SEPA
United States
Environmental Protection
Agency
Industrial Environmental Research EPA-600/7-79-168
Laboratory July 1979
Research Triangle Park NC 27711
Engineering Evaluation
of Control Technology
for the H-Coal and Exxon
Donor Solvent Processes
Interagency
Energy/Environment
R&D Program Report
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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.
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EPA-600/7-79-168
July 1979
Engineering Evaluation of Control
Technology for the H-Coal and Exxon Donor
Solvent Processes
by
K. R. Sarna and D. T. O'Leary
Dynalectron Corporation/Applied Research Division
6410 Rockledge Drive
Bethesda, Maryland 20034
Contract No. 68-02-2601
Program Element No. EHE623A
EPA Project Officer: Robert A. McAllister
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
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ABSTRACT
Control technology of the two coal liquefaction processes, namely,
H-Coal™ and Exxon Donor Solvent (EDS) process, has been evaluated for both pi-
lot plants and conceptualized commercial plants. The effluent streams have been
characterized and quantified for both processes and plants (pilot and commercial).
The emissions via gaseous effluents, liquid effluents and solid streams
were analyzed for their controllability, process complexity and efficiency. Ex-
trapolations to the larger commercial size were based partly on pilot plant data
and engineering judgment when such data was not available.
Several gaps in information were encountered in cases of liquid and
solid effluent streams,especially in their composition. These deficiencies were
pointed out and recommendations were outlined.
i±
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Contents
Abstract i:f
Figures .vi
Tables • • 7iii
Acknowledgement lx
1. INTRODUCTION '
2. CONCLUSIONS AND RECOMMENDATIONS 3
2.1 General 3
2.2 H-Coal Process *•
2.3 EDS Process *»
3. STATEMENT OF THE PROBLEM AND OBJECTIVES 6
4. PROCESS DESCRIPTION 8
A.I H-Coal 8
4. .1 Coal Feed Preparation 8
4. .2 Primary Separations 8
4. .3 Hydrogen Recycle • • ^
4. .4 Liquid Treatment 10
4. .5 Gas Treatment 10
k. .6 Sour Water Treatment 10
A. .7 Process Diagrams ^
A.2 Exxon Donor Solvent Process ^'
A.2.1 Coal Feed & Slurry Preparation 11
k.2.2 Coal Liquefaction 21
4.2.3 Solvent Hydrogenation 21
A.2.A Flexicoking 22
4.2.5 Hydrogen Generation 22
4.2.6 Product Upgrading 22
4.2.7 Gas and Wastewater Treatment 22
4.2.8 Historical Development of the EDS Process 23
5. EVALUATION OF H-COAL CONTROL TECHNOLOGY 26
5.1 Pilot Plant .Emissions 26
5.1.1 Coal Handling 6 Preparation 27
5.1.2 Reaction and Primary Separations 30
5.1.3 Sour Water and Gas Treatment 32
5.1.4 Wastewater Treatment 35
5.1.5 Waste Solids Treatment 38
iii
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Contents (cont'd)
5.1.6 Catalyst Handling 41
5.2 Control Technology for the Pilot Plant 41
5.3 Analysis of the Pilot Plant Control Technology 42
5-4 Emissions from Commercial Plant 42
5.4.1 Coal Handling and Preparation 44
5.A.2 Reaction and Primary Separations 44
5.4.3 Desulfurization and Denitrification 47
5.4.4 Wastewater Treatment 47
5.A.5 Hydrogen Production 47
5.5 Control Technology for Commercial Plant 50
5.5.1 Gaseous Effluents 50
5.5.2 Liquid Effluents 52
5.5.3 Solid Wastes 52
5.6 Assessment 53
5.6.1 Coal Handling and Particulate Control 53
5.6.2 Tail gas Cleanup 53
5.6.3 Wastewater Treatment 55
5.6.4 Solid Waste Disposal 55
EVALUATION OF EDS CONTROL TECHNOLOGY 56
6.1 Emissions from the Pilot Plant 56
6.1.1 Coal Handling and Preparation 56
6.1.2 Reactions and Primary Separations 64
6.1.3 Sour Water and Gas Treatment 66
6.1.1* Wastewater Treatment 66
6.1.5 Solid Wastes Treatment 70
6.1.6 Catalyst Handling 72
6.2 Pilot Plant Control Technology 72
6.2.1 Air Emissions Control Technology 72
6.2.2 Liquid Effluents Control Technology 73
6.2.3 Solid Waste Control Technology 73
6.2.4 Environmental Testing Program 74
6.3 Analysis of the Pilot Plant Control Technology 75
6.4 Emissions from the Commercial Plant 76
6.4.1 Coal Handling and Preparation 76
6.4.2 Reactions and Primary Separations 77
6.4.3 Sour Water and Gas Treatment 78
6.4.4 Wastewater Treatment 82
6.4.5 Solid Wastes Treatment 82
6.4.6 Catalyst Handling 85
6.5 EDS Plant Control Technology 85
6.5.1 EDS Plant Air Emissions Control Technology 85
6.5.2 EDS Liquid Effluents Control Technology 87
6.5.3 EDS Solid Effluents Control Technology 87
iv
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Contents (cont'd)
ALTERNATIVE CONTROL TECHNOLOGY SYSTEMS 89
7.2 Tail Gas Treatment
7-2.1 Institut Francais de Pe'trole (iFP)Process
7.2.2 Holmes-Stretford Process
7.2.3 Beavon Process
7.2.4 Lime/Limestone Scrubbing
7.2.5 Sulfox (UOP) Process
7.2.6 Systems Analysis
7-3 Hydrocarbon Emissions
7.4 Combustion Products
7-5 Liquid Effluents
7.5.1 Relevant Statutes
7.5.2 Water Management Program
7.5.3 Offsite Wastewater Treatment Alternatives
7-6 Solid Wastes
90
90
93
93
93
95
95
99
99
99
99
.... 100
.... 101
.... 101
8. COST EVALUATION 105
8.1 Introduction 105
8.1.1 Methodology of Approach 105
8.2 Cost of Control Technology 106
8.2.1 Capital Costs 106
8.2.2 Operating Costs 107
8.2.3 Capital Related Costs 107
8.2.^ Control Technology Cost Share 107
8.3 Cost of Alternative Technologies 107
References 109
Appendix 112
A. Table of Conversion Factors to SI Units 112
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FIGURES
Number Page
1 Schematic of H-Coal process 9
2 Overall material balance fuel oil mode of operation
Illinois #6 coal 12
3 Overall material balance syncrude mode of operation
Illinois #6 coal 13
4 Overall material balance syncrude mode of operation
Wyodak coal 14
5 Process flow diagram of the pilot plant 15
6 Schematic of the EDS process 24
7 Hourly material balance for the ECLP
Illinois #6 coal 25
8 Coal handling 28
9 Reaction & primary separations 31
10 Desulfurization & denitrification 33
11 Water treatment process schematic 36
12 Overall material balance 43
13 Coal handling 45
14 Reaction £ primary separation 46
15 Desulfurization & denitrification 48
16 Water treatment process schematic 49
17 Hydrogen production 51
vi
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FIGURES (cont'd)
Number Page
18 Particulate concentration distribution 5^
19 Flow diagram of coal preparation and storage 5q
20 Wastewater sources in the ECLP plant 68
21 Disposal of ECLP vacuum tower bottoms 71
22 Sour gas and water treatment process:
EDS plant 79
23 Phenol extraction flow plan: EDS plant Bl
2k Conventional desulfurization via amine/
Claus system with tail gas treatment 91
25 IFP process schematic 92
2& Beavon process schematic 9**
27 Schematic of 1ime/1imestone scrubbing 96
28 Sulfox (UOP) process 97
29 Gas treatment process alternatives
schematic 98
30 Wastewater processing alternatives 102
vii
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TABLES
Number Page
1 Initial Unstripped Foul Water Characteristics 34
2 Characteristics of Individual Waste Streams 39
3 Summary of Raw Waste Load, Design and
Discharge Criteria 40
k ECLP Atmospheric Emissions 59
5 Maximum Allowable Emission Rates for Coal
Preparation and Handling Facilities in the ECLP 60
6 Comparison of Calculated ECLP Atmospheric
Emissions and State of Texas Standards 61
7 Weather-0-Meter Leaching Tests for
Liquefaction Bottoms and Illinois #6 Coal Used in the ECLP .... 63
8 Comparison of ECLP Atmospheric Emissions and
Federal Standards 65
9 ECLP Sour Water Sources 67
10 Continuous Sources of Emissions for the
EDS Plant 83
11 Effluent Concentrations from the EDS Offsite
Wastewater Treating Facilities 84
12 Catalyst Disposal Schedule: EDS Process • 86
13 Cost of Pollution Control Equipment for the
EDS Process 88
14 Trace Element Composition of Illinois #6
Coal Samples 103
viii
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ACKNOWLEDGEMENT
This study was performed under EPA Contract No. 68-02-2601. The
authors wish to thank Messrs. C. Vogel and W. Rhodes of IERL/RTP for their
continued support and interest in the progress of this work.
Appreciation is extended to Dr. C.A. Johnson who acted as consultant
on the H-Coal™ process.
The data base for the preparation of this report consists primarily
of information available in the the public domain (consult the list of referen-
ces). Some additional information was obtained through direct contact with the
managers of the coal liquefaction processes.
ix
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Section I
INTRODUCTION
The increasing inability of the United States economy to meet its
needs for petroleum based products through domestic sources has had serious
repercussions on the Nation's economy and on its international political and
military posture.
Thus, in informed circles, there is a realization of the need to
have available alternative reliable and economical sources of energy to offset
the uncertainties associated with events such as oil embargoes, and externally
dictated increases in the price of petroleum and natural gas products. For-
tunately, the United States is extremely rich in alternative sources of synthe-
tic crudes,especially in recoverable coal reserves which have been estimated
at 250 bill ion tons.
As of today, three coal liquefaction processes have been identified
as having superior promise for commercial development, namely, the H-Coal™
Process, the Exxon Donor Solvent (EDS), and the Solvent Refined Coal Process
(SRC ||). Currently,a 50 ton/day SRC II pilot plant is being operated in
Takoma, Washington while pilot plants for the H-Coal™ and EDS processes are
being constructed in Catlettsburg, Kentucky and Baytown, Texas, respectively.
The Environmental Protection Agency (EPA), as part of its mission to
protect the public health and welfare from adverse effects of pollutants asso-
ciated with energy systems, has undertaken a comprehensive fuel process assess-
ment program. The goal of the program is to assure the rapid development of
domestic energy supplies in an environmentally-compatible manner by providing
the necessary environmental data and control technology. As part of this pro-
gram, the EPA has contracted with Dynalectron Corporation, through its Applied
Research Division, to make an engineering evaluation of control technology for
two coal liquefaction processes, namely, the H-Coal process and the Exxon
Donor Solvent Process (EDS).
Most coal liquefaction processes surfacing to prominence today are
all heavily involved in the generation of data on the liquefaction process
itself. A large effort is being directed at catalysts, catalyst life studies,
slurry properties, etc. in order to evaluate all the process parameters. On
the other hand, only a limited effort is being made by the process developers
toward the control technology aspects of these processes, basically because
of two reasons: (1) the control technology is solely considered as an "end-
of-pipe" adjunct to a process itself, and (2) the control technology is as-
sumed to be standard and straightforward. Although both reasons may be valid,
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the engineering evaluation of these control technologies is warranted. It must be
reiterated that the purpose of this study is to evaluate only the control technology
of the converter outputs and therefore no attempt is made to comment on the processes
or thermal efficiencies. The methodology of evaluation is outlined below.
The process is first divided into system operations and auxilliary
processes such as coal handling, reaction and primary separations, product separations,
gas treatment, water treatment and solids disposal. For each of these subsections,
the flow streams as inputs and outputs are determined along with their compositions.
The emissions are then characterized as to their rates, concentrations and other
features such as cyclic variations and excursions.
As a second step, the control system and the technology behind it are
evaluated for a) their removal efficiency, b) efficacy to this process as designed
and c) scalability for commercial application.
Next, the emissions are extrapolated to a commercial plant of a suitable
size, say 50,000 Bbl/day or 25,000 Tons of coal per day as feed. The control tech-
nology features for this size are then determined taking into account the extra-
polatability of the pilot plant design. A comparative assessment of both technolo-
gies is then made.
A conversion table to SI units rs included in the Appendix of this report.
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Section 2
CONCLUSIONS AND RECOMMENDATIONS
2.1 GENERAL
A critical evaluation of the control technology of the two coal
liquefaction processes (H-Coal and EDS) shows a mix of some accomplishments
and some deficiencies. Most of the former are in the process category and
many of the latter are in the area of environment and control technology.
These deficiencies are listed below along with some recommendations.
1. Concl us ion; Only end-of-pipe control technology has been
attempted. However, an integrated approach may prove to be
more advantageous.
Recommendation: Studies are needed for determining that end-
of-pipe approach is the only approach applicable and that an
integrated approach is economically not competitive.
2. Conclus ion: All coal conversion plants degrade the environ-
ment, by releasing carbon dioxide, depleting water supplies
and depositing solid wastes that could be harmful. The ex-
tent of this degradation has not been assessed.
Recommendat ion: An accurate assessment of the extent of envi r-
onmental degradation of a coal liquefaction plant must be made
with contributory breakdown of air, water and land degradation.
3. Conclus ion: Any coal liquefaction plant must, by logistics,
be located near a large mine or a cluster of small mines. Al-
though coal mining does not require large quantities of water,
a coal liquefaction plant does. The impact of this kind of
water use and the ability of a water body near a mine cluster
to support a liquefaction plant have not been quantified.
Recommendat ion: The impact of irrecoverable water use must
be assessed.
^. Conclus ion: As a mine is depleted and finally abandoned, it
can be used for disposal of solid wastes. However, the impact
and long range effects of such a scheme have not been evaluated
thoroughly.
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Recommendation: Solid waste disposal in abandoned mines should be
studied both from technical and environmental standpoints.
2.2 H-COAL PROCESS
The evaluation of the control technology of H-Coal process has led to
the following conclusions. Obviously, these are based on the present state-of-
the-art of the processes and technology involved. Furthermore, the pilot plant
presently under construction forms the basis for many of the following conclu-
sions.
The main thrust of the design and proposed operation of the pilot plant,
is directed towards filling the process-related information gaps only. Control
technology testing and verification seem to be peripheral at best.
The entire control technology of coal handling, pulverizing and feeding
consists of collecting coal pile runoff (for some later treatment) and bag filters
for dust control. The basis of assurance that these are sufficient has not been
established. Also, the scalability of this particular technology to commercial
plant size is still in doubt for particulate control via filters and also for
runoff collection and transfer.
Tail gas cleanup treatment seems adequate and the technology applicable is
proven. In the pilot plant it is all piped to the adjacent refinery, but the
process and technology are applicable and scalable for commercial plant size.
In the pilot plant no phenol recovery is designed, but this was planned
for a later date. More information on this is obviously needed because in the
commercial plant this is an absolute requirement.
Neither the pilot plant, nor the conceptual commercial designs incorporate
zero discharge control technology. As these plants come on stream in the early
or mid 80's this zero discharge criterion becomes effective. Hence, efforts
must be directed towards that goal now.
Solid waste disposal as landfill appears to be adequate. However, impor-
tant information on these solids is lacking. It must be studied and determined
that these solids do not contain carcinogens and mutagens and that they do not find
their way into drinking waters.
2.3 EDS PROCESS
As in the case of H-Coal Process, the bulk of emphasis in the Exxon
Donor Solvent Process also is directed towards process goals and the development
of process-related information. The control technology in ECLP (Exxon Coal
Liquefaction Plant) is almost non-existent in the sense that all effluent streams
with pollutants are simply piped to the refinery next door for treatment along
with its wastes or carted off as a landfill, as in the case of the solid wastes..
On the commercial level, the following factors need to be considered at greater
length:
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(1) The control technology of coal handling, pulverizing and
feeding needs to be ensured for scalabi1ity,especially in
the case of bag filter operation;
(2) Design of the wastewater treament plants for meeting zero
discharge requirements;
(3) Collection, transportation and disposal of the solid wastes
to comply with the regulations promulgated under the aegis of
the Resource Conservation and Recovery Act of 1976.
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Section 3
STATEMENT OF THE PROBLEM AND OBJECTIVES
The increasing attention paid to coal conversion processes stands
as a concern within EPA in its efforts to maintain the quality of the en-
vironment we live in. Most of the coal conversion processes, especially li-
quefaction, are essentially in a new technology area in which there is not
enough information to assess all the environmental factors. Therefore, EPA
has decided correctly and wisely to study the control technology of the coal
conversion processes based on the information generated by the pilot plants.
As such it is a broad assignment and requires a more precise description.
The directive describes the project as an "Engineering Evaluation
of Control Technology for Converter Outputs". The evaluations are based
upon the information available from existing pilot plant designs for the
H-Coal and EDS processes. Several process streams have been mentioned as
candidates for control technology evaluation and several pollutants have
been identified for investigation. These are illustrated here in matrix
form:
POLLUTANTS
STREAMS
U
u.
• Q)
C T3
IE
10 *3
o in
o 'x
.0 O
V. C
flj Q
«_> E
C
V 0)
wo
TJ (0
(0
4) V)
O. m
O •-
I- M-
T3 —
>- 3
C
0) (U
Coal Feed
Product Gas
Separator Overhead
Vacuum Overhead
Sour Water
Catalyst
Vacuum Tower Bottoms
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The objectives of the study can be stated as:
1. to characterize the pilot plant effluent streams and the resulting
emissions as to their quantity, components, and concentrations.
2. to evaluate the efficienci.es of the pilot plant control technology
elements.
3. to determine their applicability to the commercial size plants.
*». to identify alternate technologies other than the ones employed
in the pi lot pi ant.
5. to evaluate cost factors of the control technology as fractions
of the total plant cost.
6. to identify information gaps if there are any and to make recom-
mendations to fill these deficiencies.
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Section k
PROCESS DESCRIPTION
A.I H-COAL
This is a process of coal conversion into predominantly liquid
hydrocarbon products bv means of hvdrogenation of the coal, in an oil slurry
in the presence of a catalyst. It is a proprietary process developed by
Hydrocarbon Research, Inc., (HRl) and is an innovative modification of the
H-Oil process developed to hydrotreat heavy fuel oils. The H-Coal process
has been studied in demonstration units and on a pilot scale by HRl under
sponsorship of DOE (1). The complete design of a pilot plant having a
throughput of 600 ton/day of coal, has been performed by HRl Engineering.
This plant fs being built at Catlettsburg, Ky. The process is shown in
Figure I in schematic form.
A.1.1 Coal Feed Preparation
The coal is first pulverized and then dried and finely ground to
about 90 percent through 200 mesh. It is then slurried with a coal derived
oil (recycle oil) and the slurry is mixed with hydrogen, preheated in a
fired preheater furnace to about 840°F at about 3000 psi pressure. The
heated slurry is then pumped into the reactor containing the catalyst. The
mixture travels up the reactor and leaves from the top. The catalyst, in
the form of pellets that are larger and denser than the coal particles, how-
ever, remains in the reactor. Catalyst deactivation was found to be very
rapid and so, in order to maintain a certain level of catalyst activity, part
of the catalyst is periodically withdrawn and replenished with fresh catalyst.
A.1.2 Primary Separations
The reactor output consisting of unconverted coal, ash, liquid and
gaseous products is first separated into a condensed phase and vapor phase.
The condensed phase is then flashed in a.series of drums to about 85 psi and
the solid-liquid fraction is partially separated in a system of hydroclones.
The hydroclone overflow is flashed to atmospheric pressure and then sent to
slurry tanks for recycling. The underflow of the hydroclones is treated in
an antisol vent fill in the pilot plant, but are planned to be used as a
source of hydrogen production in a commercial plant.
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RECYCLE
COMPRESSOR
HEATER
WASTE HEAT
.REC
Vs
J
i r
JL
r "
,'
1 1
1
IflEO
UE C
U
•
<
\
TREATMENT
FLASH
SS7EM
I
SOLID
WASTE
SOLID
FUELJ3AS
FUEL GAS
DROCLONES
DEASHING
DISTILLATION
\
NAPHTHA
FUEL OIL
FIG 1 SCHEMATIC OF H-CQAL PROCESS. (FUEL OIL MODE)
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k. 1.3 Hydrogen Recycle
The vapor phase of the reactor output goes through a waste heat reco-
very system in which process steam is generated by cooling the reactor vapors.
The cooled vapors are then condensed and liquid condensate is mixed with the
liquid phase of the products for further separation. The gases are separated
into fuel and recycle gas in an absorber-stripper system using lean hydrocar-
bon oil. The recycle gas containing unused hydrogen is compressed to the
reactor pressure of 3000 psi for reuse, and the fuel gas is sent to the gas
treatment system.
k.].k Liquid Treatment
The liquid fractions of the reactor output are collected and separated
in a fractioning column into a variety of products ranging from fuel gas and
naphtha to light oil and bottoms. Operating under more severe conditions, a
liquid product comparable to crude oil can be produced which then can be pro-
cessed in a conventional refinery into gasoline and furnace oil. This is the
syncrude mode of operation. As originally designed, the liquid fraction of
the solid-liquid mixture goes first to an atmospheric column which separates
the liquid into essentially two products; a lighter overhead product is then
subjected to a vacuum distillation where another heavy and light separation
takes place. The lighter overhead is again sent to the fractionator while the
bottoms are flaked into a solid product which is disposed of as land fill in
the pilot plant. This can also be used as raw material for hydrogen production
in a commercial plant.
4.1.5 Gas Treatment
The fuel gas from the oil washing and from the various vents contains
hydrogen sulfide produced in the process. In order to m.ake clean fuel gas out
of this sour fuel gas, it is treated in an absorber with an absorbent like DEA
(Diethanolamine) which is subsequently stripped to regenerate the absorbent.
The off gases from the stripper containing predominantly H^S are sent to Claus
units of the refinery located adjacent to the pilot plant. For commercial
plants also, Claus units can be employed to convert the H.S to elemental sulfur.
4.1.6 Sour Water Treament
During the hydregeneration reaction, the oxygen in the coal is partially
converted into water. Also the treatment of the liquid fraction of the product
requires injection of process water. Thus an appreciable amount of water layer
is formed and this contains some dissolved H.S and, also, ammonia which Is formed
when the nitrogen in the coal is hydrogenated. This sour water, therefore,
must be stripped to remove the H S and NH and treated before discharging to the
environment. The stripping is done in two separate strippers at two different
pressures and H-S is sent to the Claus units in the pilot plant. The ammonia
isburned in a boiler furnace in the pilot plant, but can also be recovered as
planned in the commercial plant. This stripped sour water is partly reused in
the process and partly sent to the waste water treatment system where it is mixed
with other waste waters for treatment and discharge into natural streams.
