.  Mudge, L.K., et al.  The  Gasification of Coal.   A  Battelle  Energy
    Program Report, July 1974.

5.  Robson, F.L., et al.  Technological  and Economic Feasibility  of
    Advance Power Cycles and  Methods of Producing Nonpolluting  Fuels
    for Utility Power Stations.  Prepared for U.S.  Department of
    Commerce, December 1970.

6.  Wright, C.C., K.M. Borchay  and R.F.  Mitchell.  Production of
    Hydrogen and Synthesis Gas.   Ind. Eng. Chem. 40 (4), 591-600  (1948).

7-  Lowry, H.H.  (Editor), Chemistry of Coal Utilization Supplementary  Volume,
    Chapter 20, John Wiley & Sons,  Inc., New York,  1963.

WILPUTTE PROCESS
 1.  Wilputte Low-Btu and High-Btu Fuel Gas Process.  Wilputte Co.,
    Murray Hill, NJ, Bulletin No. 7762, 7763, June 1, 1976.

 2.  Private communication with Wilputte Co.

 WINKLER  PROCESS

 1.  Banchik,  I.N.   Power Gas from Coal Via the Winkler Process.  Symposium
    on Coal Gasification and Liquefaction, Pittsburgh, August 1974.

 2.  Banchik,  I.N.,  T.K. Subramaniam and J.H. Marten.  Pressure Reaction
    Cuts  Gasification Costs.  Hydrocarbon Processing, March 1977.

 3.  Banchik,  I.N. The Winkler Process  for the Production of Low-Btu Gas
    from Coal.   Presented at Clean Fuels from Coal Symposium at  Institute
    of Gas Technology, Chicago,  September 10-14,  1973-

 4.  Gasification of Solid Fuels  in Germany by the  Lurgi , Winkler and Leuna
    Slagging-Type Gas-Producer Processes.  Bureau  of Mines  Information
    Circular  No. 7415.
 5-  Gas  Manufactured.  Kirk-Othmer Encyclopedia of Chemical Technology,
    Second Edition  10, pp.   353-442.
                                    133

-------
WINKLER PROCESS  (Continued)

6.  Henderson, T. A.  (Compiler).  Synthetic Fuels Data Handbook.  Cameron
    Engineers,  Inc.,  1975.

7-  Pressure Reactor  Cuts Gasification Costs.  Hydrocarbon Processing,
    March 1977.

8.  White, J. W., et  al (Editor).  Clean Fuels from Coal Symposium  II
    Papers.  Sponsored by IGT, Chicago,  Illinois, June 1975.


WOODALL-DUCKHAM/GAS INTEGRALE PROCESS

1.  Brochure of Woodal1-Duckham Gasification Process.  WD Engineering
    and Construction  Co.

2.  Grant, A. J.  Application of the Woodal1-Duckham Two-Stage Coal
    Gasification.  Presented at the Third Annual International Conference,
    Pittsburgh, PA, August 1976-

3.  Hendrickson, T. A. (Compiler).  Synthetic Fuels Data Handbook.  Cameron
    Engineers, Inc.,  1975-

4.  Private communication with Woodal1-Duckham Co.


IRON OXIDE PROCESSES

1.  Duckworth, G. L.,  and J.  H. Geddes.  Oil  and Gas Journal   September 13
    1965, P. 94.                                            '

2.  Gas Engineers Handbook.   McGraw-Hill, 1934.

3.  Kohl, A. L., and  F. C. Riesenfeld.   Gas Purification, Chapter 8,
    2nd Edition.  McGraw-Hill Book Co.,  Inc., New York, 1974.

4.  Perry, R. H., and C. H.  Chilton.  Perry's Chemical Engineers' Handbook,
    5th Edition.  McGraw-Hill Book Co.,  Inc., New York, 1973,  pp. 18-21 to
    18-23.

5.  Peters, M. S., and K.  D.  Timmerhaus.   Plant Design and Economics for
    Chemical Engineers, 2nd  Edition.  McGraw-Hill Book Co., Inc., 1968,
    p. 647.

6.  Zapffe, F.  Oil and Gas  Journal, September 10, 1962, p. 136.
                                134

-------
STRETFORD PROCESS

1.  British Gas Corp.   Hydrocarbon Processing,  April  1975.

2.  Moyes, A. J., and  S.  Vasan.  Holmes-Stretford h^S-Removal  Process
    Proved in Use.  Oil and Gas Journal,  September 2,  1974.

