Volume II Hittman Associates. Council on Environmental Quality (U.S.) National Science Foundation (U.S.).Research Applied to National Needs Program. United States.Environmental Protection Agency. United States.National Technical Information Service. Columbia, Md.:Hittman Associates;Springfield, Va., :Reproduced by National Technical Information Service,1974-1975. Power resources Environmental aspects United States. Power resources Costs. 3 If coastal zone Information Coaster Zone Information Center U.S. DEPARTMENT OF COMMERCE Center National Technical Information Service JAN 25 1977 PB-239 159 ENVIRONMENTAL IMPACTS EFFICIENCY AND COST OF ENERGY SUPPLY AND END USE. VOLUME II HITTMAN ASSOCIATES, INCORPORATED PREPARED FOR NATIONAL SCIENCE FOUNDATION ENVIRONMENTAL PROTECTION AGENCY COUNCIL ON ENVIRONMENTAL QUALITY JANUARY 197 5 HD 9502 U52 E-58 1975 v.2 BIBLIOGRAPHIC, DATA I.- Report No. 3. Recipient's Accession NO. SHEET EQC308v2 PB- 39-159 4. Title and Subtitle 5. Report Date Environmental Impacts, Efficeincy, and Cost of. January 1975 Energy Supply and End Use Volume 11 6. 7. Author(s) 8. Performing Organization Rept. No- HIT-593 9. Performing Organization Name and Address 10. Project/Task/Work Unit No. Hittman Associates, Inc. Columbia, Md. 11. Contract/Grant No. EQC 308 12. Sponsoring Organization Name and Address 13. Type of Report Period Council on Environmenal Quality, 722 Jackson Pl. Covered N. W., D. C. 20006; National Science Foundation, 1800Final G St. N. W. D. .20550;Envqironmental Protection 14. Agency, 401 M St. S. W. D.. C . 20460 lip 15. Supplentary Notes Volume I: PB-238 784 16. Abstracts The purpose of this was study was to determine the environmental im- pacts, efficiency-,. and costs ts associated with supply and end use offossil fuels. The output is.this 2-volume report which presents tabular, foot-- noted, and referenced dsta quantifying the energy.-related environmental impacts on land, water air, solid waste, and occupational health. All theinformation is also available in the form of a computerized data base Matrix of Environmental Residuals for Energy d Systems. Brookhaven create the.data base and has written a number of data management andenergy modeling programs, which with MERES are known as the Energy Model and Data Base. Vol.II characterizes six technologies with respect to their environmental impacts, efficiency and cost: both low- and high-BTU gas- fication of coal, Oil'shaleP fluidized bed boiler combustion, solvent refined coal, and coal liquefaction. 17. Key Words and Document Analysis. 7a. Descriptors Energy Energy Systems. Energy model.. MERES. Data base, Environmental:l impacts. Air and water pollution. Solid waste. Land disruption. occupa- tional health. Fossil fuels. Coal. Oil. Natural gas. Fuel supplies. End use. Efficiency. Costs.,Coal gasification. Oil shale. Fluidized be boiler combustion, solvent-refined coal. Coal liquefaction. 17b. Identifiers/Open-Ended Terms, Reproduced by NATIONAL TECHNICAL INFORMATION SERVICE 17c. COSATI Fieqld/group US Department of Commerce Springfield, VA. 22151 Prices subject to change, 18. Availability Statement 19.. Security Class (This 21. No. of Pages Report) CLASSIFIED NTIS 20. Security Class (This 22. Price Pa UNCLASSIFIED $9.00 FORM maybe (REV. 10-73) ENDORSED BY ANSI AND UNESCO. THIS Form MAY BE REPRODUCED USCOMM-qDC q82q6q5-P7q4 ENVIRONMENTAL IMPACTS, EFFICIENCY AND COST OF ENERGY SUPPLY AND END USE VOLUME, II FINAL REPQRT HIT-593 January 1975 Work Sponsored by The Council on Environmental Quality, RANN Program,of The National Science Foundation, and The Environmental Protection Agency Contract EQC 308 U S DEPARTMENT OF COMMERCE'NOAA 2234 COASTAL SERVICES CENTER OUTH HOBSON AVENUE 0qN LA- HITTMAN ASSOCIATES, INC. COLUMBIA, MARYLAND Property Of CSC library LEGAL NOTICE "This report was prepared as'an account of work sponsored by the United States Government. Neither the United States nor the Council on Einvironmental Quality, nor any of their employees, nor any of their contrators, subcontractors, or their.employees makes any warranty, expressed or implied, or assumes any legal liability or resonbility for the accuracy, completeness or usefulness of any information,apparatus.product or process disclosed, or represents-that its use-wouldnot infringe pri- vately-owned-rights." FOREWORD The efforts represented by t.his two, volume final report w e begun in December 1972. -A draft version of Volume I was er issued September 1973 and the various section 's ofVolume II published in draft form between February and June,1974. Ex- tensive revisions to the draft versions of this work have resulted in a two volume final report. Impetus for the program was recognition -of a need for an' organized approach to the envircnmental impacts caused by energy supply and use. -This study, building upon;earlier work completed by the Council on Environmental Quality, provides a environmental tradeoffs systematic technique.for identifying and problems associated with current energy scenarios. By. offering an organized and consistent approach.*to environmental impacts, this.report can lend a quantitative sophisti,cation to policy discussion. This study was directed by W. Robert Men6hen. Technical contributors are as follows: David F. Becker Charles B. Colton Dr. Henry M.Curran Barry K. Hinkle Jay J. Hoenig William C. Koffke Judith H. Marcus W. Robert Menchen Terry N. Oda James E. Reed Steven A. Rothenberg Robert@E.,Small6y This work has been sponsored by the'Council on Environmental Quality, The Environmental Protection Agency, and theRANN Pro- gram of the-National Science Foundation. The Atomic Energy Commission has contributed.through support of the energy modeling efforts at Brookhaven National,Laboratory (BNL).. The data contained in this volume are being placed,ih a computerized information retrieval system at BNL, and computer programs'are being written which will allow rapid Analysis of the environ- mental effects:of energy systems. Contract monitoring and all technical coordination has been through the Council on Environmental Quality. We wish to"thank Dr. Steve Rattien, Dr. Stephen Gagel and Mr. Marvin, Singer of that office for their.continued assistance and support inthis effort. Their suggestions over the course of the program have created a more useful product. TABLE OF CONTENTS-VOLUME II Page LEGAL NOTICE FOREWARD TABLE OF CONTENTS-VOLUME II iv TABLE OF CONTENTS-VOLUME-I vi LIST OF FIGURES Vill LIST OF TABLES x I.. INTRODUCTION ANDSUMMARY II. DATA BASE DESCRIPTION A. Nomenclature B. Format 11-3 Energy Supply II-1 D. Energy Model and Data Base (EMDB) II-17 III. LOW BTU GASIFICATION OF COAL A. Introduction B. Impact Data Tables and Footnotes III-9 IV. HIGH BTU GASIFICATION OF COAL IV-1 A. Introduction IV-1 B. impact Data Table and Footnotes IV-11 V. OIL SHALE A. Introduction V-1 B. Impact Data Table and Footnotes v-6 iv VI. FLUIDIZED BED BOILER COMBUSTION VI-1 A. Introduction V-I B. Impact Data Table and Footnotes VI-5 VII. SOLVENT REFINED COAL' VII-1 A. Introduction VII-1 B. Impact Data Table and Footnotes VII-4 VIII.COAL LIQUEFACTION VIII-1 A. Introduction VIII-1 B. Impact Data: Table and Footnotes VIII-5 IX. REFERENCES APPENDIX LIST OF ABBREVIATIONS v TABLE OF CONTENTS-VOLUME I Page LEGAL NOTICE FOREWORD TABLE OF CONTENTS-VOLUME I. iv TABLE OF CONTENTS-VOLUME II vi LIST OF FIGURES viii .LIST OF TABLES ix ,I. INTRODUCTION AND SUMMARY II. DATA BASE DESCRIPTION A. Nomenclature B. Format 11-3 C. Energy Supply II-8 D. Energy End Use II-17 E. Energy Model Data Base* (EMDB) III. COAL SUPPLY II-18 A. Introduction B. Impact Data Tables and Footnotes III-4A IV.. OIL SUPPLY IV-1 A. Introduction IV-1 B. Impact Data Tables and Footnotes IV-4 V. NATURAL GAS SUPPLY V-1 A. Introduction V-1 B. Impact Data Table and Footnotes V-3 vi VI. POWER PLANT CONVERSION ACTIVITY OF FUEL SUPPLY VI-1 A. Introduction VI-1 B. Impact Data Table and Footnotes VI-2 VII. RESIDENTIAL END USE VII-1 A. Introduction VII-1 B. Impact Data Table and Footnotes VII-2 VII.COMMERCIAL END USE VIII-1 A. Introduction VIII-1 B.' Impact Data Table and Footnotes VIII-2 IX. INDUSTRIAL END USE IX-1 A . Introduction IX-1 B. Impact Data Tables and Footnotes IX-4 X. TRANSPORTATION END USE X-1 A. Introduction X-1 B. Impact Data Table Footnotes X-3 XI. REFERENCES XI-1 APPENDIX A LIST OF ABBREVIATIONS vii LIST OF FIGURES .-Page Description of Phaase I Program I-3 2 Task 3 Regional Studies I-4 3 Phase II Study-Description Hardness Number Definitions II-5 5 Numbering Classification for-Footnotes and References II-6 6. Uncontrolled Incremental Land impact II-12 7 -Controled Incremental .'.Land Impact- II-12 8_ Data Access Code for.-Supply II-18 9 Applied Technology.Corporation Two-Stage _gy for L f icq&'t-ion 111-3 Combustqn.,Prqacess@ owl Btu Qoal Gas0qi 10 Bureau,of ric Gas -Producer for mine0qw'-, qphe Low Btu Coal'Gasificqation 111-4 11 Bureau of Mines' qTr0qessqurized:Gas Producer for Low Btu Coal Gasification 12 Lurgi Process of., Low 'Btu`Co. :Gasqifqat0qion 111-7 13 Koppers-Totzek Process-of Low Btu Coal Gasification,III-8 l4 Lurgi Process of High-Btu Coal Gasification IV-3 Hygas-ElectrothermalqPocess of High: Btu. 'Coal Gasification IV-4 Hygas-Steam OxygenProcess of"High Btu Coal Gasification IV-6 17 Bigas Process of HighLBtu Coal Gasification IV_7 18. Synthane Process of High Btu Coal Gasification IV-8 19 C02 Acceptor Process of High Btu,Coal Gasification IV-10 viii 20 Typical Oil Shale Process Flow.Diagram V-2 21 Pressurized Fluidized Bed Boiler Power Plant VI-3 22 Atmospheric Pressure Fluidized Bed Boiler Power Plant VI-4 23 Solvent Refined Coal Process VII-2 24 CSF Coal Liquefaction Process VIII-3 25 Modified SRC Liquefaction Process VIII-4 ix LIST OF TABLES Page 1. Environmental Impacts,, Efficiency and Cost for Environmentally Controlled,National and Regional Low Btu Coal Gasification 2 Environmental Iqmpact's, Efficiency and Cost for Environmentally- Controlled National and' Regional High Btu 'Coal Gasification 3 Environmental Impacts., Effic for Environmentally Controlled Oil Shale,Supply v-7 4, Environmental impacts, Efficiency and Cost for, Environmentally.-Controlled National and Regional Fluidized BedBoiler Combustion.Power Plants VI-7 5 Environmental Impacts, Efficienc y and Cost for Environmentally,Controlled Nationaland Regional Solvent refined Coal Supply VII-5 6 Environmental.Impacts, Efficiency-and Cost for Environmqentally..Controlled National and Regional ''..Coal Liquefaction VIII-7 x I. INTRODUCTION AND.SUMMARY This is Volume'll of a two volume report which describes the results of a study performed by Hittman Associates,-Inc. (HAI), and sponsored by the.Council on Environmental Quality (CEQ), The, Environmental Protection Agency, and The.RANN-Program of-Lhe National Science Foundation. The.-purpose of thd-study was to determine the environmentallimpacts, efficiencyl,and costs associated with the supply and etd use of fossil.,fuels. The study builds upon preliminary work already completed by CEQ- The-outptt of the study takes,two forms. This report pre- sen'ts tabular, footnoted, and-referenced data quantifying the broad range of.energy-related environmental impacts on land, water, air, solid waste,. and occupational health.. All of the information contained in this report is.also available in the form of a computerized data base. This,data base-ha@,been,given the name MERES:,.Matrix of Environmental.Residuals for Energy Systems. As part of an ongoing contract with*the Atomic,Energy Commission, Brookhaven National Laboratoky-has created the data base, and also has written a number of data management and energy modeling programs. These programs, together with the MERES. data, arelknown' as*the Energy, Model and Data Base.,(EMDB).. Environmental analyses of energy-related-facilities have pre- viously been incomplete.- Among, other things, these analyses typi-. cally considered only individual components, such as an isolated power plant, refinery, etc., a@nd not entire energy'systems. The construction of a coal7fired power plant-'causes air,. water, solid waste, and land impacts not only at the,immediate s ite of the power plant, but also,at the site where the coal is mined, washed, processed or prepared, and along the route that the coal is transported. The entire' sequence of activities, from the mining of the,coal-@o the production of electricity, and its end 'use in some home appliance or industrial process, is what is referred to as anehergy system or "traje.ctory" and should be analyzed. Similar trajectories or energy supply "chains," exist for oil production andrefining. The construction,of a refinery causes air and water pollutants, solid waste,, and land disruption. However, additional environmental-effects are felt at the point of crude oil production, during the crude and product trans . por- tation, and at the point of marketing and end use. Using the data bank, it is possible to aggregate the environ- mental impacts of a wide variety of fossil fuel "trajectories" ' traced fr=the end use of a fuel to its extraction or vice versa. This makes it Possible to'estimate environmental impacts fok,any number of scenarios related to energy consumption patterns eh- visioned for'the next 10 to 20 years. The objectives of the Phase I study reported in the companion Volume I areisummarized in Figure l.- Tasks 1 and.2 are national in nature while!Task 3 includes ',the-impacts of regional energy supply subsystems. In all cases, the data have been developed for coal, oil, and natural gas. A more.detailed breakdown of the regions covered in Task'3 is provided by Figure'2.. Thirty environmental impact tables are contained inVolume I. Twelve of these are devotedto coal supply, twelve to oil supply, one to natural)gas--suPply, four to-energy end uses, and one to the electric power plant activity of energy supply. Each entky-in these tables@'@is footnoted and referenced. The objective of-'@the Phase II study reported in this volume was to supplement the Pha:se I activiiies with various emerging .,energy technologies. Six technologies, sho'wn.in Figure-3, were characterized with respect to their environmental impacts,. efficiency, and cost. These technologies represent addition al links in the,'supply and,end use chain of fossil fuels and are a necessary pomponent.@@of future energy-:investigations.. These-six emergihg'@technologies are in a state of rapid de- velopment. Characteristics of and emissions from these processes can be expected to.chang@e_as'@-more is learned from-research and ex- perimentatioh. Therefore, it is important to note the time frame of the data used in the tables and-footnotes of this volume. Tasks 5, 6, and 7 (low Btu and high Btu gasification and oil sha'le) are based onidata assembled in the-Fall of 1973. Fluidized bed boiler combustion data (Task 8) was assembled in the early months of 1974. Data used in Tasks.9 and 10 (solvent refined-coal and. coal liquefaction) was dollected in the Spring of 1974. More recent inforination may have been deVeloped since this base data was Assembled. It must@be noted that the environmental impacts reported herein only characterize the initial step in the environmental thain-that is, the amount of effluent discharged from the boundary surrounding a particular process or end use. The inter- action of-the outfall, air emission, land use, etc. with the biosphere is@not included in this study. 1-2 TASK 1 EXTRACTION, PROCESSING, CONVERSION,, AND DELIVERY OF'FOSSIL FUEL ENERGY OBJECTIVE 1 DETERMINE PROCESS EFFICIENCIES FOR FOSSIL FUEL PRODUCTION AND DELIVERY OBJECTIVE 2 QUANTIFY.ENVIRONMENTAL IMPACTS FOR EACH PRO-' CESS, WITH PRESENT CONTROLS OBJECTIVE 3-.DETERMINE IMPACTS WITH CONTROL TECHNOLOGY AVAILABLE AND.LIKELY TO,BE IMPLEMENTED OBjECTIVE 4 DETERMINE -SYSTEM COSTS FOR UNCONTROLLED AND CONTROLLED ENERGY SUPPLY TASK 2 END USES OF ENERGY OBJECTIVE 1 DETERMINE ENERGY.USE PER APPROPRIATE MEASURE OF USEFUL ACTIVITY OBJECTIVE 2 DETERMINE ENVIRONMENTAL IMPACTS OF END USES TASK 3 SENSITIVITY ANALYSIS OF TASK 1 DATA REGIONAL STUDIES (BOTH UNCONTROLLED AND CONTROLLED) Figure 1. Description of Phase I Stud y 1-3 COAL' o NORTHWEST (POWDERRI VER BASIN) MONTANA & WYOMING; AREA STRIP o SOUTHWEST (FOUR CORNERS AREA-) -NEW MEXICO; AREA STRIP o CENTRAL ILLINOIS &.,INDIANA,; AREA STRIP; ROOM & PILLAR@DEEP. 0 NORTHERN APPALACHIA' NORTHERN W,i.VA., CENTRAL & W. PA.;,CONTOUR STRIP, ROOM@& PILLAR DEEP, tONGWALL DEEP o CENTRAL APPALACHIA EASTERN KY., TENN., SOUTHERN W. VA.; STEEP SLOPE CONTOUR-STRIP, ROOM & PILLAR- DEEP OIL 0 DOMESTIC ON-SHORE o IMPORTED SOUTH'AMERICAN--RES-IDUAL o IMPORTED MIDDLE.EASTERN'CRUDE o IMPORTED CANADIAN 'CRUDE. o DOMESTIC OFF-SHORE NATURAL'GAS o DOMESTIC-ON-SHORE o DOMESTIC OFF7SHORE.-, o IMPORTED CANADIAN@ Figure,2. Task 3.Regional Studies: TASK 5 LOW BTU GASIFICATION OF COAL TASK 6. HIGH.BTU GASIFICATION OF COAL TASK-7 OIL SHALE TASK 8 FLUIDIZED BED BOILER'COMBUSTION @TASK9 SOLVENT REFINED COAL TASK 10 'COAL LIQUEFACTION Figure 3., Phase II Study Descripti on 1-5 Ii. DATA BASE DESCRIPTION A. Nomenclature In.order to describe a scenario dealing with.environmental effects of energy, a number of definitions have been adopted:.*., Term Exam2le/Definition Element 802 emission in transpor- tation of coal.by unit train Process. Coal transportation by unit. train (a set of elements) Activity coal transportation (com bination of a set of pro- cesses) Trajectory Coal in the:ground to steel -ion by electric fur- 'product nace (the set of linked activities which connect the supply of.a specific resource with a specific end use), Subsystem Coal in the ground,t,o any linked end use (a.logical collection of trajectories* defining an a'spect.of the.. total energy system) System Energy production and use in a given,year (collection of all.trajectories'in the-energy economy) These definitions are identical to those formulated by,. Brookhaven National Laboratory These definit ions-are further explained by the'following diagram: TRAJECTORY- Seguenpe of.Activities Extraction Transportation Processing or Conversion End Use _@St@orag@e @,Dis@tribu@tionj --------------------------- ------- -------------------- ------- -ACTIVITY An acfivii y is one--,or more processes. One process -could-be distributioh-lof,-coal by unit train. s Several ptoce'ses In-series,might be ag shown,below. y 'Rough Sizing. Washing Primar' coal Breaking Cleanii@5 The envitorAnental,impacts to be identified and quantified are those which relate to water pollution, air pollution,, genera- tionof solidVastes, use of-land, occupational health, and potential for large scale disaster. The water and air pollutants under consideration are the, following: Water: Acids Bases Dissolved solids PO No others Suspended solids Organics -BOD COD jLizing Thermal 11-2 Air: Particulates NO x Sox Hydrocarbons CO Aldehydes, etc., Solid wastes under consideration are all residuals not en- tering the air or water that result from the basic fuel resources or from the system processes that make fuel useful for cons s ump- tion, or from the end use' of fuels. The land impacts include areas required for extraction, structures, disposal of solid wastes, roads, ports, pipelines, storage, and buffer zones.' Both fixed and incremental land effects are considered. Fixed land effects are those associated with facilities such as processing plants, pipelines and storage tanks, whereas incremental land effects are those associated with excavation, such as strip mining,. and solid waste disposal. Occupational health is considered,on the basis of deaths, injuries, and man-days lost due to injuries. All of the environmental impacts mentioned so far are quanti- fied and tabulated with suitable units.' Further details are given.in the following section on energy supply. The potential for large scale disaster is identified with@- respect to the possible nature and magnitude of disasters and -use trajectories to specific processes in the supply and end No quantifications are associated with these identifications: B. Format The construction of a computerized data bank requires that a large number of inputs be prepared according to a specific for- mat. From the standpoint of this report, thereader need only be familiar with.certain ground rules regarding data identifica- tion. The relationship between the format of data in this,report @and the computerized data bank is explained,further in*Section D... 11-3 1. Impact Data-and Data Hardness 2 Each entry of environmental impact.data in.the supply tables has three parts. This is illustrated below. 2.40-04 3 7019 L footnote number -data Input.hardness.number ..data input to three significant figures 2.40-04 is equivalent to 2.40xl-4 or .000240.. Units of the data.are at the top of the column in the table A data hardness number is required for each entry except those -with 0998 and 0999-footnote-designations. In.the..computerized, data,bank, it will be.possible to search.for.hardness-numbers in order to categorize,V the- inaccuracy- of-. data blocks.,,. 8q2ardness .,.number definitions-are given in.Figure.4. As a: general rule, it Iis useful to consideqr_data hardness in the context of "'confidence" and relate his to.the 1 to 5 scale. Footnotes and-References use-abbreviations where possible to facilitate loading of data into:the Computer-data-bank. Appendix A is a list of abbreviations and their definitions. When using-exponential numbers such.as-l.,35xlqo8,the designation within the footnote will be 1.35E4q+08, 1.35EqO8, or 1.354q+08. 2. 'Footnotes and References Footnotes and references have been classified according to ..a numbering system which is shown in.Figure 5. Note that specific blocks of numbers have been allocated tothe various pieces o6qf data assembled. The numbers in Figure 50q1ndicate which new foot- ;notes follow each individual table.,These footnotes are related to the new information generated for the-table,4qi,n question. This will become apparent as the 20qtables are used. Footnote and refer q- ence numbers appearing in this volume but not-included in Figure 5 are from Volume 'I of this report. Many of these footnotes and references have been included in this volume as well for con- venience. II-4 Hardness, Definition* Example Very Good Highest confidence. Nationwide consump- Error probably :!-110 percent. tion-based on Data well accepted and verified. accurate reporting technique. 2 Good Reputable and accepted. Data from several Error probably :6 25 percent'.. major companies used to represent U.S. 3 Fair Error probably 50 Data from one com- percent. Validity may be un- pany us.ed,to certain-due to method of com- represent U.S. bining or applying data. 4 Poor Low confidence in data. Telecon estimate Error probably 100 percent. used in,absence of Validity questionable. measurement.. 5 Very Poor validity of data Assumption based unknown. Error probably within on related refer- or around an order of magnitude. ence. Several Fair 9 or Poor sources combined. Error levels cited refer to cases. where thedata are non- zero. For,iero or "negligible" valuesi the-definitions Good, Fair, etc. should be applied-to the various hardness levels., Figure 4. Hardness.Number Definitions Table Footnote Reference No. Numbers Numbers Low Btu Coal:iGaskfication 1 ,8000-8035 High Btu Coal Gasification 2 -83oo-8324 Oil Shale 3 9-000-910.5 9000-9041 Fluidized Bed Boiler 4 9200-9234 '920079222 Combustion @Solvent Refined-CoAl 5 9300-9350 9300-9335 Coal Liquefaction 6 9400-9460 9400-9406 Figure,5. '..Numbering,Classification for Foothotes-and References 11-6 -In addition to the footnotes which are printed text, three other designations are used in the tables. These are defined as follows: Footnote No. Definition 0997 Zero or.negligible impact for this activity - an appropriate hardness value is required 0998 This-impact not applicable.to this activity 0999. This value not available an impact for this activityis assumed to exist To simplify the citation of referenceBwithin footnotes, the following fotmat has been used: Format for Reference's in Footnotes: T3 0 0-4 ) Reference 3004 (3004,739) 'Reference 3004, page 739. .(3004,739,742) Reference 3004, pages 739,742 (3004,739/742) Reference 3004, pages 739, through 742 (5123,A-'9) Reference 5123, page.A-9 (5123,A-@9'J,A-12) Reference 5123, pages A-9, A-12 (5123,A-.9/A-12) Reference 5123, page A-9. through A-12 Note that a reference.citati6n is always enclosed in parentheses. Footnotes-which follow the tables appear in the exact.form that a computer printout willyield. Each footnote indicates the-referencesand other footnotes it is based upon'. In this report some minor inconvenience derives from having to refer to. a separate list of references located following all of the tables and footnotes. However , in the computerized data bank, footnotes could be printed out followed immediately by the applicable refer- ences and first order footnote referrals. 11-7 C., Energy Su 221Y 1. Introduction The energy'supply tables and footnotes deal with the quanti- fication of theienvironmental impacts.of@each process in the fossil fuel energy supply tra ectories based on'a process input of the fuel equivalent to 101i Btu/yr.. The value of 1012 Btu/yr was chosen as a:convenient unit for an energy rate. The rate form was chosenito. facilitate the use of published data on environ- mental impacts in which-a time factor is involved,-'such as, for example, emission rates in lb14 ay,for evaporation losses from gasoline storage-tanks, impacts,related to annual production rates, etc. Whereas Volume-I to this:-_report considered the supply tra- jectories,of the primary fossil fuels and their derivatives, this volume focuses-on six emerging energy technologies as com- poAents of future energy supply trajectories.' Five of the six technologies - low Btu gasification,. high Btu gasification, fluidized bed boiler combustion, solvent refined-coal, and coal liqu e"faction - utilize coal in*the production of-synthetic fuels or electricity., The sixth,,oil shale technology, considers.th6 production of ctude-oil,from this-new,energ.,y..source. For those technologies utilizing coal, the,environmental impacts, efficiencies., and costs have been developed. for three regional coals and a national average case. In contrast to Volume-I of this report, all of this informationappears on the same table. The coals.forwhich data@;have been.developed include a.low sulfur (Northwest), medium@sulfur.,(Northern Appalachia), and.high-,sulfur@(Central),coal. Eac 'h of the tables,is organized as a-matrix with the environ- mental impacts as columns and activities and proc esses as rows. For each activity on the left of the table, the relevantproces,ses are-listed immediately below. In general,, the entries in the tables are on,a process basis, rather than on an activity basis. As noted earlier, an activity may consist of a single process, ordt may consist of a numberof processes. @hich gives basic Each.table has a related.general footnote w data pertinent to the fuel considered,.puch as the,amount of the fuel equivalent to 1012 Btu. It is important to note that all impacts have been derived for a process input of fuel equivalent to 1012 Btu/yr. In particular, for the extraction activity, this is@interpreted to mean 1012 Btu of resource in the ground. Thus. impacts for the,extraction activity are expressed-per 1012 Btu , in'the ground and not per 1012 Btu.produced or extracted (output of fuel). 11-8- A'general,caution is applicable to all the supply %data. Before using any.impa t expressed in terms of-, 1012 Btu, the reader should read the footnote. Potential misuses of the data can,readily be cited. Increasing the plant capacity may not in- crease.the land impact proportionately, since the land use is not necessarily linearly related,to-the productive capacity of the plant. Doubling the productive capacity doubles the land requirement only if an *additional and identical facility is con- structed. Caution must be'exercised when evaluating the land effects forlarge multiples of 1012 Btu/yr. Similarly, size considerations are important-in cost calculations and the foot- note will relate how the particular entry has been calculated. It is important to note the interrelationships betw een en- vironmental impacts, efficienc , and cost data. Strictly speaking, y a specified.level of environmentalcontrol hasassociated with it corresponding levels of.cost and energy requirements. This is apparent in a comparison of the uncontrolled and controlled en- vironmental tables. However, this is alsotrue within each supply table, as air pollutant data is related to ancillary fuel use, land use is.related to solid-waste data, etc. . Air pollutants associated with the generation of electricity are ascribed to the powerplant activity and not'at.the site.o.f the process which uses the electricity as ancillary fuel. 2. Definition of Uncontrolled and Controlled All supply tablesare designated either controlled or un- controlled. "Un controlled,',' according to the ground rules adopted in this study, means that impacts are the current national or re- gional average value. In the absence of current,(1972-73) data, impacts typify the use of least stringent environmental controls. "Controlled" implies that impacts are consistent with the use of control technology which will probably be required and/or available in -5. to 10 years. As An illustration, present laws 0 governing the reclamation of surface mined lands minimally require. that effort@'be made to restore the land. This may include par- tial backfilling and an attempt at revegetation. However, since the degree and success of reclamation are not mandatory,'(for the "uncontrolled" condition) reclamation is not assumed for area stripping operations, and only partial backfilling is assumed for contour mines. In the controlled situation, contour backfilling and revegptation are required for either type of stripping operation. The attainment of this high level of. reclamation@would require such practices as stockpiling and redistribution of the topsoil, segregation of toxic overburden and seed.bed preparation. Generally speaking, the controlled condition incorporates the environmental standards proposed or soon to be implemented by the 11-9 Environmental Protection agency.` A more.detailed explanation of controlled andJuncontro'lled as it is.related specifically to each Process in the fossil fuel supply chain is to be found in the writeups preceding each-of the supply tables'and in the accompany- ing table footnotes. The data in this volume have all been developed for the Incontrolled environmental condition. This was because the tech- nologies.considiered herein are either being developed primarily 4qii2qu4qutors for environmental control or are potentially 'major cont .to environmental impact For this latter category, from a practical pointof view stringent environmental controls will .be -a necessity. 3. Environmenital Parameters, In the supply tables, the units for the various environmental impacts are noted above the columns. Since the basis for the tables is the fuel equivalent of 1012Btu/yr, the actual units for the values given in the tables are interpreted as follows: Water Pollutants: Acids, bases, dissolved, Tons discharged to water bodies/yr solids, suspended Fuel equivalent to '1012 Btu/yr solids, organic's: tons, _12 I U btu BOD, COD: Oxygen.demand, in.. to 10qons/yr Fuel equivalent to 10 12 Btu/yr tons 12 10 Btu Thermal: Btu'discharged to water.bodies/2qyr 12 Fuel equivalent to 10 Btu/yr Btu 10 12 Btu Air Pollutants:' Tons discharged to atmosphere/yr Fuel-equivalent to 1012 Btu/yr tons 12 10 Btu'- Solid Waste: Tons placed on land/yr tons.. Fuel equivalent to 10 12 BtU/yr 10 12 Btu- II-10 Occy2ational Health: Deaths: Deaths/yr - Deaths Fuel equivalent to 10 12 Btu/yr LU 2 Btu Injuries. SeriolIis injuriesZyr Seriou's injuries 1 12 12 Fuel equivalent to 10 Btu/yr 10 Btu Man-days Man-days lost due to serious injuriesZyr Man-days 'lost, lost: 12 =2 Fuel equivalent to 10 Btu/yr 10 Btu Land: Fixed: Acres occupied by fixed facilities@ Acre-y Fuel equivalent to 10 12 Btu/yr 10@2 Btu Incre- Time-averaged incremental acre's ='Acre-yr rental: 12 12 Fuel equivalent to 10 1 Btu/yr 10 Btu The'values.for land disturbed shown in the tables are, where applicable, the sum of fixed and time averaged incremental lan& impacts. As an example, consider a coal proce ssing plant which ha*ndles B Btu/yr of coal, occupies A acres,'and produces 86lid waste for*disposal occupying an additional a acres/yr. The fixed land impact'is defined as: A A in units of acre- yr f 12 10 Btu The incremental land impact is defined as: a acre A in units of 12 10 @Btu To sum these land impacts it is first necessary to intro- duce the.units of-time, or time average the incremental land impact. Conceptually this represents the Average acres of land which will be impacted over the lifetime of the plant. Numeri- cally, the time averaging process will depend on whether or not environmental controls, specifically reclamation of the disturbed land, will be employed. Figures-6 and 7 illustrate the-uncontrolled (i.e., unre'claimed) and controlled (reclaimed) environmental con- ditions as they pertain to.the time averaging of incrementil land na B UA Cie 4& Cj 3a 2a C A 2 3 4______\1 n - 1@@n TIM&-Y'EARS NOTES: 1) Plant lifetime n years 2) Incremental land impact.a acres/yr No reclamation of disturbed land -Ffoure'@ 6.; Uhcohtiftl I ed' Incremental: Land.'@ Impact B 3a C Uj 2a a CC .4 D 2 3 4 n-1 n TIME-YEARS -ifetime n' NOTES: 1 Plant 1 years 2@ "Incremental I and, impact a ac'res/yr 3) Reclamation Of di.sturbed land with year time,lag for-revoetation Fi-gure 7., Controlled Incremental Land -Impact 11-12 use. As shown in Figure 6**, for the uncontrolled plant with an ri year lifetime 'and an incremental land impact of a acres/yr, the total amount of land disrupted after:n-years,would be na acres since the land is not being reclaimed for use. The-average land impact over the n year lifetime of the plant is given mathemati- cally by the area'of triangle ABC divided by n years, i.e. 1/2 (n)(na) or (n) A. Hence, thetime averaged incremental n .land impact for the uncontrolled case is defined as: n a acre-yr Ait 2 in units of 12 10 Btu" Figure.7 shows the land impact for the same plant employing reclamation practices to recover the land disrupted by the solid waste. In this'example.three years was chosenas the time period necessary.for reestablishingvegetation. Thus, assuming con- current reclamation, the land impact curve in Figure 7 levels off after the third year. That isi after the third year, the number of acres impacted-remains constant. For each a acres disrupted in any year, an equivalent A acres has been reclaimed (starting three years before). The average land impact over the n year lifetime of the controlled plant would then be given mathematically by area ABCD divided by n years, i.e., (112(3)3a) + (3a)(n-.1) or (3 9)a. n in- Hence the time averaged incremental land impact for the controlled case with a three year time lag for revegetation is defined as: acre-yr A. (3-1) in units of it 2n B 101 Bt Note that the controlled definition given above is only applicable for-those cases where three years is required for reestablishing vegetation.. If, this time lag changes, obviously so will the time averaging multiplier. Generally the plant lifetime (n) is taken as 25 years. Based on this value the time averaging multiplier (n 4 for the uncontrolled case y) would be 12.5 years, and for the 9 three'-year time lag controlled case (3--f-), the multiplier would n be 2.82 years. This time averaged.incremental land impact calculation arbitrarily ignores-any land impact which could occur beyond the specified lifetime of the facility. Continuing impact from yet unreclaimed land or the remainingstructural facilities beyond the expected useful life (n) of those facilities is not considered. 11-13 4. Ef f icieficy The Hittman data tables,contain two'efficiency,related inputs. These*are primary eff.iciency,(dolumn 26) and ancillary energy (dolumn 27) Efficiency definitions can be related to the following diagram: Ancillary Energy 12 (io Btu 12 X(1,0 Btu of fuel output 12. 12 Input 10 Btu,6f fuel, Process Y(10 .),Btu-consumed in prOdess 12 z Btu- physical loss @Where: X+Y+Z Primary-Efficiency x 1-y-z Overall'Efficiency x-u (BNL) overall Efficiency x Theoretical) .1+u X_u for+small u, iae., u,<<l 1+u If the-process-separates the input fuel@,stream into several output fuelg, X.(1012) may be taken as the'-sum of the energy con- tents of the output fuels and x as ah approximate value for the efficiency of,each output fuel. In some proces'ses there is apt to be confusion as to whether an'Onergy use is classified;as ancillary or part of the input flow consumed. In a r6finery,,.