10
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4.1.7 Process Diagrams
The overall material balance as input/output for the proposed opera-
tional modes and coals is shown in Figures 2 to A. A process flow diagram of
the pilot plant with material balances is shown in Figure 5.
4.2 EXXON DONOR SOLVENT PROCESS
The EDS process involves the non-catalytic liquefaction of coal in a
hydrogen-donor solvent with subsequent separation of solids from liquids and
catalytic hydroprocessing of the liquids to provide regenerated donor solvent
and improved quality products. Preliminary process work was done on a 1 ton/
day Coal Liquefaction Pilot Plant (CLPP) (2-13). In May, 1978, ground was
broken in Baytown, Texas on the construction of a 250-tons/day Pilot Plant
(ECLP) with a scheduled completion date of November 1979. Preliminary design
work has also been completed for a 24,000-tons/day Commercial Plant. The sub-
sequent EDS Coal Liquefaction Process Description is based primarily on the
above-mentioned and ancillary sources.
To facilitate the process description, it may be broken down into 7
system operations as per the following table:
Breakdown of the EDS Process
Operation
Number Description
1 Coal feed & slurry preparation
2 Coal liquefaction
3 Solvent hydrogenation
4 F1 exicoking
5 Hydrogen generation
6 Product recovery
7 Gas and water treatment
4.2.1 Coal Feed & Slurry Preparation
Coal is fed via a conveyor belt from a stacker-reclaimer to a feedsurge
storage silo and thence to impact mill coal crushers where the coal is mixed with
the hydrogen donor recycle solvent (with a normal boiling range of 400/900°':
11
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COAL*
45/53
HYDROGEN
2387
H-CQAL
PILOT PLANT
CATLETTSBURG. KY
GASES
7325
NAPHTHA
J54J
WATER
4245
FUEL OIL
78,457
CAKE
ALL FLOWS ARE IN LB/HR
* CORRESPONDS TO 541 T/D
FIG. 2 OVERALL MATERIAL BALANCE:
FUEL OIL MODE OF OPERATION
ILUNO/S&6 COAL
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COAL*
12900
HYCROGEN
1285
H-COAL
PILOT FLAW
CATLETTSBURG. KY
GASES
3030
NAPHTHA
2260
WATER
1995
SYNCRUDE
5000
CAKE
6100
ALL FLOWS ARE IN LB/HR
* CORRESPONDS TO 2J5 T/D
FIG. 3 OVERALL MATERIAL BALANCE
SWCRUDE MODE OF OPERATION
ILLINOIS «*5 COAL
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COAL
1*300
HYDROGEN
1850
H-COAL
PILOT PLANT
CATLETTSBURG. KY
ALL FLOWS ARE IN LB/HR
* CORRESPONDS TO 220 T/D
G4SES
4330
NAPHTHA
3200
WATER
3720
SYNCRUDE
2700
CAKE
6000
FIG.U OVERALL MATERIAL BALANCE
SYNCRUDE MODE OF OPERATION
WYODAKCOAL.
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VENT
AIR
FROM
HOODS
BOOT
COAL PILE
6001
COAL PILE
^S^L
AIR
WATER
SOLIDS
TOTAL
TEMP FT]
CFM (AIR)
PCF
COAL
FEED
12.043
58-800
70.843
MILL
EFFLUENT
195.159
12.043
58.800
266.002
225
76.000
0.045
CYCLONE
-TED
195.159
12.043
58.800
266.002
225
76.000
0.045
FLUE
GAS
195.159
195 159
435
88,630
0.037
CYCLONE
DIS-
CHARGE
204.802
1,200
206.002
DRY
COAL
1.200
58.800
60.000
AIR TO
HEATER
177.255
225
65.650
0-045
SUP
STREAM
27.948
160
28.108
VENT
AIR
27.948
225
10,351
0-045
DRY
COAL
160
160
RUN
OFF
10.000
10.000
._ 1 rnAi UA A/n/ /A//^ .0 oo/rn/i o/ir/rtA/
FIG, 5 PROCESS FLOW DIAGRAM OF THE PILOT PLANT
15
-------
^\S7fi>£4M
CO^POA/EW^-^
HYDROGEN
H2S+NH3
HjO
CO+COp »/Vp
C; -Q (GAS)
C$+(L1QUID)
SOLIDS
TOTAL fLB/HR]
TEMP [VJ/PS/
CFS/GPM
S.G./PCF
POWDER
COAL
885
U.268
45.153
SUJRRY
OIL
93,411
8.208
101.619
200/-
- /168
1.11/-
RECYCLE
S4S
1.667
195*0
7
640
1.776
69(v)
4,355
200/30H.
0.68/-
-/1.8
RECYCLE
GAS
427
50+0
2
164
454
17 (V)
1.114
200/3015
0.17/-
-/I.8
RECYCLE
G4S
2.732
345*0
3397
5.561
79M
12.114
150/29H.
1-2/-
-/2.7
REACTOR
FEED
4.826
590+0
894
4.201
7.791
93.576
52.476
164.356
747/30K
EBUL
PUMP
SEAL
5.000
5.000
400/30K.
- //;
0.9 1/-
REACTOR
EFFLUENT
3.427
2170'27C
5J060
4.524
11.636
127.097
15.173
169.356
850/3011
EFFLUENT
VAPOR
2.933
1787+221
4.095
3.904
9.237
18303k
41.079
850/3011
3.3S/-
-/3.4
EFFLUENT
LIQUID
495
382+50
965
619
2.399
108.194
15.173
128.277,
850/301*
~/226
1.0/-
3 C///DDWA//7 i> DCAmriM
FIG. 5 (continued)
16
-------
^^SW£4M
CCMP(M7\/T\
HDROGEN
H2S *NH3
H20
CO+COp +A/2
C; -Q (GAS)
^(LIQUID!
SOLIDS
TOTAL \LB/HR~]
; TEMP. [T]/PS/
CFS/GPM
S.G./PCF
LIQUID
AFTER
W.H.R.
49
54*9
774
75
333
15.302
16.026
500/296
-/35
0.9/-
LIQU/D
FROM
ABSORB.
8
97+0
23
354
3,301
3,783
•
PROCESS
WATER
2.532
2,532
'00/1X0
-/5.0
1.0/-
PROCESS
WATER
U04
1.3 OL
100/ 75
-/2.6
1.0/-
M AXE UP
HfDRO-
GEN
1.667
9
271
139
2.387
100/160C
1.0/~
-/0.7
SOUR WAT
FROM
OWEPS
382+212
22432
23.026
120/-
-A6
1.0/-
NAPHTHA
AND VAC.
OWEROH
17.792
17.792
285/-
-/31
1.0/-
L.P. FlASh1
DRUM
BOTTOM
3
13+1
26
9
69
10L236
15.173
119.530
731/85
-/18I
1.13/-
RECYCLE
PLUS
MAKE UP
2. 09*.
215*0
9
801.
2.230
88 (v,
5.1.70
200/3015,
0.9 '/-
~/1.8
SOUR YM
FOR
STR1PPIW
465*269
27.371
28.125
120/15
-/56
1.0/-
rRACTlON-
ATOR
FEED
9+0
2
1
61.
39.91.9
i. 0.025
285/25
-/82
0-97/—
FUi-IL
GAS
our
120
186
171
1.101
395
1.973
125/-
3. PRIMARY SEPARATIONS
FIG. 5 (continued)
17
-------
STEAM OMtd
^\S7/£dM
p^oAe^r^
HQROGEN
/^S+A/A/j
«?0
CO+CQj+fy
q -Q re/is;
cs+fi/oty/o;
sot/os
WKCWO-
CLONE:
JNDRR.Q
1
4*0
8
3
20
29.952
6.965
TOTAL [L8/Hft36.853
TEMP M/PSM31/85
CFS/GPM ~/52
SG./PCF \1.13/~
OEAShEL
S7»WE?5
FEED
1
3+0
7
2
18
37.552
37.581.
731/85
- /70
1.06/-
aw-
WERF1XH
2
9+1
19
6
49
71.735
8.208
82.670
731/85
-S131
tJJX-
ffffl
SlURRf
56.792
8.208
€5.000
5S5/TO
-S9S
1.W-
VflCUUM
TOWER
90TTOMS
15.337
15.337
S06/2.1.
-X24
'.«?$/-
FRACTION
ATOR
FEW
3
11+1
1724
8
62
23.733
25.54 T
682/30
*5/-
-/0.26
VENT
3
12+0
a
75
61
160
120/16
o.:/-
-/0.08
FUEL
GAS
6i-0
1
51
58
100/50
QOL/-
-/0.4
NAPHTHA
fRcwcn
3.543
3.54J
100/50
-/8.5
0.8/-
LIGHT
OIL
19.31.1
19.31.1
LOO/50
-/1.2
0.9/-
FRACriON
ATOR
BOTTOMS'
1.0.735
40.735
500/50
-/80
1.0 1/-
. /. oonmirr ccoAOATtnMc
FIG. 5 (continued)
18
-------
WASTE HEAT
RECOVERY
MAKEUPOIL<3-
(QUENCHES)
\ ^
STRIP]
PEP
^-^STREAM
;OVf>OAEftr\
HYDROGEN
fyS+NH)
H?0
CO+CO^WV?
C;-<^ (GAS)
Cs* (LIQUID)
SOLIDS
TOTAL [LBMR]
TEMPC°F]/PSi
CFS/GPM
S.G./PCF
PROCESS
WATER
U.185
U.185
100/29&
-/?*
10/-
flEACTQR
EFFL
VAPOR
2.881
1703*211
3.921
3.629
6.904
3.598fo
25.050
500/296
2.3/-~
-/3.0
WATER
LAYER
OFCOMQ
380*211
18.106
18.697
TX/2915
-/38
1.0 /-
VAPOR
TO ABS-
ORBER
2.877
1.226
3.806
8.551
298
16.758
130/2915
1.3/-
-/3.5
RICH
OIL
U6
1.275
U7
1.603
83.385
89.856
125/2915
-/218
0.6/-
MAKEUP
EANOIL
(IN)
263
263
LEAN
OIL
1
391.
37
1.613
83.166
85.210
110/2915
-SI92
0.6/-
FUEL
GAS
U5
880
409
2.985
210
i.,628
113/65
6.2/-
-/0.2
MAKEUP
OIL
(QUENCH
ZERO IN
ST STATE
MAKEUP
RICH OIL
(OUT)
280
280
5. ABSORPTION SYSTEM
FIG. 5 (continued)
19
-------
GAS
-+MAKE UP
LEAN OIL
FLARE
•OUR
ABSO
'UEL
3AS
ABSO-
RBER
STWP
I J
ro
BOILER
CMOS UMTS
DE4 >
STORAGE t
s
?/p
9
>V
PS/
1
•*
NH>
STRIP
PER
Li
/YoS
••oMPOfto^
HYDROGEN
H2S
NH3
fyO
HYDROCARB
INERTS
TOTAL
SOUR
4
44
504
10
562
SOUR
289
1.381
4.654
433
6.757
HgSTRf
\ 4
504
508
CLEAN
FUEL
GZ5
289
4.654
4.943
HfSRtCH
1.425
18
443
1.886
SOUR
PiW
483
269
27.324
28.076
HyS TO
483
13
496
NHi TO
RJRNACE
269
17
286
RE-
y/wjp
27.294
27.294
PROCESS
. C nccill CIIBI7ATinU A hCMITOICirATinm
FIG. 5 I continued)
20
-------
and a molecular structure such as Tetralin) under ambient conditions of 1-3 psig
and 275°F and a solvent to coal ratio within the range 1.1 to 2.6. Adequate
residence time is provided in the dryers to dry the slurry to less than 4 wt.
percent moisture on a dry coal feed basis.
A.2.2 Coal Liquefaction
Coal liquefaction implies a radical upgrading in the H/C ratio and is
achieved by pumping the dried coal slurry to reaction pressure, mixing it with
hydrogen treat gas and heating the resultant mixture in the liquefaction slurry/
treat gas furnace. The mixture is then fed to the liquefaction non-catalytic
tubular reactors which operate at 8*»0°F and 2000 psig, where the coal lique-
faction and hydrogenation takes place in the presence of molecular hydrogen and
the hydrogen donor solvent. The reactor output stream is a mixture of gaseous,
liquid and solid products.
The reactor products are separated into vapor and slurry streams in the
liquefaction reactor separator. The vapor stream is cooled to 110°F to recover
condensible hydrocarbons, water and ammonia; hydrogen sulfide and carbon
dioxide are removed via water washing and scrubbing with diethanolamine. The
resulting gas stream consists mainly of hydrogen and is purged to control the
methane impurity level. Makeup hydrogen is then added and the treat gas is
compressed for recycle to the liquefaction, three phase reactor.
The liquid/solids stream and the condensate recovered from the gas stream
are fed to atmospheric and vacuum distillation towers where they are separated
into a number of cuts. The products include naphtha, low sulfur fuel oil (LSFO)
product, a spent solvent stream, and the vacuum bottoms slurry.
k.2.3 Solvent Hydrogenation
The purpose of the hydrogenation section is to regenerate catalytically
the depleted solvent from the liquefaction reaction and to separate the reaction
byproducts (gas and naphtha) from the solvent before it is recycled to the slurry
drier in the liquefaction section.
A series of fixed bed reactors are used with a nickelmolybdate catalyst.
The operating pressure is 1600 psig while the operating temperature is pro-
prietary information. Weight hourly space velocities range from 0.5 to 2.0.
Effluent from the solvent hydrogenation reaction is cooled and separated
into a hydrogen rich gas and a hydrotreated liquid stream. The gas is scrubbed
to recover ammonia and hydrogen sulfide, a purge is taken to control the methane
level, and the remaining gas, along with fresh make-up hydrogen, is recycled to
the solvent hydrogenation reactor. The purge gas is sent to the liquefaction
section for use as treat gas. Naphtha and a gas oil product is recovered from
the hydrotreated liquid in a solvent fractionator and the solvent is recycled to
the slurry dryers.
21
-------
k.2.k F1 exicoking
The two-fold purpose of the flexi-coker section is to convert vacuum
tower bottoms from the liquefaction section into additional liquid gas products and
to supply low-Btu gas (LBG) for the rest of the plant.
The bottoms are fed to the reactor vessel where they are pyrollzed to
form lighter boiling overhead materials and coke. These overhead materials are
cooled and scrubbed in the reactor scrubber section where a solids-laden heavy
recycle stream is condensed, withdrawn and recycled to the reactor. The scrubber
overhead is sent to the coker fractionator which separates the small amount of
coker naphtha from the heavy low-sulfur fuel oil and wash oil streams. The coker
gas, after recontacting, is treated for acid gas and nitrogen removal and then
sent on as steam-reformer feed.
The reactor coke is passed to a separate vessel where it is gasified with
steam and air to form low-Btu gas. After waste heat recovery, this gas is treated
for removal of particulates and hydrogen sulfide. The resulting fuel gas serves
to meet practically all the fuel requirements of the liquefaction plant.
if.2.5 Hydrogen Generation
Make-up hydrogen is primarily generated (seventy-seven percent) through
steam reforming of a methane-ethane mixture gas emanating from the flexicoker
section. The remaining twenty-three percent is provided by cryogenic purification
of purge gas.
Hydrogen is then compressed to the required pressures by 3 stages of re-
ciprocating compressors. In the first stage hydrogen is received from the reformer
plants and compressed to 635 psig. The output hydrogen from this stage is com-
bined with hydrogen from cryogenic recovery and compressed to 17*»0 psig (for
solvent hydrogenation) in the second stage, and to 18^5 psig in the third stage
(for coal liquefaction).
A.2.6 Product Upgrading
The products that are upgraded in this section are low-sulfur fuel oil
(LSFO) and process naptha. The LSFO meets specifications of 0.5 wt percent sulfur
and a flash point specification of 160°F. A conventional light ends system is
used to separate and treat the process naphtha into an ethane fraction (which is
sent to steam reforming as feed), liquid C, and C. LPG fractions and a
stabllzed CrAOO Naphtha.
k.2.7 Gas and Waste Water Treatment
Sour water from the various process sections is combined and fed to a
sour water stripping tower. Hydrogen sulfide and carbon dioxide are stripped
from the sour water and sent to a Claus sulfur plant with an ancillary tail gas
cleanup unit where 99.9 percent of the sulfur plant feed sulfur is recovered
and emissions are reduced to about 100 pprnw S02> The stripped water from the
22
-------
sour water treating is combined with the slurry dryer water and sent to a phenol
solvent extraction plant, where crude phenols are recovered. The effluent is
treated in a train consisting of dissolved air flotation, biological oxidation,
filtration and activated carbon. Some of the treated effluent is used as cooling
tower makeup, with the remainder being discharged.
Rich DEA from on site gas treating is fed to a DEA regeneration plant
where hydrogen sulfide and carbon dioxide are stripped and combined with the like
gases emanating from the sour water stripping and fed to the Claus sulfur plant.
4.2.8 Historical Development of the EDS Process
The EDS process bears similarity to the Pott-Broche process that was de-
veloped in Germany prior to World War II. Exxon's effort has been underway since
1966 and has reached the stage where the construction of a 250-tons/day pilot
plant is under way. The pilot plant construction costs are budgeted at $240
million with 50 percent of the financing coming from the U.S. Department of
Energy and 50 percent from industry. A preliminary cost estimate for the con-
struction of a commercial EDS process coal liquefaction plant is $1.4 billion (4).
Figure 6 is a schematic of the EDS process. Figure 7 gives the overall
mass balance data for the pilot plant (known as the Exxon Coal Liquefaction
Plant (ECLP) process).
The ECLP process differs from the EDS process in the following respects:
i) There is no flexicoker stage, thus there is no autogenous source of
low Btu gas (LBG). The ECLP produces 1,3^0 Ibs/hr of fuel gas of unspecified heat
content (see figure 6). Supplementary fuel gas needs are met through the purchase
of natural gas from local utility companies.
ii) Likewise there is no possibility of generating hydrogen through the
steam reforming of the methane/ethane gas that would be produced in the flexicoker
section. Some of the hydrogen process needs are met through the cryogenic purifi-
cation of purge gas; however, most of the process hydrogen is supplied by the
adjoining Baytown Refinery.
23
-------
NAPHTHA
SOLVENT
GAS 0
-------
ro
COAI4
13.99
MAKEUP HYDROGEN2
J.31
STEAM
724
PROCESS WATER
12.24
ECLP
AT
BAYTOWN. TEXAS
\
NAPHTHA1
203
NET SOLVENT
2.56
GAS OIL
0.11
FUEL GAS
1.31
RECYCLE GAS PURGES
1.57
WASTE GASES
1.59
SOUR WATER3
2369
VACUUM BOTTOMS
789
ATMOSPHERIC EMISSIONS
0.03
/. ALL FLOW RATES ARE IN THOUSANDS OF LBS./HR.
2. 95% HYDROGEN. 5% METHANE
2 INCLUDES EQUILIBRIUM AMOUNTS OF HYDROGEN
SULFIDE. AMMONIA. AND CARBON DIOXIDE
4. EQUIVALENT TO 239.5 ST/SD
FIG. 7 HOURLY MATERIAL BALANCE FOR THE ECLP
ILLINOIS #6 COAL
-------
Section 5
EVALUATION OF H-COAL CONTROL TECHNOLOGY
The control technology of the H-Coal pilot plant at Catlettsburg, Kentucky
is essentially designed on a two step basis; one at the plant site and the other
off-site. For a pilot plant, especially one located adjacent to a large oil refin-
ery, this is the most convenient way. However, to evaluate such a system, the pro-
cess must be analyzed as if it were independent. For the purpose of these evalu-
ations, the pilot plant as designed will be divided into several sub-sections
from which the most possible emissions would result. Some other emissions are
also expected as in-plant ones due to occasional spills, leaks and from trans-
fer operations. These will be dealt with in some detail at a later stage under
Assessment.
As has been pointed out in the Introduction, the emissions from the pilot
plant will be quantified and characterized first; then an extrapolation is made of
the emissions from a commercial plant, followed by a thorough evaluation of the
consequences.
5.1 PILOT PLANT EMISSIONS
Process Systems Diagrams are formed by combining several process steps
to form a system which has mass and energy flows as inputs and similar streams
as outputs. Thus the system can be represented by means of a rectangular box
with inputs entering the box and outputs leaving the box. These boxes can also
be considered as modules whose function will remain the same in the commercial
plant as in the pilot plant; only the sizes (of the box as well as of the streams)
vary. This has an advantage in assessing the economics because it is then only a
matter of scaling up. The systems, therefore, to be considered are:
1. Coal handling and preparation
2. Reaction and primary separations
3. Sour water and gas treatment
4. Waste water treatment
5. Waste solids treatment
6. Catalyst handling
26
-------
We shall formulate the process system and represent the streams for these groups
of process steps in the following sections.
5.1.1 Coal Handling & Preparation
5.1.1.1 Process Description: The coal is received either in railroad cars
(60-100 tons capaci ty) or i n rear dump trucks (30-50 tons capacity). The re-
ceiving station consists essentially of rows of hoppers into which the coal is
unloaded. From these hoppers the coal is fed to a conveyor belt which discharges
into a chute. The chute discharges either of two conveyor belts which dump the
coal into two piles of approximately 600 tons of capacity.
The dust control system consists of hoods connected to air ducts leading
to a dust collector of the baghouse type. The total air handled by the hopper
dust collector is about 8^,500 SCFM and the final discharge is into the atmosphere.
Unless 100 percent collector efficiency is assured, this will constitute a point
source of particulate emission.
The coal from the piles is taken out by means of front end loaders
(about k cu. yards per lift) and charged into the reclaim hopper of about 25 tons
holding capacity. From this hopper it is fed onto a belt conveyor which discharges
the coal into a primary crusher where it is reduced to about 3A" size. The
crushed coal from the primary crusher is conveyed by means of belts into crushed
coal storage bins (there are two). All the belt conveyors and bins are hooded
and the air carrying the dust is handled through a dust collector finally discharg-
ing into the atmosphere. The approximate coal flow is about 208 tons/hour and the
air flow is about 6,550 SCFM.
The crushed coal from the storage bins is transferred to a dryer feed bin
(approximate capacity 9 tons) from which it is charged into the Raymond Bowl mill.
