INFORMAL  DRAFT:





         DIRECT  LIQUEFACTION

          POLLUTION  CONTROL

          GUIDANCE DOCUMENT,





              CHAPTER 1

                 AND

  CHAPTER 2 (FOR EDS PROCESS ONLY)
            Submitted to:

U.S. Environmental Protection Agency
 Research Triangle Park, NC  27711
                             TRW, Inc.
                             One Space Park
                             Redondo Beach, CA  90278

                             6 March 1981

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CONTENTS
Page
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1—2
1—3
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1-4
1-4
1—5
1—8
1—9
1—9
1—10
1 —11
1—11
1—12
1-14
1—15
1—16
1—17
1-18
2—92
2—92
2—92
2—103
2-103
2—104
2-104
2—105
2-108
2—111
• . 2—111
• . . 2-113
• • . 2-114
1.1 General Description of Liquefaction Processes
1.1.1 Coal Preparation and Handling
1.1.2 Coal Liquefaction
1.1.3 Product Separation, Purification, Upgrading.
1.1.4 Processing of Liquefaction Residue . . . . .
1.1.5 Auxiliary Operations . .
1.2 Analysis Approach and Basis for Material Balances
1.2.1 Direct Liquefaction Process Designs. •
1.2.2 Approach to Process Characterization .
1.2.3 Control Technology Evaluation Methodology. •
1.3 OrganIzation and Purpose of the Direct Liquefaction PCGD.
1.3.1 PurposeoftheDocument. .
1.3.2 OrganlzatlonofthePCGD . . . . . . . . . . . . •
1.4 Use of the PCGD for Permit Review . . . .. . .
1.4.1 Support to Permit Reviews.
1.4.2 Examination of Uncontrolled Gaseous Streams Requiring
Control . . . . . . .
1.4.3 ExamInation of Uncontrolled Wastewater Streams Requiring
Control. . . . . . . . . • . . . . . . . . . . . . . .
1.4.4 Examination Of Solid Waste Discharges
1.4.5 ExaminatIon of Proposed Air Pollution Control Equipment
and Procedures . .
1.4.6 ExamInation of Proposed Wastewater Treatment Equipment
and Procedures . . . .
1.4.7 Examination of Proposed Solid Waste Management Practice..
2. Sources of Waste Streams and Pollutants of Concern
2.2 EDS Process . . . . . . . . . . . . . . . . .
2.2.1 Overall Description of the EDS Process .
2.2.2 Coal Preparation . . . . . . . . . . .
2.2.2.1 Coal Preparation Operations
2.2.2.2 Waste Stream Characterization . . .
2.2.2.2.1 Storage Pile Runoff
2.2.2.2.2 Fugitive Dust Emissions from
Storage Piles. .
2.2.2.2.3 Crushing/Screening Dust
2.2.3 Coal Liquefaction. . .
2.2.3.1 Slurry Drying and Liquefaction
2.2.3.2 Raw Product Separation
2.2.3.3 Waste Stream Characterization
Ii

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                           CONTENTS (Continued)
                                                                        Page

    2.2.4  Product Separation and Purification	2-119
           2.2.4.1  Liquefaction Product  Fractionation	2-119
           2.2.4.2  Solvent Hydrogenation 	   2-121
           2.2.4.3  Sas Treating.	2-122
           2.2.4.4  Product Recovery.  	   2-122
           2.2.4.5  Waste  Stream Characterization  	   2-123

    2.2.5  Processing  Liquefaction Residue/Hydrogen  Production.  .  .  .   2-130

           2.2.5.1  Flexicoking  	   2-130
           2.2.5.2  Hydrogen  Production  	   2-133
           2.2.5.3  Waste  Stream Characterization  	  .  .   2-136

    2.2.6  Auxiliary Operations  	   2-152
           2.2.6.1  Raw Water Treatment	2-152
           2.2.6.2  Steam and Power  Generation	2-155
           2.2.6.3  Cooling Operation 	   2-157
           2.2.6.4  Oxygen Production 	   2-159
           2.2.6.5  Product and  By-Product Storage	2-160

    2.2.7  Fugitive and Transient  Emissions from Plant Operations  .  .   2-163
           2.2.7.1   Fugitive Hydrocarbon Emissions	2-163
           2.2.7.2  Transient Emissions   	  -.  •   2-163
    2.2.8  Summary of Gaseous, Liquid, and Solid Waste Streams.  .  .  .   2-166

References to EDS Process	2-"184
                                     iii

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Li GENERAL DESCRIPTION OF LIQUEFACTION PROCESSES
Direct coal liquefaction processes have a comon objective of
producing liquid, gaseous, and solid products with a higher heat content
and market value than their feed coals. In addition, the product
combustion emissions should be lower in 502, N0 and particulates (per Btu)
than an equivalent heating unit of coal would produce, because of sulfur,
nitrogen, and ash removed in the direct liquefaction process. The generic
steps ich are typical of direct liquefaction plant designs are described
below.
1.1.1 Coal Preparation and Handling
Coal preparation and handling operations are similar to those found in
a pulverized coal—fired power plant. Feed coal is reclaimed from storage
and conveyed to a pulverizing—drying system. Particle sizes from 400 to
3200 micrometers are required for coal liquefaction.
Pollution control requirements for these process steps are also
similar to those typical in a coal—fired power plant, including storage,
crushing and handling dust control, drying and pneumatic conveying
particulate control, and possibly the control of volatile emissions during
drying. Storm water runoff from the coal piles will require treatment.
1.1.2 Coal Liquefaction
The pulverized coal is transferred from silos or storage hoppers
(which require dust recovery) and mixed with a recycle stream of liquid
solvent and hydrogen. The slurry of coal and process-derived solvent is
raised to an elevated temperature and pressure (700°K-755°K and 11.4 to
22.8 MPa) (800—900°F and 1500—3000 psig) prior to entering the reactor.
Various types of catalytic and noncatalytic reactors are used to process
the slurry during the liquefaction stage, where hydrogenation and
hydrocracking of the dissolved coal occurs. These steps take place in
closed systems, so the emissions normally expected from the coal
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liquefaction area of the plant are confined to the reactor preheater
contustion emissions from plant fuel gas or other low-sulfur fuels.
1.1.3 Product Separation, Purification, Upgrading
The liquefaction reactor discharge stream undergoes a series of
pressure reduction steps and separation of lighter and heavier hydrocarbon
products. Different separation and fractionation arrangements are used to
accomplish this objective, but each plant design has two streams leaving
the separation area which require downstream pollution control;
— a light hydrocarbon vapor stream which is contaminated by H S.
CU, CO 2 and traces of other sulfur and nitrogen-based pollu ants
— an aqueous stream which contains a wide variety of organic and
Inorganic pollutants.
Liquid hydrocarbon products from the separation and fractionation
steps may be sent to product storage, or they may be further upgraded. The
hydrocarbon vapor stream must be purified before it is used as plant fuel
or sold. Various physical and chemical absorber operations are used in
different plant designs to absorb the acid gases (H 2 S, C0 2 ) and yield a
purified hydrocarbon gas stream. When the concentrated acid gases are
stripped out of the circulating absorbing medium, they must be treated by
downstream sulfur recovery operations. Typical liquefaction plant designs
use a bulk sulfur removal step (such as the Claus process, followed by one
of the several proprietary sulfur clean—up processes for Claus tail gas
that have been developed for refinery and natural gas applications. Other
pollutants of concern In these tail gas streams include NH 3 , COS, CS 2 , and
possibly HCN and trace organics. Periodic spent catalyst and liquid purge
waste streams will be generated by sulfur recovery.
The wastewater streams discharged from the separation and fraction-
ation operations contain substantial amounts of H 2 S, NH 3 , phenols, and
heavy organics such as tar acids. While specific plant designs may use a
variety of wastewater treatment techniques, H 2 S and NH 3 removal operations
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are usually specific steps. The amonia recovered is salable, but H 2 S
stripped out of the wastewater must be sent to the sulfur recovery area.
Phenol extraction is also a common treatment step, with the phenol
recovered as a byproduct.
Other intermedia transfers that can be generated by wastewater
treatment include biosludges and evaporator brines, representing an
additional solid waste disposal burden.
The product separation areas may be a source of fugitive hydrocarbon
emissions, since the valves that accomplish stagewise pressure let—downs
are in a difficult service and could be subject to leaking.
All of the sulfur and nitrogen—based pollutants are a direct result of
conversion of coal constituents in the liquefaction step. Whatever doesn t
go into the waste streams will go into the products. Product upgrading
options, such as hydrotreating, will generate further wastewater and waste
gas streams.
1.1.4 Processing of Liquefaction Residue
The heaviest hydrocarbon stream is usually recovered from the final
separation steps such as a vacuum distillation. This residue stream
contains unreacted coal and ash as well as highboiling hydrocarbons. One
typical use for this residue is to gasify it, along with oxygen and steam,
to generate a “syngas (H 2 and CO) which can be converted to a high yield
of hydrogen for recycle to the liquefaction reactor. Another approach is
to coke the residue to yield more liquid product. In either case, a solid
ash residue is generated. The syngas generation method will yield a dilute
H 2 S waste gas stream froiii hydrogen purification. A selective absorption
process (e.g., selexol) is often used to concentrate this dilute stream.
1.1.5 Auxiliary Operations
A coal liquefaction plant requires as many auxiliary support
operations as a refinery. If hydrogen for the reaction step is not
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generated from residue gasification, then a conventional refinery method of
steam reforming of light hydrocarbons will normally be used to generate
process hydrogen. If a gasifier is used, then an oxygen plant will be
included in the auxiliary units. There are no polluting emissions from an
oxygen plant, although a steam reformer will generate combustion products.
Steam and power generation boilers also cause combustion emissions.
If low—sulfur liquefaction plant. hydrocarbon products are used as fuel, NO
control may be the primary pollution control concern. Plants which elect
to use coal as a boiler fuel will require conventional coal—fired boiler
controls. Boiler blowdown streams will be sent to standard wastewater
treatment.
Raw water and process cooling water operations require standard sludge
and blowdown treatment. The reuse of process wastewater may require
control of organic vapors in the cooling tower drift.
Product storage in fixed and floating roof tanks is similar to
conventional refinery practice, where tight-sealing tank roof designs,
vapor recovery systems, and other control methods need to be evaluated for
their effectiveness in minimizing vapor emissions from storage and
transfer. The question of handling potentially toxic chemicals needs to be
addressed for worker protection and compliance with TSCA regulations.
1.2 ANALYSIS APPROACH AND BASIS FOR MATERIAL BALANCES
1.2.1 Direct Liquefaction Process Designs
There are four direct coal liquefaction processes that are in advanced
stages of development. These are the Solvent Refined Coal (SRC) processes
I and II (SRC.I and SRC-II), the Exxon Donor Solvent (EDS) process, and the
H—Coal process. Three of these processes (SRC—I, SRC-I.I, and EDS) have
coinnercial designs far enough along to be included in the PCGD basis.
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The current status of these processes are:
• The SRC-1 process is being tested in a 50 tons/day pilot plant at
Fort Lewis, Washington, and in a 6 tons/day process development
unit at Wils oavi1le, Alabama. Preliminary designs for a
demonstration plant, to be located near Ne uan, Kentucky, were
completed in July 1979. The demonstration plant is designed to
produce the equivalent of 20,00U barrels of oil per day, and is
scheduled to be completed by 1984.
• The SRC—II process is also being tested in the pilot plant at
Fort Lewis, Washington. Preliminary designs for a SRC-tt
demonstration plant, to be located at Fort Nartin, West Virginia,
were completed in July 1979, The demonstration plant is designed
to process 6,000 tons of coal per day to produce the equivalent
of 20,000 barrels of oil per day. Completion of the plant is
scheduled for 1984.
• The EDS pilot plant at Baytown, Texas, started up in June 1980.
This plant has a capacity of 250 tons per day of coal feed to
produce approximately 600 barrels per day of synthetic liquid
fuel. A 70 tons per day Flexicoking unit at the same site is
planned to be completed in the second quarter of 1982. The
design of a demonstration plant could begin as early as the
fourth quarter of 1982, leading to a start-up date of about 1988.
The H—coal process commercial design is scheduled for completion
ing the latter part of 1981, which will permit the inclusion of this
process in a subsequent draft of the PCGD. H—coal development status is:
• The H—Coal pilot plant at Catlettsburg, Kentucky, was started up
in June 1980. This plant has a capacity of 600 tons per day of
coal feed. Support work in a 3 tons per day process development
unit is also continuing. Groundbreaking for a comercial plant
in Breckinridge, Kentucky, Is planned for 1983. The commercial
plant is expected to start production as early as 1987.
1.2.2 Approach to Process Characterization
The PCGD methodology uses a baseline design for each process, sized at
100,000 bbls/day net equivalent of product liquids, fuel gases, and
coal—replacement solid products. The design and pilotplant experience of
the several liquefaction processes has been limited to certain types of
feed coals, so that the guidance document recognizes that expected
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• Fugitive hydrocar. from valves, flanges, and seals
• Fugitive hydrocar . s from product and byproduct storage
• Off gas from coal
• Acid gases from so .  ef strippirg units
• Acid gases from acid gas removal units
• Flue gas from process heaters
• Fl ue gas from steam plant
• Fl ue gas from power p1 ant
• Evaporation and drifts from cooling towers
The major wastewater streams requiring control include the following:
• Sour and phenolic process wastewater from vapor washes,
condensers, fractionator overhead drums, sulfur recovery plant,
and coal slurry mixing operation
• Cooling tower blowdown
• Boiler blowdown
• Coal pile runoff
• Oily water runoff from processing areas
• Miscellaneous small wastewater streams
Untreated wastewater characterizations were derived from measurements
conducted by process developers, EPA, and DOE sampling and analysis
efforts. Some judgements were made concerning the effects of coal feed
characteristics and process operating configurations on these measurement
values. Most of these measurements have focused on process wastewater (or
‘ t sour water t1 , fol1owin refinery terminology). Other anticipated sources
of wastewater include coal pile and area runoff, cooling, tower blowdown,
and discharge from dust collection and conveying use. These other
categories are analagous to related discharges from coal handling and other
industrial operations.
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Solid waste discharges will include gasifier slag (from hydrogen
synthesis), spent catalysts, wastewater and raw water treatment sludges,
and possibly non—salable byproduct residues. Some limited amount of
leaching tests have been done to characterize gasifier slags and some
residue material, but more work will have to be done before a determination
can be made as to the probable characterization of these wastes as
non—hazardous or hazardous.
1.2.3 Control Technology Evaluation Methodology
EPA permit reviewers will be faced with a range of possible control
technologies connected with direct liquefaction process designs. To assist
permit reviewers in their examination of submitted plans, a number of
control—technology options are evaluated in the PCGD for each potential
waste stream for three of the four major liquefaction processes. The
evaluation of each control technology includes the efficiency of pollutant
removal from a stream, multipollutant removal capability, Installed and
operating cost, reliability, turndown ratio, sensitivity to process stream
conditions, energy consumption, and any other operating history Information
such as maintenance requirements. The PCGD evaluates combinations of
integrated control technology to establish performance and cost ranges.
An example of the combinations in an integrated control system for the
particular use of sulfur recovery systems is shown in Table 1, using two
bulk—sulfur removal options, three residual sulfur removal options, and a
final incineration step option (for potential trace organic removal and
oxidation of trace sulfur to SO 2 ). -
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TABLE 1. SULFUR REMOVAL SYSTEMS
—
Options
Combinations
Bulk—S
Removal
Beavrn,
Residual-S Removal
Wellman .
SCOT Lord
Incineration
Claus
Stretford
1
.
S
I
2
•
•
•
3
I
S
4
S
S
S
5
5
I
S
5
I
.•
An additional combination is included for streams containing very low
H 2 S (or COS, CS 2 , etc.) concentrations, since these may be directly
incinerated.
Both capital and operating costs are determined according to the
standardized guidelines prepared by IERL/RTP (I). The cost estimates and
performance data were obtained from vendors of pollution control equipment
or from verifiable published sources, using the estimated uncontrolled
stream characteristics from each baseline design case.
1.3 ORGANIZATION AND PURPOSE OF THE DIRECT LIQUEFACTION PCGD
1.3.1 Purpose of the Document
The primary purpose of the PCGD is to provide guidance to permit
writers and permit applicants on the best available control approaches
presently available at a reasonable cost for theprocesses under
consideration. In addition, the document is intended to:
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• Provide system developers with an early indication of EPA ’s
assessment of the appropriate multimedia environmental protection
needs for each of these processes, considering costs, so that
developers can design their facilities to achieve this level of
protection (rather than add more costly retrofit controls later).
I Describe to public Interest groups EPA’s judgment of the best
- available controls for these processes.
• Provide the regulatory offices in EPA with information useful in
helping them develop future technology—based regulations.
EPA intends this PCGD to provide guidance only. This document has no
legal effect, contains no regulations of any kind, and includes nothing
that is mandatory in nature. In publishing this document, the Agency is in
no way establishing a binding norm for permit officials to follow. Rather,
this PCGD leaves permitting authorities free to exercise their Informed
discretion, within applicable law, In choosing control strategies to be
Implemented for each direct liquefaction facility. Permitting officials
should use this document as an aid in their decision—making, not as an EPA
policy to be applied mechanically, for the Agency does not intend the
conclusions reached herein to be viewed as finally determinative of the
issues to which this document is addressed. Furthermore, it is the intent
of this document to promote good faith efforts by facility planners in the
design, operation, and maintenance of environmental controls capable of
meeting the recommended targets specified herein, not to inform such
planners of EPA policy on how permitters should exercise their authority
under current law.
1.3.2 Organization of the PCGD
The Direct Liquefaction PCGD consists of three volumes whose contents
can be sunmarized as follows:
• Volume I describes the technologies, identifies existing
reguIatiohs that apply to the subject technologies, and presents
the control guidance;
• Volume II presents suimnaries of all data employed and discusses
the baseline engineering design, waste stream characterizations
and control option evaluations; and
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• Volume III (Appendices) contains detailed data listings and
calculations supporting the guidance.
This volume (Vohi e I!) is organized in each section by the major
direct liquefaction process technologies (SRC-.I, SRC-II, EDS in this
draft), so that each one is taken in turn to describe their environmental
control needs. Characterization of the various process streams which
require pollution control is addressed in Chapter 2. The identified
constituents of these streams requiring pollution control include both
regulated and non—regulated pollutants. The rationale for selecting
pollutants of concern is presented in Chapter 3. The coamercially
available control options for air emissions, water effluents, and solid
waste discharges are covered in Chapter 4. These are treated on a generic
i sis at the outset, and then integrated control options for each direct
flguefaction process are examined and evaluated frcxn a technical and
economic standpoint.
1.4 USE OF’ THE PCGD FOR PERMIT REVIEW
1.4.1 Support to Permit Reviews
Permitting officials should anticipate that a significant volume of
information and data will be sutmitted with a permit application for a
proposed direct coal liquefaction plant, including process descriptions,
detailed process flow diagrams, tabular data, equipment specifications,
graphs, computer tabulations, and other material. The PCGD can be used as
a checklist for initial permit screening, and subsequently for detailed
examinations such as comparing proposed control technologies to other
options. The use of Volume 2 is described in the following paragraphs;
compact summaries of Volume 2 material (for screening) are found in Volume
- 1, and detailed supporting data (for establishing data confidence, etc.)
are contained in Volume 3.
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1.4.2 taa.lnation of Uncontrolled Saseous Streene Saquiring Control
A typical screening .sinatlan for conpistaness is outlined
below as a %.riei of questions and their relation to sections
of Volume 2 of the PCGD.
luminat$on Question Associated PCGO Sectien4 (Vo)u* 2 )
1) Does .pplicatlon consider SE-Il LOS S*C.l
all sources of potential
atmospheric emissions? Point sources are
suonarized In 1.1.1 1 4.2. 2.2.4 I 4.2.1 2.3.4 1 4.2.1
tnt.rmedia transfers: 4.2.1 4.2.1 4.2.1
fugitive emissions: 2. 1.1 2.2.1 2.3.7
2) Does application consider
all air pollutants of concerni SIC-li 1.0$ SIC-I
Saseous pollutant
quantities (uncontrolled)
are suonaris.d and
Identified far:
Point sources: 2.1.414.2.1 2.2.4 & 4.2.1 2.3.4 14.2.1
intereedla transfers: 4.2.1 4.2.1 4.2.1
Fugitive emissions: 2.1.1 2.2.1 2.3.1
3) i4 w should supplied urea, and The PC D pollutant quantities In the tables cited above for point
pollutant quantities be coaipar.4 sources are based on 100 bbl/day (equivalent oil heating value)
to values Indicated in the PCGD? of all plant products. hase quantities are dir.ct.ly scalable to
the proposed plant pollutant quantitias provided similar coal
co.positlons and product slates are used (i.e.. a proposed 50,000
bbl/day plant would generate approsimately 10% of the PCGI) values).
The non-point source pollutant quantities are more comples to
compare. fvgitlee hydrocarbon emissions are primarily related to
the nuder of leak sources rather than plant size, and the nuller of
potential sources (valves, pump seals coeprasser seals. etc.) is
most strongly connected with the nuder of process trains In a
proposed plant design. The baseline SIC-Il plant used in the PtGD
incorporates two process trains. Some processes (e.g. SIC—I) may
consider five trains. In initial screening assumption Is that the
uncontrolled fugitive hydrocarbon estimate for a proposed plant can
be compared with PCGO estimites on a per-train basis. Uncontrolled
fugitive dust emissions fro. active and reserve coal storage piles
are also not directly proportional to plant size. tomparision of
exposed surface areas in th. proposed plant and the PCGD baseline is
the most useful screening procedure.