3.  Riesenfeld, F. C., and A.  L. Kohl.  Gas Purification,  2nd  Edition.
    Gulf Publishing Co.,  Houston, TX,  197^-

k.  The Stretford Process.  A Report for the EPA, Research  Triangle
    Park, NC prepared  by  Catalytic, Inc., Philadelphia,  PA,  December 1976.
                                 135

-------
                            APPENDIX A


 GENERALIZED  FORMULA  FOR SULFUR REMOVAL  FROM A FUEL TOMEETA SPECIFIC
 LEVEL OF  S02  EMISSIONS

      A formula has  been derived  to calculate the required percent removal

 of sulfur from a  fuel to meet specific  sulfur dioxide emissions levels in

 the  flue  gas.  This  equation is as follows:

      R = 100 -,
where

      E = percent efficiency of Btu recovery when processing fuel

          (i.e. gasification).  If fuel  is used directly, set E equal

          to 100.

      G = percent of sulfur in fuel ending up in processed product

          which is to be burned (i.e. fuel gas from a gasifier).  If

          fuel  is burned directly, set G equal  to 100.

      H » high heating value of fuel, Btu/lb.

      L * level of SO. contained in flue gas, Ibs S02 per 10  Btu.

      R « percent removal of sulfur to meet desired emission level,  L.

      S = percent sulfur in fuel  (i.e. coal to a gasifier).

An example in applying the formula to the gasification of coal  and

burning the product gas is as follows:
                                136

-------
 E = 75% gasifier efficiency.




 G = 80$ of the sulfur in coal  ending up in the gasifier product,




 H - 8500 Btu/lb coal  heating  value.




 L = 0.5 Ibs S02 per 10  Btu (desired emission level).




 S = 2% sulfur in the  coal





100 - 97>n I 75 Xfln5°V °'5l  « 90.0« sulfur removal  required.
      ZUU \     OU X /     I
                            137

-------
                             APPENDIX B

SAMPLE CALCULATIONS OF CLEAN-UP PROCESSES
      NOTE:  Basis, assumptions and basic calculations are stated in
             Section C.
1.   Dry Iron Oxide Purifiers
    A.  Design Based on American Practices
        G = 952,380 SCFH
        S = 515 (factor for 368 grains  per  100 SCF gas)
    EPA air pollution control  guideline for gaseous fuel  is  0.5  pound
    SO- per 10  Btu.  It is equivalent  to 520 ppm by volume  of sulfur
    compounds per SCF of gas with a heating value of 175  Btu/SCF.
        The overall  efficiency required to  meet EPA guidelines  is
    100 - 520 * 100/6190 = 91.6%.
        The hydrogen sulfide removal  efficiency of the commercial  iron
    oxide boxes ranges from 85 to 95%.   Assuming one dry  box will  give
    a  91.6% or more efficiency:
        C = 2 (for one box)
    It has been suggested in the literature that the oxide bed should
    be at least 10 ft thick for good gas distribution.
        D = 10 ft.
    A- (952'380)  (515)   =13,630 ft2
        (3000)  (10+2)
    Considering the limitation of physical  size and the  requirement of
    uniform gas distribution inside the iron  oxide boxes,  ten trains of
                              138

-------
gas clean-up units, in parallel, are suggested.   The size of each


box is


    13,630/10 = 1363 ft2


    i.e., 41.7 ft I.D. x 10 ft high (cylindrical  container)


          37 ft x 37 ft x 10 ft high (rectangular container)


Total  amount of Fe20o required is


    1363 x 10 ft3/box x 10 boxes x 9 lb Fe203/ft3 = 1,226,700 Ibs of Fe203.


S umma ry


Ten boxes of 37'x37'xlO' (or 41.7' I.D. x 10')  are required for


treatment of 22.86 million cubic feet per day of producer gas with


a heating value of 175 Btu per SCF.





B.  Design Based on European Practices


    1 .  For R = 20


952,380/20 = 1*7,600 ft3 of oxide  in box.


Assume the depth of bed height is 10 ft.

                                      2
Cross-sectional area of box is 4760 ft  .


Linear gas velocity = 952,380/4768/60 = 3-3 ft/min.


Mean gas residence time - 10/3-3 = 3-0 min.


Sulfur deposition rate  is


    952,380 x 3-68 x 0.92/60/4760 =11.3 grain/ft2/min

                                                       2
Sulfur deposition is below maximum rate of 15 grains/ft /min.
                            139

-------
     Considering  the  limitation of  physical  size and the requirement




of uniform gas distribution  inside the boxes, four boxes  in parallel




are  suggested.