Hot flue gases from the air heater sweep through the bowl mill carrying the coal
dust to a cyclone, the underflow from which is dried pulverized coal (2 percent
moisture and 90 percent minus 200 mesh), and sent to dry coal storage. The cyclone
discharge goes into a final dust collector and from there into the atmosphere.
The dry coal from the cyclone is transferred by means of screw con-
veyors into two bins from which another screw conveyor located at the bottom
charges the coal to a weigh feeder. This is a belt type with weight totalizers
controlling the exact amount of coal charged to the slurry preparation tank.
This is essentially a sealed system with vents equipped with filters.
The process system is represented in Figure 8 as a block diagram with
the material balance chart showing the streams and their concentrations. There
are essentially five input streams into the module and four output streams from
the module.
5.1.1.2 Sources of Emissions: The following possible sources of emissions can
be identified.
27
-------
ro
oo
f , — .
r l
} *l
Y »
\
COAL
RECEIVING
1
AIR
HEATER
t
r
•
RAW COAL
STORAGE
PRIMARY
CRUSHING
-/
CRUSHED
COAL
STORAGE
OR
COA
STOF
y
L
tAGE
CYCLONE
1
j ,
BOV
VL
MILL
.1
•\
^i
m\
i
^-^SW£4A#
C/i4/f!4C7E/?''^->-^
FLOW RATE
STATE
CONC. POLLUT.
SOLIDS
LIQUIDS
GASES
UMTS
lb/hr
mg/ltr
rtg/ltr
ppm
RAM
FALL
IQOOO
UQ.
TRACE
RAW
COAL
70.843
SOLID
AIR
HOODS
441.300
GAS
MAKEUP
W
17.265
GAS
FUEL
DRY
COAL
60.160
SOLID
AIR
«E
27.948
GAS
COAL
mooo
UQ.
J180
AIRFROM
fftWft
441.300
0.2*
FIG. a COAL HANDLING
-------
J.) Coal pile run off, resulting from an exposed coal pile being
leached by weather precipitation. The design calls for containment of this runoff
by collecting it and pumping to water treatment section. Eventually the treated
and cleaned runoff is discharged into the river. The actual quantity of this
runoff is very much weather dependant, but is estimated to be equivalent to a flow
of 20-25 gpm. The composition of this leachate, however, has not been determined.
2.) Particulate or dust emissions from the coal handling system. Al-
though most conveyors, belts and hoppers are hooded and the exhaust treated by
means of filters and dust collectors, a certain amount escapes into the atmosphere,
This can be estimated as
particulates
di scharged
emissions \
from I
handling I
col lector
1 -effi ciency
100
This is the amount that enters the environment and distributes into the surround-
ings. The concentrations resulting from this particulte emission can then be
calculated and compared with the standards.
1 1 1 JJU U
(particulates
amount £ size)
Stochastic Model
or
Deterministic Model
1 Concent ration
1 1 n y g/m3 I
Approximately 60,000 Ib/hr are handled. Assuming 0.3 percent of this
goes as dust in the handling air and the dust collector efficiency of 99.9 percent,
the final emission rate will be 60,000 x 0^3 (1 . 0>999) = QJ8 ,b/hr> Tne flow
sheet indicates this quantity as 0.2 Ib/hr).
3.) The flue gases used to heat the air in the air heater are finally
discharged into the atmosphere. Their acceptability depends upon the fuel used
to generate them and its composition. At this time, these are considered clean
fuels and thus essentially non-polluting.
5.1.1.3 Character of Emissions:
properties^ the same as coal.
is acidic, but its composition is undetermined.
Coal particulates can be assumed to have average
TToal pile run off probably contains phenols and
-------
5.1.2 Reaction and Primary Separations
5.1-2.1 Process Description: The process system is shown in Figure 9 as a block
diagram together with material balances. For this modular section of reaction
and primary separations, there are three principal input streams and four output
streams. The waste heat recovery system has an additional input and output stream
each, but these are same chemically, as well as flow rate-wise, (^ater converting
to steam) .
Dry coal from the weigh feeders is charged to the slurry tank at an
average rate of about 45,000 ?b/hr where it is sJurried with recycle oil of about
100,000 Ib/hr and the slurry is pumped under pressure (3000 psi) with some re-
cycle gas through a feed heater where it is heated to about 750°F. This hot
slurry along with some more heated recycle gas enters the reactor at the bottom.
Ebullating pumps provide for the mixing and uniform temperature distribution in the
reactor. The reactor effluent consisting of a three phase mixture of vapor,
liquid and solid, is first separated into two fractions, the vapor phase and the
solid-liquid phase. The vapor phase is cooled in a waste heat boiler producing
process steam. The vapors are further cooled by injecting water and separating
the liquid phases. The gases are then scrubbed in an absorber by means of lean
oil to remove the lower molecular weight hydrocarbons, and the gases containing
predominantly hydrogen (about 82 percent by volume) are compressed and recycled.
The stripped gases from the absorbent lean oil are sent for gas treatment to
remove hydrogen sulfide.
The solid-liquid phase is flashed in a series of drums and the vapors
resulting1 from the decompression are mixed with the vapors for treatment described
above. The liquid-solid mixture is separated by a system of hydroclones and the
overflow from these is sent as recycle oil while the underflow is separated for
its solids in an ant i -sol vent process. The liquid is sent for fractional ion and
solids are sent for bagging and disposed as land fill.
5.1.2.2 Sources of Emissions: The emissions from this section of the process
are the flue gases from the various heaters, and any leaks from valves, or due to
accidents and ruptures so there is no need to quantify them here. However, there
are effluent streams: gaseous, liquid and sol id, which are to be treated. These
are:
Name Quant i ty Character
Solids residue 13,970 Ib/hr Contains ash, unconverted
(0.3 Ib/lb of coal) carbon & heavy hydrocarbons
Fuel gas 6,760 Ib/hr Contains hydrogen sulftde
(0.15 Ib/lb of coal) (10.8 mol percent)
Sour water 24,600 Ib/hr Contains H S, NH (NH.) 2S,
(0.5A Ib/lb of coal) phenols 6 other Iromatics
30
-------
r — ••• —
> r
/
k
>
>
_.
COAL
SLURRY
PREP.
PRIt*
DISTt
TIOt\
1 ,
1ARY
II 1 A.
LLA
/s
HYDl
GEN,
REA
•
W-
4T/OA
CTOR
HYDRO-
CLONE S&
SOLID/UQ
3ER4/M7/OS
|
»
EFFLUEN1
SEP-
ARATOR
FLASH
SYSTEM
WASTE
HEAT
REC.
ABSORBER
SYSTEM
.rr
^^^7ff£4Af
CHXl«4C^/?^-^
FLOW RATE
STATE
CONC. POLLUT.
SOLIDS
LIQUIDS
GASES
UNITS
Ib/hr
mg/ltr
mg/ltr
ppm
MAKEUP
HYDROGB\
2.387
GAS
COAL
FEED
45.153
SOLID
^ROCESS
WATER
& STEAM
20.571
LIQ.
FEED
FOR
FRACT.
22. 787
LIQ.
SOLIDS
&
£E5M&
13.970
SOLID
FUEL
GAS
7.319
GAS
SOUR
WATER
26.597
LIQ.
STEAM
40.000
GAS
BOILER
FEED
WATER
40.000
LIQ.
FIG 9 REACTION & PRIMARY SEPARA TIONS
-------
5.1.3 Sour Water and Gas Treatment
5.1.3.1 Process Description: The process system is shown in Figure 10 with the
material balance also shown. There are only three input streams to this module:
two gases and one sour water, and five output streams.
During the hydrogenation reaction, the oxygen in the coal is partly
hydrogenated to water and the nitrogen to ammonia. Some of the oxygen appears In
oxyhydro-carbons (phenols, etc.) and some of the nitrogen goes into forming
pyridine, piccolines, etc., which are water soluble to a large extent. In
addition to the water formed in the process, water Is injected for cooling pur-
poses at several points. All of these combined streams form the aqueous layer,
which contains all the above mentioned substances plus hydrogen sulfide and
ammonia. This is the sour water that has to be treated either for recovery of
these substances or their suitable modification in an environmentally acceptable
way. Recovery of some of these streams, such as H S and NH-, is done by steam
stripping the sour water under two different pressures at two different tempera-
tures. The first stripper operates at 88 psi and 300°F where all the NH and the
remaining H S are driven off. These vapors are passed through an absorber with
a partial reflux condenser operating at 39 psi and 16^°F where all the H.S is re-
tained in the liquid phase and NH flows out as vapor. The bottoms from this
absorber are mixed with feed to the first stripper while the bottoms from the
second stripper are used as reflux for the first. The stripped sour water con-
taining sulfides, phenols, and other solubles is collected in a tank and partly
recycled; the other part is sent to waste water treatment.
The fuel gas coming from the lean oil absorbers as well as the various
vents contains H.S in appreciable amounts; 10.8: mol percent in fuel gas and
3.8 mol percent in vent gas. This removal of H.S or desulfurization, as it Is
called, is achieved by washing these gases with a suitable alkaline organic
like diethanolamine (DEA) in separate absorbers, one for vent gases and another
for fuel gas operating at a much higher pressure. The off gases from the vent
gas absorber are sent for flaring and the fuel gas to the pipeline. The DEA
solution containing the H S is stripped, driving off the H_S, which is sent to
Claus units for partial oxidation at the adjacent refinery.
5.1.3.2 Sources of Emissions; The only stream that enters the atmosphere direct-
ly is the^flare which contains primarily C02 and H.O. Sometimes traces of H S
may escape into the flare gas resulting in small quantities of SO.. However, thls
is so small and infrequent that it cannot be quantified. The ammonia from the
second stripper of the sour water treatment or the denitrif feat ion step Is sent
into a boiler furnace and burned to N and HO.
The effluent stream of sour water is partly recycled and partly sent to
the waste water treatment plant. It contains a variety of dissolved substances.
For example the unstripped foul water has been characterized by AWARE, Inc., as
given in Table 1. After stripping, it can be assumed that only ammonia and su1fi
-------
1 —
1
1
1
s 1 ,
r »~~^
1
\ 1
) 1
1
i 1 r
* 1
1
1
L_
VENJ
4BSOi
\
\
i
H.P..
WATL
STRIF
\
GAS
RBER
SOW
•R
*PER
FUEL
4BS0
L
.GAS
RBEK
>-
LP <
WAT
STRU
>OUR
ER
°PER
— »
STf\
PE
i
UP-
R
H2S
ABSO-
RBER
\
CLAUS
UNITS
(NOTED
A*
pr
TC
(N
\
1MONIA
CO VERY
OTE1)
»t
I '
1
1 /
1 >
1
i
t *
1
• rt
| \
1
1
_J
(NOTE ) NOT INCLUDED IN THE PILOT PLANT.)
8
^^^S7Wf4M
CH4/MC7E^-^
FLOW RATE
STATE
CONC. POLLUT
SOLIDS
LIQUIDS
GASES
OTHER
UNITS
(b/hr
ng/ttr
•ng/ltr
ppm
SOUR
VENT
G4S
562
GAS
384*
SOUR
FUEL
GAS
5757
GAS
10.78*
SOUR
WATER
28.076
LIQ
STRIPPED
SOUR
WATER
27.294
LIQ.
AMMONIA
286
GAS
SULFUR
USB
SOLID
CLEAN
FUEL
GAS
4.945
GAS
FLARE
508
GAS
*MOL
FIG. 10 DESULFURIZATION * DEMTRIFICA TION.
-------
TABLE 1
H-COAL PROCESS
INITIAL UNSTRIPPED FOUL WATER
CHARACTERISTICS (1*0
Parameter
COD (%)
Phenol
Ammonia (%)
Organic nitrogen
Sulfide ft)
Oil and grease
Total sol ids
Dissolved sol ids
Suspended sol ids
Volatile suspended solids
pH (pH units)
Phosphate
Cyan i de
Cr
Cd
Fe
Pb
Al
Cu
Mg
Ni
S0*t
Ca
V
Ti
Na
Ho
Co
Ib/hr
78.3
0.51
0.334
26.9
26.9
.2
.02
0.0037
0.01
0.008
0.012
0.029
0.025
0.004
0.007
0.017
24.2
0.043
0.105
0.014
Concentration
35.7
7,830
2.8
51
11.8
33.4
2,690
2,690
20
nil
10.8
2.1
3.7
0.1
0.8
1.2
2.9
2.5
0.4
0.7
1.7
252
4.3
1.0
1.0
10.5
0.5
1.4
a. Composite sample.
b. Concentration shown in mg/1, unless otherwise designated,
34
-------
effluent stream will have the characteristics given in Table 1 as Ib/hr.
5.1.4 Waste Water Treatment
The process schematic is shown in Figure 11.
5.1.^.1 Process Descrlption: The process design parameters were based on the
results of trie characterization and bench-scale investigations reported in
reference No. 14. Influent flow and temperature information was supplied by
HRI-Engineer!ng and Ashland Oil. The basic process flow sequence was developed
by AWARE through discussions with HRI-Engineering and Ashland Oil. In this
section design parameters for the individual unit processes are presented. The
design was developed to treat the waste water anticipated from the H-Coal pilot
plant. The H-Coal pilot facility is being designed for a 2-year operation. Since
this is a pilot facility, it is being designed for an on-stream factor of 50
percent. The H-Coal facility will be operated under a wide range of conditions.
Several types of coal will be processed and operating parameters will be varied
to obtain various petroleum products. The resulting process related waste waters
are anticipated to vary, depending on the operational mode employed.
The design information developed as a result of the experimental in-
vestigations can be considered to be applicable to the process waste waters fro,,.
the pilot plant, provided that:
1. The raw process waste water does not deviate significantly from the
unstripped process waste water samples received from the process de-
velopment unit.
2. The raw stripped waste water must contain only enough nitrogen to
achieve biological treatment of the organic components. The
maximum stripped process waste water sulfide concentration cannot
exceed 50 mg/1 , otherwise the potential for biological inhibition
will be present. No significant change in the foul water organic
strength can occur due to the foul water stripper.
The process design was developed recognizing that differences may exist
in the process waste water produced by the PDU and those anticipated from the pilot
plant. Since these differences cannot be completely identified at the present
time, it is necessary to base parts of the design on judgemental factors. Operat-
ing flexibilities have been integrated into the design in an attempt to accommodate
these differences and the frequent shutdown periods anticipated. Additional flexi-
bility has been included for evaluating various process arrangements necessitated
by the need to design treatment facilities for subsequent commercial size H-Coal
plants.
As a result of the experimental investigations performed and discussions
between HRI-Engineering, Ashland Oil, and AWARE, the following decisions were made
regarding the waste water treatment plant design (14):
35
-------
COOLING
TOWER
BLOW DOWN
BOILER
BLOW
DOWN
EQUALIZED
COAL PILE
RUN OFF
FLOCCULATOfi - T"\
70
PRIMARY
CLARIFIER
JrtxJ—
AERATION/
CLARIFIER
AIR FLOTA-
TION UNIT
EQUAL-
IZED
OILY __,
RUNOFAWATER
RIVER DISCHARGE
UP0
SLUDGE
\FILTER
CAKE
TO DISPOSAL
PROCES
WASTE
API
SEPARATOR
NUTRIENTS
PH ADJUST.
EQUALIZATION,
BASIN
1.660
\^7ffi£>IAf
WATER
SOLIDS
TOTAL
COOLING
TOWER
SLOWDOWN
25.000
25,000
BOILER
BLOW
DOWN
5500
5500
COAL PILE
RUNOFF
/2.500™,
12500
OILY
RUN OFF
15.000^,
/5000
PROCESS
WASTE
WATER
10.000
10.000
CLEAN
VATER FOR
DISCHARGE
68.198
68.198
CAKE
FOR
DISPOSAL
1.678
1.678
FIQ.I I WATER TREATMENT PROCESS SCHEMATIC.
-------
1. The process waste water and the non-process waste waters (oily water
runoff, coal pile runoff, boiler blowdown, and the cooling tower
blowdown) are to be combined prior to biological treatment. The
non-process waste waters will provide dilution of the concentrated
process waste streams.
2. The process waste water will be stripped to reduce the ammonia and
sulfide concentrations to those levels compatible with an activated
sludge system designed to treat organic materials. The organic
strength of the foul water will not be significantly altered by
stri ppi ng.
3. The oily water runoff and the stripped process waste water will
be combined and pretreated to reduce the waste water oil and grease.
An emulsion-breaking system is to be included to handle possible
emulsions resulting from the combined process waste water and
oily water runoff streams.
4. Floated oil removed from the surface of the API separator will be
discharged to the light slop oil system. The API separator
bottoms will be combined with the aerobically digested waste
activated sludge prior to pressure filtration.
5. The cooling tower blowdown is to be pretreated for chromium re-
duction prior to biological treatment. An electro-chemical chromate
reduction unit will be used followed by pH adjustment, flocculation,
and clarification. The metal hydroxide sludge removed by clarifica-
tion will be combined with the aerobically digested waste activated
sludge prior to pressure filtration.
6. The coal pile runoff and oily water runoff are to be equalized prior
to entering the treatment system.
7. Equalization facilities are to be provided to minimize the potential
for treatment plant upsets or inconsistent operation, since the
variability of the process waste water to be generated by the H-Coal
pilot plant is unknown.
8. Storage facilities are to be installed to provide feed necessary to
maintain an acclimated sludge in the biological treatment system
during extended pilot plant shutdowns.
9. The combined waste water from the equalization basin is to be pre-
treated to reduce the oil and grease content using an induced air flo-
tation unit. The induced air unit skimmings are to be combined with
the aerobically digested waste activated sludge prior to pressure
fi11rat ion.
10. Biological treatment will consist of a single-stage activated sludge
system. The system will be designed to ensure reasonable operating
37
-------
flexibility. Effluent from the biological system will be combined
with the treated sanitary waste water and runoff from uncontaminated
plant areas prior to discharge to the Big Sandy River.
II. To conserve heat, a submerged aeration system will be employed.
During the winter operating months, the cooling tower blowdown
will be discharged from the hotter side of the cooling tower.
During the summer months, the blowdown will be discharged from the
cooler side.
12. Waste activated sludge will be thickened using a gravity thickener.
The thickened sludge will be stabilized in an aerobic digester.
13. Aerobically digested waste activated sludge will be combined with
the API separator bottom sludge, the metal hydroxide sludge from
the cooling tower blowdown pretreatment system, and the skimmings
from the induced air flotation unit. The combined sludge will be
chemically conditioned and dewatered using a pressure filter
operated at 225 psig. The dewatered cake will be landfilled.
The characteristics of the individual and combined H-Coal waste waters
are presented in Table 2.
Other significant waste water constituents not enumerated in Table 2,
but anticipated to be Included in the discharge permit are oil and grease and
ammonia nitrogen. For the purpose of calculating the combined raw waste water
load, an oil and grease concentration of 80 mg/1 was selected based on measurements
during the laboratory simulation and differences anticipated in the pilot plant.
The unstripped foul water will have an ammonia nitrogen concentration of 21,200
mg/1, which will all be stripped prior to biological treatment.
A summary of the combined raw waste water load, the design effluent
criteria and the recommended discharge limitation are given in Table 3. The steady-
state effluent levels were used as the basis on which to transmit the treatability
data into the process design. However, for the experimental reactors operated at
the same conditions under which the steady-state criteria are achieved, the
variability in influent waste load, temperature, and composition observed during
the treatability phase of this investigation were felt to be similar to that
variability which would be experienced in the pilot plant.
5.1.5 Waste Solids Treatment
5.1.5.1 Process Description; Waste solids or solid products with no current
market value are produced in the H-Coal process in two operations. One, when the
hydroclone underflow is solvent deashed separating the solids and the liquids. The
solids contain coal ash, unconverted carbon and heavy hydrocarbons. The other
source of solids for disposal is the vacuum tower bottoms which are solidified and
sent for disposal as land fill. The hot residue from the vacuum tower bottom is
partially separated into liquid and solid fractions and the solid fraction, still
38
-------
TABLE 2
CHARACTERISTICS OF INDIVIDUAL
WASTESTREAMS 04)
Winter
Sumner
Was test ream
Flow SS COD BOD8 Phenol" Temp
(gpm) (Ib/day) (Ib/day) (Ib/day) (Ib/day) fF)
Flow SS COD BOD* Phenol0 Temp
(gpm) (Ib/day) (Ib/day) (Ib/day) {Ib/day) (°F)
Process Wastestream
Foul Water Stripped 15.5
Stream 52 0.8
Stream 50 3.7
Von Process Wastestream
Cooling Tower Blowdown .50
Boiler Blowdown 10.5
Coal Pile Runoff 20
Oily Water Runoff 14
Combined Total 115
*Based on the correlation of the
K ._.
4 4.
5
2
2
2
155
JSP.
210 5,
wastewater
935
40
15
5
10
60
Ji -
090 3,180
total and COO
.
-
-
.
_
.
.11"-
1,180
developed
90
90
• 90
100
212
33
33
15.5
0.8
3.7
50
10.5
25
.30
136
during this
4
5
2
2
.2
195
-90
300
4,935
40 -
15
.5
TO
75
_5i :_ __r_
5,136 3,210 1.190
Investigation; BOOy • 0.66 CODj •
110
110
no
85
212
75
-Zi
- 180.
^Based on the BOO/Phenol correlation developed during this Investigation; Phenol • 0.37 BOOT.
cHot side blowdown 1n the winter; cold side blowdown In the summer.
-------
TABLE 3
SUMMARY OF RAW WASTE LOAD, DESIGN, AND DISCHARGE CRITERIA
.e-
o
Effluent (Ib/day)
Raw waste loading Design steady-state Recommended discharge
(Ib/day) r.t«.--«~d limitation
Flow, mgd
BODT
Phenol
Suspended sol ids
Oil and grease
Ammon i a-n i trogen
Unstrippedb
Stripped0
Winter
0.165
3,180
1,180
210
110a
3,950
0
Summer
0.195
3,210
1,190
300
130a
3,950
0
30-Day avg. Max.
_-
82 180 360
1.6 10.8 21.6
82 2^2 k8k
25 2k l»8
16 16.3 32.6
An oil and grease concentration of 80 mg/1 assumed.
Ammonia nitrogen present in the process wastewater prior to pretreatment by steam stripper.
cAmmonia nitrogen present in the combined wastewater prior to biological treatment following steam
stripping.
Steady-state criteria based on results achieved during steady-state operation of bench-scale units,
This effluent level will not be achieved in the pilot facility due to the anticipated variability
associated with the H-Coal process and the manner in which the pilot plant will be operated.