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4) Where are these stream, located SRt-lI [ OS — S8C . .I
In the plant?
Comprehensive discussions
of gaseous streams are in
these sections: 2.2.2 to 2.2.2 to 2.3.2 to
2. 1.1 2.2.7 2.3.7
5) How do the pollutant p,antltlts The SRC-ll b .sellne uses a single plant configuration with two
vary with plant configuration, typical teed coals. Th. pollutant quantities for these
feed coal, mode of operation. etc.? conditions are suimearized in Section 2.1.8. Transient emissions are
In 2.1.7.
The (US baseline uses two plant configuration. with one typical feed
coal (for this draft). The pollutant quantities irs stamiarized In
Section 2.2.0. and transient emissions are contilned in 2.2.?.
The SRC-I baseline uses one plant configuration and one typical feed
coal (for this draft).
All baseline cases use process-generated fuel gas for process heater
and boiler fuel to the maximum extent.
6) What Impact do the ausiliary SRC-!I auciliary operations (steam & power generation, cooling
operit Ions hive on plant emissions? operations, oxygen production, product storage) which generate
emissions are covered in Section 2.1.6. The PCGO model plant
assumes that most plant power can be generated from gas or steam
turbine drives, with a minor amount of puchased power.
LOS auxiliary operations are covered in Section 2.2.6. Power
generation Is an SRC-II option which yields emissions typical of a
coal-fired power plant when on- tte generation is selected.
Purchased power is another option.
SRC-I auxiliary operations are covered in Section 2.3.6. Either
coal-tired power generation or purchased power are options.

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1.4.3 tea.ination of Uncontrolled Wastewater Streame he iring Control
temeinatlen question Associated PCGO Sections (Vol. 21
I) Does spIication consider all SIC-Il [ 05 SIC-I
sources of potentical wastiwater
effluents? Point sourc.s are
Suomarited in: 2.1.8 $ 4.3.1 2.2.8 1 4.3.1 2.3.8 £ 4.3.1
intermedia Transfers: 4.3.2 4.3.2 4.3.2
2) Does q plicatIen consider all SIC-Il LOS SRC.l
water pollutants of concern?
Water pollutant quantities
(Uncontrolled) are suamarlied
and identified for:
Point sources: 2.1.8 $ 4.3.1 2.2.8 £ 4.3.1 2.3.8 $ 4.3.1
Intermedi. lransl,rs: 4. 1.2 4.3.2 4.3.2
3) 1 10w should supplied streaa and The PC00 pollutant quantities cited above for point sources are
pollutant quantities be compared based on 100,000 bbl/day (equivalent oil heating value) of all plant
to values ied lcat.d in the PCIZI7 products. These quantities are directly scalable to the proposed
plant pollutant quantities, provided similar coal compositions and
product slates are used. (i.e., • proposed 50,000 bbl/day plant
would generate appqosi.ately 501 of the PCGD values.
4) Where are these strea.s located SIC-Il LOS SIC-i
in the plant?
Comprehensiv, discussions 2.1.2 2.2.2 2.3.2
of wastewater streams are to to to
contained in these section: 2.1.6 2.2.6 2.3.6
5) 110w do the pollutant quantities The S iC-Il baselin, uses a single plant configuration with two
vary with plant configuration, typical feed cases. The pollutant quantities for these
feed coal. aode of operation, etc.? conditions are sumearized in Section 2.1.8. Th chief wastewater
variation will be caused by water reuse decisions, which are
esamined in 4.5.2. Coal pile and area runoff ar. assumed to be
collected for subsequent treatment, so they are not transient
streams.
The LOS baseline uses two plant configurations with one feed coal
(for this drift). The pollutant quantities for these conditions are
summarised in Section 2.2.8. Reuse and runoff handling are the same
as the SIC-Il baseline, as covered in 4.6.2.
The SIC-I baseline uses on. plant configuration and one feed coal
(for this drift). Reuse and runoff handling are the same as the
SIC-Il baseline, as covered in 4.7.1.
6) What impact do the •usiliary IffluentS from SIC—Il •usiliary operations include blowdown streams
operationt have on plant from raw water treatment, boilers, and cooling operations as
e lflupnts? discussed in Section 2.1.6.
Effluents from LOS austli.ry operations include blowdown streams
fro. raw water treatment, boilers, and cooling operations as
discussed in SectIon 2,2.6.
Effluents from SIC-I ausiliary operations include blowdown streams
from raw water treatment, boilers, and coolinq operations as
discussed in Section 2.3.6.

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1.4.4 Esemination of Solid Waste Discharges
Isamination question Associated PCGD Sections (Vol. 2 )
1) Does application consider all SRC..Ii EQS
sources of solid wastes requiring
disposal? Point sources and
guintities are
suasnarized in: 2.1.8 $ 4.4.1 2.2.8 & 4.4.1 2.3.8 8 4.4.1
Intermedia transfer
quantities: 4.4.2 1.4.2 4.4.2
2) Vow should supplied solid waste The PCGD Solid waste quantities cited above are based on a plant
stream quantities be compared to producing 100,000 bbl/da 7 (equivalent oil heating value) of all
values Indicated in the PCIID? plant products. Although some of the siuall.r solid w sts straCel
(e.g.) blosludges) are approsimitely proportional to production
rate, the largest iolid waste stream comes from unconverted or very
heavy coal conversions products (either directly or as ash from
gasification). The baseline plants are based on an I$%aMd thermal
coal conversion as follows:
55C-i1 71%
LOS 66%
SPC-I 60%
Proposed plants may differ significantly from these converSion
percentages.
3) Where are these Streams discharged SRc-It ros SRC.I
in the plant?
Comprehensive discussions 2.1.2 2.2.2 2.3.2
of solid waste streams are to to to
contained in these Sections: 2.1.1 2.2.1 2.3.1
4) Vow do the solid waste quantities the SRC-il baseline uses a single plant configuration with two
vary with plant configuration, typical feed coals. The solid waste quantities for these con-
feed coal, mode of operation, etc.? ditions are suii.arlzed in Section 2.1.8. The other variations are
caused by interimedla transfers, such as a brine discharge from
wastewater evaporation when this option is selected. (Section
4.4.2)
The LOS baseline uses two plant configurations, with one feed coal
(for this draft). The solid waste discharges for th,s conditions
vary, since one involves a gasification step and tile other doet not.
these quantities are suaasarized in Section 2.2.8. Intermedi,
transfers are covered in Section 4.4.2.
The SRC-I baseliina uses one plant configuration with one feed coal
(for this draft). The solid waste discharges are sunnsarized in
Section 2.3.8, md intermedi transfers are covered In Section
4.4.2.
5) What Impact do the eusiiiary Sludges from raw water treatment and product storage, and collected
operations huve on solid waste ash from boiler operations are covered in 2.1.6 for SRC-iI.
di tc ha rqes 7
Sludges from raw water treatment and product storage, and collected
ash from boiler operitions are covered in 2.2.6 for LOS.
Sludges from raw water treatment and product storage. and collected
ash from holler operitions are covered in 2.3.6 for S 1 1C-l.

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1.4.5 ( vaeination of Proposed Air Pollution Control Iguipment and Proc.dur.t
A typical screening esamination of proposed air poluatlon controls is
outlined below, such as might be done for a PSI) permit application.
( saminstion question Associated PCGI) Sections (Vol. 2 )
I) Doet the control efficiency
indicated in the application
compare reasonably with
independent data sources? Is
It backed up by supplier
guarantees?
2) Will trace quantities of other
pollutants be r.moved by, or
are cited in the teat.
interfere with the proposed
control system?
3) Is the proposed control systim
reliable? Will it maintain Its
claimed efficiency throughout
an operating year?
4) Is th, proposed control system
SAC?? If not. an there other
options id ich can be considered?
5) If an alternative control system
was used. what would be the
Impact?
6) 140w do each of the proposed
control technologies fit
together as an integrated
facility?
-4
-4
Section 4.2.2 covers the control efficiency ranges for a ntmiber
of candidate controls for similar streams, taken from related
applications. Tables 4-9. 4-13, 4-IS. 4.19, and 4—20 list
thes, data, together with some typical guarantees wher. applicable.
Multipollutant removal capability is indicated in Table 4-9 and 4-13
in Section 4.2.2 for sulfur recovery processes. Potential inter-
ferences are cited in the tent.
The PCI does not provide quantitative reliability figures. but
Section 4.2.2 describes methods used in practice for increasing
air pollution control systems reliability.
Volume 2 of the PCGI) does not rate control systems as SAC?; a
number of candidate control systems are covered in the analysis
of Section 4.2.2, and their comparative performance estimated from
r,lated industry track records.
The capital, operating, and annualized costs of control options are
summarized in Section 4.2.2 for the different streams associated
with the SAC-Il. LOS. and SAC-I baseline plants. Although an
engineering analysis is necessary to assess the impact of using
alternative control system, relative costs can be compared foni, the
PC GD.
Control options in Integrated facilities are covered in section 4.5.
The point of introduction of individual streams into a train of
control units will depend on the types and quantities of pollutants
contained in each stream.

-------
1.4.6 ( naminat ion of Proposed Wistewater Treat nt Igulp*nt and Procedures
A typical screening eaaiain.tien of proposed wasteweter treatm.nt is
outlined below, such is might be done for an NPDIS permit applicition.
( smainatlon question
I) Does the control efficiency
indicated in the application
compare reasonably with
ipdependent data sources? Is
it backed up by supplier
guarant net?
2) Will trace quantities of other
pollutants be removed by, or
interfere with the proposed
control system?
3) Is the proposed control syste.
reliable? Will it maintain its
claimed elf iciency througbaut
an operating year?
4) Is the proposed control system
SAC ?? If not. are there other
options ebich can, be considered?
5) II an alternative control system
wit uSed. wi at would be the
impact?
6) Now do each of (ha proposed
control technologies fit
together as an integrated
facility?
Section 4.3.2 covers the control efficiency ranges for C number
of candidate controls for tidier streams, talon from rilitid
applications. Table 4-24 lists these data, together with some
typical guarantees where applicable.
Peiitipollutlflt removil capability is indicated In Table 4-24 In
Section 4.3.2. Potential Interferences are cited in the text.
The PCGO does not provide quantitative reliability figures, but
Section 4.3.2 describes methods used In practice for iflcreising
air pollution control systems reliability.
Volime 2 of the PC( does not rate control systems as SACT; a
number of candidate control systems are covered in the analysis
of Section 4.3.2, and their comparative pertoraance eitl.atel trc
related industry tract records.
The capital operating, and innualized coSts of control options are
suaiaarized in Section 4,3.2 for the different streams AsSOciated
with the SAC-li. (OS, and SAC-i baseline plants. Although an
engineering analysis is necessary to assess the impact of using
alternative control system, relative costs can be compared form the
‘(GO.
Control options In Integrated facilities are covered in section 4. 5.
The point of introduction of individual streams into a train of
control unite will depend on the types and quantities of pollutants
contained in each stream.
Associated PCGII Sections (Vol. 2 )
-J
- J
-4

-------
03
1.4.7 tna.inatioi, •t Proposed Solid Waste Nanagent Practice
A typical screening eea.inition c i a proposed saud waste
management plan Is outlined b, low, such as. might be done
for a RCIA application for permit.
tualnat ion Quest ion
• I) Is the proposed management
practice PACt for each waste?
2) Within each waste catagoq
what are the ipp.cts at
choosing other options?
Associated PC O Sections (V.1, 2 )
V.Ii.. 2 ci the PCPO does not rate management practices as PACT;
but the requirements for hazardous and non-hazardous wastes are
distinctly covered in Section 4.4.2. and th. hazard catagory of each
waste oust be determined on a case-by-case basis.
Costs are cited in Section 4.4.2 for each management practice
covered, and the intar..dia transt.rs associated with various
options are identified in Section 4.5.3.
AtFIPINCES fl* CHAPlIN I
I. A Standard Procedure for Cost alysis •f Pollution Control ( arations (Vol. I $ 2
tPA-oooje-is-oia , June 157$.

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2. SOURCES OF 3LLUTANTS OF CONCERN
rn tids chapter, the proc . xiliary operations associated with
direct coal liquefaction and the cn n ::eristics of uncontrolled waste
streams resultfrsg froii these operations are described. The material
presented is used as input in evaluating environmental control options.
For discussion purposes, the process operations covered are divided into:
coal preparation, coal liquefaction, product separation/purification!
upgrading, and processing of liquefaction residue/hydrogen production
plant. Auxiliary operations covered are divided into: raw water treat-P
ment, steam and power generation, cooling system, oxygen production, and
product/byproduct storage. Fugitive and transient emissions are covered in
an individual subsection.
2.2 EDS PROCESS
2.2.1 Overall Description of the EDS Process
The Exxon Donor Solvent (EDS) is a non—catalytic process that
liquefies coal by the use of a hydrogen donor solvent obtained from coal-
derived distillate. The donor solvent transfers hydrogen to the coal, thus
promoting the liquefaction of coal.
The base case configuration for the EDS process, designed to maximize
the production of C 4 + liquids, is sho m schematically in Figure 2-7. The
major processing areas consist of coal crushing, coal liquefaction, solvent
hydrogenation, solvent recovery, Flexicoking to process liquefaction
residue, cryogenic hydrogen recovery, hydrogen generation by steam
reforming, amonia synthesis, and light ends processing. Auxiliary
operations shown include raw water treatment, steam generation, power
generation, cooling system, oxygen production, and product/byproduct
storage. Pollution control operations such as sulfur recovery, amonia
recovery, phenol extraction, and wastewater treatment are also included in
the block flow diagram to indicate the flows of waste streams into various
treatment areas.
2-92

-------
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-------
In the EDS process (62,68,69), raw coal is crushed, dried, and
slurried with the recycle donor solvent. The slurry is heated by a
fired—heater, and preheated hydrogen is added. The slurry, together with
hydrogen, are then fed to a liquefaction reactor operated at 700-756 0 K
(800—900°F) and 13.9 MPa (2000 psia).
The reactor effluent is separated In a vapor—liquid separator and
several distillation steps into a recycle solvent depleted of its donor
hydrogen, light hydrocarbon gases, a C 4 —1000°F distillate, a heavy vacuum
bottoms stream comprised primarily of unconverted coal and mineral matter.
The recycle solvent Is hydrogenated in a fixed bed catalytic reactor.
The heavy vacuum bottoms from distillation are fed to a Flexicoking
unit with air and steam to produce additional distillate liquid products
and a low Btu fuel gas for process furnaces. In the Flexicoking unit,
essentially all organic material In the vacuum bottoms is recovered as
liquid product or combustible gases. A small amount of residual carbon is
rejected with the ash from the gasifier fluidized bed.
Hydrogen for In-plant use Is produced by steam reforming of light
hydrocarbon gases. The method for hydrogen production is the major
difference between the base case design and an alternate design, the Market
Flexibility Sensitivity (MFS) case.
The f S design for the EDS process Is shown schematically in Figure
2—8. In the MFS design, hydrogen is produced by partial oxidation of about
50 percent of the vacuum bottoms Instead of steam reforming of light
hydrocarbon gases as In the base case. The light hydrocarbon gases
released by elimination of steam reforming are then to be sold as pipeline
gas. The remainIng 50 percent of the vacuum bottoms are fed to a
Flexicoking unit to produce low Btu gas for plant fuel.
The coal feedstock selected for examination in both the base case and
the tfS case designs Is an Illinois No. 6 coal. This coal was selected
because It Is the design coal for the 1975/1976 EDS convnercial plant study
design (61), and subsequent updates of the EDS commercial plant study
2-94

-------
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-------
design (62,63,64,65). Illinois No. 6 coal has also been extensively tested
by Exxon Research and Engineering Company (ER&E) In the laboratory, and
considerable amount of process and waste stream characterization data are
ay.ailable.. The second coal feedstock originally selected for examination
is a Wyoming coal with low sulfur content. However, work on the Wyoming
coal design studies has been temporarily tenTilnated by ER&E, and data
needed to characterize the uncontrolled waste streams are not currently
available. As a result, a Wyoming coal case is not included. Data on the
composition of the Illinois No. 6 coal are presented in Table 2-54. In
Table 2-55, data on the trace element contents of the Illinois No. 6 coal
are presented. These data were used in the estimation of the LOS process
and waste stream characteristics.
For purposes of analysis, a plant size corresponding to 633 TJ per
stream day (equivalent to 100,000 barrels per stream day, assuming 6
million Btu per barrel) of net products has been selected. This capacity,
although 56 percent larger than the ER&E base case and 3]. percent larger
than the ER&E MFS case coimnercial plant designs, is envisioned to be
representative of typical first U.S. comercial direct coal liquefaction
facilities. For commercial plants of this size, the EDS product slates for
the base case and MFS case are given in Table 2—56.
A listing of the waste streams and selected process streams for the
EDS commercial plant is provided In Table 2-57. The stream numbering
system used is consistent with the numbering system in the ER&E EDS
commercial plant designs (62,63,64,65). In this system, the first digit of
the 3—digit stream number Indicates the process area (e.g., 100 for coal
liquefaction) from which the stream is originated.
2-96

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TABLE 2-54. CHARA OF EDS COAL FEEDSTOCK
ILLINOIS t . COAL
Dry “As Received”
Coal Composition Wt % Wt %
C 69.9 58.2
H 5.2 4.3
0 (By difference) 10.1 8.4
N 1.2 1.0
Pyritic 1.2 1.0
S Sulfate 0.1 0.1
Organic 3.1 2.6
Cl 0.1 0.1
Ash 9.1 7.6
Water 16.7
TOTAL 100.0 100.0
wt S
Ash Composition S03 Free
1.08 1.10
Si0 2 51.64 52.29
Fe 2 0 3 19.37 19.61
A 1 2 0 3 18.17 18.40
Ti0 2 .87 .89
CaO 3.15 3.19
MgO 1.23 1.24
503 1.57
K 2 0 2.19 2.22
Na 2 0 1.07 1.08
TOTAL 100.34 100.02
Data source: Reference 62.
2—97

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TABLE 2-55. TRACE ELEMENT CONCENTRATIONS OF EDS ILLINOIS NO. 6 COAL
Trace
E ement
Wt
of
%
Ash
Trace
Element
Wt
of
%
Ash
Al 9.74 Mg 0.748
As 0.0050 Mn 0.0447
B 0.114 Mo 0.0078
Ba 0.0936 Na 0.801
Be 0.0013 Ni 0.0185
Br 0.0126 p 0.480
Ca 2.28 Pb 0.0228
Cd 0.0034 Rb 0.0135
Ce 0.0110 Sb 0.0008
Cl 1.35 Sc 0.0022
Co 0.0056 Se 0.0019
Cr 0.0169 Si 24.4
Cs 0.0010 Sm 0.0010
Cu 0.0110 Sn 0.0040
Eu 0.0002 Sr 0.0304
F 0.0531 Ta 0.0001
Fe 13.7 Th 0.0019
Ga 0.0026 Ti 0.534
Ge 0.0047 11 0. 0006
Hf 0.0004 Ii 0.0013
Hg 0.0002 V 0.0278
K 1.84 Zn 0.354
La 0.0059 Zr 0. 0438
Data source: Values for Al, Ca, Fe, K, Mg, Na, P, Si, and Ti are based on
ER&E EDS commercial plant design data (62). Values for other trace
elements were from Illinois No. 6 coal analysis determined by Glushotor, et
al. (82).
2-98

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TABLE 2-56. NET : uci SLATES FOR LOS COMMERCIAL PLANT
(STREAM DAY BASIS)
Net Product
Base
Case
MFS Case
Pipeline Gas
-——
2.263
Sq
(2,604,000
Nm 3 )
C 3 LPG
C 4 LPG
Naphtha
0.367
0.353
4.482
Gg
Sq
Gg
(721 in 3 )
(610 in 3 )
(5,866 in 3 )
0.444
0.306
3.692
Gg
Gg
Sq
(873 in 3 )
(530 m 3 )
(4,832 m 3 )
Fuel 011
9.389
Gg
(9,132 m 3 )
7.569
Gg
(7,355 m 3 )
Sulfur
1.416
Gg
1.169
Gg
An ionia
0.362
Sq
0.188
Gg
Crude Phenols
0.092
Gg
(85 m 3 )
0.077
Gg
(71 m 3 )
Data source: Reference 83.
Product Property Basis
Pipeline Gas 63.0 vol S methane, 22.3 vol 5 C,, 2.7 vol %
C + hydrocarbons, 5.4 vol S N 2 , .4 vol S H 2 ,
a d 3.2 vol S CO.
C 3 LPG 95.8 wt S C 3 , 0.9 wt S C 2 -, 3.3 wt S C 4 +.
C 4 LPG 95.1 wt S C 4 , 3.2 wt S C 3 -, 1.7 wt S C 5 +.
Naphtha Petanes to 350°F normal boiling range; contains
0.43 wt S sulfur and 0.06 wt S nitrogen.
Fuel QU 13.O wt S C /400°F, 34.0 wt S 4OO/7 O°F, 29.1
(Base Case) wt S 7OO/10 0°F, and 17.9 wt S 1000 F+; contains
0.54 wt S sulfur and 0.77 wt S nitrogen.
Fuel Oil 19.2 wt S C /400°F, 35.2 wt S 400/7 2 0°F, 31.6
(MFS Case) wt S 700/10 0°F, and 14.0 wt 5 1000 F+; contains
5.1 wt S sulfur and 0.75 wt S nitrogen.
2- gq