     4760/4 -  1190  ft2




     i.e., 39  ft  I.D. x  10  ft high




          (4  columns are required)




     Total amount of  Fe£0o  required is 428,000 pounds.




     2.  For R - 50




952,380/50 =  19,050  ft3 of oxide in box.




Cross-sectional area is




     19,050/10 = 1905 ft2




Linear gas velocity = 952,380/1905/60 - 8.3 ft/min.




Mean gas residence time = 10/8.3 ~ 1-2 min.




Sulfur deposition rate  is




     952,380 x 3.68 x 0.92/60/1905 = 27-6 grains/ft2/min.




Since sulfur deposition rate is larger than acceptable value, 15,




R equal  to 50 cannot be used for design.




    Table I  lists designs at varying values of R.




Summary




According to European design practices for  iron oxide box, the values




of R can be 20 or 25 for this case.  The dimension of the boxes is:




    39 ft I.D. x 10 ft high, 4 boxes required; for R = 20.




    35 ft I.D. x 10 ft high, 4 boxes required; for R = 25.
                            140

-------
                             TABLE I:   IRON OXIDE BOX DESIGN BASED ON EUROPEAN PRACTICES
                                 Total  Cross
     R        Volume of    Bed    Sectional                  Linear     Mean Gas      Rate of S                No.  of
  CFH Gas     Iron Oxide  Depth  Area Needed  No.of Box  Gas Velocity  Residence    Deposition       Box      Boxes
per CF Oxide     Ft^       Ft        Ft^      Suggested     Ft/min     Time, min  Grains/ft2 min  Dimension  Required


     20         47,600     10       4,760         4          3-3          3-0          11.3       39'  I.D.        4
                                                                                                     X
                                                                                                  10'  High

     25         38,100     10       3,810         4          4.1           2.4          14.1        35'  I.D.        4
                                                                                                     x
                                                                                                  10'  High

     30         31,700     10       3,170                    5.0          2.0          16.0 *



     50         19,050     10       1,905                    8.3           1.2          27-6 *
                                                       n
  Rate  of  sulfur  deposition  is  greater  than  15 grains/ft /min.  limit.

-------
11.   Liquid-phase Iron Oxide Process (Ferrox)

     H2S  must  be removed from product gas to meet EPA guidelines:

         3.68  x 952,380 x 0.92/7000 = 460.6 Ibs H2S/hr = 0.128 Ibs H2S/sec

         2  Fe  (OH)3  + 3 H2S —*• Fe^ + 6 H20

            3  H2S               (3k)        ...   Ib H7S    .
         2  Fe  (OH)3  " '-5 x  (58.5 + 51)  " 0.466 Ib Fe (OH)3 (theoretical)


     Theoretical  amount of Fe (OH), required to remove 0.128 Ibs per

     sec  of H2S is

         0.128/0.466 - 0.275 Ibs of Fe (OH)3/sec            (theoretical)

     Actual  amount of Fe (OH) 3 used is usually about 3 times that  of the

     theoretical  one,

         0.275 x 3 = 0.825 Ibs Fe (OH)3/sec                 (actual  use)

     This amount corresponds  to 0.5 W %  in scrubbing solution, the

     amount of solution is


         0.825 x 122-= 165 Ibs solution/sec
                 0.5

                     = 1161  gpm % 63.6 lb/ft3

                          0.83 Ib/sec :  Fe (OH), }
                                                7          fl65   Ib/sec
     Scrubbing Solution*  4.94 Ib/sec :  Na2C03  >    Total \
                                                 (          (J2.59 ft3/sec)
                        J58.93 Ib/sec :  H20     )

     Physical  properties of  gas and solution:

         JU.=  1.0 cp

        |°g =  20/380 = 0.053  lb/ft3

        f1  -  63.6 lb/ft3


        VjJ   =PH20//>1  " 64.2/63.6 = 0.981

         FD **  packing  factor

            •  40  for 2"  Intalox Saddles


                                142

-------
Calculate Flooding Point for a Packed Column

    L'  =   165 Ib/sec

    G1  = 952,380 x 0.053/3600 = 14.02 Ib/sec

The limiting vapor velocity for practical  operation of a packed

twoer is set by the flooding point.   The flooding point can be

predicted as presented in Perry's Chemical Engineer's Handbook or

in the generalized pressure drop correlation of an aritcle by

J. S. Eckert (Chemical Engineering Progress, Vol. 66, No. 3,

March 1970, p. 40).