-------
a fluid, is discharged onto a belt cooled with water sprays. As the belt cools the
solidified material is chipped off the belt and transported to a silo from which it
is bagged and trucked out for landfill purposes. The equipment and operation have to
be tested and experimented for suitable operation and optimum conditions. The tentative
operating conditions, however, call for a feed capacity of 6700 Ib/hr. at a belt speed
of about 160 fpm. Feed inlet temperature is about 590°F and the cake discharges
at l^O^F. Cooling water rates are about 255 gpm under spray and about 20 gpm above
the belt.
5.1.5.2 Emiss ions: As the mass cools, certain amount of vapors evolve and these
are collected and condensed. The liquid is recycled into the system. The exhaust
still may contain traces of hydrocarbons, perhaps harmless, but will be very odorous.
The cake itself contains a variety of heavy aromatics. The expected flow rate of
vacuum tower bottoms is about 15,300 Ib/hr.
5.1.6 Catalyst Handling
5.1.6.1 Process Description: In order to maintain a certain catalyst activity,
the catalyst in the pilot plant is periodically withdrawn and replenished with fresh
catalyst. The operation is designed as batchwlse and manual. A slip stream from
the reactor is taken out at given intervals and discharged into one of two tanks.
The slurry is then filtered and the solid spent catalyst is disposed. Fresh
catalyst is added from the top of the reactor via a system of hoppers and feed tanks.
Potential source of emission is the solid spent catalyst containing heavy
hydrocarbons and coal deposit on the catalyst. The ultimate fate of this spent
catalyst is not well defined. At an approximate ratio of 1 Ib of catalyst per
ton of coal the quantity of spent catalyst produced will be about 600 Ib/day.
5.2 CONTROL TECHNOLOGY FOR THE PILOT PLANT
As has already been pointed out, the pilot plant is not an integrated
operation, but is located adjacent to a large oil refinery and is supported by it.
Of the three principal effluents from the pilot plant, the gaseous streams con-
taining H S are combined and sent to the refinery for treatment. Another gas
stream containing ammonia is sent to the boiler furnace and burned to yield N
and H_0 as combustion products.
The liquid waste streams consisting of process waste water, cooling
tower blowdown and coal pile run-off, are all combined in an equalization tank
and treated in a series of steps as described in the previous section. The sludge
from this treatment in the pilot plant is disposed of as landfill.
The solid wastes from the pilot plant emanate from three process units:
1) the Lummus anti-solvent deashing system; 2) the cooled vacuum tower
bottoms; and 3) the spent catalyst. The nature of all these three wastes is that
they contain heavy, coal-derived, carbon compounds in addition to the inorganic
compounds present in the coal ash. At the present time, the process design of the
-------
pilot plant calls for disposal of these wastes only as landfill. This method is
based on some tests carried out on these materials for their leachabi1ity. The
appear not to be leachable. However, it is believed that the spent catalyst can b
regenerated and the vacuum tower bottoms can be used to produce hydrogen in a *
gasifier of the Texaco type.
5.3 ANALYSIS OF THE PILOT PLANT CONTROL TECHNOLOGY
Since the mission of the pilot plant is to establish the technology of
coal conversion and prove the process, the principal emphasis is naturally on
the process itself. That is, the emphasis is predominantly upon studies con-
cerning the reaction, product separations, catalyst life, etc. As regards the
control technology, it is usually assumed to be off-the-shelf type and even pre-
sumed proven.
In these pilot plants, accordingly, there is little control technology
per se because all the effluent streams are channeled to the adjacent refinery
where they are probably mixed with those of the refinery and treated. While it
is difficult to analyze a situation like that, it still shows that these wastes
are treatable and the treatment is similar to the practice existing in petroleum
refineries at the present time.
On the other hand, because of the nature of the operation and the
objectives, the pilot plant operation may be more often in an unsteady state
than in a steady state. Under these conditions the characterization of the
effluents and emissions becomes very difficult. Also, the control technology,
whatever it is, demonstrates an erratic mode of operation rendering any analysis
very problematic.
5.4 EMISSIONS FROM COMMERCIAL PLANT
Any scaling up of pilot plant information to commercial plant size
involves several judgments. These depend upon the nature of information
available on the item that is to be scaled up. In the case of coal 1iquefacation
plants it is rendered more complex because the raw material characteristics (coal
properties) are not uniform. For purposes of estimating emissions, however, a
linear scaling up of the quantities should suffice. Furthermore, as has been men-
tioned In Section 5.1, the process systems will also be the same as in the case of
the pilot plant except for three more added systems for hydrogen manufacture, power
and utilities, and oxygen plant. These will be considered along with the six
analyzed for the pilot plant.
The overall material balance for a conceptual commercial H-Coal plant of
25,000 tons of coal per day is shown in Figure 12. This is shown only for one
mode of operation, namely the fuel oil mode using Illinois #6 coal.
-------
CO/1/.
25000 (625)
HYDROGEN
1.321 (135)
(FOR CLAUS)
H-COAL
PLANT
TPD)
FUEL GASES1
2,943 035)
NAPHTHA
1.961 (78.4)
WATER
2.909
FUEL OIL
10.213 U08J5)
SOLIDS2
7.735 (232)
SULFUR
993 (7.9)
AMMONIA
158 (3.1)
1. TONS PER DAY. THE NUMBERS IN
( ) REPRESENT BTU'S IN BILLIONS.
2. CAN BE USED TO PRODUCE HYDROGEN.
FIG. 12 OVERALL MATERIAL BALANCE:
FUEL OIL MODE OF OPERATION
ILLINOIS »6 COAL.
-------
5.A.I Coal Handling and Preparation
Assuming the process steps are similar to those in the pilot plant
for this throughput of coal, the process system is shown in Figure 13 with a
material balance chart showing the emissions.
5.4.1.1 Principal Emissions: The principal emissions from this section of the
process are:
1. Particulates, at an estimated rate of 3.2 Ib/hr with properties
closely resembling those of the parent coal.
2. Coal pile runoff estimated to be equivalent to 1150 gpm. The
character of this effluent Is similar to leachates of washing
operations containing phenols and other soluble hydrocarbon
compounds and can be very low in pH.
3. Flue gases used to heat the air for drying in the pulverizers.
This is essentially flue gas derived from clean fuels and hence
non-polluting.
4. Spills and fugitive emissions which cannot be characterized or
quantified. These have to be considered only on a case by case
basis.
5.A.2 Reaction and Primary Separations
Process description and the unit steps involved are about the same
as described in Subsection 5.1 for the pilot plant. The process system and the
material stream flows are shown in Figure 14.
5.4.2.1 principal Emissions; The principal emissions are as follows:
1. The solid residue from antisol vent deashing system and the vacuum
tower bottoms which contain ash, unconverted carbon and heavy
hydrocarbons. The estimated rate of output of this residue is about
322 tons per hour. However, this residue will be used partly to
produce hydrogen and to recover the heating value as needed in the
process so that ultimately the solids that go for disposal are only
the ash content of the coal. The final quantity of this waste stream |s
about 110 tons per hour and it has the same properties as that of
ash from conventional coal burning installations.
2. Spent catalyst is another solid effluent stream from this section.
The amount of this stream is approximately I.0 ton/hr with 52 percent
of the solids consisting of cobalt-molybendum catalyst. The current
methods of recovering or regenerating these metals from the spent
catalyst are vague and undefined. Research is, however, being
carried out by at least one catalyst manufacturer towards regenerating
44
-------
/"
/ '
I
cox
RECB
\L
IVINL
AIR
HEATER
' 1
1
\ '
RAW COAL
STORAGE
PRIMARY
CRUSHING
CRUSHED
COAL
STORAGE
DRY
COAL
STORAGE
CYCLONE
*
,
BOWL
\
MILL
•
r(
i ^
-J
^\SflipM
DH>a/?>acrf^^^^
FLOW RATE
STATE
CONC. POLLUT.
SOL/DS
LIQUIDS
GASES
UNITS
tph
-ng/ltr
my/ltr
ppm
RAIN
FALL
230
LIQ
TRACE
RAW
COAL
1,634
SOLID
AIR
FOR
HOODS
10.177
GAS
MAKE UP
AIR FOR
DRYING
398
GAS
FUEL
DRY
COAL
1387
SOLID
AIR
FROM
CV 'CLONE
644
GAS
COAL
PILE
RUNOFF
230
LIQ
1180
AIR FROM
DUST COL-
LECTORS
10,177
GAS
9.2*
FIG 13 COAL HANDLING
-------
f
v r
'
*,
>
)
'
I
L
COAL
SLURRY
PREP.
I
PRIMARY
DISTILLA-
TIONS
— —
»•
(
HYDRO-
GEN ATlOt
REACTOR
|
HYDRO-
CLONE S&
SOLID/LIQ.
SEPARATE
>
EFFLUEM
$EP-
FLASH
SYSTEM
\
HEAT
REC.
ABSORBER
SYSTEM
"]
1
1 j
1
I J
\ V
1
i
i J
\ >
! ./
- ^ i v
. , , j
^*--^SJ9E4/W
CHAR/CTF& ^
FLOW RATE
STATE
CONC. POLLUl
SOLIDS
LIQUIDS
GASES
UMTS
fph
mg/ltr
mg/itr
ppm
MAKEUP
WDROGto
55.0
GAS
COAL
FEED
1041
SOLID
PROCESS
WATER
&STEAM
474
L/Q
FEED
FOR
FRACT.
525
L/0
sa/Ds
RFSIDS
322
SOLID
FUEL
GAS
169
GAS
SOUR
WATER
554
LIQ
STEAM
922
-.
BOILER
FEED
VATER
922
FIG. M REACTION * PRIMARY SEPARATIONS
-------
the catalyst for reuse. No specific data or technology is yet
available. Therefore, this spent catalyst disposal must be con-
sidered as a waste, and so treated. One such system can be con-
ceived as first extracting the catalyst with a solvent followed by
washing and then drying the residue. The dried spent catalyst can
be sold for its metal value. The recovered hydrocarbons and the
solvent can be recycled into the system.
Desul furi zat ion and Den it ri f cat ion
The unit process steps are essentially the same as described in
Section 5-1 and consist primarily of absorption and stripping in case of fuel gas
streams and only stripping in case of sour water streams. The process schematic
and effluent streams are shown in Figure 15. The hydrogen sulfide-rich gases are
sent to Claus units for partial oxidation to elemental sulfur. The tail gases,
however, must be treated to meet the existing environmental standards. The con-
trol technology for this treatment is discussed in detail in Section 7- It is
sufficient to mention here that this technology is not only proven but also is wide-
ly accepted and so must be considered as off-the-shelf. Only the size of the
system of Claus units followed by tail gas treatment are somewhat larger than
normally employed units. The system must be capable of handling about 28 million
SCFD of rich (about 80 percent) H S gas.
The principal emissions are:
1. The combusted products from flares which containonly C0_, HO
and traces of SO- and particulates (as soot) in amounts of about 60 tons/hour.
2. Sulfur and ammonia as products in the amounts of 1,000 and 150
tons/day of each.
3. Stripped sour water at a rate of about 2,500 gpm of which approxi-
mately two-thirds can be reused without any treatment. The other one-third is
sent to waste water treatment.
$,k.k Waste Water Treatment
The waste water treatment designed for the pilot plant was discussed
in Section 5 -1 •** • 'n the case of water treatment plants, scaling-up from pilot
plant data is not the best procedure, but in the absence of anything else, this
is acceptable. Such a scaled-up plant with flow rates and the conceptual process
schematics are shown in Figure 16. The figure is self explanatory and the two
effluent streams are: 1) clean water for discharge into river at about 6,250
gpm and 2) the solid cake for disposal at a rate of about 40 tons/hour. The
method of disposal of this solid waste is only as fill material at this time.
5.4.5 Hydrogen Production
The hydrogen required for hydrogenat ion is planned to be produced from
the solids fraction of the LUMMUS-System and the solidified vacuum tower bottoms.
47
-------
oo
1
1
1
1
r \ '
1
1 !
i
i
i
L.
VEN1
4850
1
1
'GAS
RflEfl
-
H.P.SOUF
WATER
STRIPPER
i
p
FUEL GAS
ABSORBER
u
L P. SOUR
WATER
STRIPPER
r
STRIP-
PER
1
H2S
ABSO-
RBER
1
a
I/A
.AUS
//rs
|
AMMONIA
RECOVERY
'V
i J
\ v
1
1 t
1 >
1
i
1
1 _j
1
1
.J
fi) (D
(8)
-^W£4M
:HARACTE$° — ^
FLOW RATE
STATE
CONC. POLLUT.
SOLIDS
LIQUIDS
GASES
OTHER
UNITS
tph
mg/ltr
mgrttr
ppm
SOUR
VENT
GAS
13
GAS
3.84*
SOUR
FUEL
GAS
156
GAS
10.78*
SOUR
WATER
647
LIQ
STRIPPED
SOUR
WTER
629
LIQ
AMMONIA
6.6
GAS
SULFUR
41.4
SOLID
CLEAN
FUEL
G4S
114
GAS
FLARE
12
G4S
FIG 15 DESULFURIZATION & DENITRIFICATION
-------
COOLING
TOWER
BLOW DOWN
BOILER
BLOW
DOWN
EQUALIZED
COAL PILE
RUN OFF
EQUAL-
IZED
OILY
RUNOFF
WASTE
WATER
PLOCCULATOR
K)
70
PRIMARY
CLARIFIER
ARE AT I ON
CLARIFIER
AIR FLOTA-
TION UNIT
NUTRIENTS
PH ADJUST.
o
EQUALIZATION
BASIN
TO DISPOSAL
\STREAM
COMPOfc^
WATER *
SOLIDS
TOTAL
COOLING
TOWER
BLOW DOWN
2300
BOILER
BLOW
DOWN
500
COAL PILE
RUN OFF
mo
OILY
RUN OFF
J380
PROCESS
WASTE
WATER
920
CLEAN
WATER FOR
DISCHARGE
6250
CAKE
FOR
DISPOSAL
40 t/h
»gpm
FIG. 16 WATER TREATMENT PROCESS SCHEMATIC
-------
The process by means of which this can be achieved is the Texaco partial oxidation
A water-sol ids slurry is pumped through a preheater in which the water is vaporized
and the mixture heated to about 1000°F at 225 ps?. The steam-solid mixture then
enters the gasifier at the top. Preheated oxygen is introduced also at the top
by means of a different nozzle. The temperature of the mixture in the reaction
zone reached 2000° - 2500OF. The ash forms molten slag flowing down the gasifier
walls into a quench section, from where it is removed as a glassy solid. The gases
are removed from the end of the reaction zone and cooled in a heat recovery
system for preheating the feed and oxygen. The cooled gases are treated and com-
pressed to the reactor operating pressure and sent to the hydrogenation section.
In order to produce 60 tons/hr of hydrogen required, the system
should be capable of handling 325 tons/hr of solids. It requires 130 tons/hr of
steam and 275 tons/hr of oxygen. The process schematic is shown in Figure 17.
The principal emissions are: C02 - 5&0 tons/hr., slagged ash - 110 tons/hr and
nitrogen from the oxygen plant. Of these the control technology to be employed
is only for the disposal of solid wastes. At present this technology consists
of suitable landfill. There can also be a small stream of H S which is mixed
with that from the refinery units and treated as outlined before.
Another source of emission is the oxygen plant. Usually oxygen plants
do not have any serious or harmful emissions, other than the spills and blowdowns
of the lubricants and coolants used. The extent of harm these could cause has not
been determined, but, for control technology purposes, they can be collected and
treated along with the waste water treatment streams.
5.5 CONTROL TECHNOLOGY FOR COMMERCIAL PLANT
Assuming any coal liquefaction plant is a grass roots-integrated plant
i.e., the only inputs to the plant are coal, air and water; (chemicals and
catalyst are considered small and negligible), the control technology as far as
emissions are concerned, consists of:
1. gaseous effluents containing predominantly hydrogen sulfide and
hydrocarbons
2. .liquid effluents mainly water containing inorganic salts, heavy
metals and organic compounds in dissolved state
3. solid wastes consisting of ash constituents of the coal, sludges
from waste water treatment and coal dust from coal handling.
5.5.1 Gaseous Effluents
As mentioned previously the gaseous emissions consist of hydrogen
sulfide, ammonia and some hydrocarbons. Hydrogen sulfide, formed from the sulfur
in coal, appears in the two streams of fuel gas and sour water. The fuel gas is
scrubbed with an amine solvent like DEA, which is subsequently stripped to re-
lease the hydrogen sulfide. The sour water which contains both ammonia and
50
-------
r
STEAM
~1
FEED
GASIFER
02
(275)
1
CO-SHFT
GAS
TREATMENT
5)H2RICHGAS
AIR SEP
SYSTEM
^J ____________ I
-0/Vp
0
^^4W£4M
CHARACTER^^
FLCW RATE
STATE
CONC. POLL
SOLIDS
LIQUIDS
GASES
UNITS
tph
FEED
WACTWR
BOTTOMS
325
SOLID
WATER
130
LIQUID
AIR
1310
GAS
EXHftUST
GASES
560
GAS
H2(RCH
'GAS
60
GAS
96%H2
SLAG
110
SOLID
NITROGEN
1035
GAS
FIG. 17 HYDROGEN PRODUCTION
-------
hydrogen sulfide is simply steam stripped in two stages under different pressures
releasing hydrogen sulfide in the high pressure stage and ammonia in the low pres-
sure stage. The two hydrogen sulfide rich gas streams are mixed and sent to Claus
units for oxidation to elemental sulfur. Tail gases from the Claus units could be
treated by means of any of the 15 or so tail gas treatment processes that are
available. More on this tai1 gas treatment will be discussed in a later section.
The ammonia from the second stripper can be recovered as anhydrous
liquid and marketed as fertilizer.
Another important emission from any coal liquefaction plant is the
particulate matter from the coal handling operation. In the conceptual design
this amounts to about 9.2 Ib/hr assuming that the control technology is 99.9 per
cent efficient. However, as is well known, it is very much dependent upon how
the plant is operated and maintained. 0 6 M history and experience (in the USA)
does not guarantee that this level of efficiency can be maintained. Even a
small reduction in the efficiency of this control technology element, results in
several times the rate of emission given above.
Other minor emissions such as hydrocarbons due to spills and the gases
from direct fired equipment can be readily controlled by properly designed traps
knock-outs, washers and scrubbing equipment.
5.5.2 Liquid Effluents
The principal liquid effluent is the stripped sour water which still
contains dissolved hydrocarbons, inorganic salts and aromatic alcohols. Treat-
ment of these waste waters has been described only vaguely and qualitatively.
Even for the pilot plant in which this particular aspect of control technology
is to be tested, there are few data available. However, the company, AWARE, Inc.
a leader in waste water treatment, is charged with the development of a process
for treating these waste waters. A tentative scheme, as described in Section 5.1
has been developed by them, which, will be tested in conjunction with the pilot
plant at Catlettsburg, Kentucky.
The proposed concept is to mix all the waste waters, namely stripped
sour water, boiler and cooling tower blowdowns, coal pile run-off and other knock-
out and accidental spill washes into one stream and treat this stream to meet the
standards. The difficulty, however, is in quantifying what is there in all these
streams as pollutants and also how to treat them. A simple COD and BOD assessment
is insufficient because of the inorganics and heavy metals. Also, the fate of these
in the final sludge disposal has to be studied more thoroughly.
5.5.3 Solid Wastes
The main solid wastes resulting from the process are the ash content
of the coal, which is produced at a rate of 110 ton/hr in the form of glassy mass
from the hydrogen plant, plus a cake from the waste water treatment plant pro-
duced at the rate of kO tons/hr. The disposal of these solid wastes, at the
present time, is considered to be only as landfill.
52
-------
Assuming that there are no harmful leachates resulting from open
disposal of these wastes, the full requirement for these quantities is approxi-
mately kQO acre-ft per year of operation of the plant. In any case, to be on
the safe side, this disposal site must be some sort of lined pond.
5.6 ASSESSMENT
Any control technology assessment has to begin with the efficiency of
removal of the harmful substance and the economics of the control technology.
The former will be discussed in this section. The latter will be discussed in
Section 8.0. The principal control technology systems employed in these commercial
coal liquefaction processes are: 1) in the coal handling to remove particulates,
2) tail gas clean-up after the Claus units for H-S removal, 3) waste waters and
their treatment and, 4) handling and disposal of solid wastes. These will be
assessed in the following for their efficiencies and efficacies.
5.6.1 Coal Handling and Participate Control
The control technology as envisaged consists of hooded conveyor belts
and handling equipment and air flowing through these hoods passes through a cyclone
first to remove the coarse particles and then bag filters for removing the fines.
While the cyclones can be designed and operated efficiently for the flow rates
involved, the bag filters do present several problems. For instance the air to
be handled is approximately 4.2 million SCFM and the filter boxes containing bags
to handle such flow rates will be physically staggering. Their operation and
mechanical maintenance capability to insure efficiencies greater than 99-9 per cent
is questionable. The particulate emission at this efficiency is calculated to be
about 9.2 Ib/hr and a typical dispersion characteristic of this emission is shown
in Figure 18. However, it must be noted that this is based on a removal efficiency
of 99-9 per cent. As is well known with these types of systems, it is doubtful
that they can be maintained to operate at this efficiency all the time. It is
therefore necessary to evaluate their reliability and provide for alternative
technologies. An alternative technology is that of wet scrubbing using a venturi
scrubber for particulate removal. A discussion of this will be given in Section
7.0 on alternate technologies.
5.6.2 Tail Gas Clean Up
Tail gas from typical Claus plant contains about 2-k percent of H S +
S02 and up to 10,000 ppm of COS + CS2. A process usually employed for treating the
tail gas is to mix the tail gas with a hydrocarbon fuel such as methane and heat it
in a furnace with just enough air to maintain a reducing atmosphere. The S02 in
the tail gas is reduced to H S which adds to the H S already present in the tail gas,
These gases are then sent for amine wash where the H2S is absorbed and the clean
gases with less than 100 ppm of H S are either sent to the boiler furnace or are
discharged into the atmosphere.
This technology is proven commercially and is available. The removal
efficiencies amount to 99.7 percent and greater. The process can be applied
53
-------
.3 .1 .5 .9 .7 8 .91 2 3 <
DISTANCE F*QN SOURCE (Arm)
PIG. IS PABTKULATe CONCENTRATION DISTRIBUTION
5 S 7 8 9 10
54-
-------
anywhere regardless of the local conditions as long as physical space is
ava i1 able.