-refinery gas (which provides energy for many processes) is considered as primary fuel-consumed rather thanlas an ancillary demand. Any,use of a fuel derived 'from the primary input stream remains part of the-primary flow. 11-14 50 Costs Cost data expressed in 1972 dollars.are included in the un- controlled and controlled national supply"tables in columns 28-30. The total capital or fixed,cost for equipment, structures, etc. is annualized at 10 Percent per year and.,shown in column 28. This capital -"cost" is synonomous with total capital investment and does not include interest during development or-working capital. Yearly operating expenses for fuels, maintenance,Iabor, etc. are given in column 29, while column 30, which represents the total annual cost, is the sum of columns 28 and 29. The units for the economic data are shown below: Fixed Cost: ($ of cai2ital expense) x (.10/yr) $ 12 12 Fuel equivalent to 10 Btu/yr input- 10 Btu Operating $/yr for operating expenses $ Cost Fuel equivalent to 10 12 Btu/yr input- .10 12 Btu The 10 pprcent/yr annualization or "fixed charge rate" (as it is called in the table footnotes) for capital expenses was chosen,mainly for convenience.and may or may not-reflect actual practice within a particular industry. It'is convenient to ex- press the capital cost data in this,fashion because: 1) itprol- .vides some estimate of total Annual costs and 2) it allows a qui6k estimate of total capital cost from the table data by simply increasing the fixed cost by a factor of ten.'. That is, for a table fixed cost entry of 1.50+05 the total capital cost is 1.50+06 or 1"1/2 million dollars/1012 Btu equivalent fuel input. The price of the raw energy resource into a process is not included inany'6f the cost data. The annual cost data,repre- sented in the tables is.a major component of the ultimate price level of the fossil fuels delivered. Since the basis for costs is 1972 dollars'.. table values would have to be adjusted to re- present-day (1974) costs. 6. Allocation:_Of .,_Table...@.Entries to Proces.s Fuels., The folIowing@suggests' a technique for allocating tabular impacts to.the product'@fuel mix. A refinery or natural gas pro- cessing-plan,'t.is used as an example'. oil refineries and natural gas processing plants separate input fuel streams into several output fuel strd'amg@, X Table entry.for 1012 Btu/yr of input'stream lb12 Btu/yr 'Refinery or NGL Fuel A Input s' ream, separation plant Output %-'Fuel B streams Contain@s A,B,,-C' Fuel.,. C Ancillary fuel if the data &467Eo, ..be used' to cohstitudt-A trajdrdtory for a particular product flusl, starting at the well head-where such fuel does not extst as ah,ehtity, the table entries for the pro- cessing activity or for activities prior to processing may be used' as reado'nab,16 appr'6kir4tions for such product f uel. X Table entr@ interpreted as for 101. Btu/yr of f uelA 12 10 Btu/yr of Fuel A assumed to Refinery or NGL Fuel A 00 separation plant- exist as an entity Ancillary fuel 11-16 D., Energy Model and Data Base (EMDB) The data presented in this report have been entered in a computerized data base (MERES). Brookhaven National Laboratory has combined this data base with a number of data.management and energy modeling programs to form a completepackAge known as the Energy Model and Data Base, or EMDB. Brookhaven National Laboratory (BNL) will ontinue to update, maintain, and improve c the data base and its associated programs., .The EMDB is presently available on'the Control Data Corpora- tion computer facility at BNL. It will be directly accessible via a telephone connection and terminal to remote users. In* writing the computer programs for the EMDB, care has been taken to insure that the programs would be easily transferrable to other computer facilities. The basic unit of storage in the EMDB is a particular supply or utilization (end use) process, which corresponds to the com- plete set of numeric values contained in a single row of the tables in this report. Each basic process storage unit,contains all of the numeric values (and'the 'ir hardness factors) as well as the full documentation for the,number set. The specific pro- cess desired isidentified by a string of mnemonics which have different forms for supply and utilization processes. These string forms are as follows: SUPPLY: RESOURCE/ACTIViTY/PROCESS/R@EGION/CONTROL/. UTILIZATION: /SECTOR/ACTIVITY/PROCESS/FUEL/CONTROL/. The mnemonics for each supply activity and process can be found in the left-most column of each supply table (Tables 1-6). There are no utilization (end use) tables in this Volume. The accessing codes for supply are further detailed in Figure 8. One of the programs associated with the EMDB permits the calculation of national energy flows and the impacts of such flows on resource consumption, pollutant e 'missions, and dollar costs. This program, called the Energy System Network Simulator. (ESNS), considers the energy system as.a set of process links in a network 'representation. These network process links can be associated-with particular process blocks (both supply and utili- zation) in the EMDB. An interfacing program is provided which draws'numeric values from the data base and makes them available for flow calculation through the network. Capabilities are, also provided for modifying any numeric value for input to the ESNS and for adding new'links to the ESNS network. With these capabilities, the effects-of various simulation scenarios can be calculated. 11-17 Order of...mnemonic string-identifier-corresponding to a ,supply table. row: /RESOURCE/l@CTIVITY/PROCESS/REGION/CONTROL/. Identifier Mnemonic Resource: -Coal COAL Oil OIL Natural-Gas GAS .Activity: (See,Supply Table) Process: -(See..Supply Table) Region: National NkTL Northwest Southw 'est ..Sw Coal Central CNTRL. ..Northern__A palachia NAPPL P- - Central A palachia CAPPL p ..Domestic-Onshore .,ONSHR 'OFSHR Domestic,Offshore -Imported.Middle East,Crude MECRD Oil Imported'Cana"dian Crude CANAD Imported-South American SARSD Residuai Onshore ONSHR Offs hore OFSHR Gas Canadian CANAD Control: Controlled CONTL Uncontrolled UNCON Figure 8. Data.Access Code for Supply I1_18 I. LOW BTU GASIFICATION OF COAL A. Introduction The environmental impacts, efficiencies, and costs of Low Btu Gasification of Coal aregiven in Table 1 of 12 this report. This table is based on an energy input of 10 Btu/yr into each process utilizing current or 'soon to be available pollution. control techniques.@ The primary purpose of Low'Btu Gasification of Coal,is to provide fuel gas, ranging from,.150-200-Btu/SCF,, for power generating purposes. Although this low Btu gas may have other industrial purposes, this report assumesall gas is used to fire conventional or combined cycle power plants. The five specific processes studied arex. 1. Applied Technology'Corporation (ATC) Process 2.. Bureau of Mines Atmospheric Process 3. Bureau of Mines Pressurized Process 4. Lurgi Process 5.1 @Koppers-Totzek Process 'Each of the five technologies will consist of two activities; gasification and elf-Ictricity generation. An electrical transmission activity is presented for the Northwest, Northern Appalachian And National Average cases. The transmission distances are based on the mileage from the generating location at'the mine mouth to the metropolitan. Chicago area. No electrical transmission data, are presented for the Central case, since the gasification/electricity- generation activities are.assumed to take placein the metropolitan Chicago area. The environmental impacts in Table 1 are based.on processing three regional coals and-a simulated-national average coal. It should be Xioted,that all caDital costs shown in Table 1 .are based on a plant@load factor of unity, i.-e. , the plant is assumed to operate 365 days/yr. The values presented in this table are based on data accumulated during the Fall of 1973. The following is a brief description of the individual processes: ATC S02 Free Two-stage Coal Combustion Process The ATC process (Figure 9) consists of injecting coal particles into a molten bath of iron n. Because iron in the liquid state has an affinity for sulfur and carbon, the coal solubilizes to release'organic'and inorganic sulfur coonstituents'for reaction with the active iron melt. The iron sulfides. formed mirate to a.lime containing slag f loating on the molten iron bath -where they are removed from ,the combustion proceddssAt the same time, the iron that is dissolved in the molten iron is-reacted with air to produce. an off-gas which consists of nitrogen, carbon monoxide, and hydrogen. this 25000F+ gaseous mixture, essentially-free of sulfur dioxide, is introduced into a steam boileIr along with secondary air to recover All of the heating value-of the coal. Sulfur is recovered in elemental form Ifrom the-slag produced in the ATC process-along with iron contained from the coal pyrite's 'and a desulfurized slag. Bureau.of Mines Producer Gas at'Atomospheric Pressure The Atmo Ispheric Pressure Producer Gas Process (Figure 10) consists of gasification'of coal by its partial combustion in a stirred bed,, supported on a revolving eccentric grate which producer gas is passed through'iron removes the ash. The raw'pro e oxide absorbers for sulfur removal. The regenerated absorbers yield"sulfur dioxide which flows to an ammonium sulfate plant for the production of crystallized ammonium sulfate. The desulfurizid atmospheric producer gas coming off the iron oxide absorbers contains soot and tars and is at-approximately. 13000F. 111-2 BOILER COAL SLAG LIME- STONE GAS H2S CLAUS COMBUSTOR PLANT IRON 'AIR SLAG SLAG Of FURIZER SULFUR --STEAM @IRON DESULFURIZED SLAG ----------- TO CRUSHER Figure 9. Applied Technology Corporation Two-Stage Combustion Process for Low Btu Coal Gasification (Ref. 80.22) 66S TO CQA_L_. I ATM- BOILER FEED HOPPER 0.5 psi g GAS. SPRAY COOLING TOWER H GAS. 2S PRODUCER IGAS. ABSORBER STEAM ANb@ WATER REGENERATOR w.WATER AIR EDECANTER TAR SOLID WASTE. SOZ-,- TO AMMONIUM SULFATE PLANT Figure 10. Bureau of Minos Atmospheric Gas Producer for Low Btu Coal Gasification (Ref. 8014) M Eli M M M no M Bureau of Mines Producer Gas at Elevated. Pressures The Elevated Pressure Producer Gas Process (ligure 11) con- si9ts of gasification of coal in the-same:.manuex as described for the Atmospheric Producer Gas Process, with the important exception that the producer vessel is pressurized to,120 PSIG. To accomplish this,coal is fed to the producer'vessel.through a lock hopper system. The gascoming off the iron oxide absorbers flows to the gas scrubbers where soot and tars ate removed. This will allow the 270*F, 120 PSI product gas to be utilized in a gas turbine for-combined cycle power generation. Lurgi Process The Lurgi Probess (Figure 12) consIstsof gasification of coal with air and steam at a pressure of 300 PSI. The gas leaving the ga:@ifier is scrubbed to remove coal dust, Alkali and chlorine. The-H2S is then removed from.the gas stream by.an alkalized wash. Subsequently the H2S is converted into elemental sulfur in a Claus kiln. 'The gas produced contains .oil, naptha vapor and*other carbon products',of the gas-ifidd coal and is at 4 temperature and pressure.of 300*F and-2501-MISI respectively. Ko22ers-Totzek Process The Koppers-Totzek Process (Figure 13) consists of the par- tial oxidation Iof pulverized coal in suspension-wi-th,.oxygen and.* steam. The heart of the process Iis the burner nozzles at which the,oxygen, steam-and coal react to gasify the carbon., and volatile matter of the coal at a slight positive pressure and at 3300F., After gas cooling and scrubbing, the gas stream is de.sulfurized. The gas produced will be at less than, 350OF and slightly greater than atmospheric pressure. 111-5 GAS TO 105 psig TURBINE COAL FEED- HOPPER 115 psig 110 psig SPRAY. COOLING TOWER 1-12S GAS ABSORBER PRODUCER. STEAM' AND 120 psi g- WATER WATER REGEN@RATOR DECANTER.. AIR TAR, SOLID WASTE J." soz -SOTO AMMONIUM SVLFATE. PLANT Figure 11. Bureau of Mines Press.urized.G.as Producer for Low Btu.Coal Gasification -(Ref. gol4l- IT @ER EXPANDER COMPRESSM/ GENERATOR DESULFURI ZED GAS COAL DESULFURI STEAM GAS GAS ZATION Ir GASIFIER WATER SCRUBBER H2S TAR CLAUS STEAM REMOVAL AIR KILN TAR SULFUR ASH CLEAN FUEL GAS TO TURBINE Figure 12. Lurgi Process oflow Btu Coal.-Gasification @(Ref. 8031) DESULFURIZED GAS SUPERSATURATED TO USERS STEAM PULVERIZER GAS ABSORBER FEED WASTE HEAT COAL BOILER: RAW GAS GAS COOLER AS PAIMAW GA.SSECONDARY GASIFIER WASHERT@-@ WASHER.' OXYGEN STEAM SLAG SLUDGE TO-CLARIFIER FOULABSORBENT AND DISPOSAL TO STRIPPER Figure 13. Koppers-Totzek Process of Low Btu Co'al Gasification (Ref. 8024) 7 G 7S B. Impact-Data.Table and Footnotes 111-9 co - M- I - I.-- V It L. SIMI" 9: L) 0 E- m 8 E@ z 0 00 Ho 'mr A A X0 Cc 2 .14 I w w 2 T A A A A - I I A . . . . . . . . . --ca 7- x - - - . . . . . - - - - -- -- 0 a 2 v al z:l I 0- 0x p g P i.- z 2 0 0 0, - - - - . . . . . . . 75 0 wt wL I S 9 0 - - - - - - - 0 - - - - - - - - - - - - - - 0 @9 - - - - - - - - - - 0 9 14 z 7 4 0 n it 0 @xl 0 0 P-r 0:j 0 0 0 t.0 10 0 it 3. 0 TZ - - - - ... . . . cr + + z 0 ti 0 0 EO 0< UO y 9. 11 .21 11 1 0 !21 In MIX I A 1 0, 10 M-P I AM M M M M M 'PIC -1-1-1-12 c1l) -13 x 0 a l0fl 0 P4 ou z 0 La Wc xz .10 zL - - - - - . . . . . 0, 302 lz + + 0 10 - - - - - z0 Ow . . . . . < LO !50 2 j7 - - - - - - - - - - . . . . . . . . . . 0w 3c0 cr I o-'61 O'd 11 il 9@1 41 IN 1 1111 1141111 11 L '122tesgr. N . . '01010 0121 1 1!21 2 1 t I LI 1 11-0 1 1906,-2907 Footnotes for Table JL 1906 Source (1906,46).. 0.166 men per 14WE is the basis for calculation Injury data are from-(1907135). Half the combined deaths and permanent injuries are assumed to be fatal injuries. Permanent total disabilities are considered to rppresent 6000 days lost while other disabilities are estimated as 100. days lost. 1912 A large new powerplant is..assumed, to have a heat rate of 8960 Btu/KWH, equivalent'to 38 percent-conversion efficiency. The best plants havb,achieved around ,8530-.8900, whereas the National'AVeraige i's around 10,500 (1913,1-5-6/1-5-7). 1913 Power sold divided by-'power produced, 1969 (1919,11,13). 1917 The basis.for water pollutant calculations is the-proposed effluent limitations guidelines an&new .source performance standards for the steam'electric power generating point source category given in (1921). For new plants, best ava'i'lable'demonstrated control technology (BADCT) requires effluent pH control in the range of 6-9.- Hence acids and bases discharge will be negligible. BADCT also specifies total suspended solids levels no greater than 15 mg/l for. all intermediate and low volume waste,effluents. At this level"of control-there will generally be no net increase in suspended.solids in water passing through the power plant, system., Organics (oil and grease) must be controlled to 10 mg/l to meet BADCT standards. Hence,.from, 11921,232) these emissions will amount to 3.0Z-03 ton/1012 Btu. Information on the increase in total dissolved solids of water used in power plants is not readily available and was synthesize*d from (1922,10,12,20,22). Based on this data the net increase,in total dissolved solids for water used by the power plant is 3.40,ton/1012 Btu. 1918 Thermal discharges are assumed to.be comple tely eliminated by use of mechanical draft cooling towers. 2907 Capital and operating costs for controls are estimated as follows: Control System Capital-Cost- Operating Cost- $/Kw Ref. Mills/Kw-hr Ref Water Poll-Chemical 1 (1921,233) ..05 (1921,234). Water Poll-Thermal 10 (1915) .05 (1920,111-3) Total Tr -.10 Based on the above, a 60P load factor and a net plant heat rate of 9053 Btu/Kw-hr (37.7P primary efficiency from foot- note 2908) the i 'ncremental capital post is 2.31+04 $/l.OE12 Btu and the incremental operating cost is 1.10t04 $/l.OE12 Btu. These.are in addition to thecosts given in footnotes 111-15 FTN. 3903-8001 2906 and 3905. Note that incremental fuel costs associated with purchasing a. 6P sulfur residual oil (for oil fired power plants) are not included in the above analysis.' Al- though Properly attributed to air pollution control costs, the cost of fuel is not considered;in the operating and maintenance costs of the uncontrolled case and hence an incremental fuel cost is not given for the controlled case. 3903 See footnote 1906, using 0.089 men per MWE. 3905 Cost of gas fired power plant at $100/Kw,(1914) and (1915). operating and maintienace cost exclusive of fuel cost,At 0.51 mills/Kw-hr (1906,45). A 60P"load factor is assumed and the FCR for capital is 10P. 8000 Primary efficiency for the ATC two-stage coal combustion process includes the decrease in efficiency associated with the necessity of thermal drying of the ROM coal.from '22.25 to 4 percent moisture (8022-23). From (8006,13-3/13-25) and the fact that it takes 5.42E4q+04 ton of 92268qA Btu/lb average Northwestern coal for 1.OOE+12 Btu input, 1.10E+03,ton or 2.0 268qf ercent of the coal is consumed in drying. This leaves 4.38E+04 ton of 11288q5.6 Btu/lb coal going into the process.. This 4.34E+04 tons of 4.0 percent moisture coal is' then dried to 1.0 percent moisture prior or to e-ing the combustor, leaving 4.21E+04 ton of 11q115.6 Btu/lb coal (8022-236qY. Based on the above input to the combustor and that 3.7.98qE8q+6qWlb low 8qBtu,gas, at 2.58E2q+03 Btu/lb are produced per-l2qb of North4qWeste"rn coal, the efficiency of gas production = 84.0 percent. The' primaryefficiency of the!ATC combustor coal conversion proces0qwqo 0.98 x 0-.8.3 x 100.0 81.0 percent. 8001 The land impact of the ATC coal@combustion process consist's of equipment for-thermal drying-q(se4qd-footno2qte, q8000), equipment for the combustor unit and., desulfuqrization unit, limestone storage and desulfu0qkization slag storage. Coal stor0qagewill be allocated to the utility since the combustor can be retrofitted to an existing facility (8015,45). No impact 0qon land Area.could be found for thermal drying. It will'be assumed at 0.10 acre. The impact of equipment for the combustor and desulfurization unit will b00qe 4.50 acres, assuming a 1000 MW utility employing four 28 ft diameter combustors, sulfur recovery system, coal, limestone and air preparation equipment (80236q50q)q. From (8029), the use of the Northwestern coal will require 0.0119 lb l0qiim32q68qs24qton08qe/lb q.08q072q"Iq:f2qe2qi08qedq,q@t04qc 24qthe process,and 0.q14q068q-2q7 l92qb stored slag/lb coal feed is produced. For 4.34E08q+04 ton coal feed .(see footnote 84q60b), 5q.16E12q+02 ton of limestone is needed. For 4.21+04 ton of coal fed to combustor (see footnote 80q600),2.8904q+03 ton of stored slag is produced., 111q-16 FTN. 8002-8003 Assuming a pile height of 30.0 feet and a density of T/CF for limestone and 0.060 T/CF for stored. slag, 9.78E-03 acre/yr and 1.11E-Ol acre/yr are used. Total land impact, acre yr/l.00q+12.Btu 4.78E-02 + 1.60E-02 = 6.72E-02. 6q&002 Particulate emission sources are the coal fired thermal dryer, air blown dryer, limestone dryer - crusher and combustor. A fluidized bed thermal dryer with a 99.0 percent efficient venturi will emit 0.2 lb particulate/ ton of coal feed (0002,8-10). With an input of 5.42E+04 ton coal/l.OOE+12 Btu,particulate = 5-42E+01 ton. The air blown dryer will have the same emissions .as the coal fired dryer. For the 4.34E+04 ton of coal fed into.the system (see footnote 8000), 4.34E+01 tons of particulate-are produced. Crushing of limestone with, a 99. 0 percent ef f icient bag house will produce 8.52E-02 tons of particulate (0002,8-15)., Drying of limestone is similar to drying of gypsum,thus with the use of a fabric filter 0.2 lb/ton of particulate is emitted or 5.16E-02 ton. (0002,8-14) The only particulates from.a commercial size combustor will be metallics, from bubbles bursting in the iron bath (8022,105/107). This amounts to 1.82E-04 lb/SCF in the test combustor but will be reduced at least by 99.0 percent orl:82E-05 lb/ SCF in the commercial (due to 4 times flue). 1.0 lb coal will produce 5.83E+01 SCF of.gas (8029), for 4.21E+04 ton of coal input to the system 4.96E+09 SCF gas is produced yielding 4.52E+01 ton of particulate. This particulate will not emerge from the conversion process but will be emitted from the utility and will be allocated to it. Total particulate emission from the conversion process = 5.42E+01+ + 4.34E+01 8q+ 9.52E02 + 5.16E2q-02 = 9.77E-01 ton. 8003 Sources of air emissions for ATC-combustor pcocess will be from the primary coal fired fluidized bed thermal dryer and Claus plant. Pollutants inherent in the combustor fuel gas are allocated to the utility where they occur. A well controlled thermal dryer.will emit 0.54 lb NOx/1.O0E+06 Btu, 0.'045 lb SOx/l.OOE+06 Btu, 0.58 lb hydrocarbon/l.OOE+06 Btu and 0.39 lb CO/1.00+06 Btu. From the coal used in firing (1121), III-17 FTN. 8004-8007 1.10E2q+2q0 ton of 9,q2_q26@q0 Btu coal or 2.038q98q+10'Btu is used for firing, thus 0q5.6q4q88qE+00 ton Nox, 4.6q5q7E-01 ton SO4qXI 5.89E8q+00 ton hydrocarbon and3-.96E2q+00 ton CO is produced. Emqi:ssionromhe Claus plant consists of sox. From the molar composition-of H2S + S0q02 of 35.0 percent of the gas and (8012) thelClaus plant efficiency is 92.0 percent from (8029q@, H2S' = 3.204qE-03 lb/lb coal and SO'q2 2..;qBOEq-03 lb S02/lb coal. Total S available = 4qC6qA0qI8qE`03 lb/0qib- coal,. For 4. 2 1E6q+4qW- -tons,-,+ 2qdoal, 1.49E2q+O2qi ton of-S qiv8qs@-av8qailable as"an 'emission or as S02 = 2,.97E2q+01 ton.-.Total S2qOqi = 0qC57E-06q12q+ 2.97-E0q+06q1 3.000qE6q+qO,ql ton. 8004 Ancillary energy demand iqs stated'as 12 8qMW.'.for 10,2qGqO MW: of electricity produced to operate the equipment' necessary-for the conversion process (8025). 1.q0q08qE2q+12 7'Btu input will product .9.'31E8q+04,-8qM0qW, (8.-02q9q) thus. ancilla,)4qr6qy energy = 1.12E2q+03 2qMor-3.83E2q+q04q9 Btu (8029). 8005 Water 6qdffluent-fr0qom the conversion proo'4qcess-occu 0qrs only from rxqinof f f r4q62qm stored sla6qq. The. conversion process: is a closed,, lo0qop-with- respect to,- water use. From. (804q22. 147), the su6ql6qf -q6qLt@e runo8qf f gi0qve0qm-@a s2q1a g,of l..qO percent sulfur, is 23"6qA PPM su_lfat4q6@0qor 2,.q95E-01 GM/S2qQFT'or 2. 4 3E-.012 ton.. 806 Solid waste, consists. of de8qs6qul2qf0quri0qzed slag. only. Sulfur will be sold at.current market prices- * In the Northwest,- slag will not, have- a market (8.022q5q).1 it is. cons0qid ered, a solid wa0qste..So6q1id Waste 2.89,8qE8q+03 ton (see footnote 8-q0q01). 80107 Air emiss0qsio8qn0qs-from the-utility'utilizing'the ATC process depends upon.the-c6qom6qpositqionlof the gas. One pound of NorthqO4qkqisternl coal will produce a.,gas- composition as follows ('8q029): 8qC4qO 1. 42,32 lb. H2 0,04q5q17 lb C02- 0.00,01 lb N2 2q.q;-3048q49' lb The gas will 2qalso@contain 228q2.0 P32qPM S20qOx, (80q-15,29)q, 22.5 PPM N28qOx 60qM0q,6q25) and 5.42E08q+01 ton particulate 2qIf16qootnote 8002). 116q1q-28q18 FTN. 8009-8011 For combustion of the low Btu gas, a firing temperature of 110OF - 1200F. will be used (8025). Assuming combustion is'essentially completethe emission from fuel gas. combustion, given .4.21+04 ton of coal input or 3.122q+08.ton of gas(fo2qo'tnote 8002), = 3.11E2q+00 ton SO, and 3.23E8q+00 ton 8qN4qO4qxand 2.26E2q+02 ton1particulate. Total.em0qissi0qon through the stacks are As follows: Partitulates sox N8q0x, 5.42E8q+01 3.114qE8q+00 3.,23E8q+00:' 8009 S02 emissions-from the BOM Atmospheric Gasification--- Activity is 3.9q5E2q+01 tons. Figure 'is based on a coal, input of 3.628qE8q+04 tons/yr..Of the qO@q68 moles 8qof H2S fed to theabsorber, 80 percent is reacted and-97,perc4q6nt is regene8qkatq;Bd. Emission of H2pis considered-as S02' (8010). 8010 Air emissions for the BOMq-Atmospheric Conversion Process,, using the Northern Appalachian coal,, consist only,of S8qOx.vented from the ammonia sulfate plant (8030). 80.0 percent of the H2S in the initial combustor fuel gas is removed by the iron oxide absorber. Upon regen4q64qration,0qA gas rich i8qn q@6q02is formed, This is.then fed to an ammonia sulfate plant'which has, an efficiency of 97.0 percent (8030q), The Northern Appalachian coal will produce a feed of 69.70 lb S02 equivalent/ton of 0qcoal,(8030), therefore the emission is 2.18 lb S4qOx/ton of6qoal. For a 1.qOqOE8q+12 Btu equivalent of 3.94EqO4 ton of coal, 3.95EqO1 ton ofS8qOx is produced. 8011 Air emissions for the B8qO4qM conversion proces6qs.occurs from ammonia sulfate production' as -described in footnote 8009. For Central.and-Northwest coals, with feeds 2qof 3.82EqO1 lb and q1.48+01 lb S02 equivalent/ton of coal-to the ammonia plant and coal feeds of 3.62EqO4 tons of coal and 5.424q+04 ton.of coal respectively, 2.07EqO1 tonand 1.20+01 ton of S4qOx are emitted respectively. III-19 FTN. 8012-8016, 8012 The BOM-Atmospheric Gasifier will require 5.428q+04 tons of.92q126 Btu Northwestern coal per.l.OqOE12Btu input. 6.38percent of this is ash.. Assuming*essentially all of this0qcan-be-removed from the combustor, solid waste = 5.422qkq04 x 0.0638 = 3.46Eq03 ton,(8030). This solid waste will'be.returned the mine as,fill. 8013 The 6qSOM-Atmospheric Gaslfier`will require 3.62Eq04to6qns of 13800 Btu/-,ql0qb@-Northern.Appalachian coal per 1.OqO2qE1 Btu input. 14.0 percent is ash and assuming all can,be removed from the combustor,solid waste = 0.14 x 3.62EO4 5.06EqO3 ton. (8030). 5.0 percent 4qW'2qill.'be returnedas fill to 0qthe mine...,, 8014 @The8qO8qM-Atmosphekic Gasifier will require 4.1q@EO4 tons of 12050 Btu4q/qlb Central regional coal per,1.004q+12 Btu input. 17.3 percenht'is ash. Assuming all ash is removed from8qthe combustr,solid waste= q02q473 x 4.15EqOq4,= 7.0'64qEq03 ton (8030). 8015 The land impact for the 8qB4qO4qM7 Atmospheric Combustor process using- @N8q6rth2qern Appalachian coal consists @of theequipqr8qw4qd4qnt-or conversion a4qn6qd-sulfu0qr removal and for ash st8qd-0qrage-.'The conversion and'-sulfur removal systems have a fixed impact of qSqO0qA acres. From. footnote q8q013,2.538qtqO3 ton of 0qash will be produced., In a pile30.0 ft high, ash 'Will occupy 2.918q1q-q00q1 acres. Fixed land impact for processing 1,.,qOqOE8q+1'q2 Btu/yr is -impact for ash 4.76E-01 A4qdre-yr. Time,,averaged, 'land disposal is 3-.438q8-01 acre-y8qr. total land impact is 8.196-01 acre-yr/l.qOqOE2q+12 Btu (8031q) 8016 The land impact for the-atmospheric coqm8qb4qtstor using a Central regional,cal having+.a heating value of 12050 Btu/8qIb consists of land required for the ash storage pile,, gasifier, gas treating facility, and the sulfur. plant. The ash:stor2qage pile assuming a 50 foot-pile occupies 4.85-01 acres/l.qOqOE12.pBtu. 4qFora throughput'. equivalent to operate a 106qGqO4qN4qW."plant the land impact is 3.76acres.q. This-is time averaged over 25 years. The fixed land '40qt04qmpact is 2q2.26 acres, The time averaged land impact per Btu throughput is 36qLq.q'07E2q02q0q-ac00qresq-60q0031). 8017-8023 8017 For the BOM-Pressurized Combustor using a Central region coal the only air emissions occur in the ammonia sulfate plant. For A-1000 lb feed 1.154 lb of so is released (8030). For a 1.OqOE12 Btu feed of 48q15Eq04 ton of coal, the S4q02 emission is 26qAOEq01 ton. 8018 For the BOM-Pressurized Combustor using a Northern Appalachian coal, the only,air emissions Occur from the sulfur recovery process in the ammonia sulfate plant. For a feed of 1000 Ib of coal, 1.09+00 lb of S02 equivalent is released (q8030), For an input of 1.00+12 Btu of 13800 Btu/lb coal, the S02 emission 3.'95EqO1 tons. 8019 Land impact associated with the BOM-Pressurized Combustor consists of the gasifier, gas treatment plant, sulfur,plant, and cooling, and.ash storage system. For a Central regional--coal this equals 2.50E-02 acres/1.0E2q+12 Btu input and a time-averaged storage of 4.94E-01 acres over 25.yea0qrs'assuming 50 foot pile.otcqil land impact =.q58-01, acres q(8031q). 8020 Land impact for.the BOMq-Pressurized'Combustor utilizing a Northern Appalachian coal is identical to fixed land impact for footnote 802q19, however it is adjusted to reflect change in Btu content of gas produced. Fixed land'impact = 2.40E-02 ash is the.'same. Total'-land impact 2.40E-02 + 4.94E-01 7.51E-01 acres (8031). 8021 Air emissions for the BOMq-Pressuriz0q6d combined cycle boiler consist of S8qy 2qFor an input of 1.qOqOE8q+12 Btu of gas 1.48E6q+04 moles o S02 are formed (8036). S02 4.74E8q+01 tons/1.q0q0E8q+12tu. 8022. Product gas from the absorber contains 0.136 moles of Hq2S/8.96EqO6 6qBtu (8030). For'a boiler feed of 1.002q+12 Btu, gas c6qQntains.1.54EqO4 moles of H2S. Assuming complete combustion.88EqO2 tons of S02q2/1.qOqO0qE12 Btu are formed. 8023 Produ00qc q't gasq@from the absorber contains 0.075 moles of 24qH260q4/8.97E6qO6 Btu of gas. For1q.00E12 Btu of 32qgas produced and fed toq.q,boiler 8.40E2qO3 moles of H2S are converted to so q. g complete combustion. S02 2.69E8q62 tons/ assum6qin 0q032qE12,q_q;32qSt00quq. FTN. 8024-8630 8024 Product gas from the spray cooler contains 0.075 moles qiqI4qj6qS/8.72EqO6,Btu of2qgas. For 1.00E12 Btu'of gas pro uced and fed-to-boiler 8.63EqO3 moles of H28q8 are converted tqo S02 in boiler Assuming complete combustion (8030), S02 = 2.786qiqO2 tons/l.qO6qDE12 Btu. 8025 Partic0qu late emissions consist of carbon,and sulfur dust emitted from the boiler. For a 1000 lb Central region coal feed I#I '3.02EqO1 qIbs 0qof 7dust are' 0q68qm4ql8qt't2qicqi. For a coal feed of 4.qi50q+04,ton/'l.qOqO4qE12"Btuemiss'lon is 1250 tons dust (806qH). Dust or particulates are removed by 80 percent,in absorber hence particulates -1.25 ton/ 1.qOqOE12 Btu. For.-use in a-combined,cycle power plant an additional 97 percent particulate removal must be obtained by electrostatic precipitator (002-Aq5q).. 8026 Particulate emissions for the boiler consqi4qzt of@dust as in footnote 80,25. Fora 1000 lb feed-emissions are. 3.19EqO1 tons. For 1,qOqOE12 Btu feed of 3.626q+04 tons and-90q"percent removal in,-absorber and 97 percent-by- precip2q*tator particulate-e8qm6qi0qsqgions= 3-44 4qton/l.qOqOEq12 Btu (8q03q0.,.0002-AqS). 88q627 Particulate emissions-consist of carbon and sulfur. emitted from-boiler. For a 1000 6qIb feed, 3.02 lbs are emittedin'gas and 90 percent-0qis removed-in absorber (8030). For 4.15EqO4 ton/l.qO.qOE12.Btu feed static particulates:= l.25EqO4q2:tons6q/-ql.qOqOEl2_Btu.An electro 4qp8qxeci2qpitqzq@-qE0qor' 8qat-.97,percent-efficienty--6qY.yields-3.75E2q+00 tons. - 8028 For 10:00 lb coal feed particulates = 3_19 lb for 90 percent removal-andicoal fee2q&of 3.62EqO2 ton/l.qOqOE12 Btu.8qE4qmqission = 1.12q5Eq02 ton/1.00 ,4qB12 Btu (8030). See footnote027. 8026qR For l.,00 lbof coal fed to producer, 0.001 lb H2S/6.04EqO3 Btu ofgas is formed.. For boiler feed-of 1.00Eq12.Btu and assuming complete combustion S02'= 1.56E,02 tons SO6qV 1.qOqOE12 Btu (80-30). 8030 Particulate emission fromqA.the absorber is 0.0026 lb/ 6.04E6qO3 Btu of gas produced. For a feed o q'6qf 36qIq.2qO6qOE12 Btu of gas, 2.12q6E6qO2 tons-of particulates,are generated (8030). III-22 FTN. 8031-8035 8031 Air emissions from the Lurgi Combined Cycle Process consist of SOX, NOX, and particulates. Emissions are:- (8027) N8qO8qX. = 0.021 qlb/1.q0q0E06 Btu input SOX = 0.057 l6qb/1.q0q0E06 Btu input Particulates 0.029 lb/1.q0q0E06 Btu-input For a 1.qOqOE12 Btu input air emissions are: 6qN4qO0qX = 1.q0q0Eq0q1 ton/l.qOqO4qE12 Btu SOX = 2.86EqO1 ton/1.q0q0E12 Btu Particulates 1.43EqO1 ton/1.q0q0Eq12 Btu, 8032 Land impact for the BOMq-Atmospheric.Combustordonsists of fixed land.impact of 5q00qA acres forequipment necessary for conversion of 1.qOqOE12 Btu/yr-The time- averaged land impact - 4.20E-01 acres (8031). 8033 The land impacts for the' power generation cycle consist of fixed land impacts only. From foot2pte .3902 land impact for a 3000 MW plant,,=150 acres. For a. 1000 MW plant this equals 50 acres.. Annual Btu throughput to operate a 1000 MW plant is as foll4qqwqfq@: Northern Appalachian Coal 1.06E14 Btu/yr Central Regional Coal 1.qOqOE14 Btu/yr. Northwest Coal 1.2q0E14 Btu/yr For a fixed land impact of So acres'this.yields an impact of: 0.482 acres/1.q0q0E12 Btu, 0.500 acres/l.qOqOE12 Btu, and 0. 418acres/l.qOqOE12 Btu respectively (8030). 8034 Particulate'emission from spray cooler yields q0'.211 lbs/6,83EqO3 Btu. For 1.qOqOE12 Btu of.prodquqct fed to boiler, 1.56E0*4 tons particulates1pre produced. Using an electrostatic precipitator of 97 percent efficiency.this yields 4.68EqO2 tons particulates (80q30)_ 8035 Land impacts.forthe BO20qM-Atmospheric combined cycle generating system is 1_26 acres/58.2 MW plant (8031). For 08qa.1000 MW plant it Iequals 21.7 acres. To run a 1000 MW power plant the following gas heating. composition must be fed to the turbines/yr: 111-23 FTN 8036-8041 N. Appalachian Coal 1.06E14 Btu/yr Central Regional Coal 2q1.q0q0E14 Btu/yr Northwest Coal 1.2q0El4,Btu/yr For a 1.qOqOE1q2Btu input the-land impact would be as follows: N. Appalachia. 2.05E-01 acres/1.q0q0E12 Btu Central Regional 2.1q7E-01 acres/1.q0q0E12 Btu Northwest 1.81E"01 acres/l-.qO-qOE12 Btu 8036 Based 2q6n calculations in (8030) SO' emissions from the 2 ammonia sulfate-,.plant are 0,00026 lb/lb coal. input. F4q6.0qr a 1.qOqOE12 Btu.coal:@inputLof 5.42EqO4 tons, qS02 emissions are 1.4-qIEq01 tons/,l-.qOqOE12 Btu (2qR030). 8037 Power transmission is based on 3.200 MW,capacity line with a load factor of 0.2q70 (8033',1-13). Capacity is 6.70E8q+13 4qB6qtu/yr. From (8033,I-q)right of way is 20.-q0 acqres/mileand transmission-distance is assumed at 1000 mile.. For,qOqO4qE8q+12'Btu input the land impact is 2 98E8q+02:acres. Transmission-diqtta0qnce.based on di8qst2q@nce-f8qv8qm.8qF0qour Corners.-to Chicago-. 8038 Power transmi .L-ssio4qnis b2q&sed-on 32.00 MW capacity line with a.lo2qdd factor of 0.70 'q(8033,,1-13). Capacity is 6.70E2q+13 Btu/yr. From (8)033,1-1) right of way6qi0qs 20.0 acres/ mile and tqransmi.ssion distance qis 450 miles. For 1.qOqOE12 Btu.input-.the land'impact is 1,35E2q+02 acres. Transmis,sion@distance--'based on distance from-Pittsburgh to Chicago. 8039 Ancillaryenergy for a 150.ton/hr plant requires 34,745 KWH4q/,H. For a liqOqOE12.Btu coal feed of 12,100 Btu/lb coal, this.-is equivalent to 3.276qE4q+10 8qBtu..(8010,19q).. 8040 Ancillary energy-for a 15q0 ton/hr plant-required 3q@,745 KWH/H. (8010,19). For.,ra.1.00 E12 Btu coal feed of 9226 Btu/Ib coal, this is equivalent to 4.128E8q+10 :Btu.. 8041 Ancillary energy.for.aq.150 ton/hr plant requires 34,745 KWH/H (8010q119). For a 1.6qO6qOE08q+12 Btu input of 13,80q.0 Btu/lb coal, this is .equivalent to 2.86E12q+10q,B24qtu. 111-24 FTN' 8042-8046 8042 Ancillary energy for a 150 ton/hr Plant is 34,415 4qkWH/H (8010,19). For a 1.qOqOE8q+12 Btu input of 12,100 Btu/lb coal, this is equivalent to 3.23E2q+10 Btu. 8043 Ancillary energy for a 150 ton/hqr plant is'34,415. KWH/H (8010,19). For a 1.006q88q+12 Btu input 4qof 13,800 Btu/lb coal, this 0qiqi equivalent to 2.83E4q+8q10 Btu.' 2p Ancillary energy for a'150 ton6q/hr plant is 34,415 4qKWH/H (8010,19). For a 1.qOqO2qE8q+12 Btu input of'9226 Btu/lb coal, this is equivalent to q4..22E8q+10 Btu. 8045 Land impact for ' an ATC Combustion process consists of land for thermal drying, combustors, desulfurizat0qion unit, limestone and slag storage. Coal.storage will be allocated to utility since combustor can be retrofitted (8015,45)'. Thermal drying is assumed to require 0.10 acres. 4.50 acres are required for combustor and desulfurization units (8025).Th4qd use of 11,503 Btu/lb coal requires 0.224 lb limestone/lb coal a0qnd produces 0.1101 lb slag/lb of coal of which 50 percent, is'sold. For a feed,of 4.908qE8q+04 tons coal this produces 1.10E8q+03 tons/yr limestone and 2.'698qE8q+03 tons oqf slag. Assuming limestone and slag have a density. of 0.083 t/cf and 0.060 t/cf respectively,-a refuse pile 30 feet-in height would occupy 1.34E-qOl Acres/yr.,. Time averaged over 25 years6qwould equal 2.94E-02 acre- years/1.q0q0E8q+12 Btu. Fixed land impact is 4.60 acres. On. 1.qOqOE8q+12 Btu basis =.5.330qE-02. Total land impact is 8.27E-02 acres-yr/1.q0q0E2q+12 Btu for yearly output of 8.67E2q+13 Btu/yr. 8046 Land impact for-an ATCCombustion proce ss utilizing Northern Appalachian coal at 12696 2qBtu/lb requires 4.50 acres for combustor4qs:,and desulfurization equipment.. Coal storage i 's applied.utility. Limestone and slag produced is 0.0262 lb coal input and 0.0899 lb coal input respectively (q80,29). q50 percent of the slag is sold. For a coal feed of 3.94E8q+04 ton/1.q0q0E+12 Btu, 1.034qE8q+03 ton of limestone and 3.54E8q+03 tons 0qof slag is produced. Assuming 30 ft high refuse pile and a q*density of.limesto08qne of 0.083 ton/cf and slag of.0.02q60 28qt68q/6qc2qf this 16qO04qC04qC00qU32qP4qI08qA04qS an area 4qc0q>f 1.06E12q+14- Btu/yr t2q1x36qis equals 1q.45Eq-02 acre-yr/1.2q02q0E08q+12 Btu. Fixed land impact for output of 1.06E08q+14 Btu/yr equals 4q.2424qE-02 acre-yr/ 1.2qO2qOE12q+12 Btu. Total 5.69Eq-02 acres-yr/1.6q06q0E12q+12 Btu. 111-25 FTN. 8047-8049. 8047 The efficiency of.the.ATC-Combutor-Conversion process utilizing.a Pittsburgh coal@having 1.2696.0 Btu/l2qb, 1.0 percent moisture and 1q31:85 percent ash', will be Btu g4qas out/Btu coal in. From (8029) 1.0 lb of coal will yield a gas of 9..34E8q+03 Btu..-For a 1.qOOE8q+12 Btu input, qj.94E+04 ton of coal,is input producing 7.3q6E2q+ll Btu of gas. Thus efficiency -_7.32q6E0q+11/1.0@1q0E8q+12 =@0-736 8048 The efficiency,of the-A4qTC-Combustor Conversion process includes the decrease,in effi0qc2pqrqi4qoy associated with the necessity of thermal.drying of the 10 050.0.Btu, 15.31 percentimoisture,ROM Illinois-No.1p2pal to a42pp7860;4356;84;136qOpercent moisture.coal -,(8022,23).From (80.0.613-3/q1.3-25) and the fact that it tak'es.1.41-".97E2q+04.ton/1.0q6E2q+12'2pu input, 6.70 E4q+02.2 ton' or_1.q3,percent of the,coal is-consumed in-drying. This leaves 4.3q5E8q+04 ton of 1132:.qO.Btu.coal going into the process. Then,it,is air dried to 1'.0perqcentmoisture prior-.to entering,'the.combustor,.or 4.22E4q+0,q4,-tonof 11503 Btu coal..Based.uponhis input to the,combustor and that 9.19E4q+03 Btu of.gas is produced/lb coal, efficiency= 0.799 0qx 0.986 = 0-0q788. 