    L/G  (Pg/P,)1/2 =    (Pg/P,)172 =       (053} '/2 „ 0.339
From the correlation, it is found that the value of ordinate is

             _  = 0.063

                *\  A   —
    G2 = 0.063 -

    G2 = 0.063  (0.053) (63.6) (32.2)  =0>,7A
                (40) (0.981)  (l.O)0'2

    G = 0.418 lb/ft2 sec

Cross-sectional area of packed column at flooding point  is

    14.02/0.418 = 33.6 ft2

The vapor velocity at flooding point  is, V f,

    Vgf = 952,380/3600/33.6 = 7-9 ft/sec

Calculate Packed Tower Diameter

Because the packed column operation may become unstable  as  the

flooding point  is approached, the design value for allowable vapor
                            143

-------
velocity  is usually estimated  to be 50  to 70% of the maximum

allowable velocity, and this allowable  velocity  is used to

establish the column diameter.  Say at  50%,

    Vg = Vgf x 50* = 7-9 x 0.5 = 3.9 ft/sec

    A  - 952,380/3600/3.9 - 67.2 ft2

    i.e., 9 ft 3  inch  I.D. column.

Packed Bed Height

The height of packing material required can be estimated by
    NOG
                    - (mGM/LM)
where NQQ » number of overall transfer units

        m * slope of equilibrium curve dy /dx

       X£ - mole fraction solute in liquid fed to top of column

       yj • mole fraction solute in gas fed to bottom of column

       Y2 ** mole fraction in gas leaving top of column

       Gu - superficial molar mass velocity of gas stream,
            Ib moles/(hr)(sq ft)

       LM - superficial molar mass velocity of liquid stream,
            Ib moles/(hr)(sq ft)

The number of overall transfer units is estimated to be 15 from

Perry's Handbook.
                (15)
                           26 3 ft
                              *  *
         20  (o.    i.o)

plus about 10 ft of freeboard for gas-liquid disengagement, 15 ft for

bottom head, the overall height of the packed column is about 50 ft.

-------
    Size of Regenerator




    It has been  indicated  in literature that a minimum 5 minutes of




    liquid mean  residence  time  is required for regenerating ferric




    sulfide into ferric oxide.




        V - 2.59 ftVsec x 60 x 5 = 777 ft3




        i.e., 7-0 ft  I.D.  x 20  ft high




    Summary




    Packed Tower




    Packed column    :  9 ft 3 inches  I.D. x 50 ft overall height




    Packing Height   :  26  ft




    Packing Material:  2"  Intalox Saddles with F  = AO




    Regenerator




        Total Volume  Required:  777 ft3




                          i.e.,  7-0'  I.D. x 20' High  (for example)




    Flow  Rates




        Product  Gas:   952,380 SCFH or 22.86 x  10  SCFD




        Solution Circulation  Rate:     165  Ib/sec or  1161 gpm








III. Stretford Process




    The amount of HnS to  be  removed from  raw product  gas to meet  EPA




    guidelines  is




         3.68  gr/SCF x 952,380 SCF/hr  x 0.92/7000  gr/lb  =




              460.6  Ib H2S/hr -  0.128  Ib H2S/sec.

-------
From process basic chemistry, it is shown that one mole of sodium
carbonate is required to react with each mole of hydrogen sulfide.
    i.e.,   Na2C03 + H2S = NaHS + NaHCOj
    Na2C03 _ 106 _     .  Ib Na2C03
      H2S     3k    '     Ib H2S

Hence, theoretical amount of Na^CO, required to absorb 0.128 pound
per second of H2S is
    0.128 x 3-118 = 0.399 Ib Na2C03/sec.
Actual amount of Na2C03 used in practical operation is usually about
two to three times that of the theoretical one.  Say three times,
    0.399 x 3 = 1.197 Ibs Na2C03/sec.
The scrubbing solution is an aqueous solution containing sodium
carbonate and bicarbonate in the proportion of about 1:3 and 2,7
anthraquinone disulfonic acid (ADA).  The concentration of Na2CO? is
about 0.1 N and NaHCO. is 0.3 N in order to keep the pH range of 8.5
to 9.5-  This is equivalent to a solution with 0.505 W % of Na2COj.
Thus the amount of solution required is
    1.197 x 100/0.505 = 237-1 Ib solution/sec
                      = 1625 gpm £ 65.5 lb/ft3
The following physical properties of gas and solution have been
estimated:
     jU = 1.0 cp
    pg - 0.053 lb/ft3
    f, = 65.5 lb/ft3
                    = 0.952