5.6.3 Waste Water Treatment
This is a technology which is still emerging as far as coal conversion
processes are concerned. A great deal of research is now being carried out by
the process developers themselves, but as regards control technology, there remain
a lot of questions to be answered. Some of the important ones are:
1. What are the amounts and final resting places of the heavy metals
present in the coal which find their way into the process waste
waters?
2. What poly nuclear aromatics (PNA's) are present and how are they
distributed in the final waste waters?
3- The penetration of these pollutants and carcinogens into the ground
waters and thus into population groups.
4. Also the adequacy of good clean water around the commercial coal
liquefaction plant (CCLP) because the process uses a lot of water
in an irrecoverable manner.
These questions cannot be answered at the present time, due to lack of
information. So this area of control technology must be emphasized for further
study with clearly defined goals.
5.6.^ Sol id Waste Disposal
The solid wastes from a CCLP fall into two classes: the regenerable
ones such as spent catalyst and the unregenerable wastes containing ash from the
coal and various sludges. The regenerable ones are usually shipped out to some
processing plant to recover their value. The other type of solid wastes can only
be disposed of as landfill at the present time.
Although their chemical character is somewhat different from the common
ash from a coal burning plant, the same disposal technology can be used. This
consists of ponding within a suitable distance from the plant.
55
-------
SECTION 6
EVALUATION OF EDS CONTROL TECHNOLOGY
The evaluation procedure for the EDS process control technology follows
similar lines to those that are used for the H-Coal process. First, the pilot
plant process (the ECLP process) is discussed with respect to all projected
plant emissions and the technology that will be utilized to control them. Then
an analysis is presented on the appropriateness of the pilot plant emissions con-
trol technology. Secondly, a similar discussion will be presented on the
commercial-scale EDS process with respect to the plant emissions, the technology
utilized to control them and the appropriateness of the control technology. Where
possible, the information and judgements gleaned from the discussion of the ECLP
process will be applied to the EDS process.
The process itself has been divided into six subsections in such a way
that the emissions control problem is of approximately equal gravity in each
section. These are: l) coal handling and preparation, 2) reactions and primary
separations, 3) sour gas and sour water treatment, *t) waste water treatment,
5) solid wastes treatment, and 6) catalyst handling.
6.1 EMISSIONS FROM THE PILOT PLANT
In discussing the process emissions for each subsection, Process
Systems Diagrams (PSDs) have been utilized, where appropriate, to present process
information in a precise and succinct manner .A PSD is formed by combining process
steps that form a system with concomitant mass and energy inputs and outputs.
Conceptually the system is represented by a rectangular box with necessary input
and output streams.
The system boxes may also be considered as modules whose function is
identical in the pilot plant and in the commercial plant; only the sizes of the
process equipment and streams will vary.
6.1.1 Coal Handling and Preparation
6.1.1.1 Process Description: Coal is delivered to a coal storage area in rail-
road cars (60 - 100 tons capacity) and then transferred to a 110 ton bottom dump
hopper. Through feeders and conveyors the coal is then transferred to a 5000-ton
inerted raw coal storage silo (with dimensions of 55 feet diameter and 182 feet
high). The coal reception and transfer rate can reach 300 TPH.
56
-------
The coal preparation plant consists of two parallel equipment trains.
These trains begin at the point of collection of the raw coal from the storage
silo feeders and proceed through the delivery of the prepared coal to the slurry
dryer feeder. One train is designed to crush and dry the coal and deliver it
to an inverted coal storage bin. The other train is designed to crush the coal
without drying and deliver it directly to the slurry dryer feeder. The prepara-
tion plant is located in its own equipment block along with the raw coal storage
silo adjacent to the onsite equipment block.
Coal is fed at a rate of 19,960 Ibs/hr (239.5 ST/SD) to the ECLP plant.
At this stage it has been pulverized to 95 percent minus 8 mesh. Figure 19 is a
flow diagram of the coal preparation and storage area.
Emission control equipment is located at various sites in the coal
preparation and storage area. The control equipment in place is designed to meet
new source performance standards for particulate removal. Table k details the
atmospheric emissions of the ECLP. Table 5 (source numbers 1 to 5) summarizes
the relevant maximum allowable emission rates that appear in the Construction
Permit issued to the Carter Oil Company by the Texas Air Control Board. Reference
to Figure 19 indicates where the control equipment is located. Table 6 compares
the ECLP calculated atmospheric emissions rate with the State of Texas Standards.
6.1.1.2 Sources of Emissions; The following sources of emissions have been
identi fled:
1. Coal Pile runoff results from exposed coal being leached by rainfall.
The design calls for the retention of this and other runoff water in an oily water
retention tank of 40,000 barrel capacity, with eventual disposition of the oily
water in the adjacent Exxon Baytown Refinery Waste Water Treatment System. (See
Figure 20). The storm water runoff design rate is based on a rainfall intensity
of 3.5 in./hr with a maximum storm rainfall of 10.2 inches in a 24-hour period.
Leaching tests have been performed on samples of Illinois #6 coal in a
Weather-0-Meter with exposure to water sprays, heat, infra-red and ultra-violet
radiation simulating approximately 27 months of outdoor storage. The results of
this test are summarized in Table 7-
Analyses of water taken from the Weather-0-Meter showed very little
organic carbon (TOC) or chemical oxygen demand (COD). There was no visible oil
in the water nor appearance of weathering of the samples. Thus, even under
severe conditions in the Weather-0-Meter, very little material was leached from
the coal samples.
2. Particulate or dust emissions from the coal handling system. As
mentioned earlier, the emissions from most components of the coal handling system
are minimized through the installation of appropriate control technology. However,
it is inevitable that some particulates escape to the atmosphere.
Approximately 20,000 Ibs/hr of coal are handled. Assuming that 0.3
percent of this is converted into dust in the handling process and a dust collector
57
-------
vn
oo
COAL
RECEIVING
STORAGE SILO
IMPACT
MILL
ROLLER
MILL
I
GAS HEATER
FURNACE
STORAGE BW
CYCLONE
t=* 1=1-
©
"^-^^^ STREAM
CHARACTER^^
FLOW RATE
STATE
CONC. POLLUT.
SOLIDS
LIQUIDS
GASES
UNITS
UfyR
rrg/ltr
rrq/ltr
ppm
RAIN
FALL
UQ.
RAW
COAL
19.960
SOLID
AIR
FOR
HOOCB
GAS
MAIfUP
AIRFOR
DRYING
GXIS
FUEL
G4S
TOPUVERJZED
SOLID
AIRFROM
DUST
:ousms
GAS
0.06*
COAL
STORA&
RUNOFF
LIQUID
VENTED
W&'i
G4S
SCRUBBED
TTILENT
LIQUID
*LBS/HR.
FIG. 19 FLOW DIAGRAM OF COAL PREPARATION AND STORAGE AREA'-
ECLP PLANT
-------
TABLE 4
ECLP ATMOSPHERIC EMISSIONS (15)
v-n
Sou rces
Liquid Recycle
Gas Preheat
Liquid Slurry .
Preheat (1 & 2)
Vacuum
Stripper Feed
Solvent Hydro-
genation Reactor
Preheat
Sol vent
Fract ionator
Preheat
Heat
Fired
(106 Btu/hr)
9.10
25.20
3.60
9.16
9.28
Stack
Height
(ft.)
95
88
68
90
86
Stack
Diameter
( inches)
22
33
21
22
24
Exit Gas
Temp.
(°F)
584
1270
1400
625
710
Gas"
Flowrate
(SCFM)
2170
3010°
860
2190
2220
so2
0.13
0.36
0.05
0.13
0.13
Emission
NO
1.03
2.85
0.41
1.04
1.05
Rates (
NMHC
0.22
0.60
0.09
0.22
0.22
Ibs/hr)
TSP CO
0.91 0.19
2.53 0.53d
0.36 0.08
0.92 0.20
0.93 0.20
Fugitive Losses
(Tankage, Valves,
Seals, etc.)
3-75
aAt 60°, 14.7 psia
Only one liquid slurry preheat furnace operates at one time. Each furnace has two identical stacks.
cPer stack
Total for both stacks.
-------
TABLE 5
MAXIMUM ALLOWABLE EMISSION RATES FOR COAL
PREPARATION AND HANDLING FACILITIES IN THE ECLP (16)
Source
Number
01
02
03
04
05
06
07
Source
Name
Fugitive Coal Dust at
Rail Car Dump Site^
Unloading Pit
Bag Filter Effluent3
Coal Receipt Bag Filter
Effluent3
Coal Preparation Bag
Filter Effluent
Coal Preparat on Venturi
Scrubber Effluent Gas
Vacuum Bottoms Venturi
Scrubber Effluent Gas
Vacuum Bottoms Conveyor
Discharge Bag Filter
Emi ss ion
S°2
Ibs/hr
k.O
0.3
2.1
0.6
3.5
0.3
0.5
Rate
T/year
6.0
0.1
0.2
1.4
9.2
0.7
1.3
a
The Ib/hour rate applies to an operating schedule of 10 hours/day.
60
-------
TABLE 6
COMPARISON OF CALCULATED ECLP ATMOSPHERIC
EMISSIONS AMD STATE OF TEXAS STANDARDS (1?)
SOURCE
1
1
2
3
4
5
6
SOURCE
NAME
Liquid Recycle
Gas Preheat
Liquid Slurry
Preheat
Vacuum Strip-
per Feed
Solvent Hyro-
genat ion
Reactor Pre-
heat
Solvent
Fract ionator
Preheat
EMISSION RATES (LBS/HR)
so2
CALCULATED MARa
0.13 NVb
0.36 KO
0.05 0.2
0.13 0.3
0.13 0.3
Fugitive Losses!
NO
X
CALCULATED MAR
1.03 NV
2.85 4.2
O.M 0.9
1 .04 1 .9
1.05 1.9
NNHC
CALCULATED MAR
0 . 22 NV
0.60 0.8
0.09 0.1
0.22 0.2
0.22 0.2
3.75 28.8
a. MAR: Maximum Allowable Rate
b. NV: No Value Available
61
-------
TABLE 6 (Continued)
SOURCE! SOURCE
#
i
2
3
4
5
6
NAME
Liquid Recycle
Gas Preheat
Liquid Slurry
Preheat
Vacuum Strip-
per Feed
Solvent Hyro-
genat ion
Reactor Pre-
heat
Solvent
Fract ionator
Preheat
Fugitive Losses
EMISSION
EMISSION RATES (LBS/HR) CONCENTRATIONS
TSP
CALCULATED MAR
0.91 NV
2.53 3.1
0 . 36 0.5
0.92 0.9
0.93 0.9
CO
1 CALCULATED MAR
0.19 NV
0.53 0.6
0.08 0.1
0.20 0.2
0 . 20 0.2
S°2
(ppm)
CALCULATED SIANDARD ~
6
6
6
6
6
kko
kkQ
440
440
440
a. MAR: Maximum Allowable Rate
b. NV: No Value Available
62
-------
TABLE 7
WEATHER-0-METER LEACHING TESTS FOR THE LIQUEFACTION BOTTOMS AND
ILLINOIS #6 COAL USED IN THE ECLP (18)
Weight Loss: After 27 days (equivalent to 27 months outdoor exposure)
Liquefaction Bottoms - Weight Before-
Weight After -
Illinois No. 6 Coal
Loss
Weight Before-
Weight After •
Loss
•556.7 grams
•556.2
0.5 g rams
-463.1 grams
417.2
- 45.9 grams
No weathering of either Liquefaction Bottoms or Coal was apparent by visual
inspection.
Analyses of Water Taken from Weather-0-Meter:
Water After
Sample Day
Liquefaction Bottoms 4
11
14
18
21
27
Illinois No. 6 Coal 4
}]
14
18
21
27
TOC
29
14.5
13
16
16
16.5
29-5
16.5
18.5
18.5
16.0
15.5
TOD COD E
34 79 . 7 1
56.4
0
3 5.1
6.7
7.9
39.4 69.7
56.6
18.2
4 16.1
10.5
5.9
OD
.8
.7
Distilled Water Source
Distil led Water From
Weather-0-Meter with
Blank Sample
12
TOC = Total Organic Carbon
TOD = Total Oxygen Demand
COD - Chemical Oxygen Demand
BOD = Biological Oxygen Demand
63
-------
efficiency of 99.9 percent the final emission rate will be
20,000 X Q.3 (1-0.999) = 0.06 Ib/hr
100
Pressurized blowdown streams from the venturi scrubbers in the coal preparation
are handled separately and sent directly to the Baytown Refinery cat-cracking unit
scrubber settling pond where their fines (5 weight percent maximum) will settle out.
3. The exact fuel gas compos i t i on used to heat the air in the gas heater
furnace is unspecified. However, its characteristics are identical to the fuels
used by the furnaces in the process block where current EPA standards for fossil
fuel firm steam generators are easily met (See Table 8).
6.1.2 Reactions and Primary Separations
6.1.2.1 Process Description: Subsections 4.2.1 through 4.2.5 provide a concise
description of the reactions and primary separations as they are handled in the
ECLPwith the following modifications:
i) There is no flexicoker stage, thus there is no autogenous source
of low-Btu gas (LBG). The ECLP produces 1,340 Ibs/hr of fuel gas
of unspecified heating content (See Figure 7). Supplementary fuel
gas needs are met through the purchase of natural gas from local
uti1i ty companies.
ii) Similarly, there is no possibility of generating hydrogen through
the steam reforming of the methane/ethane gas that would be produced
in the flexicoker section. Some of the hydrogen process needs are
met through the cryogenic purification of purge gas; however most of
the process hydrogen is supplied by the adjoining Baytown Refinery
6.1.2.2 Sources of Emissions^ Both continuous and fugitive emissions are gen-
erated from this section of theT process as well as gaseous and solid effluent
streams. The principal continuous emissions are:
Effluent Name Quant? ty Comments
Solids Residue 7,890 Ib/hr Contains ash, unconverted
(0.394 Ibs/lb of coal feed) carbon, heavy hydrocarbons
Waste Gases 1,590 Ibs/hr Contains 176 Ibs of sulfur/hr
(0.08 Ibs/lb of coal feed)
Sour Water 23,690 Ibs/hr Contains equilibrium amounts
(1.185 Ibs/lb of coal feed) of hydrogen sulfide, ammonia
carbon dioxide plus phenol
and polynuclear aromatics
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TABLE 8
COMPARISON OF ECLP ATMOSPHERIC EMISSIONS AND FEDERAL STANDARDS (19)a
Emission
Source
Liquid Recycle
Gas Preheat
Liquid SI urry
Preheat
Vacuum
Stripper
Solvent Hydro-
genat ion Reactor
Preheat
Solvent
Fractionator
Preheat
S02 Standard
(1b/106Btu) (lb/106Btu)
0.01 1 .2(solid fuel)
0.8(1iquid fuel)
0.01
0.01 "
0.01 "
0.01
TSP Standard NOX
(ib/lO&Btu) (Ib/lO^Btu) (lb/106Btu)
0.10
0.10
0.10
0.10
0.10
0.1
0.1
0.1
0.1
0.1
0.11
0.11
0.11
0.11
0.11
Standard
u)
0.7(solid fuel)
0.3(Mquid fuel
0.2(gas fuel)
ii
it
it
ii
a 40 CRF 60. There are no federal standards of performance applicable to the ECLP project. The
standards listed are those for fossil-fuel fired steam generators with a heat input more than
250 million Btu per hour.
-------
Table 6 indicated the levels of expected fugitive emissions from the
ECLP. Table 9 gives a detailed rundown of the ECLP sour water sources. (23 690
Ibs/hr of water flow are equivalent to kl .k gpm).
6.1.3 Sour Water and Gas Treatment
6.1.3.1 Process Description: The ECLP sour water contaminants of most concern
are carried by the sour water streams of the process block. These sour water
streams are individually listed with their expected rates in Table 9. The maxi-
mum total sour water rates are approximately 52 gpm for the Illinois coal opera-
tion and 61 gpm for the Wyoming coal operation. From the ECLP sour water
collection drum, the sour water is sent to the Baytown Refinery for treatment in
existing sour water handling facilities. A one hour storage hold for the sour water
is provided to permit continued operation of the coal plant during short-term in-
terruptions of sour water flow to the refinery. Treatment at the refinery consists
of steam stripping contaminants from the water. The removed contaminants (mainly
H2S, NH , and CO.) are then sent to the refinery's Claus sulfur plants where they
are partially oxidized.
The stripped sour water is sent to crude desalters in the Baytown Re-
finery and subsequently combined with other waste waters for future processing at
the waste water treatment plant.
The sour gases in the ECLP consist of separate hydrogen and fuel gas
streams. Each stream is compressed, water washed and DEA scrubbed for removal
of H2$ and NH . The H-S and CO. are stripped from the DEA in the regenerator
feed, water washed for NH removal and subsequently sent to Claus units for partial
oxidation at the adjacent"*refinery. It should be noted that the fuel gas treating
section alone has the capacity to process 1.75 million SCF/SD of feed.
6-1-3-2 jpurces of Emissions; Since the ECLP sour waters and the off gases
from the regenerator towers are sent directly to the Baytown Refinery for subse-
quent treatment, no emissions will be produced in the sour water and gas treatment
of the ECLP systems. However, the presence of polynuclear aromatics (PNA's) in
the stripped sour water are of some concern. The amount of polynuclear aromatics
are based on Wyoming Wyodak coal which produces about 15 times the amount from
Illinois coal. The planned testing program calls for running Wyoming Wyodak coal
for only about 6 months out of the projected 2.5 year program. The Wyodak
operation would contribute only 2 to 3 parts per billion of PNA's to the refinery's
untreated waste water (10-12,000 gpm).
The subsequent effect of stripping the sour water (in the crude desalt-
ers) of phenolics and PNA's has not been quantified.
6.\.k Waste Water Treatment
6.1.^.1 Process Description: The waste treating facilities collect, store,
and dispose of all waste water streams from the Exxon Coal Liquefaction Pilot Plant
A diagram of sources and dispositions is shown in Figure 20. The waste treating
facilities have been specified on the basis of segregating waste streams into oily
water, non-oily water, and sanitary wastes.
66
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TABLE 9
ECLP SOUR WATER SOURCES (20)
EDS PROCESS
Rate, GPM
Source
Phenol ic water
Slurry dryer distillate drum
Liquefaction cold separator
Atm. frac. distillate drum
Vacuum stripper distillate drum
Solvent hydro, cold separator
Solvent frac. distillate drum
Subtotal
Nonphenolic water
Liquefaction recycle gas scrubber
Solvent hydro, recycle gas scrubber
Fuel gas scrubber
Fuel gas condensate separator drum
Acid gas scrubber
Flare seal drum
Subtotal
Illinois
5.3
*.7
2. A
11.7
5.3
1.7
31.1
2.0
2.8
9.k
0.1
3.0
5.0
21.3
Wyodak
13.0
5.6
2.k
11.7
5.3
1.7
39-7
2.0
2.8
8.**
0.1
3.0
5.0
21.3
TOTAL
61 .0
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-co
^1
?\
t
RETENTION
TANK
RETENTION
POND
1
IMHOFF
TANK
1
i
* L_ _J "'
(D
-^S7/?£>W
CHARACTER
FLOW RATE
CONC. POLLUT.
BOD
COD
TOC
UNITS
GPM
OILY
STf&MS
NON
m**
PROCESS
1C WATERS
80
SANITARY
WATERS
:OAL PREPARA-
TION AND
fajUMBOTJqMS
KRUBBERWAER
30
TO REFINERY
540
SLUDGE
TO
SDMT^S
FIG. 20 WASTEWATER SOURCES IN THE ECLP PLANT
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Other waste water streams without treatment facilities within the
plant include sour waters from the process block, coal preparation water and vacuum
bottoms scrubber water, all of which are sent directly to the Baytown Refinery.
Uncontaminated rain water runoff flows to the natural drainage.
The oily water sewer system collects all waste water streams that might
be expected to be contaminated with oil. These streams include process oily wastes,
tank/drum water drawoff, tankage area runoff, safety area runoff, storm runoff from
oil contaminated process areas and pump pads, cooling tower blowdown, excess
collected condensate, and any other miscellaneous oil water streams. The col-
lected oily water is pumped to the retention tank from where it is gradually
pumped to the refinery's waste water treating facilities.
The non-oily water sewer system collects all waste water streams that
might contain coal fines and other oil-free streams. These streams include 1)
storm runoffs from the coal preparation and vacuum bottoms cooling and loading areas,
and 2) coal unloading sump water. The collected non-oily water is pumped to the
retention pond where provisions for fines settling have been made. The pond
effluent is pumped intermittently to the refinery for treatment in their waste
water treatment system.
The sanitary sewer system collects sanitary wastes from the control house,
general purpose building, coal unloading shed, and the administration building.
Sanitary sewage is treated in an Imhoff tank and the tank effluent sent to the oily
water retention tank. The Imhoff tank effluent is chlorinated to residual level
of one milligram per liter.
Rainwater runoff from tank and drum fields is considered to have some
oil contamination and is contained within the fire banks. The contained runoff
is discharged at a controlled rate to the oily water collection system during dry
periods. Oily and sanitary sludges collected in the treated waste facilities are
removed by vacuum truck.
Pressurized blowdown streams from the venturi scrubbers in the coal
preparation and vacuum bottoms solidification areas are handled separately and
sent directly to the refinery's fluid cat-cracking unit scrubber settling pond
where the fines content (5 wt percent maximum) will settle out. The clarified
water from this pond is sent to the refinery waste water system. Disposal
of the settled fines will be handled by the refinery, along with the settled
catalyst fines.
Uncontaminated clean rainwater runoff from areas such as parking lots
will be directed toward the natural drainage that now characterizes the proposed
plant site.
6.1.4.2 Sources of Emissions: Since all the waste treatment will take place
off site at the Baytown Refinery there will be no emissions generated at the
ECLP. As a result, there are no wastewater emissions to describe.