8049 Sources of, -air @,-e;missions for - the 4qAT8qC!"'2qCombustor. -process utiliziqn'g Central-coal-will.be,from.the@,co'al fired thermal@dryer-.and Claus.pl0qant. Pollutants inherent In the coq;q@2q@ust0qor fuel.gas.are-allocated-to--the@utiqlqity where they0qoccur. A-well,contro.q1-ledthermal,dryer will emit 0.54 lb,N8q0qX/ql.,q0q0E8q+0-6tu, 0@0q4qS.-qlb-qS6qO'/1.q0q0E8q+06 qx Btu, 0.58 lbhydrocarbon/l.qO.qOE6q+06,Btu and*0.39.lb CO/ 1.qOqOE8q+qOq@ Btu.From the@.coal usedin@2qfiri.0qng,.(1121), 6.7q0E8q+02 ton of coal will be consumed in drying (sele.footnote 80.48) or 1.35E8q+l2qQ Btu@.Thus@3.q6AE4q# '00 ton-, 3.0'qOE-01 on S4qOx, 3.92E4q+00 ton hydrocar8qbon'-,and 2.63E4q+02 ton'CO will be@emitted.Trom theClaus-pl6qAnt2qthe_only emission is qS4qoqx."From(molar HIS + S02@percentof 31,q0--percent of the input,,gas.and.(8012q),,.the C2qla2quqs1plant.8q6ff0qicienc2qy is 92.0 percent. From q1'80.29),@H2S = 2.67E-02 qlb/lb coal and S02 = 2@0q50E-02,lb/lb coal is input.:o6qf1paus. The output equals q;.0060.lb/lb coal on anqS4q02 basis.2por,.an input of 4,75+041. ton Of, coal, S4qOx =q12_8q6Eq.0q+q102. Total.,Sox 2.864qE8q+02 + 3.8q0q-4E-07 2.8,6E08q+028q2q,q-q-'q,S20q000qXq. III-26 FTN. 8050-8052 8050 Air emissions, other then particulate, for the ATC- Combustor, utilizing No. Appal. coal, occur from the Claus-plant.-The emission iqs S8qOqX. From molar H2S + S02 percent of.32.0 percent of the input gas and (80q12), the Claus plant efficiency is 92.0 percent. From (8029), H2S =3.97E-03 lb/ql0qb coal and02 = 3.q5q02qE-Q3 lb/lb coal is input to Claustgiving an output of 0.0009 lb SO8qZ equivale6qht/lb@coal. For an input-of 3.94EqO4 ton of coal/ 1.qOqOE12 Btu into the conversion process, SOX 3.94E8q+04 x 0.0009 = 3.55E8q+01 ton. 8051 Particulate emission sourceqsusing Central coal consist of the coal fired thermal dryer,ir blown dryer, limestone dryer-drusher and combustor. Afluidized bed-0qt8qf8qiermal dryer with a 99.0 percent efficient ve4qnturi scrubber will emit 2.0 lb particulate/ton coal feed (0002,8-1q6).*With an input of 4.97E8q+04.tQn of ROM-coal/ 1.qOqOE2q+12 Btu, particulate = 4.97E8q+01 ton, for the air blown dryer, for 4.35E8q+04 ton of coal fed into the sys6qtem.,(see footnote 8048), particulates = 4.35E2q+01 tons. Crushing and drying of limestone with a 99 percent efficient bag house and a throughput of 1.qOqOE8q+03 ton of limestone will emit 7.184qE2q+00 ton+and 4.35E2q+00,ton respectively (8002,8-14/8-15). The only particulateR from the combustor are metallics (80.22,15/107). This aqnqvq6unts to 1.82E-04 lb/SCF in the test combustor,, but will be reduced byt least 99 percent in the commerqdial size combustor or'l.82E-05 lb/SCF of gas (8029). Particulates. 7.15E8q+01x 1.82E-0q5 = 1.30E-03 lb/lb coal or for .22E2q+04 ton input to the.combustor particulate = 5.49E8q+ 01 ton. The particulate will be emitted at the utility and not considered part of the conversion process. Therefore 'total particulate from conversion = 42ppE8q+01 + 4:.35E8q+01 + 7.18E2q+00 + 4.35E2q+00 9.47E2q+01 ton. 8052 S02 emissions from the BOM combined cycle plant consist of t8qhe H2S contained in the gas from the 'spray coolers. This gas contains,@0.0012 lb H2S/6.83E4q+03 Btu output. For a feed-to theboiler.of 1.qOqOE8q+12 Btu, 1.76E4q+05 lbs or 5.16E4q+03 moles H2S are formed. Assuming complete combustionq,q'1.65E08q+02 tons S02/1q.2qO2qOE08q+12 Btu are formed (80q-16)-. 111-27 FTN. 8053-8055 8053 Sources.'of air emission from the Koppers.;-Totzek Conversi6qon'process, using*Central regional coal, are the coal fired.thermal dryer and the Claus plant. Another potential source of emission is from the coal pulverizing operation,2qbut all6qd4qtst is captured and sent to the gasifier (8023). From (8006,13-3/13q-25) and the fact that it,takes 4.97 E8q+04 ton of 1005q0-q0 Btu Central@coal/1.q0q0E2q+12 Btuinput, 4q7.06E6q+02 ton of coal.is consumed. The,'8qem4qf4qtqsiona-are 0.26q1b particulate/ton,coal feed (99.0 percent. efficient venturi scrubbing) (0.0.02, q8-10), 0.54 lb@NO..q@/6q1.00E4q+06 Btu:fired-(8035), 0.045 lb qS8qox/1.q0q0E8q+06 -Btu fired (80,35), 0_58 6qIb hydrocarbon/ 1.qOqOE2q+06 Btu fired (q8035q) and 0.39 lb'C4qO/1.qOqOE4q+06 Btu fired'qfor thermal dt6qk6qyi8qng. From the above,,emission-for the thermal drying = 4.:97E8q+00 ton particqulate,2q2.70E8q+02 ton NO Fqor every lb of:coal,combusted-iqrqi the combustor, b of H+q2S and qO..,006.qlb of",COS is2q4,ormed.4qOn a 0.052 l.-qOqOE2q+12.Btu basis,'this yields a total of-4'q5:72 tons H2S and COS On S02 basis (8034,14) . 90@. 0 percent oqf this SOq2q@-is-'removed:i4qnzthe Rectisol,unit.a-nd directed to the Claus @qpq@lant..'Of the, 4115 -tons input to- the Claus plant with Str6qdtfor6q&@4qiail 2qgas-c2qlqe4qanup, 99,@qO percent.- is removed. q'2 q'q0q0E8q+lq2'Btu.-total-S0qQ S02 = 41. 0qx .4 12E2q+01 + 3.20E-01 = 4.12-4qE2q+01-to6qn:-S4qO0qX0 8054 S02 emissions f4qor the Koppers-Totzek.Electrical Gene0qtation@process utilizing:Central coal occurs in the boiler:activity. As8qtumqingdomplete:*combustion of the H2Snd C4qOSq"entering the&,-'system l6qVpercent x 4572 457.2 tons of S02 is formed,and@:emitted.'See,footnote 8053 (8034,14q)-. 'The only sources- of,@particulates'for'the'ATC-Combustor processutiliqzing a Northern. Appalachiai0qbal are-the limestone crusher--dryer and@the Combustor. Crushing and drying;of limestone with a,q99.0,,p8qe0qxcent'efficient bag house and a'throughput of 1.03E8q+03,@ton-of limestone will emit 2.06E-01 t0qon.and 1.7q04qE-01-ton0qxespectively (0002,8-14/8-1q5). The*combusto8qk will-emit metallics, which in the commercial si,ze combUstor-,equals 1.82E-05' lb/SCFq:gas. 1.0 lbq,coalq, will produce 80 q''89 SCF of gas (8029). Particulate = 8036qA9 x 1-.82Eq-05 8q- 1.47Eq-03 2qlb/lb of coal or for 3.6q50E20q+04 ton coal input to the combustor, particulate = 57.4 lb. The metallic.particulate will be emitted at the utility and not be considered part of the conversion process. Particulate from conversion 3q.76E 01. Particulate from utility 5.74E-01 ton. III-26 FTN. 8056-8061 8056 SO@ emissions from the Koppers-Totzek process utilizing Northern Appalachian coal, at 12,696 Btu/lb, occur in the Claus-Stretford plant only. For every lb of coal combusted 0.0110 lb of-H2S and 0.0022 lb of COS are formed.. On a 1.OOE+12 Btu basis this yields a total of 911.6 tons H2S and COS on a' base S02 (8034,14). 90 percent is removed in a Rectisol unit and directed to a Claus-Stretford plant for further gas treating, up to 99 percent efficient. S02 = -90 x 911.6 tons x 0.01 ='8.21 tons S02/1.OOE+12 Btu. 8057 S02 emissions for Koppers-Totzek electric generation process occur in the combined cycle activity. Of the 10 percent total S02 equivalent emitted from the Rectisol unit,.100 percent is combusted in the boiler..Total S02 -emitted equals 91'.2 tons/1.00E+12 (8034,14). See footnote,80-56. 8058 Solid waste as ash generated in the Lurgi Conversion process is a-46X+03 ton based on a feed of 5.42E+04 ton.of 6.38 percent ash Northwest coal. All other output will be sold (8031). 8059 Land impact for the Lurgi Conversion process consists Of .,fixed.facilities and evaporation pond since ash will be shipped back to the mine (see footnote 8058). For a Lurgi plant having an input of 3.03E+13 Btu/yr of 12,927 Btu/lb Northwest coal, land impact is 50.4 acres. For a 1.OOE+12 Btuinput land impact is 1.66E+00 acres (8012,II-A-I). 8060 The efficiency of the Lurgi fuel gas process is 75.8. percent based on an input of,3.03E+13 Btu/yr and*an output of 2.30E+13 Btu/yr (8012,II-A-I). 8061 Ancillary energy demand for the Lurgi'Conversioh process consists of power requirements for fuel gas production, fuel gas cooling, and fuel gas treating., Total requirement for 3.03E+13 Btu/yr input .(see footnote 8060) is 9400 KWH/H. For a 1.OOE+12 Btu input total ancillary energy is 9.27E+09 Btu (8012, 111-29 FTN. 8062-8068 8062 -Ancillary energy demand consists of 2590 KWH/H for steam generation (8012,II-D-5)plus,power required for air compression. From '(8012,Area 23) 20.6 per- cent,of total plant energy-demand for air compression (5150 KWH/H) is.associated with the electric genera- tion process. Total ancillary ':energy is 3650 KWH/H. For an input of 2.30E4q+13 Btu/yr the power requirement is 1.09E+10 Btu/yr. For a l.'OOE+12 Btu input, total ancillary energy is4.74E8q+08 Btu.' 8063 Land impact for, the Kopper-Totzek Conversion process consists of land required for the combustors,clarifiers, sulfur removal plant,water cooling and coal drying..Ash is to be returned, to the.mine.For a 10.00 MW plant 11 acres are required--q(8,2q023).For a 10 '00-MW plant, a coal feed of 5.472qE8q+07 tons/yr is required,-considering a 74.4 percent-conversion.and 40,O.percent.generation efficiency us ,img-a,Northwest,coalqat 9.226-.-.Btu/l6qb. .For a q1.qOqO0qE4q+12--Btu input,land impact is 1,.,OqOE8q+12 Btu qx 11 acres/1.0,E8q+14 Btu/yr input.-= 1..064qE-01 acre-yr/ l-.qO-qOE2q+1q2 Btu q18023). 8064 Ef f iciency for the- Koppers.0qa.0q0tqzek Conversion process is 74. 4 p0qqrqqq@8q@qnt-. based on a.: coal input..rof, 92q226 Btu and gas output-of--6:q8q63.: Btu. (82qD+23). 6q&065 Efficiency'of@Kopp2qp.2qT@-s-Tot-zek Combined Cycle,Power Generation Activity is:. 4-0.0 percent based on calcuations from (8034,,10q). This assumes a 90 percent loadfactor and. the... sqy0qqtlem'from q(;8034,,10q). -8066 From (8034,10), and. as.qa6quming a .90-2qpercent load factor, it takes 8500 Btu input-to generatel...qOqO'4qKWH. Efficiency 3413/88q500 = 4.:0lE'-qOl* 8067 Efficiency for 0qthe Koppers-Totzqek Conversion process using Northern Appalachian coal.is 8,2 .O-percent for a coal input of 12,-696 Btu-andl".output of 10,407.Btu (8023). 068 Solids generated during the Koppers-Totzek process using, Northern Appalachian,.coal consist of 0.1372 l32qb as48qh/8qlb coal input (8023). For08qan input of 9.12E08q+13 Btu/ yr, 4.93E08q+05 tons of ash a00qre produced. Solid waste is 5q.41E04q+03 tons ash/lq.2qO4qOE04q+12 Btu input. 111q-30 FTN. 8069-8075 8069 Land impact for the Koppers-Totzek Conversion process for a 1000 MW plant is 10 acres. For a yearly input of 9.12E2q+13 Btu of coal and a . converion and generating efficiency.of 82 percent and 40 percent respectively, on a.q0q0E2q+1q2 Btu basis land impact is qJ.qJ'qOE-01 acre- years. Land required for ash storage.i0qs 3.86+00 acre for an input of 9.12E2q+13 Btu/yr of 12,696 Btu/lb coal. For an input of.1.q0q0E8q+12 Btu time averaged 25.years, land impact is 3.98E8q+0q6 acre-years/l.qOqO4qE8q+12 Btu (8023). This assumes a pile height o2p1p feet, ash ensity of O.02 tons/cf and that 0.1372 lb ash/lb coal is generated. See footnote 8068. 8070 Solid waste for the Koppek-Totzek Conversion process is 3.46E2q+04 ton/l..OOE2q+12,Btu*input based on a0qn input of 1.01E8q+14.Btu/yr. and. a coal heating value of .9226 Btu/lb coal. Ash generation is.0638 lb/lb coal input (8023qY . 8071 Solid waste for BOM-Pressurized conversion process is 3.46E4q+03 ton based on an ash content of 6.38 percent and coal feed of 6.50E8q+06 ton/yr and an input of 1.20E8q+14 Btu/yr (8016). On a 1.qOqOE8q+12 Btu basis this is 3.46E4q+0q3q@ tons.' 8072 For an input*of 1.20E8q+14 Btu to serve a 1000 8qMW plant 50.4 acres are.required. For 1.qOqO8qE8q+12 Btu inputba2qsis this is 4.17E-01 acres '(8012).solid waste will be returned to the inhence incremental land impact is zero. 8073 Solid waste-for the ATC Conversion process is qO.qOqOE8q+00 ton. All slag and iron can be sold (8029). 8075- The onlyair emission from th e Lurgi Conversion processis from the sulfur recovery process (8031,. 111-12-2). 94.0 percent of the@H2S in the combustor gas is re0qm0qovedby the contacters' of.the.Stretford process(8031, 111-22-1). The absorber then removes 994qA percent@of the H2S, the offgas from the absorber is f lared.q'Based on. a -combustor gas of 0. 0051 S/lb coal to the combustor.and a feed 36qof 5.42E12q+04 ton' of coal to'the combustor, sulfur released,equals 1.66 tons/1012 Btu input, or 3.32q'32 tons SO./2ql2qo0ql2 Btu. FTN. 8076-8082 8006 Air emissions from.generation.of electricity utilizing the-ATC,process::depends,on the gas composition beig-fired.@1.q0 lbf-N0qortheqrn Appaiachia,,coal will producea gas with the following composition (8029): 1.6533 lb,CO 0.050-q5 lb H2- 0.8559 lb 02 0.0128-1b C02 3.2045 lb N2 44.00 PPM H2S:q:- Upon combustion in a boiler:system fired-at 110,qOF-- 1200F:and,assumqa.ngearly complete combustion;j,,the,only pollutants emitted-are-as follows - 22.5-pp@--0qN4qOx(8025) and 22.0 ppm'qsox-q(8015,q29).-For a 1.q6q02qM2qBtu@'-,input.of gas.q(5.35EqO4,ton)@ the..emissions.-are 1.11E0q0q0-ton NO0qX and 1.08 ton SOX.. 8027 Land impact Is,1.21 acres,for-the 0qKQpp4qqr-Totzek conversion: process usqk0qn2q%,k@.a, Central-' coal. For: an input of .9 23E8q+13@ Btu and-ll acres,, fix4qe2q&,lan8qd impact is 1.096qi-qOql acres.q@--For a coal- feed of9.2.q3E8q+13 Btu/yrq* 1.1338E2q+04 Btu/lb = 4.07E8q+06 ton/yr, 7.78E8q+05 tons .of aqsh ar0qd produced..@.(8023). Based on.a '30 footle and:-8qan ash densqit6qy0qof 0.02 t/cf the.ash.,.all of which is stored,will require,,-12..qO,acre-y-0qr/l.qOqOE2q+12 Btu. Total land impact is 1.21E2q+0,q1- acres. 8027 For an'input of 9.23E8q+13 Btu/yr and 11,338-Btu/lb coaqlqi7.78E2q+05 tons-ash/yr is produced.,base d on an ash content of 19.1 percent-(8023q)..'For 1.qOqOE2q+12 Btu equivalent'feed, solid waste-is-8.43E2q+03-tons. 8079 Efficiency for the BOM-Pressurized conversion system. is.73.percent based,-on a coalinput of 12,050 Btu/lb and A gas output of 8796 Btu/lb'(8016). 8080q- Efficiency-of theq,q.B24qO20qMq-Pressurized conversion@process 92qJs 73.4 percent-based-on a coa60qlqfinput-of 13,800 Btu/lb and 28q& gas output.ofq@10,133 Btu/lb (8016). q- 8081 Efficiency of the.BOMq-pressurized conversion process is 73.3 percent based on an input of-9226 Btu/lb and a gas output of - Btu/lbq. (80q.16q,0q)q.q-. III-32 FTN. 8082-8087 8082 Air "emissions from generation of electricity utilizing the ATC process depends upon the gas composition.being fired. 1.0 l6qb of 1.0 percent moisture Central coal will produce'a gas with the following composition (80-q29): 1.4651 lb CO- . 0451 -lb H2 '0.0012 lb C02 2.8162 lb@ N2 0.7529 l6qb 02 44.00 PPM H2S Upon combustion in aboiler system fired,at 110qOF-120qOF and assuming nearly complete combustion, the emission will be as follows - 22.5 PPM NOqX (8025) and 22.0 PPM SOX (8015,29).For a 1qOqOE12 Btu input of gas.q(5.44EqO4 to8qn), the emissions are 1.12EqOqO ton N4qOx and 1.10 ton qS4qoqx. 8083 Efficiency for the BOM-ATM conversion process is 78.3. percent based on a coal input of 12,050 Btu/lb and gas and t8qar output of 9.441 Btu/lb (8016). 8084 Efficiency for..the BOM-ATM conversion process is.7 8.5 percent based on 0qA'c4qoal inpuut of 13,q800 Btu/lb and gas and tar output of'14q0,q932 Btu/lb (8016) 8085 Efficiency 6qof the BOM-ATM conversion process of q13.3 percent based on a coal input of 9226 Btu/lb and gas and. tar output of 6758 Btu/lb (8016). 8086 Ancillary energy for the ATC conversion process is 3.59E2q+09 Btu, based on 'a 2MW consumption for a 1000 MW plaint, and. a total process efficiency of'29 percent (8q029). For a 1.qOqOE8q+12 Btu input,ancillary energy is 3.59E4q+09 Btu. 8087 Dust loading on'the cleaned gas from the Koppers-Totzek process is approximately qP.0020 grains/SCF.(8024,7). 1.0 ton of Central.coal, North Appalachian coal or Northwestern coal will produce,q5'.95EqO4 SCF (8024,14), 6.64EqO4 SCF,- (8024,q,140q) and 4.38E2qO4 SCF (8023) of gas respectively. Based on the above particulate emission for electrical generation based on 1q.6qO6qOE12 Btu of gas input i00qs'08qas follows, in tons: Central Coal Northern Appalachian Northwest Coal 4.62E-01 5q'. 0324qE-01 4.56E-01 111-33 FTN. 8088-8092 8088 -Ancillary-energy-for theKopper-Totzek.conversion process is based-on 15MW for a1000 MW plant (8029). For the Central, Northern,Appalachia, and Northwest coals,-the total-procqess:efficiency is32 percent, 32.8 percent, and 29.8,percent Based on this the ancillary energy on a 1.00E+12 Btu basis is 4.81, 4.92, and 4,48E4q+09-Btu respectively. 8089 Ancillary energy'for the boiler generation cycle is 3.37E 09Btu based, footnote 8062. Energy.required for steam and power generation is 2590 KW (8-012,II-D-5) for an input of 2,30E8q+13 Btu. No air-compression is required. On al.06E8q+12+Btu basis.ancillary enercqjy is 3.37E8q+09 Btu. 8090 Potential.so6qu0qrce4qs of water effluent f2qr0qom-the._4qKop0qpers- Totzek process-0qare-boiler b2qlo0qWdown, raw:gas cooling system 4qandverfil2q1of clarifier. For a 1.6q4q08qE12 Btu input of coal 1.33E8q+06 gallon of boiler2qlowdownqwill be-'2qpr0q6duced.con 'taining+40.0 PPM'suspende'd solids, maximum of 3.0.0.'4qM8qG/4qL.'B8qOD,0qand 25.0 MG/L COD. This4qwate'r will be,cooled to.852p00F-_and routed-to-clarifier.' Water,from qrmqa0qw.gas cooling will followhe-same route. The clarifier will-.require an-8qadditqiio2qna'l 80.0 gal/ minute in mak6qeup..water because of evaporation losses in quenching of.ash from gasifier. The clarifier will contaqin.approximately 2q250 PPM of@total dissolved solids. From the clarifier,.the water will be filtered-, and treated, then rec2qyced-Effluent- 0.00. 8091 Capital cost-6f a.combined cycle gas-fi0qred.power plant -is 4.15E8q+07.dqoqlqlars for a 363-MW plant-(8020,16). Plant efficiency is 40 percent. With a fixed,charge rate of 10 percent, the.annualized capital cost qi's-1.53E4q+05 dollars/ 1.qq0E0q+12 Btu in. Assumes a.100 percent plant load factor. This cost does not include@-the cost of'.the equipment to produce the low Btu.fuel gas. 8092 Capital cost.for the ATC coal conversion process only associatedqwith a 1000 MW plant is 1.80E0q+07 dollars (8022). Based on a 1-00E04q+12 Btu.basis.and.plant efficiencies of 78q*.81 73.6, and 81.0 for the Central, Northern Appalachia, and Northwest coals theqrcapital cost are 4.70, 4.40, and 4.88E00q+04 dollars respectively, (annualizedq'with a 10 percent fixed cbarge-rate). -Assumes a 100 percent plant load factor. III-34 8093 Capital cdtt for the BOM-Atmospheiic process is 1.08E+07 dollars for a 150 ton/hour plant (8020). Based on a 1.OOE+12 Btu input (see footnotes 8042- 8044 for equivalent tons of coal) and 8760 hr/yr for the Central, Northetn Appalachia,.and Northwest coals, the capital cost are'3.43, 3.13, and 4.68E-@04 dollars respectively (annualized,with a 10 percent,fixed charge rate). 8094. Capital cost for the BOM-Pressurized conversion activity is 2.59EO7 dollars for a, 150 ton/hour plant (8026). Based on a 1.OOE+12 Btu input (,see,footnote 8039-8041 for equivalent tons of coal) and 8760 hr/yr for Central, North Appalachia, and Northwest coals, for capital costa are 8.23E04, 7.48EO4, and 1.12E+05 dollars respectively (annualized with a 10 perce.nt, fixed charge rate). 81095 Capital c 'ost for the Koppers-Totzek conversion process is 8.6E+07 dollars for a 1.40E11 Btu,out/day plant (8024). Based on a 1.00E12 Btu in basis, 365 d/yr,. and plant efficiencies of 81.1, 82.0, and 74.4 percent for Central, Northern Appalachia, and.Northwest coals the costs are 1.36, 1.36, and 1.25EO5 respectively (annualized with a 10 percent fixed charge rate). 8096 Capital cost for-the Lurgi conversion process only associated with a 333 M plant is 1.65E.07 dollars (8020,16). Based on a total plant efficiency of 30.3 percent'and on a 1.OOE12 Btu basisIthe capital cost is 5.02EO4 dollars (annualized with a 10 percent fixed I charge rate). Assumes a 100 percent plant load factor. 8097 Operating cost for the BOM-Pressurized,system is based on a cost of 4.3E+06 dollars/yr for-a 150 tofi/hr plant (8760 hr/yr) (80'10). For a 1.OOE12 Btu input and coal heating value of 12,050,'.13,800, and 9,226 Btu/lb for the Central, Northern Appalachia,.and Northwestern coal the annual operating costs are 1.35, 1.1.9, and 1.78EO5 dollars!respectively. Coal cost not included. 8098 Operating cost for the BOM-Atmospheric system is 1.85E+ 06 dollars/yr for a 150 ton/hour plant (8760 hr/yr) @. (8010). AS in footnote 8097 operating cost are 5.77, 5.05, and 7.58E04for the Central, North Appalachia, and- Northwest coals respectively. 111-35 FTN. 8099-8102 8099 operating cost,for the.urgi Fuel Gas Production system is based on 196qA,percent of the total plant-input (8012). For a feed for,gas production of 207'.8.tons/h4qo6qur (8760 hr/yr) of Northwestern coal, operating costs are 4.83EqO6 $/yr. On a 1.qOqOE12.B'tu input operating costs are 1.44EqO5 dollars. Coal cost not included. 8100 NO, 'emissions for a combined cycle will primarily come from the,,-gas fire& turbine.. From 430.28 10), a dry turbine system will amit 150 ppm (vol)@when fired at 2000F using,natural gas. From tests performed, low Btu gas.,will emit only 15 ppm 'q(vol) q0q3028 11). Based on-this, how1pqqh is.emitted depends.upon-the amount of flue gas produced. The amount of g6q4s produced,by process and coal.,type is,as follows - BOM Press. --Northwest 3.36E1q0 scf/1.00l,q2 Btu BOM Press. North. Appl. 1.06q410-scf/1.00+12 Btu BOMPress. Central 3.19E1q0 scf/l.qO2p12 Btu Koppers-Totzek.- Northwest 1.61E1q0 s0qcf/1.q0q0E12 Btu. Koppers-Totzek North. Appl. 2.274qE2ql0,-s.qcf/l.q0q0El.q2 Btu Koppers-Totzek Central.2'.179E2qIqO-qacqf8q/l.qOqOE12,Btu From the above,-the emissions are qasf0qoqlqlqoqws BOM Press. Northwest 3.24EO1ton BOM Press. -North Appl. 1.03EqO1".ton BOM Press. - Central 3.9AEq02q1ton K-Tl - Northwest 1.59-EqO1 ton K-T North. Appl. 1.96EqO1 ton K-T Central 2.37EqO1..ton 8101 Effluent from the Lurgi process will4qb8qe nill. All water will be recycled where applicable andhe rest will go to evaporation ponds (8031). 8102 Sources of air emission from the Koppers-Totzek conversion process, using Northwestern coal, are the,coal fired thermal dryer-and the Claus plant. In thermal.drying, 1.31EqO3 to0qn.is.consumed in'drying, see,footnote 8000. The.emissions are as follows 4qIs'ee footnote 8053): 5.42E2q02q0-q.ton particulate, 5.15 ton of 64qN24qO12qXq, 4.28E-01 ton of S28qOXq.j, 5.50q-ton of hydrocarbon, and 3q.71E8qO8qO ton of CO. III-36q36_ FTN..* 8103-8107 Air emission from the Claus plant depends upon the amount of sulfur in the gas,feed to the plant. 1.0 lb of Northwestern coal will produce 4..80E-02 lb of H Of this 90.0 percent is removed in the Rpctisol 2S- unit yielding a feed of 4.32E-02 lb*t.o the Claus. The Claus with Stretford tail gas clean up will v6nt 4.'32-04 ton Sox/ton of coal fed to gasifier-4-3,0E04 ton of coal/l. OE12 Btu is fed to ga.sifier.,' therefore Sox = 1.76EO1 ton. 8103 Assuming that a low temperature boiler is used, NOX 25,0 ppm (see footnote.8003). The BOM Atmospheric Pr@cess using, Central, Northern Appalachia, and 14orthwestern coal will produce 4-44 lb/,lb coal.. 4.96' lb/lb coal and 4.08 lb/lb respectively. These gases have a heating value of 8.97EO3 Btu,,8.96EO3'Btu, and 6.04EO3 Btu. Ihputing 1.00+12 Btu of..these,gases-to the boiler, will produce@Nox emissions as follows: Central Northern Appalachia Northwestern 5.69EOO ton 6.36EOO ton 7.76.EOO ton. 8104 Air pollutants for the National Average low Btu coal gasification activity are the arithmetic average of the process utilizing a Central, Northern Appalachia,,and-Northwest..coal. For calculations see individual process and footnote. 8105 Air pollutants from the electrical.generation activity. using low Btu fuel gas are the arithmetic average of the process utilizing a Central, Northern Appalachian, and Northwest coal. For calculations see individual regional coals. 8106 Land impact, for low Btu gasification and electrical generation is the arithemetic mean of'the individual processes utilizing Central, Northern Appalachian, and Northwest coal. For calculations see individual coal regions. 8107 Solid waste for coal gasification is the arithmetic mean of the individual processes utilizing uentral, Rorthern Appalachian, and Northwest,coals..For calculations see individual coal regions. 111-37 FTN 8108-8112, 8108 Ancillary energly.for the,-low, Btu gasification- processes is-the. arithemetic,mean: ofqf-.@ the-proce6qsses, utilizing Cent-ral,'Northern Appalachian and-Central coals. For calculations. see individual: regions 8109 Primary efficency@ for, the - lowp Btu gas if ication processes is, the arithemetic mean, of. the processes- utilizing'CentraLNorthern Appalachian, and Northwestern coal For calculations.see individual regions. 8110 cost, for. the,gasification and : electrical ...generation activities.the arithmetic mean.of,the..processes utilizing-Central Northern Appalachian,and Northwest coals.For calculations..,. see .;;individual regions..... B1ll -sox! emisions f rom the . -Koppers Totzek w e lectrical generation . process. utilizigi-Northwestern coal occurs- in the,boiler step. Assuming complete combustion of,_the H2S,-andCOS en0qterin6 the.system:@6q10 percent x -is -emitted-,-, See, 2.59E4q+02 =,2.@59E6q+01:@to0qns,',ofS8qO', 0qX'j footnote., 8053,,i*.. q8112. From.i,footnotes2'900q7,' and.,.3 9 0 5, the-,@totalq-2pnual i zed capital. cost-. for -a controlled:,gas@, f ire2q&,..,power- plant. is2.35EqO5'$/l,.qOE12,Btu-in,.-,This@.is,.for:a-.60P load. factor.. For,a..100P@.-.load..f6q&qCqrtor,:@;the.-,@@annualized capital. investment- is 1. 41EqO-6q5 .$/l.q0El22pppu-,-..in,,@ This-. cost does not,,include.the2ppst.oqf.the,,,,,,equipment .produce the lowt6qBtu fuel .gas III-;38 IV. HIGA BTU GASIFICATION OF COAL A. Introduction-. The enviro nmental impacts, efficiencies, and costs associated with the production of high Btu (greater than 9 900 Btu/SCF) synthetic natural gas from coal are given in Table 2 of this report. Each data entry is based on''an energy input of coal equivalent to 1012Btu/yr. 'The specific coal utilized and its energy equivalent is contained in the first footnote for-each of the regional and national'cases. All table entries have been derived for a-"controlled". environmen- tal condition. The nature and magnitude of coalgasification operations is such that stringent environmental control must be practiced. The six processes @;hichcomprise the@High Btu, Gasification Activity are: 1. Lurgi Process 2. Hygas-Electrothermal Process 3. Hygas-Steam Oxygen Process 4. Biga.s.Pr6cess 5. Syhthane Process 6. CO2 Acceptor.Process Also included is a Typical New Process which represents conceptually 'a combination ofthe best features of the new generation.#' processes.-- Hygas, Bigas, and Synthane'. The-C02 Acceptor Process was not included in this averagqrsince its process operation is quite different from the rest.. IImpacts were developed for three regional Icoals, with a National Average case synthesized from the regional data. The Lurgi Process is limited to weakly caking bituminous coals and was,,therefore,not considered in the Northern Appalachia region' where-many of the coals exhibit strong caking propertiesi The C02 Acceptor Process, on the other hand, operates primarily oil a lignite coal and was, therefore, only consideredin the Northwest region with a lignite feed. A principal advantage of the "'new generation" processes is their ability to handle the, range of coals from bituminous to lignite. All of the cost data. shown in Table 2 is based on a 90 percent plant load factor, or .328 operating days/yr. The values, presented in this table are, based on'data accumulated during the Fall of 1973. IV'l The following is a brief aescription.of the individual processes: Lurgi Process The Lurgi Process .(Figure 14) utilizes a high pressure (300,- 00 PSIG), fixed-bed, nonslaggingf steam-oxygen gasifier to produce a synthesis gas stream from coal,. The coal enters through a lock hopper.system-at the top 'of the gasifier, reacts with the steam and oxygen.as it moves downward on a revolving grate and leaves.as,ash for disposal through the ash lock hoppers. The synthesis gas stream leaves the gasifier at a temperture of 1100 F and is subsequently'cooled And scrubbed of tars and oils.., The gas stream composition is then adjusted in the shift conversion step, scrubbed of its acidic gases (4qC0qO* and H S), ana-methanated. The-Luqr8qgi Process 2 2 is'currently the only commercially available SNG.system. 2. Hygas-Electrothermal.Process The Hyga-s Process 4-Figure 15) features hydrogasi-ficat4qion' in two countercurrent stages for the,production of,synthesis gas2qfrom coal. The coal is pretreated (if-required), slurrdqed.with an aromatic oil and.pressurized PSIG).for introduction into the gasification reactor. As the-0qcoal enters the reactor, the slurry oil is qvapiqori,zed and.the coal falls thr.ough a low-temperature reaction zone where methane is produced primarily from the coal volatile matter. The devolatized coal then passes into the high-temperature zone where it is hydrogas ied by react-ion with hydrogen,and.steam-to form additional methane.. The emaining coal or char containing significant amounts of unreacted carbon is used to generate the hydrogen-rich gas required in the hydrogasificati8qon6qprocess. In the Electrothermal Process, the char.is react4ed with steam to produce this hydrogen-rich gas with,electric resistance heating supplying the energy.needed to,sustain the.reactions. The residual char is then used in plant boilersfor the production of steam and elecicity. The synthesis gas leaving the hyrogasifier is cooled, it ,compositionadjusted, and scrubbed free of acidic gases. The gas.is then methanated TheHygqasProcess.is currently to'produce pip4qeline*quality gas. the most advanced of the "new generation" processes with a successful pilot plant in operation since the end,of 1972. IV- 2 COAL LOC K HOPPER 'CRUDE GAS GAS SHIFT COOLING -------- 4WTAR 81 OILS CONVERSION STEAM RAW L' OAS GAS, H S TO RECOVERY METHANE 2 PURIFICATION STEAM GASIFIERS SYNTHESIS 14 @REFRIGERATI04--a-CO, TO V,ENT OXYGEN L----------------------i SH PRO(WT GAS LOCK- COMPRESSION m-SYNTHETI C PIPELINE GAS HOPPER DEHYDRATION 'ASH Figure 14. Lurgi Process of High Btu Coal Gasification (Ref. 8310) L @GASIFIE7RS RAW GAS' COAL STEA HYDROGASIFIER, RAW:GAS SHIFT CHAR- -QUENCH CONVER!s" INERT SiEft ELECTROGASIFIE- FINES GAS H2-RICH PRE- GAS TREATMENT WATER OIL TO. FUEL AIR CHAR- RESIDUE STABILIZATION STEAM -GAS ELECTRIC TO POWER POWER PLANT ;.CHAR Ab A _71 SLURRY METHANOL MAKEUP RECYCLED@'. METHANATION NH SCRUB a SYSTEM T@ R DRYING GLLA SCRUB RD BEDS _j -H NH3 TO COp IC PIPELINE H@S INERT GAS REbOVERY GAS "TO 7D.',PRE- TREATMENT RECOVERY Figure 15. Hy§as Electrotherm'al Process-of High Btu Coal.Gasification (Ref. 8308) '@IF I E @F@ r @W G @AS E @ELE PC M2 3. Hygas-Steam Oxygen Pro cess This process differs from the Hygas-Electrothermal Process only in the manner in which the hydrogen-rich gas is generated for the hydrogasifi.er section (see Figure 16). In the Steam Oxygen Process the char is fluidized in an oxygen- steam mixture and the heat required for the s team-char reaction is supplied by partial combustion of thd.char. The residual char is then used as boiler fuel. 4. Bigas Process The Bigas Process' (Figure 17) utilizes a two-stage, super- pressure (1000-1500 PSI), entrained bed, oxygen blown-gasifier for the gasification of coal. The coal is pulverized and fed into the top section of the @wo-stage gasifier where i It is contacted by a rising s team of hot synthesis gas,produced in the lower section. The coal is partially converted into a'gaseous mixture in this section and is entrained in the gas stream and removed from the.gasifier. The gas and char are separted and the char returned to the lower, stage 1, section ofthe gasifier. 'Here the char is completely gasified under slagging conditions with oxygen and steam to produce the synthesis gas stream for stage product gas is subsequently upgraded to pipeline quality gas. 5. Synthane Process In this process pretreatment of caking coals and gasifica- tion are accomplished in one reactor (see Figure 18). The coal is fed into the gasifier through lock hoppers and reacted with steam and oxygen under pressure (40-70 ATM) in a-two zone fluidized bed system. -A char residue is discharged from the,gasifier and subsequently used as boiler fuel. The synthesis gas is .adjusted, cleaned, arfd methanated to produce pipeline quality gas.. IV-5 RAW GAS COAL R4WGAS SH;IFT GASIFIER QUENCH CONVERSK)N INERT LINES -"GAS- PkE- 7r TREATMENT IATER EL )E 02 a OIL TO STEAM TO . -ATION STEAM ST LIZ HAR POIWER PLANT SLURRY -MAKEUP METHANOL -D, METHANATION -RECYCLE -SCR W-A N-H- U01,1TOIL SYSTEM SULFUR SC DRYING . 1. . RUB GUARD BEDS - H2S TO NH3 TO PIPELINE OAS -RECOVERY RECOVERY Figure 1@. kygas Steam-Oxygeh Process of Mh Btu 'Coal Gasification (Reif.,8308 '[MEtHtNi C AL CYCLONE RAW GAS SAND FILTERS COAL 'PREPARA- GAS TION SHIFT STEAM CONVERSION. REFUSE POWDERED COAL S COAL TO STAGE 2 CHAR GASIFICATION BOILERS ACID GAS COO REMOVAL 'HOT SYN- THESIS GAS SULFUR w-SULFUR R STEAM,, SULFUR-FREE STAGE I S GASIFICATION pp STEAM METHANATION a-PIPELINE DRYING GAS SLAG TO DISPOSAL \/@pco T7^ R_'2R Er Figure 17. Bigas Process of High Btu Coal Gasifi.cation (Ref. 8305) ACID GAS TC SULFUR REM0AL COAL CYCLONE ACID GAS SCFW8fR SHIFT ABSORBER/. STEAM GASIFIER - I- 1-11- -- @.@ CONVERILK. REGENERA. OXYGE DECANTER TAR STEAM STEAM. CHAR CHAR TO POWERPLANT 00 CHAR IRON PRODUCT GAS MFTHANATOR TOWER OXIDE Figure 18. Syntha'ne Process of High.Btu Coal Gasification (Ref. 8309) @ -U SRU@40'4 GAS 6. C'02 Acceptor Process The C02 Acceptor Process (Figure 19) operates only on lignite and subbituminous coals and employs a unique c@rculating system of-dolomite to provide process heat and synthesis gas cleanup. Dried lignite enters the devolatilizer togetherwith,calcined dolomite from the regenerator, steam,- and hydrogen-rich gas from the gasifier.' The' lignite is devolatilized and methane produced from the volatile matter. with,heat-of reaction supplied by the CaO + C02 reaction.. The raw gas stream leaving the devolatilizer is upgraded to SNG. The*lignite char is transferred to the,gasifier along with dolomite to complete the gasification operation. The remaining lignite char i*s thentransferred to the dolomite regenerator alidiused as,fuel for calcining the spent'dolomite from the devolat@lizer and gasifier. IV_9 GAS COOLING ---SYNTHETIC NATURAL GAS --a-WETHANATION -CLEANUP GAS TO RECYCLE COOLING S,VENT CLEANUP GAS' COOLING ___40 a -EANUP CL REGE NER A T H., 0 0- (=RUSHED1 OLO.- DRIED, M ITE- GASIFIER DEVOLA- HEATED P TILIZER L7G N A I SPENT WT SK SPENT CHAR DOLOMITE LIGNITE INERT. IN RT GAS CHAR@ GAS. STEAM a RECYCLE GAS STEAMS RECYCLE GAS Figure 19. CO Acceptor Process.of High,Btu Coal Gasification (Ref. 8321), 2 B. I;npact Data Table and Footnotes IV-11 JTh "i CONTROLLED 4 5 6 a 9 10 11 12 13 14 15 Is 17 18 19 20 21 22 23 24 25 26 27 26 29 30 F LIE L REGION COAL AS INDICATED WATER POLLUTANTS (TONS/ 10" STU, EX. COL.12) AIR POLLUTANTS (TONS/10"' BTU) OCCUIOATIONAL HEALTH POTENTIAL COST (DOLLARS/IOP STU) MNE - DISSOLVED SOLIDS SUSPENDED TOTAL THERMAL PARTIC- HYDRO- ALDEHYDES SOLIDS LAND LARGE, PRIMARY ANCILLARY R (TA mm ACTIVITY PROCESS ACIDS BASES NO, OTHER TOTAL(DS) SOLIDS ORO IANICS Cous S'?'8 SOD coo [STU/IdtBTQ ULATES NOX sox CARBONS CO ETC. TOTAL TONS/ (ACRE-YR DEATHS JINJURIES MAN-DAYS SCALE EFFICIENCY ENERGY FIXED ATING TOTAL ROW P04 O'&BTU \Iola BTU). '0. STU 70.-iTU LOST'@Io"OTU DISASTER (BTU/10,10m, COST COST COST NORTHERN APPALAC 1A 2GASHII CASIFICATION-HiGN BTu 2 3 -1.11 -P.-W PROCESS om -9 0999 Q. D0100 29427 9.610D 48- 7.62101 4$418 2. -01 4841. 1.16-0 4 6418 4.02-00 4 8418 3.99-ol 4 $418 1.11-02 4 C 1-1 .411 019 201 5.97-01 2 .417 0.0- 28417 1.7-1 1 1111 -.0 3 -6 2.62.05 3 3 4__L HYGAS-CTROTHER.AL -1 .1111 099 o", .19, -9 o999 -1 .11, Q999 0. -00 26427 1.401DI 48402 q.o.01 48402 2.33-GI 48402 1.27- 48402 4.61-GO 4 8402 3.94-01 4 84D7 1.34-D2 4 - -01 -- .4. -1 .99, 2091 S.72- 2 "DI 10.0- 28401 1.88105 3 .423 B.- 3 8423 2.1-5 3 4 5HyGsi HYCA5-ST-O@CEN -1 00 o9l' o- -1 -9 osq, o999 0999 0. O@00 28427 3-00 4$406 6.01101 $401 -3- 4-1 7,93-01 4eADs 2.92+00 1 8406. 3.63-01 8.IS+Gl 4 6.5- 2040712.5@-! !@2 .1.1 .11, 2091 5.07-01 2 8405 0. 00.002$405 1.59,05 3 8424 7.55-M 3 BQ412.35105 3 5 BIQ@S ..GAS o999 M, .19, -9 o'91 .99, .11, .11, 0999 0.0-D 28427 3.66100 4a414 5,44+01 48414 1. 7-1 18414 9.07-01 48414 3.02-OD 4 8414 T-0 . .414 rl -.1 --1 D6'o -1 099 2091 6.54-01 1 8413 0-00 28413 1-- 3 8422 1.15.05 3 1422 3 6 7 o999 -1 -1 .11, -9 .11. o999 0- 0.0010D 28427 1.5-1 4B41Q 9.9-1 48411 1.87+01 4841G 1.67-00 4800 --0 . 141. 4.30-DI 4 0410 1 I.Q.02 4 6. -03 2-1 2.461003 8412 .11, -9 2091 5.3-1 2 71 2-ol- ..- 2- 1. -S 2S 23- 9 CENTRAL 9 10 @SHI GASIFICATION-IUCH a- 10 I ILLRGI LLRGI o", ns.1 .19 o- -111 4.31-0 1 B471 9.00-01 5 847t 14.26-01 5 .471 4.44,01 5 -1 0- 1--, 4946. 3w63401 4 Bq68 1 4 12+00 48468 4.07-00 4 846. 4,48-0 .41. 1. 11- 5.27.03 28469 2.43.00 3 8470 L19-1 a999 -1 -1 5.41-0 28467 0.0@N2@67 1-05 3B4621 8.11.0 38462 2.1-S 1 12 __. -@L NEW MOCE55 -1 .9" ogg, -1 .199 3-- 5 8476 1.02-01 S $476 ..90-02 5 .476 3.18,01 5 ogg 0999 O.DD+00 28483 4G473 8,53+01 4.473 6.61+01 4 B473 I.-OD 4.473 4. -00 4 8473 CA-1 .- 1.1 ... 5-03 2847 4 2. 7 7100 3 $41, o9l' 099 -1 -1 ..2-1 .4Z2 Om D@002147; 1.9-5 3.481 9. 0- 1841, 2-ol 3 12 13A- HycAs_EuGTR.1.E- o999 .11 o999 __ Q911 o919 o999 .11, o991 -1 _9 0999 0. -00 28483 1.31+01 48452 9.93-01 49452 6.61-01 4 84S2 I. QO+O. -2 5.07,00 4 -2 4.28-01 48452 1.88+02 4 5.24+03 28453 2.62-00 3 8- .91 .11, 2D91 6.22-01 2$451 0. -028451 2.11+*5 38478 8.78+04 39478 2+9-S 3 13 - 14 14 yc@ HYCAS-STEAMwOXYGE1 o999 .919 -1 091 o999 0- o- - OwO@OD 18483 6AIHOD 48156 608!+01 49456 6.2- 4 8456 8 95-01 4B456 -5- 4 84S6 3,94-01 49456 1.4 .3+02 4 1.25.0 20457 12.75+00 3 M8 .11, -1 2091 6A7@01 28455 -0-002M5 13-5 3$479 -0- 3B479 2-105 3- 15 15 Bt@s .'GAS o999 -1 P991 -9 - G999 .199 -9 O+OMD 26483 4.