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TABLE 2-57. LISTING OF WASTE STREAMS AND SELECTED PROCESS STREAMS
FOR THE EDS COMMERCIAL PLANT
*
Stream No. Stream Description
Run of mine coal
Coal feed to slurry dryer
Liquefaction cold separator sour gas
Atmospheric fractionator off gas
Vacuum bottoms slurry to Flexicoking
Vacuum bottoms slurry to partial oxidation unit
Solvent hydrogenation cold separator vapor
Solvent hydrogenation fractionator sour gas
Flexicoking gasifler/heater sour gas
Flexicoking fractionator off gas
Sweet gas from DEA scrubbing
Uncontrolled Discharge Streams from Process Operations
Fugitive dust from coal pile
Coal pile runoff
Fugitive dust and
Slurry drier vent gas
Slurry drier cold separator wastewater
Liquefaction cold separator wastewater
Flue gas from liquefaction slurry preheat furnace
Solids accumulated in the slurry drier
Atmospheric fractionator overhead drum wastewater
Vacuum flash off gas
Vacuum flash wastewater
Partial oxidation feed vacuum flash off gas (MFS
Partial oxidation feed vacuum flash wastewater
(MFS case only)
Flue gas from partial oxidation feed vacuum flash preheat
furnaces (MFS case only)
Solvent hydrogenation cold separator wastewater
flue gas from hydrogenation fuel preheat furnaces
Spent hydrogenation catalyst
Solvent hydrogenation fractionator overhead drum
wastewater
Flexicoking
Flexicoking
Fl exicoking
Flexi coking
Flex Icoking
Flexicoking
Fl exicoki ng
—Continued-
Process Streams
010
101
104
151
159
160
200
251
304
310
406
particulate from coal handling and crushing
011
012
013
102
103
106
107
108
152
153
155
156
157
161.
202
203
204
252
302
303
306
307
308
312
313
case only)
gasifierfheater dry fines
gasifier/heater wet fines
heater bed coke
recontacting drum wastewater
fractionator overhead drum wastewater
heater overhead drum wastewater
heater chunks/agglomerates
2-100

-------
TABLE 2-57 (Continued)
Stream No. Stream Description
403 Knockout drum wastewater in H 2 cryo recovery
404 Spent hydrotreater catalyst in H, cryo recovery
405 Spent drying agents in H, cryo rkovery
426 Vent gas from CO 2 removal by Catacarb process
(base case only)
428 Acid gas from acid gas removal unit in hydrogen
purification (MFS case only)
430 Blowdown and (.0. drum wastewater from hydrogen
generation (base case only)
43]. Catacarb overhead receiver wastewater in hydrogen
generation (base case only)
433 Spent sulfur guard in hydrogen generation
(base case only)
434 Flue gas from hydrogen plant reformer furnaces
(base case only)
435 Spent reformer catalyst in hydrogen generation
(base case only)
436 Spent shift catalyst In hydrogen generation
(base case only)
438 Hydrogen plant deaerator vent
439 Spent methartation catalyst in hydrogen generation
(base case only)
440 Flash gas from partial oxidation unit (MFS case only)
441 Sour water from partial oxidation unit (FlfS case only)
442 Slag from partial oxidation unit (MFS case only)
443 Slag filtrate from partial oxidation unit
(MFS case only)
444 Spent high temperature shift catalyst in hydrogen
generation (MFS case only)
445 Spent low temperature shift catalyst in hydrogen
generation (MFS case only)
446 Regeneration/decommissIoning off-gas from reformer
catalyst (base case only)
447 Regeneration/deconvulssioning off-gas from shift
conversion catalyst (base case only)
448 Regeneration/decommissioning off-gas from methanation
catalyst (base case only)
449 Regeneration/decommissioning off-gas from high temperature
shift conversion catalyst (MFS case only)
450 Regeneration/decommissioning off-gas from low temperature
shift conversion catalyst (MFS case only)
451. Aqueous ammonia from ammonia synthesis (base case only)
452 Knockout drum wastewater in ammonia synthesis
(base case only)
453 Spent drying agents in ammonia synthesis (base case only)
454 Spent ammonia synthesis catalyst (base case only)
—Continued-
2-101

-------
TABLE 2-57 (Continued)
Stream No. Stream Description
a
508 Acid gas from DEA unit
801 Transient waste gas from Flexicoking (MFS case only)
802 Transient waste gas from partial oxidation unit
(MFS case only)
803 Transient waste gas from liquefaction
901 Low quality rain runoff
Uncontrolled Discharge Streams from Auxiliary Operations
702 Blowdown from steam generation system
703 Fly ash from steam generation system
704 Bottom ash from steam generation system
706 Ash pond overflow from steam and power generation systems
108 Blowdown from power generation system
709 Fly ash from power generation system
710 Bottom ash from power generation system
722 Clarifier sludge from raw water treatment
723 Regeneration wastes from water demineralizatlon
731 Drift and evaporation from cooling tower
732 Cool ing tower bi owdown
751 Evaporative emissions from product storage
Discharge Streams from Pollution Control Operations
429 CO 2 rich vent gas from H,S removal/sulfur recovery unit
in hydrogen generation (MFS case only)
501 Acid gas from sour water strlpping/aninonia recovery
502 Phenol ic wastewater from amonia recovery
504 Wastewater from phenolic extraction
510 Tall gas from sulfur plant
512 0ff gas from sulfur plant tail gas treatment unit
514 Incinerator stack gas from sulfur plant tail gas
treatment unit
515 Sour water from sulfur recovery plant
516 Sour water from sulfur plant tall gas treatment unit
517 Spent sulfur plant catalyst
518 Spent sulfur plant tail gas treatment unit catalyst
521 Effi uent from wastewater treatment
522 Reclaimed water for reuse
523 Oily sludge from wastewater treatment
524 Biological sludge from wastewater treatment
701 Flue gas from steam generation system
705 FGD sludge from steam generation system
707 Flue gas from power generation system
711 FGD sludge from power generation system
741 Flue gas from combustion of slurry drier vent gas
and vacuum flash off gas
2-102

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2.2.2 Coal Preparation
The amount of coal handled by the coal preparation plant was
determined by assessing the power boiler and feed reactor coal
requirements. These are listed in Table 2-58. Plant fuel requirements to
produce process steam were assumed to be internally met by plant products
and by-products.
TABII 2-58. COAL FEED REQUIREMENTS - EDS PLANT
Unit
Illinois Coal
Base Case,
Mg/hr
Market Flexibility
Sensitivity (MFS)
Case, Mg/hr
Feed
Reactor
1,760
1,485
Power
Boiler
95
150
Steam
Boiler
65
130
2.2.2.1 Coal Preparation Operations
Coal is received five days per week from three mines. The run-of-mine
(ROM) coal is brought in from nearby mines by conveyor belt and from
distant mines by train. The throughput of coal through the various units
varies for the Illinois Coal Base case and the MFS case.
A common conveyor is utilized to transfer coal from the incoming
nearby mine conveyor and coal received via railcar unloading facilities to
the stacker—reclaimer area (live storage). If the reclaimer is out of
service, coal from the live storage piles is transferred by mobile
equipment to a dump hopper on the conveyor feeding the crushers.
Similarly, dead storage is reclaimed by mobile equipment and dumped into
the dump hopper and then moved through the plant in the normal fashion.
2-103

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The Incoming coal Is stored in two stockpiles with a combined storage
capacity of 5 days of process feed. Two tripperstackers are used to stack
the live storage piles. A 30—day dead storage pile is built up and
retained.
A crawler-mounted reclaimer is used to reclaim the stored coal (24
hrs/day, 7 days/week) at varying rates. A surge storage silo is provided
downstream of the stock piles. This eliminates flow rate surges and allows
equipment stoppages upstream of It without affecting process feed to the
liquefaction trains.
Three 50% crushers (455 Mg each) are provided downstream of the surge
silo. The crushers reduce the reclaimed ROM coal from 90% minus 1” to 95%
minus 8 mesh. The crushed coal Is then elevated in enclosed belt conveyors
to a distribution bin, which divides the total flow of crushed coal into 8
streams to feed the 4 driers. Eight gravimetric feeders (2 per slurry
drier) are located directly under the distribution bin to control coal feed
to the slurry driers. A flow chart of the coal handling system and feed
rates are provided in Section 2.2.2.2.3.
2.2.2.2 Waste Stream Characterization
The major waste streams associated with the coal preparation
operations are storage pile runoff, fugitive emissions from coal storage,
and fugitive particulates fran coal processing.
2.2.2.2.1 Storage Pile Runoff— —
In the literature, storage pile runoff has not been chemically
characterized because of lack of specific data. However, effluents from
some coal storage piles comprised of high sulfur coal have been analyzed.
4n addition, laboratory leaching tests done at Los Alamos Scientific
Laboratories have shown that types and quantities of pollutants released
f ran coal storage piles are similar to those from coal refuse (31).
2-104

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In general, coal from eastern sources has been found to have a highly
acidic waste stream with pHs ranging from 2.2 to 3.1. Total suspended
solids concentrations are generally low during base flow periods but
increase dramatically during storm runoff to levels as high as 2300 mg/i.
Sulfate concentrations are also c jite high with ranges from 1800 to 9600
mg/i. Concentration of iron and manganese are both very sigh ranging from
23 to 1800 mg/i and from 1.8 to 45 mg/i, respectively. Other elements of
potential concern include aluminum, mercury, arsenic, and zinc.
Estimates of the amount of runoff produced at the coal storage sites
as a result of a 10 year, 24—hour storm (refer to Table 2-59) were
determined as follows. The surface area covered by the 5-day and 30-day
storage were calculated based on a pile height of 15.2 m (50 ft) and a bulk
density of 1.153 Mg/m3 (72 lb/cu ft). The storage pile was assumed to be a
truncated cone with an angle of repose of 350• Annual and 10-year, 24—hour
storm rainfall values for Southwestern Illinois were obtained from the
Rainfall Frequency Atlas of the U.S.
2.2.2.2.2 Fugitive Dust Emissions from Storage Piles- —
The quantities of fugitive particulates generated by the 5-day and
30—day storage piles were estimated using methodology described in
Reference 33. The four major sources of fugitive particulate emissions
are: loading onto piles; equipment and vehicle movement in storage area;
wind erosion, and loadout fran piles. Emission rates from these sources
are dependent on the turnover rate for the pile, methods for adding and
removing material, and the pile configuration.
Fugitive emission estimates were calculated using several different
formulas (33) and are presented in Table 2-60. These formulas which are
described in Appendix F include correction factors which account for such
parameters as activity on and around storage piles, silt content of
material stockpiled, duration of storage and average surface moisture in
different geographic areas.
2—105

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TABLE 2- 59 AVERAGE AND 10-YEAR, 24—HOUR STORM RUNOFF
FROM 5—DAY WET STORAGE PILES AT THE EDS PLANT
Coal Type
Base Case
MFS Case
Quantrty of coal j *
5 day storage (Mg)
230,400
211 ,800
Storage pile volume ( 3)
199,800
183,700
Ground area covered 2
by storage pile (m )
17,770
17,110
10—year, 24—hour storm
runoff (m 3 )
1,660
1,600
Average daily runofftt (m 3 )
118
114
FROM 30-DAY
DEAD STORAGE
PILES
AT
THE
EDS PLANT
Coal Type
Base Case
MFS Case
Quantity of coal in *
30 day storage (Mg)
1,382,400
1,270,800
Storage pile volumet Cm 3 )
1,199,000
1,102,200
Ground area coveredl 2
by storage pile (m )
89,800
83,000
10-year, 24—hour --
storm runoff (m 3 )
8,370
7,740
Average daily runoff
600
550
*
Based on 24 hours per day
Based on 1.153 Mg/rn 3 bulk density
Based on a covered radius of 76 m.
lOayear, 24-hour rainfall In Southwestern Illinois was assumed to be
5 inches
Annual rainfall in Southwestern Illinois was assumed to be 40 inches.
2—106

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TABLE 2-60
UNCONTROL : DUST GENERATION
5—DAY COAL T r - PILE (Ma/vr)
Illinois #6
Type Coal
Base
MFS Case,
Activity
Case, Mg/yr
Mg/yr
Wind Erosion a
29.5
27,1
Loading On b
87.9
80.3
Loading o b
112.5
103.4
Vehicular Activity
b
0.16
0.15
TOTAL
230.06
211.45
30—DAY
COAL
STORAGE PILE (Mg/yr)
Activity
Illinois #6
Type Coal
Base
Case, Mg/yr
MFS Case,
Mg/yr
Wind Erosion a
176.9
162.7
Loading On b
87.9
80.8
Loading Off b
112.5
103.4
cu1ar Activity
b
5.8
5.3
TOTAL
383.1
352.2
a
Based on a respirable emission factor of 6.4 mg of dust per Kg/yr of coal
stored (Ref. 5). Since respirable emissions represent only 5 percent of
total particulate emissions, a correction factor of 20 has been applied.
b Emission factor formulas used were obtained from and are described in
Appendix.
2—107

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2.2.2.2.3 Crushing/Screening Dust- —
Coal crushing/screening data are available from surface coal mining
And ore mining operations, the crushed stone, and the manufacturing of coke
Industries. The published data on particulate emission factors for coal
operations is limited. The emission factors that are available are
Inconsistent. One study lists an average uncontrolled emission factor of
0.2 kg/Mg of coal processed for loading and unloading activities in all
modes of transport while another study (34) lists emission factors of 0.05
kg/Mg and 0.01 kg/Mg of coal mined for coal loading and unloading
operations respectively. The emission factor used in deriving emission
rates presented in Table 2-61 are intended to provide approximate emissions
generated during the specific operations. The streams associated with the
estimated emission values are shown in Figure 2-9.
In the absence of more specific data several simplifying assumptions
were made. No modification to the emission factor was made to correct for
the moisture content of the coals. Nonparticulate emissions in the
pulverizer/dryer off-gases were assumed to be negligible.
The storage silos and lockhoppers require a continuous purge with
inert gas to prevent spontaneous combustion. This continuously moving gas
stream will entrain sane particulates. An emission factor for this type of
operation was not available, so emissions were assumed (conservatively) to
be the same as for a transfer operation.
2-108

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TABLE 2- (1.
FUGITIVE PARTICULATE EMISSIONS FROM LOADING, UNLOADING
TRANSFER, AND CRUSHING OF COAL - (OS PLANT
IllinoIs #6
Average
Factors
Fe
(as
Base Case
ed Rate Uncontrolled
received Emission
basis) Rates
Mg/hr kg/hr
MFS
Case
Uncontrolled
Emission
Rates
kg/hr
Stream
No.
Particulate Estimated
Emission Emission
Source Uncontrolled
kg/Mg
Fe
(as
ed Rate
received
basis)
Mg/hr
Reference
1
‘
Unloading
0.2
92
1000
200
1000
200
2
Unloading
0.2
92
1000
200
1000
•
200
3
Transfer
0.1
93
1920
192
1765
176.5
4
Transfer
2 (0.10)
93
2800
560
2500
500
5
Loading
0.2
92
2800
560
2500
500
6
UnloadIng
0.2
92
1920
384
1765
353
7
Crushing*
0.04
93
1920
76.8
1765
70.6
8
Transfer
0.1
93
1920
192
1765
176.5
9
loading
0.2
92
1920
384
1765
353
10
Unloading
0.2
92
1920
384
1765
353
11
Transfer
0.1
93
1760
176
1485
148 ,5
12
Transfer
0.)
93
1760
176
1485
148.5
F ’)
-J
Q
‘.0
* Emission factors are reported for combined “secondary crushing/screening” operations as
processed. Assume equal contribution to crushing and screening.
0.08 kg/Mg of coal

-------
Figure 2-9. EDS Coal Handling System
2—flO
10 5CR PROCESS
AND DEASIIING

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2.2.3 Coal Liquefaction
In the coal liquefaction area for the EDS coni ercial plant (61),
crushed coal fran coal preparation facilities is fed to the slurry drier,
where it is mixed with recycle donor solvent from solvent hydrogenation.
The dry slurry is pumped to reaction pressure, preheated, mixed with pre
heated hydrogen, and heated in the slurry preheat furnace to the reaction
temperature. The preheated dry slurry is then sent to the liquefaction
reactor. The reactor effluent is separated into a recycle gas and a slurry
stream. The recycle gas Is treated, added with makeup hydrogen, com-
pressed, preheated, and sent to the slurry preheat furnace. The slurry is
let down to nearly atmospheric pressure and sent to the product fraction-
ation facilities. A block flow diagram indicating all the major process
and waste streams for the coal liquefaction area is presented in Figure
2—10.
2.2.3.1 Slurry Drying and Liquefaction
In the slurry drier (61), crushed coal feed (minus 8 mesh) is mixed
with recycle solvent to form a coal slurry. Concurrently with the mixing
process, the slurry is dried to less than 4 wt % moisture on dry coal feed.
The dry product slurry is then heated, pumped to reaction pressure, pre-
heated by heat exchange with liquefaction reactor effluents, and fed to the
liquefaction slurry preheat furnace. The overhead from the slurry drier
consisting of water vapor and stripped recycle donor solvent is condensed,
cooled, and separated into phenolic water, distillate liquid, and offgas.
The phenolic wastewater (stream 103) is withdrawn from the drum and sent to
the phenol extraction unit ii$ ile the distillate is returned to the slurry
drier. The slurry drier vent gas (stream 102) is burned as fuel.
The preheated, dry, coal slurry from the slurry drier is mixed with
preheated hydrogen treat gas and fed to the slurry preheat furnace fired
with fuel gas. The slurry—hydrogen mixture is heated to liquefaction
reactor conditions of 700—750 0 K (800—900°F) and 13.9 MPa (2000 psig). Thts
mixture is then sent to the liquefaction reactor, where the coal is
2-111

-------
112 PURGE IC
CRYOGENIC
HYDROGEN
RECOVERY
VENT
GAS
COAL
RECYCLE
DONOR
SOLVENT
-a
-a
N)
HYDROCARBON
LIQUID TO
ATMOSPHERIC
FRACTIONATOR
SLURRY TO
ATMOSPHERIC
FRACTIONATOR
HYDROCARBON
COLD LIQUID TO
SEPARATOR ATMOSPHERIC
WASTEWATER FRACTIONATOR
COLD
SEPARATOR
WASTE WATER
Figure 2-10. Block Flow Diagram for EDS Commercial Plant Coal Liquefaction Operations

-------
liquefied in the presence of molecular hydrogen and the hydrogen donor
solvent.
2.2.3.2 Raw Product Separation
The reactor effluent is separated into a vapor stream and a slurry
stream in a vapor—liquid separator. Wash oil from the hot separator drum
is used to minimize solids entrainment in the overhead vapor. The vapor is
then cooled by heat exchange and sent to the hot separator drum. The hot
separator vapor flows to a venturi mixer, where cold separator water is
added to prevent aninonia chloride deposition. This mixture is then cooled
by additional heat exchange and fed to the cold separator drum. Aninonia
formed in the process is removed with the sour water.
The vapor from the coal separator is scrubbed with DEA for acid gas
removal. A portion of the resulting hydrogen rich gas is purged to the
cryogenic hydrogen concentration section. The remaining hydrogen rich gas
is mixed with makeup hydrogen and hydrogen purge from the solvent hydro-
genation section to form recycle treat gas. The treat gas is compressed,
preheated by heat exchange with effluent separator vapor, and recycled back
to the slurry furnace.
The slurry stream from the reactor effluent separator is let down to
nearly atmospheric pressure and sent directly to the atmospheric frac-
tionator. A portion of the liquid stream from the hot separator is
recycled to the reactor effluent separator as wash oil. The remainder of
the hot separator liquid is let down in pressure and fed to the atmospheric
fractionator. The cold separator hydrocarbon liquid is let down in
pressure, preheated by heat exchange with hot separator vapor, and fed to
the atmospheric fractionator. A portion of the cold separator sour water
is recycled and mixed with hot separator vapor to prevent amonia chloride
plugging. The remainder of the liquefaction cold separator sour water
(stream 106) is sent to the sour water stripper/amonia recovery system fgr
treatment.
2—113

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2.2.3.3 Waste Stream Characterization
There are five waste streams fran the cold liquefaction area:
a
• Stream 102 - slurry drier vent gas
• Stream 103 — slurry drier cold separator wastewater
• Stream 106 - liquefaction cold separator wastewater
• Stream 107 — flue gas fran slurry preheat furnace
• Stream 108 — solids accumulated in the slurry drier
The slurry drier vent gas generation rate for the base case and MFS
case was estimated to be 828.0 kmol/hr and 695.8 kmol/hr, respectively
(65,83). This vent gas contains 86.0% N 2 , 9.9% H 2 0, 4.1% hydrocarbons
(mostly In the C 6 — 400°F normal boiling range), and 30 ppmv H 2 S.
The estimated characteristics of the two wastewater streams are
presented in Table 2-62. The quality of these wastewaters were
extrapolated from data provided by ER&E (83). The ER&E estimates were
based on analyses of wastewater samples obtained from several small
operating pilot units together with computer process synthesis. Stream 103
Is a non—sour phenolic wastewater stream that can be sent directly to the
phenol extraction unit without sour water stripping.
Additional characterization data are available for the combined
process wastewater stream fran the coal liquefaction (excluding stream
103), product separation and purification, solvent hydrogenation, and
Flexicoking operations. In addition to stream 106, there are eight sour
and phenolic wastewater streams from these operations:
• Stream 152 — atmospheric fractionator overhead drum wastewater
• Stream 155 — vacuum flash wastewater
• Stream 202 — solvent hydrogenation cold separator wastewater
• Stream 252 — solvent hydrogenation fractionator overhead drum
wa stewate r
2—114