69
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6.1.5 Solid Wastes Treatment
6.1.5.1 Process Description: The bottoms product from the vacuum stripper tower
will be solidified and disposed of in an approved landfill. Two lines feed the
liquid product from the vacuum tower into two distributor nozzles which spread
the liquid across the width of a steel-belted cooling conveyor. The liquid cools
and solidifies on the steel belt into a sheet approximately 1/4" thick. The solidi-
fication is accomplished by spraying cooling water on the underside of the cooling
belt. The bottoms product solidifies into a brittle sheet which breaks into small
pieces as it discharges from the end of the cooling conveyor. The material then
falls through a chute onto a conventional, portable conveyor which elevates the
material and discharges it into portable steel containers. The material is
hauled away in these containers and disposed of in a landfill. Figure 21 is a
diagram of the solid waste handling procedure. The bottoms production rate is
7890 Ibs/hr.
6.1.5-2 Sources of Emissions: The vacuum bottoms slurry contains ash, uncovered
coal and heavy hydrocarbons. It also generates a fume consisting of a fine liquid
aerosol which is made up of hydrocarbons. The aerosol does not contain gases
such as SO , H S, CO or NO . Design values from the heat and material balance in-
dicate that the lightest component of the vacuum bottoms is a hydrocarbon with a
boiling point of 760°F.
The fumes from the cooling belt are completely withdrawn and sent through
a high-energy venturi scrubber. In addition, the discharge end of the conveyor,
where the solidified bottoms are loaded into transport conveyors, is enclosed with
a hood which sends fines-containing vapor through a bag filter (See Figure 21.)
Source numbers 6 and 7 of Table k outline the maximum allowable particulate matter
emission rates for this equipment.
The solidifed vacuum bottoms will be hauled by a waste disposal company
to a landfill site. At the landfill site, the disposal pit is impervious clay from
which there is no runoff and little or no seepage. Leaching tests have been per-
formed on vacuum bottoms samples in a Weather-0-Meter with exposure to water sprays
heat, infra-red and ultraviolet radiation simulating approximately 27 months of
outdoor storage. The results of this test are summarized in Table 7- Weight loss
from the bottoms sample are neglible (less than 0.1 percent) and less than that
observed in similar tests with the parent coal. Analyses of water taken from the
Weather-0-Meter showed very little organic carbon (TOC) or chemical oxygen demand
(COD). There was no visible oil in the water, no appearance of weathering of
samples. Thus, even under severe conditions in the Weather-0-Meter, very little
material was leached from the vacuum bottoms. Even less leaching is expected
under the milder conditions in a buried landfill, and any that should occur will
be retained in the impervious pit.
Other solid waste sources have much lower volumes and require inter-
mittent disposal. Among them are the following:
1. A non-oily water retention pond gradually builds up an accumulation
of coal fines which settle to the bottom of the pond. When a level of approximately
70
-------
VENTURI
\SCRUBBER
WASTE
PACKAGING
VENTS
TO
ATMOSPHERE
BAG
FILTER
WATER
COOLING
TO LAND
FILL
00
00
FIG.21 DISPOSAL OF ECLP VACUUM TOWER BOTTOMS?
i. FLOW RATE: 7890 LBS/HR OR 34.7 ST/SD.
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six inches has accumulated in the shallow section of the pond, the layer is bull-
dozed to the coal-fines collection sump on the eastern end of the pond. Evacuation
then will be to a state authorized landfill site. Over the short project life,
it is unlikely that fines removal will be necessary more than once or twice.
2. Sludge eventually accumulates in the bottom of the oily water re-
tention tank and the Imhoff tank. When necessary, these sludges are removed by
vacuum truck and combined with similar sludges from the Baytown Refinery for
disposal .
3. Coal fines from the venturi scrubber purge stream eventually settle
out in the Baytown Refinery settling pond for fluidized cat-cracker fines. Dis-
posal of the settled coal fines is handled by the refinery along with the settled
catalyst fines.
k. Coal fines collected in the bag filters are dumped to grade-level
"tote bins" for disposal, and then wetted and disposed of as landfill.
5. Coal diversion to dumpster bins or to trucks is possible in the coal
preparation area in the event of coal overheating or burning, or when testing the
system. Diverted coal is returned to the coal storage area or disposed of to a
state approved landfill.
6.1.6 Catalyst Handling
6.1.6.1 Process Description: Since many different operating conditions and
different types of coal(such as Illinois #6 and Wyodak) will be tested, it is
estimated that the plant service factor should be approximately 60 percent during
the operating period of 2.5 years. Catalysts will be used in the solvent hydro-
genation reactors and may have to be dumped once or twice during the life of the
project. Spent catalyst, when used as the filtering medium in the solvent hydro-
genation feed filter is disposed of in a similar manner.
Spent catalyst will be collected in sealed drums and shipped to a firm
on the Gulf Coast for metals reclamation.
6.2 PILOT PLANT CONTROL TECHNOLOGY
It has already been indicated that the ECLP is located on a site
adjacent to the Exxon Baytown Refinery. Where possible, advantage has been taken
of the available waste treatment facilities at Baytown to treat the gaseous liquid
and solid waste streams emanating from the ECLP. In section 6.1 the treatment and
disposal of the ECLP waste products has been reviewed—here it is presented in a
more concise fashion.
6.2.1 Air Emissions Control Technology
Emissions control technology is located on-site and offsite of the ECLP.
On-site control technology is located in the following areas; a) coal preparation
72
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and storage; b) various fractional and preheat furnaces; c) solid waste handling
and d) pretreatment of sour gases. Further treatment of the fuel gas takes
place offsite at the Baytown Refinery.
The performance of the required control equipment mandated to be in
place (that principally consists of different bag filters) at the coal prepara-
tion and storage areas Is summarized in Table 5. Similar performance data on the
various furnace emissions appears in Table 6. The furnace fuels are selected to
comply with Federal New Source Performance Standards for Fossil Fueled Steam Gen-
erators while the furnace stack heights are designed to comply with Regulation I,
Rule 105.12 and Regulation II, Rule 201.012 of the Texas Air Control Board.
The performance requirements of the emission control equipment that
will be in place in the solid waste handling area are outlined in Table 5. (See
also Figure 21 and Section 6.1.5.2). As previously indicated (in Section 6.1.3.1)
the sour gases are compressed, water washed and DEA scrubbed for removal of
hydrogen sulfide, ammonia and carbon dioxide. The hydrogen sulfide and carbon
dioxide are subsequently stripped from the DEA in the generator feed and water
washed for ammonia removal.
The resulting hydrogen sulfide/carbon dioxide gas mixture is forwarded
to the Baytown Refinery for conversion into sulfur in a Claus unit. A tail gas
cleanup unit is provided to reduce the sulfur content of the sulfur plant tail gas
to an acceptable environmental level. Approximately 99-9 percent of the sulfur
plant feed sulfur is recovered while the tai1 gas cleanup unit reduces sulfur
dioxide emission to about 100 ppm.
6.2.2 Liquid Effluents Control Technology
A full description of the on-site facilities for the collection and
storage of the waste water streams is given i n Sections 6.1.3.1 and 6.1 .A.1.
Eventually all the ECLP generated waste waters are transferred to the Baytown
Refinery and treated in the waste water system there.
The Baytown Refinery waste water treatment system has permits (both
federal and state) to discharge its treated waste waters into the Houston Ship
Canal. Since the maximum possible flow of ECLP waste waters is less than 3 percent
of the design capacity of the Baytown Refinery Waste Water Treatment System a
judgment was made by the Texas Department of Water Resources that no new discharge
permit was needed in this case.
6.2.3 Solid Waste Control Technology
All solid wastes are collected and disposed of in a state approved lar:-
fill site. Full details of these operations are available in Sections 6.1.5.2 anc
6.1.6.1. Leaching tests were also carried out on the vacuum bottom samples and
showed a neglible weight loss and very little chemical oxygen demand (COD). Fur-
ther details of the leaching tests are provided in Section 6.1.5.2.
73
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6.2.4 Environmental Testing Program
The overall objectives of the Environmental Testing Program are twofold:
1. A quantitative assessment of the environmental impact of the
EDS plant and
2. Evaluation of control techniques used to comply with environ-
mental regulations in a cost-effective manner.
Major emphasis will be placed on resolving the liquid effluent
problem, specifically:
a) Waste water streams will be characterized as process modifi-
cations are made.
b) Treatability studies will be carried out with liquefaction-
coking waste waters to test the efficacy of solvent ex-
traction, BIOX and activated carbon.
c) An evaluation will be made of existing and emerging environment-
al control technology and research and development needs for
new environmental control technology.
d) A pilot waste water treatment plant will be designed, construc-
ted and operated to treat a slipstream of the ECLP waste waters.
e) It is expected that preliminary design studies for evaluation
of alternative waste water treatment techniques for the EDS
process will be completed.
Air emissions studies incorporate the following features:
a) Quantitative characterization of the various emissions from
laboratory pilot units.
b) Assessment and evaluation of methods for fugitive dust problems.
c) Assessment of the environmental impact of burning synthetic
fuel plant streams (i.e., heavy liquids, low-Btu gas) in on-
site furnaces and boilers.
d) Evaluation of noise and control techniques for liquefaction
plant equipment not common to refineries or chemical plants
(e.g., large scale coal crushing and transportation).
In all cases, consideration will be given to potential changes that
can be made in the EDS process to minimize water and atmospheric emissions, while
taking into account the evolving status of federal and state environmental regu-
lations.
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6.3 ANALYSIS OF THE PILOT PLANT CONTROL TECHNOLOGY
The primary objective of Exxon Research Engineering Company in setting
up the ECLP is the development to commercial readiness of a Donor Solvent process
for coal liquefaction. While a lot of work has and will be done in the monitoring
and control of pol1utants,it is obvious that the pollution control problem has
a lower priority, especially since the ECLP scrubber product gases and all waste
waters are sent to the Baytown Refinery for subsequent treatment. This approach
has minimized the consideration of engineering controls as pilot plant process
modification that could be instrumental in eliminating the generation of pollutants
at the source.
Within the context of treating the incorporation of control tech-
nology as an "end of pipe" requirement rather than as an integral part of the pro-
cess itself a strong development program is underway in the areas of waste water
treatment and air emission control (see Section 6.2.4). However, there is no
published evidence that indicates that the full ramifications of the Resource Con-
servation and Recovery Act of 1976 have been noted or are being acted upon,
especially with respect to Sections 3001-3005 of the Act that treat the identi-
fication of hazardous wastes and sludges, the promulgation of guidelines and
regulations that affect the generation, treatment, transportation, storage of
hazardous wastes, and their concomitant handling facilities.
It bears noting that no plans have been made for predicting how the
ECLP control equipment will function under unsteady state conditions. Since
the ECLP is an experimental plant that will be operated under varying feed composi-
tions and operating conditions it is inevitable that for a large proportion of
its operating life unsteady state conditions will prevail.
An important topic that has not been addressed, even superficially,
is the question of the interference/inhibition effects of toxic organic chemi-
cals (such as phenols) or heavy metals (such as chromium from the cooling tower
blowdown) on the biological part of the waste water treatment process at the
neighboring Baytown Refinery. For example, concentrations as low as 0.02 mg/1
of phenols have been reported to be capable of upsetting secondary waste water
treatment plants. An even more insidious problem is the question of dealing
with slug flows of such toxic organic chemicals and heavy metals.
Finally, it should be noted that a much more thorough analysis of
the control of pollutants from the ECLP process \s needed to ensure that the
development of the coal liquefaction is completely consonant with the public
health and welfare as reflected in the Clear Air Act (1977), the Clean Water Act
(1977)i tne Resource Conservation and Recovery Act (1976), and the Toxic Sub-
stances Control Act (1976). At the very minimum the fallowing information should
be made available:
1. A detailed mass balance giving inlet and outlet stream characteris-
tics (flow and composition) for the major process stages such as
coal storage and preparation, coal liquefaction, solvent hydro-
genation, etc.
75
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2. The fuel gas composition and its variation with changes in the
process operating parameters such as the solvent-coal ratio.
3. A detailed breakdown of the sour water composition (both ionic
and organic) especially with respect to concentrations of heavy
metals and polynuclear aromatics and its variation with respect
to changes in the process operating parameters.
4. The dimensions of the proposed air pollution control equipment
and the design air flow rates.
6.if EMISSIONS FROM THE COMMERCIAL PLANT
6.4.1 Coal Handling and Preparation
6.4.1.1 Process Des cr i pt i on: Coal will be received five days per week from
two mines at a totalrate of 34,000 TPD. The run-of-mine (ROM) coal will be
brought in from the distant mine by an 85-car train (2 trains/day), and from the
nearby mine by conveyor belt (constant service).
A common conveyor will be utilized to transfer coal from the in-
coming nearby mine conveyor and coal received via railcar unloading facilities to
the stacker-reel aimer area (live storage). If the reclaimer is out of service,
coal from the live storage piles will be transferred by mobile equipment to a dump
hopper on the conveyor feeding the crushers. Similarly, dead storage can be re-
claimed by mobile equipment and dumped into the dump hopper and then moved through
the plant in the normal fashion.
The incoming coal will be stored in two stockpiles with a combined
storage capacity of 10 days of process feed. Two tripperstackers will be used
to stack the live storage piles at a rate up to 4,000 TPH. A 30-day dead storage
pile will be built up and retained.
A crawler-mounted reclaimer will be used to reclaim the stored coal
(24 hr/day, 7 days/week) at rates varying from 1,000 to 1,500 TPH. A surge storage
silo with a capacity of four hours of process feed will be provided downstream
of the stock piles. This will eliminate flow-rate surges and allow up to four
hour equipment stoppages upstream of it without affecting process feed to the lique-
factor trains.
Three 50 percent crushers (500 TPH each) will be provided downstream
of the surge silo. The crushers will reduce the reclaimed ROM coal from 90 percent
minus 1 inch to 95 percent minus 8 mesh. The crushed coal will then be elevated in
enclosed belt conveyors to a distribution bin which divides the total flow of
crushed coal into 8 streams to feed the 4 dryers. Eight gravimetric feeders (2/
slurry dryer) will be located directly under the distribution bin to control feed
to the slurry dryers.
The following steps are taken in the design to minimize emissions from
the coal handling and preparation area:
76
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1. Water sprays are provided at the track hopper pit to suppress the
dusting resulting from bottom-dumping of coal from railroad cars.
2. Water sprays are also utilized at the outlets of the coal crushers.
3. The inclined conveyor belts from the crushers to the feed distributing
bins are housed in a completely enclosed gallery with emissions con-
trolled by baghouse filters.
4. Each transfer point along the covered conveyor belts also has a bag-
house filter to remove particulates and dust.
A major difference in the ECLP and EDS processes is that the option of
crushing and drying the coal before delivering it to the slurry dryers is not avail-
able for the EDS process. Also, at this time emissions in the coal handling and
preparation area have not been quantified nor have the costs of the associated pol-
lution equipment been detailed explicity.
6.4.1.2 Sources of Emissions: The sources of emissions are as follows:
1. The coal pile runoff results from exposed coal being leached by rain-
fall. The design calls for the retention of this and other runoff water (containing
fines) in a rainfall retention pond of 22 million gallon capacity with eventual
disposition of the rainwater in the EDS waste water treatment system.
2. Particulate and dust emission from the coal handling system will be
appreciable in spite of the installation of appropriate control technology. Approxi-
mately 1000 tons/hr (2x10° Ibs/hr) of coal are handled. Assuming that 0.3 percent of
this is converted into dust in the handling process and a dust collector efficiency
of 99-9 percent the final emission rate will be:
2 x 106 x 0.3 (1-0.999) = 6 lb/hr
100
6.4.2 Reactions and Primary Separations
6.4.2.1 Process Description; Subsections 4.2.1 through 4.2.7 provide a concise
description of the reactions and primary separations as handled by the EDS process.
6.4.2.2 Sources of Emissions; Both continuous and fugitive emissions are generated
from this section of the process. The principal continuous emissions are:
EFFLUENT QUANTITY COMMENTS
Solids residue 2780 ST/D Consists of ash residue, these flexicoker
emanating solids are sent to a (5 year
capacity) settling pond.
Air emissions See Table 10 Consists of principally of furnace emissions.
Effluent water 7000 GPM Contains oils, phenols, hydrogen sulfide,
ammonia; consult Table 11.
77
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The dry fines from the flexicoker are pneumatically conveyed to offsite
mixing tanks. These dry fines are removed in a venturi scrubber prior to re-
leasing the carrier air to the atmosphere. A very small but undetermined amount of
dry fines is emitted to the atmosphere along with this air. An H S removal unit
removes H S from the low-Btu fuel gas from the flexicoker.
6.4.3 Sour Water and Gas Treatment
6.A.3.1 Process Description; The EDS sour water and sour gas treatment trains
are more comprehensive than the corresponding trains in the ECLP process; not only
do they allow for the recovery of sulfur, but they also recover ammonia and
phenolics as well. Conveniently, the sour water and sour gas treatment facilities
can be divided into five sections:
i) Sour water treating
i i) Ammon i a recovery
iii) Phenolic water treating
iv) DEA regeneration
v) Sulfur plant and taflgas cleanup
A process flow diagram for the gas and water treating facilities is
given in Figure 22.
• Sour Water Treating
Sour water treating consists of facilities for stripping H,S,
CO and NH from the sour water. A H S and CO. stream is fed to the sulfur plant
for recovery of elemental sulfur, whife the ammonia is recovered as a high purity
anhydrous product. The plant contains two-50 percent sour water strippers, each
designed to handle 860 gpm of sour water from a single liquefaction train. Inter-
mediate tankage is provided to handle up to 6 days of sour water production from
a single liquefaction train in the event that the sour water stripper is out of
service. The sour water contains 3000-4000 ppm of phenols.
• Ammo n i a Re co ve ry
The NH /H 0 vapor from the sour water stripper passes through
a suction knockout drum and is compressed, cooled, and separated. The knockout
liquid is recycled to the sour water treating facilities, while the vapor follows
the same sequence through two more stages of compression. The essentially pure
NH vapor leaving the third stage of compression is condensed at 110°F to yield an
anhydrous ammonia product of 99.8 percent purity.
The EDS plant contains 2-50 percent ammonia recovery trains,
each integrated with one of the sour water treating trains. Each train is de-
signed to recover 60 ST/SD from a single liquefaction train (120 ST/SD per plant).
• Phenolic Water Treating
The stripped sour water is cooled at 241 F and fed to the Phenol
Extraction Unit. This unit is designed to extract the mixed phenols from the
73
-------
1
/~~\ 1
\£/~
i&\
i
OFFGA
SCRUBB
S
ER
DEA
3EGENERAIX
\
SOURMTER
STRIPPER
4
.
1
SULFUR
PLANT
— "1
1 _,
4
TAILGAS
CLEANUP
UNIT
AMMONIA
RECOVERY
1
J
i ^n
^
© 0 © © ©
^47/?£>lM
CHARACTER^-
FLOW RATE
STATE
CONC. POLLUT.
SOLIDS
LIQUIDS
GASES
OTHER
UNITS
KLBS/HR.
RICH
DEA
1954*
LIQUID
LEAN
DEA
896'
UQUD
'JNTREA1ED
OFF GAS
GAS
SOUR
WATER
826.8
LIQUID
TO
HYDRO3EK
GAS
SULFUR
54.88
SOLID
VENT
GAS
GAS
LEAN
DEA
2650'
LIQUID
ANHYDROUSllO PHENOL
AMMONIA W^TION
JO.O I 1103.0
GAS LIQUID
•GPM
"DATA HAS BEEN SUMMED OVER2 TRAINS
FIG.22 SOUR GAS AND WATER TREATMENT PROCESSES-EDS PLANT
-------
stripped sour water and from the slurry dryer phenolic water. The plant contains
2-50 percent phenol extraction units each sized to handle the phenolic water
effluent rate of 1100 gpm from a single liquefaction train (2200 gpm pet plant).
Preliminary results from pilot plant simulations of the EDS process indicate
that the phenolic concentrations in the waste water will be of the order 3000-1*000
wppm. Figure 23 is a simplified flow sheet of the Phenol Extraction Unit.
The effluent water (containing 18 wppm phenols) is sent to the
offsite. waste water equalization tank along with water from the API Separator (see
Section 6.4.k). Crude phenols are recovered in the phenol extraction unit at a
rate of 120 B/SD per liquefaction train (2^0 B/SD per plant).
• Gas Treating
In the gas treating section, the atmospheric fractionator and
solvent stripper offgas streams are combined and scrubbed with DEA for H S re-
moval. The overhead gas from the fractionator offgas scrubber is sent to the
cryogenic hydrogen concentration unit. The rich DEA bottoms stream is combined
with the rich DEA streams from liquefaction, solvent hydrogenation and the coker,
and fed to the DEA hydrocarbon skimming drum.
• DEA Regene rat i on
In the DEA regeneration section, the combined rich DEA stream
is preheated against lean DEA product and fed to the DEA regenerator. The tower
overhead is partially condensed to yield a reflux stream which is returned to the
tower and a vapor stream containing the H S and CO- is stripped out in the re-
generator. The vapor stream is fed to a sulfur recovery plant, while the lean
DEA bottoms from the regenerator are cooled and sent to tankage. Pumping facili-
ties are provided to pump the lean DEA charges to liquefaction and solvent hydro-
genation sections and to the offgas scrubbers. Three 50 percent DEA regenerators
(two operating, one spare) are provided to improve the unit service factor.
* Sulfur Recovery
A sulfur plant is provided to recover elemental sulfur from the
combined H S stripper and DEA regenerator offgas. A tail gascleanup unit is pro-
vided to reduce the sulfur content of the sulfur plant tail gas to an acceptable
environmental level. Approximately 99.9 percent of the sulfur plant feed sulfur
is recovered while the tail gascleanup unit reduces SO. emissions to about 100 ppm.
The gas treating solution required for the tail gas clean up unit is obtained from
the flexicoker H S removal unit regenerator which has been oversized to handle
this additional service. Three-50 percent sulfur plants each handling 280 LT/SD
of sulfur are provided for the total liquefaction plant. Two-50 percent tail gas
cleanup units are also provided. Facilities are included for continuous degasifica-
tion of the sulfur plant sulfur pits to reduce H S emissions during loading
ope rat ions.
6.^.3.2 Sources of Emissions; The only source of gaseous emissions in the sour
water and gas treatment processes are the stack gases from the tail gascleanup unit.
30
-------
EXTRACTOR
FRACTfONATOR
SCRUBBER STRIPPER
SOLVENT
CW
oo
MIXER-
SETTLER
EXTRACT
LP
STEAM
OR HOT
TER
W
STEAM
40-50 Psig
GAS
BLOWER
GAS
PHENOLIC EFFLUENT CRUDE PHENOL DEPHENOLIZED EFFLUENT
FIG.23 PHENOL EXTRACTION FLOW PLAN'- EDS PLANT
-------
The approximate stack gas composition has been estimated to contain less than
100 ppm of S02- Further details are given in Table 10.
As far as the liquid effluents are concerned, the exit waters from
the phenol extraction plant (containing less than 18 ppm of phenols) are sent to
the offsite waste water treatment plant.