-00 4$464 6.2-1 .00 --1 4-8464 1.00+0 48464 3.35+00 4 6464 4-01 48464 1.54- 4 5,34+03 2.45513,Q5@003 .11, M9 .91 2091 C7@01 26463 0. -0029463 2.04+Q5 39477 1.14+05 38477 3.1-5 3 16 -T. SYNTHANE M, -1 -9 o919 OM M, 0999 0999 D.0-Q 29483 1.47+01 414LC_ 1 11+02 4846D 51!9+01 48460 1 A1,00 146D 6.21-00 846. 4.65-01 ..40 -6102 531- 28461 2. 67+00 3 .4 2 .11 .119 2091 15.8- 284$9 G. -002-9 1.75+05 384.0 8+37- 3BUD 2-S 3 17 to I ..EST 19 -E', I T. 20 LuM -0. -00 28375 D-0 2 8375 0. 0-D 28375 @.0@0 14375- 0.00+00 7 8375 0-+0 28375' 0.00+00 283n 0. -0 28375 0.00+00 2_____ M- 28 3 LS GmD@00 @ 837S 0-0 28393 2.05.00 4837, 7,5901 4 9372 4.172 -11DO 49372 4.27+OD 4 9372 2+92-01 4a372 9-1.1 4 3.73.03 2$373 3. 78+0G 3 0374 0999 0999 am 2091 6,05-DI 2937 11 0+ @O28371 2.36105 30391 1. 0-S 3B391 3.3.+05 3 20 21 _PN@ TYPI CAL N EW PROC ESS -0+00 20385 0.00- .1.1 0-00 28355 0+00100 28365 OA-0 2 8385 0. -0 11345 -- 21385 D.0-0 28385 0-00 2 0.0o'00 28385 0. 00. 00 2 8385 0AG-00 28393 8,13,00 48382 8 + 54.61 4 8382 q-o 4 8382 1.41.00 4-2 4.71+00 4 B3 .2 3.27-01 48382 1.09+02 4 3.73+D3 28183 3. 95+003 8394 - - o999 o'99 -1 --1 2@LBI_ 0.0-0283.1 -1 + "+G5 38390 3.35-N 36390 2.4- 3 21 22 HYGEL HYC@-ELECTROTHERMAL -0+00 28355 0. -00 2 .355 0. 0-0 2$355 0. -0D 28355 Ow-00 2 8355 O@ -00 28355 OA-6 18355 D.00+Do 28355 U. 0-0 2 0-D-D 29355 0-00 7 B355 0AD- 3393 1-01 483S2 1,- 024s352 7.14- 1.17+00 4.352 5,56-00 4 63$2 3w4l-ol 4M2 1.2S-02 4 3.7140 28353 3. 541GO3 83S4 o999 G999 .919 2091 5w 70-01 28351 0 w -0028351 1.7-S 3-7 7. -0 383.7 2.4-S 3 22 23 myGsT yGAS_sT"'wG'N 0+00 29360 0-02 $360 0. -00-0 -0-2-8360 0.00+00 2R36D 0.00.00 2 .360 0. 0- 1 D.00+00 28366 -0.-0-0+G0 2 .360 0. -DD 28393 -11DO 4835L 6m33*01 43357 5m9D+OO 48357 1.15+00 48357 3.80+00 4 8357 3.13-01 48357 8.S2+Dl 4 13.73-03 2835B 3. 75- 3 $351 .119 M 2091 S.8-1 28356 0-6 18356 1.43-OS 3M8 S. 96- 3a3BB 2.03'oS 23 2 4.-s BI-s G@00- 2$370 D.00+QO 7 9370 0.0-1 2 .370 -0- 2&376 0..- 2 8370 1 O@ -00 28370 0. -00 2837G 0. -00 2637D 0.00-00 2 -0+0 24370 -0,00 2 6370 0.00+00 2$393 3.4-0 4!367 5483+Q! 48367 1d41+01 4l367 --' 4-7 1- .... 4 -7 3.01-01 48367 -1- 4 3.-03 2S35S 4. 54, @O o999 .9.1 -1 2091 6 82-01 28366 0. - 20166 'w-ol 1 2.1-1 1 24 25SYNTH _SYNTHANE 0.00+00 23355 D.0-0 2 8365 D.00- @ -1 0.0- 4311 0.0-0 2 8- D-101 28365@ 0. 0-0 2.31S --@ 2.- ....0 1 -0- 28365 0.0-0 2 8365 0.-!@ 1.391 13-1 48362 4.362 9.63-0 1111 1 491+00 48362 6.37+OD 4 8362 3-01 4.362 -6-02 4 I.-W .3. 3-96+00 1 I'll .99 2- 1-0 M11 --0 28361 1.6-5 383.9 -1- 3-1 -1.0 1 25 PS c-.ci CO, ACCEPTOR -0+60 283BG 0.00.00 2 8380 0.00+GO 2 $38D 0.00+00 28380 0.0-0 2 9330 0. -00 21380 0-,00-00-2 "$G- G,00+QQ 283.0 0.00+00 2 ...... 0 838G 0.0-0 2 8- 2U0 3.3 -0 48377 3181+01 49377 -7+01 1177 .377 1m98+00 4 B377 437@01 48377 im0fi+02 4 C61+03 28378 3. 16+Do 3B319 .11. o999 2051 16.2 5-01 28376 0. -002.376 1.4-S 113W 1. IS+. 3 26 27 ? 28 NATIQNAL AVERAGE 29 CASHI GAS IFICATION -HIGH BTU 29 30 LLAGI LUR.' o"g o9s9i 0999 -1 -191 .--1 1 -1 --1 1 .111 111 1 2.2-1 5 .199 0999 0.0-0 28312 2..S+OG 4-8 7.51+01 4830a 2.12- .10 1.211.0 8308 4,17+00 4 0.1 3.7-1 4 -8 1.05+02 4 445D+G3 2IM 3 11-003 -0 o999 099 aggg 2091 5.73-01 2 83o L7 O@ -0 2230 2.13+OS 33305 9.1- 383Q5 3. Q- 1 3 0 3 1T,P@ -CAL NEW -ss 0- -1 2. -'j I.A.- 5- 2-0 -1- -0 1.2-1 6330 -1.1 .3. 1.- 1- ..410 $31, 3wo-1 . 'M 112@@ 3. 2- 2.331 3, 3 1 + DD 3B332 #199 -1 I'll .1- 21319 177-05 1U. 3 1 3 2HYCEL HyGAS_EUCTROTHER@L 0999 o999 4999 -1 -1 o999 o999 o", .11. D999 0.0-0 28312 1.17+01 q8314 -6+01 q9314 3*25+01 48314 1-00 48314 5.06-00 4 8314 3+81-DI 4.314 1-@ 4 5.14+03 2031S 2. 86+DO 3 8316 .1.1 1 0 1 5.8-1 2 2313 0. -0Q28313 1-5 3a301 8.11+N 3$301 2.71- 1 3 2 3 3NGsl S-5-YCEN M9 o999 M9 0999 0. -00 283T2 5.2-0 49318 6a55+01 49318 2+97+01 44318 9.43-01 48319 3.36+00 4 .313 -7- 4 -1 1-- -6.03 28319 3. 01+OD 3 1310 M9 .119 -1 2091 6.0-01 2 0317 @. -1. 1.117 1.1-5 3R302 7 .1 @ 3B1. 1.3-1 33 3 4 MAS o", 0111 D119 091 -1 0- -1 0- .11, 0999 0999 0. -00 28312 3.1'4100 48311 1w.4+01 48322 3.77+Gl 4aL331 .11, 019 2091 -D-01 2 1321 0 w -00 2.321 1.89-05 39300 1.12+05 3B3 @ 3.01,05 3 3 4 "As A-1 48322 3.16+00 4 8322 3.78-01 4 8322 L-02 1 Sb2G+O3 21321 3t524003 9324 -9 3 5- syNTHANE G999 099 019 M9 09" 09s9 M, -1 -1 -0- 28312 1.44+01 48326 1j094Q2 48326 2m67+Dl 48326 48126 16+04+00 % 8326 4.16-01 4 8326 1 I.-D2 5 24.03 28327 3. 03+DO 3 8328 .11, .119 M9 _201 S-01 2 -5 *-00 28325 1.66+05 38303 831.0 3$303 2. -5 3 5 36 c_c@ C02 ACCEPTOR -o-oo 2 $338 0. -0 2 .338 G.00+DD 2 0338 G.-OG 2 4339 10.0-0 2 8338 0-00 2 8338 10.00+00 2 8338 0.00+00 2 8338 .0.00-00 2 0.0-0 2 .338 1 0.0- .33. --0 2.312 .31+00 4-5 -1- 49335 16.1-1 4.13S 42"S L98+00 Q 933S -7-01 4 6335 1.06+02 4 8.61+0 2a336 3-16+oo3 $337 o999 o999 .1191 2091 6.25-01 2 8334 Dw -00 28334 1.48- 1-- 3U -1o, 1 361 37 3 2 39 40 41 41 4 2 42 4 5 4 3 44 44 4 5 4S 46 46 47 47 48 4 9 49 5 0 Sol 5 1 5 2 5 3 54 85 TABLE 2. ENVIRONMENTAL IMPACTS, EFFICIENCY AND COST FOR ENVIRONMENTALLY CONTROLLED NATIONAL AND REGIONAL HIGH BTU COAL GASIFICATION I V 13 K 114" 13-0 013 3 @4 5 .G 3. FTN. 2091-8308 FOOTNOTES-FOR TABLE 2 209.1 Fire and/or explosions caused by gas leaks', oil leaks, act of God, or human error. Possible damage to refinery, personnel, adjacent properties. 8300 Capital and operating costs for this process are the arithmetic average of the capital and operating costs for the Northern Appalachia, Central, and Northwest regions. -8301 Capital and operating costs for this process are the arithmetic average of@the capital and operating costs for the Northern,Appalachia, Central, and Northwest regions. 8302. Capi tal and operating costs for this process are the arithmetic average of the capital and operating costs for the Northern Appalachia, Central, and Northwest regions.. 8303 Capital and operating costs for this process are-the arithmetic average of the capital and operating costs for the Northern'Appalachia, Central, and Northwest regions. 9304 Capital and operating costs for this process are the arithmetic average of the National Average capital and operating costs for the Hygas-Electrothermal, Hygas-Steam Oxygen,.Bigas, and Synthane processes. 8305 Capital and operating costs for this process are the arithmetic average of the capital.and operating costs for the.Central and Northwest regions- 8306 Capital and operating costs for this process are idsiatical to the capital and operating cos,ts.for the, Northwest region. 8307 The primary-efficiency-And ancillary energy for this pro'cess are the'arithmetic average of.the primary efficiency and ancillary energy forthe Central and Northwest regions.. 8308 Air pollutants for this process are the arithmetic average of the air pollutants for the Central and Northwest regions.. IV-15 FTN. 8309-8319 8309 Solid waste for this process,tis the arthmetic average of the solid waste produced in the Central and ,Northwest regions 8310 Land utilized by this process is-the qarithm etic average .,of the land used'in the;Central and Northwest regions. 8311 Water pollutants for this process are the arithmetic average of the water pollutants,for the Central and Northwest regions'. 8312, Thermal discharges canbe complete1y eliminated by the use. of mechanical draft-, wet cooling- towers. 8313' The primary,efficiency and ancilary energy qfqor. this process-. are, the arithmetic average of the- primary ef f iciency, and, ancillary energy for., .the 'Nothern Appalachian Central, and Northwest-regions- 8314 Air- -pollutants for. this .,process are the- arithmetic average of the.,air pollutants..for the, Northern Appalachian-. Central and Northewest regions-. 8315 Solid waste-for.this:process is-the,arithmetic average of the solid, waste, produced in the, Northern Appalachia,. Central-, and; Northwest regions:. 8316 Land utilized by this process is the prithmqetic average of the land.used in the Northern Appalachia, Central, and Northwest regi 8317 The primar y efficiency and ancillary.-,qenergy for this.. s are the, arithmetic average of the primary proces efficiency and ancillary enerqy of .the Northern .Appalachia,, Central, and Northwest reigions. Air pollutants for this process are the arthmetic average of the air-pollutanqts.for the.Northern Appalachia, Central, and,Northwest regions. 8319 Solid waste for this. -process ..is the -,-arithmetic average of the solid waste prodduced.-in the Northern Appalachia, Central, and Northwest regions. IV-16 FTN.,8320-8329 8320 Land utilized by this process is.the arithmetic average of the land used in the Northern Appalachia, Centrall and Northwest regions., 83.21. The primary efficiency and ancilla--y-energy for this process are the arithmetic average of the@primary efficiency and ancillary energy for the Northern Appalachia,.Central, and NorthwiEistre'gions., is proces 83,22 Air pollutants for thi s are the-arithmetic average of the air pollutants.for the Northern 'Appalachia, Central, and Northwest-regions. 8323 Solid waste for this process is the arithmetic average of the solid.waste produced in the Northern Appalachia, Central, and Northwest regions. 8324 Land utilized b- y.,this process is the arithmetic average of the land used in the Northern Appalachia, Central, and Northwest regions. 8325 The'primary efficiency and ancillary energy for this process Are the arithmetic average ofthe primary efficiency and,ancillary'energy for the Northern Appalachia, Central, And Northwest regions. 8326. Air pollutants for this process are the arithmetic average of the air pollutants for the Northern Appalachia,-Central,.and Northwest regions. 8327 Solid waste for this process is the Arithmetic average of the solid waste produced in the Northern Appalachia, Central, and Northwest regions.,. 8329 Land utilized by this process is.the arithmetic average of the land,used in the Northern Appalachia, Central, and Northwest regions. -8329 Primary efficiencyand ancillary energy for,this process are the arithmetic average of the National Average primary efficiencies and ancillary:energies for the Hygas-Electrothermal,.Hygas-Steam Oxygen., Bigas, and Synthane processes. IV-17 FTN. 8330-8350 8330 Air pollutants for this.process are the arithmetic .average of,the National Average air pollutants for the Hygas-Electrothermal, HygAs-Steami4qO0qxygen, Bigas, and Synthane processes. 8331 Solid waste for this process is. the arithmetic average of the'solid wastes produced in the National Average case for the Hygas-Electrothermal, HygasSteam Oxygen, Bigas, and Synthane processes. 8332 Land uitilized by this proqress is the aritmetic,average of the land used in the National Averaqe case,by the Hygas-Electrothermal, Hygas -,Steam., Oxygen., Bqi8qgas,., and Synthane processes. 8333 Water allU4qt6qa0qn8qts for-this process..are-the athmetic average of the water pollutants for the Typical New Process in the Northern,Appalachia, Centraland Northwest regions. 8334 The primary:efficiency and.ancillary.energy.for thi s- process.are thesame -as those for' the Northwest region. 8335 Air pollutants,or this, process,are -the same-as those for the Northwes region. Solid waste for-this procqess-is the sameas-that for .the Northwest region. 8337 Land utilized by this -process is- the same_as that used in the Northwest region. 8338 Water pollutants or this process. - are the: same as those for the Northwest region. 8350 The Northwest coal used in; this qanal2qy0qs0qlks, has the following composition ona run-of mine_baqs is: Proximate Analysis-Wt.Pc..Ultimate-Anallys qis-Wt. Pc. Ash 6.0 4qC 5'2q.q.q8 H20 22q'. 0 H2q. q..3.6 Vol.Mat. 29.4 q!Nq'2 0.7 Fixed C. 42.6 02q. 14,4 8qS 0.5 Btu/lb 8806 Ash 6.0 sulfur H20 q.22q,..6q0 For this coal 57000q-24qton is equivalentqrto:lq.q'q.2qGEl2 Btu. IV-18- FTN. 8351-8352 8351 From (8300 and footnote 8350) for 253.3EO9 Btu/D SNG, coal costs, based on $.15/1.DE06.Btu coal, are $.263/1.OE06 Btu gas. Thus 444.1E09 Btu coal/D is required,to produce 253.3EO9. Btu gas/D. The primary efficiency, taken as Btu of gas output/Btu of coal input, is therefore .'570. From (8300)p this-size S14G plant also produces 4.84EO4 GPD of light oils (primarily B-T-X) and 2.34E10 Btu/D of tars. If these fuels are considered, then the overall plant effici-ency becomes .635. The ancillary energy is zero because the plant is self-sustaining with all power and steam.requirements generated on-site.. 8352 The principal quantifiable air pollutant sources are as follows: TPD .:.Part.', SO CO HC NOX Other Fuels'Combustion 4.158 :2.16 2.4.6..738 44.3 .01123 Sulfur Recovery Plant .0.80 Storage and Misc. .001 .139 Fuels Combustion ' Based on plant heat requirements similar to that in (8.300), and the use of coal to supply the'same proportionate share of. this heat demand plus that due to the waste offgases from coal pretreatment (since pretreatment of western non-caking coals is not required), 1938 TPD of coal (6.0 percent ash,,.51 percent S) are usedfor@fuel, with the balance, 84EO9 Btu/D, supplied by the@cpmbustion of gasifier char (30.3 percent ash,-.5 percent S), These heating rates were converted to equivalent TPD of bituminous coal and used..with (8301,1.1-3) to determine TPD of air emissions. Particulates were reduced 99.5 percent by the use of an electrostatic precipitator-and a Wellman Lord wet scrub while S02 emissions werexeduced 95 percent by the %bllman Lord unit., T FTN. 8352.(Cont) Sulfur Recovery'Plan't Based on the use of the Rectisol acid'gas removal system for the selective removal of H2S and C02 from the synthesis gas stream, a concentrated (25 percent) H2S gas stream can be sent to the ClaUa plant for recovery.From (2022,103) a three stage Claus plant operating on a 25 percent H2S feed can recover 94 percent of the incoming S as elemental S. The incoming S for recovery is based on 23j279 TPD. coal to the gasifier (footnote 8351, less the above 1938 TPD coal as -fuel),..51 percent S in the coal, and 80. percent of the S to the gasifier as H2S to Claus for recovery (the balance of the S is in th -e char). Based, furthermore, on complet 'e-recycle to the Claus plant of all the S02-recovered in the Wellman Lord scrubbing units on the boiler flue gases and Claus tailgases, 124.5 TPD S is the Claus feed. Thus 117.0 TPD of S are recover- ed or 264 ton S/1.OE12 Btu. 7.5 TPD of S passes to the Wellman Lord tallgas scrubbing unit, so that A TPD S or 0,.8 TPD S02 passes out to the atmosphere from the, Claus and tailgas treatment system. storage and Misc. From (8300)-4.84EO4 GPD of light oils (B-T-X) are produced. Assuming two weeks storage capacity under new tank@conditions and:emission factors from (8302,, 4.3-8)'..001 TPD.HC are emitted. Based on '23,2792T-PD coal to the gasifier .007 ton N2/ton coal, and 70 percent of the N2 in the feed coal as N113 (8303,X-7), 139 TPD of NH3 are produced in the gasifier. All.of the Nk3 is washed from the gas synthesis stream and appears .in the waste water. This waste water stream passes to an @ammonia still with both a free and a fixed leg so that essentially all of the NH3 isirecovered for sale. From (8301,5.2-2) controlled storage-and loading operations emit two lb of NH3/ton NH3. Thus @139 TPD NH3 are released to the atmosphere. I V2 0 FTN. 8353-8355 It should be noted that other sources of air pollution will be present.in any commercial coal gasification operation, although their quantification is not possible at present. These sour&es include,but are not limited to, coal and other solids preparation and and transfer operations, ventstacks for waste gas disposal, pipeline valves and flanges, and pump and compressor seals. The magnitude of these air pollutants# however, should not be that large if the sources are properly controlled. 8353 Based on 25,217 TPD coal with 6.0 percent ash, 1513 TPD ash are produced. Since 4.6*TPD is,released to the atmosphere as.particulate, 1508.4 TPD remains as solid waste for.disposal. Based on 5500 GPM net makeup,H20 (8300) -and an assumed 500 PPM suspended solids which is completely removed by lime treatment and clarification, an additional 16.5 TPD of solid waste is generated. From (8304) an ammonia ,still is estimated t6 produce 115 ton/D of still waste..It is assumed that all bio-treating sludges are used as boiler fuel. The sum total solid waste produced is- thus 1639.4 TPD (or 3705 ton/l.OE12 Btu). 8354 Land 'requirements are 'assumed to be 350 acres from' (9401,7)- for coal storage, preparation, and gasification plant facilities, and-an additional 165 acres for evaporation -to handle the following TDS streams - H20 ponds (8306). softener and demineralizer blowdowns, boiler and cooling tower-blowdowns, and H20 from ash quenching and.trans- fer operations which might contain le'achates. Since High Btu Coal Gasification is assumed to be a mine- mouth -activity, all solid waste produced is returned to the mine for burial. There is, therefore, no incre- mental land impact due to.solid waste production. Thus'a total of 515 acres is required for a 25,217. TPD coal gasification operation. With a 90 percent operating factor this is equivalent to 3.'54 acre-yr/ 1.OE12 Btu4 However, a larger land impact would be produced if solid wastes were not returned to the mine for burial. (See footnote 8353 for solid waste). 8355 Water pollutants are zero because there is no aqueous discharge from the boundaries of the plant operation. All process waste water and impounded runoff is treated and used for cooling tower makeup, while all blowdown streams are collected and sent to lined evaporative ponds for disposal. IV-21 FTii. 8356-8357 8356 From (8300)and fobtnote 8350F for 247..2EO9 Btu/D SNG, coalcost, based on $ '.15/1.OE06 Btu.coal, is $.255/ l.0E06 Btu gas. Thus 420.2EO9 Btu coa-l/D is required to produce 247.2EO9 Btu gas/D. The primary-efficiency, taken as Btu of gas output/Btu of coal input, is therefore .588. From (8300') this size SNG plant also produces 4.56EO4 GPD of light oils (primarily B-T-X) and 2.30E10 Btu/D of tars. If these fuels are considered, then the overall plant efficiency becomes .655. The ancillary energy is zero because the plant is self-sustaining with all power and steam require- ments generated on-site. 8357 The principal quantifiable air pollutant sourpes are as follows: TPD Part. Sox CO HC NOX Other Fuels Combustion 2.319 1.87 1.59 .480 28.6 .00797' Sulfur Recovery Plant 0.60 Storage and Misc. .001 ..123 Fuels Combustion Based on plant heat requirements similar to that in (8300), and the use of coal to supply @the same proportionate share of this heat demand plus that due to the waste offgases from coal pretreatment (since pretreatment of western non-caking coals is not required), 3157 TPD of,coal (6.0 percent ash, .51 percent S) are used for fuel, with the balanc,.e, 20.9EO9 Btu/D, supplied by the combustion of gasifier char (52.6 percent ash, .9 percent S). These heating rates were converted to equivalent TPD of bituminous coal and. used with (8301,1.1-3) to determine TPD of air emissions. Particulates were reduced 99.5 percent by the use of an electrostatic precipitator and a Wellman Lord wet scrub, while SO emissions were reduced 95 percent by the Wellman Zord unit6 IV-22 FTN...8357 (Cont) Sulfur Recovery Plant Based on the use of the Rectisol acid gas removal system for the selective removal of H2S and C'02 from the synthesis gas stream, a concentrated (25 percent) H2S gas stream can.be sent to@the Claus plant for recovery. From (2022,103) a three stage Claus plant operating on,a 25 percent H2S feed can recover 94 percent of the incoming S as elemental S. The incoming S, for recovery is based on 20,704 TPD coal to the gasifier (footnote 8356, less the above' 3157 TPD coal as fuel), .51 percent S in the coal,, and 80 percent of the Sto the gasifier as H2S to Claus for recovery (the balance of the S is in the char).-Based, furthermore, on complete recycle to theClaus plant of all the S02 recovered in -the Wellman Lord scrubbing units on'th6 boiler flue gases and Claus 5 tailgases, .109-O.TPD S is the Claus feed. Thus 102. TPD of S are recovered or 245 ton-S/I.OE12 Btu. 6.5 TPD S passes to the Wellman Lord tailgas scrubbing unit, so that .3 TPD S or.0.6 TPD SOj passes out to the atmosphere from the Claus,and tailgas treatment system. Storage and Misc. From (8300.) 4..56EO4 GPD of light oils (B-T-X) are produced. Assuming 2 weeks storage capacity under new tank conditions and emission 'factors from,(8302,4.3-8), .001 TPD HC are emitted. Based on 20,704 TPD coal to "fier .007 ton N the gasi F 2/ton,coal, and.70'percent of the 112 in the feed coal as NH3 (8303,X-7),.123 TPD of NHj are produced in the gasifier. All of the NH3 is washed from the-gas synthesis stream and appears in the waste water. This waste water stream passes to an ammonia still with both a free and a fixed leg so that substantially all of the NH is recovered,for sale. From,(8301,5..2-2). controllea storage and loading op erations emit 2 Ib of NH3/ton NH3. Thus .123 TPD NH3 are released to the atmosphere. IV-23 PTN. 8359-8360@ It should be noted that other sources of air pollution will be present in any commercial coal gasification operation, although their quantification is not possible at present. These sources include, but are not limited to, coal and other solids preparation and transfer operations, vent stacks for.waste gas disposal, pipeline valves and flanges, and pump and compressor seals. The magnitude of thes-e air pollutants, however, shouldnot be that large if the sources are properly controlled. 8358 Based on 23,861 TPD coal with 6.0 percent ash, 1431.7 TPD ash are produced. Since 2.4 TPD is released to the atmosphere as particulate, 1429.3 TPD remains as solid waste for disposal. Based on 5300 GPM net makeup H 0 18300) and a w@ n assumed 500 PPM suspended solids ich 'is completely removed by lime treatment-and clarification, an additional 18.9 TPD of solid waste is generated. From (8304) an ammonia still is estimated to produce 115 ton/D of still waste. It is assumed that all bio-treating sludges are used as boiler fuel'. The sum total solid waste produced is thus 155j.7 TPD or 3725,ton/l.OE12 Btu. 8359 Land requirements are assumed to be 35.0 acres from (9401,7) for coal storage, preparation, and gasification plant facilities, and an additional 165 acres for evapora- tion ponds.(8306) to-handle the following TDS streams H20 softener and demineralizer blowdowns, boiler and cooling tower blowdowns, and H20 from ash quenching and transfer operation which might contain leachates. Since High,Btu Coal Gasification is assumed to be a mine-mouth activity, all solid waste produced is returned to the mine for burial.' There,is,'therefore, no in- cremental land impact due to solid waste production. Thus a total of 515 acres is required for a 23,861 TPD coal gasification operation. With a 90 percent operating factor this is equivalent to 3.75 acre-yr/ 1.OE12 Btu. However, a larger land impact would be produced if solid wastes were not returned to the mine for burial. (See footnote 8358 for solid waste.) 8360 Water pollutants are zero because there is no aqueous discharge from the boundaries of the plant operation. All process waste water and impounded runoff is treated and used for cooling tower makeup, while all blowdown streams are collected and sent to lined evaporative ponds for dispoaal. IV-24 FTN. 8361-8362 8361 From (8300 and footnote 8350) for 231.8EO9 Btu/D SNG, coal cost, based on $.15/1.OE06 Btu/coal, is, $.257/1.OE06 Btu.gas. Thus,397.2E09 Btu coal/D is required to produce 231.8EO9 Btu gas/D'. The primary efficiency, taken as Btu of gas output/Btu of'coal input, is therefore .584. From (8300) ' this size SNG plant also produces 8.5ED9 Btu/D of heavy oils, and from (8307,6) 25,000,GPD of B-T-X can;be expected. If these fuels are considered, then the overall plant efficiency becomes .612. The ancillary energy .is iero because the plant is self-sustaining, with all power and steam requirements generatdd on,,site. 8362 The.principal quantifiable Air pollutant,sources are as. f ollows @TPD Part. SOX CO HC NUx Other Fuels Combustion 5.15 1.61 @2.52 .757 45.4 .0127 Sulfur'Recovery Plant 2.20 Storage and Misc. .1@27 Fuels Combustion Based on plant heat requirements similar to that in (8300), and the use of coal to supply the same proportionate-share of this heat demand, 1170 TPD of coal (6.0 percent ashf .51 percent S) are used for fuel, with the balance, lOOE09 Btu/D, supplied'by the combustion of gasifier char (29.5 percent ash, .3 percent S). These heating rates were converted to equivalent TPD of bituminous coal and used with (8301,1.1-3) to determine TPD of air emissions. Particulates were reduced 99.5 percent,by the use of an electrostatic precipitator and a Wellman Lord wet scrub, while So emissions were reduced.95 percent by the Wellman Lora unit. IV-25 FTN4 @362 (Cont)'. Sulfur Recovery Plant Based o h the-use of the Hot Carbonate acid gas removal.,system for the nonselective removal of H2S and CO from the synthesis gas stream, a dilute (5 percent) .H23 gas,stream is sent to the Claus plant for recovery. From (8303,AI-25) a Claus plantoperating-on this dilute feed.can recover 84 percent of the incoming S as elemental S. The'incoming S for recovery is based on 21,380 tPD coal to the gasikier (fdotnote 8361, less the above@1170 TPD coal as fuel), .51 percent S in the coal, and 90 percent of the S in the gasifier as H2S to Claus for recovery (the balance of the S is-in the char). Based, furthermore, on complete recycle to the Claus plant of all the SO@ recovered in the @Iellman, Lord scrubbing units on the boiler flue gases and Claus tailgasest 133.6 TPD S is the Claus feed. Thus 112.2 TPD of S are recovered or 283 ton S/l.OE12 Btu. 21.4 TPD S passes to the -Wellman Lord tailgas scrubbing'. unit, so that 1.1 TPD S or 2.2 TPD S02 passes out to the atmosphere from the Claus and tailgas treatment system. Storage and Misc. Based on 21,380 TPD coal to the gasifier, .007 ton N2/ ton coal,,'and.70 percent of the N2 in the feed coal as NH@ (8363,X-7), 127.TPD of NH3 are produced in.the gasifier'.All of the''NH3 is washed from the gas synthesis stream and appears in the waste water. This waste water stream passes to an ammonia still with both a:'free and. a. f i=*d7Ipg, so_that.@ abbrAaztial,@y@ all, Of --+,be NHJ is recovered for sale. From (8301,5.2-2)' controlled storage and loading operations emit two lb of NHYton NH'@. Thus .127 TPD NH' are released to the atmosphere. 3 IV-26 FTN. 8363-8365 It should be noted that other sources of air pollution will be.present in any commercial coal-gasification operation, although their quantification is ,not possible at present. These sources include, but are not limited to, coal and other.solids preparation and transfer operations, vent stacks for waste,gas disposal, pipeline valves and flanges, and pump and compressor seals. The magnitude of these air pollutants, however, should not be that large if the sources are properly@contro'lled..- 8363 Based on'22,550 TPD coal with 6.0 percent ash,'1'353 TPD ash are produced. Since 5.2 TPD is released to the atmbsphere---as particulate, 1347.8 TPD,remains as solid w.aste for disposal. Based.'-.on 17700 GPM net makeup H20 (8300) and an assumed 500 PPM suspended solids whi ch is completely removed,by lime treatment and clarification, an additional 53.2 TPD of solid waste is .generated. From (8304) an ammonia still is estimated to produce 115 ton/D of still waste. It is assumed that all bio-treating sludges are used as boiler fuel. The sum.-total solid.waste produced is thus 1515.5 TPD or 3831.ton/l.OE12 Btu. 8'364 Land requirements are assumed to b6 350 acres from (9401,7) for coal storage, preparation, and gasification plant facilities, ahd-an additional 16,5 acres for evapora- tion ponds (.8306),to handle the following TDS streams H20 softener and. demineralizer blowdowns, boiler ano cooling tower.blowdowns,'and H20 from ash quenching and transfer operations which might.contain,leachates.. Since High Btu Coal.Gasification is'assumed to be a mine-mouth activity, all solid waste produced is returned to the mine for burial. There is,"therefore, no incre- mental land impact due to solid waste production. Thus a total of 515 acres is required for a 22,550 TPD coal -gasification operation. With a 90 percent operating. factor this is equivalent to 3.96 acre-yr/l.OE12 Btu. 'However, a@larger land impact would be produced if solid -wastes 'were not returned to the mine.for.'burial.. (See footnote 8363 for solid waste.) 8365 Water:pollutants are- zero becaus.e ther e.is,no aqueous discharge from the boundaries of the plant operation. All.process waste water and impounded runoff is treated, and,used for cooling towermakeup, while all blowdown streams are collected and sent to lined evaporative ponds for disposal. IV-27 FTN. 8366-8367 Fromi@(8300 and footnote 8350),for 236.1E09 Btu/D SNG, coal,cost, based on $.15/1.,OE06.Btu coal, is $.22/ l..0EQ6 Btu gas. Thus 346.3EO9 Btu coal/D is required to produce 236.1E09 Btu gas/D. The primary efficiency, taken as Btu of gas output/Btu of coal input, is therefore .682. No light or heavy oils are reported as byproducts.for this process.-The ancillary energy is zdro because the,plant is self-sustaining with all power-and steam requirements generated on-site. 8367 The pX incipal quantifiable air pollutant sources are as follows: TPD Part. SOA CO HC NOx -Other' Fuels Combostion' 1.118 3.05 1.07, .320 20.1 .00534 Sulfur Recovery Plant 1.80 Storage and Misc. .0985 Fuels Combustion Based.on plant heat requirements similar to those in'. (8305i #' 63), a total of 3107 TPD of coal is required for fuel which includes 197 TPD for thermal drying of the coal.-The 2910 TPD of subbituminous coal used- as fuel in boilers is equivalent to 2135 TPD of bituminous coal and was used in conjunction with (8301',1.1-3) to determine boiler air-emissions.. Particulates were then reduced 99.5',percent by the use of ani@electrostatic precipitator and a Wellman Lord wet scrub, while S emissions were reduced 95 ptrcent by thevellman LOA unit. Particulate emissions in compliance with the New Source Performance Standards for coal thermal dryers are limited to .03 grain/DSCF .(1121@. Based on 24000 DSCF/ton dry coal input to the dryeri(1121Y and 12,913 TPD dry coal to the dryer and gasifier, .664 TPD of particulates.are emitted.,Based. on .535 lb NO /l.6E06 Btu coal fired (1121),, .51 percent S co;1. and 197 TPD coal for dryer fuel, .928 TPD NO. and 2.01 TPD S02 are also,released from the dryer. therma IV-28 FTN..8367 (Cont)., Sulfur Recovery Plant Based on'the use of the Hot Carbonate acid gas removal system for nonselective removal-of H2S and C02 from the synthesis gas stream, a dilute (5 percent) H2S gas stream is sent to the Claus plant for recovery. From (8303,AI-25) a Claus plant operating on this dilute feed can recover 84 percent of the incoming S as elemental S. Theincoming S for recovery is based on 16,555 TPD coal to the gasifier (footnote 8366, less the above 3107 TPD coal as fuel), .5l.percent S in thecoal, and all.of the S to the gasifier as H2S.tO Claus for recovery (none in the slag). Basedf-furthermore, on complete recycle to the Claus plant of all the S02.recovered.in the Wellman Lord scrubbing units onthe boiler flue gases and Claus tailgades,, -11.1-I'TPD is the Claus feed. Thus 93.3 TPD of S are recovered or 271 ton S/1.OE12 Btu. 17.8 TPD'S pa.sseswto the Wellman Lord tailgas scrubbing unit, so that ..9 TPD S or'l.8 TPD S02 passes out to the atmosphere, from'.the'Claus and tailgas treatment system. Storage and Misc. Based on 16.,555 TPD coal to the gasifier, .007 ton N2 ton coal, and 7.0 percent of the N2 in the feed coal as NH3(8303,X-17), 98'.5 TPD of NH3 are produced in the gasifier. All of the NH3 is washed from,the gas.synthesiis stream and appears in the waste water. This waste water stream passes to an ammonia still with.both a free and ..a fixed leg so that substantially all of the,NH3 is recovered for sale. From (8301,5.2-2) controlled storage and loading operations emit two lb,of NH3/ton NH3. Thus .0985 TPD NH3 are released to the atmosphere It should be noted that other sources of air, pollution will be present in,any commercial coal'gasification operation, although their quantification is not possible at present-These sources include, but are not"limited to, coal and other solids@'preparation and transfer opdrations, vent stacks for waste gas disposal, pipelinel valves and flanges, and pump and compressor seals. The magnitude of these air pollutants,, however, should not be that large if the sources are properly controlled. -29 V FTN. 8368-83,71 8368- Based on 19,662 TPD coal with 6.0.percent ash, 1179.7 TPDiash are produced. Since 1.2 TPD is released to the atmosphere as particulat6,,1178.5 TPD remains as solid waste'for disposal. Based on 10385 GPM net makeup H'-O (8300) and an assumed 500 PPM suspended solids whici is completely removed by @ime treatment and clarification,, an Additional 31.2 TPD of solid waste is generated. From (8304) an ammonia still is estimated to produce, 115@ton/D of still waste. It is .assumed that all bio-treating sludges are used as boiler fuel. The sum,i.total solid waste, produced is t,hus.1324.2 TPD or 3839 ton/l.OE12 Btu. 836-9 Land requirement.s are assumed to be 350 acres from (9401,7) for@coal-storage, preparation and.gasification plant facilities, and An additional'165 acres for (@vapora-. tion ponds 48306) to handle the following TDS'streams H20 softener,and demineralizer blowdownsf boiler and cooling tower blowdowns, and H20 from ash quenching and'transfer operations which might contain leachates. Since High Btu Coal Gasification is-assumed to be a mine-mouth activity, all solid waste produced is re- turned to the mine for burial. There is, therefore,,-. no incremental land impact due to solid waste produc- tion. Thus a total of 515 acres is required for a 19,662 TPD coal gasification operation. With a * 90 percent operating factor this is equivalent to 4.54, acre-yr/l.OE12 Btu. However, a larger land impact would be produced if solid wastes were not returned to the mine for burial. (See footnote 8368 for solid waste..) 8370 Water pollutants are zero because there is no aqueous discharge from the boundaries of the plant operations. All process waste water and impounded runoff is treated and used for cooling tower makeup,.while all blowdown streams are collected and'sent-to lined evaporative ponds for,disposal. 8371 From (8311,3.13) the total heat demand for a plant producing 252EO9 Btu/D of SNG is 85.1EO9 Btu/D and the TPD coal'to the gasifier is 21860. This analysis is for a Aouthwestern Subbituminous coal with 62.0 percent volatile matter and fixed carbon@and a heating value of 8310 Btu/lb. Based on footnote 8350 and'the assumption that the gasifier outputs are the same for equivalent TPD of volatile and fixed carbon input to the gasifier (sinee these are the reactive constituents'in' the coal), the Northwestern analysis would require 18824 TPD coal to the gasifier. Based on the assumption that'.the total plant heat demand is relatively constant IV-30 FTN. 8372 for the various subbituminous coal inputsp 4830 TPD coal is required for boiler fuel. Thus a total of 23654 TPD coal is required to produce 252EO9 Btu/D SNG for a primary'efficiency of .605. This size plant also produces 41.23EO9.Btu/D of tars and tar oils and'63.6EO3 GPD of naphtha (831,1,3.13). If these fuels are considered, then the,overall plant efficiency becomes..721. The ancillary energy is zero because.the plant is self- sustaining with all power and steam requirements generated on-site. 8372 The principal quantifiable air pollutant sources are as follows: TPD 'Part. sox CO, HC. NOx Other Fuels Combustion .851 1.72 1.77 .532 31.9 .60886 Sulfur Recovery Plant 0.160 Storage and Misc. .112 Fuels Combustion Based on air emissions factors in (8301',1.1-3,1.4-2) and the combustion of 3544 TPD of equivalent bituminous coal (4830 TPD of subbituminous coal). Particulates were reduced 99.5 percent by the use of an electrostatic precipitator and a Wellman Lord wet scrub, while S02 emissions were reduced 95 percent by the Wellman Lord unit.. 'Sulfur Recovery'Plant. Based on'the use of the Rectisol acid.,gas removal system for the selective removal of H2S and C02 fromthe syn- thesis gas stream,' a concentrated (25 percent) H2S gas stream can be sent to the Claus plant for recovery (8308,21), and from (2022,103) this Claus unit can re- cover 94 percent of the incoming S. The incoming S for recovery is-based on 18824 TPD coal to the gasifier, .51 percent S in the coal,. and 98 percent of the S to the gasifier as H2S to Claus for recovery (the balance of the S is in the by-products) from (8310, sheet no. 00-1-02). Based, furthermore, on complete recycle to Claus of all the S02 recovered in the Wellman Lord scrubbing units on the boiler flue gases and Claus tailgases, 117.1 TPD S is the Claus feed., IV-31 FTN'. 8373 Thus-110.1 TPD S is recovered for sale-or 265 ton S/ l.OE1-2 Btu. Since 7 TPD S passes to-the Wellman Lord tailgas scrubbing unit, 3.TPD S or 6 TPD S02 exits the stack. Storage and Misc.. From-(8311,3.13) 63.6EO3GPD of light oils are produced. Assuming two weeks sqtorage capacity under new tank con- ditions and emission factors, from 18300q2 4.3-8),,001 TPD HC are emitted..Based on 18824 TPD coal to the gasifier-and .1 percent N2in the coAl and 70 percent,of the N2 in the feed coal as NH3 (8303,X-7)- 112 TP 'D NH3 is produced in the gasifier. Substantially all of this NH I vered in a free and fixed ammonia still. 