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TABLE 2-62. ESTIMATE; QUALITY OF SOUR AND PHENOLIC WASTEWATER
STREAMS FROM EDS COMMERCIAL PLANT COAL LIQUEFACTION
OPERAT IONS
Contaminant
Stream 103
Stream 106
Slurry Drier
Liquefaction
Co’d Separator
Cold Separator
Wastewater
Wastewater
1125, ppmw
6
32,330
NH 3 , ppmw
76
22,840
HC1, ppmw
12
2,470
C0 2 , ppmw
291
19,450
Phenols, ppn
968
13,720
Organic acids, ppmw
- —
7,410
Flow rate, kg/hr
241,900 (base case)
203,300 (MFS case)
156,600 (base case)
131,600 (MFS case)
Flow rate, m 3 /hr
246.4 (base case)
207.1 (MFS case)
159.8 (base case)
134.3 (MFS case)
Temperature, 0 K
317
317
Pressure, MPa
0.09
12.7
.jata source: Reference 83.
2—115

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• Stream 308 - Flexicoking fractionator overhead drum wastewater
• Stream 307 - Flexicoking recontacting drum wastewater
• Stream 312 - Flexicoking heater overhead drum wastewater
• Stream 403 — K.O. drum lastewater in H 2 cryo recovery
These nine sour water streams are combined and denoted as stream A. This
combined sour water stream A is generated at the rate of 452,000 kg/hr
(461.7 m 3 /hr) for the base case and 271,900 kg/hr (279.9 m 3 /hr) for the MFS
case. In Table 2—63, data on the characteristics of the combined sour
water stream A, including phenol breakout, are presented. The data
presented were extrapolated from ER&E data (81,83). In Table 2-64, data on
the trace element concentrations for stream A, as provided by ER&E (81),
are presented. These data show that the trace element concentrations for
stream A are extremely low.
The flue gas stream from the slurry preheat furnace (stream 107),
fired with fuel gas, is a major flue gas stream generated by the EDS com-
mercial plant. The flow rate and composition for this stream are described
in SectIon 2.2.6.2, along with the description of flue gas streams from
steam and power generation.
Coal feed to the EDS process has a nominal top—size of 8 mesh (2.38
nm). Oversize feed Is intermittently removed from the slurry drier for
removal (stream 108). A removal frequency of one eight hour shift every
three months has been estimated. Approximately 318 Mg are recovered from
the slurry drier under the base case design and 268 Mg are recovered under
the MFS case design. Corresponding annual generation rates for this waste
are 1280 Mg/yr and 1070 Mg/yr for the base and MFS cases, respectively.
The slurry drier solids are similar in composition to the feed coal.
2-116

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TABLE 2-63. CHARACTERIST S OF COMBINED SOUR WATER STREAM A
FROM EDS COMMERCIAL PLANT
Contaminant Stream A Concentration
H 2 S, ppnn 15,700
NH 3 , ppmw 13,810
HCI, ppmw 1,020
C0 2 , ppmw 9,910
Phenols, ppmw 8,080
Organic Acids, ppmw 2,890
Ketones and Aldehydes, ppmw 220
SCN, ppmw 10
CtC, ppmw 4
PNAs, pprnw 1.5
Phenol Breakout wt %
Phenol 52.2
Cresols 18.0
Heavier alkylated phenols 19 .8
Resorcinol 4.3
Heavier alkylated dihydroxy benzenes 5.7
Data source: Extrapolated from Exxon Research and Engineering data
(81,83).
2—117

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TABLE 2—64. ESTIMATED TRACE ELEMENT CONCENTRATIONS FOR
COMBINED SOUR WATER STREAM A FROM EDS
COMMERCIAL PLANT
r
Trace E1 nent -
Stream A Concentration,
ppm
Zn
1.60
Cu
0.77
Cr
0.52
N i
0.50
Sn
0.37
Ti
0.31
Pb
0.21
Mn
0.05
Mo
0.04
Cd
0.02
Co
0.02
As
ND*
Hg
ND
Se
ND
V
ND
* tC - Not detected.
Data source: Exxon Research and Engineering (81).
2—118

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2.2.4 Product Separation and Purification
The product separation and purification operations for the EDS
commercfai plant cons st of four major process areas: liquid product
fractionation, solvent ‘iydraçenation, gas treating, and product recovery
(61). A block flow diagram indicating all the major process and waste
streams fran; these operations Is presented in Figure 2 -Il.
2.2.4.1 Liquefaction Product Fractionation
The slurry stream from the liquefaction reactor effluent separator and
the liquid streams from the liquefaction hot and cold separators are fed to
the atmospheric tower at different points (61). In the atmospheric tower,
the reactor effluent is separated into offgas, naphtha, a 400/650 0 F low
sulfur fuel oil (LSFO)/spent solvent sidestream, and a slurry bottoms
stream. The 400/650 0 F LSFO/spent solvent cut is steam stripped in a
sidestream stripper tower in order to meet flash point requirements for the
LSFO product and for the solvent, and sent to the solvent hydrogenation
area. The atmospheric tower offgas (stream 151) is sent to the DEA scrubber
for acid gas removal. The overhead drum wastewater (stream 152) is sent to
the sour water stripper/amonia recovery system for treatment. Naphtha
separated from the overhead drum wastewater is sent to the product recovery
area for additional processing.
The atmospheric tower bottoms are fed directly to the vacuum
fractionator. Products from the vacuum fractionator include offgas, vacuum
distillate, vacuum gas oil (VGO), 650/900 0 F LSFO/spent solvent sidestrearns,
and the vacuum bottoms which are fed to the Flexicoker. The vacuum flash
offgas (stream 153) is burned as fuel. The sour water (stream 155)
separated from the vacuum distillate is sent to the sour water stripper/
amonia recovery system for treatment. The VGO obtained is sent to liquid
storage. The vacuum distillate and 650/900°F LSFO/spent solvent are sent
to the solvent hydrogenation area.
For the fS case, a vacuum fractionator for the partial oxidation feed
is added to process part of the atmospheric tower bottoms. The major
2—119

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FIgure 2.11. Block Flow Diagram for EDS Commercial Plant Product Separation
and Purification Operations
oc,GAI
-J
0
N Ø$THA
C, IPU TO
170M43*
To STORAGI
C 4 tPO TO
It ThAGE
AT Q9 4NIC ø*CTIO$I*tO* t A HT)4A

-------
difference between this fractionator and the Flexicoker feed vacuum
fractionator is preheating of the atmospheric tower bottoms in furnaces
before feeding to the partial oxidation feed vacuum fractionator. As a
result, the partial oxidation feed vacuum fractionator bottoms have a cut
point of 975°F vs. the Flexicoker feed vacuum fractionator bottoms cut
point of 920°F. The deeper cut point has proven to result in more
favorable operation of the partial oxidation unit. Similar process and
waste streams are generated from the partial oxidation feed vacuum
fractionator, including a vacuum flash offgas (stream 156) burned as fuel,
a sour water (stream 157) sent to the sour water stripper/amonia recovery
system for treatment, a VGO to liquid storage, a vacuum distillate and a
650/900°F LSFOfspent solvent to the solvent hydrogenation area.
2.2.4.2 Solvent Hydrogenation
In the solvent hydrogenation area, the sidestreams from the
atmospheric and vacuum fractionators and the liquid distillate from the
vacuum fractionator are blended and passed through a feed filter. The
blended stream is pumped to process pressure, preheated by heat exchange,
mixed with hydrogen makeup gas, and fed to the solvent hydrogenation feed
preheat furnace. The mixture is then passed through the solvent
hydrogenation reactor, which operates at an outlet pressure of 11.2 MPa
(1605 psig). Recycle quench gas is used to absorb the exothermic heat of
reaction and control the reactor temperature. The reactor effluent is
cooled by heat exchange with the incoming feed, and sent to the hot
separator drum. The hot separator vapor is cooled by heat exchange with
cold separator liquid and hydrogen makeup gas, and is washed with water for
corrosion control. This mixture is further cooled by air and cooling
water, and is then fed to the cold separator drum.
The vapor from the cold separator drum (stream 200) is scrubbed with
DEA for acid gas removal and is compressed. Most of the compressed gas is
recycled back to the process as quench gas, which is added between reactor
beds for temperature control. The remaining portion of the compressed gas
is purged to the liquefaction area after cryogenic hydrogen recovery, where
it is used to supplement the hydrogen makeup gas. Amonia formed in the
2—121

-------
process is removed with the sour water. The solvent hydrogenation cold
separator sour water (stream 252) is sent to the sour water
stripper/alTinonla recovery system for treatment.
The liquid streams from the hot and cold separator drums are sent to a
conventional steam stripped fractionator. The products from this solvent
stripper include an offgas stream (stream 251) which Is combined with the
atmospheric and Flexicoker fractionator offgas (streams 151 and 310) and
fed to the DEA scrubber for acid gas removal, a naphtha product sent to
product recovery, a recycle donor solvent bottoms product, and a LSFO
product sent to liquid storage. The overhead drum sour water (stream 252)
separated from the naphtha product is sent to the sour water stripper!
aninonia recovery system for treatment.
2.2.4.3 Gas Treating
In the gas treating area, the atmospheric fractionator offgas (stream
151), solvent stripper offgas (stream 251), and Flexicoker fractionator
off gas (stream 310) are combined and scrubbed with DEA for H 2 S removal.
The overhead gas from the fractionator offgas scrubber is sent to the
cryogenic hydrogen recovery 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 regeneration unit. The acid gas (stream 508) from
the DEA unit is sent to the sulfur plant. The regenerated lean DEA
solution is returned to the DEA scrubbers.
2.2.4.4 Product Recovery
The product recovery operations consist of a deethanizer, a
debutanizer, a C 3 /C 4 splitter, and LPG treating and drying facilities. The
compressed gas from cryogenic hydrogen recovery, the cryogenic liquid
condensates (C 3 ), and the total distillate from the atmospheric
fractionator, the solvent stripper, and the Flexicoker fractionator are fed
to the deethanizer. The off gas (C 2 ) from the deethanizer Is used as feed
to steam reforming for hydrogen generation In the base case, and sent to
the cryogenic hydrogen recovery area for C 1 /C 2 gas product in the MFS case.
2-122

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The deethanizer bottoms (C 3 ) are fed to the debutanizer where they are
fractionated to yield a C 3 /C 4 overhead product and a stabilized naphtha
(C 5 /400°F) bottoms. The naphtha product is cooled and sent to storage.
The C 3 /C 4 overhead product is treated for H 2 S/RSH and fed to the C 3 /C 4
splitter. In the C 3 /C 4 splitter, the C 3 /C 4 stream is fractionated to yield
a C 3 LPG overhead and a C 4 LPG bottoms product. The C 4 LPG is cooled and
sent to storage. The C 3 LPG is dried and sent to storage.
2.2.4.5 Waste Stream Characterization
There are e’even waste streams from the product separation and
purification operations:
• Stream 152 — atmospheric fractionator overhead drum wastewater
• Stream 153 - vacuum flash offgas
• Stream 155 — vacuum flash wastewater
• Stream 156 — partial oxidation feed vacuum flash offgas (MFS case
only)
• Stream 157 — partial oxidation feed vacuum flash wastewater (MFS
case only)
• Stream 161 — flue gas from partial oxidation feed vacuum flash
preheat furnace (MFS case only)
• Stream 202 — solvent hydrogenation cold separator wastewater
• Stream 203 — flue gas from hydrogenation fuel preheat furnace
• Stream 204 — spent hydrogenation catalyst
• Stream 252 — solvent hydrogenation fractionator overhead drum
wastewater
• Stream 508 — acid gas from DEA unit
Acid Gas Stream- —
The composition, flow rates, temperature, and pressure of the acid gas
from the DEA unit (stream 508) for both the base case and the MFS case are
2—123

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presented in Table 2—65. These estimates were based on data provided by
ER&E (83).
The characteristics of the sour gas streams entering the DEA scrubbers
are presented in Tables 2-66 and 2—67 for the base case and the MFS case,
respectively. These estimates were also based on data provided by ER&E
(83). In the ER&E design, three DEA scrubbers are used to remove the acid
gases from the sour gas streams. The atmospheric fractionator offgas
(stream 151), the solvent hydrogenation fractionator sour gas (stream 251),
and the Flexicoking fractionator offgas (stream 310) are combined as a low
pressure (L.P.) gas stream and treated in the same DEA scrubber. The
liquefaction cold separator sour gas (stream 104) and the solvent
hydrogenation cold separator vapor (stream 200) are each treated In
individual DEA scrubbers. As shown In Tables 2-66 and 2-67, stream 104 has
a H 2 S/C0 2 ratio of 1.9:1 whereas the combined L.P. sour gas has a H 2 S/C0 2
ratio of 3.0:1. Carbon dioxide is not present In stream 200. Concentration
of the H 2 S present by se1ectlve acid gas removal (AGR) processes is,
therefore, not necessary. The data presented in Tables 2-66 and 2-67 can
be used to assess the environmental and economic impacts of other AGR
systems.
Vacuum Flash Offgas— —
The vacuum flash offgas (stream 153) generation rate for the base case
was estimated to be 107.3 kmol/hr (83). For the MFS case, the combined
vacuum flash offgas (stream 153) and partial oxidation feed vacuum flash
offgas (stream 156) generatIon rate was estimated to be 90.2 kmol/hr (83).
For both the base case and the PFS case, the off gas contains 7.5% 02, 28.7%
N 2 , 11.3% H 2 0, 47.5% hydrocarbons (with average molecular weight of 46.2),
and 5.0% H 2 S.
f ”1ue Gas Streams- —
The flue gas streams from the partial oxidation feed vacuum flash
preheat furnace (stream 161, MFS case only) and the hydrogenation fuel
preheat furnace (stream 203) are major flue gas streams generated by the
2-124

-------
TABLE 2-65. COMPOSITIC RATES OF ACID GAS STREAM
FROM EDS CL PLANT PRODUCT SEPARATION
AND PURIFICA RATI0NS
Component
Stream 508 - Acid Gas From DEA Unit
Base Case MFS Case
CO 2 . kmol/hr
H 2 5, kmol/hr
NH 3 , kmol/hr
COS, kmol/hr
485.6
1213.0
74.2
0.9
383.7
1011.9
81.3
0.7
H 2 0, kmol/hr
Total, kmol/hr
Temperature,
115.4
1889.1
322
91.2
1568.8
322
Pressure, MPa
0.29
0.19
Data source: Reference 83.
2—125

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TABLE 2-66. COMPOSITION AND FLOW RATES OF SOUR GAS STREAMS TREATED IN
EDS COMMERCIAL PLANT DEA UNIT (ILLINOIS COAL BASE CASE)
p
•‘L
Component
Stream 104
Liquefaction
Stream 151
Atmospheric
Stream 200
Solvent
Stream 251
Solvent
Stream 310
Flexicoking
Cold Separator
Fractionator
Hydrogenation
Hydrogenation
Fractionator
Sour Gas
Offgas
Cold Separator
Fractionator
Offgas
Vapor
Sour Gas
H 2 , kmol/hr
10317.5
1074.3
26861.1
1042.8
1433.9
C 1 , kmol/hr
7121.5
1227.1
8874.7
541.3
1002.5
C , kmol/hr
1355.9
527.7
88.3
12.7
178.1
C 3 , kmol/hr
505.6
323.9
12.5
3.1
54.0
C 4 , kmol/hr
140.2
156.4
0.7
0.4
15.6
C 5 , kmol/hr
35.7
62.8
0.5
0.6
-—-
C 6 ’, kmol/hr
41.9
145.0
35.9
98.9
31.6
N 2 , kmol/hr
—-—
---
--—
---
136.4
CO , kmol/hr
94.7
37.6
---
---
124.7
C0 2 , kmol/hr
276.6
143.3
---
-—-
65.7
H 2 S, kmol/hr
520.2
576.8
68.4
16.6
32.7
NH 3 , kmol/hr
1.0
12.4
53.1
8.4
———
COS, kmol/hr
0.3
. 0.1
—-—
-——
0.5
H 2 0, kmol/hr
14.3
77.8
29.7
33.6
58.0
Total, kmol/hr
20425.4
4365.2
36024.9
1758.4
2997.3
Temperature, °K
317
317
317
317
317
Pressure, MPa
12.7
0.48
10.6
0.48
0.48
Data source: Reference 83.

-------
Component Stream 104 Stream 151 Stream 200 Stream 251
Solvent
Stream 310
Flexicoking
Liquefaction Atmospheric
Col’d Separator Fractionator Hydrogenation Hydrogenation
Sour Gas Offgas Cold Separator Fractionator
Sour Gas
Fractionator
Offgas
Vapor
-
H 2 , kmol/hr 8669.8 902.7 22571.1 876.3
454,9
:
593.8
414.6
C 1 , kmol/hr 5984.2 1031.1 7457.4
10.7
73.9
C 2 , kmol/hr 1139.4 443.4 74.2
2.6
22.3
C 3 , kmol/hr 424.9 272.2 10.5
0.3
6.8
C 4 , kmol/hr 117.8 131.4 0.6
0.5
C 5 , kmol/hr 30.0 52.8 0.4
83.1
12.3
C 6 4 ’, kmol/hr 35.2 121.8 30.2
59.6
N 2 , kmol/hr -—- --- ---
52.8
CO, kmol/hr 79.6 31.6 --- ---
C0 2 , kmol/hr 228.1 120.4 —-- --—
13.9
35.2
20.1
H 2 S, kmolfhr 437.1 484.7 57.5
7.1
19.2
NH 3 , kmol/hr 0.8 10,4 44.6
.
0.3
COS, kmol/hr 0.3 0.1 ---
F’ 2 0, kmol/hr 12.0 65.4 25.0 28.2
24.4
Total, kmol/hr 17159.2 3668.0 30271.5 1477.6
1335.3
Temperature, °K 317 317 317 317
317
Pressure, MPa 12.7 0.48 10.6 0.48
0.48
TABLE 2-67. COMI’l
EDS It,
F1 AND FLOW RATES OF SOUR STREAMS TREATED IN
RCIAL PLANT DEA UNIT (ILL1 IS COAL MFS CASE)
r 3
—a
V.,)
Data source: Reference 83.

-------
EDS commercial plant. The preheat furnaces are all fired with fuel gas.
The flow rates and composition for these flue gas streams are described in
Section 2.2.6.2, along with the description of flue gas streams from steam
and power generation.
Sour Water Streams- —
The estimated characteristics of the four sour water streams are
presented in Table 2-68. The quality of these wastewaters were
extrapolated from data provided by ER&E (83). The ER&E estimates were
based on analyses of wastewater samples obtained from several small
operating pilot units together with computer process synthesis. Additional
characterization data are available for the combined sour water stream from
the coal liquefaction (excluding stream 103), product separation and
purification, solvent hydrogenation, and Flexicoking operations. These
additional data have been previously presented In Section 2.2.3 in the
discussion of the sour water stream from coal liquefaction.
Solid Waste- -
Only one solid waste stream is generated from the EDS commercial plant
product separation and purification operations. This solid waste is the
spent catalyst (stream 204) from the solvent hydrogenation reactor. Annual
generation rate for the spent catalyst was estimated to be 384 Mg/yr and
322 Mg/yr from base case operation and MFS case operation, respectively
(83). The composition for the spent catalyst is not well defined, but is
expected to contain nickel, molybdenum, carbonaceous material, and
sul fides.
2-128

-------
TABLES 2-68. ESTIMATED iALITY OF SOUR WATER STREAMS FROM EDS
COMMERCIAL PLANT PRODUCT SEPARATION AND PURIFICATION OPERATIONS
Contaminant
Stream 152
Atmospheric
Fractionator
Overhead Drum
Wastewater
*
Stream 155
Vacuum
Flash
Wastewater
Stream 202
Solvent
Hydrogenation
Cold Separator
Wastewater
Stream 252
Solvent
Hydrogenation
Fractionator
Overhead Drum
Was tewa ter
H 2 S, ppmw
NH 3 , ppmw
HC1, ppmw
‘
4,210
5,390
1,280
8,440
38
19
58,140
54,460
---
26,720
18,640
--
C0 2 , ppmw
Phenols, ppmw
310
18,400
750
4,910
-—-
1,030
---
5,160
Organic Acids, ppmw
3,130
340
---
--—
Flow Rate, kg/hr
.
Base Case
45,300
7,530
19,550
19,400
MFS Case
Flow Rate, m 3 /hr
Base Case
38,100
48.0
6,330
7.6
16,430
20.8
16,300
19.8
MFS Case
40.3
6.4
17.5
16.6
Temperature, °K
392
317
317
317
Pressure, MPa
0.52
0.74
10.7
0.48
Data source: Reference 83.
*For the MFS case, this includes stream 157 - the partial oxidation feed vacuum flash wastewater.