The H2S removal unit solution purge stream may present some water treat-
ing problems due to the chemical nature of this solution which contains vanadium,
thiosulfates, and anthraquinone disulfonic acid (ADA). Separate treatment of this
solution may be required to reduce the effluent chemical oxygen demand (COD) due
to thiosulfate. Although thiosulfate is readily oxidized in the biological treat-
ment unit, the optimum reaction occurs at low pH. Since the biox unit must be
operated at a pH of 7-9 to remove organic compounds, thiosulfate may not be readily
removed. If separate ^S removal unit solution treatment is required, this may
be done via acidification with sulfuric acid which converts the sodium thiosulfate
to sulfate and allows for the recovery of ADA and vanadium.
6.4.4 Waste Water Treatment
6.4.4.1 Process Description; The waste water treatment facilities were designed
on the basis that the NPDES permit for the EDS plant would be predicated on the
installation of the best available technology (BAT). Using a design flow of 7,000
GPM the following offsite treatment sequence was proposed:
i) API Separator
ii) waste water equalization tank
iii) neutralization facilities
iv) chemical flocculation
v) dissolved air flotation
vi) biological oxidation facilities
vii) activated carbon units.
Facilities are provided for the regeneration of carbon. The sludge
disposal train consists of i) thickeners, ii) a digestor and iii) gravity belt
filter presses.
Approximately 15 percent of the treated waste water is reused as cooling
tower makeup with the remainder being discharged.
6.4.4.2 Sources of Emissions; The treated waste water characteristics are
out 1ined in Table 11.
6.4.5 Solid Wastes Treatment
6.4.5.1 Process Description: Solid wastes from the EDS process include digested
biological sludge from the biological oxidation unit, oily sludge from the API
separator and dissolved air floatation unit, ash from the flexicoker and solids
removed from the boiler feed water cold lime treating unit blowdown.
82
-------
TABLE 10 SOURCES OF CONTINUOUS EMISSIONS FOR THE EDS PLANT (12)
co
Source of Emission^
Liquefaction Slurry preheat furnaces
(1368 MBtu/hr)
Solvent Hydrogenation Feed Preheat
Furnaces (183 MBtu/hr)
H2 Plant Steam Reformer Furnaces
(2004 MBtu/hr)
Offsite Steam Boilers (207 MBtu/hr)
H2 Plant Deaerators
C02 Removal Regenerator Overhead Drum
(7600) MPH C02)
Tail Gas Cleanup Unit
Sulfur Plant Incinerator:
Fuel Gas Combustion
Sulfur Pit Purge Gas Combustion
Totals
Notes:
furnaces
'reheat
aces
MBtu/hr) d
head Drum
bust ion
Ib/hr
598
80
876
91
-
-
39
3
S02 d
(vppm)
(150)
(150)
(150)
(150)
(100)
(115)
CO
Ib/hr (vppm)
34
5
50
5
<1
6
22
-------
TABLE 11
EFFLUENT CONCENTRATIONS FROM THE EDS OFFSITE WASTE WATER
TREATING FACILITIES (21)
Contaminants Effluent Cone., ppm Contaminant Rates
Oil «5 <20 Ib/hr
Phenols <\
-------
Sludges from the waste water treating facilities (API & DAF units) are
thickened and then concentrated in a gravity belt filter. The sludge is then loaded
into trucks and disposed of in a land farming operation outside the plant limits.
The digested biological sludge should not create any odor problems.
The ash removed from the flexicoker low-Btu product gas is slurried with
water and pumped to an above-ground lagoon for disposal. This lagoon is located
about 1/2 mile from the plant site and has about a 5 year capacity. The lagoon
will eventually be covered and reclaimed. The blowdown from the cold lime treating
unit is thickened and disposed of with the ash from the flexicoker.
6.4.5-2 Sources of Emissions: No information has been found on possible emissions
in the solid wastes treatment process.
6.4.6 Catalyst Handling
6.4.6.1 Process Descr iption; The catalyst disposal schedule is outlined on
Table 12. Several disposal options exists i) burying or landfill, ii) in-situ or
ex-situ regeneration followed by re-use, or iii) metals reclamation. As of yet no
definite plan has been decided upon.
6.4.6.2 Sources of Emissions: No information is available on the possible sources
of emissions caused by removal of the catalysts.
6.5 EDS PLANT CONTROL TECHNOLOGY
In section 6.4 mention has been made of the treatment and disposal of EDS
process waste products-- here, this information is presented in a more concise
fashion.
6.5-1 EDS Plant Air Emissions Control Technology
As of yet only skimpy information has been provided on how the air emis-
sions caused by the EDS process will be controlled. In fact, the air emissions
problem has only been addressed in three stages of the EDS process a) coal handling
and preparation, b) reactions and primary separations and, c) sour water and gas
treatment.
The following steps will be undertaken to minimize emissions in the coal
handling and preparation area:
1) Water sprays are provided at the track hopper pit to suppress the
dusting resulting from bottom-dumping of coal from railroad cars.
2) Water sprays are also utilized at the outlets of the coal crushers.
3) The inclined conveyor belts from the crushers to feed the distributing
bins are housed in a completely enclosed gallery with emissions con-
trolled by baghouse filters.
85
-------
TABLE 12
CATALYST DISPOSAL SCHEDULE: EDS PROCESS (21)
Location of Catalyst
Disposal Freq.
Amt. (ST)
Solvent hydrogenation
reactors
(a)
h*2 plant hydrotreaters
H£ plant zinc oxide reactors
H2 plant steam reformers
\\2 plant high temperature
shift reactors
H£ plant low temperature
shift reactors
\\2 plant methanator reactors
h"2 plant carbon treater-
activated carbon
Sulfur plant converters
Tail gas cleanup hydrogenation
reactors
Once every 4 years
Once every 2 years
Once every k years
Once every 2 years
Once every 2 years
Once every k years
Once every 3 months
Once every 2 years
Once every 2 years
95
240
150
160
300
140
8
180
2k
(a)
The catalyst for solvent hydrogenation will be returned to the
manufacturer for regeneration.
86
-------
k) Each transfer point along the covered conveyor belts also has a
baghouse filter to remove participates and dust.
At this time, emissions in the coal handling and preparation area have
not been quantified nor have the designs or the costs of the associated pollution
equipment been detailed explicity.
The dry fines from the flexicoker are pneumatically conveyed to offsite
mixing tanks. These dry fines are removed in a venturi scrubber prior to releasing
the carrier air to the atmosphere. A very small but undetermined amount of dry
fines is emitted to the atmosphere along with this air. An H2$ removal unit
removed h^S from the lowBtu fuel gas from the flexicoker. These items have been
costed (see Table 13).
A scheme was presented for removal of hydrogen sulfide from the sour gas
and sour water streams (see Section 6.^.3-1). Cost and ancillary data has been
presented on the processing of hydrogen sulfide rich streams in the Claus and
tail gas cleanup plants.
6.5-2 EDS Liquid Effluents Control Technology
Descriptions of the on-site and offsite liquid effluents control tech-
no
logy have been given in Sections 6.A.3.1 and 6.k.A.I.
The expected effluent characteristics from the waste water treatment
plant are detailed in Table 11. Cost data is provided in Table 13.
6.5.3 EDS Solid Effluents Control Technology
As of yet very limited information is available on the control of solid
wastes generated by the EDS process. The information at hand appears in Sections
6.4.5.1 and 6.k.6.1.
87
-------
TABLE 13
COST OF POLLUTION CONTROL EQUIPMENT FOR THE EDS PROCESS (22)
Direct Material & Labor Costs (a) M$ (b)
o On-site
Sulfur plant 9.8
Tail gas cleanup 3*9
H2S removal unit 13.0
Sour water treating 7-1*
Ammon i a recove ry 1.8
DEA regeneration 5-3
Phenol extraction 7.5
DEA scrubbing 2.0
Total on site pollution abatement cost 50.7
o Offsite
Waste water treating - BIOX k.Z
- Act. C Treat. 7.9
- Other 7.1
Ash handling 9.7
Sludge disposal 2.5
Offsite tankage loading
(S, NHj, phenol, sour water) 3.5
Cooling water facilities fr.O
Total offsite pollution abatement cost 38.9
o Total direct pollution abatement cost 89.6
Notes:
(a) Excludes indirect charges and process and project contingencies
(b) Hint 11 ion
-------
Section 7
ALTERNATIVE CONTROL TECHNOLOGY SYSTEMS
7.1 INTRODUCTION
It has been apparent that close similarities exist between the H-Coal and
EDS processes. In both cases the starting material is the same and the processing
steps involved are also similar to a large extent. This includes coal handling,
slurry preparation, primary reactors and separators, and product treatment. While
the similarities are obvious, there are large gaps in the information actually
available on these various unit process steps. At least for purposes of this
study, the Applied Research Division of Dynalectron was able to obtain considerably
more substantive information on the H-Coal process than on the EDS process. There-
fore, it is decided to address the alternative control technologies of both these
coal liquefaction processes in a unified manner. For instance, control technology
and alternatives for tail gas cleanup will be treated as essentially the same in
both cases; and similarly, the waste water treatment will be treated as a single
type of process. This is considered appropriate because both liquefaction pro-
cesses are similar and produce similar effluents. However, where there are sig-
nificant variations and/or differences these will be dealt with separately and
as specialized features.
The following multimedia emissions from a coal liquefaction plant can be
ident i fled:
1. Gaseous effluents:
a. Tail gases from Claus furnaces containing sulfur compounds.
b. Hydrocarbon emissions from vents.
c. Combustion products from direct fired equipment and flares.
2. Liquid effluents
a. Waste waters from process, cooling towers, boiler blowdown, coal
pile runoff and pump seals.
b. Hydrocarbons and solvents from leaks, spills and accidental
discharges.
c. Liquid wastes from hydrogen manufacture and oxygen plants.
89
-------
3. Sol id effluents
a. Particulates from coal handling.
b. Solids from deashing steps and hydrogen plant (if use is made of
some of the coal residues other than vacuum tower bottoms).
c. Spent catalysts, sludges and other process residues.
7.2 TAIL GAS TREATMENT
The basic Claus process usually employed for desulfurizing ^S-rich
gases (around 80 percent h^S) can be designed and made to operate at a recovery
efficiency of about 95 percent. The raw gas can sustain the combustion according
to the react ion
H2S + 1/2 02 *-S = H2 + 2225 Btu/lb of H2S
Under these conditions, already present in the furnace, almost half of the hydrogen
sulfide is converted to sulfur without any catalyst. The heat of reaction is
recovered as high pressure steam and the sulfur produced is recovered as liquid by
cooling down the gases to 300 - 350°F. The gases are then passed through a cata-
lyst converter, where the reaction between the H2S residue from the furnace and the
S02 produced in the furnace takes place according to:
2H2S + S02 ^3S + 2H20 + 660 Btq/lb of H S
The heat produced can be recovered as low pressure steam and one or more converters
may be needed to drive the reactions to equilibrium. Sulfur is recovered again as
liquid by cooling down the gases to about 300°F.
The tail gas from a Claus plant contains thus H2S and S02 and some other
sulfur compounds such as COS, C$2 depending upon the feed composition. The amounts
of these sulfur compounds is usually larger than that allowed by the present air
pollution regulations. In order to meet these standards, the tail gases require
cleanup. A scheme generally employed is to mix the tail gas with a hydrocarbon
fuel and just enough air to maintain a reducing atmosphere and pass the mixture
through a furnace. The S02 in the tail gas is reduced to H£S increasing the
concentration. This mixture is then sent to an amine recovery unit (absorber-
stripper system) separating the h^S tail gas. The h^S is recycled to the front
end of the plant and the clean tail gas goes to the stack via an incinerator if so
required. A schematic of this system is shown in Figure 2k. The h^S concentration
can be reduced to less than 100 ppm in a scheme like this. There are, however,
other alternatives to this reduction, recovery and recycle (3R) sequence of tail
gas cleanup. Some of these are described in the following subsections.
7.2.1 Instltut Franca is du Petrole (IFF) Process
A schematic of this process is shown in Figure 25. The process is based on
liquid phase reaction between SO? and h^S according to:
90
-------
CLEAN GAS
AMINE
MAKEUP
STRIPPED
SOUR WATER
.FIG. 2*. CONVENTIONAL DESULFURIZATION VIA AMINE/CLAUS
SYSTEM WITH TAILCAS TREATMENT
-------
ro
TAILGAS
STACK
-STEAM
-CATALYSTS.
SOLVENT
RECYCLE
SOLVENT
•**SULFVR
FIG. 25 IFP PROCESS SCHEMATIC
-------
The reaction is carried out in a solvent which dissolves both h^S and SC^. A
catalyst is used to enhance the reaction rate. The equipment consists of a packed
tower for gas-liquid contacting. The sulfur produced is insoluble in the solvent
and forms tiny spheres which travel down the column along with the solvent. COS
and C$2 do not react and pass through the system. An incinerator can be used to
destroy these and any residual ^S that has not reacted.
The system is sensitive to H2S/S02 ratio and so very close control of the
feed composition is necessary. Attached to a Claus plant, the combined sulfur
removal efficiency is about 99-3 percent.
7.2.2 Holmes-Stretford Process
This process is based on a complex chemistry of reduction of sodium and
vanadium salts selectively by H2S, producing sulfur in a aqueous medium. The salts
are regenerated by means of air blown oxidation. The chemistry approximately is:
2V5+ + HS" - »-2V + S
2V1*+ + ADA (oxidized) - ^2V5+ + ADA (reduced)
ADA (anthroquinone-disul fonic acid) is used only to provide a mechanism for
accelerated oxidation of vanadium. The air converts the reduced vanadium into
vanadate and also acts as a flotation agent to froth out the product sulfur. The
process has an advantage in that it can be designed to desulfurize gases containing
high concentrations of C02-
The process is proven technology and claims removal efficiencies of 99-5
percent and above with exit concentrations of l^S of less than 50 ppm.
7.2.3 Beavon Process
The Beavon desul furizat ion system is based on a two-step operation. First
the sulfur compounds in the Claus tail gas are reduced to ^S in a catalytic re-
actor and as a second step the H2S is removed using Stretford technology. Thus
the process is simply a mix of reduction steps of the conventional tail gas treat-
ment and Stretford process to remove h^S instead of recycling it back to the
Claus units. A schematic of the process is stown in Figure 26.
7.2.4 Lime/Limestone Scrubbing
As a throw away process in contrast to the regenerable processes described
above this lime/limestone scrubbing system offers a powerful alternative because
of its simplicity. The technology is well established in coal burning installa-
tions and the chemistry involved is simple. The process consists of incinerating
the tail gases to convert all sulfur compounds to S02/SO-, and absorb the S02/S0o
93
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REDUCING
FURNACE
TAILGg
REACTOR
VjD
-C-
CLEAN GAS
^
••••i
L
WDIZER
^ T~
SULFUR
MELTER
"\ AIR
I
-SULFUR
•STRETFORD SYSTEM
FIG. 26 BEWON PROCESS SCHEMATIC
-------
in a 1ime/1imestone slurry producing calcium sulfite and sulfates which are dis-
carded as fill material. A process schematic is shown in Figure 27.
7.2.5 Sulfox (UOP) Process
Essentially this process presents an alternative not only for tail gas
treatment, but also to the Claus process itself. According to the claims by its
developer — the Process Division of UOP-- the Sulfox process can process both sour
water and sour gas together to 10-100 ppm of objectionable pollutants. The process
is schematically represented in Figure 28.
Sour refinery gas is introduced into an absorber, where it is scrubbed
with aqueous ammonia solution. The rich liquor from the bottom of the absorber
is mixed with sour water, heated, aerated and passed through two oxidizing reactors.
The reactions involved are:
NH^HS + 1/2 02 »• S + H 0 + NH
NH^HS + nS *• NH^S HS
Waste gas consisting primarily of nitrogen (the oxygen has been used up in the
reactors) is separated and sent to a scrubber where ammonia is scrubbed out by
water. The sulfur is removed from the bottom of the second reactor. The liquor is
essentailly aqueous ammonia and is recycled to the absorber.
While the claimed removal efficiencies are very high, the process remains
still untried on a large scale. However, since the sour water from coal liquefaction
contains both hydroden sulfide and ammonia, the process may have a great promise of
efficacy.
7.2.6 Systems Analysis
All tail tas treatment systems can be studied in a unified manner by means
of a systems analysis. The total system consists of three subsystems as shown in
Figure 29: first the Claus system, followed by a tail gas treatment, which is
then followed by product disposal.
The conventional (or commonly used) sequence is for the tail gas to be
reduced and then the amine scrubbed to remove the h^S, which is then recycled.
Several variations of this process scheme are known and available.
Another alternative is to incinerate the tail gases to convert all the
sulfur compounds to S02 and desulfurize the flue gas by any one of the know Flue Gas
Desulfurization (FGD) technologies.
The third group of alternatives is to react the tail gas catalytically
and produce elemental sulfur like the IFP, Sulfreeen, and SNPA p-ocesses. These are
sensitive to feed composition processes. Since coal liquefaction tail gases very
widely in their compositions depending on the type of coal used, this group of
alternatives may not be the most suitable as control technology elements of fuel
95
-------
vo
INCINERATED
TAILGAS
CLEAN GAS
STACK
I^H
M
SCRUBBER
7 r-
/ r
t I J
•
r>
v
THICKENER
-^SLUDGE
PUMP
UME/UMESTONE
MAKEUP
FIG.27 SCHEMATIC OF UME/UMESTONE SCRUBBING
SYSTEM
-------
CLEAN GAS
VENT
OR1.0R2: OXIDATION REACTORS
RR: REDUCTION REACTOR
FIG. 28 SULFOX
-------
GO
MR
o3s— '
CLAJS
FURNACE
>
"1
|
SWC/fQdS
CLEANUP
A Ml IMC lA/ACLJ
A MlNk. rw-on
INCINERATOR
I
-4+*CLEANGAS
qi/rvjp
1
-j-*O£*/V GflS
RECYCLE
1
1
_ __^toCT/l/*h' /7^1 T
™T"^O/AlCAl U>IJ
|
— —fcj
-------
converter outputs.
7.3 HYDROCARBON EMISSIONS
The principal sources of hydrocarbon emissions are: 1.) vents, 2.) safety
devices like rupture discs, valves, etc. to protect the equipment from runaway
operation, and 3.) spills, accidents and rupture lines. In all of these cases, the
control technology to deal with these eventualities is strictly a matter of mech-
anical design and providing suitable safeguards. There are codes for these pur-
poses, such as the ASME codes for pressure vessel and piping design, ASCE codes
for structural design and strict adherence to OSHA standards.
7.4 COMBUSTION PRODUCTS
The origin of these emissions is mainly the power plant to support the
liquefaction plant. Control technology of fluegas treatment consists at the present
time of SOX control and particulates. Both are more or less well established
technologies and the alternatives are dictated by state and local regulations.
Other sources of combustion products are direct fired heaters and flares.
There is little of importance as far as control technology of these emissions is
concerned.
7.5 LIQUID EFFLUENTS
7.5.1 Relevant Statutes and Regulations Governing the Disposal of
Liquid Eff1uents
In recent times in the economically developed countries, industrial
development has been tempered by the need to maintain and enhance the quality of
the environment. In the United States this attitude is reflected in the goal that
has been set for the complete elimination of industrial point-source liquidefflu-
ents by 1985. The pathway toward meeting this goal has been delineated in two
statutes and their concomitant regulations, namely the Federal Water Review Pol-
lution Control Act as amended in 1972 and the Clean Water Act of 1977-
Pollutants have been identified as "conventional" (such as BOD or sus-
pended solids (SS)), "toxic" (according to a list of 65 elements, compounds or
families of compounds) or "non-conventional" (pollutants other than conventional
or toxic). By the time commercial size coal liquefaction plants will be in
operation (from the middle to the end of the next decade) the following EPA pro-
mulgated industrial liquid effluent standards will be in force:
a) For toxic pollutants, effluent standards will be based on the
"best available technology" (BAT).
b) For conventional pollutants, effluent standards will be based on the
best "conventional pollution control technology" (BPCT). This
level of technology can be no less than "best practicable control
99
-------
technology" (BPT) and as high as BAT.
c) For non-conventional pollutants industry must comply with BAT.
The treatment of wastewaters to meet the above mentioned point source
standards oftentimes produces sludges containing various levels of toxic pollu-
tants. These types of sludges are defined as hazardous wastes under Section 3001
of the Resource Conservation and Recovery Act (RCRA) of 1976 and will be subject
to recently promulgated EPA regulations that govern the treatment, generation,
transportation, storage and disposal of hazardous wastes.
The above discussion has been limited to the impact of federal statutes.
At the state level, there is always the possibility that more stringent statutes
and regulations may govern the disposal of liquid effluents (and their concomitant
sludges). In general, however, the states have decided to follow the federal laws
and regulations. Also, since the locations of the commercial size coal liquefaction
plants (for both the H-Coal and the EDS processes) have not yet been decided on,
the following dicussion will take as its starting point the federal regulations
only.
7.5.2 Water Management Program
The principal wastewater sources for a typical coal liquefaction plant
have been delineated in Figure 22. 1n quantity the major source of wastewater
pollution is the non-contact water (including blowdown) used for evaporative
cooling systems (11). Other major sources of wastewater are also extra-process
produced such as drawoff from tankage and excess collected condensate and the
runoff from various process areas such as the tankage area, and the coal prepara-
tion area.
The federal regulations that will be in force by 1985 will have the effect
of mandating not only a reduction in the amount of the pollutants discharged, but
also a reduction in the amount of water discharged. To achieve substantial reduc-
tions in the amounts of waste discharged, a very thorough water management program
will have to be implemented and will include i) those innovations that will reduce
extra-process water needs such as cooling systems or combined air/water cooling
systems, ii) a comprehensive re-cycle/re-use program, iii) a very detailed house-
keeping program.
Other aspects of a water management program that will affect the char-
acter of wastewaters that will be treated at the wastewater treatment plant are
i) incorporation of phenol sulfur and ammonia recovery units, ii) segregation of
incompatible streams.
The water management program as such will not be referred to again in
this report as all in-plant activities fall outside its scope. A good starting
point for such information is reference (23). The remainder of this discussion
will look at the "end of pipe" (offsite) wastewater treatment system alternatives
from both technological and cost viewpoints.