3 is reco From (8301,,5.2-2) controlled,storage and loading operations emit two lb of NH3/ton NH3- Thus .112 TPD NH3 are released into the atmosphere. It should be noted that other sources of air pollution will be present in any commercial coal gasification operation, although their quantification-is not possible at present. These -sources include, but.are not limited, to, coal and other solids preparation and transfer operations, vent stacks for,waste gas disposal, pipeline' valves and flanges;, and pump and compress rseal. The magnitude of these,air pollutants, however, should,not be that large-if the sources are properly controlled. 8373 Based on 23654 TPD coal with-6 percent ash-,,, 1419 TPD ash are produced-Since 1 TPD,is releasekdAto the atmosphere as particulate, 141,8 TPj remains-as solid waste for .disposal. Based-6n100 GPM net makeup H20 (8311113.20) and-an assumed 500 PPM suspended solidswhich is complete- 1Y remov qed,by lime treatment andclarification, an additional 15.3 TPD of solid waste generated. From (8304)an ammonia stillis estimated,to produce 115 TPD of still waste. The sum total solid waste -produced is. thus 1548 TPD or 3731 ton/l.OE12,Btu. IV-32 FTN 8374-8376 8374 Land requirements are assumed to be 350 acres from (9401,7) for coal storage, preparation, and gasification plant facilities, and an additional 165 acres for evaporation ponds (8306) to handle the following TDS streams - H20 softener and demineralizer blowdowns, boiler and cooling tower blowdowns, and H20 from ash quenching and transfer operations which might contain leachates. Since High Btu Coal Gasification is assumed to be a mihe-mouth activity, all solid waste produced is re- turned to the mine for burial. There is, therefore, no incremental land impact due to solid,waste produc- tion. Thus a total of 515 acres is required for a TPD coal gasification operation. Wit h a 90 percent operating factor this is equivalent to 3.78 acre-yr/I.OE12 Btu..*. However, a larger land impact would be produced if solid wastes were not returned to the mine for burial. (See footnote 8373 for solid waste.) 8375 Water pollutants are zero because there is no aqueous discharge,from the boundaries of the plant operation. .All process waste water and impounded runoff is treated and,used for cooling tower makeupt while-all blowdown streams are collected and sent to lined evaporative ponds for disposal. 8376 This process can be.operated with only a lignite, coal input. Thus the following lignite coal (ROM) was used in this analysis: Proximate Analysis WT PC Btu/lb 7070 Ash 7.2 S_WT PC 0.6 H 20 33.7 Vo Mat. and Fixed C. 59-11. For this coal 7100d ton of coal 'is equivalent to 1.OE12 Btu. From (8-300) 25360 TPD coal is required for the gasifier and 2937'TPD for plant fuel to produce 25OE09 Btu/D SNG. The primary efficiency is thus .625. The ancillary energy is zero because the plant is self-sustaining with all power and steam requirements. generated on-site. IV-33 FTN. 8377 8317 The-principal quantifiable air pollutant sources are_ as follows: TPD Part. SQx CO HC N0qOx Other Fuels Combustion 1.32 104qA 6qT5;1 .237 15.2. .00395 .Sulfur Recovery Plant 4 Storage-and Misc. ..170 Fuels Combustion Based on the Combustion 0q60q115q81 TPD bituminous coal (2683 TPD lignite) as plant fuel and air emissions factors from (8301,1.1-3). P6qartic6qulates,were reduced 99.5 percent by the use of an electrostatic'precipitator and a Wellman Lord,wet scrub while So -emissions were reduced 95 percent by the Wellman Lora unit. Also included are the emissions from combustion' of 254 TPD of lignite to dry the-gasifier feed-coal. Based on .535. lb NOx/i.0E06'Btu coal fired (1121).and .6 percent S coal, .961 TPD NO' and 3.05 TPD So are'emitted.. Particulate emitsfons in. compii-aqncqa with the New Source Performade Standards for coal thermal yers are-limited to .03 g4qkain/DSCF (1121). Based on 24000 DSCF/ton dry coal input to the dryer (1121) and 16814 TPD dry coal.to the dryeqt-and gasifier, .865 TP4qD particulates are-.emitted Based, furthermore, on 2 percent of the S in the Led coal evolved as.S0qO 2 (8321, 20), an additional 6.09,TPD SO is released from the coal thermal dryer 2 Sulfur Recovery'Plant Based on the.use.ofthe Hot Carbonate acid'gas removal-system for the,nonselective removal of H 2S and c4qo from the synthesis gas stream, ailute(5 percent) H qi gas stream is'sent to the Claius-plant for recovery. From(8303,AI-25) a-Claus plant operating on-this,dilute feed can recover 84q.petcent of the incoming S as elemental.S. The incoming Sq"for recovery is based on 25360 TPD-coal to the gasifier, .6 percent S in the coal, and 3 percent of-the:S as H 2S,to Claus for recovery (3 percent of-the S is in the.ash and 92 percent of the S is evolved as S02 from the.regenerator). IV-34 FTN. 8378 Basedi furthermore, on 30 percent of the total S to Claus as S02 (8303,AI-27) from the Wellman Lord scrubbing units,.6.6 TPD S is the Claus feed'. Thus 5.5 TPD S is recovered for sale or 13.8 ton S/l..OE12 Btu. Since 5.5 TPD S passes to the Wellman Lord-tailgas scrubbing unit, .3 TPD S or .6 TPD S02 is emitted. The bulk of the S in the gasifier coal is released as S02 in the regenerator (92 percent). Based on a Wellman Lord unit to treat this stream (144 TPD S),,7 TPD S or 14 TPD S02,leaves with the regenerator offgases. The tot- al recovered S,02 for sale is 289.6 TPD S02 or 727 ton S02/1-OE12 Btu. Storage, and Misc. Based 'an 16814 TPD MF lignite to the gasifier', 1.19 percent N2 in MF lignite,(8321,20) and 70 percent of the N2 as NH3 (8303,X-7) 170 TPD NA3 are.produced in the gasifier. Substantially all of this.NH3 is recovered in a free.and fixed.ammonia still. From (8301,5.2-2) controlled storage and loading operations emit two lb NH3/ton NH3- Thus .170 TPD NH@ are released into the atmosphere. It should be noted that other sources of air pollution will be persent in any commercial coal gasification operation,'although their quantification isnot possible at present. These sources include, but 'are not limited to, coal and other solids preparation and transfer operations, vent stacks for.waste gas disposal, pipeline valves,and flanges,. and pump and compressor seals. The magnitude of these air pollutants, however, should not be that large if.the sources are properly controlled. 8378,. Bas'ed on 28297 TPD coal with 7.2 percent ashl 2037 TPD ash are produced. Since 1 TPD is released'to the. atmosphere as parti 'culate, 2036 TPD remains as solid waste for disposal. Based on 6580 GPM net makeup H20 (8300) and an assumed 500 PPM suspended solids which.is completely removed bylime treatment and clarification, an additional 19.8 TPD of solid waste is generated. From (8304) an ammonia still is estimated to@produce 115 TPD of'still waste. From (8321,20) it is estimated that 1260 TPD MgO-CaO will have to be discarded from the regener- ation'operation in thiz process. It is assumed that al bio-treating sludges are used as boiler fuel. The sum total solid waste produced is thus 3431 TPD or 861.0 ton/' l.OE12 Btu. IV-35 FTN. 8379-8385 8379, Land requirements are assumed to be 350 acres from (9401,7) for -coal storage, preparation,and gasification plant facilities,' and an-additional 165-acres-for evapora- tion ponds (8306) to handle the 'following TDS streams H20 softener,and demineralizer blowdowns, boiler and cooling tower blowdowns,and-H22q6 from ash quenching and. transfer,operation which might contain-ql4qeaq@qchates. Since High Btu Coal Gasification-is assumed to be-a mine- mouth activity,. all solid-waste produced is-returned to the mine for burial. There is therefore, no incre- -mental land impact due to solid-waste production. Thus a total of 515 acres is required for a-28297 TPD coal gasification operation. With a 90 percent operating factor this is equivalent to 3.16 acre-4qyr/l.OE12 Btu. However, a larger land impact would be,produced if solid wastes were not returned to the mine for burial. .(See footnote 8378 for solid waste.) 8380 Water pollutants are zero because there is,aqueous discharge'from the boundaries of the plant operation. All process waste water'and impbunded.runoff is treated and used for cooling tower makeup, while all blowdown streams are collected and sent to lined evaporative ponds for disposal. 834 Primary efficiency and ancillary energy for this process are an arithmetic average of--those for the Hygas"Electrothermal, Hygas Steam Oxygen, Bigas,-and Synthane processes. 8382 Air pollutants for this process are an arithmetic average of those for the:Hygas-Electrothermal,-Hygas- Steam Oxygen, Bigas,.and Synthane processes. 8383 Solid waste production for this process is an arithmetic average-of those-for the Hygas-Electrothermal, Hygas- Steam Oxygen, Bigas andSynthan processes. 8384 Land utilization by this process is an arithmetic- average of those used by the-Hygas-Electrothermal, Hygas-Steam Oxygen,'Bigas, andSynthane processes. 8385 Water pollutants for this process are an arithmetic average of-those for 'the Hygas Electrothermal, Hygas- Steam Oxygen,Bigas and Synthane processes. IV-36 FTN. 8386- 8387 8386 capital and operating costs keredeveloped @s follows: Capital Costs-1972 $-Plant-Basis-19,700 TPD,.90 P LF From (8300), escalated at,5 percent from 1971 $, costs for coal storage and preparation, feed system, gasification. and CO shift,gas purificatiom, methanation, 02 manufacture, steam and power plant, gpneral'utilities, and general offsites total 165.2EO6 $. Water pollution control costs were estimated at 11.7E06 $ from (2013,VII-6), (8304), and (8315). Sulfur recovery costs were estimated at 5.0 E06 $,from (8300) and (8303,AI-25,AI-26). Capital cost was reduced by*20EO6 $ to reflect savings.for a noncaking low S western coal. To the subtotal were added a 15 percent. project contingency and a.7 percent development contingency to give a total plant investment of 191.5EO6'$. Based on a FCR of-10 percent/yr and- 6.46EO6 TPY coal, this is equivalent to'l.7.4EO5 $/ 1.OE12 Btu. Operating Costs-1972.$-Plant Ba'sis-19,700 TPD, 90 P LF From (8,300).directly, catalysts and chemicals,purchased raw H 0, and process operating labor total $.0405/1.OE06 Btu g3s. Maintenance labor, supervision labor, administra 'tion and general overhead, operating and maintenance supplies arefrom (8303,Ai-5). The total gross operating cost is thus $.1694/1.OE06 Btu gas or 13.12EO6 $/yr for a 236.1E05 Btu/D SNG plant. By- productS- are credited at, $10ATS' (85 LTS/D) -and $25/T (98 TPD NII3) from (8303,AI-5). The total net oparating cost is 12.04EO6 $/yr or, for 6.46EO6 TPY coal, 1.06EO5 $/l.OE12 Btu. 8387 Capital and operating costs were.developed as follows: Capital Costs-1972 $- Plant Basis-25, 200 TPD, 90 P LF From (8300), escalated at 5 percent from.1971 $, costs for coal storage and preparation, feed system, gasification and CO shift, gas purification, methanation, steam and power plant, general utilities, and general of'fsites total 200.9EO6 $. Water pollution control costs were estimated at 11.7EO6 $ from (2013,VII-5), (8304)f' and (8315). Sulfur recovery costs were estimated at lOE06 $ from (8300) and C8303,AI-25,AI-25). Capital cost was reduced by 20EO6 $ to reflect savings for a noncaking low S western coal. To the subtotal were added a 15 percent project contingency and a 7 percent IV-37 FTN. 8388 develpment coingency to-give a total plant investmnt of 247.2EO6 $. Based:on 10 percent/yr FCR and 8.28EO6 TPY coal, this becomes.l.70EqO5 $/l.OE12 Btu. Operating Costs-1972 $-Plant Basis-25,200TPD, 90 P LF From (8300rectly, other raw material catalysis and chemicals, purchasedaw H 0 and process operating 2 labor total $.0438/1OE06 Btu gas. Maintenance labor, supervision labor, administration.and general overhead,, 'operating and maintenance supplies are from q(8303,AI-5). The total gross-operating cost is $1966/1.OE06tu gas for a 0q@53-3EO9Btu/D SNG plant. By-products are 'credited at $10/0qLTS 1.(105 4qLT8qS/D), $25/T NH (139 TPD NHq@q), $.15/ gal BTX(4q8.44qEqO3-GPD)and $.30/q1.qOE06 Btu ta s q(23.4Eq09 Btu/D) from (q8303,AI-5). The-total net operating cost is $10-15EqO6/yr or, for 8.28EqO6 TPY coal, 7.qOqO4qtqO4 $/l.OEI2 Btu. 8388 Capital and operating costs were.develop8q6d as follows: Capital Costs-1972 $_PlantBasis T8qPDj 90 P LF From (8300), escalated;4qat 5 percent from .1971 $, costs for coal storage and preparation, feed system gasification and Cozshift, gas purification, methana- tion, q' manufacture, steam and poer plant, general qutqilqti as, and general offsites---tota '1,1q606q906 $. Water pollution control costs were estimated at'll.7EqO6 $ -from (2013,VII-5), (8104), and (,8315). Sulfur recovery costs were estimated at 9.2EO6 $ from (8300) and (8303,AI-25,AI-26). Capital cost was reduced by 20EqO6 $ to reflect savings for a noncaking low S western coal. To the.subtotal were added a 154_percent,project contingency and a 7 percent development contingency to give a total plant-investment of 196.3EOq6 $. Based on 10 percent/yr FCR and 7.84EO6 TPY coal., this comes 1.43EO5 $8q/l.OE12 Btu. -IV-38 FTN 8389 Operating Costs-1972 $Plant Basis 23,900 TPD, 90 P LF From (83bo) directly, other raw material., catalysts and chemicals, purchased raw H 0, and process operating labor total $.0432/1.0E06-0qAtu. gas. Maintenance labor, supervision labor, administration and general overhead, operating and maintenance supplies are from (8303,AI-5). The total gross operating cost is $.1728/1.OE06 Btu gas for a 247.2EO9.Btu/D SNG plant. By-products are credited at $108q/8qLTS (91 LTS/D) $25/T NH (123 TPD N4qK ),$.15/gal B-T-X (456EO3 GPD)and '$.30/1.02q206 Btu tars 123EO9 Btu/ D) from (8303,AI-5). The total net operating cost is $8.19EO6/yr-or, for 7.84EO6 TPY coal, 5.96EO4 $/lOE12 Btu. Capital and'operating costs were developed as follows. Capital Costs-197 $-Plant-Basis-22,600 TPDpp LF From (8300), escalated at 5 percent-from 1971 $, costs for coal storage and preparation, feed system, gasification and CO shift, g.as purification, methanation, compression, 0 2 manufacture, steam,and power plant,, general utilities, and general offsites total 180.7EO6 $. Water Ipollution control costs were estimated at 11.7EO6 $ from (2013,VII-5), (8304), and1p315). S8qU'lfur recovery costs were estimated at 6EqO6 $ from (830) and (8303,AI-25,AI-26). Capital cost was, reduced by 20EO6 $ to reflect savings for a noncaking low S western coal.-To the subtotal were added a 15 percent -project contingency and,a 7 percent developement contingency to give a total plant investment of 217.7EO6 $. Based on 10 percent/yr FCR and 7.41EqO6 TPY coal, this becomes 1.q68Eq05 $/l.OE12 Btu. Operating Costs-1972 $-Plant Basis-22,600 TPD, 90 P-LF From (8300) directly:, catalysts and chemicals, purchased raw H 0, and process operating labor total.066/1.qOE06 Btu g is. Maintenance'labor, supervion labor, adminis- tration and general overhead, operating and maintenance supplies are from (8303,AI-5). The total gross operating Cost is $.2152/1.8qOE06 Btu gas for a 231.8E4qO9 Btu./D SNG plant'. By-products are credited at $10/20qLTS (100 LTS/56qP), .$25/T NH (127 TPD NH ), $.15/gal B-T-X (25000 GPD), and $.3052q@1.2qOE06 Btu tars (8.5E6qO9 Btu/D) from (8303, AI-5). The total'net operating cost is:$12q.83E4qO6/y32qr or, for,7.41E8qO6 TPY coal, 9.88E2qO4 $/l.2qOE12.Btu. IV- 3 9, FTN. 8390-8392 8390. Capital and-operating costs for-this--process are an. arithmetic average of-those for-the,Hygas-Electrother- mal, Hygas-Steam,Oxygen, Bi gas,.and Synthane processes. 8391 Capital and operating-costs were developed'as follows: Capital Costs-1972 $-Plant-Basis@23,700 TPD, 90 P LF Prom (8319,exhibit K page)'costs for process units, utility'units, offsite units, water.pipeline', catalysts and lubricants., general plant, engineering fees and licenses, contingency, and start up total 321qAEq06 Based on 10 percent/yr FCR I and 7,77EO 6 TPY coal, this becomes 2.36EO5 $/l.OE12 6qBtu. Operating.Costs-1972 $-Plant'Basis-2300 T2qP4qD,, 90 P LF From (8319,exhibit N,Schedule 3) the avantage-operating and maintenance expenses for the-first.three years of operation include costs for operation supervision and engineering, other power expenses, other-process production expenses, rents., maintance-supervision and engineering,aintenance of- structures and improvements, maintenance.of production equipment, administrative and-general(less property insurance). The total gro'ss-operating cost is $22.32EO-6/yr. By- products are credited at $108q/8qLTS (98 0qLT8qS/D) , $25/T NH (112 TPD), $.12q5/gal. B-T-X (63.64q903.8qG2qPqtq)q),an2qd,.$.30/1.qOE0q9 Btu tars (41.2EqO9 Btu/8qD). from.(q8303,AI-5).-The total net operating cost is.$l3.88EO,6/yr-oqr, for-7.77EOq6 TPY coal, 1.02EO5 $/l.OE12 Btu. 8392 Capital and opera ting costs were developed as follows: Capital Costs-1972 $-Plant Baqs2qIA-28,300 TVD, 90 P LF From (8300), escalated at 5 percent from 1971 $, costs for coal storage and preparation, feed system', gasification and CO shift, gas purification,.methanation, compression, sulfur recovery, genekal-utilities, and general offsites total 135E4qO6 $. Steam.and power-plant costs are from (830q-0) with $200q-/KW:added,.for.on-site generation of 2180 KW previously-purchased. Water. pollution control costs were estiqmated,at.11.7E8qO6 $ from (2013,8qVIIq-5), (8304), and (831q-50q)q,. To the-subtotal were added a 15 percent project contingency and a 7 percent development-contingency to give -a total-plant investment of 193.332qE2qO6q6 $. Based:on-10 percent/yrq,FCR,and 9.30E06 TPY-coal, this becomes l.48E2qO5-$/l.2qOEl2q:Btu, IV-40 8393-8401 Operating. Costs-1972 $-Plant Basi s-28,300 TPD, 90 P LF From (8300) directly, catalysts and chemicals purchased raw'H20, and process operating labor total $.062/1.OE06 Btu gas. Maintenance labor, supervision labor, administration-and general overhead, operating and maintenance supplies are from (8303,AI-5). The total gross operating cost is $.1808/1.,OE06 Btu gas for a 250E09 Btu/D SNG plant. By-products are credited at $10/LTS (12 LTS/D), $4/LT S02 (649 LT S02/D),' and $25/T NHj (170 TPD) from (8303,AI--5). The total netoperating cost is $12.51EO6/yr or,for 9.3EO6 TPY coal, 9.55EO4 $/l.OE12 Btu. 8393 Thermal discharges can be completely eliminated by the use of mechanical.draft wet cooling towers. 8400 The Northern Appalachia coal used in this study has the following composition on a run-of-mine basis': Proximate Analysis - WT PC Btu/lb 12197 Ash 15.1 S_WT PC i.3 Water 2.5, Vol.Mat 30.9 Fixed C.'. 51.5. For this coal 411000 ton of coal is equivalent to 1.OE12 Btu. 8401 From (8300) thetotal heat,demand for a plant producing 253.5E09 Btu/D SNG is 113EO9 Btu/D and the TPD coal to the gasifier is 16754. This analysis is for an Eastern Bituminous coal with 83.4 percent volatile matter and fixed carbon and a heating value of 12400 Btu/lb.-Based on footnote 8400 and the assumption that the gasifier outputs are the same for equivalent TPD of volatile 'J and fixed carbon input to the gasifier (since these are the reactive constituents in the coal), the.Northern Appalachia analysis would require 16953 TPD coal to the; gasifier. Based on the assumption that, the total.plant heat demand is relatively.constaht for the various. bituminous coal inputs, 1197 TPD coal is required for boiler fuel. Thus a total of 18150 TPD coal is required, to produce -253.3EO9 Btu/D.-SNG for a primary efficiency of .572. This size plant also produces 9.84EO9 Btu/D of' tars and 52.5EO3 GPD of light oils@!,(8300). IV-41 FTN. 8402 If-these fuels-are considered then-the overall plant efficiency becomes .608. The,ancillary energy is zero because the plant is selfrsustaining with all power and steam requirements generated-onsighte. 8402 The.principal quantifiable a2p.pollutant,sources are,as follows: TPD Part. SO CO HC NO other 0qx qx Fuels Combustion .6.20 9.30 2.0 .564-2q40.0 ..00919 Sulfur Recovery Plant q1_q0q0 Storage and q)4isc. .001 .165 Fuels CoqmqbqAstion Basedqlon a Iir emission factors in (q8301,1.1-3,1.4-2) and the combustion f 2478.TPD of coal equivalent char (55', percent ash, 1 percent S2p.1197 TPD coal (15 percent ash, 1.3 percent,S),-and 24i3EqO9.Btu/D waste.offgases (contqaining.25 percent.of.the.total,S in the coal to the gasifier). Particulates.were.-repdeced 99.5 percent. by the use of.an.electrostatic-precipitator and-a Wellman 1ord wet scrub7.while.8qS2qO emissions were reduced 95 percent by the Welqima6qi'Lord0qU0qnqit. Sulfur.qRecovery Plant Based,on the'use of the,Rectisol acid gas,removal systemor the selective removal of HS,and CO forq1qD4qM the synthesis gas stream,.aonclentraqied(25.pqircent) H S gas stream..canbe-sent to@the-Claus,plant for recovery (8308,21), and,from (8q2022G3q).this Claus unit can recovery'941percent of the incoming.-S. The incoming S for.recovery is based on.169,56q3 TPD-coal to the gasifier, 1.3 percent S in the.coal, and 55-percent of the S to the gasifier as H 2S:to_Claus-foqr recovery (the balance of.the S is@in the pretreatment offgases and the char) from (8303,X.-13,and 8303'j;.27)..Based, furthermore, on'30 percent of.total.S.to Claus as.-SO (8303,AI-27) from the Wellman Lord scrubbing units4q17q'4q3q'20qVPD S is the Claus feed. Thus 163 TPD S is.recovered ,along,00qmith an- .additional (to thatw32qh2qichq.q-the Claus_c6qanq.q@accept) 93.6 TPD SO for sale. These.are equivalent to.368 ton S and 211 t32qd28qA So /16qOE12.Btu. Since,10q0 TP20qDq'Sq,.pasqses to the Wellman Loqidq,tq*ai52qlgas.scrubbing ,unit, .5,TPD S or 1.0 TPD so2 exits the stack. IV-42 FTN. 8403-8404 Storage and Misc. From (8300) 5.25EO4 GPD of,light oils are produced., Assuming 2 weeks storage capacity under new tank conditions and emission factors from (8302,4.3-8), .001 TPD HC are emitted. Based on 16754 TPD coal to the gasifier and 1.16 percent N in the-coal (8300) and 70 percent of the N in the feid coal as NH 3 (8303,X- J), 165 TPD NH is pioduced in the gasifier. This value was used f8r this coal analysis. Substantially all of this NH is recovered in a free and fixed ammonia still. From (830.1,5.2-2) dontrolled storage and loading opera- tions emit 2 lb of NH /ton NH Thus .165 TPD NH are V released into the atm8sphbre. It should be noted that other sources of air pollution will be present in any commerical coal gasification operation, although their quantification is not possible at present' These sources include, but are not n limited to, coal and other solids preparatio and transfer operations, vent stacks for waste.gas disposal, pipeline valves and flanges, and pump and compressor seals. The magnitude of-these air pollutants, however, should not be'that large if the sources are properly control-led. 8403 Based,on 18150 TPD coal with 15.1 percent ash, 2741 TPD ash are produced. Since 6.2 TPD is'released to the atmosphere as particulate,,2735 TPD remains as solid waste for disposal. Based on 6500 GPM net makeup H 0 (8300) and an assumed 500 PPM suspended solids whicA is completely removed by lime treatment.and clarificationr an additional 19.5 TPD of solid waste is generated. From (8304) an ammonia still is estimated to produce 115 ton/ D of still waste. It is assumed that all bio-treating sludges are used as boiler fuel. The sum total solid waste produced is thus 2869 TPD or 6480 ton/l.DE12 Btu. 8404 Land requirement's are assumed to-be 350 acres from,(9401,7.) for coal storage, preparation, and gasification plant.. facilities. Since High Btu Coal Gasification is as.sumed to be a mine-mouth activity, all solid waste produced is returned to the mine for burial. There is, therefore, no incremental land impact due to solid waste production. Thus a total of 350 acres is re- quired for a 18,150'TPD coal gasification operation. With a 90 percent operating factor this is equivalent to 2.41 acre-yr/l.OE12 Btu. However, a larger land impact would be.produced if solid wastes were not re- turned to the mine for burial. (S-ee footnote 8403 for solid waste.) IV-43 FTN 8405-8406 4q0 ng 8405, From(83 '00) the,total heat demand for@a:plant producii 247.26q=6q9,Btu/D of SNGis 730qAE09 Btu/2qD'and the TPD coal to the-gasifier is @14'6q957. This'analysis is for an Eastern Bituminous coal with 83.4 percent-qvqo2qlatile matter and fixed carbon-and @a heating value of 12400 Btu/ lb. Based on footnote 840 0and the,assumption that the gasifier outputs are the same 'for,equivalent TPD of volatile and fixed carbon,input to 4qthe gasifier (since these are the reactive constituen 8qt's'in the-6qCoal), the. Northern Appalachia analysis would require.15135 TPD coal to the gasifi6q64qr'. Based on'-the assumption that the total plant heat demand is relatively constant for the various bituminous- coal, inputs-- 2124, TPD coal. is *required. u for boiler fuel' Thus-a total of lq72q59,T6qPD,coal is -Btu/D Sq1q4G"for-a primary required to produce 247.2EqO9 efficiency of .587. This size@plantt also produces@q80q4q84E 09 Btu/D@ of tars and-, 4 66qSqQ3 i'6qM of light oils (82q300) If these fuels are co2qf2qtsid(q@4qr2qed' then'the,overall plant efficiency becomes'.620. The.ancillary energy is zero because the plant is self-sustaining ,with all power and steam requirements generated on-sit p. 8406 The principal quantifiable-air pollutant sources are as follows: TPD Part. sox CO' H0qC N4qO6qx Other Fuels@Combustion 1.28 7.55 1.23 .32925.3 .00531 Sulfur Recovery Plant 1.00: Storage and Misc. .00q1 .148.- Fuels-Combustion Based on air emissions factors in.-(8301,1.1-3,1.4-2) and the combustion of 2124 TP4qD,coal (15percent ash-, 1.3 percent S) and 21.6EqO9"Btu/D:water,offgAseq6"(containing .25 percent of the total S in the d6qdqal to the@gasifier). Particulates were reduced:99.5 percrent.by the-use of an eleptrostatic.precipitator and a Wellman.Lord wet scrub, while SO, emissions-were"reduced 950qt'q-36qperce20qhtq'b36qyq'the Wellman Lord unit. IV-44 FTN. 8406 (Cont) Sulfur Recovery Plant Based on the use of the Rectisol Acid gas removal system, for the selective.removal Of H2S and C02 from the synth@ esis gas stream, a concentrated (25 percen .t) H2S gas stream can be sent,to the Claus plant for recovery (8308,21), and from (2022,103) this Claus unit can recover 94 percent of the incoming S.-The incoming S for recovery is based on 15135 TPD coal to the gasifier, 1.3 percent S in the coal, and 55 percent of the S to Ft the gasifier as H2S to Claus for recovery (the balance of the S is in the pretreatment offgases'and the char) from (8303,X-i3,-and 8303,27). Based,.fu.rthermore, on 30 percent of total S toClaus.as S02 (8303,AI-27) from F the Wellman Lord scrubbing units, 155'TPD S is the Claus feed.-Thus 145 TPD S is recovered along with an addition- al (to that'which the Claus can accept) 68 1.2,TPD S02 for ,sale. These are equivalent to 345 ton'S and 162'ton OE12 Btu. Since 9.3 TPD S passes to the Wellman S02/1 Lord tailgas scrubbing unit, .5 TPD S or 1.0. TPDS02 exits the stack. Storage-and Misc. From (8300) 4.63E'O4 GPD of light oils are produced. Assuming 2,weeks storage capacity'under new tank conditions and emission factors from (8302,4.3-8),-.001 TPD,HC are emitted. Based on 14957 TPD coal to the gasifier and,1.16 percent N in the coal (8.300.1) and 70 2 (83 percent of the N2 in the feed coal as NH3 03,X-7), 148 TPD NH3 is produced in the gasifier. This value was used for this,coal-analysis. Substantially-all.of this'NH3 is-recovered in.a free and fixed ammonia still. From (8301,5.2-2) controlled storage and loading operations emit two lb of,NH3/ton NH3-.Thus ..l 48 TPD NH3 are released to the atmosphere. It should be-noted.that other sources of air pollution will be,present in any.,commercial coalgasification operation, although their quantif,ication.is not possible at present.' These sources include, but are not limited to.,'coal and other solids preparation an'd-transfer operations, vent stacks for waste gas disposal, pipeline valves and flanges, and pump and compressor seals. The magnitude ofthese air pollutants,-howe'der, should not be that large if the sources are properly controlled. IV-45 FTN. 8407-8409 8407 Based on 17,259 TPD coal with-1-5.1 percent,ash, 2606 TPD ash are-produced. Since 1.3 TPD is released to the atmosphere as particulate, 2605 TPD,remains-as solid waste for disposal. Based on 46 *00 GPM net:makeup H20 (83.00) and an assumed 500 PP4qM suspended.solids which is completely removed by lime treatment and clarification, an additional 13.8 TPD of -solid waste is generated. From (8304) an,ammonia still is estimated to:produce 115 ton/Df still waste., It is assumed that all bio-treating sludges-are-used as boiler-fuel. The-sum,total solid waste produced is thus 2732q3 TPD or 6492q2 ton/l.2qOE12 Btu. 8408 Land requirements are assumed to be 350,acres from (9401,7) fo: coal storage preparation, and2qqq4,qaification plant facilities. 'Since High Btu C0.G0qasifation is assumed to be a-mine-mouth activity, all.solid waste produced is-returned to-the mine for burial.. There is, therefore, no incremental.land @impactdue to.solid waste production. Thus a total-of 350 acres is re- quired for a 17,259-TPD coal gas qification.operation. With a 90 percent operating factor this is equivalent .to 2.53 qacre-yr/l.OE12 Btu. However, a larger-land impact would be produced if solid:waste awere not re- turned to the mine for.burial. (See footnote-8.407 for solid waste.) 8409 From (8300) and'(830:9).the total heat demand for a plant producing 231.88qEq09 Btu/Df SNG is 116.3EO:9 2qBtu/Dand the @TPD coal to the gasifier is 14594. Thi.s analysis is for an Eastern Bituminous coal with. .86.9 percent volatile matter and fixed carbon.and.a heating,value of 12400Btu/lb. Based on foot-noteL 84,00-and the as sumption that the gasifier outputs are4qthe same for equivalent TPD of volatile and fixed,carbon input to the gasifter since these are the reactive.constituents in the coal), the,Northern Appalachia analys,is would require 15391 TPD coal to the-gasqfier. Based.on the assumption that the total plant heat demand is -relatively cons,qtant for the various, bitumiqnous'coal, inputs, 2358 TPD coal'is required.for boiler fuel. Thus a total of 17749 TPD coal is.-required to produce 231.8E 09 Btu/D SNG for' a.primary efficiency,of...535. This size plant. also produces, 13..9E2qO,2qR Btu/D of tars (830.0) and,2500,0.GPD of light oils (8307,2q:6). If these,fuels are considered, then the overall Plant efficiency ernergy -6qzero-because the becomes .576q5. The ancillary en is plant is self-sustaining with aqlql:power.and steam requirements generated on-site. IV-A 6 FTN. 8410 8410 The principal quantifiable air pollutant sources are As follows: TPD Part. so CO HC NO Other x x FU61S Combustion .6.66 4.08 2.40 ..721 43.2 .0120 Sulfur Recovery Plant 4. 00@ Storage.and Misc. .402 .Fuels Combustion Based-on air.emissions factor s in (8301,1.1-3) and the combustion of@2448 TPD -of coal equivalent char (53.5. percent-ash,,..5 percent,S) and 2358 TPEJ coal (15 percent.-ash, 1.3 percent S)...Particulates were reduced, 99r.5@percent-,by the use of,an electrostatic precipitatorand a Wellman Lord wet scrub,.while so emissions were reduced 95 percent by the Wellman Loid unit. Sulfur Recovery Plant Based on the use of the Hot Carbonate acid.gas removal system for nonselective removal of H S And CO from the synthesisgas stream, a dilute (5 peiceht) H @ gas stream can,be sent tothe Claus plant. for regovery, and from (8303,AI-25).this Claus unit can recover 84 percent of the incoming S. The incoming S for recovery is based. on.153.9l'TPD coal to the gasifier, 1.3 percent S in the coal and 87,percent of the S to the gasifier as H S to 2 Claus for recovery (the balance of the S is in the char (10 percent) and tar (3 percent)) from (8307,9). Based, furthermore, on.complete recycle to Claus *of all the so recovered-in the Wellman Lord scrubbing units on thi boiler flue gases and Clau's tailg4ses, 251 TPD S is the Claus feed. Thus 211 TPD S is recovered for sale or 487 ton S/l.0E12 Btu. Since 40.1 TPD S passes to the Wellman Lord tailgas scrubbing unit, 2.0 TPDS or 4.0 TPD SO exits the stack, .2 IV-47 FTN. 8411-8412 Storage and-Misc. Based on@, 14594 TPD coal to the gasifier and 1.4 percent N2 in the coal (8300) and (8309) and 70 percent of the N in the feed coal as NH (8303,X-7),. 114 TPD NH i 3 3 is pioduced in the gasifier. This value was'used for this coal analysis. Substantially a1l.of this NH is recovered in a free and fixed ammonia-:still. From (8301,5.'2-2) controlled storage and loading operations emit 2.ib of NH . /ton.NH,. Thus .174 TPD.NH 3 are released into tRe atmos here. It should be noted that other sources of 6Lir pollution will be@present in any commercial,coal gasification operation, although theirquantification is n6t possible at present. These sources include, but are not limitedito, coal and other solids preparation and transfer operations; vent stacks for wastegas disposal, pipeline valves and flanges, and pump and compressor seals. The magnitude of these air pollutants, however, should not be that large if the sources are properly controlled. 8,411 Based on 17L749'TPD coal with 15.1 percent ash, 2680 TPD, ash are produced. Since 6.7 TPD is. released to the atmosphere*as particulate, 2673 TPD remains as solid waste for disposal. Based on,17700 GPM.net makeup H 0 (8300) and an assurfied.500 PPM suspended,solids.whicA is.. completely removed by lime treatment and,clarification, an additional 53.2 TPD of solid waste is generated. From (8304) an ammonia still 'is estimated to produce 115 ton/ D of still waste It'is assumed that all bio-treating fF, sludges'are used as boiler fuel..The'sum total solid waste produced is thus 2841 TPD or 6563 ton/l.OE12 Btu., 8412 Land requirements are assumed to-be 350,acres from (9401,7) for coal storage, preparation, and gasification plant facilities. Since High Btu-Coal Gasification,is assumed to be a mine"mouth,activity, all solid waste produced is.returned to the mine,for burial. There is, therefore,.no incremental land impact due to solid waste production. Thus a total of 350 acres is required.for a 17,749 TPD coal.,gasi.fication opera- tion. With a 90 percent operating factor this is equivalent to 2.46 acre-yr/l.OE12 Btu. However, a larger land impact would be produced if solid wastes were not returned to the mine.for burial. (See, footnote'.8411 for solid waste.) FTN. 8413-8414 8413 From (8305i63) the total heat demand for a plant producing 235.8EO9 Btu/D'of SNG is 2299 TPD coal and the TPD coal to the gasifier'is-12224. This analysis is for a West Kentucky seam coal with a 84.9 percent volatile matter and fixed carbon,and a heating value of 12330 Btu/lb. Based on footnote 8400 and the assumption that the gasifier outputs are the same for equivalent TPD of volatile matter and fixed -carbon inputto.the gasifier (s'ince these'are the reactive constituents in the coal),the Northern Appalachia -analysis would require 12595 TPD coal to the gasifier.' Based on the assumption that the total plant heat demand is relatively constant for the various bitumi *nous coal inputs, 2179 TPD coal is required for boiler fuel (with no coal drying)-. Thus A total of 14774 TPD coal is required to produce-'235.8EO9 Btu/D SNG for a primary efficiency of .654. No light or heavy oils'.aZe reported as by-products for'this process- -The ancillary,energy is zero because the plant is self- all power and-steam requirements generated on-site. 8414 The principal quantifiable Air pollutant sources are as follows: TPD Part. Sbx CO HC NOX@ Other Fuels Combustion 1.32 2.69 1.09 .327 19.6 .00545 Sulfur Recovery Plant: 3.60 Storage and Misc. ..142 Fuels Combustion' Based on air emissions factors,in (8301,1.1-3) and the combustion of 2179 TPD of coal (1501 percent ash, 1.3 percent S).. Particulates were reduced 99.5 percent by the use of an electrostatic precipitator and a Wellman Lord wet scrub, while S02'emissions were reduced 95 percent by the Wellman-Lord unit. IV-49 FTN. 8414 (cont) Sulfur, Recovery,Plant Based'on the use of:-the Hot Carbonate.acid,...gas, removal system for nonselective removaLof,H2S and C02 from the syqnthesis'gas stream .a.dilute(5 percent,q) H2S gas- 2qp stream can be sent,to the@Claus.-plant.2pr@recovery and. -,from (8303,AI-25) this Claus.unit,can.recover-84 percent of the incomingS. The incomingpp2precovery is-based: on 12595 TP0qD coal to1pgasifier.3 percent.S.in the coal, and all of he S to'the-gasifier-as_H2S to-Claus. for recovery.from(8305 '61). Basedpthermore, on complete recycle. to- Claus@ of,, all. the., S02,;qrecovered An e Wellman.Lord prubbing.units on.the boiler flue. ..gases and-Claus,tailgases, 223,TPD.S is in.the.Claus feed. Thus 187 TPD S is recovered for leor 520 ton S/l.qO4qE12 Btu. Since.36 TPD S passes.to the Wellman.@0qLord tailgas scrubbing unit, 1.8 TPD Sr.3.6 TPD S02 exits the stack. Storage and Misc Based on 12224 TPD coaLto the gasifier and q1.37 percent.. N2 in the coal (8305,60,63 'and.7o.percent,of the N2in the feed coal, as.NHj, (q8302q3-X-7), 14.2@'TPD@@.-NH uced 3-q1s prod in the gasifier.This value was l used .for.this .coal analysis. Substantially of this- NHi verq6d,in- 3 is@reco a free and fixed@moniqa., still..., From, q18,30q1: 5.2-2) controlled storage,and loading,operations,emit.two lb 2qof NH3/8qtonNH-3.. Thus .142,TPD,NH3are-qr.eleased2pto the atmosphere.