-------
2.2.5 Processing Liquefaction ReslduefHydrogen Production
Vacuum—bottoms slurry from the liquefaction/distillation area is
utilized to generate additional liquid products (e.g., naphtha and low
ul fur fuel oil), fuel gas and either syngas or light gases for hydrogen
production. In the tf S case, high Btu sales gas is also produced. The
principal operations involved in processing vacuum—bottoms are Flexicoking
and hydrogen generation. These operations are presented schematically in
Figures 2-12 and 2-13 for the Base and MFS cases, respectively, and
described in the ensuing sections.
2.2.5.1 Flexicoking
The Flexicoking unit converts vacuum-bottoms slurry into additional
liquid and gas products, and generates low Btu fuel gas for process
consumption. Flexicoking Is a low pressure process (<0.45 MPa; <65 psia)
consisting of integrated reactor (coker) and heater/gasifier sections.
Vacuum-bottoms slurry is coked in the reactor section at temperatures of
755—920°K (900—1200°F) to yield liquid and gas products. Reaction heat is
supplied by a circulating stream of coke which transports heat from the
heater to the reactor vessel. Temperatures in the heater are maintained by
circulating gas and solids from the gasifier. Coke produced in the reactor
is fed to the gasifier (via the heater vessel) and reacted with air and
steam at 1100-1250 0 K (1500-1800°F) to form low Btu fuel gas.
Pyrolysis products from the reactor are scrubbed, and heavy organics
and solids are recycled to the reactor. The scrubber overhead is
fractionated to separate naphtha from low sulfur fuel oil and wash oil.
Olefinic coker gas from fractionation Is cooled, compressed, recontacted
with fractionator naphtha to recover additional naphtha and sent to
hydrogen recovery. Coker gas consists primarily of light hydrocarbons,
bydrogen and carbon oxides with lesser amounts of nitrogen, hydrogen
sulfide and aninonia.
2-130

-------
FLUSH
0I
NAPHTHAT ISFO
fit
REGENERATION/
C 1 + TO DECOMMISSIONING
OFF .G AS
LIGHT ENDS
RECOVERY
VACUUM
BOTTOMS
SLURRY
STEAM
AIR
STE AM
I; . ,
—‘
(A)
-J
STEAM
COKI
HYDROGEN
AOIJEOUS AMMONIA
SPENT CATALYST
WASTEWATER SPENT
DRYING AGENTS
4 FUEL GAS
H 2 S
REMOVAL
L___J
H 2 S REMOVAL REPRESENTS A SULFUR EMISSION CONTROL OPTION
Agure 2-12. Block Flow Diagram for EDS Liquefaction Residue Processing and Hydrogen Production — Base Case

-------
FRATIONATOR
APE OF? GAS OFFGA*
VACUUM
SLURRY
I SOTTOMS HYDROGEN
LIFO
PURGE FROM C 3 . TO LIGHT
FLUSH OIL N4lJ’HTHA UG. AND SIN ENDS RECOVERY
tI f I ____ ____
_____ 1 i%1 DEA ______________
HYDROGEN
CRYOGENIC HIGH S1U GAS
STEAM REACTOR AIZORSIR
____ 41
a
___________ GAS RECOVERY ____________________________
J OFF
________________ HYDROGEN
__________ ______________ GAS 1
+4+
COKE c 1 1c 3 FROM
DAY LIGHT ENDS
FINES
4 WET WASTEWATER , e’ENT
DRYING AGENTS
SPENT
HYDROTREATER
WATER
CATALYST
SOUR
STEAM
_______________ ___________ SULFUR a
WATER I GASIFIEN J ..€ OUi4I REMOVAL • I 0 FuEl. ciM
______________________________
— AIR
FUEL L — — — J
(4 ________
VACUUM SOUR I AGGLOMERATES
WATER $ REGENERATION!
BOTTOMS
SEQ DECOMMISSIONING
DEAERATOR COKE OFF-GAS
ACID GAS
VENT GAS FLASH GAS
____________ PARTIAL 1
_________ _________ _________ ACID GAS ________________________
OXYGEN __________ OXIDATION SHIFT til_ REMOVAL HYDROGEN
STEAM
4) 4) *428 REMOVAL REPRESENTS A SULFUR EMISSION CONTROL OPTION
SOUR CON SLAG
WATER BINED FILTRATE SPENT
SLAG CATALYST
Figure 2-13. Block F’ow Diagram for EDS Liqufaction Residue Processing and Hydrogen Production — MFS Case

-------
Raw fuel gas from the heater/gasifier system is treated for
particulate and sulfur removal prior to plant use. Entrained particulate
consisting of ash and approximately 20% residual coke is removed by
sequential dry and wet (venturi scrubber) removal systems. Wet fines are
recovered as a 6% solids slurry requiring dewatering prior to disposal.
Essentially complete hydrogen sulfide removal is effected in the sulfur
removal plant yielding a fuel gas containing approximately 100 ppm sulfur
as carbonyl sulfide.
Ash and residual coke are removed on a continuous basis from the
heater/gasifier system at an ash-to-coke weight ratio of approximately two.
Chunk coke or agglomerates are removed from the system for disposal on a
daily basis.
2.2.5.2 Hydrogen Production
A major difference between the Base and MFS cases is the method of
hydrogen production. Both cases obtain a portion of the make-up hydrogen
requirement by cryogenic separation of high pressure purge streams from
liquefaction and solvent hydrogenation, and off—gas from product
distillation, solvent fractionation and Flexicoking. However, the balance
of the hydrogen requirement is generated by steam reforming for the base
case t i1e the FS case employs partial oxidation of vacuum—bottoms slurry.
Base case hydrogen generation involves steam reforming, shift
conversion, carbon dioxide removal and removal of residual carbon oxides
and nitrogen. Feed streams to the reformer are the ç hydrocarbons from
cryogenic hydrogen recovery, and the C 1 and C 2 hydrocarbons from light ends
recovery. These streams are passed through a ZnO sulfur guard for trace
sulfur removal prior to steam reforming. Reforming of the hydrocarbon feed
is performed over a nickel-urania catalyst at approximately 2 MPa (300
psia) and 1090 0 K (1500°F) to yield hydrogen and carbon oxides. Reaction
heat is provided by burning low sulfur fuel gas; waste heat is recovered in
steam production for the reformer feed and for other process uses.
Additional hydrogen is produced by high temperature (>622°K; >660°F) shift
conversion over an iron oxide catalyst.
2-133

-------
Bulk removal of carbon dioxide from the base case shift gas employs
the Catacarb process. This process is ahot potass ium carbonate process
utilizing amine borates to increase the carbonate solution activity. The
Catacarb unit will remove most of the carbon dioxide along with traces of
hydrogen, carbon monoxide and methane. Any amonia which may be generated
by reaction of hydrogen and nitrogen during hydrogen generation will also
be removed. Hence, regeneration of rich Catacarb solution will produce a
carbon dioxide rich off-gas containing small quantities of hydrogen, carbon
monoxide, methane and possibly amonia.
Hydrogen rich gas from the base case carbon dioxide removal unit is
combined with the hydrogen from cryogenic separation prior to removal of
trace carbon oxides and nitrogen. Methanation of the combined hydrogen
stream Is employed to remove trace carbon oxides by converting them to
methane. For amonia synthesis applications, carbon oxide levels are
typically reduced to 10 ppm or less to prevent catalyst poisoning.
Methanation is followed by compression, drying and amonia synthesis for
nitrogen removal. Compression condensate Is removed by physical separation
employing a knockout drum and with drying agents. Amonia synthesis
proceeds at about 620°K (660°F) and 13 MPa (1900 psia) over an iron oxide
catalyst. Amonia is removed from the product gas stream by water
scrubbing and sent to amonia recovery for dehydration. Purified, high
pressure hydrogen is provided to the liquefaction and solvent hydrogenation
units as required.
Hydrogen production for the ?fS case involves syngas generation, shift
conversion, acid gas removal and compression. Approximately half of the
vacuum—bottoms slurry produced in the liquefaction/distillation units will
be processed into hydrogen while the balance will be processed through
Flexicoking to produce additional liquid and gas products.
Production of raw synthesis gas for MFS hydrogen generation will be
based upon Texaco coal gasification technology. The Texaco gasification
process involves a pressurized, downflow, slagging gasifier which gasifies
the vacuum—bottoms slurry with oxygen and steam. Pilot units gasifying
coal operate at pressures of 2.1 to 8.2 MPa (300 to 1200 psia); available
2—134

-------
test data and design information indicate that pressures in this range are
appropriate for gasifying liquefaction residues similar to those generated
by the EDS process (8,26). Gasification temperatures are generally above
the ash fusion temperature (1500 0 K; 1300°F) to obtain high gasification
rates and minimize the quantities of undesirable byproducts such as tars,
oils and phenols in the raw gas.
The gasifier is a refractory—lined carbon steel vessel which can
roughly be divided into two zones: (1) a gasification zone and (2) a
quenching zone. During gasification, the feed is partially reacted with
oxygen, in the presence of steam, to produce a raw gas consisting primarily
of GO, H 2 , and CO 2 . Quenching takes place in the lower portion of the
reactor iá ere the raw gas is partially cooled and the slagged ash is
solidified through contact with water In a quench bath. Quenched gas is
scrubbed with water to remove impurities such as amonia, for-mate and char
prior to subsequent processing (e.g., shift conversion). Buildup of
soluble ash constituents as well as organic and inorganic reaction products
is controlled by blowdown of quench and scrubber water. flash gas derived
from blowdown streams is sent to the sulfur recovery area for processing.
Solids generated during gasification are slag and char. Quenched slag
is removed from the gasifier through an ash lock system, and sized into
coarse and fine fractions using a moving screen. Coarse slag is readily
dewatered, while slag fines require thickening and filtration dewatering.
Slag fines are filtered in the slag handling area, combined with the coarse
slag id trucked to disposal. Filtrate from slag dewatering is pumped to
wastewater treatment for suspended solids removal. A small quantity of
char, containing approximately 6-12% unreacted carbon, is recovered from
scrubber and recycle water by settling. Depending upon the carbon content
of the char, this material may be recycled to the gasifier or added to the
coal feed in the front end of the liquefaction plant.
Carbon monoxide produced during gasification is converted to hydrogen
by combined high and low temperature shift conversion. High temperature
shift (in the range of 590-750 0 K; 600—890°F) proceeds in two stages over a
chromia—promoted iron oxide catalyst. High temperature shift gas is cooled
2-135

-------
in a waste heat boiler and further shifted at low temperature (530-560 0 K;
490—550°F) over a copper-zinc oxide catalyst. Removal of acid gases from
the shift gas employs the Catacarb process, as in the Base case. The
Catacarb unit will remove most of the carbon dioxide, hydrogen sulfide,
ammonia and carbonyl sulfide along with traces of hydrogen, carbon monoxide
and mtthane. Acid gas fran regeneration of the Catacarb solution Is sent
to sulfur recovery. Purified hydrogen from hydrogen generation is combined
with the hydrogen from cryogenic recovery, compressed and sent to the
liquefaction and solvent hydrogenation units, as required.
2.2.5.3 Waste Stream Characterization
Gaseous Waste Streams— —
There are ten gaseous waste streams generated within the EDS
liquefaction residue processing/hydrogen production area:
• Stream 426 — vent gas from CO 2 removal (base case only)
• Stream 428 — acid gas from acid gas removal (MFS case only)
• Stream 434 — flue gas from reformer furnaces (base case only)
• Stream 438 — deaerator vent gas from hydrogen generation
• Stream 440 — flash gas from the partial oxidation unit (MFS case
only)
• Stream 446 - regeneration/decommissioning off gas from the
reformer catalyst (base case only)
• Stream 447 — regeneration/decommissioning off gas from the shift
conversion catalyst (base case only)
• Stream 448 — regeneration/decomissioning off gas from the
methanation catalyst (base case only)
• Stream 449 — regeneration/decommissioning off gas from the high
temperature shift catalyst (MFS case only)
• Stream 450 — regeneration/decommissioning off gas from the low
temperature shift catalyst (tIES case only)
2-136

-------
Gaseous waste stream characterization data for the EDS base case are
presented n Table 2-69. Streams not included in this table are the flue
gas from reformer furnaces (stream 434), and regeneration/decommissioning
off gases fran the shift cor versf on and methanation catalysts (streams 447
and 448). Flue gas from reformer fwi aces is discussed with emissions from
other furnaces in Section 2.2.6.2. Regeneration/dec issioning off gases
from shift and methanation wifl be intermittent in nature. They are
expected to consist primarily of steam with approximately 1 g/Nrn 3 of
particulate, and will be free of sulfur and carbon oxides. Small
quantities of Ni(CO) 4 may be present in the methanator off gas.
Vent gas from carbon dioxide removal (stream 426) will consist
primarily of carbon dioxide and steam with 1.9% hydrogen, 370 ppmv methane
and 160 ppmv carbon monoxide. Any ammonia which may be generated by
reaction of hydrogen and nitrogen during hydrogen generation would also be
present in the vent gas. Data for this stream is based upon design data
(83) and available data for hot carbonate processes (84).
Deaerator vent gas (stream 438) is estimated to contain 0.6 ppmv CO.
the only criteria pollutant present in the stream (83). Total CO emissions
are estimated to be less than 1 kg/hr. Deaerator vent gas is expected to
consist primarily of steam with a small quantity of carbon dioxide and
traces of light hydrocarbons, although detailed characterization data are
not available.
Regeneration/decommissioning off gas from the nickel—urania reformer
catalyst will be intermittent in nature. No data are available regarding
the composition of the off gas; however, it is anticipated to consist
primarily of steam with 0.5% CO and 1 g/Nm 3 particulate. Small quantities
of Ni(CO) 4 may also be present in the off gas. Estimates of off gas
characteristics presented in Table 2-69 are based upon engineering
judgment.
Gaseous waste stream characterization data for the EDS MFS case are
presented in Table 2—70. The deaerator vent gas stream (stream 438) has
not been included in Table 2-70 since no characterization data are
2-137

-------
TABLE 2-69. GASEOUS WASTE STREAMS FROM THE EDS LIQUEFACTION RESIDUE
PROCESSING/HYDROGEN PRODUCTION AREA - ILLINOIS NO. 6 COAL
BASE CASE
Component
Stream 426*
Stream 438t
Stream 446$
Vent Gas
Deaerator
Regeneration!
From C02
Vent Gas
Decon nissioning
Removal
Off Gas From
Reformer Catalyst
H 2 , kmol,’hr
183.8
C 1 , kmol/hr
3.5
N 2 , kmol/hr
770.2
CU, kmol/hr
1.5
0.6 ppmv
49.2
CU 2 , kmol/hr
7443.2
H 2 0, kmol/hr
1862.8
9822.2
Total, kmol/hr
9494.8
No Data
10641.6
Total, kg/hr
361574
No Data
199903
Solids, kg/hr
291
Grand Total, kg/hr
361574
No Data
200194
Temperature, 0 K
339
No Data
No Data
Pressure, MPa
0.1
No Data
No Data
* Characteristics of vent gas from CO removal are based upon EDS design
data (83) and available data for ho carbonate processes (84).
t The CO concentration in deaerator vent gas is based upon design data
(83).
4 Regeneration/decommissioning off gas from reformer catalyst is inter-
mittent in nature. No data are available regarding the characteristics
of this stream; tabulated values represent engineering jud nents.
2—138

-------
TABLE 2—70. GASEOUS WASTE STREAMS FROM THE EDS LIQUEFACTION RESIDUE
PROCESSING/HYDROGEN PRODUCTION AREA - ILLINOIS NO. 6 COAL
MFS CASE
Component
Stream 428*
Stream 440f
Stream 449$
Acid Gas
Flash Gas
Plus Stream 450
From Acid
Gas Removal
From
Partial
Regeneration!
Decomissionirig
Oxidation
Off Gas From
Shift Catalyst
H 2 , kmol/hr
147.6
80.2
1775.3
C 1 , kmol/hr
0.4
0.1
N 2 , kmol/hr
1.8
1775.3
CD, kmol/hr
1.0
101.6
CD 2 , kmol/hr
15878.1
108.1
145.5
H 2 S, kmol/hr
194.6
14.7
NH 3 , kmol/hr
11.7
0.05
COS, kmol/hr
0.7
0.4
SO 2 , kmol/hr
320.1
H 2 0, kmol/hr
1316.3
24.9
26861.7
Total, kmol/hr
17550.4
331.9
29102.6
Total, kg/hr
729715
8795
560559
Solids, kg/hr
795
Grand Total, kg/hr
729715
8795
561354
Temperature, 0 K
110
322
No Data
Pressure, MPa
0.1
0 2
No Data
* Acid gas characteristics are based upon design data (24,83), Texaco
gasifier test data (8) and available data for hot carbonate processes
(84).
t Flash gas composition is based upon pilot plant data obtained using
SRC—II residue from Kentucky No. 9/14 coal (8).
$ Regeneration/decommissioning off gas would be intermittent. Off gas
compositions are based upon estimates provided in permit applications for
the ANR Synthetic Natural Gas Plant (27).
2-139

-------
available. It is assumed that this stream will be similar to the base case
deaerator vent gas with ppm levels of carbon monoxide as the only criteria
pollutant. This stream will also contain small amounts of carbon dioxide,
hydrogen sulfide, and aninonia.
The composition of the acid gas stream from acid gas removal (stream
428) has been estimated assuming that the Catacarb process is employed, and
is based upon design and test data (8,24,83,84). The acid gas stream will
contain 1% H 2 S, 700 ppmv NH 3 , 60 ppmv CO. and 40 ppmv COS.
Flash gas from the Texaco gasifier (stream 440) is generated on a
continuous basis as a result of the depressurization of water in
the gasifier circuit. Flash gas consists primarily of H 2 , CO and CO 2 with
4.4% H S, 0.12% COS, and 150 ppmv NH 3 (8). CompositIon estimates are based
upon pilot plant tests performed with SRC—II residue (Kentucky 9/1.4 coal).
Shift catalysts may require regeneration If carbon deposition occurs.
The shift units in an EDS plant would be modular with several parallel
trains. During regeneration, one or more trains would be taken off line
for regeneration ile others remain in service. Thus, emissions from
regeneration would be intermittent in nature (e.g., annually), depending on
the extent of coking, the number of trains and the exact regeneration
schedule. The duration of regeneration may range from 12 hours to 72
hours, depending on ich shift stage is being regenerated. Off gases from
regeneration/ deconmissioning of shift catalyst (streams 449 and 450) would
consist primarily of steam with 6% N 2 , 1% 2’ and 0.5% CO (27). In
addition, volatilized trace elements (e.g., Hg, As, Se) and particulate
matter are also expected tobe present, although data from actual operation
are not available.
The estimated composition of feed gas to the acid gas removal system
rs presented in Table 2—71. These data may be utilized to evaluate
alternative acid gas revomal systems for the EDS NFS case.
An additional stream requiring control is the sour fuel gas from the
Flexicoker heater/gasifier (stream 304). Sour fuel gas contains 0.4—0.5%
2-140

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sulfur as H 2 S and COS. With a heating value of 4.7 MJ/Nm 3 (125 Btu/DSCF),
combustion of sour fuel gas would result in SO emissions of approximately
2550 ng/J (5.9 lb/],O Btu). Hence, sulfur is removed from the sour fuel
gas prior to combustion in process heaters and boilers. Characterization
data for the sour fuel gas stream under base case and MFS case designs are
sumarized in Table 2-72. These data are based upon EDS design information
(83).
TABLE 2-71. ESTIMATED COMPOSITION OF FEED GAS TO THE EDS ACID
GAS REMOVAL UNIT - ILLINOIS NO. 6 COAL MFS CASE
Component Shift Gas
to Acid
Gas Removal*
H 2 , kmol/hr 24201.5
C 1 , kmol/hr 117.7
N 2 , kmol/hr 159.9
CO. kmol/hr 344.2
C0 2 , kmol/hr 16222.1
H 2 S, kmol/hr 195.0
NH 3 , kmol/hr 11.7
.COS, kmol/hr 0.8
H 2 0, kmol/hr 23302.8
HCN, kmolftir 0.03
Total, kmol/hr 64555.7
Total, kg/hr 1204901
Grand total, kg/hr 1204901
Temperature, 0 K 394
Pressure, MPa 6.2
* These data are based upon test and design data (8,24,26,83).
2-141

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TABLE 2-72. ESTIMATED COMPOSITION OF SOUR FUEL GAS FROM THE
FLEXICOKER HEATER/GASIFIER UNIT
Component
Stream 304* - Sour Fuel Gas
Base Case
MFS Case
H 2 , kmol/hr
C 1 , kmol/hr
N 2 , kmol/hr
CO, kmol/hr
15,284.3
1,293.7
40,080.7
15,305.8
7,014.6
544.3
16,307.1
6,192.9
C0 2 , kmol/hr
H 2 S, kmol/hr
COS, kmol/hr
9,871.3
356.7
9.2
4,107.5
158.3
3.3
120, kmol/hr
Total, kmol/hr
3,050.0
85,251.7
1,273.8
35,601.8
Total, kg/hr
2,105,229
862,486
Grand Total, kg/hr
T nperature, 0 K
2,105,229
316
862,486
316
Pressure, MPa
0.2
0.2
* Characterization data are based upon EDS design information (83).
Liquid Waste Strearr. —-
There are ten liquid waste streams generated within the EDS
liquefaction residue processing/hydrogen production area:
• Stream 307 - Flexicoking recontacting drum wastewater
• Stream 308 — Flexicoking fractionator overhead drum wastewater
• Stream 312 — Flexicoking heater overhead drum wastewater
• Stream 403 — knockout drum wastewater fr cryogenic hydrogen
recovery
• Stream 430 - blowdown and knockout drum wastewater (base case
only)
2-142

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• Stream 431 - Catacarb overhead receiver wastewater (base case
only)
• Stream 441 — sour water from the partial oxidation unit (MFS case
only)
• Stream 443 - slag filtrate fri the partial oxidation unit (MFS
case only)
• Stream 451 — aqueous aninonia from aninonia synthesis (base case
only)
• Stream 452 - knockout drum wastewater from aninonia synthesis
(base case only)
Estimated compositions of wastewater streams generated during EDS base
case and MFS case operation are presented In Tables 2—73 and 2-74,
respectively. Wastewater from Flexicoking (streams 307, 308, and 312)
contains 0.18—1.4% H 2 S, 0.02-1.4% NH 3 , and 20—3300 ppmw phenols, based upon
EDS design data (61). The fractionator overhead drum wastewater (stream
308) also contains 120 ppmw HC1. Detailed characterization data for
knockout drum wastewater from cryogenic hydrogen recovery (stream 403) are
not available, although this waste may contain traces of hydrogen sulfide,
aninonia, carbon dioxide, phenols, and organic acids.
Little data are available regarding the characteristics of wastewater
streams exclusive to base case operation. Blowdown and knockout drum
wastewater (stream 430) and Catacarb overhead drum wastewater (stream 431)
are anticipated to be free of hydrogen sulfide, phenols and organic acids,
but may contain traces of aninonia. Aqueous aninonia (stream 451) from
aninonia synthesis (nitrogen removal) contains 11.5% NH 3 and possibly traces
of hydrogen sulfide and organics. Any pollutants present in the knockout
drum wastewater from amonia synthesis (stream 452) are anticipated to be
present at trace levels.
Compositions of wastewater streams exclusive to MFS case operation,
wastewater from the partial oxidation unit, are based upon test data and
design data from the EDS and SRC-II processes (24,26, 65,151). Sour water
from partial oxidation (stream 441) contains 7500 ppmw NH 3 , 540 ppmw HCN
and about 1000 ppmw of formate. Based upon limited test data fran, coal
2-143