-------
Calculate Flooding Point of a Packed Column


    L1  = 237-1  Ib/sec

    G1  = 952,380 x 0.053/3600 = 14.02 Ib/sec
From Perry's Chemical  Engineers'  Handbook,  it is found that


    G F tyjlH^

     pP o]     = o-0**1


Assuming 2" saddles are used as a packing material with a packing

factor of 40, i.e. F  =40

                                                             1/2
    r
    G =
           ,,  PgPl >c 1/2   [(0.041) (0.053)  (65.5) (32.2)]

          '"  FpVxiO-2}    =[     (40)  (0.952)  (1.0)0-2   J
      = 0.347 lb/ft2 sec


Cross-sectional area of packed column at flooding point  is


    14.02/0.347 - 40.4 ft2


The vapor velocity at flooding point  is


    952,380/3600/40.4 = 6.5 ft/sec


Calculate Packed Column Diameter


Assume the design value for allowable vapor  velocity  is  50%  that of


flooding point.


    V  = 6.5 x 0.5 = 3-3  ft/sec


Thus, the cross-sectional area  is


    A = 952,380/3600/3-3  = 80.2  ft2


     i.e., 10 ft  I.D.
                            147

-------
Packing Height


A mean residence time of 10 seconds  is assumed.


    3-3 ft/sec x 10 sec = 33 ft.


Reaction Tank (Delay Tank)


The reaction tank is located at the  bottom of the absorber tower.


A minimum of 10 minutes holding time is required to ensure a


complete sulfur deposition.  The height of the reaction tank is


    h - (2.371)  (60) (10) m    ,

    n     (65.5) (80.2)Z/ tt-


Oxidizer (Regenerator)


The oxidation of reduced ADA to normal  ADA will take 20 to 60 minutes


for completion.   However, 10 to 15 minutes will be practically enough


for reefrculation of the solution.  Say 15 minutes for this calculation.


Then the size of the oxidizer is



    2?7 *6° x 15  = 3260 ft*
        65.5


    i.e.,  }k ft  6 inches I.D.  x 20 ft high


    (Twenty feet high is typical for oxidizer)

-------
                              APPENDIX C
       MATERIAL BALANCES ON NITROGEN AND SULFUR COMPONENTS fOR
                   RILEY-MQRGAN GASIFICATION SYSTEM
1.   DATA

    The following data are extracted from the paper presented by Rawdon
    et al.

    A.  Dry Gas Composition                      V %

               CO                               2k.6
               H2                               13.1
               CHi,                               4.4
               C02                               5.9
               N2 + A                           51.7
               CnHm                              Q.I
               NH3                               0,07
               H2S                               0.12

    B.  Average gas flow Rate is 40 scfm

    C.  Ammonia concentration in gas is 666 ppm

    D.  Carbon, nitrogen and sulfur contents of feed coal  are 81.0
        1.54 and 0.7 W %, respectively.

    E.  Molar conversion of coal nitrogen to ammonia is 9*

    F.  Tar loading in the gas is 0.8 grams/scf

    G.  Nitrogen and sulfur contents of tars in the gas are 1.2 and
        0.5 W %, respectively.

2.   CALCULATION

    A.  Back-calculation of coal feed rate

        1)   Based on nitrogen balance in gas

            666 ppm NH3 x 40 x 60 - 1.598 scfh of NH3

            1.598/380 x 17 = 0.0715 Ibs of NH3

                           - 0.0588 Ibs of Nitrogen

            0.0588 - 0.09 x 0.0154 x W

            W - 42.4 Ibs/hr of coal feed


                                  149

-------
  2)  Based on carbon balance and an assumed value of carbon



      conversion.



      Gas Component                    Carbon Balance



           CO                2k.6% x 40 x 60 = 590.4 scfh



           CH^                4.4% x 40 x 60 = 105.6 scfh



           C02                5.3% x 40 x 60 - 141.6 scfh



           C H                0.1% x 40 x 60 x 3  = 7.2 scfh
            n m                           	
                                                 844.8 scfh



                                                   2.22 Moles/Hr



                                                  26.7 Ibs/Hr




      If 80% of carbon in coal  is  in the  gas,  the the  coal  feed rate



      is 26.7/0.8/0.81  =41.2  Ibs/Hr.








      Since both figures come  out  very  close  to  each other,  the coal



      feed rate is taken to be 42  Ibs/Hr  in subsequent calculations.