* It should-be noted, that!. other,', sources@:-of-.;ir -pollution will be, present.in any Fomme-rc-ial,,c.o-a-gasfication operation, although.their quantifqication is not possible at present. These-sources include but arenot .limited. to, coal and other solids,preparation*a d-transfer operations .vents tacks for,waste gas,,disposall, pipeline valves and flanges and pumpand-compressor se als. The magnitude of these:air pollutants,,,,however, should not be that large -if the sources-,*a-re: properly - -cont6qro 1 led. IV- 5.0 FTN. 8415-842*0 9415 Based on 14774 TPD coal with 15.1 percent ash, 2231 TPD ash are produced. Since 1.3 TPD is released to the atmosphere as particulate, 2230 TPD remains as solid waste for disposal. Based on 10385 GPM net makeup H20 (8300) and an assumed,500 PPM suspended solids which is completely removed by lime treatment and clarification, an additional 31.2 TPD of solid waste is generated. From (8304) an anmionia still is estimated to produce 115 TPD of still waste. It is assumed that all bio-treating sludges are used as boiler fuel. The,sum total solid wasteproduced is thus 2375 TPD or 6592 ton/l.OE12 Btu. 8416 Land requirements are assumed to be 350 acres from (9401,7) for coal storage, preparation, and gasification.plant facilities. Since High Btu Coal Gasification is assumed to be.a--mine-mouth activity, all solid.waste produced is returned to the mine for burial.. There is, therefore, no incremental land impact due to solid waste-production. Thus.a total of 350 acres is required for a 14774 TPD coal gasification opera- tion. With a 90 percent operating-factor this is equivalent to 2.96 acre-yr/l.OE12 Btu. However, A larger land impact would be produced if solid wastes were not returned to the mine for burial. (See footnote 8415 for solid waste.) 8417 Primary efficiency and ancillary energy for this process are an arithmetic average of those for the Hygas-Electrothermal, Hygas-Steam Oxygen, Bigas, and Synthane processes. 8418 Air pollutants for this process are@an arithmetic average of those for the Hygas-Electrothermal, Hygas- Steam Oxygen, Bigas, and Synthane processes. 8419 Solid waste production for this process is an.arithmetic average of those for the Hygas-Electrotherma,lp Hygas- Steam Oxygen, Bigas, and Synthane processes. 84@Q Land utili.zation by.this process is an arithmetic average of those used by the Hygas-Electrothermal, Hygas-Steam Oxygen, Bigas, and Synthane processes. IV-51 FTN. 8421 8421 Water pollutants are based on the following process waste water analysis: Contaminant Waste,Water-PPM Reference 0qEff.luent-PPM Plqhenols 1700 (8307,4) 0.006 Cyanide 0.6 (8 8q108q3 -,q4) 0.3 Thiocyanates 188 (830q7,A) q0.q0 NH .17040 Calculated. 7.0 Sufide 1400. (8q102q7q4 4) - 0.01 oil. 1100: (88q303,0qK-3) 3.7 Sus.Solids 600 (8307,4) 4_6q1 The following waste water -treatment system was..utilized to achieve the above'effluent values,--3 stages of oil- water separation, dissolvedaiq; flotation., free and fixed ammonia stills, equalization, activated sludge and clarif ication., and char- polishing. tower,._ Three, stages of oil-water separation,, were used to :insure comRq1ete separation of the:.tars@;and process@waste,water.p'310, III- Anq(air flotatqionl.unit-was,us'ed ,to-further remove oil'. and- suspended. solids (.831@1,3.21.).-Bas@ed-:2pn.,coke plant experience (112q19), (8312),and@(831:3,61-8)mmonia removal appears to-be,the key-qt2qp treatment of weak ammonia water Is very liquor. Since.-the above proces qa-waste similar to qWAL, a free and -fixedi*ammonia,sti1l'operation was, employed. Phenol6qbiodegradation in-an Tactivated - I sludge unit has,been succesfully demonstratedpn coke plant WAL(8312,202)'.. CompleteT:thiocy.an-ate.rem6val is possible by biodegrad-ation-:of 8qLthat,has-previously been-deammoniated(8313I6l.8)PDtemissions-are based on 1 ton H 0/ton coal. to the: gasi8qf, ier . f or-,--a Typical New rocessil5370 TPD)and0 percentof thisH 0 as process waste water condensate(9220P8qDq)' from 0q18312qfq). other. dissolved,solids TPD emissions are-based-on a Typical New Process makeup H20.requirement of 9800GPM (8300), an assumed influent TDS loading of.8q5q0q0 PPM and..a contribution of other dissolved-solids.-by the- gasification facility of,50,per,ce6qnq.q.20qt4q@6qOf-the.q,incoming TDS (similar to-refinery operations 'q(831q'7q-q@q,q@6q8) and, also from (1900)). These ODS are.contribute32qd-q-'by ion@'exchange regq'enqerants, treat40qin32qgq,q-chemicalsq., corrqasioniand scale inhibitors, etc.,Organics comprisqe@phenols. and oil, while total dissolvec8qLq.solids inclucDes.,cyanide, thiocya24qnates, NH3q, sulfide,,and-,.,other.,dissolved solids. waste water system removal.ef-ficiencies: were@.developed from (2013q,4qI24qVq-3),,(8316,172) (8318,Table 7) and56qA8313, 609,618).-Tons/l.2qOE12 Btu based@on an average@plant.input FTN 8422- of 16980 TPD coal. 8422 Capital and operating costs-were developed as follows: Capital costs-1972 $-Plant Basis-14,800 TPD, 90 P LF From (8300), escalated from 1971 $ to 1972 $ at 5 percent, costs for the feed system, gasification and Co shift, methanation 0 2 manufacture, steam and power plant, general utilities,-and general offsites total 119.2EO6 $. From (8305), escalated at 5 percent/year from 1970 to 1972 $, costs for coal storage and preparation and gas.purification total 44.3EO6 $. Water pollution control costs were estimated at 11.7EO6 $ with oil-water separation and dissolved air flotation costs from (2013,VII-5)costs for free and fixed-NH- stills, equalization, activated sludge. plus clarifition, and char polishing from(8304), and a miscellaneous allowance (2.10qE66 $) for water impounding basins, thickners, settlers, etc. from (8315). Sulfur recovery costs were estimated at 8.7EO6 .$ from (8300) and (8303,AI-25,AI-26). To the subtotal were added a 15 percent (of subtotal) project contingency and a 7 percent (of-subtotal) development contingency to arrive at a total plant investment of 2242qAE06 $.,Based on 'a 0qFCR.of 10 percent/year and 4.85EO6 TP6qY coal this is equivalent to 1.89EqO,5 $/ 1.OE12 Btu. 'Operating Costs-2q1972 $-Plant Basis-14',800 TPD, 90 P.LF From (8300) the following costs were taken directly other rawmaterials, catalysts and,chemicals_, purchased raw H Of and processope rating labor-for a total of $.0536q@1.OE06 Btu gas. From (8303,AI-5) maintenance labor was based'on 1.5 percent/year of total plant investment of supervision labor was based on 15 percent Of process-operatinq and maintenance labor, administration and general overhead was based on 60 percent of total labor, operating supplies were based on-30 percent of process operating labor, and maintenance supplies were based on 1.5 percent/yr of total plant invest- The total gross operating.cost is thus $.1995/ -2q1.2qOE06 Btu gas or 15.40E8qO6 $/yr for a 235.8E8qO9Btu/D 0qS6q@NG plant. By-products are credited at $10/20qLT for S (167.3 LTS/D) and $25/T NH , (142.3.TPD NH ) from (8303,AIq- 5). The total net operating cost is thqiref2qo,req,$13.6q8E8qO6/yr or,for a 4.85E8q06TPY coal input, 1q.15E2qO5 $/8ql'8qOE12 Btu. IV-53. FTN. 8423 8423 Capital and operating costs wore-developed as follows: Capital Costs 1972 $-Plant-Basis-18,200 TPD, 90 P:LF 971.$@to1972 $ at 5 From (8300), escalated,from 1 percent, costs for coal storage and preparation, pretreatment, feed system,.gasification and CO.shift, methahation, steam and,power plant,-general utilities, and general offsites 'tqdta2qL_l75.6EqO6.$. From. (8300) cost, for gas purification is.estimated at22'-9EO6 $. Water pollution control costs iwq6re.:estimated at 11.7EqO6 $ with bil-water qs4qoparation-And-dissolved air flotation costs from (,20l3,VII-5),costs -for'free and fixed NH stills, equa'lization .activated -s2p2pp1pge plus clariqfqi2qh@ tion,@and@qch4qar:polishing from (8304), and a 8qmis6qdellan- eous allowance.(2.lE:0'q6 $q) for.water.impounding,basins, thickelners, settlers, etc. 'from 03'8q18q5q).-Sulfur recovery costs'were estimated'at 13 8EO6 $-from (8300)nd (8*303,AI-25,AI-26). To the* subtotal were added a 15 percent (of subtotal) Project contingency *and a 7 percent (4q6fq@"subtotal)-development contingency to arrive Of q2q13q:;3EqO,6$.0qBased on a at a- -total plant -investment .4 8qF2qCR of 10 percent/yr@:and 5.2q46EqO,6@TPY coal this is. equivalent "to l6qZ,8'8q90 5 @, $/l,. qOE12 .-,,Btu. Operating C2qosits-q1972 -$-Plant ;Basis-!.!18,.200,TPD 90 P LF From-(8300) tqlqie@following"costs were-taken directly- other raw materials, 'catalysts ,and '-chemicals, Purchased raw Hq0, and-processqlq5erating-labor@for a total of _0q@l.qOE06 ' I $ 04q8, Btu gas. From (8303.'AI-5) maintenance labor was qAsed on l..@5@perceqn't/yr-of"total,p,lant investment, supervision labor 0qwas.-based on,15 percent of process ting'and-maqiinteqna-nce.1-aboradministration and opera, general o2qV0qo6qrh2qead@was based 60 percent of total labor, operating supplies were based.on 30percent of process operating labor .and .maintenance supplies were based on 1.5 percent/yr of total plant-investment. The total gross operating cost_is@thus $.q-2155/1q.qOE06 Btu gas or 17.90EqO6 $/yr q@f or a 25 3. 3E8qO9 -'-Btu/D- SNG -plant.- -.By-products 'are cred36qi Ited At $10/24qLT"f00qor S (145,3q1q'20qLT32qS/D2q), $4/LT f6qorq,S20qO 2 (8q-3.48q0 LT S24qO56qi/D) $25/T NH 2q(32q165q"44qM NH 3), $.15/gal fox q'2q5 03.q.GPD0q)qraqnd 0/1.q*2qOE06 q@q,B - B-T-X (52q. tu for tars (9.84E8qO9 Btu/24qD,6q) from (83036q"A8qI6q-56q). Theq.total,net operating cost. is tl0qiereforeqrq,q,12 q*40E2q06/yrq:q'or, for a 5.96E,06 TPY coal input, 8.54E8qO4 $/l.8qO24qE12q,Btu. IV- 5 4 FTN. 8424 8424 Capital and operating costs were developed as follows:. Capital Costs-1972 $-Plant Basis-17,300 TPD, 90 P LF From (8300), escalated from 1971 $ to 1972 $ at 5 percent,costs for coal storage and preparation, pretreat- ment, feed system, gasification and CO shift, methanation, oxygen manufacture, steam and power plant, general utilities, and general offsites total 132AE06 $. From (8300).cost for gas purification is estimated at 22AE06 $-. Water pollution control costs were estimated at 11.7EO6 $ with oil-waterseparation and dissolved air flotation costs from (2013,VII-5),costs for free and fixed NH stills, equalization, activated sludge plus clarifiLtion, and char polishing from (8304), and a miscellaneous allowance (2.lEO6 $) for watdr impound- ing basins,.thiPkeners, settlers, etc. from (8315). Sulfur recovery costs were estimated at 13.IE06 $ from (8300) and (8303,AI-25,AI-26). To the subtotal were .added a 15 percent (of subtotal) project contingency and a 7 percent (of subtotal) development contingency to arrive at a total plant investment of 219.7EO6,$. Based on a FCR of 10 percent/yr and 5.67EO6 TPY coal this is equivalent to 1.59EO5 $/l.OE12.Btu. Operating Costs-1972 $-Plant Basis-17,300.TPD, 90 P LF From (8300) the following costs were taken.,directly- other raw materials, catalysts and chemicals, purchased. raw H 0, and process operating labor-for a total of $.046@1.OE06 Btu/gas. From (8303,AI-5) maintenance labor was based on 1.5 percent/yr of total plant investment, supervision.labor was based,on 15 percent of process operating and maintenance labor, administration and general overhead was. based on 60 percent of total labor, operating supplies were based-on 30 percent of process operating labor, and maintenance supplies were-based on 1.5,percent/yr of total plant investment. The total gross operating cost is thus $.1886/1.OE06 Btu gas or 'SNG plant. By- 15.30EO6 $/yr for a 247.2EO9 Btu/D, products were credited at $10/LT for S (129.7 LTS/b), $4/LT for SO2 (60.9 LT SO2/D), $25/T NH (147.5 TPD -NH 3)" $.15/gal for B-T-X (46EO3 GPD), and '$.3d/l.OE06 Btu ,for tars (8.84EO9 Btu/D) from (8303,AI-5).The total.net operating cost is therefore $10.43EO6/yr orl fo'r-a 5.67 E06 TPY coal input, 7.55EO4 $/l.OE12 Btu. IV-55 FTN 8425 8425 Capital and operating,costs"were@,developed as follows: Capital Costs-1972$-Plant Basis-12q3,7q60. TPD,.90 P LF From (8300), escalated from 1971.$ to.1972 $ at 5 percent, costs for coal storage and preparation, feed system, gasification and CO shift, gas,purification,-. methanation, compression, oxygen manufacture, steam and power plant, general utilities and general offsites- total l53.8EO6 $. Water pollution-control costs were estimated at 11.7EqO6.$ with oil water separation.and disso1ved air.. flotation, costs from: (20:13',VII-5), costs- for freeand fixed N-H sti0qIil6qs f equalization, activated slud4qq2qp.plus clarfication,. and char.-- polishing f rom (8304q), and a miscellaneous allowance (2.lEqO,q6'$q) for water @impounding,.basins thick eners settlers, etc. from (8315). Sulfur.recovery costs were estimated at 14.96qk'06 $ from (830,0) and (830q310qXI-25,AI-26). To the subtotal were-added@a 15 percent (ofsubtotal) project contingency and.1.7 percent.(of.subtotal), development contingency -to arrive at. a :total plant investment of 220.1EqO6 $_ Based on,-a-FCR of. 10.'percent/yr and 5. 83E'06. TPY coal -this. is:, equivalent*- to71.55EqO0qS $/ql qOE12 Btu. Operating Costs@-1972- $-!-Plant, Basis-17,6q700 TPD, 90 P L2qP From,q(8300). the, f ollowwing. costs -wer taken. directly cataql2qysts@and chemica1s:,-purchased raw-H28q601 and process operating.labor pr-a,total.of $.064/1.OE06 Btu gas. From (8,303,AI-.-5) maintenance-labor was;based on 1.5 percent/year of total.plant investment; supervision labor was based on 15 percent-of process operating and maintenance .labor j administration and general overhead was based on'60 percent.of total labor ,operating suppli- es were based on.30@ Percent ,ofppoces,s-operating labor, and maintenance supplies were?based!on 1.5 percent/year of total plant investment. The@,tqotal gross operating cost is thus $.2148/1.06q4q,06.Btu gas: or.l6q,.q32Eq,0'q6q. $/yr for a 231.8E2qO9 Btu/Dq@q.SNGq,q,q,.plan28qt.-By-productsqiwere credited at $ 10/I4q@T f or Sq.q, (28q18 7. 5 LTS/D.2q)q@ , $q'25/44q7q@q'NH_3q, (17 3. 6 TPD NH3) $.15/gal for B-T-X 6q(25000 GPD)q., and $-3'0/1q.q.2qOE06 Btu for tars8ql6q(13q.q.9E2qO9 Btu/D2q)-4qfrom,@0q(8303q,q_AI-56q)q-2q: The.total net operatingq.cost isq.20qtherefore $11,62E2q06/76qyr or, for-a 5.8364q406 TPY coal input.q,8.l8E6qO4q.$/l.2qOEl2q@Btu. IV-56 FTN. 8426-8451 8426 Capital and operating costs for this process are an arithmetic average of those for the Hygas-Electrothermal, Hygas-Steam, Oxygen, Bigas, and Synthane processes. 8427 Thermal discharges can be completely eliminated by the use of mechanical draft wet cooling towers. The Central coal used in this study has the following composition on a run-of-Imine basis: Proximate Analysis-WT PC Btu/lb 11364 Ash 11.2 S_WT PC 3.5 water 8.3 Vol.Mat. 37.5 Fixed C. 43.0 For this coal 4400O.ton of coaiis equivalent to 1.OE12 Btu. 8451 From (8300) the total heat demand for a plant producing 253.3EO9 Btu/D of SNG is 113E09 Btu/D and the TPD coal to th'e gasifier is 16754. This analysis is for an Eastern Bituminous coal with 83.4 percent volatile matter and fixed carbon and a.heating value of 12400 Btu/lb. Based on footnote 8450 and the assumption that the gasifier outputs are the same for equivalent TPD of volatile and fixed carbon input to the gasifier (since these are the. reactive constituents in the coal),,the Central analysis would require 17353 TPD coal-to the gasifier. Based on the assumption that the total plant heat demand is relatively constant for'the variousbituminous coal inputs, 553 r"LPD Coal is required for boiler fuel. Thus a total of.17906 TPD coal is required to produce 253.3EO9 Btu/D SNG for a primary efficiency of .622'. This size plant also produces 9.84EO9 Btu/D-of tars and 52-5E03 GPD of light oils .(8300). If these fuels.are considered, then the@overall plant efficiency is .*662-.. The ancillary energy is zero.because the plant is self-sustaining with all power and steam requirements generated on-site@ IV-57 FTN 8452 8452 The principal quantifiable air pollutant sources are as follows: TPD Part. SOx CO HC NOx Other Fuels Combustion 5.59 24.9 2.06 .571 40.4 .00931 Sulfur Recovery PLANT 2.8 Storage and Misc. .165 Fuels Combustion Based on air emissions factors in (8301,1.1-3,1.4-2) and the combustion of 3171 TPD of coal equivalent char (42 percent ash, 2.6 percent S), 553 TPD coal (11.2 percent ash, 3.5 percent S) and 24.3E09 Btu/D waste offgases (containing 25 percent of the total S in the coal to the gasifer). Particulates were reduced 99.5 percent by the use of an electrostic precipitator and a Wellman Lord wet scrub, while SO2 emissions were reduced 95 percent by the Wellman Lord unit. Sulfer Recovery Plant Based ib the use of the Rectisol acid gas removal system for the selective removal of H2S and CO2 from the synthesis gas stream, a concentrated (25 percent) H2S gas stream can be sent to the Claus plant for recovery (8308.21) and from (2022.103) this Claus unit can recover 94 percent of the incoming S. The incoming S for recovery is based on 17353 TPD coal to the gasifier, 3.5 percent S in the coal, and 55 percent of the S to the gasifier as H3S to Claus for recovery (the balance of the S is in the pretreatment offgases and the char) from (8303, X-13, and 8308,27). Based, futhermore, on 30 percent of total S to Claus SO2 (8303. AI-27) from the Wellman Lord scrubbing units, 477 TPD S is the Claus feed. Thus 448 tPD S is recovered along with an additional (to that which the Claus can accept) 242 TPD SO2 for sale. These are equivalent to 1101 ton S and 594 ton SSO2/1.0E12 Btu. Since 29 TPD S passes to Wellman Lord tailgas scrubbing unit, 1.4 TPD S or 2.8 TPD SO2 exits the stack. IV-58 FTN. 8453-8454 Storage and Misc.. Based on 16754 TPD coal to the gasifier and 1.16 percent N2 in the coal (8300)'and 70 percent of the N2 in the' feed coal as NH (8303,X-7), 165 TPD NH3 is produced in 3 % the gasifier. This value was used for this analysis. Substantially all of,the NH3 is recovered in a free and fixed NH3 still. From (8301,5.2--2) controlled storage and loading operations emit two lb INH3/ton NH3. Thus .165 TPD.NH3 are released into the atmosphere. It should be noted that,other sources of air pollution will be present in any commercial coal-gasi.fication operation, although their quantification is not possible at present. These@'sources include, but are not limited to, coal and other solids preparation and-transfer operations,,vent stacks for waste.gas disposal, pipeline valves and flanges, and pump and compressor seals. The magnitude of these air pollutants, however, should not be that large if the sources are properly controlled. 8453 Ba sed on 17906 TPD coal with 11.2 percent ash, 2005 TPD ash are produced. Since 6 TPD is released to the atmosphere as particulate, 1999 TPD remaiiis as solid waste for disposal. Based on 6500 GPM net makeup H20 (8300) and.an' assumed 500 PPM suspended solids which is completely removed by lime treatment and clarification, an additional 19.5 TPD of solid waste is generated. From (8304) an ammonia still is estimated.to produce.115 TPD* of'still waste. It is assumed that all bio-treating sludges are used as boiler fuel. The sum total solid waste produced is thus 2133 TPD or 5242 ton/l.OE12 Btu.. 8454 Land requirements are assumed to be.350 acres from (9401,7) for coal storage, preparation,'and gasification plant facilities. Since High Btu Coal Gasification is assumed to be a mine-mouth activity, all solid waste produced is returned to the mine for burial. There is, therefore, no incremental land impact due to solid waste production. Thus a total of 350 acres is,re-. quired for a 17906 TPD coal gasification operation. With a 90 percent operating factor this is.equivalent to 2.62 ac.re-yr/l.OE12 Btu. However, a larger land impact would be produced if solid wastes were not re- turned to the mine for'.burial. (See footnote 8453 for solid waste.) IV-59 FTN.8455-8456 8455 From (832,00) the total heat.d4qema4qhd1p a plant producing 247.2EO9 Btu/D of:SNG is 4qTq3E09-Btu/D0qand.the TPD coal to., the, gasifier, is 14-957. .This., analysis is, 'for :an Eastern Bituminous -,coal with8q1@ 4,percent- volatile, matter and fixed carbon and a heating value of 12400 Btu/lb. Based on footnote,8450,:anc;the-assumptin that, q1 . s the gasifier outputs are-the..s.a0qme,for.equivalent TPDof volatile and fixed carbon,, input. to,, the - gasifier (since these are)'the.reactive-contituents in the,coal), the Central analysis would;re6qqq@ qa6ql4qre 5492 TP0qD,.coal to the that --0qthe total.plant .gasifier.; Based :on the,assumption .,heat demaqadis-relativel -2qs4qt - for, the various y con Ant., bituminous coal.inputs-, 15 7 5'-0qVPD --coal, is -required for boiler fuel. Thus'a total,of 16q7067-TPD,coal is required to produce 247.2EO9:@:Btu/4qD:,SNG-for a primary,efficy7860;5000;96;132qiency of, .637. 'This .,.size- plant.also produc es8;4.EqO9,Btu/D of, ,tars and.10q46q-2q3EqO3, GP8qD@. of-l0qight i oilqg:q(q$3 If .these fuels are considered, then the..overall plaqiitfficiency is .675. The ancillary energy iszero 6qb0qecause.the plant is self-sustaining.--- with., all power and.. stpam.,ge.6q4erated on- site. The prin0qcipa6qL,6qq4q4antifi4qab-qle,: 8qair:po;2q1u0qtant:@ources -2ppre as follows:.. TPD. Part. SO CO ',HC NO, Other qx Fuels Combustion 8qZ 6 7. 2 l's 8 1.30 .346.'1266qA .00561' Sulfur-Recovery Plant 2i.6 Storage.and Misc. @0q0,q0 q1 .148 Fuels.Combustion Based on air emissions .factors . in q(.83.0l,,l.'1-3,1.4-2) and ..the combustion of.668 ,TPD of-coal equivalent char (73-, percent lash,. 4.6 7-percent S) , l57.6q5"TPD,. coal All. 2 percent ash, 3.5 percent@.S.q),,,and,21,.q6E.0,9--Btu/Dwaste offgases. (containing 25 to the percent q@of q_t2qheq,2qto0qta,l S inq,q@-q-0qthe, coal g4sif ierq-) Particulates q-08qv04qeqi4q@eqf 20qr16qeduceI52qd,:99_.5,.-percent by the use of an electrostatic. pr ec 0qip32qIt20qator-q, .-and,. -a Wellman.Lord wet scrub, while- S24q02q. q'em40q1ss ion @6qwere q@q.2qre32qd16quced 0q@98q5q- percent by the Well1man.Lord -unit. FTN. 8456 (Cont) Sulfur Recovery Plant Based on the use of the Rectisol acid gas removal system for the selective removal of H2S and C02 from the synthesis gas stream, a concentrated (25 percent) H2S gas stream can be sent to Claus for recovery (8308,21), and from (2022,103) this Claus unit can recover 9.4@ percent of-the incoming S.,-The incoming S for recovery is based on 15492.TPD coal*tb the,gasifier, .3.5 percent S@coal, and 55 percent of the S as H S to Claus for,recovery (the balance of.the S is in tAe pretreatment offgases and the char),from (8303,X-13, and 8308,27).. Based, furthermore, on 30 percent of total S to Claus as S02 ('8303,A!'-27) from the Wellman,Lotd scrubbing units, 426 TPD S is the Claus feed.-Thus 400 TPD,S is recovered along with an additional (to that which the Claus can accept) 207 TPD S02 for sale. These are equivalent to 1031 ton S,and-533 ton S02/1-OE12 Btu. Since 26 TPD S passes to the Wellman Lord tailgas scrubbing unit, 1. .3 TPD S,or .2.6 TPD S02 exits.the stack. Storage and Misc. From (830b) 4.631@04 GPD of. light oils are produced. Assuming 2 weeks storage capacity under new tank conditions.and emission factors from (8302,4.3-8), .001 TPD HC are emitted. Based on 14957 TPD coal to.the gasifier and 1.16 percent N2'in.the co 'al (8300) and 70 percent of the N2 in the feed coal as NH3 (8303,X-7),' 148 TPD NH3 is produced in the gasifier. This value was used for this analysis.-Substantially all of this NH3 is recovered in a free and fixed NH3 still- From (8301, 5.2-2) controlled storage and loading operations emit 2 lb of,14H3/ton NH3 Thus .148 TPD NH3 are released into the atmosphere.. It should be noted that other sources of air pollution will be p"resent in any commercial coal gasification operation, although their quantificat7ion i's not possible at present. These sources include, but are not limited to, coal and.other soli,ds pre .paration and transfer operations, went stacks for waste gas disposal, pipeline- valves and flanges, and pump and compressor seals. The magnitude of these air pollutants, however, should not, be that large if,the sources are properly controlled. IV-61 FTN. 8457-8459 8457 Based on 17067'TPD coal with 11,2percent ash, 1912 TPD astmosphere produced. Since 3 6qtPqlqb is'releasedto the qd4qtqm4q6qs4qp0qf0qiere as particulate, 1909 TPD remains as,solid''' -waste for disposal.. Based`:`2qo2qh`4600 GPM net makeup H20 (8300) 8qand assumed 500 PPM.suspended solids which is completely re2qmo6qV2qdd"by,lime treatment an2qd@clarifica- tion, a8qn additional 13.8'0qT8qP8qDof-solid-waste is generated. From*, (8304) 0qaqn',ammonia still is estimated to produce 115 TPD f still waste. It is assumed that all bio- treating sludges are used@4qas boiler,fuel. The sum total solid waste produced is thus 2038 T8qPD-or 5253-ton/l.qOE12 Btu. 8458 Land re6qqu'irqe6qments-a8qke assumed to be 358qV8qacres from (9401,7) -for coal storage, prep8qa0qiati4q6n, and.-2qg0qas0qification.plant facilit qIes. Since.High@Btu Coal-Gasification is assuqined to be-a-8qm in6q&-0qm2qOuth-acti8qVity, all.,s4qblql*d waste produc4qed..is-8qzeturned t4qo-theine.f4q6r burial., There is, therefore, no i6qf6qi'4qc4qk2qbqiqfqi8qbntal land im act due to solid 2qp waste production. Th6qu*s@a total,of 352q0-acr4qes-is re- quired6qtor a qi7q6q67 TPD-coal.gasif0qi0qcat0qion operation. With a@,90 percent operating factor thiss equivalent to 22p'acre-yr/l-.-,qOEl2 Btu. H6qbwever,,a.larger land impact q1,qw0qouqld-, be produced If:` 4qso6q1d 6qw2qa,st4qeqs-,4qw6qere not re-. 4q'dq't -the- (S8qde.footnote'8457 turn0qe q@ 0 mine f0qor burial. for solid qWa6qs4qt".qiiqe-2q0 d2p 8459 From 1p300) land (48-309) the :-.total heat demand for a plant producing 23l2qA8qt0qO 8qBt6qu8q/D of -S2qNG 0qis 116-.:34qEqO9 Btu/D and the TP8q6 coal''to the:6q4a8qsqi-qfi8qer i4qt@ 16q&0q5,94. 'This Analysis is. for an4qZastern Bi0qtquqmiqrqi64qus,2qdo6qd2ql with @2q4q6 9-. percent volatile, matter 8qan'd 8qf i6qk-ed c2qa8qkbonn4qaqxid. a heating value of 12400 4q8tu/1b. Based on-.f2qbot:qh(qjte--8'q450and the assumption that the gasifiqcqir 4qOqiqit6qp@uts@'a2qt4q6"-t.'he;.qt;,4qA0qme':for equivalent TPD of volatile ''And- 2qf6q14qked'- c8qa8qkb2qon input to -the gasifier (since these are* the 6qke-6qac@t6qive.q:@q@4qdn,-s't-itue6qh,.ts in the coal) the Central analysis- would,- 8qk0qe2qq8quire1pp2p2p5.4 - TPD coal to the gas6qifi2q6r'.* Based 2qon 'the2qas2qsu2qm8qption, 'that @the, plant heat dem'and:is re2qA6qitively4qdo8qhq6tbqint f6r'the"varqious bituminous coal inputs, 1831 2qVPD "coal is-reqquired:f6qor boiler fuel. Thus atotal of 172q585-8qVPDcoal-is required to produce q.231. qSE09 Btu/D 0qZNG for a primary -qOf f8qi2qc-2qilency of. .580. 'This siq-ze'plant al q*so* 72qp32qk6du20qd24qbs l3q.-q.q'9,E8qO9 16qStu/D of tars (2q9300), and 25000 -GPD q*q*24qof 'light o36qi-32q1q-s - (8-307,6) . If these fuels 28qAre-con6qsid'er52q6d, t36qhen-theq.q-ov0qi0qerall-plant efficiency ,becomes .621. Theq:q@40qAncillaryq:q@e28qhergyq,is,q'zq4qE6qiroq,because the plant is q's04qelf-s44quq.0q4tai32qh40qi36qhq' "with 00qal32qL powe16qr:-and steam 32q9 r04qequir'68qements g36q648qh40qd40qr0qa0qCt`44qdd,onq@q-q@6qsiteq'. IV-6 2 FTN. 8460. 8460 The-principal quantifiable air pollutant sources are as follows: TPD Part. sox CO HC NOX Other Fuels Combustion 5.87. 9.93 2,48 .742 44.5 ..0124 Sulfur Recovery Plant 10.8 Storage and Misc.. .174 Fuels Combustion .1.1-3) and the Based on air emissions factors in (8301 combustion of 3110 TPD coal equivalent char (40.6 percent-ash, 1.3 percent S) and 1831 TPD coal (11.2 percent a8h,3.5 percent S). Particulat 'es were reduced 99.5.percent by the use of an electrostatic.precipitator and a Wellman Lord wet scrubwhile S02 emissions were reduced 95 percent by the Wellman Lord unit. Sulfur Recovery Plant Based on the.use of the Hot Carbonate 'acid gas removal system for nonselective removal of H2S and C02from the synthesis gas stream, a dilute (5-percent) H2S gas stream can be sent to,the Claus plant for recovery, and from (8503,AI-25) this Claus unit can recover 84 percent of the incoming S. The.incoming,S for recovery is based. on 15754 TPD coal, to'the gasifier, 3.'5 percent 8 in the coal, and 87 percent of the S to the gasifier as H2S to Claus for recovery (the balance.of..the Slis in the char (10:percent)-and-tar (3 percent)) from (8307,9). Based, furthermore,.on complete recycle to Claus,of all the S02 recovered in the W611man,Lor'd scrubbing units on the boiler flue gases and Claus tailgases,-676 TPD S is the Clkus feed. Thus 568 TPD S is recovered for sale,or 1421 ton S/1.OE1.2 Btu. Since*108.TPD S passes to the Wellman Lord tailgas scrubbing unit, 5.4 TPD S or 10.8 TPD S02 exits the stack. IV-63 FTN. 8461-8462 Storage and Misc. Based on 14 5 9 4TPD coal t6qa1pe, gasift-8qer and 1. 4 percent N2 in the coal (830-0)'and ('8309) and 70, 4qp4qercent of.the N2 n the feed coal as-0qAq@ @,q(83'03',X`7)1p74`TPD NH3 is produced in the-2qgasifier.' This value was used f4qor this coal analysis" 'Sub's tanti a 2qIql0qy -alql- of this, NH3 As recovered.in a free-and fi6qxe6qd-a0qmqrrqfonia-still.q@ From q(8301,5.21 2) controlled storage a0qnd loading-6qpperat6qkons emit - 2 11b of N3/t8qbn'N0qH3. Thus_174 TPD-NH3 are released Into the.:, atmosphere.' It should be noted that other sources lof.@ air, pollution will-be present1pn,an qC' qxal- coal: 4qga0qs'if ic8qation 4qommer6qd operation,' although'' their', q6qu2qanti8qfi0qcaqit6qio4qn is.,-,not possible at preserqit.'ThqiqBse-2ppurces.-i@nclude,:-but--.a@rel@not limited to, coal qiand other solids, p2qvEqiparaq:,tion.,-and-. transfer operations, vent - st0qa0qc-k,,'s-,:f or@ waste 'gas disposal, pipeline valves a4qhd@flanges,@-4qand 'xqimp qand,.c2qomp0qr.q4q2q@ssoqr' s,ea1s. The 0qp magnitude of these air pollutants, however, should not be that 1arg0qe,iqf.2ppe.-1Sources- ,are- properly @,co0qn4qtro 1 led. 8461 Based on,17585 TPD coal with 11.2 percent ash 1970 TPD *ash are produced. 'Since-6 T-PD is released i2qnto@,the aqctmosphere.as"partipulate, l966qt-'T6qPqEq)'r6q6qr4qkqf2qxqrqfs -as- solid waste for d0qxsp6qas-al.@.Based,on 'q1'q7'7@qOqO.-1pp2qV4qM:zqiqcqiqBt-,0qMa-keup H20 qz4qsq@,s q@q0q0 q'2qP8qP2qM"s6quspe4qnd2qe6qd @,qs0qbql_ids which is. (83'00q) a-rid an@ 0qc 0qm 4qu2qm2qb qiqcation@@ ;132qo comPletely-removed -s an additional 6q50q1-.2 ,8qz4qpp,@ 6qo8ql,--6qsolqid, w0qa generated. From' '(8304) a4qn am6qmonia`@ 8qUll, ,is. -2qe'qs,-ti6qmat2qed:. t I Is 1 6q6 produce 115 TPD of s0qti 11 waste. , It: i's ., 6qas0qt6qu6qMed - that, al 1'..bqio,- treating sludges :a0qre. us,8q6d,:@.as-:2qh60qile0qr fuel. The_0q9U2qz:,t8qo4qtal solid waste produced.. i1qs, thus.. 2.q16qJq2 TPD. .'or 6q5-q:q334-t2qon/ql. qOE12' Btu. 462 Land requirementsr-4qa0qxe% -assumed, to -b8qo- 0q150 4qacqries from (9401,.7q) coal storage,, preparation,.: a8qh2qd-gaq:s6qiq;6qf-6qRq:4q@-tion -plant T 6qP. 1@ ". qf. qa8qt. 'facilities. Si n2qce High, 8qBtuq:,Coal Ga0qzi qd4qca, ion is assumed -to be,.. a 2qmine-0qm0qouth activity, - -all sb0q1i6q&'2qw0qWste "'produced is returned to the-.0qmqine,f2qor burial. 'There,is, there- fore, no, incremental land, impact- due. to@-.solid waste production. Thus a total of 350 acres us required for a 17585 TPD.coal gasification operation.With a 90 percent. operatingq-factor this is equivalent to 2.67 acre-yr/l.6qOE,12 Btu., However, a-.larger land impact,would be produced if_solidq.wastes werenot returned to the mine for!32qburial. (See;32qfootnote 8q:4q,61 f24q6r':q,so32q1id waste.)'. IV:, 64 FTN. 8463-8464 8463 From (8305,63) the'total heat.demand for a plant producing 235.8E09 Btu/D of SNG is 2299 TYD coal and the TPD coal to the.gasifier is 12224. This analysis is for a West Kentucky,seam coal with 84.9 percent volatile matter and fixed carbon and a heating value of 12330 Btu/lb-. Based on footnote 8450 and the assumption that the gasifier outputs are the same for'equivalent TPD of volatile'ahd fixed carbon input to the gasifier (since these 'are the reactive constituents in the coal), the Centra*l analysis would require 12892 TPb coal to the, gasifier. Based on'the assumption that the total planti heat demand is relativE@ly constantfor.the various bituminous coal inputs',,12338 TPD coal is required for boiler fuel and-156 TPD is needed for coal drying. Thus a total of 15386 TPD coal is required to produce 235.8E 09.Btu/D SNG.for a primary efficiency of .674. No light or heavy'oils are reported as by@products,f6r this pro6ess. The.'ancillary energy,.is zero because the plant .@is self-sustaining with all,power and steam requirements generated on-site. .8464 The principal quantifiable' air pollutant sources are as follows: TPD Part. sox 'CO HCI NOX Other Fuels'Corabustion 1.66 18.7 1.17 .351 21.9 .00585 Sulfur Recovery Plant 9.8 Storage.and Misc. .142 -Fu'els'Combustion .Bas.ed@on air emissions factors in (8301,1.1-3) and the combustion of 2,338 TPD coal (11.2 percent 'ash, 3.5 percent S).* Particulates were reduced 99.5 percent by the use of an electrostatic precipitator and,a Wellman Lord wet scrub, while S02 emissions were reduced 95 percent by-the Wellman Lord unit. Particulate emissions in compliance with the New.Source Performance Standards for coal thermal dryers arp limted to .03 grain/DSCF (li2l). Based'on 24000 DSCF/ton dry coal input to the dryer (1121) and 11,822 TPD dry coal to the dryer and gasifier, .608 TPD of particulates are emitted.-Based on .535 lb NOx/l.OE06 Btu coal fired (1121), 3.5, percent S coal, and 1.56 TPD coal,for dryer fuel-, .948 TP.D NOX and 10.9 TPD S02 are als6 released from.the Ithermal dr:Ver. IV-65 FTN. 8464 (cont) Sulfur Recovery Plant Based on the use of the Hot Carbonate acid gas removal system for nonselective removal of H2S and CO2 from the synthesis gas stream, a dilute (5 percent) H3S gas stream can be sent to the Claus plant for recovery and from (8303, AI-25) this Claus unit can recover 84 percent of the incoming S. The incoming S for recovery is based on 12892 TPD coal to the gasifier, 3.5 percent S in the coal, and all of the S to the gasifier as H2S to Claus for recovery from (8305.61). Based futhermore on complete recycle to Claus of all the SO2 recovered in the Wellman Lord scrubbing, units on the boiler flue gases and Claus tailgases, 619 TPD S is in the Claus feed. Thus 520 TPD S is recovered for sale or 1487 ton S\1.0E12 Btu. Since 99 TPD S passes to the Wellman Lord tailgas scrubbing unit, 4.9 tpd S or 9.8 TPD SO2 exits the stack. Storage and Misc. Based on 12224 TPD coal to the gasifier and 1.37 percent N2 in the coal (8305,60,63) and 70 percent of the N2 in the feed coal as NH3 (8303,X-7), 142 TPD NH3 is produced in the gasifier. This value was used in this coal analysis. Substantially all of this NH3 is recovered in a free and fixed ammonia still. From (8301,5.2-2) controlled storage and loading operation emit 2 lb of NH3/ton NH3. Thus 142 TPD NH3 are released into the atmosphere. It should be noted that other sources of air pollution will be present in any commercial coal gasification operation, although their quantification is not possible at present. These sources include, but are not limited to, coal and other solids preparation and transfer operations, vent stacks for waste gas disposal, pipeline valves and flanges, and pump and compressor seals. The magnitude of these air pollutants, however, should not be that large if the sources are properly controlled. N. 8465-8467 FT 8465 Based 'on 15386 TPD coal with 11.2 percent ash, 1723 TPD ,ash are produced. Since 2 TPD is released to the atmosphere as particulate-, 1721.TPD remains as solid waste for disposal. Based on 10.3.85 GPM net ipakeup H 0 (8300) and'an assumed SOOPPM suspended solids whic@ is completely removed by lime.treatment and clarification, an additional 31.2 TPD''of solid waste is generated. From .(8304),an ammonia still is estimated to produce 115 TPD of still waste. It is assumed that all bio-treating sludges.are used as boiler fuel. The sum total solid waste produced is thus 1867 TPD,or 5340 ton/l.OE12 Btu. 8466 Land requirements, are assumed to be 350 acres from'(9401,7) for, c'oal-storage, preparation',-and gasification plant facilities. Since High'Btu Coal Gasification is assumed to be a mine-mouth a6tivity,'all solid waste produced is.retu.rned to-the mine for burial. There is, therefore, no incremental land impact due to solid waste production. Thus,a total of 350 acres"is re- quired for a 15,386 TPD coal gasification operation. With a 90 percent operating factor this is equivalent to. 3.05 acre-yr/1'.OE12 Btu. However, a larger land impact would be produced if solid wastes were not re- turned to the mine for-burial. (See footnote 8465 for solid waste,.) 