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Table 2-73. ESTIMATED COMPOSITION OF WASTEWATER STREAMS FROM THE [ OS LIQUEFACTION
RESIDUE PI1OCESSING/HYDROGEN PRODUCTION AREA • ILLINOIS NO. 6 COAL BASE CASE*
Stream 307
Flextcoking
Recontacting
Drum
Wastewater
Stream 308
Flexicoking
Fractionator
Ovhd. Drum
Wastewater
Stream 312
Flexicoking
Heater Ovhd.
Drum
Wastewater
Stream 403
K.O. Drum
Wastewater
From Cryo.
Recovery
Stream 430
Blowdown and
k.O. Drum
Wastewater
Stream 43)
Catacarb
Ovhd. Drum
Wastewater
Stream 451
Aqueous
Aimnonla
From
Synthesis
Stream 452
K.O. Drum
Wastewater
From A rmion1a
Synthesis
H 2 5, ppmw
17,730
1,770
6,020
TR
No Data
No Data
1K
tb Data
N H 3 , pp.m
240
2,140
13,930
1K
No Data
No Data
115,260
No Data
HC1, ppntw
No Data
120
No Data
No Data
No Data
No Data
No Data
No Data
CD 2 , ppn
26,080
2,620
21,680
TR
1K
600
1K
TR
Phenols, ppmw
18
3,290
16
TR
No Data
No Data
No Data
No Data
Organic Acids, ppmw
No Data
No Data
No Data
TR
No Data
No Data
No Data
No Data
Flow Rate, kg/hr
m 3 /hr
2,03 )
2.1
155,413
156.9
44,202
44.6
2.075
2 ,1
86,276
89.8
35,322
36.0
35,114
39.1
/06
0.7
Temperature, ‘K
316
316
316
316
366
339
322
311
Pressure, MPa
0.5
0.9
0.7
10.3
1.7
1.4
12.9
12.4
Estimated stream concentrations are based upon [ OS design data (61)

-------
Table 2-74. ESTIMATED COMPOSITION OF WASTEWATER STREAMS FROM THE [ OS LIQUEFACTION
RESIDUE PROCESSING/HYDROGEN PRODUCTION AREA - ILLINOIS NO. 6 COAL MFS CASE
Stream 307*
Stream 300*
Stream 312*
Stream 403*
Stream 441t
Stre m 443t
Flexicoking
Flexicoking
Flexicoking
K.O. Drum
tour Water
Slag rntrate
Recontacting
Fractionator
Heater Ovhd.
Wastewater
From Partial
From Partial
Drum
Ovhd. Drum
Drum
From Cryo.
Oxidation
Oxidation
Wastewater
Wastewater
Wastewater
Recovery
11 2 S, pprnw 17,730 1,770 6,020 TR TR 1
NH 3 , ppmw 240 2,140 13 930 TR 7,500 10
lid, ppmw No Data 120 No Data No Data TR No Data
C0 2 , ppmw 26,080 2,620 21,680 TR TR TR
Phenols, ppmw 18 3,290 16 TR TR 5
ti,)
Z Organic Acids, ppmw No Data No Data No Data TR No Data No Data
U,
HCN, ppmw No Data No Data No Data No Data 540 1
S 2 0 3 , ppmw No Data No Data 110 Data No Data No Data 75
Formate No Data No Data No Data No Data 1 ,000 100
Flow ate, kg/hr 860 41,895 18,756 1,744 59,561 12,187
m 3 /hr 0.9 42.3 18.9 1,8 59.6 12
Temperature, 316 316 316 316 No Data 316
Pressure, MPa 0.5 0.9 0.7 10.3 No Data 0.1
[ sti natrd stream compositions are based upon [ OS desiqn data (61).
LtiffldtCd st.rf InI compositions are based U Ofl [ OS and SRC-II desiqn data and test data (24,26,65,151).

-------
gasification with Texaco gasifiers, polycyclic hydrocarbons (e.g.,
anthracene, fluoranthene, naphthalene, and pyrene) are present at part per
billion concentrations (26). Slag filtrate (stream 443) will be similar in
composition to the gasifier sour water, although it will not contain
significant quantities of anTnoniaor cyanide, and the expected concen-
tration of formate will be an order of magnitude lower. Additional
characterization data for wastewater streams from partial oxidation are
presented in Table 2-75.
Solid Wastes- —
There are 15 solid waste streams generated within the EDS liquefaction
residue processing/hydrogen production area:
• Stream 302
• Stream 303
• Stream 306
• Stream 313
• Stream 404
recovery
• Stream 405
• Stream 433
case only)
• Stream 435
(base case
• Stream 436
case only)
• Stream 439
(base case
• Stream 442
• Stream 444
generation
• Stream 445
generation
- Flexicoker gasifier/heater dry fines
- Flexicoker gasifier/heater wet fines
- Flexicoker heater bed coke
- Flexicoker heater chunks/agglomerates
— spent hydrotreater catalyst from cryogenic hydrogen
- spent drying agents from cryogenic hydrogen recovery
- spent sulfur guard from hydrogen generation (base
- spent reformer catalyst from hydrogen generation
only)
- spent shift catalyst from hydrogen generation (base
— spent inethanation catalyst from hydrogen generation
on 1 y)
— slag from the partial oxidation unit (MFS case only)
- spent high temperature shift catalyst from hydrogen
(MFS case only)
- spent low temperature shift catalyst from hydrogen
(MFS case only)
2—146

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TABLE 2-75. ESTIMATED WATER QUALITY DATA FOR WASTEWATER FROM
TEXACO GASIFICATION*
Stream 441 Stream 443
Sour Water Slag Filtrate
(Blowdown)
TDS, g/rn 3 2000 400
TSS, g/m 3 330 No Data
TOC, 9/rn 3 450 30
COD, g/m 3 400 200
so 4 , g/m 3 20 40
Trace elements, ppm
As 0.022 0.07
Ba 0.54 0.10
Be 0.018 0.005
Cd 0.003 0.003
Cr 0.006 0.003
Co 0.021 0.10
Cu 0.01 0.017
F 175 31
Hg <0.0001 <0.0001
Mn 0.104 0.08
Mo <0.02 0.03
Ni 0.03 0.07
Sb <0.001 0.016
Se 0.010 0.033
Ti 0.01 0.006
V <0.04 <0.04
Zn 0.03 0.046
* Based on data from gasification of Eastern Bituminous coal (26,151).
2-147

-------
• Stream 453 - spent drying agents from amonia synthesis (base
case only)
• Stream 454 - spent aninonia synthesis catalyst (base case only)
Solid waste generation rates for the EDS base case and MFS case are
sunriarized in Table 2-76. Generation rates have been estimated based upon
EDS design data (63,65,83). Solid wastes from Flexicoking are coke, dry
and wet fines, and agglomerates. Combined solid waste production rates
from Flexicoking are 1.57 x io6 Mg/yr and 6.81 x Q5 Mg/yr during base case
and MFS operation, respectively. Dry wastes have a bulk density of
approximately 38 pounds per cubic foot. Wet fines are delivered to battery
limits as a water slurry with 6% solids. The average composition of these
solid wastes Is approximately 67% coal ash and 33% carbonaceous material.
Estimated average concentrations of major and trace elements and limited
leaching data are presented in Appendix A. Concentrations are anticipated
to be similar to those in the feed coal ash, corrected for carbon dilution,
although analytical data are not available. Leaching data indicate that
Flexicoking fines are non—hazardous according to RCRA criteria.
Spent catalyst compositions will be generally similar to fresh
catalyst compositions although contaminants such as sulfur and volatile
trace elements present in the vacuum bottoms (e.g., As, Pb, Se, and Hg) may
be present. Bulk density data for these materials are sumarized in Table
2—77. No data are available on the leaching susceptibility of spent
catalysts or sulfur guard, although the potential exists for these wastes
to be classified as hazardous according to RCRA guidelines.
Drying agents such as alumina and zeolites are generally inert in
aqueous environments and alone would likely be non—hazardous according to
RCRA guidelines. However, it Is possible that accumulated leachable trace
elements would be present in sufficient quantities to exceed RCRA criteria.
Slag from the Texaco gasifier is provided to the slag handling system
in two streams: 1) a 90% solids coarse slag stream and 2) a 20% solids
fine slag slurry. After dewatering, coarse and fine slag fractions are
combined to yield a 16% moisture waste gasifier slag (stream 422) to
2-148

-------
TABLE 2—76. SOLID WASTES iENERATED WITHIN NE EDS LIQUEFACTION
RESIDUE PROCESSING/HYDROGEN PRODUCTION AREA*
Stream Descript
Number
ion neration Rate,
— (dry basis)
Base Case
Mg/yr
MFS
Case
302 Flexicoker heater/gasifier
dry fines 211,000 87,400
303 Flexicoker heater/gasifier
wet fines 211,000 87,400
306 Flexicoker heater bed coke 1,120,000 494,000
313 Flexicoker heater chunks/
agglomerates 32,600 11,700
404 Spent hydrotreater catalyst
(Ni -Mo based) 52 21
405, 453 Spent drying agents 119 39
433 Spent sulfur guard (ZnO) 117 Not Present
435 Spent reformer catalyst (Ni U
based) 144 Not Present
436 Spent shift catalyst (iron oxide) 297 Not Present
439 Spent methanation catalyst (Ni
based) 38 Not Present
442 Slag from partial oxidation Not Present 395,000
444 Spent high temperature shift
catalyst (Cr—Fe based) Not Present 360
445 Spent low temperature shift
catalyst (Cu—Zn based) Not Present 101
454 Spent amonia synthesis
catalyst (Fe based) 122 Not Present
* Generation rates are based upon EDS design data (63,65,83).
2-149

-------
TABLE 2—77. CATALYST, SULFUR GUARD AND DRYING AGENT BULK
DENSITY DATA FOR THE HYDROGEN GENERATION AREA
Catalyst
Bulk Density, kg/rn 3
Hydrogenation — Ni-Mo
641
Hydrotreater - Ni-Mo
800
Sulfur Guard — Zinc Oxide
1090
Reformer — Nickel Urania
1360
Shift — Iron Oxide, Cr—Fe, Cu—Zn
1120
Methanation — Nickel Oxide
1040
Aiimionia Synthesis — Iron Oxide
865
Alumina
881
Molecular Sieve
721
2-150

-------
disposal. Characterization data are not available for slags from
gasification of EDS vacuum—bottoms residues. The slag is anticipated to be
similar in composition to the feed coal ash with up to 2% carbonaceous
material. Major and trace element concentrations in the slag have been
estimated from feed coal ash analyses and are presented in Appendix A.
Size distribution and leaching data have been published for slag
produced in the Texaco pilot plant at Montebello, California. This slag
resulted from gasification of SRC-II flash drum bottoms obtained with
Kentucky No. 9/14 coal (3,8). Detailed results are presented in Appendix
A. Bulk and true specific gravities of the composite dry slag were found
to be 1.64 and 2.62, respectively. Approximately 50% of the dry composite
slag is smaller than 0.4 ITIU. Batch leaching tests were performed using
slag/extractant weight ratios, time intervals, and equipment suggested in
the proposed standard leaching tests. Column leaching tests were performed
in 95 nr (3.75 inch) diameter columns using a slag depth of 305 nm (12
inches) and approximately one liter of demineralized water extractant.
Results of these tests appear to indicate that the slag is a non-hazardous
material. Low levels of polynuclear aromatics were detected in the slag by
benzene extraction) although details of the extraction procedure are not
available.
2—151

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2.2.6 Auxiliary Operations
2.2.6.1 Raw Water Treatment
Various treatments are required to render raw waters to be suitable
for use as boiler feed water, cooling tower makeup water and potable water
in direct liquefaction facilities. The degree of treatment required
depends upon the characteristic of the raw water and the end-use water
quality requirements. Table 2-78 presents the source and characteristic of
raw waters assumed for the EDS direct liquefaction facility, and Figure
2—14 presents a block flow diagram of the raw water treatment systems.
Boiler feed water has highest quality requirements and thus required more
sophisticated treatment.
Raw water is generally pumped from rivers and stored in a reservoir.
This storage: 1) provIdes a reliable supply of water to the facility
independent of river flow, 2) reduces the impact of raw water quality
variation, and 3) allows sedimentation of silts and other large suspended
materials.
The raw water is chlorinated to prevent biogrowth to destroy organics,
and to oxidize reduced species (mainly iron and manganese) to their more
insoluble oxidized form for removal In the subsequent coagulation!
sedimentation step.
Alum and polymers are generally added in the coagulation step to
improve suspended solids removal. After the coagulation/settling step, the
water is generally suitable for use as cooling tower makeup. If high
recirculation is required, acidification to reduce bicarbonates and/or
addition of lime and magnesium hydroxide to remove hardness may be
requi red.
A filtration step is usually required to protect the demineralization
units, and to render the water suitable for use as potable water. The
filter effluent passes through the demineralization unit. The deminerali-
zation effluent is essentially pure water and is used as boiler feed water.
2—152

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COOLING IOWLR MAKIUP WAlER
BACKWASH t POTABLE WATER
RAW —
BOILER FEED
WATER
STORAGE — CHLORINATION COAGULATION / ATION T 1 ’ REGENERATION CHEMICALS
DEMINERAL I— -$ WATER
RESERVOIR CLARIF I
ZAT ION
CATION
REGENERATION
N)
THICKENING WASTE
0 1
4 —
VACUUM
FILTRAT ION
SLUDGE
Figure 2-14 Raw Water Treatment Block Flow Diagram

-------
TABLE 2-78. SOURCES AND CHARACTERISTICS OF RAW WATER FOR EDS
.
Parameter*
EDS
Mississippi
River
Total Hardness,
M—Alkalinity
as
ppm
CaCO 3
130
105
$04
Ca
46
37
Mg
9
Na
9
Ci
10
5102
pH
6
7.7
*
All concentrations except pH expressed in mg/i.
As shown in Figure 2—14, there are two major waste streams from the
raw water treatment operation, namely sludges from the clarification units
and the regeneration brines from regenerating the demineralization unit.
Raw Water Treatment Sludge
The sludge coming off the filter press is a cake—like material with
about 60% moIsture content, and consists mainly of calcium carbonates and
magnesium hydroxide. The estimated characteristics of this stream for the
EDS liquefaction facilities are presented in Table 2-79.. As the data
indicate, this is a small stream, and although there is no RCRA-EP data, it
Is believed that this Is nonhazardous and can be disposed of in
nonhazardous waste landfills.
2—154

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Regeneration Brine
The estimated characteristics of the demineralizer regeneration waste
are presented in Table 2-79. This waste stream contains high dissolved
solid and is assumed to be routed to the brine concentrator.
TABLE 2—79. ESTIMATED CHARACTERISTICS OF RAW WATER TREATMENT
SLUDGE AND 6 ENERATIOM WASTE BRINE
Parameter EDS - Base Case
Raw Water Treatment Sludge
Quantity, Mg/day 30
H 2 0, S 60
CaCO 3 , 5 36.4
Mg(OH) 2 , S 3.6
Regeneration Waste Brine
Flow rate, Mg/day 30
Ca, mg/i 1,030
Mg, mg/i 760
Na, mg/i 2,280
SO 4 , mg/i 11,690
Cl , mg/i 530
NO 3 , mg/i 100
Si0 2 , mg/i 70
2.2.6.2 Steam arid Power Generation
Both steam and power requirements vary with the mode of operation.
For the Illinois Coal Base Case both requirements increase with increased
production rate of low Btu gas. In order to estimate emissions, heat and
material balances for IBC were based on an averaged maximum plant
requirements. In the Market Flexibility Sensitivity Case (MFS) data were
available only for the normal production mode thus these data were used for
2-155

-------
the calculations. Available data were scaled up so as to be representative
of a model 100,000 BPSD EDS plant, Assumptions and calculation details are
presented in Appendix B.
Steam is mainly produced on—site In the steam reformer and flexicoker.
Additional steam to satisfy plant requirements Is produced in auxiliary
steam boilers firing low Btu gas (LBG) and coal.
Maximum steam requirements for ICB case are 1770 Mg/hr for the high
LBG production mode. Required heat can be supplied by coal and LBG used at
rates of 1590 )/hr (1509 x io6 Btu/hr) and 1470 GJ/hr (1393 x io6 Btu/hr),
respectively. For the MFS case heat requirements were estimated to be 3200
GJ/hr (3030 x io6 Stu/hr) and 960 GJ/hr (908 x 10 Btu/hr) for coal and
LBG, respectively.
Although the EDS commercial design stipulated the purchase of power
from a local utility, some coal liquefaction plants may opt for on—site
power generation. Thus, heat and material balances were estimated and
potential emissions calculated, Heat requirements were assumed to be
supplied by use of Illinois #6 type bituminous coal.
For the base case an average power requirement during the high LBG
production mode Is estimated to be 245 MW. However the estimates are based
on the maximum power requirement of 288 MW. This power will be supplied by
use of coal at a rate of 3020 GJ/hr (2865 x Btu/hr). For a normally
operating MFS case, 389 MW of power use is required. This power can be
supplied by the use of coal equivalent to 4120 GJ/hr (3903 x Btulhr).
These are three major fule gas streams from the combustion of low Btu
gas (LBG) In process furnaces. These include the flue gas from the
liquefaction slurry preheat furnace (stream 107), the hydrogenation fuel
preheat furnace (stream 203), and the hydrogen plant reformer furnance
(stream 434, base case only).
2—156

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Potential emissions from steam and power generation, and process
furnaces are presented in Table 2-80. Assumptions, calculation details and
balances can be found in Appendix B.
2.2.6.3 Cooling Operation
All direct liquefaction plants generate nonrecoverable heat, most of
which is dissipated through cooling towers. There are several types of
cooling operation, including wet cooling, dry cooling, and indirect
cooling. The selection/design of optimum cooling systems would require
detailed heat balances for the whole plant, and is beyond the scope of this
study. From the environmental point of view, only wet cooling results in a
waste stream which requires treatment or discharge. Table 2-81 presents
total plant wet cooling loads for the EDS coninercial plant.
A wet cooling tower removes heat by evaporating part of the
circulating water. To prevent excessive buildup of impurities in the
circulating circuit, some of the circulating water must be removed from the
system. Makeup water is required to compensate for losses through
evaporation, blowdown, and to a lesser extent, drift. The makeup watel can
either be from treated raw water or from heated process wastewater. Thus,
cooling operation not only affects the overall plant water balance, but can
also be a critical factor in the disposal and reuse of process wastewater.
TABLE 2-81. COOLING TOWER LOADING FOR EDS COMMERCIAL PLANT
Cooling Tower Parameter
Base Case
MFS
Case
Circulation rate, m 3 /hr
59,180
(260,610 gpm)
69,430
(305,700 gpm)
Drift and evaporation,
m 3 /hr
740
(3,260 gpm)
870
(3,820 gpm)
Blowdown, m 3 /hr
677
(2,980 gpm)
707
(3,110 gpm)
Makeup, m 3 /hr
1,420
(6,240 gpm)
1,580
(6,930 gpn)
2-157

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TABLE 2-80. ESTIMATED UNCONTROLLED EMISSIONS FROM EDS STEAM AND POWER PLANTS,
AND PROCESS FURNACES
Steam Plants
Base Case MFS Case
(kgfhr) (kgfhr)
4,700 9,437
726 1 ,03l
Power Plants
Base Case MFS Case
(kg/hr) (kg/hr)
8,985 12,151
785 1 602
Process Furnaces
Base Case MFS Case
(kg/hr) (j g hr)
417 148
6,399 2,277
Pollutant
-a
(7 1
03
TSP
NO
(as
NO 2 )
CO
14.6
65
61.9
83.5
473
168
HC
(as
Cu 4 )
9.7
19.5
18.5
25.0
84
30
SO 2
4,486
9,032
8,610
11,608
383
136
MFS - Market Flexibility Sensitivity

-------
Discharges from cooling towers consist of blowdown, entrained water or
drift, and stripped gases. Table 2-82 is a suninary of the blowdown and
drift characteristics. The estimates are based upon the use of Mississippi
river water and a concentration cycle of two.
TABLE 282. COOLING TOWER BLOWDOWN AND DRIFT CHARACTERISTICS
Parameter Concentration, mg/i
Hardness, as CaCO 3 260
TDS 500
Alkalinity, as CaCO 3 205
Cr 0.8
Cu 0.25
Fe 0,8
Mg 18
Na 18
Mi 0.03
Si
Zn 1
Sulfate 1,700
Chloride 20
Nitrate 8
Phosphate-P 4
2.2.6.4 Oxygen Production
Oxygen required for partial oxidation is assumed to be produced by
standard cryogenic air separation units. Air is compressed to 0.58 to 0.61
MPa (85—90 psia) and cryogenically cooled to facilitate distillation of
oxygen, nitrogen and noble gases (153). The oxygen stream, containing
small quantities of nitrogen and argon, is compressed and sent to the
gasifiers. Air and oxygen compressors can either be steam, gas, electric
driven or a combination thereof. The separated nitrogen containing small
quantities of oxygen, water and carbon dioxide is primarily vented to the
2-159