B.  Sulfur-component balance



    In:   42 x 0.7% = 0.294 Ibs of  sulfur  per  hour



   Out:   0.12% x 40 x 60 x 32/380  = 0.243 Ibs/Hr in HgS



         0.8 x 2400/453.6 x 0.5% = 0.021  Ibs/Hr  in Coal  Tars



         0.294 - 0.243 - 0.021  = 0.030  Ibs/Hr in (Coke + Char)



C.  Nitrogen-component balance



    Accurate calculation of nitrogen balance  is  impossible because  no

    data  on the ratio of air  feed rate to coal  feed  rate have been given.

    The  nitrogen-component balance, however,  is  estimated as follows:



    In:   42 x 1.54% = 0.647 Ibs of N in Coal/Hr



   Out:   0.07% x 40 x 60/380 x 14  = 0.062 Ibs  of N in  MH3



         0.8 x 2400/543.6 x 1.2% = 0.051  Ibs  of  N in Coal Tar
                                  150

-------
      The balance 0.53** (0.6^7 - 0.062 - 0.050  appears as free nitrogen in
      the gas and as bonded nitrogen in the coke and char.  According to data
      of Kohl, the split of the remaining nitrogen is estimated as 3**% in coke
      and char and 66% in the gas.
      Hence  0.53^ x lk% = 0.182 Ibs/Hr in Coke  and Char
             0.531* x 66% = 0.352 Ibs/Hr in Gas as N0
3-     SUMMARY
      A.   Sulfur Balance
          In, Ib/Hr
          Coal
          0.29**
          (100%)
               Out, Ib/Hr
 H S       Tars        Coke & Char
0.253     0.021          0.030
(82.65%)  (7.14*)        (10.21%)
      B.  Nitrogen Balance
          In. Ib/Hr

          Coal
          0.6^7
          (100%)
NH
0.062
(9.58%)
     Out, Ib/Hr

Tars       N     Coke + Char
0.051      0.352   0.182
(7.88%)    ($k.50%) (28.
                                      151

-------
                                TECHNICAL REPORT DATA
                          (Please read Instructions on the reverse before completing)
 1. REPORT NO.
  EPA-600/7-79-171
                           2.
                                                       3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Summary of Gas Stream Control Technology for
 Major Pollutants in Raw Industrial Fuel Gas
                                 5. REPORT DATE
                                  July 1979
                                 6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
F.D.Hoffert, W.Y.Soung, and S.E.Stover
                                                       8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Hydrocarbon Research, Inc.
Lawrence Township, New Jersey  08648
                                 10. PROGRAM ELEMENT NO.

                                 E HE 62 3 A
                                 11. CONTRACT/GRANT NO.
                                                       68-02-2601
 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 PI
                                 Final; 7/77 - 3/79
                             PERIOD COVERED
                                 14. SPONSORING AGENCY CODE
                                   EPA/600/13
15. SUPPLEMENTARY NOTES
IERL-RTP project officer is William J. Rhodes, Mail Drop 61, 919/541-2851.
is. ABSTRACT
              repor|. summarizes coal gasification and clean-up technology with em-
phasis on methods of producing a clean industrial fuel gas as defined by agreement
for study purposes. The coal-derived industrial fuel discussed produces no more
than 0. 5 Ib of SO2 ,  0. 4 Ib of NOx, and 0. 1 Ib of particulates per million Btu of fuel
gas. In general, existing state-of-the-art  control technology will allow these emission
guidelines to be met, although the end use for the fuel gas will strongly  influence the
choice of the pollution  control technology that is used. Many but not all important
factors pertinent  to control technology application were considered. Costs are an
example of important factors which were not evaluated because the objective was to
first determine appropriate technology that could be applied. Emissions other than
the three major pollutants  indicated were given only cursory treatment. Neverthe-
less , a general overall background of control technology for industrial fuel gas has
been covered.
17.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                           b.IDENTIFIERS/OPEN ENDED TERMS
                                              c.  COSATI Field/Group
Pollution
Goal Gasification
Coal
Gases
Fuels
Sulfur Dioxide
Nitrogen Oxides
Dust
Pollution Control
Stationary Sources
Industrial Fuel Gas
Particulate
13 B
13H
2 ID
07D

07B
11G
18. DISTRIBUTION STATEMENT
 Release to Public
                                           19. SECURITY CLASS (ThisReport)
                                           Unclassified
                                                                    21. NO. OF PAGES
                     20. SECURITY CLASS (Thispage)
                     Unclassified
                                              22. PRICE
EPA Form 2220-1 (9-73)
                  152

-------