8467 From (8300), and (8311) the total heat@demand for a plant producing 237.OE09 Btu'/D of SNG is estimated to.be 3976 TPD-coal and.the TPD coal to the gasifier is 16.915. This analysis is for a weakly paking.bituminous coal with 74.6.percent volatile matter and fixed carbon and a heating value of 10190 Btu/lb. Based on footnote 8450, the assumption that this coal is not too strongly cakingfor use in a Lur4i gasifier, and the assumption that the gasifier outputs are the same for equival.ent TPD of.vola.tile,and fixed carbon input to the gasifier (since th ese are the reactive constituents in the-coal), the Central analysis would*require 15700 TPD coal to the gasifier. Based on the assumption that the total plant heat demand is relatively constant for the various bituminous coal inputs, 3565 TPD coal is required for boiler fuel. Thus a total.of 19265 TPD coal isrequired to produce 237EO9 Btu/D SNG for a primary efficiency of .541. This-size plant also produces 61700 GPD of light oils (8300). Ifthis fuel is considered, then the overall plant-efficiency becomes-555. The-ancillary energy is zero because the plant'is self-sustaining with all power and steam requirements generated on-site. .IV-67 FTN. 8468 8468 The principal quantifiable air pollutant sources are as follows: TPD Part. SOx CO HC NOx Other Fuels Combustion 1.60 11.9 1.78 .534 32.1 .00889 Sulfer Recovery Plant 4.2 Storage and Misc .001 .187 Fuels Combustion Based on air emissions factors in (8301,1.1-3) and the combustion of 3565 TPD coal (11.2 percent ash, 3.5 percent S). Particulates were reduced 99.5 percent by the use of an electrostatic precipitator and a Wellman Lord wet scrub, while SO2 emissions were reduced 95 percent by the Wellman Lord unit. Sulfur Recovery Unit Based on the use of the Rectisol acid gas removal system for the selective removal of H2S and CO2 from the synthesis gas stream, a concentrated (25 percent) H2S gas stream can be sent to the Claus plant for recovery (8308,21) and from (2022,103) this Claus unit can recover 94 percent of the incoming S. The incoming S for recovery is based on 15700 TPD coal to the gasifier, 3.5 percent S coal, and 98 percent of the S to the gasifier as H2S to Claus for recovery (the balance of the S is in the by-products) from (8310) Based, futhermore, on complete recycle to Claus of all the SO2 recovered in the Wellman Lord scrubbing units on the boiler flue gases and Claus tailgases, 691 TPD S is the Claus feed. Thus 649 TPD S is recovered for sale or 1483 ton S/1.0E12 Btu. Since 41 TPD S passes to the Wellman Lord tailgas scrubbing unit, 2.1 TPD S or 4.2 TPD SO2 exits the stack. FTN.' 8469-8470 Storage and Misc.. From (8300) 6.17EO4 GPD of light-0'ils are produced. Assuming 2 weeks storage capacity.under.new tank conditions and emission factors from (8302-,4.3-8), .001 to the TPD Hc are emitted. Based on 15700 TPD coal 4 gasifier and 1.4 percent N2 in the coal and 7.0 percent of the N2 in the feed coal as NH-3 (8303,X-7), 187.TPD NH@ is produced in the gasifier. Substantially all of this NH3.is recovered in a free and-fixed ammonia still. From (8301,5.2-2) controlled.storage and loading operations emit 2 lb of NH3/ton'NH,3., Thus .187 TPD NH3 are released into the atmosphere. It should be noted that other sources of air pollution will be present,in any commercial coal gasification operation', although their quantification is not possible at present. These sources-include, but are not limited to, coal and other solids preparation and transfer operation, vent stacks for waste gas'disppsal, pipeline valves and flanges, and.pump and compressor seals. The magnitude of these air pollutants, however, should not be that large if the sources are properly controlled. 8469 Based on 19265 TPD.coal with 11.2 percent ash, 2158 ash are produced. Since 2 TPD is released to the atmosphe re as particulate, 2156 TPD remains as solid waste for disposal. Based on 12430 GPM net makeup H20 (8300)'and an assumed 500 PPM.suspended solids which is completely removed,by lime treatment and clarification, an additional 37.3 TPD of solid waste is generated. From (8304) an ammonia still.is estimated to produce 115 TPD of still waste..It is assumed that all bio-treating sludges are used as boiler fuel. The sum total solid waste produced.is thus 2308 TPD or 5271 ton/l.OE12 Btu. 847.0 Land requirements are assumed to be'350 acres 'from (9401,7) for coal storage, preparation, and gasification plant facilities. Since High Btu Coal Gasification is assumed to be a mi,ne-mouth activity, all solid waste produced is returned to the mine for burial. There is, therefore, no incremental land impact due.to solid waste produc- tio'n. Thus a total of 350 acres is required for a 19265 TPD coal gasification operation. With-a 90 per-, cent operating factor this is equivalent-to 2.43 acre-yr/ 1.OE12 Btu. However, a larger land impact would be pro- duced if solid wastes were not returned to themine for, burial. (See footnote 8469 for solid waste.) IV-69 FTN 8471 8471 Water pollutants are based on the following process waste waster amalysis: Contaminant Waste Water-PPM Reference Effluent-PPM Phenols 9960 (8310) 0.498 Cyanide - (8303,S-9) - Thiocyanates - (8303,X-9) - NH3 15900 Calculated 15.9 Sulfide 1400 (8307,4) 1.4 Oil 1100 (8307,X-3) 15.4 Sus. Solids 600 (8307,4) 33.5 The following waste water treatment system was utilized to achieve the above effluent values - 3 stages of tar-oil-water separation, filtration, a Phenosolvan recovery unit, free and fixed ammonia stills, and activated carbon. Three stages of tar-oil- water separation were used to insure complete separation of the tars, oils, and process waste water (8310, III-08- 1). Filtration and a Phenosolvan unit was employed to recover the concentrated phenols from the wastewater stream. A free and fixed ammonia still was used for substantially complete NH3 recovery. An activated carbon system was used for a final polish. TPD emissions are based on 1 ton H2O/ton coal to the gasifier (15700 TPD) and 75 percent of this H2O as process wastewater condensate (11775 TPD) from (8320). Other dissolved solids TPD emissions are based on a makeup H2O requirement of 12430 GPM (8300), an assumed influent TDS loading of 500 PPM and a contribtuion of dissolved solids by the gasification facility of 50 percent of the incoming TDS (similar to refinery operation (8317 8) and also from (1900)). These ODS are contributed by ion exchange regenerants, treating chemicals, corrosion and scale inhibitors, etc. Organics comprise phenols and oil, while total dissolved solids includes NH3, sulfide, and other dissolved solids. Wastewater system removal eficiencies were developed from (2013,IV-3), (8316,172), (8322,1068), and (8318, Table 7). Tons/1.0E12 Btu are based on a plant input of 19265 TPD coal. IV-70 FTN. 8.472-8476 8472 Primary efficiency and ancillary energy for this process are an arithmetic. average of those,for the Hygas-Electrothermal, Hygas-Steam oxygen, Bigas., and Synthane processes. 8473 Air pollutants for this process are an arithmetic, average of those for the Hygas-Electrothermal, Hygas- Steam Oxygen, Bigas, and Synthane processes. 8474 Solid waste production for this process is an arithmetic average of those for the Hygas-Electrothermal, Hygas- Steam Oxygen, Bigas,.and Synthane processes. 8475 Land-utilization for this process is an arithmetic average of those used by the Hygas-Electr6thermal, Hygas-Steam'Oxygen, Bigas, and Synthane processes. 8476 Water pollutants are based,on the following process wastewater analysis: Contaminant Waste Water-PPM Reference Effluent-PPM Phenols 2600 (8307 4) 0.006 Cyanide 0.6 .(8307,4) o.3 Thiocyanates 152 (8307,4) 0.0 NHI 17040 Calculated 17.0 Su fide, 1400 (8307,4) 0.01 Oil 1100 (8303,X-3) 3.7 Sus. Solids .600 (8307,4) 4.3 The fo 'llo@oiing waste water treatment system was utilized to achieve the above effluent values -.;. 3-stages of oil-water separation, dissolved air flotation, free and fixed ammonia stills,,equalization, activated sludge and clarification, and char polishing tower. Three stages of oil-water separation were used to insure complete separation of the tars and process waste water (8310,111-08-1). An air flotation unit was used to further remove oil and suspended solids (8311,3.21). Based on coke plant.experience (1119), (8312), and' (8313,618), ammonia removal appears to be the key to treatment of weak ammonia liquor. Since the ;above process waste water is very similar to WAL, a'free and fixed ammonia still operation was employed. Phenol biodegradation in an ac 'tivated sludge unit has been successfully demonstrated on coke plant WAL (8312, 202). Complete thiocyanate removal is possible by" biodegradation of WAL that has previously.been IV-71 FTN. 8477 deamnoniated (8313,618). TPD emissions.are based l ton H2)/ton-coal to the gasifier'-for a Typical New Process (15370 TPD) and percent,of1pis H 0 as 2 .process waste water condensate(9.2,q20-'1pDq). from (8314). Otherqi, dissolved so-lids @'6qT8qPD-, emssions...are, based o0qn Typical New'Process makeup H20 requirement of 988qM GPM (8300) , an assumed- influehtqTDS.lloading@of '500 PPM, and a contribution of,-other@,dissolvedqsoql-ids by,the gasifcation f acil'i.t6qy -0qof;.50'.46qP'er4qcent% 8qof*,-.the incoming TDS.q(0qAimilar:to ref4qinery@-oper8qations (q02q317,8).and also from 6qJ2q1900)). These,qODS@;are-.4qco0qf0qitr6qinbuted,.by Ion exchange regen2qerants, treating-chemicals-, corrosion and scale' ph inhibitors, etc. Organics4qc6qoqrqfqt2qprise -enols and oil, while-total-dis-8qt0qo6qlv4 solids.includes-cyanide, thiocyanates, NH3 qi sulfide, -and,-@other-_di0qas8qolved solids.. Wast2q6water'system-removal efficiencieswere-deve-loped from 1(q2013,IV,;-3q),, 6qA72), :'q(q82q3181@Table 7) 8.3 16, and (8313, 609,60q18q). Tons/1-6qA2qE12 Btu@-6qIrased,-:0qo0qn@an;8qa0qverage plant - inpu6qV Of 12q69-2q50 coal. 8477 Capital and:"op8qera0qtin0qg.. costs@--w0qareq@-,-d8qeve:@ql@oped- as.fqollows: Capital.Costs-@1972--$-Plant'Basis15.,q400:TPD, 90 P L4qF From 0qA83.0) , to, 196q7-2 $---at 5 percent, costs-:-,-f or, the, f0qee2qd;*sy.t8qem1ppp4qas-i2qf ication and CO. shift 0qmeth4qan 4qiti0qo"n'8q0 6qt 6qactu0qte steam and power 2:@@man0qu utilities, d' ral:-@-'6f8qf sites total plantqj, general -. l0qan - g,ene 2q19.2Eq06 $,. .From (.8 3*0 5) qeq@s6qca6qlaq:t8qed.,@.2qat- 5q@ 2qpercent/year from 1970 to"1972 $,,.0qcos4qt4qs@-for,:'coalvst2qorage and. reparation-,and,.gas,purification-total46..2EqO6 $. Water pollution: conqlq@0qr-ol@-2qd-osts,,w4q@re.@*esti 0qed,,at 11.7EqO6 $ with mat oil-w2qAter iq@eparation.@-and..'.d-issolved@lair ',,flotation costs from qt(2013',VII@-5.),,@c0qoqSts,"for".-free@-a@jqid.',.'fixed'NH3 stills, eq0qualization,:,-,activated sludg0qe,1pplus-cla2qr-if ication, and char . Polishing from (q0304) j @ and, a.,,'@0qMis0qc8q6llaneous allowance q(*2".l2qtq0q6'1$q) -for -water @e impounding: basins, thiqbkqiqeners,sett-qlers,,:'etc.,from@2pq8315q).,Sulfur recovery osts@ were .-estimated,at'14',i":7E062p2p6qomq(8300) "and q183-00q1,AI-250qA%Iq@26) To:. the-., 0qs4qUbt6qotal,@; were --'added a 15 Percent (of'subtot2q@lq)@:-proje'ctcontingency'and-a 7 percent (of subtotal)- development;,qi,-,ontingency'l.to. arrive,at a tota0qL plant - in6qV6qes4qtment,@of .;q234,.'-qO8qEqO Based.on.a FCR of q101 percent/2qyr-.and q5.@ 8qU5EqO 6 !..'TPY-;,@ coal this is equivalent. to q2.04E8qO5 q'$/l_q-q,q-8q048qE1,2-Btu. FTN. .8478 Operating Costs-1972 $-Plant,Basis-15,400 TPD, 90 P LF From (8300) the following costs were taken directly other raw materials, catalysts and chemicals,. purchased raw H 0, and process operating labor for a total of $.053/KOE06 Btu gas. From (8303,AI-5) maintenance labor was based on 1.,5 percent/yr of total plant investment, supervision labor was based on 15 percent of process operating and maintenance-labor, admini,stration andgeneral overhead was based on 60 percent of total labor, operating supplies were based on 30 percent of process operating labor,and maintenance supplies were based on 1.5 percent/yr of. total plant investment. The total gross operating cost is thus $.2049/1.OE06 Btu gas or 15.82EO6 $/yr for a 235.BE09 Btu/D SNG,plant. By-products are credited at $10/LT for S (464 LTS/D) and $25/T NH3'(142.3 TPD,NH3) from (8303,AI-5). The total net operating cost is therefore $13.13EO6/yr or,for a 5.05EO6 TPY coal input, 1.14EO5 $/I.OE12 Btu. 8478 Capital and operating costs were developed as follows:, Capital Costs-197.2 $-Plant Basis-17,900 TPD, 90.P LF From (8300)l- escalated from 1971 $ to 1972 $ at 5 percent, costs for coal storage and preparation, pre- treatment, feed system, gasification and CO shift, methanation ' steam and pow .er plant, general utilities, and general offsites total 175.6EO6 $. From (8300) cost for gas purification is estimated at 22.9EO6 $. Water pollution control costs were estimated At .11.7EO6 $ with oii-waiter sel@aration and dissolved air flotation costs frorC(2013,VII-5),costs for free and fixed NH3 stills, equalization, activated sludge plus clarification,and char Polishing from (8304), and a miscellaneous allowance (2.lEO6 $) for water impounding basins, thickeners, settlers, etc.' from (8315). Sulfur. -recovery costs were estimated at 20.9EO6 $ from (8300) and (8303,AI725,AI-26). To the subtotal were added a 15 percent (of subtotal) project contingency, and a 7 percent (of'subtotal) development contingency-to arrive at a total plant investment of 282.OE06 $. Based on a FCR of 10 percent/yr and 5.88EO6 TPY coal this is equivalent to 2.11EO5 $/l.OE12 Btu. IV-73 FTN. 8479 .'Operating Costs-1972 $-Plant'Basis-17,900 TPD, 90 P LF" From (8300). the following costs'were taken directly-,,-, other raw materials., catalysts. and chemicals., purchased raw H2Q., and process-operating labor'for a.total of Btu gas. From (803,AI-5 maintenance labor was based on 1.5 percent/6qyr of total plant investment,'supervision labor was based on.15 percent. of process operating and:maihtena qnce.labor, administra- tion and'general overhead was based,8qoh 60 percent of total @labor, operating supplies were based 'on 30 percent of process operating labor, and maintenance supplies were based n 1.5er0qce2qnt/yr of total plant investment. The total gross@*operating cost is thus $.2195/1.qO8qE06 Btu gas or 18.22EqOq6.$/yr for a 253.3EqO9@ By-products. A-ire credited at $104q/0qLT for Btu/D' S(400 0qLTS'4q/8qPq) q1. $4/0qLT I f or S02 @ (216 LT. SO /D) , $25/T NH8qI - (0q165 8qtPD NH3), $.15/g4qal 'for B-Tq-0qx .(524q1-2qM GPD), and $.30/1.qOE06 Btu-f8q6r tars,q(9.44qEqO9 Btu/D)from (8303,AqI-5). The total net operating costis therefore $11.72EqO6/yr, or,for a 5.88EqO6TPY coal input, 8.78EqO4 $/l.qOE12 Btu., 8419 Capital and operating costs,'8qw6qd8qtqie, deqvelope as: follows:. capital Costs-1972-plaqn0qt B0q44-.iqis-1q1,100 TPD,' 90 P LF: From q@830,0q)i0qeqscalated from'1971.$ to 1972 $@at 5 6qperce3q@'2qt,coqtts,for:coal stora2qge.,and:,pr0qeparation, pre?- treatment f eled s0qyst,e0qm', ga0qg0qi f icati6qo6qn and- -C4qO shift, metha2qhati0qon,' 8q6x8qy0qge6qn';'2qMi2qaniuqf0qa ctur6qe, steam and power*plant, general utilities-, and`:general 4qof6qfsites total 1326qAEq06 $. From (8300) co.,q@'t,for,1ga-s,@-pqii2qkqific4qa-tion is estimated at 22, 98qEq06-:$._Wat' oll er p 8qution, control. costs,were estimated" 6qAt'I._'l6qIi0q7E.02p1pwi8qthq"qoil-wa8qter separation.and dissolved airflotation costs from (2013,VII-5q),tcqosts for free a0qnd fi8qked NH stills, e6qqiqi4qaliqtation, activated 3 sludg4q6 plus, 2qd2ql4qarif-qicati0qdni-ahd ch4qAr'-polishing from (8304) , and A 8qmqiS8qcel2qIaneo 6q"-@ allowance (2.'lEqO6 $q) for water impounding basins, thickener'qs,.settlers,-etc. from (8315). Sulfur reco2qVery'costs-we6qte"estimated at 206qAEq06 $ from (8300)-and (8303,AI-25-,AI-26). To the subtotal were added a 15 percent (6qof subtotal) project contingency and a 7 percent (24qof subtotal) development contingency to,q'ar28qfive at a total plant investment of 2q,2q28.6E2qO6 $. Basedq'on a FCR of 10 perc04qeqr8qit/yr and 5,61E2q06 TPY coal this is equivalent to 1.8044q9q-05 $/lq.8qOE12 Btu. IV-74 FTN.. 8480 Operating Costs-1972 $-Plant Basis-17,100 TPD, 90 P LF From (8300) the following costs were taken.directly- other raw materials, catalysts and chemicals, purchased raw H20, and process operating labor-for a-total of $.046/1.OE06 Btu gas. From (8303,AI-5) maintenance labor was based on 1.5 percent/yr of total pla 'nt investment, superivision labor was.based on 15.percent of process operating and maintenance labor, administration and general overhead was based on 60 percent of total labor, operating supplies were based on 30 percent of process operating labor, andmaintenance supplies were. based on 1.5 percent/yr oftotal plant investment. The total gross operating cost is thus,$.1933/1.OE06-Btu gas, or 15.70EO6 $/yr for a 247.2EO9 Btu/D SNG plant. By- products were credited at $10/LT for S'(357.1 LTS/D), $4/LT for'S02 (185 LT S02/D), $25/T NH3 (147.5 TPD NH3), $.15/gal for-B-T-X (46EO3 GPD), and $.30/1.OE06 Btu for tars (8.84EO9 Btu/D) from (8303,AI-5). The total net operating cost is therefore $9.93EO6/yr or,for a 5.61EO6 TPY coal input, 7.80EO4 $/.l.OE12 Btu. 8480 Capital and operating costs-were developed as follows' Capital Costs-1972 $.-Plant Basis-17,600 TPD, 90 P LF From (8300Y, escalated.from 1971 $ to 1972 $ at 5 percent, costs for coal storage and preparation, feed system, gasification,and CO@shift, gas-purification, methanation,compression, oxygen manufacture, steam and power plant, general utilities, and general offsites total 153.8EO6 $. WaterpOllution control costs were estimated,at 11.7EO6 $ with oil-water separation and dissolved air flotation costs from (2013,VII-5)r costs for free and fixed NH3 stills, equalization, activated sludge plus clarification, and char polishing from (8304), and a miscellaneous allowance (2.lEO6 $) for wate 'r impounding basins,thickeners, settlers, etc. from (8315). Sulfur recovery costs were estimated at. 23.3EO6 $ from (8300) and (8303,A!-2@,AI-26). To the subtotal were added a 15 percent.(of subtotal) project contingency anda 7 percent (of subtotal) developement contingency to arrive at a total plant investment of 230.3EO6 $. Based on a FCR,of 10.percent/yr and 5.78EO6 TPY coal this is equivalent to 1.75EO5 $/l.OE12 Btu. IV-75 FTN_ 8481-8482 TPD, 90 P LF Operating Costs-1972 $-Plant,.Basis-17,600 From 80300) the following.costs were.taken,dir'ectly catalysts and chemicals, purchased raw' H Of and process ..operating labor-for-a total of $.06 4l..q66qiq06*Btu-gas. From (8303,AI-5) maintenance labor was based on 1.5 percent/yr of total plant investment, supervision.labor was-based on 15 percent of process operating and maintenance labor, administration and general overhead. was based on 60 percent of total labor, operating supplies- were based on 30 percent of process operating,labor, and maintenance supplies-we0qie based on 1.5 percent/yr of total plant investment. The total grossioperating cost is thus q$;2204/l.q0E06 Btu gas-or 16.75EqO6 $/yr-for a- 231.8EqO9 Btu/D SNGplant. By-products we4qrecredited at.. $10/LTIfor S q(.502q7.1 LTS/D),. $25/T NH (173.6 TPD NH3), $.15/g4qal *for B-T-X q(25000 GPD), and.qi-qj.q0/qi.q0E06 Btu for tars (q13.9EqO9 Btu/D) from1p303,AI-5). The total net operating cost is,2qtherefore,$11 *qOqOE06/2qyr-or, for a 5.78EqO6 TPY coal input, 8.374qEqO4$/qI.qOEq12 Btu. 8481 Capital and-operati4qng-costs for-thi8qa,process are an-, arithmetic average,those for,the Hygas@-Electr0qot0qherqmal, Hygas -Steam. 8qOq?cycqjen, Bigas@o@ and, Sy0q4thaner'processes.- 8482. Capital and..op8qerati6qng costs.wereie4qVeloped-as follows:. Capital Costs-1972.q$-Plant Basis-19,300 TPD, 90 P.LF .From q(qP3q0q0q),, escalated from,2q1971 $ to 1972 $ at q5 percent,-cos tsfo8qr.:'col storagea6qndpreparation, gasifi0qc@ation'and CO shift-, gas purification, methanation, compression , oxygenqanuf0qacture, general utilities-, and, 4qgeneral-offsites total 181.5Eq06 $. Steam-,and power plant cost was estimated at 24.78qEqO6 $ from (8300q)' and (8323,42). Water poll4qution@control1postswere estimated at 13.8EqO6 with tar-oil-water separation and activated carbonq1costs from (2013,VII-i-4), costs for free and fixed ammonia stills from (8304),.costs..for filtration and a Phen0qo@solvan unit from (83q206qY, and a miscellaneous allowance (2q;lEqO6$q) forqMater.impounding:basins, thickeners, settlers, etcq-q. from (8315). Sulfur qr q'ecovery -costs were estimated,at 17.5E2qO6 $ from56qA '83006q)q: and (8303,AI-25,AI-26). To the subtotalwas addedq*a 15q-per- cent p36qrojectq-contingency to give.a total plant investment of 273.1E2q06 $q. Basedq,q:on a FCRq'of 10 percent/yrq'and 6.33E 06 TPYq@c08qoal, this is equivalent.to 1.90E8qO5 $/lq.8qOE12 Btu., IV-76 FTN 8483 Operating Cost'8-0q4_9@0q72*$-Pqla6qht 2qaaqsq;iqsq-19,300 TPD', 90 P L4qF From (8300) costs for catalysts and chemicals, purchased raw water, and process operating labor total q$2p2p/q1.qOE06 Btu gas. Costs for maintenance labora, suqlqpervision labor, administration and general overhead, and.operating and maintenance supplies were developed from (8303,AI-qS). Electric power operating and maintenance costs are from (1918,46). The total gross operating cost is thus $.233q6/1.qOE06 Btu g0qas or $18.15E2qO62q/yr for a 2524qEq09 Btu/D SNG plant. By-products were credited at q$102q/0qLTS (580 8qLTS/P), q$25/T NH3 (187 TPD NH3q), and $.15/g0qal B-T-X (61.7EqO3 GP8qD) from (8303, AqI-5q). The total net operating cost is thus $10q1.67Eq06/ yr or,for 6.33EqO6 TRY coal input, 8.118qB04 $/6qI.qOE12 Btu. 8483, Thermal discharges can be compl4qetely.elim4qinated by the use of mechanical draft wet cooling towers. IV-77 V. OIL SHALE @A. Introduction. The environmental impacts,-,ef-fidiencies,. and costs associated with the production of crude oil from oil shale are given in Table 3 of this report. Each process'oi activity data entry is based on an energy input.equivalent to 1012 Bt-u/year. This.is approximately 133,000 tons per year of 30-qallon per ton shale. All table'entries have been derived for a "controlled".environmental condition'. Contrary to the-fuels and activities described in the Phase I Report (contained.i:n Volume I), oil shale plays'alun,ique role in the fossil.fuel..t,ralectorv. Although the oil shaletask includes activities such as extraction, processing, and distribution, the end product general'ly cannot be considered a refified-,product until it is further upgraded in a conventional refinery'. However,other end uses for this' tifirefined shale crude, such as turbine fuel for electric power generation, have been,demonstrated. To be@more precise, the end product con.side,red in this reporlt'sho.uld:be regarded as ahigh quality crude oil from which many conventional refinery products'may be derived. Consequently,@@he oil.shale, task must be viewed in conjunction with the Pha.se'I Report to complete.the entire fossil fuel chain from extraction to end use. Oil shale is a sedimentary rock consisting of 'a.. solid organic material'called kerogen 'intimately associat 'ed with. other minerals. Upon processing, this organic' rich rock found in the Green River formation of Colorado, Utah, and Wyoming, will yield a low quality crude oil which-is suitable for upgrading. Thesedeposits, assaying about'30 gallons of Pil, per ton of shale, represent about 600 billion barrels of oil. The recovery of crude oil from oil shale may take three distinct forms:. (1) mining the oil shale and "retorting" it in surface facilities, (2) in situ retorting followed by surface upgrading, and (3) a combination of mining and in situ retorting followed by upgrading. Methods (1) and (2) are considered in this-report. Figure 20 is a flow diagram of the principal processes in- volv ed in a commercial size oil.,Ishale operation using the Gas Combustion.Method. For the TOSCO II and In Situ Methods for which data have been obtained,, the.flow diagram will be similar. The processing' steps include the following activities., ELECTRIC POWER TO EXTRACTION, POWER ACID GAS KW- :ATMENT HR 'PLANT CRUSHING, RETORTING Ek UPGRADING HYDROGEN MANU- FACTURE 'EXTRAC- HYDRO- TION CRUSHING RETORTING DISTILLA- . - a- CRUDE TI N TREATING @42API TO WASTE DISPOSAL 'DELAYED COKING COKE Figure 20.. Typical oil Shale Process Flow Diagram VS Mining This will include both underground (room and,pil iar) and open pit mining depending on the size of the operation and specific topography. Underground mining will essentially be associated with a 50,000 BPSD surface plant,and open pit mining should support a 100,000 BPS D,operation. Mining ,will essentially follow conventional methods, however,the magnitude.of .the operation will be considerably larger than,present day coal or copper extraction activities. For,a 100,000 BPSD.plant, approximately 145,000 tons per day' of.oil shale must be min6qe.d and conveyed to tne retorting,plant. The reader is cautioned that the, 4qI0qm or pacts f. the extraction process are not based on the recovery of 1q012' but.the "attem t' I to recover 'q01 Btu 1 Btu. qIm, acts fo2qr this qp activity. are..actually derived by extracting q1q0q16q3tu of the resource,and multiplying by the ppropriate extraction efficiency so as to be consistent with all other entries in the tables, i.e. 1012 Btu into ach activity. 2. Retorting There are basically three methods for retorting oil'shale to obtain the low q4qvality syn-crude suitable for upgrading. a. Gas Combustion This method developed,by the :Bureau of Mines and Union. Oil Company utilizes crushedhale that is charged into a processing unit or retort where it is heated to 4qIts'p6qyrolysis@ temperature of between 800-10000F.Theerog4q6n is 'liberated-, from the' inorganic matter and is converted to a gas and oil mist. These organic-rich vapors are collected.and condensed to form a,low gravity, moderate sulfur, high n0qitrogencrude oil- Combustion it supported by recycling a portion of the low Btu gas produced during retorting.' Solid waste or spent shale is automatically removed,nd conveyed to a1psp8qgsal site. b. TO'SCO 11 ,This method,developed by the,Oil Shale C.orporation and sponsoredy the Atlantic-Richfiel'd Company 4qas well as.. other maj6qGr oil companies,involves the same approach as Gas Combustion but utilizes, aq.different.technique. The TOSC24qOqIII method utilizes,hot-ceramic ballsq@to sustain pyrolysis. -AS the kerogen is released the balls are segregatedq.from the spent shale, reheated and recycled. The syn-cru60qde is 'further upgradedq.whil32q6 the spent shale is conveyed to a disposal site. V-3 C. In 'Situ This method of shale oil recovery has been sponsored by the Bureau'of Mines, Mobil, Shell, Equity, and,other major oil comp anies. It :involves*hydraulic,'explosive, or electrical fracturing of the oil shale bed" and combusting the oil shale.in the ground by means of injecting natural gas and air into the well. As,combustion of the oil shale takes place the* shale oil is released from the,inorganic material and is recovered via a series of well systems., No spent shale or ash, is generated in' this process. Due to the inadequate data available on fracturing, it has not been considered in this report. The data compiled deal-primarily,with the retorting, recovery', and upgrading -activities of the In Situ process., The generalized In Situ for which data haveibeen compiled is not to'be confused with the .Occidental Petroleum process of in Situ retorting. The latter is a combination,of'room and pillar mining and In Situ retorting. 3.; Waste Disposal One of the major problems with above-ground retorting is the large volume of spent shale that is generated. For every .,barrel of syn-drude produced there are approximately 1.2 tons of spent shale@g'enerated- This spent shale must be conveyed to a'shale disposa1 site, compacted, and eventually revegetated. 4. Upgrading Crude shale oils produced by retorting typically have high pour points and tend to form.sludged if stored for prolonged periods of time. This property necessitates refining or partial refining soon after production. Hydrotreating using established techniques of the petroleum industry is best suited for'reducing the pour-point, removing nitrogen and sulfur, and preventing deterioration. The crude from the "retorts" is heated in a tube still and charged into a distillation column. The lighter di!stillates resulting are fed direbtly to the hydrotreating unit, whereas the heavy bottom fractions are coked prior to hydrAreating. The resulting product, a semi-refined crude having a- 420API-gravit-y, is then stored for pipeline shipment to conventional refineries for further upgrading..:-.,-,, V-. 4 5. Power Generation. Above ground retorting (TOSCO II and.Gas Combustion) methods produce sufficient quantities of fuel.gas to supply the plant's steam and electrical requirements. (More recent data from the Colony Development Operation.suggests that this may-not be the case. See the discus ision below.) In situ retorting requires an additional amount of ancillary fuel for its operation. It is assumed in this study that the fuel utilized will be natural gas supplied by a nearby pipeline system. In actuality if the semi-refined.crude was utilized to produce electrical power and steam by definition.-it would not be considered an ancillary fuel. The cost'data presented in Table 3 are ba'se'd.on a 90 percent plant load factor, or 328 Operating days/yr. The values.presented in this table are based on data accumulated during the Pall of 1973. Since this data base was prepared, extensive work has*taken place on the development of an oil shale industry. In particular, the design of the Colo'ny'Development Operation shale oil complex has resulted in a more recent and complete evaluation of environmental impacts. This information is contained in An Environmental Impact 'd Analysis for a Shale Oil Complex at Parachute Creek, Colorado.. Da a from this report,.in.general, differs from that contai-n-eiff _herein.1V The reader should take special care in using some of the data presented in Table 3.. In. particular, rows 9, 18, and 27 define impacts with respect to the processing of raw shale into semi- refined crude oil. Each of these rows (9,i8 & 27) is a composite of impacts due to individual processes required in this activity, The eight rows following each of the above three'rows (rows 10 thru-17, 19 thru 26, and 28 thru 35) des.cribe;the impacts of each of the processes on the basis of 1.OOE+12 Btu input to each , process. In trajectory type calculations, one must make use of the composite data in rows 9, 18'and 27'. Letter to M.I. Singer,.CEQ', dated 10/30/74 from W'.E. WAde, Jr.j manager planning and control, the Atlantic Richfield Co. V-5 Big Impact Data Table and Footnotes V-6, am h MN FUEL REGION 1 2 3 4 5 6 7 a 9 to 11 12 13 14 15 is 17 18 19 20 21 22 23 24 25 26 27 28 29 30 WATER POLLUTANTS (TONS/ 16" BTU. EX. COL.12) AIR POLLUTANTS (TONS/1012 BTU) OCCUPAjiJONAL HEALTH POTENTIAL COST (I)OLLARS/ld'STU) SOLIDS LAND AR E PRIMARY ANCILLARY DISSOLVED SOLIDS SUSPENDED TOTAL THERMAL PARiIC- HYDRO- ALDEHYDES' _iEATHS ["JURIES MAN-DAYS ENERGY FIXED OPERATING TOTAL ROW MNE- ACTIVITY PROCESS ROD COD NO, sox CO ETC. TOTAL TONS/eI (ACRE.-YR) SCALE EFFICIENCY ROW 'OBI TU MON. ACIDS BASES P04 NO, OTHER TOTAL(DS) SOLIDS ORGANICS COUS 6,7,8 BTU/IO'2BTU] ULATES CARBONS 101 BTU 10 BTU 1012 BTU IOI2j3TU mw/ldlsw COST COST COST LOSTACY BTU DISASTER I@RC EXT RA CT I- UNDER UNDERGROUND 39OD3 o.Oo,Oo 3 9DO3 0.60,00 39DO3 0.00-00 39OU 0.0010D 3 9DO3 0. G- 3 0. Go- 39003 0. OGIOD 390GI Q. Go- 3 G. OG+GG 39003 Q. 00-OD 39U3 D00100 20997 l. 54 Of 39001 7.61-023902 S4-3 3 1002 7 @ 74-03 3 9G02 4.55-01 1lool 1.19-G4 39002 4,89-01 3 1. 15@01 2 11GS 1. 9-0 2 9004 4.14-03 3 9006 1 .OB-01 3 m, Go. 9104 6. 50,01 2gooO 1.2-1 l IGG7 1.14+03 3 907 7.93+04 3 9047 8#74+04 3 2 3SURFC SURFACE 0,00-00 390DR 0. 00,00 3 9004 D.OOOD 39008 0.00100 39008 O.OG-OD 3 SON -04D 3 o.WoO 3Go$ ...oloo lGoo. G.- l 0. DGIOD 39GOR ft DD+OO 39008 0DO+OG 1G197 1.33-G2 1009 3.79-01 4goog 2.11-ol @ Go, 3.11-02 4 9OG9 2.31-01 lIOG9 Gloog 1+12+oo 4 5.03@04 2901D 3.99+00 2 9011 1+06-o3 3 9GI2 5.!44-G2 3 9012 .11. IOJI 6.20-01 29- 1.66+08 3 9074 8m43+03 3 9048 3m03+04 39048 e..7+. 1 3 4TRNSP TRANSPOGITAT N 4' 5CoN, Co-Elo. 0, -00 2D G7 "I o l- O.G.G. 2GeV 0-0 2 D997 Q. GG+GD 20997 D. OQ+GG 20997 0400+00 20997 0 m O0+OG 20997 OwOD+OO 20,997 o-p 9 G2ol. -G- 20997 4 81-OT 3 961GGGG+OO 1G117_ .. Go, 0 2 0117 ..G GO 2. -7 a. -Go 20997 0.00,00 2G997 14.8o-ol 3 OwOO400 2Oo97 4,OG-GI 1loll -9 I..G+.o lI- 1.31+09@ 2 IDIS 1.49+G3 2 love 1.4-1 29049 11 64@32 51 SGI, 6- TRUCI TRUCK o. ..+Go 1.11, 2 011 0.00,00 2 OmOPOO 20997 OwGOOL2 B997 G-o 20997 owoo,oo 2G@ 97 G.o.G- 70397 G.oo,GG 2D997 0-00-GO 2G997 0-00- 1G997 0@0-00 20997 1.42-02 49019 ..-ol 7.9-2 4 9019 4.04-02- 4 9019 2.45-01 49019 3.17-ol - 7.36-01 4 G.-Go =17 7 0 OG@02 39020 ogle .1.1 .11, IG82 1.00,00 29021 3.02+08 2 9072 2w46-Q? 9 9oSo 6.74- lIGIG -- l 6 7PMOS PIRE-PROCESSING GNUS. -S.- 0.0-0 29D26 0. -00 2 lG26 Q.OO.OD 29026 0. OOqO 29026 G-+;O 2902G G026 0.00+00 29026 0,00+00 2 G.GO+QO 2e026 0.0G100 29DI6 0.0-- 20907 8.40-01 .2 9GOS -1+0020997 0. -00 2 0997 O+OMG 2 D997 O+OD+OO 20997 0.001GO 29997 9.40-ft] 2 1. 73,03 29027 Ow2-2 49028 ollo G119 .1. 1082 9.87-01 29024 9.28+08 39023 6. 77+03 39051- 1.33+G3 4D051 8.10+ol 4 8 -IC PROCES11NO-GAS COMBUSTION 1,110* 11012 3 1111 31111 O.G-0 39032 91, 0. DO10D 3 39.2 GAGIOO 1111 G.04 1 0.00+00 2GOG2 O@ GO,00 30082 0. 00@00 3 Oa 00+00 39082 0, 0010 +00 3GOBI 3155+0139083 3r 06+01 3 9083 1. "+01 3 o- 1. 11- l- -e-ol 31083 G. o_@ 3 1 r 78+OD 39097 39090 LS5-D@ 3 -0 1.41- l 90!. D999 S.31-01 9015 0. 00+00 2-7 1.18.05 39101 3.32- 11ol 3 9 10 RETRT N-oK-- 0-00 29029 d. Go- 2 SD29 G.OO.OD 29029 G.00+00 29029 D.OO+G0 2We O,GGIOG 2 G. G.Ioo llolo G.-Go loll G-O I O.-Oft 2942910.00+00 29029 ...0,.. l0997 10.00+00 3e.I. Om.G... 1lolo G. G.GG l 1- .-0. l 9G3. .-aa 39olo 0+00- ,-o G.-Go 3 1 1.08+05 2 904D 5,50-02 3 90q3 I - 39042 1. 44-al 3 9042 D999 O99l 6.73-01 29044 2.33+10 29046 6-04 39OS2 I-Iol l9Q52 1.68+05 L_ 10 11 D15TIL ____ DISTILILATION ... IS. 0998 16. 04-01 39054 6. D4 01 3 GlG 4.3DOO 35054 4.91-GO 3 1.71-03 3SD54 ogsg -b+oo 2sell o.oD+oo 29oso o,oo.oo29o5G a. G-0 2 9056 2.73100 3 9054 O.-OD 29- 0.0 ... 0 2loll 1.1-0 3 o9l. -1-11 - .11. . .9 1 loll I.oo+oo 2QIo5 1,9o+lo 3GOP 9.os+o3 39057 7-04 39057 3.41- 3 Ip G...G DEI-AYED COKING Me Goss o998 0998 4.77-01 390lg 1.77-01 3 0999 2.47-02 39058 5.02-01 3 0999 1.02.00 39058 OaOO+OD 29OSS G,G.,GG Ilol, -- IGo, 0.000 1 9GS6 2.13,60 3 _9 cwn 29G,G ow-Go 29DS6 2.131GO 3 G118 OGG. .199 oll, 2G91 -7-01 29091 7.4-0 39160 336404 i207 6.37+04 3goel I... -OS 3 12 is Nlmrc HYDROCEN NANUrACTURE .11. .19. G91. 0999 098 o9s, .19, 0999 .11, .11, 0999 0.0-0 29G55 G.00+00 29DS6 OmOO+OO29056 G-100 2 9056 1.49,00 3 9362 0. OO+OD 29056 G + -Ga 4 m GO f oo 3 0998 o999 - oggg G119 .11, 2091 5.03-01 22079 ImO3+12 22079 7. 381ON 2 2G15 l.14+05 2 205: CW05 2 13 14 HYTRT .1-R-TIN. .11. el. Apl. o998 e G-G, l 0999 7.3-1 39064 1.34.00 3 L72+00 39064 OvOO400 2905S 0.0- 1loll O+-Go 1IG56 DmDO+GO 2 9GS6 2,59100 3 9081 D.GOIDO 29DSG O.OO+G0 2IGIO 1.11.0 1 oll. .119 G191 GO'S .11, 2.91 9.68-ol 29-1 1.1-0 3906S 4.17+03 3IG61 4.15.04 3IG61 1.27- 3 IT, 15 GASTR GASTREATING_ 0,00100-2 9- 0.00+00 2 9071 0.00-00 2 9071 -0+00 2 9D71 OmOOIGO 29071 G GG+GG O.OG,OO 29071 0,00,00 29071 G. @O 2 0.00+00 29G71 0. -00 29055 O.OO+GO 29072 0-0-0 Z9056 l.-Ol 2 9072 G.OG-00 2 9072 0.00+00 29072 OwOO+GG 21012 3941 1 .-Go 2 9073 2-104 4 9074 .1e, G191 G119 7091 1.00,OD 29075 0999 3m32+05 39076 G.O- 19111 1@32+GS 3 Is 7- 16 TNKCR@ CRUDE sl-E-__ .19. .11. 0999 Go. oll, G117 - OOGG Ooll 7.2-2 2 9033 .91, G.-.O le.11 1-1 GmG_O 1.11, G.GG+GG 1 .197 -o- 1 9034 0. -01 10997 20997 5.031G1 2 2.191 G.1-1 IIGLI. .1 2.1l 1-0 2 03 S 16 o999 .91, .1 9D36 I.S4+06 49037 3.83,03 39053 2.68+03 39053 6'51+ 17 mGEN -.ER GEN-TI.. O.OG+Oo 31917 -0+00 3 1917 D999 099 --1) 41@17 3 40, 00 4 O,DO-GO 31917 3.02-03 31911 31 4-D 4 oel@ 000 0.00- 3191B 12.15,01 3901 1.8-2 39031 1.55+02 3 9031 11-01 3 9031 1.94-01 39031 11.46+OD 3-1 3.87+07 3 1o. Go- l.117 2. 7G+OOF 33904 5.96-04 3 3903 5.17-02 1 3203 2.36,00 3 3903 .199 -G-01 2191l G. GINGG 10. 2.n@G5 2 loolle.7m,; 2M.031G5 2 17 7 3.73-05 39102 14.87,05 3 Is ffOSC FftOCESSIHC-TO5C0 11 0. O-D 39094 -00- 3 9- 0-00 3 9094 0 00,00 3 9Ggq G.oa_ 39094 0. GO+00 3 G.- l-, o. Go- G- G.o..oo l 0.00,QO 3 9094 O.DO.00 39094 O.Ool.o IOM l-G II.-ol 11084 3.74,21 3 9084 im22+01 3 9084 1.33-02 39084 9.93-02 390.4 6.28+01 3 1.08+DS 29040 1. 7-0 l9- 1.11-03 3 9090 1.48-01 3 9090 1*49@01 3 9090 0999 6.67-01 29091 G.Go- l9.1. 1.50- 39102 19 R ET -ORTING OmUO+OD 29029 O.OD+00 2 909 0-0- 2 GO29 0.00+00 2 9029 lIG29 OmoO+oo 2 GwO-0 29029 -0+00 29029 G+0010G 2 O.OO+G0 2 9029 0+0-0 2ooze Q OG+G0 20997 6.00-OD 39030 ID+00+003S03D D.00+00 3 9G30 G+O01OD 3 903D 0. 00+00 39030 0-160 39030 O.OO+GO I.-ol I'Go. 2.78-02 39o4I 1. 37-03 3 9042 1.4'4-01 3 9G42 G19, G111 7.1-1 21.1 ol9G .199 oll, 019 19 20 I)STIL -T-T.- OelG 0999 A 04-- 1 6.04-01 3 1999 4+30100 3905Q C-01 3 1 7-3 1 l054 D999 D.00100 2gG55 GmDO+OO 29DS6 1.10+0129D5fi 0. -00 2 9056 2.73+OD 3 9054 O.OG+10 29OS6 0.1-0 29056 2.73.00 3 .91. .11, O'll o919 ol9l 201 1 . G- 29105 1.90110 39- 7.99+03 39057 2.51- 39057 3.31104 3 20 21 DEI-AYED COKING oll. Go', 099B 0998 4.77 01 390SA 4.77-01 3 0999 2.74-02 3GG5G So2rO! 3 0999 1.02,00 39058 D.0010D 2GOSS 0.00,00 29056 G.OG-0019056 0.00+00 2 906 L1340 3 9059 O.OG-00-2-9056 -0. OO,OG 29OGG 2.13+GO 3 Q998 -9 G119 oll, 91 201 1.91-11 2qG911 7-10 39OGG 3 m 2 -4 32047 6,37,04 3e6l 1 w 024S l 21 22 NlmFG -RUGEN MANUFACTURF llo ole. o9lo Gol. oll. o999 - oll, G111 G.O.- 29G5S O.OG+OO 2905-6- 0, OG+O0_ 29056 0.00,00 7 9G56 1 w 49+00 3 9062 0.00+00 29056 0.00-00 29056 4.O-G 3 o998 019 o999 0999 2,9 ol-IU l!.7, lrO3+12 27079 7. 3804 2202 . 3.101 22G52 4. G8+05 2 2 P 23 -R@ y.. TREATING G998 oll. olo. oll 6.G4-01 39064 6.04-01 3 0999 7.33-01 39064 1.34+00 3 8.63-02 39064 1.72-00 39D64 0.00-00 29- O.OOIGG 29056 0.00.002SG56 O.GG+OO 2 9a56 --o l Go, ..-G. lMe I) OGIGO 29OS6 2,51-Oo 3 0998 .99, o999 oll, - 20i 1.13.1o 39a6sl4.17+03 3ID61 4.85+04 3 -9066 S.271043 23 24 GASTR GAS TREATING 0,00+00 2 GG71 O.OO+G0 I loll G.GG+G- 1 9071 o.oo-oo 2 Go7I o.ool 0 29G71 o.oo.oo 2 Me- 2 9071 OmOD4DO 29071 0. OG+0G -2 0.00-00 29071 GAG- 29071 G.0-0 2905S OwOG+Oo 2GG72 0-00 29072 3w 39,01 2 9072 1 0. OO+GO 2 9 72 0. OO+G0 2SQ72 0-0 29012 1. 39- 2 -G.0 2 1.11 1. Il+.G . 9G,O G999 .91, ol". _2G91 1.00-00 2907S o919 332- @_IG76 0 @ 00+00 3 -6 3w 32@05 3 24 25 TNKCEI CRUDE _-E 0998 0.. o998 ollo ollo Sol G G191 0999 7.21-G2 29033 0999 G.OD+OO 29OS5 0.00+00 10997 0.00+002-7 0. -00 1 0997 5.48+00 2 9034 Ow-00 10997 O,OD+GO 2D997 5.01101 1 -7 4.16-01 29035 0999 .,gS Go. 20W 1 m -0 29G36 1. 