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 ------- CONTENTS Page 1—1 1—1 1 —1 1—2 1—3 1—3 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 ------- 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 ------- 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 1—1 ------- 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 1-2 ------- 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 1—3 ------- 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. 1-4 ------- 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 1-5 ------- • 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. 1—7 ------- 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 ). - 1-8 ------- 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: 1-9 ------- • 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 1-10 ------- • 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. 1—li ------- 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. ------- 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. ------- 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. ------- 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. ------- 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$. ------- 2. SOURCES OF 3LLUTANTS OF CONCERN rn tids chapter, the proc . xiliary operations associated with direct coal liquefaction and the cn n ::eristics of uncontrolled waste streams resultfrsg froii these operations are described. The material presented is used as input in evaluating environmental control options. For discussion purposes, the process operations covered are divided into: coal preparation, coal liquefaction, product separation/purification! upgrading, and processing of liquefaction residue/hydrogen production plant. Auxiliary operations covered are divided into: raw water treat-P ment, steam and power generation, cooling system, oxygen production, and product/byproduct storage. Fugitive and transient emissions are covered in an individual subsection. 2.2 EDS PROCESS 2.2.1 Overall Description of the EDS Process The Exxon Donor Solvent (EDS) is a non—catalytic process that liquefies coal by the use of a hydrogen donor solvent obtained from coal- derived distillate. The donor solvent transfers hydrogen to the coal, thus promoting the liquefaction of coal. The base case configuration for the EDS process, designed to maximize the production of C 4 + liquids, is sho m schematically in Figure 2-7. The major processing areas consist of coal crushing, coal liquefaction, solvent hydrogenation, solvent recovery, Flexicoking to process liquefaction residue, cryogenic hydrogen recovery, hydrogen generation by steam reforming, amonia synthesis, and light ends processing. Auxiliary operations shown include raw water treatment, steam generation, power generation, cooling system, oxygen production, and product/byproduct storage. Pollution control operations such as sulfur recovery, amonia recovery, phenol extraction, and wastewater treatment are also included in the block flow diagram to indicate the flows of waste streams into various treatment areas. 2-92 ------- 0 1111 I WIll) NVUSI$IIII*,IS I •lflw CAI11 II CAlalyll 514 1 1*111 10 WIll WIN) 11J4 000 0 1 100 1 . 11*110 CAISI 1107 —S 5 11 . 04 -4 lullING I I WIl.R* F j J r.. 00001 .0 100 WU I N 0 0 0 I lIS I GU O l I j P 1 4 I i 0014* 0.0000 V I I I GM Il l 0*000 0*000 0 1 1 . 0 W ) . , I ll S. 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L 13 * I *00.0 SOIlS V III Sal SOIlS *40 100 - . r ,eI .4hI% 0 5*00 0 0GM 00 0 111000 11 —IIIIIIIIIi11:I.,IIWI. ________________ ___________ p.015*.,.. • 1 .1100 00 151010101 MUW •1 J00I NA Il .. 0*100 ‘p 5 5 4 7 G M 1101 10 51101000700 0 *0 0 1 1 AP I OW I S SAIlS 00100 (00 III Ill 00*0 ISI0 III 44 0 0*0 1 1 0W 4. *01 101 : . . 0*0 1111.0 5 IOn ... I ,- Figure 2-7. Block Flow Diagram for EDS Commercial Plant Base Case ------- 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 ------- ii; .:: IS I acS’sa IILS’SNUIØ 2 - -_ Tii _u ____ -MS A I S IS !US V asvI asllssnAft — —I_a ( ‘ A S) C aSAOIlM AA S AD I I ‘A.’ MS I S’ a. PIN, SMAINMAIN P 1 1 1 1 0Nt N l A MIS ______________________________ MIS P U M I St M MI II LAS I UMa. ‘.4 —IS’— .* lIlieS IS PI at.. ,’. v i .. p Io.ap .cos. ,Iulo .ul.s 00, QICISLII f .,A 0 1 16* 1 5 * 5 O ,lA , ,ajll I, , 4 ( ) ( _________ W 1D S . I S I I I _________ IIH — H__H H •,,ISIa I. 1 1* 1, WI ..lt. I.II 1 1 1 ( 0* 1 1 “— —‘a PA I I I AP I S Al A MI’. afl I . 5 ’ , ’ ___ 0 ’ .I I MION SI I I N ‘All. • I 4II.,Ila Cl i , , S AN AIIAPAIIIIA All IN N I I I I II I l l 111 5AM ISANAS SMAll n. a. .isi.a is ‘A..’ ic 3 I MI Ml ISA MI ti ,l ___________ 1 1V 1 1 1*A ’ . I ‘ I ’ MMMII lIISMI A N COCO I I l*SAI ONS API* 0 10 510* ir lI 1 ’ ; I ee 11 1 1 1 00(51 01I 01 1 . 4M ‘. 4l.I NU A. 1 1*00 1 1CM SIOMSIS, _______ 1 500 15 1 j41 ______ = ‘_}e r 9 9 1 -t J “ I I , Mw _I NNV(N MIMI AU I l l S Ill 1 1 14 15 14 0.1 1 ,10 . lAP AlA 551 PASO 5141*1 Figure 2-8. Block Flow Diagram for EDS Commercial Plant - MES Case ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- • 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- • 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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. ------- •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. ------- $ 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- |