-------
atmosphere. However, a portion of the nitrogen stream may be utilized as
an Inerting agent for coal storage and transfer, and/or as stripping gas
for solvent regeneration In acid gas treatment and phenol recovery units.
The quantity of condensate resulting from air compression depends upon
atmospheric humidity and therefore, is highly variable. Condensate
contains only dissolved gases and can be utilized as a supplement to the
plant high quality water supply. The estimated EDS MFS case oxygen
requirement is 5800 Mg/day.
Production of oxygen does not directly generate waste streams
requiring treatment, since chemical reactions do not take place in the air
separation process nor are any chemicals added to the process streams. A
gaseous waste stream containing mostly nitrogen and a liquid condensate
stream are produced but these streams should both be pollutant free.
Cooling water required to reduce the compressed air temperature prior to
cryogenic cooling results in increased drift and blowdown from the cooling
towers. Emissions indirectly associated with the compressors are dependent
upon the type of power drive (either steam, gas, or electric).
2.2.6.5 Product and By-Product Storage
Storage capacities for product and by-products were estimated based
upon the expected production rates of upgraded liquid and gaseous fuels for
the EDS direct liquefaction plant. Table 2-83 provides a summary of the
storage capacities, vessel types, and estimated mass emission rates for the
various liquids. Storage for the EDS process plant consists of a variety
of storage tanks for liquid products, by—products, and make up chemicals.
Depending on the vapor pressure of the liquid stored, the design
incorporates floating roof, fixed (cone) roof, pressurized or dome type
tanks. The more volatile products (e.g., LPG, ammonia) are stored in
pressure vessels and are expected to have no routine evaporative emissions.
Pcoducts such as naphtha are stored in floating roof tanks while fuel oil,
phenol, vacuum gas oil, etc., are stored in fixed roof tanks. Some streams
such as sour water/phenolic water require intermediate storage and are
stored in dome tanks. Various products such as vacuum bottoms,
liquefaction hydrogenated recycle solvents, blended fuel oil, etc., require
2—160

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Vapor
Pressure
Product
Type of Tanks
# of
Tanks
Capacity
c 3
Liters
of Stored
Liquid
kPa
Uncontrolled
Emissions
Illinois Coal
Base Case
,
Naphtha
Floating Roof
5
19,100
10.0
37,900
Blended Fuel Oil
Fixed Roof
5
16,100
0.0003
45
Phenol
Fixed Roof
6
335
0.14
1,990
Market Flexibility
.
Sensitivity Case
Naphtha
Floating Roof
5
16,100
10.0
34,570
Blended Fuel Oil
Fixed Roof
5
13,200
0.0003
37
Phenol
Fixed Roof
6
280
0.14
1,680
+ Blended fuel oil requires storage at 160°F, therefore, the storage tank is insulated
and heated. As a result, uncontrolled emissions only consist of working losses.
TABLE 2-83. EVAPORATIVE EMISSIONS FROM THE EDS PR0DUCT/8y-pRontJcT
STORAGE FACILITIES
-J
a’

-------
storage at temperatures ranging from 70°C to 260°C (160°F to 500°F).
Consequently, these tanks are provided with a heating mechanism and are
insulated.
From an emissions standpoint, floating roof and fixed roof tanks are
of potential concern. Under normal conditions, no evaporative emissions
are expected from pressurtzed tanks or cylindrical/fixed roof tanks
containing non—volatile compounds. Both in the Illinois Coal Base case and
the Market Flexibility Sensitivity (MFS) case, storage tanks containing
fuel oil, naphtha, and phenol were identified as the main sources of
evaporative emissions. Since tanks containing fuel oil are heated and
Insulated from the normal daily variation of ambient temperature, no
breathing loss from such tanks is expected.
Data on the components of evaporative emissions associated with
storage of coal derived liquid fuels are generally lacking. However,
limited data are available regarding the chemical composition of some of
the direct liquefaction products. For example, the major constituents of
naphtha are paraffins, naphthenes and arcmatics and these are also expected
to be present in evaporative emissions. Hydrotreating of naphtha reduces
the aromatic and removes the olefins and polar fractions.
No data are available on the composition of evaporative emissions from
the storage of tar oils although it is expected that the vapors would
consist of mostly C hydrocarbons.
2—162

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2.2.7 Fugitive and Transient Emissions from Plant Operations
Since no data on fugitive emissions exists for direct coal
liquefaction, it was assumed that fugitive emission streams are similar to
those found in petro’eum refineries. In addition 1 , transient emissions have
been assumed to be siruilar in composition to gases produced throughout the
plant during normal operation. These emissions are discussed in the
ensuing sections.
2.2.7.1 Fugitive Hydrocarbon Emissions
No emission estimates were made for the EDS process since component
data from ER&E Co. are not yet available.
2.2.7.2 Transient Emissions
Gases generated during startup, shutdown, and upset conditions may not
be suitable for use within the liquefaction facility. No data are avail-
able on the characteristics or magnitudes of such transient waste gases,
and in any case, the gas composition would be expected to vary greatly
during the transient period and from occurrence to occurrence. Further,
the frequency of transient conditions is difficult to estimate since
routine startup/shutdown would be plant-specific and upset conditions are
not predictable. It is expected that transient waste gases would be
generated in larger amounts during the early life of a plant than after
some operating experience has accumulated.
Themajor potential sources of transient waste gases are the
liquefaction, Flexicoking, and partial oxidation (MFS case only) units.
Transient waste gases from the liquefaction unit are anticipated to be
similar in composition to the liquefaction separator sour gas (stream 104).
The normal flow rate of this stream would be 432,000 Nm 3 /hr during base
case operation and 405,000 Nm 3 /hr during MFS case operation. Stream
composition data are sunii arized in Table 2-85. These data are considered
to be indicative of the liquefaction waste gas composition during startup
or shutdown operations. A major upset requiring blowdown of the dissolver
2-163

-------
TABLE 2-85. ESTIMATED COMPOSITION OF MAJOR TRANSIENT WASTE GASES
FROM THE EDS LIQUEFACTION PLANT*
C9mponent
Liquefaction
Volume Percent in
Waste Gas
Flexicoker
Partial
Separator
Fractionator
Oxidation
Off Gas
Off Gas
Quenched Gas
50.5 44.6 20.2
Cl 34.9 31.2 0.2
C 2 6.6 5.5
C 3 2.5 1.7
C 4 0.7 0.5
C 5 0.2 0.7
C 6 — 400°F 0.1 3.4 ppmv
400 - 700°F 20 ppmv
N 2 4.5 0.3
CO 0.5 4.0 17.7
CO 2 1.2 2.7 7.9
H 2 S 2.6 1.4 0.3
NH 3 49 ppmv 1.4 170 ppmv
COS 167 ppmv 253 ppmv
H 2 0 702 ppmv 1.8 53.4
HCN 8 ppmv
HCO 2 H 70 ppmv
Temperature, 0 K 316 316 No Data
Pressure, MPa 12.7 0.5 No Data
Estimated compositions are based upon EDS design data (62,63,64, 65,83)
and are considered to be indicative of transient waste gas compositions
during startup and shutdown operations. Transient waste gas from the
liquefaction unit may contain substantially greater amounts of organics,
depending on the details of the transient event resulting in waste gas
generati on.
2—164

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system would generate substantially more waste gas and result in higher
concentrations of organics.
Transient waste gas from Flexicoking is assumed to be similar in
quantity and composition to the flexicoker fractionator off gas (stream
310). Assuming that three Flexicoker wiits are employed during base case
operation, an order of magnitude estimate of the transient waste gas
production- rate is 25,500 P ii 3 /hr per unit. Assuming that two Flexicoker
units are employed during MFS case operation, an order of magnitude
estimate of the transient waste gas production is 15,700 n 3 /hr per unit.
Stream composition data are suninarized in Table 2-85. Approximately three
Flexicoker outages are anticipated per year. No data are available
regarding duration of transient emissions per outage.
Transient waste gas from partial oxidation is assumed to be similar in
composition to quenched syngas. Assuming that four partial oxidation units
are employed, an order of magnitude estimate of transient waste gas
emissions is 382,000 Nm 3 /hr per unit. Stream composition data are suma-
rized in Table 2—85. Gasifier outages are anticipated to occur at a rate
of approximately five per year. The average duration of transient
emissions is estimated to be about one day per outage.
2—165

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2.2.8 Summary of Gaseous, liquid, and Solid Waste Streams
The primary gaseous waste streams requiring control in the EDS
coninercial plant are the acid gas streams generated from various process
operations. The characteristics of these acid gas streams are summarized
in Tables 2-86 and 2—87 for the base case and MFS case designs,
respectively. As shown in these tables, one acid gas stream (stream 508)
in the base case and two acid gas streams (streams 508 and 428) in the MFS
case are generated by acid gas removal (AGR) processes In gas purification.
One other acid gas stream (stream 501) is generated from sour water
stripping. One acid gas stream (stream 304) in the base case and two acid
gas streams (streams 304 and 440) in the IfS case are sour fuel gas streams
which will require treatment either before or after combustion as fuel.
Also summarized in Table 2—86 are the characteristics of a CO 2 rich stream
from the Catacarb unit in the base case design. This stream contains trace
quantities of organics and may require incineration prior to release to the
environment. Detailed characteristics of the acid gas streams and the CO 2
rich stream are given in Sections 2.2.4 and 2.2.5.
There are sixteen sour and phenolic wastewater streams in the base
case, and thirteen sour and phenolic wastewater streams in the IfS case
from the EDS commercial plant. The characteristics of these sour and
phenolic wastewater streams are summarized in Tables 2—88 and 2-89 for the
base case and IfS case designs, respectively. The slurry dryer cold
separator wastewater (stream 103) is a non-sour phenol Ic wastewater stream
which can be sent directly to the phenol extraction unit without sour water
stripping. Detailed characteristics of the sour and phenolic wastewater
streams are given in Sections 2.2.3, 2.2.4, and 2.2.5.
In addition to the sour and phenolic wastewater streams, there are
eight sources of other wastewater streams in the base case and nine sources
i n the IfS case from the EDS commercial plant. The characteristics of
these wastewater streams are summarized in Tables 2-90 and 2—91 for the
base case and MFS case designs, respectively. Stream 504 is derived from
treatment of the sour and phenolic wastewater streams. The characteristics
of this stream will, therefore, depend on the particular sour water
2—166

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TABLE 2-86. JMMARY OF ACID GAS STREAMS FROM [ OS
COMMERCIAL PLANT (ILLINOIS COAL BASE CASE)
Stream Stream Description Stream
Pollutants
Concentrations
Factors Affecting
No.
Flow Rate
(kmol/hr)
of
Potential
Concern
of Major
Pollutants
Effluent Stream
Characteristics
508 Acid gas from DEA 1,889 H 2 S, NH 3 , H 2 S - 64.2% • Coal composition
unit COS NH3 3.9% • AGR process used
COS - 476 ppm
501 Acid gas from sour 449 H 2 S, NH 3 H 2 S - 60.3% • NH recovery
water strlpper/ NH 3 - 0.61% process used
arrunonia recovery
304 Acid gas from 85,249 FI 2 S, COS H 2 S - 0.42% • Gàslfier type
Flexicoker COS - 107 ppm
gasifier/heater
(sour fuel gas)
426 C02 rich stream 9,305 Organics Organics - trace • CO 2 removal
from Catacarb process
unit

-------
TABLE 2-87. SUMMARY OF ACID GAS STREAMS FROM EDS
COMMERCIAL PLANT (ILLINOIS COAL MFS CASE)
Stream
No.
Stream Description
Stream
Flow Rate
(kmol/hr)
Pollutants
of Potential
Concern
Concentrations
of Major
Pollutants
Factors Affecting
Effluent Stream
Characteristics
508
501
Acid gas from DEA
unit
Acid gas from sour
water strlpper/
anunonia recovery
1,492
321
H 2 S, NH 3 ,
COS
H2S, N113
H 2 S - 64.2%
NH 3 - 3.9%
COS - 476 ppm
H2S - 60.3%
NH 3 - 0.61%
•
•
•
Coal composition
AGR process used
NH 3 recovery
process used
304
Acid gas from
Flexicoker
gasifier/heater
(sour fuel gas)
35,600
H 2 S, COS
H2S - 0.44%
COS - 92 ppm
•
Gasifier type
.
.
428
Acid gas from
Catacarb unit In
hydrogen purlf 1-
cation
17,551
H2S, COS
H 2 S - 1.1%
COS — 47 ppm
•
AGR process used
440
Flash gas from
partial oxidation
unit (Texaco
gasi fier)
332
H 2 S, CO,
COS
H 2 S - 4.4%
CO - 30.6%
COS - 1230 ppm
•
Gasifler type

-------
TABLE 2-88. U1!IARY OF SOUR AND PHENOLIC WASTEWATER STREAMS
FROM LOS COMt1E CIAL PLANT (ILLINOIS COAL BASE CASE)
Stream Stream Description Streaim
Pollutants
Concentrations
Factors Affecting
No.
Flow i ate
(m 3 l r)
of Potential
Co cern
of Major
Poflutants
Effluent Strear
Characteristics
103 Slurry dryer cold
separator wastewater
246 Phenols
Phenol s—968 v / i
. Coal composition
106 Liquefaction cold
separator wastewater
152 Atmospheric fractionator
overhead drum wastewater
155 Vacuum fractionator
overhead drum wastewater
202 Solvent hydrogenation
cold separator wastewoter
Solvent hydrogenation
fractionator overhead
drum wastewater
30B Flexicoking fractionator
overhead drum wastewater
307 Flexicoking recontacting
drum wastewater
312 Flexicoking heater over-
head drt wastewater
403 Knockout drum wastewater
in H 2 cryo recovery
430 Blowdown and KO. drum
was tewa ter from H 2
generation
431 CatacarD overhead
receiver wastewater in
H 2 generation
452 Knockout drum wastewater
in ammonia synthesis
H 2 S, NH 3 ,
phenols, CD 2 ,
organic acids,
MCI, ketones.
SCN, CN,
PHA s
H 2 S-16,700 mg/i
NH3—13 ,810 mg /;.
Phenols-8,080 mgi;.
C0 2 —9,910 mgi;.
Organic acids-
2.890 mnJL
HC1-l,030 mg/i
Ketones and
aldehydes-220 ngiz
PNAs -l.5 mgi;.
SCN-lO mg/i
CN -4 mg/ i.
C0 2 —600 mg/i.
NH3- trace
NH 3 — trace
• Coal composition
• Liquefaction reactor
operating condition
• Flexicoker operating
condi tion
451 Aqueous aermnia from
ammonia synthesis
515 Sour water from sulfur
recovery plant
39
- 2 H 2 S, NH 3
lH 3 -ll .5
H 2 5— trace
NH 3 - trace
• Flexicoke— oesign
• Plant desi:n
516 Sour water from sulfur
plant tail gas treatment
unit
20 H 2 5, N H 3
i*2S- trace
NH 3 - trace
• Plant esi n
160
48
8
21
20
1 57
2
45
2
NH 3 — trace
90 NH 3
36 NH 3 , CO 2
0.7 NP1 3
• Plant design
• Plant design
• Plant des cri
2-169

-------
103 Slurry dryer cold
separator wastewater
106 Liquefaction cold
separator wastewater
152 Atmospheric fractionator
overhead drum wastewater
155 Vacuum fractionator
overhead drum wastewater
202 Solvent hydrogenation
cold separator wastewater
252 Solvent hydrogenation
fractionator overhead
drt’m wastewater
308 Flexlcoking fractionator
overhead drum wastewater
301 Flexicoklng recontacting
drum wastewater
312 Flexicoking heater over-
head drum wastewater
403 Knockout drum wastewater
in H 2 cryo recovery
441 Sour water from partial
oxidation unit (Texaco
gasifier)
515 Sour water from sulfur
recovery plant
516 Sour water from sulfur
plant tail gas treatment
unit
19
2J
H 2 S, NH 3 ,
phenols, CO 2 .
organic acids,
HC1 1 ketones,
SCN , C1(,
PNAs
60 NIl 3 , CN.
formate
H2S-16,700 mg/I
N 11 3 -13,810 mg/I
Phenols-8,080 mg/I
C0 2 -9,910 mg/I
Organic acids-
220 mg/I
HC1-1,030 mg/I
Ketones and
aldehydes-220 rn/f
PNAs-l.5 mg/I
SCN-lO mg/I
C l i -4 mq/t
N 1 1 3 -7.500 mg/I
CN-540 mg/I
Iormate-l,000 mg/I
1 1 2 S- trace
Nil 3 - trace
H 2 S- trace
Nil 3 - trace
• Coal composition
• Liquefaction reactor
operating condition
• Flexicoker operating
condition
TABLE 2-89.
SUP’IIARY OF SOUR AND PHENOl IC WASTEWATER STRENIS
FROM EDS CO IERCIA1 PLANT (ILLINOIS COAl. MFS CASE)
Stream Stream Description Stream
Pollutants
Concentrations
lactors Affecting
No.
Flow Rate
(ini/hr)
of
Potential
Concern
of Major
Pollutants
Effluent Stream
Characteristics
I.
201 Phenols Phenols-968 mg/I • Coal composition
I; , ,
0
134\
6
18
‘7
42
0.9
2 Il?S 11113
17 II?S , Nil 3
• Gasifier type
• Plant design
• Plant design

-------
TABLE 2-90. :,UMMARY OF NON-SOUR WAST [ WATEI AMS FROM
LOS COMMERCIAL PLANT (ILLINOIS BASE CASE)
Stream Stream Description Stream Pollutants Concentrations Factors Affecting
No. Flo Rate of Potential of Major Effluent Stream
(m /hr) Concern Pollutants Characteristics
504 Stripped wastewater 895 H 2 S, NH 3 , H2S-l mg/V • Sour water strlpplng/
from phenol Ic phenols, other NH 3 -80 mg/V NH 3 recovery process
extraction organics Phenols-SO mg/V selected
Organic acids- . Phenol extraction
1500 mg/V process selected
732 Cooling tower 677 Phosphorus, Phosphate-3.7 mg/V • Quality of cooling
blowdown chromium, Chromlum-O.8 mg/V • Blowdown ratio
zinc, sulfate, Zinc-l,O mg/t • Additives used
chloride, Sulfate-1700 mg/V
aninonia, TDS
722 ClarifIer sludge 2.8 Suspended Wirying • Quality of raw water
from raw water solids, alum, • Amount of lliiiefalum
treatment lime used
723 Regeneration waste 53 IDS, excess Varying • Quality of raw water
from water regenerants S Resin combinations
dernineral Ization employed
901 Low quality rain 711 OIl/spill Varying • Amount of precipita-
runoff products tion
01? Coal pile drainage 29 Sulfates, Fe, Sulfate-2l500 mg/V S Sulfur content of coal
As, Cr, Se Fe-77l0 mg/V • Amount of precipita-
As-O.l5 mg/V tion
Cr-O.4 mg/V
Se-0.4 mg/V
706 Ash pond overflow 43 As, Fe, Mg, Varying • Coal composition
Mn, Ni • Boiler design
• Ash pond design
10?, Boiler hlowdown iO8 Alkalinity, Alkalinity- • Boiler type
70 i [ l i lA 10 mg/p. • Additives used

-------
504 Stripped wastewater
from phenol Ic
extraction
732 Cooling tower
blowdown
564 H 2 S, Nil 3 ,
phenols, other
organ ics
Phosphorus,
chromium,
zinc, sulfate,
chloride,
aiiinonia, lOS
H 2 S-l mg/f
NH 3 -80 mg/t
Phenols-50 mg/t
Organic acids-
1500 mg/I
Phosphate-3.7 mg/f
Chromium-0.8 mg/f
Zinc-i .0 mg/t
Sulfate-1700 mg/t
• Sour water strlpping/
NH 3 recovery process
selected
• Phenol extraction
process selected
• Quality of cooling
• Blowdown ratio
• Additives used
702,
Clarifier sludge
from raw water
treatment
Regeneration waste
from water
demineralization
Slag filtrate from
partial oxidation
unit (Texaco gasifier)
Ash pond overflow
Boiler blowdowri
3.1 Suspended
solids, alum,
lime
51 TDS, excess
regenerants
603 011/spill
products
26 Sulfates, Fe,
As, Cr, Se
12 Form te,
S 2 O 3
10 As, Fe, Mg.
Mn, Ni
77 Alkalinity,
[ 1)1 A
Varying
Varying
Varying
Sulfate-2 1500 mg/f
Fe-77l0 mq/t
As-0.15 mg/f
Cr-0.4 mg/f
Se-0.4 mg/f
Formate-lOO mg/f
S 2 O 3 -75 mg/t
Varying
Alkalinity-
10 IIKj/t
• Quality of raw water
• Amount of lime/alum
used
• Quality of raw water
• Resin combinations
employed
• Amount of precipita-
tion
content of coal
of precipita-
• Gasifler type
• Coal composition
• Boiler design
• Ash pond design
TABLE 2-91. SUMMARY OF NON-SOUR WASTEWATER STREAMS FROM
(OS COMMERCIAL PLANT (ILLINOIS COAL MFS CASE)
Stream Stream Description Stream
Concentrations Factors
—____________
Pollutants
No.
Flow Rate
(m’/hr)
of
Potential
Concern
of Major
Pollutants
Affecting
Effluent Stream
Characteristics
707
722
723
901 Low quality rain
runoff
012 Coal pile drainage
443
706
• Sulfur
• Amount
tion
• Boiler type
• Additives used