100
-------
7.5.3 Qffsite Wastewater Treatment Alternatives
As of yet, no point source effluent standards for coal liquefaction
processes have been promulgated mainly because these processes have not yet passed
the fledgling state — the largest coal liquefaction plant currently operating is
the DOE-financed pilot plant at Tacoma, Washington. This plant incorporates the
SRC-II process and has a coal utilization rate of *»5 metric tons per day. However,
comprehensive regulations have been promulgated for a similar industry, namely
the petroleum refining industry.
Further discussion will be based on the premise that when point source
effluent discharge regulations will be promulgated they will be very similar in
nature to those in effect for the petroleum refining industry. The fact that the
organic wastewater pollutants for coal conversion processes tend to be aromatic
in nature while the petroleum refinery wastewaters tend to be aliphatic will be
taken into account.
The standards that will be in force will, at a minimum, demand that the
effluents be treated to the tertiary level. A wide variety of pre-treatment, sus-
pended solids removal, secondary treatment, and tertiary treatment options plus
liquid and sludge disposal possibilities are outlined in Figure 30. All the
technology up to and including secondary treatment has been demonstrated amply to
the commercial plant level. However, except for chlorination and activated carbon,
most tertiary treatment processes have not been tested at the commercial plant
level. It is expected that in the next decade all the mentioned tertiary pro-
cesses will become proven technology.
It is possible that an additional level of treatment will be needed to
ensure that the toxic effluent standards will be met. Treatment processes such
as electrodialysis, electrolysis, alkaline chlorination, freeze crystalization and
evaporation will have to be considered. Of particular concern is the likely
presence of heavy metals in the wastewater due to their presence in the coal raw
materials. Antimony, arsenic, beryllium, chromium, copper, lead, mercury, and
nickel are typically found in coal, as shown in Table \k.
The options of sludge and ash disposal are likewise limited due to the
presence of heavy metals in the sludge. The only feasible options are incinera-
tion, lagooning, sanitary landfill and chemfixing.
The offsite wastewater treatment and sludge disposal scheme proposed
for the EDS process corresponds to a tertiary treatment plant. The wastewater
treatment process proposed for the H-Coal plant at Catlettsburg , Kentucky sep-
arates incompatible waste streams and treats them to the secondary level before
their final disposal in the rivers.
7.6 SOLID WASTES
The bulk of the solid waste of an integrated coal liquefaction plant
comes from the ash and mineral content of the coal. The point where it emanates
from the plant depends upon the design of the plant. In H-Coal plants this is
at the gasifier for hydrogen the production unit. As mentioned before in Section
5-5-3, the method of disposal of this solid waste envisaged at the present time
101
-------
PntfMtffMfH
Saeondarydhiol-wlioHdt
fwiHowp |tonowwo by
darlfkatlonl
Tertiary dlnotiMd
•ollrfi ramonl
LkjuHi dhpoal
*
•*| grttftmevri \ _ ||
"*1 IzXkm [1 II
1 ComigMd H-
^•^Ipidg luttroptoi 1
•*{ floeeulathNi L 1
1 h J'
LtJ APlMVMMor F |
1
1
f
H _______ . .
•nd^kbrtmiril 1
H
Hf|.,i ^|. m H" ""
pl°W«oii p
1 |
1, „ i
•*! *«•» Li
__J Triekta h - '
'"n "^ h
»^ i •crawling and t* ^ | Aarttvll f"" ™"
^*f fHtntkHi L | "*1 togoon I 1
i r
Uj A~^«* rj
|-^l trMinant l_ |
1 1
1 1
1 1
1
1 CMorinatlon 1
•*^ or dMMMtton j
_kJ lonniehang* j
"*"{ arattanpracau {
^j ActniaUd 1
"^1 carbon 1
1 1__
-toJ FHtratlon I
. „" , . . /
HCoagulatton & 1 '
ftoeeulatlon {_,
1
oonotntratkMi
i
Hmjj^,,,,., T
thk**nlng f
HDtiwtvadalr 1
notation |^
/
dlgtttlon
1 i
i
i _J A»roWe j
^1 Anaerobic 1
"*1 dlgaMlon |
H Sludge 1
lagooni 1
~G.30 WASTED
Sludgt
eondltlonlng
' II
1.
1 "*1 eondltlonlng 1
LJ H«t I_J
-•1 ttMrn^t |
1 1
1 1
1
1
1 !
WER PROCESSIf
Sludg* dcwttiring
and drying
1
1.
\
-M Drytnfb«d» 1—
^ 1
HvCCUtlfll j
ffltratton J
H sr h
HPrmurt I
Nitration J
^1 drying |
K3 ALTERNATIVE
1
I
-»»| Lagoonfeg J \
"*" mttrt 1
ControHad J
1 ,
1 1
Efaporatfcm 1 |
• i
1
siudg*
COfTKMIftKin
I nl
f -M JncifMratfcn 1
U. *« LJ
1 ^^ oxidation I
l
5 rOF? A COMME
Haat removal
H Cooling toK«f 1
(oxidation) |
_(J Spnypondi
-«J Airitripping
__J Auto- I
^*1 oxidation J
,1
.Sludgiind
•ih dhpottl
F
-»J Ugoonrng
~H landfill
^*\ prooin
•pc/w
h
h
H
COAL LIQUEFACTION PROCESS
-------
TABLE 14
TRACE ELEMENT COMPOSITION OF ILLINOIS NO. 6 COAL SAMPLES (24)
Element
Aluminum
Antimony
Arseni c
Bar i urn
Berryl1ium
Boron
B rom i ne
Cadmium
Calcium
Cerium
Ces i urn
Chlorine
Chromi urn
Cobalt
Copper
Dyspros ium
Europium
Fluorine
Gal 1ium
German i urn
Hafnium
I nd i urn
Iodine
I ron
Lanthanum
Lead
Lutetium
Magnes ium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potass i urn
13500
0.
5.
Ill
1.
135
15
<4
7690
13
1.
1600
20
6.
13
1.
0.
63
3.
<5.
0.
0,
1.
18600
7
27
0
510
53
0
9
22
45
1700
98
9
0
25
1
6
52
14
9
08
18
2
Element
Rubi di urn
Samariurn
Scand i urn
Seleni urn
S i1i con
S iIver
Sodi urn
Stront i um
Tantalum
Terb ium
Thai 1ium
Thori um
Tin
Ti tani um
Tungsten
Urani um
Vanadi um
Ytterb i um
Zi nc
Z i rconi um
EEL
16
1.2
2.6
2.2
26800
0.03
660
36
0.16
0.17
0.67
2.2
A.7
700
0.7
1.6
33
0.54
420
52
103
-------
is as fill material. The technology of landfill ing is well known from power
plants and other landfill projects.
Since, in the case of the H-Coal process, the solid waste material
comes out from the gasifier in the form of fused slag or glassy material, this
suggests possible alternatives for its use as building material.
Another effluent in solid form is the particulate emission from coal
handling. This can be controlled effectively by wet scrubbing and recycling the
sludge either to the reactors or to the gasifier. This method of dust supression
should prove not only effective, but economical in the long run because of low
maintenance costs and less frequent shut downs.
Wastewater treatment also produces sludges which have to be disposed of
after dewatering. Usually, sludges are disposed as soil spread, making available
the nutrients in them for plants and vegetation. However, in this case the pro-
cedure is not suitable because of the trace metals contained in this sludge. So
the only method of disposal of this sludge is as landfill along with other solid
wastes.
-------
SECTION 8
COST EVALUATION
8.1 INTRODUCTION
Implementation of new and untested environmental control technology is
a matter of vital concern to both the concerned public as well as to the branch
of government charged with the mandate of insuring the quality of our environment,
in this case the U.S. Environmental Protection Agency. Therefore, it is only
logical to ask some pointed questions such as whether the control technology is
usable and does it represent the minimum economic penalty for meeting environmental
goals. These are, naturally, very involved questions even in those cases where
the technology is well know and tested. In case of coal liquefaction where the
process technology is still emerging, it is very difficult to assess the control
technology according to the above criteria.
In the following, an attempt will be made to evaluate the costs of the
control technology. It should be pointed out that these are only approximate
numbers based on plants in similar industries and on professional experience.
Their accuracy is believed to be within - 20 percent.
8.1.1 Methodology of Approach
The methodology for cost assessment is as follows: First, the capital
cost of a base case control technology will be estimated. This is to be done for
all effluents i.e., gases, liquids and solids. Then the approximate operating
costs will be estimated for all three classes of effluents. The total cost of
control technology is then calculated using suitable rates for depreciation and
return on investment for the life of the system. From this, total cost, the share
of control technology cost as dollars per barrel of LFE (liquid fuel equivalent)
is evaluated. This is the base case cost of control technology of a coal lique-
faction plant, and can be expressed as
S=S +S.+S +S (Equation 1)
Ct Q I S C
where S = total cost of control technology
S , S. , S , S - parts constituting gas treatment, liquid treatment,
solid treatment and capital related.
105
-------
For alternative technologies, depending upon which alternative is being considered,
it can be evaluated as
°r 2 - g 2J s c (Equation 2)
°r
The variance of control technology cost is then calculated as
- ,S H
i g
- S H
g
- S H
g
hsi4
h2Sl
1- S +
I
• S +
S
+ S
,s
3 s
S
c
+ S
c
'ct (Equation 3)
8.2 COST OF CONTROL TECHNOLOGY
As mentioned in the preceding subsection, the cost of a base control
technology system will be evaluated first. The base case is assumed as:
A. Gas Treatment Train Consisting of
1. Reduction furnace
2. Amine wash system
3. H2S stripper
4. Solvent recovery
5. Incinerator
B. Water Treatment Train consisting of
1. API-separator
2. Equalizer
3- Pretreater
k. Aeration units
5. Biox units
6. Filtration
7. Activated carbon
8. Sludge treatment
C. Solid Treatment consisting of
1. Bag filters
2. Slag cooler
3. Size reducers
4. Catalyst cleaning
5. Loading and dispersing
6. Fill spreaders
All costs of these units are estimated in 1978 dollars for a 25,000 tons of coal
per day liquefaction plant.
8.2.1 Capital Costs
106
-------
Unit Cost (in mill ion $)
Gas treatment train (GTT) 6.6
Buildings & structures 1.3
Total (GTT) 7-9
Water treatment train (WTT) 21.7
Sol ids Treatment 5.3
Buildings S structures 1.1
Total solids treatment 6.^
Total investment cost of CT 36.0
8.2.2 Operating Costs
Cost/yr Life cycle cost
I tern (in thousand $) (in mill ion $)
Gas Treatment
Water Treatment
Soli d Treatment
Total
8.2.3 Capital Related Costs
1. Depreciation calculated as
straight line over 20 years 36.0
2. ROI calculated as straight
10 percent over 20 years 72.0
8.2.4 Control Technology Cost Share
Total cost of CT = 212 x 10 (dollars)
i r O
Total production = 3.55 x 10 Btu = 5-92 x 10 Bbl (LFE)
o
S = 2J2 x 10.. = 0.35 ($/Bbl)
ct 5.92 x 108
8.3 COST OF ALTERNATIVE TECHNOLOGIES
It is apparent from the nature of Equation 2 which formulates the incre-
mental changes in the cost of control technology due to an alternative, that a
very large number of A's and thus E's can exist. Any one or a combination of
alternatives results in a separate A and so making it an eigen valued A . It is
impractical to list all the possible variations, and so it was decided only to
attempt two variations; one resulting in the lowest A and the other the highest A
107
-------
These constitute the lower and upper bounds of the share of the environmental
cost. A quick evaluation shows the lowest case (or least expensive) alternative
to be burning the tail gas and treating the S02-containing flue gas as a throw-
away FGD system for the gas treatment train with a water treatment train and wet
scrubber for particulates. The most expensive or upper bound is a regenerative
treatment train for gases such as Beavon, with a waste water treatment system
that removes all toxic materials above and beyond the capabilities of a tertiary
treatment system. This would be coupled with a solid waste treatment system such
as a lined and covered pond.
The changes in the control technology costs are, in the least expensive
case, ~k6 x 10^, and in the most expensive case, +165 x 10", giving Emjn = 0.78
and Emax = 1.78. The resultant variation in the control technology cost share
is 0.273 $/Bbl minimum and 0.623 $/Bbl maximum.
108
-------
REFERENCES
1. Hydrocarbon Research, Inc. H-Coal Integrated Pilot Plant - Phase I Final
Report. Report No. L-12-C1-510. 3 volumes. July 1977.
2. Epperly, W.R., J.W. Taunton, 1978. Status and Outlook of the Exxon Donor
Solvent Liquefaction Process Development. In: Proceedings of the Fifth Energy
Technology Conference, Washington, D. C. Feb. 27 - March 1. pp. 353-361*.
Published by Government Institutes Inc., 4733 Bethesda Avenue, N.W.,
Washington, D. C. , 20014.
3. Fant, B.T., October 1977. EDS Coal Liquefaction Process Development:
Phase III, Quarterly Technical Progress Report for the period January 1 -
June 30, 1976 prepared by Exxon Research and Engineering Company, Baytown
Research and Development Division, P.O. Box 425, Baytown, Texas 77520 for
U.S. Energy Research and Development Administration under Contract No. E(49-18)-
2353.
4. Fant, B.T., January 1973. EDS Coal Liquefaction: Commercial Plant Study Design,
Interim Report, prepared by Exxon Research Division, P.O. Box 425, Baytown,
Texas 77520 for U.S. Department of Energy under Contract No. (49-18)-2353-
5. Hittman Associates Inc., November 1977. Environmental Characterization and
Technology Comparisons for Coal Liquefaction Processes. Report prepared by
Hittman Associates Inc., 9190 Red Branch Road, Columbia, Maryland 21045 for
the Envirpnmental Protection Agency under Contract No. 68-02-2162, Phase II,
Chapter 6, The Exxon Donor Solvent Process.
6. Furlong, L.E., E. Effron, L.W. Vernon and E. L. Wilson, August 1976. The
Exxon Donor Solvent Process. Chemical Engineering Progress 75(8):69-75.
7. National Academy of Sciences, 1977. Assessment of Technology for the
Liquefaction of Coal. Prepared by the Ad Hoc Panel of Liquefaction of Coal
of the Committee on Processing and Utilization of Fossil Fuels. Commission
of Diciotechnical Systems, National Research Council, National Academy of
Sciences, Washington, D. C.
8. Rogers, K.A., A.S. Wilk, B.C. McBeath and R.F. Hill, April 1978. Comparison
of Coal Liquefaction Processes. The Engineering Societies Commission on
Energy, Inc., 444 North Capitol St., N.W., Washington, D. C. 20001 to DOE.
Contract No. EF-77-C-01-2468.
109
-------
9- Swabb, L.E. Jnr., 1978. Liquid Fuels from Coal: From R & D to an Industry,
Science, 199, (4329). pp. 619-622.
10. Texas Air Control Board, February 27, 1978. Construction Permit #C-6o80
issued to the Carter Oil Company (a subsidiary of the Exxon Oil Company)
authorizing the construction of a Coal Liquefaction Pilot Plant to be located
at Baytown, Harris County, Texas.
11. U.S. Department of Energy, Assistant Secretary for Energy Technology,
December 1977. Environmental Assessment: Donor Solvent Coal Liquefaction
Pilot Plant (Exxon Research and Engineering Company, Baytown, Harris County,
Texas), Publication # DOE/EA-004 available from the U.S. Department of
Energy, Washington, D. C.
12. Talty, John T., 1978. Assessing Coal Conversion Processes. Environmental
Science and Technology, ]2(B) . pp. 890-894.
13. Ghassemi, M., D. Stehler, K. Crawford and S. Quinlivan, 1978. Applicability
of Petroleum Refinery Control Technologies to Coal Conversion. A Report
Summary, Environmental Review of Synthetic Fuels. 1(3). pp. 10-12.
14. AWARE. Report on "Treatment Investigations and Process Design for H-Coal
Liquefaction Wastewater" by Associated Water and Air Resources Engineers, Inc.
Nashville, TN. December 1976.
15- U.S. Department of Energy, Assistant Secretary for Energy Technology, December
1977- Environmental Assessment. Donor Solvent Coal Liquefaction Pilot Plant
(Exxon Research and Engineering Company, Baytown, Harris County, Texas) .
Publication No. DOE/EA-004 available from the U.S. Department of Energy,
Washington, D. C. Table 2.7.
16. Texas Air Control Board, February 27, 1978. Construction Permit #C-6o80
issued to the Carter Oil Company (a subsidiary of the Exxon Oil Company)
authorizing the construction of a Coal Liquefaction Pilot Plant to be located
at Baytown, Harris County, Texas.
17. U.S. Department of Energy, Assistant Secretary for Energy Technology, December
1977. Environmental Assessment. Donor Solvent Coal Liquefaction Pilot Plant
(Exxon Research and Engineering Company, Baytown, Harris County, Texas).
Publication No. DOE/EA-004 available from U.S. Department of Energy, Washing-
ton, D. C. Tables 2.7 and 2.8.
18. U.S. Department of Energy, Assistant Secretary for Energy Technology, December
1977. Environmental Assessment. Donor Solvent Coal Liquefaction Pilot Plant
(Exxon Research and Engineering Company, Baytown, Harris County, Texas).
Publication # DOE/EA-004 available from the U.S. Department of Energy, Washing-
ton, D. C. Table 2.7.
110
-------
21
19. U.S. Department of Energy, Assistant Secretary for Energy Technology, December
1977. Environmental Assessment. Dorrbr Solvent Coal Liquefaction Pilot Plant
(Exxon Research and Engineering Company, Baytown, Harris County, Texas).
Publication No. DOE/EA-OOA available from the U.S. Department of Energy,
Washington, D. C. Tgble 2.8.
20. U.S. Department of Energy, Assistant Secretary for Energy Technology, December
1977- Environmental Assessment. Donor Solvent Coal Liquefaction Pilot Plant
(Exxon Research and Engineering Company, Baytown, Harris County, Texas).
Publication # DOE/EA-00^ available from the U.S. Department of Energy,
Washington, D. C. Table 2.6.
Fant, B.T., January 1973. EDS Coal Liquefaction. Commercial Plant Study
Design, Interim Report. Prepared by Exxon Research and Engineering Company,
Saytown Research and Development Division, P.O. Box ^25, Baytown, Texas
77520 for U.S. Department of Energy under Contract No. (Ag-18)-2353-
Table 1, p. 68.
22. Fant, 3.T., January 1978. EDS Coal Liquefaction: Commercial Plant Study
Design, Interim Report. Prepared by Exxon Research and Engineering Company,
Baytown Research and Development Division, P.O. Box k2S, Baytown, Texas
77520 for U.S. Department of Energy under Contract No. Ug-18)-2353. pg. 72.
23. Sittig, M. Petroleum Refining Industry Energy Saving and Environmental Control
Noyes Data Corporation, Park Ridge, New Jersey. 1978.
2k. United States Environmental Protection Agency. 1977- Trace Elements in Coal:
Occurrence and Distribution. EPA-600/7-77-OSA. Illinois State Geological
Survey, Urbana, Illinois.
25- Dravo Corporation. Handbook of Gasifiers and Gas Treatment Systems. Prepared
for ERDA (now DOE) by Dravo Corporation, Pittsburgh, PA. February 1976.
Contract No. FE-1772-11.
26. Fluor Engineers and Constructors, Inc. H-Coal Commerial Evaluation. Prepared
for ERDA (now DOE) by Fluor, Los Angeles, CA. March 1976. Contract No.
FE-2002-12.
27- Electric Power Research Institute. Screening Evaluation--Synthetic Fuels
Manufacture. R.M. Parsons Co. to EPRI, Palo Alto, CA. August 1977.
Report No. AF-523.
28. Barrett, Bruce R., 1978. Controlling the Entrance of Toxic Pollutants in
U.S. Waters. Environmental Science and Technology, 12(2). pp lS^-162.
29. Metzner, Anthony V., 1978. Target: Toxin Removal. Environmental Science
and Technology. 12(5). pp. 530-533.
Ill
-------
APPENDIX A
TABLE OF CONVERSION FACTORS TO SI UNITS
Multiply To Obtain
English Unit by SI Unit
bbl (oil) 0.1590 m3
Btu 1.056 J
Btu/lb 2.328 J/g
°F (°F-32)x5/9 °C
ft 0.3048 m
ft2 0.0929 m2
ft3 0.0283 m3
gal 3.785x!0"3
in 0.0254 m
Ib 453.6 g
lb/106Btu 0.4295 g/MJ
mi 1609 m
psi 6895 Pa
ton 908 kg
112
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA -600/7-79-168
2.
3. RECIPIENT'S ACCESSION NO.
TITLE ANDSUBTITLE
engineering Evaluation of Control Technology for the
H-Coal and Exxon Donor Solvent Processes
>. REPORT DATE
July 1979
6. PERFORMING ORGANIZATION CODE
. AUTHOR(S)
K.R.Sarna and D.T.O'Leary
8. PERFORMING ORGANIZATION REPORT NO.
. PERFORMING ORGANIZATION NAME AND ADDRESS
Dynalectron Corporation/Applied Research Division
6410 Rockledge Drive
Bethesda, Maryland 20034
10. PROGRAM ELEMENT NO.
EHE623A
11. CONTRACT/GRANT NO.
68-02-2601
2. SPONSORING AGENCY NAME AND AODRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 1/77 - 3/79
14. SPONSORING AGENCY CODE
EPA/600/13
5. SUPPLEMENTARY NOTES ffiRL-RTP project officer is Robert A. McAllister, Mail Drop 61,
919/541-2134.
STRACT
report gives results of an evaluation of the control technology of two
coal liquefaction processes, H-Coal and Exxon Donor Solvent. The effluent streams
were characterized and quantified for both processes and plants (pilot and concep-
tualized commercial). The gaseous- j liquid-, and solid-stream emissions were
analyzed for their controllability, process complexity, and efficiency. Extrapolations
to the larger commercial size were based partly on pilot plant data and (where such
data was unavailable) engineering judgment. Several information gaps were encoun-
tered for liquid and solid effluent streams , especially as to composition. These
deficiencies were pointed out and recommendations were outlined. Present control
technology for the H-Coal process seems to be barely adequate: present designs are
inadequate for zero discharge criteria. Control technology for the EDS process
depends on being able to rely on the facilities of an adjacent refinery's controls: the
scalability of present control technologies , especially in the case of the bag filter
operation, is not confirmed.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Coal
Liquefaction
Pollution Control
Stationary Sources
Coal Liquefaction
H-Coal Process
Exxon Donor Solvent
Process
13B
21D
07D
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
122
20. SECURITY CLASS (Thispage}
Unclassified
22. PRICE
EPA Form 2220-1 (»-73)
113
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