-------
stripping and phenol extraction technologies employed. Estimated
characteristics of this stream, as provided by ER&E (69), are given in
Tables 2—90 and 2—91. Five of the wastewater streams (streams 732, 722,
723, 706, combined 702 and 708) are derived from auxiliary operations and
discussed in Section 2.2.6. Two rain runoff streams are considered,
including a low quality rain runoff (stream 901) containing oil and other
spilled products, and a coal pile runoff stream (stream 012) discussed in
Section 2.2.2. The slag filtrate from the partial oxidation unit (stream
443), generated only in the fS case, is discussed in Section 2.2.5.
Solid waste streams from the EDS convnercial plant are sumarized in
Tables 2-92 and 2-93 for the base case and MFS case, respectively. The
largest sources of solid waste are the Flexicoker, the partial oxidation
unit (MFS case only) and the power/steam generation boilers. Solid wastes
from these units will be similar in composition to the feed coal ash, with
a variable degree of dilution due to residual carbon levels. Pollutants of
potential concern are trace elements and organics. Spent catalyst, sulfur
guard, and drying agent generation rates are several orders of magnitude
lower than those for Flexicoking and partial oxidation, although these
materials have potentially higher concentrations of leachable trace
elements. Pollution control wastes (e.g., FGD and wastewater treatment
sludges) are of concern due to potentially leachable trace element
concentrations, organics, and dissolved solids. Detailed solid waste
characterization data are discussed in Sections 2.1.5 and 4.4.
Fugitive dust and particulate emissions from coal storage Piles and
coal Processing are sunm arized in Table 2-94. These emissions are site
specific and vary with the type of coal being processed. Further
information regarding these emissions is provided in Section 2.2.2.
Emissions from steam and power generation, and process furnaces are
sunnarized in Table 2-95 and Table 2-96, respectively. These emissions
vary with the mode of operation. Emissions for the base case are for the
high LBG mode of operation. Steam and power generation emissions for the
MFS case are for the normal production mode. More details regarding these
emissions is provided in Section 2.2.6.2.
2-173

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TABLE 2—92. SUV ARY OF SOLID WASTES FROM EDS CO ERCIAL PLANT
(ILLINOIS NO. 6 COAL BASE CASE)
Stream Stream Description Stream
Pollutints
Concentration
Factors
Affecting
Effluent
*o.
Flow Rate
of
Potential
of Major
Stream
Characteristics
(Mg/yi.)*
Concern
Pollutants
108 Slurry Dryer Solids 1,300 Trace elements, No Data • Coal cor ,osition
organics • Slurry solvent composition
302 Flexicoking gaslfler/ 211,000 Trace elements, • Coal composition
heater dry fines organ ics
303 Flexicoking gasifierf 211,000 Trace elements. • Coal composition
heater wet fines organics O.018 ’ Cr
0.O46 Mn
306 Flexlcoking heater 1,120,000 Trace elements, 0.018 Ni • Coal composition
bad coke organics
313 Flexlcoking chunks/ 32,600 Trace elements, • Coal composition
agglomerates organi cs
Spent Catalyst, Solfur
Guard & Drying Agents:
204 HydrogenatIon (NI—Mo) 380 Trace elements, Mo Data • Catalyst composition
organics • Decoerissioning procedures
404 Myarotreater (Ni- ) 50
405, 453 Drying Agents (Alt ina, 120
zeolites)
433 Sulfur 6uard (mO) 120
Reformer (Ni-U) 140
436 Shift (Iron Oxide) 300
439 Methanetlon (Ni) £0
£54 n1a Synthesis (Fe) 120
517 Claus (Ali,ina) 180
51St Hydrolysis (Co—Mo) 10
Total 1,460
703, 704, Boiler ash 132.000 Trace elements, 0.005 As • Coal composition
709, 710 organics 0.017 ’ Cr
0.045 Mn
0.0l8 Ni
FGD sludge 321,000 Trace •l nts, Variable • Fly ash removal effic,encv
711 organics • Scrubber type
• Solid/1igu O eparat on
efficiency
523 ’, Nastewater treatment 73,000 Trace elements, Variable • Coal composition
S24 sludge 105, or-ganics • Treatment processes
employed
Dat .. are on a dry basis except for wastewiter treatment cludge.
‘Discharge streams from ollut,on control operations are discussed in Chapter 4.
2-174

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Trace elements,
organ i Cs
505.000 Trace elenents.
organics
0.005 As
0.017 Cr
0.045 Mn
O.018 Ni
Variable
Fa tor
Strea
Affecting Effluent
m Characteristics
• Fly ash removal efficiency
• SCrubber type
• Solid’liauid separation
efficiency
Variable • Coal cornpositlo ”
• Treatment processes
emol oyed
Stream Stream Description
Mo.
Comcentration
of Major
Pollutants
Mo Data
TABLE 2—93. SU$T4ARY OF SOLID WASTES FROIl EDS C0 lERCIAL PLANT
(ILLI$.OlS NO. 6 COAL MFS CASE)
Stream Pollutants
Flow Rate pf Potential
(Mg/yr) Concern
1,070 Trace elements.
organi cs
87,400 Trace elements.
organics
87,400 Trace elements.
organics 0.018 Cr
0.046 Mn
494.000 Trace elements, 0.018 Mi
organics
11,700 Trace elements.
organics
395.000 Trace elements
• Coal composition
• Slurry solvent composition
• Coal composition
• Coal composition
• Coal composition
• Coal composition
• Coal composition
• Solid liquid separation
efficiency
10$’ Slurry dryer solids
302 Fle—icoking gasifier.’
heater dry fines
303 F1exicok nq asifier!
heater wet fines
306 Flexicoking heater
bed coke
313 Flexicoking chunks!
agglomerates
442 Partial oxidation 0.005- As
slag 0.0l7. Cr
0.045: Mn
O.018 Ni
Spent Catalyst, Sulfur
Suard & Drying Agents:
204 Hydrogenation (Ni-Mo) 320 Trace elements,
organ ics
404 Hydrotreater (Ni—Mo) 20
435 Drying Agents iZeolite) 40
444 High Temperature Shift 360
(Cr—Fe)
Low Temperature Shift 100
(Cu-Zn)
Claus (Alumina) 150
518” Hydrolys,s (Co—Mo)
Total 1,000
703. 704, Boiler ash 209,000
709, 710
7 05. FGD sludge
711
No Data • Catalyst composition
• Decommissioning procedures
• Coal Composition
523,
524’
Wastes:ater tree tment
sludge
62,000 Trace elements,
105, organics
Data are on a dry basis except for wastewater treatment ludge.
tDischarge streams from pollution control operat ions are . ‘ eJ in Chapter 4.
2—175

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TABLE 2-94. SUMMARY OF UNCONTROLLED FUGITIVE DUST GENERATION FROM COAL STORAGE PILES
AND FUGITIVE PARTICULATE EMISSIONS FROM COAL LOADING, UNLOADING, TRANSFER
AND CRUSHING OPERATIONS
‘I .
Stream
Number
Stream Description
Stream
Flow Rate
(Mg/yr)
Pollutants
of Potential
Concern
Concentrations
of Major
Pollutants
Factors Affecting
Effluent Stream
Characteristics
Ofl
Fugitive Dust Emissions
from Coal Storage Piles
• Wind frosion
30-day storage
383
TSP
No Data
• Loading On
. Loading Off
Base Case
MFS Case
352
TSP
No Data
. Vehicular Activity
5-day storage
Illinois Base Case
230
TSP
No Data
• Turnover Rate of Pile
• Pile Configuration
Market Flexibility
Sensitivity Case
211
TSP
No Data
013
Fugitive Particulate
Emissions from Coal
Loading, Unloading,
Transfer and Crushing
Operations
.
• Moisture Content
I Cru hin9 Screening
Equ.pment
• Feed Rate
Base Case
24,430
TSP
No Data
MFS Case
22,020
TSP
No Data
ICB - Illinois Coal Base Case
MFS - Market Flexibility Sensitivity Case

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1 TABLE 2-95. SUMMARY OF UNCONTROLLED EMISSIONS FROM EDS STEAM AND POWER GENERATION,,
Stream Stream Description Pollutants
Pollutant
Concentrations
of
Factors
Affecting
Number
of
Concern
Flow Rate
(kg/hr)
Major
Pollutants
(ng/J)
Effluent Stream
CharacterIstics
701 Flue Gas from Steam • Fuel Composition
Generation • Excess Air
Base Case SO 2 4,486 169
NO 726 238
COX 15 4.9
TSP 4,700 1539
HC 10 3.3
MFS Case SO 2 9,032 2179
NO 1 ,031 249
COX 65 15.7
TSP 9,437 2277
-J HC 20 4.8
705 Flue Gas from Power • Fuel Composition
Generation • Excess Air
Base Case SO, 8,610 2835
NO’ 785 258
COX 62 20
TSP 8,985 2958
HC 19 6.3
MFS Case SO 11,608 2826
NO 2 1 ,602 259
COX 84 20
TSP 12,151 2958
lIC 25 6.1

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TABLE 2-96. SUMMARY OF UNCONTROLLED EMISSIONS FROM THE LOS PROCESS FURNACES
Stream
S
Stream Description
Pollutants
Pollutant
Concentrations
.,‘
Factors Affecting
Number
of
Concern
Flow Rate
(kg/hr)
of Major
Pollutants
(ng/J)
Effluent Stream
Characteristics
107,203,
LIquefaction slurry
. Fuel Composition
434
preheat furnace flue
gas, hydrogenation
. Excess Al
r
fuel preheat furnaces
flue gas, steam reform-
er flue gas.
Base Case
SO.,
NO’
COX
TSP
lIC
383
6399
473
417
84
47.4
793
58.6
51.7
10.3
MFS Case (excludes
steam reformer)
so
NO 2
COX
TSP
HC
136
2277
168
148
30
47.4
793
58.6
51.7
10.3
ICB - Illinois Coal Base
MFS Market Flexibility Sensitivity

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Two major vent gas streams are generated from the EDS commerical
plant. These are the slurry dryer vent gas (stream 102) and vacuum flash
offgas (stream 153). The characteristics of these streams are samrnarized
in Table 2—97. Additional information regarding these streams is provided
— in Sections 2.2.3 and 2.2.4.
Table 2-98 sumarizes fugitive and evaporative hydrocarbon emissions
from the EDS direct coal liquefaction plant. Fugitive emission estimates
are based on emission factors developed from testing performed at petroleum
refineries. Evaporative emissions from fixed and floating roof tanks were
estimated using equations developed by the M ericar, Petroleum Institute
(API). Further discussion regarding evaporative and fugitive emissions is
provided in Sections 2.2.6.5 and 2.2.7.1, respectively.
Transient and regeneration/decormiissioning waste gases are sumarized
in Tables 2-99 and 2-100 for the EDS base case and MFS case, respectively.
Characterization data for these streams are discussed in Sections 2.2.5,
2.2.7 and 4.2.
2-179

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TABLE 2-97 SUMMARY OF MAJOR VENT GAS STREAMS FROM
EDS COMMERCIAL PLANT
Stream Stream Description Stream
No. Flow Rate
(kmol/hr)
Pollutants
of Potential
Concern
Concentrations
of Major
Pollutants
Factors
Effluent
Characte
Affecting
Stream
ristics
102
Slurry dryer
820
(Base
Case)
Hydrocarbons
HC-4.l%
•
Coal Compositior
Vent Gas
696
(MFS
Case)
(HC), H 2 S
H 2 S-30 ppm
•
Slurry Dryer
Design
153*
Vacuum Flash
107
(Base
Case)
HC, H 2 S
HC-47.5%
•
Coal Composition
Off Gas
90
(MFS Case)
H 2 S-5.O%
.
Plant Design
* Includes stream 156 (partIal oxidation feed vacuum flash off gas) In the MFS Case.

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•TABLE 2-98. SUMMARY OF FUGITIVE AND EVAPORATIVE HYDROCARBON EMISSIONS FROM THE EDS
DIRECT COAL LIQUEFACTION PLANT
Stream Stream Description Stream
Number Flow Rate
kg/yr
Pollutants of
Potential
Concern
Concentration of
Major Pollutants
Factors
Effluent
Characte
Affecting
Stream
ristics
Fugitive Hydrocarbon NA HC No Data • Number of valves,
Emissions flanges, pumps,
compressors, etc.
• Type of product In
unit streams
751 Evaporative Hydro- • Type of storage tank
carbon Emissions • Type of liquid stored
r Base Case 39,935 HC No Data • Storage temperature
MFS Case 36,287 tIC No Data
NA - Component counts for the plant are not available at the present time.

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$ i.
TABLE 2-99. SUMMARY OF TRANSIENT AND REGENERATION/DECOMMISSIONING WASTE GASES
FROM EDS COMMERCIAL PLANT (ILLINOIS COAL BASE CASE)
Stream
No.
Stream Description
Stream
Flow Rate
(kmol/hr)
Pollutants
of Potential
Concern
Concentrations
of Major
Pollutants
Factors Affecting
Effluent Stream
Characteristics
803
TransIent waste gas from
liquefaction
20,400
H 2 S, NH 3 ,
CO, RHC
H 2 S-2.6%
NH 3 -49 ppmv
CO-O5%
RHC-3.5%
•
.
Startup/shutdown
procedures
Type of upset
requiring venting
801
Transient waste gas from
Flexicoking
1,000
H 2 S, NH 3 ,
CO, RHC
H2S-l.4%
NH 3 -l.4%
CO-4.O%
RHC-2.9%
•
•
Startup/shutdown
procedures
Scrubber bottoms
recycle rate
446
RegeneratIon/decommissioning
offgas from reformer
catalyst
10,640
CO,
particulate,
NI (CO) 4
C0-0.5%
Part.-l g/Nm 3
•
•
Catalyst composition
Decommissioning
procedures
447
RegeneratIon/decommissioning
offgas from shift catalyst
14,000
Particulate
Part.-1 g/Hm 3
•
•
Catalyst composition
Decomissioning
procedures
448
Regeneration/decommIssioning
offgas from methanatlon
2,600
Particulate,
NI (CO) 4
Part. -1 g/Nm 3
•
•
Catalyst composition
Decommissioning
procedures

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TABLE 2-100. SUMMARY OF TRANSIENT AND REGENERATION/DECOIIIISSIONING WASTE GASES
FROM EDS COMMERCIAL PLANT (ILLINOIS COAL MIS CASE)
Stream
Stream Description
Stream
Pollutants
Concentrations
Factors Affecting
No.
Flow Rate
(kmo l/hr)
of
Potential
Concern
of Major
Pollutants
Effluent Stream
Characteristics
• 803 Transient waste gas from 17,100 H 2 S, NH 3 , H 2 S-2,6% • Startup/shutdown
liquefaction CO RFIC NH3-49 ppmv procedures
CO-O.5% • Type of upset
RHC-3.5% requiring venting
801 Transient waste gas from 670 H2S, 11113, 1125-1.4% • Startup/shutdown
Flexicoking CO RIIC NH 3 -1.4% procedures
CO-4.0% • Scrubber bottoms
RHC-2.9% recycle rate
802 Transient waste gas from 16,100 H 2 S, NH 3 , H 2 S-O.3% • Startup/shutdown
partial oxidation COS, CO , NH 3 -170 ppmv procedures
11CM COS-253 ppmv • Startup fuel
CO-17.7%
HCN-8 ppmv
449, Regeneration/decowunissioning 29,100 S02, S0 2 —l.l% • Catalyst composition
450 offgas from shift catalyst particulate Part.-1 g/Nm 3 • Regeneration/decom-
missioning procedures

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REFERENCES TO EDS PROCESS
3. Draft Environmental Impact Statement. Solvent Refined Coal-Il
Demonstration Projec Project, Fort Martin, West Virginia.
Revised DOE Approval Draft. May 19,1980.
8. Robin, A.M. Gasification of Residual Materials from Coal
Liquefaction. Type III Extended Pilot Plant Evaluation of SRC—lI
Vacuum Flash Drum Bottoms from Kentucky No. 9/14 Coal. Report
prepared by Texaco, Inc., for the U.S. Department of Energy.
FE-2247—20. February 1979.
24. SRC-II Demonstration Project Phase Zero. Task Number 3.
Deliverable Number 8. Vol. 2 of 5. Conceptual Comercial Plant
Plant Description. Report prepared by the Pittsburg and Midway
Coal Co. for the U.S. Department of Energy. July 31, 1979.
25. Magee, E.M., H.L. Hall, and G.M. Varga, Jr. Potential Pollutants
In Fossil Fuels. EPA—R2—73—249. June 1973.
26. Schlinger, W.G. and G.N. Richter. Process Pollutes Very Little.
Hydrocarbon Processing , 59 (10): 66—70. October 1980.
27. Data from the State of North Dakota permit files submitted by
American Natural Resources for the ANG Synthetic Natural Gas
Facility.
32. Clark, J.W. W. Viesman, and M.J. Harmier. Water Supply and
Pollution Control. Harper and Row, 1977.
33. Jutze, G.A., et al. Technical Guidance for Control of
Industrial Process Fugitive Emissions. Report prepared by PEDCo
Environmental for the U.S. Environmental Protection Agency.
March 1977.
35. Blackwood, T.R., and R.A. Wachter. Source Assessment: Coal
Storage Piles. Report prepared by Monsanto Research Corp. for
the U.S. Environmental Protection Agency. May 1978.
31. Cox, D.B., T.Y.J. Chu, and R.J. Ruane.
Pile Drainage. Report prepared by TVA
Protection Agency. EPA-600/7—79-051.
Characterization of Coal
for the U.S. Environmental
February 1979.
34. Assessment
Industrial
the U.S.
September
of Fugitive Particulate Emission Factors for
Processes. Report prepared by PEDCo Environmental for
Envi ronmental Protection Agency. EPA—450/3—78-107.
1978.
37. Wetherold, R. and L. Provost. Emission Factors and Frequency of
Leak Occurrence for Fittings in Refinery Process Units. Report
prepared by Radian Corp. for the U.S. Environmental Protection
Agency. EPA—600/2—79—044. February 1979.
2—184

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38. The Assessment of EnvironmentalEmissions from Refineries,
Appendix F. Draft report prepared by Radian Corp. for the U.S.
Environmental Protection Agency. August 1979.
61. Fant, B.T. Exxon Donor Solvent Coal Liquefaction Commercial
Plant Design. Report prepared by Exxon Research and Engineering
Co., for the U.S. Department of Energy. FE-2353-13. January
1978.
62. Epperly, W.R. EDS C v ercial Plant
Onsite Design Basis — Illinois Coal
Exxon Research and Engineering Co.,
Energy. FE -2893—32. August 1979.
Study Design Update, Revised
Base Case. Report prepared by
for the U.S. Department of
63. Epperly, W.R. EDS Coimnercial Plant Study Design Update, Revised
Offsfte Design Basis - Illinois Coal Base Case. Report prepared
by Exxon Research and Engineering Co., for the U.S. Department of
Energy. FE—2893. 33. September 1979.
68. Bayer, G.T., C.W. DeGeorge, and D.H. Wasserstrom. Water
Pollution Control in the Exxon Donor Solvent Coal Liquefaction
Process. Paper presented at the 87th National AIChE Meeting,
Boston, Mass. August 1979.
74. Epperly, W.R., K.W. Plumlee, D.T. Wade. Exxon Donor Solvent Coal
Liquefaction Process: Development Program Status. Paper
presented at the American Mining Congress, International Coal
Show, Chicago, Illinois. May 5—8, 1980.
75. Epperly, W.R., J.W. Taunton. Progress in
Donor Solvent Coal Liquefaction Process.
72nd AIChE Annual Meeting, San Francisco,
25—29, 1979.
81. EDS Commercial Study Design Wastewater and Solids Disposal
Program. Exxon Research and Engineering CO. August 5, 198C.
82. Gluskoter, H.J., R. . RucPt, W.G. Miller, R.A. Cahill, G.B.
Drehen, and J.K. Kuhn. Trace Elements in Coal Occurrence and
Distribution. Report prepared by the Illinois Geological Survey,
Urbana, Illinois. EPA—600/7—77—0 64 . 1977.
64. Epperly, W.R.
Design Basis —
Report prepared
U.S. Department
65. Epperly, W.R.
Design Basis -
Report prepared
U.S. Department
EDS Commercial Plant Study Design Update, Onsite
Illinois Coal Market Flexibility Sensitivity Case.
by Exxon Research and Engineering Go., for the
of Energy. FE-2893—36. July 1979.
EDS Commercial Plant Study Design Update, Offsite
Illinois Coal Market Flexibility Sensitivity Case.
by Exxon Research and Engineering Co., for the
of Energy. FE-2893—37. July 1979.
Development of Exxon
Paper presented at the
California. November
2—185

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83. DeGeorge, C.W. and I4.R. Wise. EDS Information Response to EPA
Requests of September 9 and September 25, 1980, for Assistance in
Preparation of Direct Liquefaction Pollution Control Guidance
Document. November 18, 1980.
84. Ghassemi, N., K. Crawford and S. Quinlivan. Environmental
Assessment Data Base for High-Btu Gasification Technology:
Volume 2 Technical Discussion, Report prepared by TRW Inc. for
the U.S. Environmental Protection Agency. EPA-600/7-78—186b.
September 1978.
151. Coal Gasification Project, Draft Environmental Impact Statement.
Prepared by Tennessee Valley Authority.
153. Scharle, W.J. Large Oxygen Plant Economics and Reliability. TVA
Symposium on Amonia from Coal. Mussel Shoals, Alabama. May
8—10, 1979.
2-186

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