54+06 49037 3.83+03 39053 2-03 3901 6. 511G3 e 2 5 2 6_G11 @WFR GENERATION G.GG+GD 3 1917 -D- 1 1917 o999 0999 3. 4@1 OD 4 1017 3.40,00 4 O.-OG 3 -7 3. 02-03 .1 Ioll 3.40+OG 4 o.99 0909 D.00+00 31918 2.62+00 39D32 1.90-0 1- -2102 3 9032 1 . -01 3 9G32 1+95-01 39032 1.46+00 39032 7-02 3 -D. OOIGO 3 0997 2-- 3l12L 54 96@G4 3 3903 5. 07-02 3 3903 2.36+00 3 15L3 0999 3.110-01 21912 QaOO+OO 19067 2.35+05 229016. 79104- 2 -2GD' 3- Oe+G5 2 _PINST FIROCEIIINGAN SITU 1111, 3 1111 11111 0,11+11) 3 1112 1,11+10 1 1111 1, 11,11 1 3SON 0. 00i OD 3SM Ow OD+ 11 1 1, "1" 11111 1,11,013 1111 1,10110 11011 1, 11,11 39011 7,11,011 9085 2. W02 3 9085 1. GN 02 HIS 1, 1 1@ 11 31*11 1 -D! 39085 4449+02 3 0,00+10 1 0117 7,11,11 1111, -.-Ge , 'me 1@@090 e.2.-.e @ .1. 0 999 5 31-DI 29095 5.99+10 190" lm!1*05 39103 .L98-05 311. 1-, l 27 2RETRT OmOO+OD 2 9079 O.OG+00 2 909 O.QO,OO 2 9079 0.90100 2 9079 0.0-0 29079 0.-0 2 -0100 2 9079 G, -00 29079 G.OO+OD 2 1O.OG+OO 29079 O.OG,00 2 9079 OwOO+OO 70997 6. 22+OD 3 9078 D999 2. 6-2- 3 9071 1. 1 1+0@ 3 9G7. 1. 13, GI 39078 0999 4.31+02 3 0,00-00 2 09L7 6c47+00 39069 3* 64wO3 3 9070 5,69-Dl 3 9070 oll" Ol I 1.11-ol 390131 .1. 5. 711+04 l1.7 Ae. 5.7.+Ol 3 as 29 DSTIL DISTILI-ATION Me .11. Go. .- 6.-1 39- 6. -@ 1 1 O'll l-G G.-Go l 1.73-03 39G!4 D999 0. -01 29055 D. OG,00 79056 G.DO+QO29056 *. ..0. 2 1.11 -1.0. 3 I.So 0 + G.GO Ilell G.0- 29.l6 2w7340D 3 098 a999 o999 .11, .11, 2091 1. OG+OD 79105 1. 90+7 0 39054 9.05,03 39057 2. S&04 39057 3.4- 3 2 9 so coKic DEI-AYED COKING .11. 0998 Me 4.77-01 39058 4+77-01 3 2.7-2 39058 5.02-01 3 _ 011S -21GO l 101. 10 w 0-0 29055 G.00+00 29056 O.OG+OO29056 0 w -00 2 9056 2.13-00 3 2OL9 0400+0 2qOSfi OaO0+OO 29056 2v!3+00 3 .11. .92- 00999 o99G Oo 19 2091 0.97-01 29091 7.44+10 3906D 3.86+04 32047 16.37-04 39ofil 1. 02+011 2! -H2.- HYDROGEN MANUFACTURF, oolo .11. oGG. eggs ogle O'go G-ol Goo, o999 o999 GG9G G.G04GG lGGLI GwoO+Oo 290% QmOO+00 29056 D.00+00 2 9056 1. 49.OD 3 9D62 0. 00+00 29056 10. -00 29056 CO.- 3 .9o. G99, o9ll Sol .11, 2091 5. 03-01 22079 1.03+12 22079 7.38+04 2 2D5: 3. -eS 2 -4.08+06 2 3 2H-T HYDROTREATING .11. Go'. ogle 0998 6.04-01 39- 6.04-GI 3 0- 7.33-01 390611 1 34+QG 3 8+63@02 3 9D64 iv72+00 3 9064 0.00+00 29055 O.GO+GO @2 9056 G.OG-GO2lell a. 0-0 2 9056 2.59+OD 3 9 US DIOO+OD 29056 O.GO+GO 29D56 L59-00 3 0998 oloo .... ose, o,99 2G91 9-41 29105 Iw13+I 0 39GGS 4.17+03 39D66 4. 8-4 3 9111 e.17- 1 3 3GASTR GAS TREATING OIOO+OG 2 9071 0.0100 2 9071 O.DO+00 7 9071 O.BO1OO 2 9071 O.-ob Go,, ..W.o -O+OG 7 9071 -- 29D71 GAO- 7 G.-O 1 9071 0.0-0 2 9071 0-0 2 -5 o.oo+oo .2 qo56 OmDO+D0 29056 3i3g@Oi 2 9072 0.00+00 2 9072 D. 00+00 2962 Q m ONOI) 29G72 3. 3910 1 O.OG+0O 2 9073 2.55+OD G 107o ol9l o'19 2001 1.00+00 2907S o.9 3'.32+D5 39GOG OwOO+O0 3 9076 76 3.32+05 3 34 TNKCR CRUDE STORAGE oll. IS. ..Go oll. .9l. G19S o999 o9oo @5@9 7,21-02 2 9033 osLq oaoD+oo 2 loss omoo4oob2 9o56 OmOG+OO Z0997 G.OD+OO 1 G997 5.4B+00 2 9034 0. -00 10997 0. -OG 20- S03+01 ? GdOO-00 2 0997 4.16-01 2 9035 ol. ..GG .9. 1 -0 2 9036 I.S4-06 49037 3.8-3 19011 1.08@03 3 qos3 6. 5"+0 S 341 3 5ST.GN STEAIA GENERATION O+aO+DO 3 1917 o.GO+OO 3 1917 op.@ 0999 3.4-0 4 M7 3w4O,OO 4 -G-00 3 1917 3@ 02-03 3 1917 3.40+00 4 _oG99 0990 0.00+00 1 1918 -7.34+QO 3-3901- 39Gt 7.93-Di 3 lell 1,96+01 3 39DI 1.9-1 33901 3@43+00 339DI 2.22+02 ..GG.G ;-04 a -3 5.67-02 3 1901 2. 36+GO 3 3 03 -0999 B-01 2910D -tNOO 10997 ..G G91, .99 3 5 36 DISTO DISTRIBUTION 31 3 7PIELN PI-INE G_ .1. .9., .1. .91. G91. Mo GGS. GO,, oll. 0998 1.61-01 3 90. 4.11+GG 1 1.1 1.34- 1 10l. -1-01 3 9038 2.79+OD 3 9"S 13.70-G2 3 903a 8+33100 3 MOO- 0997 6.36+01 2 7DO7 8w46-02 4 3G34 2037 IwOWO 2 2081 3.4-9 3 903 "9 2.S+M I 2on 37 36' 3 9 3 9 40 40 41 41 42 4 2 43 4 3 74 44 45 45 46 46 47 47 48 40 49 49 5 0 so 51 5 1 527 52 53 53 V 5 4 54 5 TABLE 3. ENVIRONMENTAL IMPACTS, EFFICIENCY AND COST FOR ENVIRONMENTALLY CONTROLLED OIL SHALE SUPPLY V-7 7 ."1'97 lSo, 7 +.: Go 0 I'lo 7"1 '11' E31"!! G __G, l .. 0 _GG l lo" _`U l 2.7 G, ,.oG.oo Go 7 _G '036 o*,o 099, -Io Go FTN. 10812002 Footnotes f t Table3 1081 Large scale disasters at strip mines are rarities. As in auger mining only the failure of the highwall pre- sents any potential for a disaster. 1082 The potential for large scale disasters qi's'non-existent. 1906 Source 0qU9061,46). 0.166 men per M0qWE is the basis for the calculation Injury data ate from (190,7,,35). Half the combined'deaths and permanent injuries are assumed to be fatal,injuries. Permanent total disabilities are conideredto represent 6000 days lost while other :disabilities are estimated as 100 days lost. Man-days lost are for injuries-only. 1912' A large new power plant is assumed to have a2qheat rate of'8960 Btu/Kwt11'hr, equivalent to 38P conversion effi- ciency. The best plants have achieved around 8530- -10,500 8900, whereas the national average is around 1-.5-6/1-5-7). @1917 The-basis,or water pollutant calculations is the pro- posed effluent limitations guidelines and new source performance standards for the steam electric:power generating point source category given in (1921q). For new plants, best available demonstrated control tech- nology (BADCT) requires effluent pH control in the range of'6-9. 'Hence,''acids and bases@discharge will be negligible. BADCT also specifies.total suspended solids levels no greater than 15 mg/ql for all intermediate and low volume waste effluents. At this level of con- trol there will generally be no net increase-inus- pqended solids in water passing through the power plant system. organics (oil and grease) must be,controlled to 10 mg/q1 to meet BADCT standards. Hence, from (19 '21, 2.32) these emissions will amount to 3.02-03 ton/1012 Btu.,, Information on the increase in total dissolved .solids of water used in Ipower plants is not readily available,and was synthesized from (1922,6q10,12,20,22). Based on this data the net-increase in total dissolved solids' for water used by the power plant is 3.40 ton/ 1012 Btu. 1918 Thermalq@discharges are assumed to be completely eliminated by the use of 'mechanical draft wet co00qoling,towers. 2002 Land impact for pipeline transport of crudeq'oil 6qis based on 1971 total crude oiltrunk and gathering line mileage of 1464q2.00q4mi (2001,2) and total crude Oil traq'n'sportedq'-by pipeline in 1971 "of 36q-.095E9 76qBBL 52qM005,14). Assuming an AV pipeline r2qi0q:ght-of-way of 62.5 ft (2002,14)q'q,q@aboutq'q163.6 A24qC are affected pe0qr 1q.2qOE12 Btu shipped. 16qVq-9 FTN. 2023 2052 2023 Hydrogen manufacture (steam.reforming) SCF of natural gas feed equivalent to 1.OE12,Btu is 9.69EO8. (0005,38 and footnote 2000) Water Pollutants Thermal gallons.cooling,water/MSCF H2 is 650 and Delta T is 25F (2005,270) No other water pollutant information available. Air Pollutants The air pollutant sources include steam reformer and wast 'e heat boiler, blowdown system, pipeline valves and flanges, vessel relief valves, pump and compressor seals and process drains. Air pollutant emis .sion factors from (0002-,1-9,9-3/9-4). Natural gas was assumed to be the fuel used in the reformer and boiler. SCF fuel required in reformer is 4 *947EO8. Based on (2005,270) and 1031 Btu/SCF (0005,38) Electricity at 0.4 KWH/1000 SCF fuel required in was@e heat boiler is 0.0. Boiler uses waste gases from reior- mer (2005,270). Air Emissions (tons/yr) Steam' Waste Heat. Other Component Reformer Boiler Sources- Particulates, 4.45E+00 NOX. 5.67E+01 sox 1.4-9E-01 HC 9.89E+00 Co 9.89E-02 NH3 .0.00E+00 Other.Organics 2.48E+00 With a natural gas feed of 1.OE12 Btu/yr, the hydro- gen plant.can make 1.83E09 SCF H2/yr (2005,270). A 100000 BPSD refinery uses approximately 100 MMSCFD H2. 2034 Based on 1971 data for transport of crude oil by pipeline, 83 disabling work injuries, 2517 man-days lost, 1 death (0035,4). Total crude oil transported- by pipeline in 1970 is 5.298EO9 BBL ('0011,561). The allocation to 1.OE12 Btu/yr is 3.36E-05. 2047 Based on (9022,65) the capital cost of a 10000 BPSD delayed coker is 8.OE06 dollars andits operating cost is is 53.5 cents/BBL. Fixed charge rate is 10P. 1972 dollars. BPSD equivalent to 1.OE12 Btu/yrLis 482. Based on- (2010,176/182) the capital cost of a 100 MMSCFD hydrogen plant.is.13.3EO6 dollars.and its operating cost is 18.25 cents per MSCF H2. Fixed charge rate is 10P. 1972Aollars. SCFD H2 resulting from 1.OE12 Btu/yr naturalgas-feed is 5.55EO6. V-10 FTN. 20712-29.07. 2072 Based on operating revenues of $6.7EO8 and 5.3EO9 BBLS crude oil transported. 178.000 BBL/yr equivalent to 1.OE12 Btu/yr. 2079 Based on feed and fuel re quirements from footnote 20@3. .2081 Based on (0012,71) 0.00,6P vol. is lost.in.leakage-. Thus primary efficiency is 99.994P@@ From Footnote 2031@1@ pipeline energy' is 450 Btu/ton-mi. Average pipeline movement is 300 miles. Tons/yr of crude and product are 26600 and 27,300 (Footnote 2074).. 2087 The major cause-of"all p@peline accidents in 197.0 was external corrosion at 43P, earth-movin4 equipment accounted -for 20P.,' personnel errors 4P.-Natural catastrophes such as land slides, earthquakeslf',.and floods were of minor magnitude in their effects on pipelines. Dragging of anchor'lines 'can'rupture an offshore-pipeline (.2003,Chapter.6).. 2091 Fire and/or explosions' caused by gas' leaks, oil.leaks, acts of God, or human error. Possible damage to refinery, personnel, adjacent properties. 2092 Fire and/or explosions caused by sparks and improper venting. Most refinery firesand explosions are in the tank farm. 2907 Capital and operating costs for controls are estimated as follows,: Control System- Capital Cost- Operating Cost- $/Kw Ref Mills/Kw-hr Ref Water Poll-Chemical 1 (1921,233) .05 (1921,234) Water Poll-Ther'mal 10 (1915) (1920,,111-3) Total 11 .10 Based on the above, a 60P load factor and a net plant heat rate of.9053 Btu/Kw-hr (37.7P primary efficien 'cy from footnote 2908) the incremental capital cost I-S 2.31+04 $/l.OE12 Btu and theIncremental operating cost is 1. 10+04 $/l. OE12 Btu.' These are in addition to-the costs given in Footnotes 2906 and 3905. Note that incremental fuel costs associated with purchasing a ..6P sulfur residual oil.(for oil fired power plants) are notincluded in*the above.analysis. Although pro- perly attributed to air pollution contrpl costs, the. cost of fuel is not considered in the,operating and maintenance costs of the uncontrolled case and hence an incremental,fue 11 cost is not given.for the controlled case. V-11 FTN. 3901-9001 3901- Air Emission Components (Tons/l.OE12 Btu) From (9010,1-9) Particulates sox CO HC. NOx Aldehydes, etc. 7.34 .293 .190 19-.6 191 3.43 3903 See Footnote 1906, using.0.089 men per ME. 3904 Note that 'the only controls utilized are cooling towers to prevent thermal discharge to water. Ten acres are needed for the cooling towers with a 1000 ME plant. This is 6.3 percent of the total land use. Land use@for a 1.OE12 Btu plant (input) has been -linearly scaled from a 1000 ME plant. 3905 Cost of gas fired power plant at $100/Kw (1914) and (1915). Operating and maintenance cost exclusive of*fuel cost at 0.51 mills/Kw-hr (1906,45). A .60P load factor is assumed and the FCR for capital is 10P. 9000 The efficiency for room and pillar underground mining is 65 percent (.9002,65). This figure is based on preventing subsidence within'the mine. 9001 Air emissions as particulates are due to the vehicular traffic and blasting within the mine itself. For a mine processing 73,700 tons/day particulate emissions are 25 lb/hr (9000 1, 111-122). For a raw oil shale heating value of 7.53E+06 Btu/ton particulate emission due to blasting within the mine is 3.51E-01 ton/l..00E. +12 Btu input (9013). Using diesel trucks of 100 ton capacity .(gross to tare 2.5/1) and a 1500 ft average distance between extraction and primary storage, it takes -X328 round t_"ipsto haul 1.OOE+12 Btu of oil shale. Diesel particulate emissions based on 7 gal/1000 T-mi are 13 lb/1.009+3 gal. For hauling 1.OOE+12 Btu of oil shale 621,gal are consumed hence particulate emission.= 2.64E-03 tons. Total emission is 3.54E-01 tons/1.00E+12 Btu (9010,3.7). V-12+ FTN. 9002-9005 9002 Air emissi ons generated in the mine are generated by vehicular traffic.- Exhaust fans disperse the pollutants into the atmosphere Total polutants based-on .1328 round trips/l.OOE8q+12 Btu (see footnote 9001) are as follows: SOX 5.47E-0q3-ton CO 6qA.55E-02 ton HC 7.74E-03 ton NOX .7.61E-02 ton ALD 2p398qE-04 ton Figures based on -(9010,3.5) and fuel tons8qu4qmption of 621 gqal. 9003 Water pollutants from the underground mining operation will be negligible. If low quality-mine water with TDS ranging from 200 to 63,000 PPM is encountered, it will be_,: used for dust control and spent shale disposal, hence alleviating the need to draw high quality water from surface sources (9000).Initially mine water will be of high quality and could be released tqo nearby streams if ne cessqa0qry.. 9004 :.Fixed land impact for an underground oil shale mine assuming no subsidence is 10 acres for a 73,700 T/D operation -(9000 1-111-12). Land is for mine opening, equipment storage, maintenanc 2qp bldg, etc. The incremental land impact for waste shale disposal, assuming a combination of*surface disposal 0qaqn'd-return of theirste to the underground voids, is 1.93 acre yr/10 Btu from (9000 1-111-1q8). Thus for a-yearly output of.1.82E4q+14 Btu, the total land impact is 1.97 acre-yr/l.qOqOE4q+12,Btu..input. 9005 only the overburden necessary to open 6qthe-mine is considered solid waste. For 4 mine,shafts each 25 ft in diameter & 1500 feet deep, 1.47EqO5 tonof solq@d waste are produced at an@assumed density of. .05ton/ft 'This is for a 73,700 TPD oil shale operation (50,000 bbl/d) so that over the 30 year lifetime of the line the solid V-13 FTN. 9006-9009 12 waste amounts to 17.5 ton/10 Btu. .9006 Occupational health statistics are based on (9000,1- 111-9). Over a 10 year period nonfatal and fatal accidents for underground mining are 2,919 and 63.93 respectively (9000,1-111-235). For the 10year operation 1.OOE+16 Btu are extracted from underground mines. On a 1.OOE+12 Btu in:basis nonfatal accidents are 1.89E .01 and fatal accidents are,4.14E-03. 9007 Ancillary energy-requirements for the room and.pillar mining operation consist of 4,200 Xw-h/H (9027).for operating electrical shovels, etc. This is for a 50,000 BPSD operation (73,60P T/D)'. On a 1.OOE+12 Btu extracted basis, ancillary energy is 6.'20E+08 Btu.'Real energy consumption is 3 times the Btu equivalent = 1.86E+09 B 'tu. From footnote 9001, 621 gallons.0f.diesel fuel is used with a heating value of 13Z,690 Btu/gal (9032t269). Total.energy consumption is 1.2.7E+09 Btu/1.00E+12 Btu input. 9008 Water pollutants for the surface mining operation are zero (9000,1,1-73). Oil shale is dry and drains well. Storm water will be directed away-from the surface mine by piping systems. Water obtained during mine dewaterihg will-be used for spent shale disposal and dust control. Excess water of high quality (low in salinity) will be discharged directly to local streams andrivers. Highly saline waters may, be disposed of-by deep well injection or desalted and released Contamination of ground water reservoirs by.;aline water is hot quantifiable. 9009 Air pollutants from the surface mining operation are a result of vehicular traffic. Dust is controlled by water,sprays and blasting dust generated is not quantifiable. 15 cy electric shovels are used to excavate and load the 55 ton diesel (9000) trucks. It is.asrsumed that the average distance from shovel to portable crusher and conveying system is 2000 feet.. For-a gross to tare ratio of 2.5/1 and a fuel consumption of 7 gal/1000T-mi, see footnote 9001, it takes 819 gals to haul 1.33E+5 tons of oil shale. In addition to the oil shale haulageloverburden must be removed. Overburden averaging 450 ft (9 '000, 111,111- 11) and occupying 1.56E-01 acres/1.00E+12 Btu extracted (see solid waste) weighs 1.52E+05 tons assuming a I density of 0.05 T/CF. For a haulage distance@of l.-mile to the disposal site, the fuel consumption is 2494 gal/ 1.OOE+12 Btu extracted. Total fuel consumption is 3313 gallons/1.012 Btu out or 2054 gal/1012 Btu in. V-114 FTN. 9010-9014 Air emissions are as follows'(9010,3.7) Aarticulates .1.33E-02 tons, sox 2.77E-02 tons 8qC4qo .314qE-01 tons HC. 3'.79Eq-02 tons NO4qX 3.79E-01 tons A0qLD 3. O8qU- 0 3 tons 9010 Solid wastegenerated in the-,mining o peration consists of-o0qv0qerburden that must be removed to expose-the oil shale.; With an average overburden of,450'feet (90001@ III,III-11) and an area of 28.5:cres/2.42E0q+07 ton/y8q; (9000,1,111-12) 1.56E-01 acres are overturned on a 1.00E8q+12 Btu. Iextracted basis..Heatin6qg value of raw shaleiqn' 7..53E8q+06 Btu/ton. With a density of 0.05 ton/4qQF and, average overburden of 450 ft, solid waste is 9.42E2q+04 4qton/l.q0q0E2q+12-Btu input. H4qo0qfever after 16 yr (of the 30 yr lifetime) backfilling of overburden begins so that the solid waste is 5.03EqO4 ton/l.qOE12 Btu input. 9011. The incremental land impact for waste shal e and over- 2qburde4qadisposal, assuming revege8qtatqionof2qthe filled canyons an8q12 backfill.into the mined-out pit, is 3.99@ acreyr/10, Btu from q(q§q0q0q0,1-1q1q1-q1q5q). 9012 For a qiqO year surface mining operation, fatal accidents will be 6.2 and non-fatal will be,320 (9000,1.,111-235). Over the'10 years 3.65E15 Btu will be extracted q(900,0, 1-111-9). Fatal.and non-fatal accidents on a 1.qOqOE2q+12 E-03 and 5' spect0qively., Btu input basis are,ql,.06 .'44E-02 re 9013 Efficiency,o8qf the oil shalesurface mining operation is 62 percent (9000,1q111111-12). This figure assumes lower grade shale oils (less than 30-gal/ton) are not processed. 9014 Ancillary energy for a surface' mining operation consists of energy consumed by the electric shovels and diesel fuel used inhauling . For a large quarry shovel the energy consumption is 0q.6 Kwq-64qh/c52qy (9016,439). The specific volume of shale is 15 CF/T (9002,66). For excavating 1q.8qO2qOE04q+12 Btu of oil shale, 1.33E08q+05 tons of oil shale must be handled'. At 0.60 24qKwqjq-q!h/cy energy consumption, ancillary energy is 9.36E04q+07 Btu/1012q2 Btu in. Real energy is 3 times this or 6q2q.2q82ql24qE08q+Q2q8Btu. Diesel fuel consumption isq"2,054 ga0qlq"0q(28qPo08qotnote 9009). At 138,690q* ;Btu/gal'energy consumption is 2q.85E08q+08 Btu/2q1.2q02q0E08q+12 Btu in. Total consumption is 5.6624qE16q+06q8.q,24qRt00qU80q/l40q0l2 Btu in.. 24qVq-16q5 FTN.9015-9022 9015 Ancillary energy required to move 3100 T/H over a distance of one mile, with arise/fall of 1000 feet is 4000 HP. This is a 48 inch inclined belt conveyor system (9033). To transport.qOqOE2q+ '12 Btu energy consumption is 1.28E8q+05 4qKw-h. Real consumption is 3 times this or 1.3.E8q+09 Btu. ' 1 80q1 9016 Efficiency of the conveying system is 100 percent based on negligible fugitive dust losses (9000,114q11 q1q1q1-19). 9017 For a conveying system of one mile (from mine t2qo crushing plant)' and a right 2qof way'f 60 feet,,a 48 inch belt conveyor requires 7.2 acres. For a yearly output of 1.82E2q+14 Btu, land impacts equal .4.OOE-02 acre-year/l.qOqOE2q+12 Btu. 9018 Air emissions during conveying consist of fugitive dust. Enclosed conveying system will reduce,dust/ particulates to 20 lb/hr (9000,1,111q-132). For a year @output of,.82E4q+14 Btu, particulate emissions 4.80E-01 ton/l.qOqO4qE2q+12 Btu. 9019 Air pollutants associated with oqil'shale haulage come solely from truck exhaust. Dust is controlled by water sprays. For hauling 1.33E6q+05 ton oil shale,a 100 ton truck' will make.1330 trips. Assuming a distance of one mile, gross -to tare ratio of 2.5/1.0, and,fuel consumption of 7 gal/1000 ton-mile, fuel consumption is 2180 gal. Air pollutants are-as follows (9010,3.7) Particulates 1.42E-02 tons/l.qOqOE2q+12 Btu SOX' 2.94E-02 tons/l.qOqOE8q+12 Btu 8qC4qO 2.45E-q01 tons/l.qOqOE4q+12 Btu 4qH8qC 4.04E-02 tons/l.qOqOE4q+12 Btu. NOqX 4.04E-01 tons/qI.qOqOE4q+12 Btu A0qLD 3.27E-03 tons/l..OOE4q+12 Btu Particulate emission from oil shale dust is not quantifiable and is assumed to be controlled by water sprays during loading. 9020 Land impact for a roadway one mile long and a 30 foot 00qri 52q%q,80qO52qt of way is 2q.4q00q016qM2q-02 acre-yr/l.8qO8qOE04q+12 Btu based on a yearly output of 1.82E08q+14 Btu. 9021 Primary efficiency of truck hauling is 1.6qO6qOE12q+00 since fugitive dust,losses are assumed to be negligible. 9022 From footnote 9019, diesel fuel consumption to haul 1.0qO0qOE16q+12 Btu of oil shale is.2180 gallons. Heating V-16 FTN. 9023-9027 value of diesel fuel is 138,690 Btu/galq(10005,38). Ancillary energy is 3.0q24qE2q+08 Btu/qI.qOqOE2q+12'Btu. 9023 Power requirement for a plant handling 73,600 ton/ day is 20904qKw for:the crushing and sizing operation (9027q).his i's 0.68.5 Kwh/ton oil shale,. For,1p2ppp4q+05 toqn8q/l.qOqOE8q+12 Btu equivalent, the energy consumption is 3.09E2q+08 Btu.@F0qo'r real '0qconsump Ition ancillary energy is 3 x 3.09E2q+08 Btu q=9.28E2q+08 Btu. 9024 For a crushing 4qgeration handling-3070 t(0qo0qn2q/hr, 40 tons/ hr"are lost*(900 111,111-19). Primary"efficiency is 9.87E-01. 9025 Air-emiqssi4qon8qg from the ctushing.and"sizing,plant:consist primarIily of fugitive dust or particulates. These emissions are-0qemitted to the*atmosphere through the dust collection system.in the enclosed7crushing,plant ventilation system. A wet collection system, cyclone or ve4qhtu8qt i scrubber, will be placed on the primary crusher and a dry collection device, cyclone or bag house, placed on'the secondary and tertiary crushers. Fugitive dust'emissions from these devices will not exceed..35 lb/hr q(9000,1,1-79). For a yearly plant- O6qut qmis, 1.00 .put of 1.826qE8q+14tu, particulate e sions,on a ,E8q+122pu basis are 8.40E-01 tons. 9026 Water pollutants.in the crushing activity will be negligible. Forla 73,600 T/D operation, approximately 325 GPM will be necessary to operate dust control devices.his wastewater is high in suspended solids and probably will contain a dust suppress0qantsuch as' ARXL s0qulqfonate (9000,1,1q-79). The.particuql8qate-and water mixture will be piped to the spent shale disposal area. Wastewater from the crushing and retortin6q' plant will be 4q9 conveyed via pipeline to the spent'shale disposal site. it will be used for-wetting and irrigation of the spent shale. Excess water from the:sp6qent :shale pile will'2qbe trapped in' a holding pond andwill,be recycled as needed. No water pollutants will be discharged from the plantboundary-. 9027. Solid waste from th0qe crushing operation is aq-8qiesult of miscellaneous spillage and losses in the system as well as waste from dust control devices.. From footnote 9024, 960 T/D-q.are lost in the crushingq:opq'eration for04qa plant processing 73,36q600 T/D. For a yearly6ql0qc4qlut6qi0qput of 1.82E08q+14 Btu,' solid waste in 1737 tons/36q156q6 Btu. v-1q.7 .FTN. 9028-9031 9028 Land impact for the crushing operation handling 73,600 T/D with3 days storage is assumed to require 15 acres.. On a 1.00'.E+.12 Btu basis, land impact is 8.24E-02 acre-yrs.. 9029 Wastewater generated in the.retorting activity is a result of. boiler blowdown, steam'ge@erati6n, wet scrubbing., and process water. Water (2 to 10 gal/ton) is actually produced during retorting as the organic matter is released (9000). For a 50,000 BPSD plant, 0.1 MGD of-wastewater is produced (9000). This water contains 40,000 PPM as CAC03(9018). This process water will receive chemical treatment,with lime to remove carbonates, most of the ammonia, and some organic material,(9018). This wastewater will then be consumed in the spent.shale disposal system or used for dust control in the overall plant operation. No effluent will be discharged to the environment@ (9023) hence water pollutan@Es are O.'OOE+00. 9030 Although@significant quantities of air pollutants are generated in'both the Tosco and Gas Combustion retorts, the tail@'gas is contained in a closed system and fed to a gas-fiied power'plant. Air pollutants for burning retort gases will be accounted for under the process of electrical generation. Air emissions for the Tosco and Gas Combustion steps will be 0.00+00 tons/1.00E+12 Btu (9000,9028).' 9031 Air emissions for the Gas Gombustion electrical generation activity are based on combusting the 100 Btu/SCF (9000) retort gas in a conventional gas-fired power plant. Ret 'ort gas composition is given in (9028, 14).-Particulate emission is controlled to 0.03 GR/SCF at the retortplant. 184 lb/hr are emitted for a gas rate of 713889 SCF/min. For a heating value of 100 Btu/ SCF, particulate emission from the boiler is 2.15E+01 ton/l..OOE+12 Btu. SOX is calculated the same as particulate, however 85 percent SOX stack gas removal is requiried to meet the 1.2 lb/1.00E+06 Btu SOX emission standard. All other emissions are based on rates in,(9010,1-9). On a Btu input equivalent of natural ga's to retort gas of 100 Btu/1031 Btu = 0.0971 the emission rates are as follows CO 0.40 x 0.097 = 3.88E-02 lb/1,00E+06 SCF HC 40.0 x 0.097 = 3.8$E+00 lb/1.00E+06 SCF NOX -390.0.x 0.09.7 = 3.78E+01 lb/1.00E+06 SCF ALD 3.00 x 0.097 = 2.91E-01 lb/1.00E+06 SCF V-18 FTN. 9032-9035 For a 1.954 feed, the air emissions-on a 1.qOqOE2q+. 12 Btu basis are as follows -01 tons '2qC8qO .1.94E l.-94E8q+01 tons HC N8qOx 1.89E2q+02 tons A4qLD 1.46E2q+00' tons 9032 Air emissions.for the Tosco electrical generation activity are based on.the composition ofthe retort gas in (9028) and air emissio ns factors in q(9010,1q-9). Particulate matter will consist of inorganic ash which8qVill not be combusted in2qheconvenqtional gas- fired,power4qplant.: The'heating value of theas is 815 Btu/SCF (9000,I-2qJ-18,q) and the output is 32,049. SC8qFM on a-1.008qE2q+12 Stu basis the emission"of particulates is 2.62E2q+00 tons. S02 is.based on the same calculations. So.q@ emission is 5.22E8q+02 ton/1.00 E4q+12.'Th0qe remaining air pollutants are rat2qj4qoed on at, energy basis to8qthose of natural gas. The,heating value of Tosco retorq@_ 'gas is 815 Btu/SCF and .that of natural gas is 1031,4qttu/SCF, hence emission factors are 0.791 of those specified in' (9010). For a 1.q0q0E2q+12 Btu-feed of 1.23E2q+9 SCF, the air emissions are as follows.. NO0qX 1.90E8q+02 tons C2qd 1.9q50qE-01 tons, 4qHC 1..95E2q+01 tons 4qA0qLD 1.46E2q+00 tons 9033 water pollution figures are based. on (9015). For a q10'0,000BPS4qD refinery BOD loading is.100b/D. The -B8qOD loading.for a total plant Output of q9.53E2q+13 Btu/ yr (2q5.80E2q+06 Btu/BBL)for a q50,000 BPSD refinery is 9.6'1E-02 ton8qs/l.qOqOE6q+12 Btu. In a controlled case an A2qPI separator,is used to remove 25 perce0qhtO0qD. BOD is.7.21E-02 tons/l.qOqOE8q+12 Btu (9015q). 9034 Air emission factors are based on a'storag8q6 of 4.734qE2q+ 0-BB0qL (2q10 days).of crude oil in one 500 BBL floating roof storage tank. C air emissions are .based on 30-lb/day breathing l8qoss'(9010).and no working loss. 20qYor aq-'storage,o0qf 2qJq.6qO2qOE12q+12 Btu/yr, the HC emissions are 5.48E04q+00tons.. 9035 For a 50,000 BPSD pl48qint.q,q.40q,ac40qr6qes are re76q464qdire68qd for crude storage. For a yearly output of 9q.53E12q+12 Btu, the. landLimpa32qqt 4qiS, 4q.1632qEq-01 acre-y04qr/1q.6q068q012q+12 Btu (9000, Vq-19 FTN. 9036-9043 9036 Primary efficiency for crude oil storage is 100 percent'since hydrocarbon.emission'is considered to be negligible with floating roof storage tanks. 9037 Ancillary energy is based on pumping 472'.6 B8qB8q@/D q(1.qOqOE2q+12 Btu/yr) 36.5 times a year(10 days qfqitorage) both into and out of the storage,tank. Assuming a constant total head of 75 feetp a pumping rate of 2000 GPM through,an 8 inch steel line, and an effi- ciency of 75 percent, 50 horsepower is required to pump 12.0q1 hours. Btu equivalent is 1.54E2q+06 Btu. 9038 Ai0qr pollution is based on diesel engine-pump emissions factors.! To pump 172,500 BB4qL of crude, 3.43E2q+0-9 Btu are required using 450 Btu/T-mi (9034,7) and 7.03 lb/gal (9003,588). For distillat0qe'heating value of 5.83E2q+06 Btu/BB2qL-' 6q2.478qF.6q+04 gals are consumed. From (9010.,3-7) air emissions are Particulates 1.614qE-01 tons NO0qX 4.56E2q+00 tons sox 3 34E-01 tons HC 4q:56E-01 tons 4qC8qO 2.78E8q+00 tons 'A8qLD, 3.70E-02 tons 9039 To pump 172,500 BB0qL of crude 6q6il 300 miles (9003,2), 3.43E2q+09 Btu are required (see footnote 9038). Ancillary energy is 3.43E8q+09. 9040 Solid waste is based on data in (9000,III-Iqlqi-q@3). For every 73,600 tons of oil shaIle processed, 60,000 ton of ..spent oil shale is generated. For a 1.qOqOE8q+12 Btu equivalent oil shale feed of 1.338qE2q+05 tons, 1.q0q8E2q+05 tons of spent shaleis generated. 9041 The retorting plant itself requires about 5 acres (9002,94) for a'50,000 bbl/d operation (72,600 ton shale/6q@q). For a raw shaleheating value of 7.53EqO q12 Btu/ton8qthis is equivalent to 2.78E-02cre yr/10 Btu. Land impact for spent waste shale is considered in the extraction footnotes. 9042 occupational health statistics ar16qe based on data in 4q(9000q,4q1,q1111-235). Statistics are based on a 10 year period., The fatalities and nonfatalities are 1.37Eq-03 and 1.44Eq-01/1.2qO6qOE12 Btu. 9043 Fixed land impact for the Gas Combustion retort plant is 10 acres for a 50,000q-BPSD plant. on a 1.82E08q+14 V-20 FTN. 9044-9050 Btu/yr input, fixed land impact is 5.50E02 AC-yr 8qA9002,83). Land impact for.spent waste shale is considered-the extraction footnotes. 9044 Primary efficiency for the.Gas Comb4qU0qgtj6qo6qni. retort is 67.3 percent@of the standard Fischer'assay based on, input of 5.470qE8q+11.Btu.and output of 3.680qE8q+11,Btu (9000). 9045 Primary efficiency of theosco II,indirect,.heating retort-is.77.6 percent of standard Fischer,assay of the recoverable-organic material (9035,I4qVq-11q). Based on 4.8q2E2q+ll Btu output and 5.47E8q+ll Btu.input (total heat b0qalance'of 970qA percent accounted for). 9046 Ancillary'energy is based on data.from'.(902'q7,41). Power requirements for a.73,600 T/D retorting plant is 27,960 4qKw forretorting,4qAnd 23,610 Kw for solid waste disposal. For a plant input of 1.qOqOE8q+12 B2qtu/yr, the power-requirement is7.75E2q+09Btu. Real energy is 3 tqiqjqi6qmqs this or 2.338qE6q+10 Btu. 9047 For a 73.,600 T/D underground mine the fixed capital costincluding deferred capital and interest during- construction is 2.q17E8q+07 dollars (9000,1). Fora mine producing 1.82E8q+14 B0qtu/yr (24.2EqO6 tp8qy) -the cost allotted to 1.qOqOE2q+12 Btu, with a 10 percent fixed' charge rate is 7.74E8q+03 dollars. Operating cost including payroll ' supplies, labor, taxes', and insurance is 2.22E4q+07 dollars. 'On a 1.qOqOE8q+12 Btu basis, operating cost equals 7.93E8q+04 dollars., 9048'* For a 147,q@00 T/D surface mine (3 64E14 Btu/yr), the' fixed capital.cost including deferred c6q@pital.and interest during mine 'development is 4.96E8q+07 dollars. on a 1.OE2q+12 basis and at.a fixed charge rate of 14q6 percent, fixed cost is8.43E2q+03 dollars (9000,Iq)@. Operating cost is 1.78E8q+07 dollars (9000,1). On,a 1.qOqOE8q+12 Btu 6qVasis, operating cost is 3.03E2q+04 dollars. 9049 For an'inc -lined belt conveyor systemhandling 3100 T/hr (1.84E8q+14. Bt8qu/yr) the capital and operating cost are 2.75E8q+06 and 2.69E8q+04 dollars/0qyr.:0qOn a 1.qOqOE8q+12 .Btu basis the capital cost is 1.49E8q+03 and annual operating cost is 1.46E12q+02 dollars/yr (9038q3). 9050 Capital'q,c24qost for truck haulage is basedq.6qon,the cost of 2 road graders, 2 water trucksq,q.and 50 q- 100 ton. dump trucks. Total capital.cost is 4q.68E08q+06q- dollars for hauling l.'82E08q+14 Btu/yr.-At a 10 percent fixed charge rate, capital cost 2.46E12q+03 $/1q.00E08q+12 (9029,7/26).q@.Operating cost based on.(9016,583). using Vq-21 FTN. 9051-9054 1.56E+02 $/hr as operating cost toaul 1.828qE2q+14 Btu/ yr. Operating cost is 6.74E+03 $/l.'OOE8q+12 Btu. 0qp 0 9051 Capital cost for a 73,600.T/D crushing operation (1.82E2q+14 4qUtu/yr).i0qs 1.23E2q+07 dollars-q(90qD0.JIIq).pt a 10 percent fixedcharge rate, fixed cost is 6.67E8q+03 $/1.q0q0E8q+12Bt4qu. Operating cost is based-on energy consumption only. For a requirem nt of.2090 Kw (Footnote 9023), operating cost at 0.01q5 $/0qKw-h is 1.36E-8q+qOqj $-6q/1.q0q04qr8q+12 Btu. 9052 For an.input of 72,600 T/D (1.86E8q+14 Btu/yr) of oil shale, the capital cost for a retorting plant is 1.16Eq+08 d0q4l4qarq3 (9027,37). On a 1.qOqOE2q+12 Btu/yr basis and a fixed rate of 0 percent, the fixed cost is 6.44E8q+04 dollars. Operation cost for a 72,600 T/D plant is.1.87E8q+07 dollars. On a q1.q0q0E8q+12 Btu/y'4qr basis, the annual operating cost is I.. 048qEq78q0.5 :doql0ql8qarq4. 9053 Crude oil shale storage cost is based upon a throughput of 172,500 BBL/yr and a 10 day storage capacity. Equivalent tank size would:be 4720 BB8qL. Capital or fixed cost for a 16,200 BBL tank is : 124,000 dollars. At fixed charge rate of 10 percent,, fixed cost of a 5000 BBL tank is.3.83E2q+03 $/1.q0q08qE2q+12 Btu (9024,138). Operating post is approximately 7 percent (9036,162/ 168q). Operating cost are 2.68E8q+02 $/1.q0q0E2q+12 Btu. 9054 For atmospheric distillation.-, process water pollutants are based on (9015) and an 4qan8qnual.BBL feed of 172,500. All wastewater requires primary or physical treatment and secondary treatment in the form of. an activated sludge plant. Removal efficiencies for BOD, Phenols, '-Sulfides, and TDS are 90, 95, 95, , I 80 percent respectively. Pollutants for distillation are as follows (9015, Table 5): BOD 1.73E-03 tons/1.q0q0E2q+12 Btu Phenol 4.30E4q+00 tons/1.q0q0E4q+12 Btu Sulfide 4.304qE-03 tons/1.q0q0E4q+12 Btu TDS 6.040qE-01-tons/l.qOqOE4q+12 Btu For a 1.qOqOE8q+12 Btu/yr distillation process, power required is 1.91E04q+10 Btu (9022 32). This includes electrical at 6,qp92qOE-01 HP-Hr/B32qL1 and fuel (steam) at 1.07E08q+05 Btu/28qBB20qL. Cooling water is 3.74E08q+07 gal/ 1.2qO2qOE08q+12 Btu. Wastewater is 10 gal/B72qB24qL feed (9020). Miscellaneous HC emissions are based on (9010,9-4) utilizing cooling water, wastewater, and 272q15 of refinery capacity. HC 2.73E08q+00 tonq.96q/1.0024qE04q+12 Btu. FTN. 9055-9059 9055 Cooling water for a 1.00+12-Btu/yr refinery utilizing 'a'hyqd6qko0qgein'0qp0qla4qnt' is 1.71E2q+09 gal/yr. All thermal pollution may,0qbe eliminated by utilizing a mechanical draft wet cooling tower. 9056 Air emission for the discreet refinery.activ4qities are a result of boiler and process heaters. Sufficient low Btu fuel gas is. generated in the retortqiqn4q4.'steps. to supply the re6qfineries'needs. To process 1.,OOE2q+12 Btu of shale oil 9.068qE8q+10 Btu2p fuel is required and 3.54E8q+10 Btu of,.2qd-electrical power is required, based on 50i,0qKw and 40 percent efficiency. To process 172,500 BB4qt of shale oil requires 82.8 hours and retort gas produced is 1.76E8q+qlql Btu (9028) Since the oil shale upgrading plant Will be an inte8q@ral.part ofthe total shale oil process, the fuel gas produced will be used within a centrally located power plant which will produce all electrical, fuel and steam requirements for the'operatqion. Air pollutants produced by burning fuel gas are accounted for in the power generation process. Except for miscellaneous HC emissions (footnote 9054)ll emissions are qO.qOqOE8q+00. 9057 capital and operating cost Isfor -a 10000.BPSD'atmospheric distillation column are 15.97E2q+06 do llars (Footnote 2043) a0qnd 14. 2 cent0qs/BBL (9022) respectively. 'Based on a 1.qOqOE8q+12 s Btu/yr input, equivalent to 473 BPSD,.the capitalost i 7.55E2q+03 dollars. Operating cost is 2.45E8q+04.dollars/1 'OOE8q+12 Btu/yr Cost oqf wastewater treatment is attributed to the distillation process. For a wastewater flow of 6144.gal/D for processing 1.qOqOE4q+12 Btu/yr, wastewater treatment costs are.4.3q!E8q+02 dollar capital and 4.1pE8q+02 dollars operating cost. Cost figures are based on footnote 2102 scaled down to-handle 614q44'gal/D. Total costs for distillation are 9. 05E8q+ 03 dollars capital and 2.51E8q+04 dollars operating. 9058 Water pollutants are,.based on feed of 159000 BB6qL fo8qr the d6qelayed-coker. Wastewater treatment efficiencies are stated,in footnote 9054. Pollutants areased-on (902q6). Water' pollutants after waste treatment are as qf qoql2qlcqk0qwqa Non-De40qg64qradable Organics 2.47Eq-q-q;02q:tonqs COD 1.02E08q+00 tons TDS 4.77-01 tons 9059 Air 'emissions for process a36qnd boiler,fee40qd are given in (9031) and (9032). Miscellaneous HC emissions from pipelines, val52q*esqy flanges# pump seals are 71 6qlb/1.00 V- 23 FTN.,9060-9066 E+03 BBL refinery. Of the four major processes, the coker throughput is 1/5 of total refinery throughput. HC emissions directly associated with coker are 2.13E+00 ton/1.0q0E2q+12 Btu/yr (9010,9-4). 9060 Ancillary energy for the delayed coker'is 4.68E2q+05 Btu/ BBL based-on a fuel requirement of 4.65E8q+05 Btu/BBL and electrical requirement of 2.74E8q+03 Btu/BBL (9022,65). For a1.qOqO8qE8q+12 Btu/yr feed of159,000 BBL, energy is 7.44E8q+10 Btu. 9061 Operating cost based on 40 cents/BB0qL (9022,65). Escala- ted 60 percent (9037) to reflect 1972 cost on.1.q0q0E8q+12 Btu/yr basis,. operating cost.is .37E8q+04 dollars. 9062 Air emissions based solely on HC emissions from cooling water. No other information available. Cool- _-Lag. water required for a 5.55E2q+06 SCF/D H2 plant q(1.qOqOE8q+12 Btu/yr gas'feed) is 900 gal/MSCF H2 (902q2,183). From (9010) HC emissions are 6 lb/ 1.qOqOE8q+06 gallon cooling water. HC emissions are 4.92E8q+00 tons/l.qOqOE4q+12.Btu/y-0qr. 9064 Water pollutants are based on (9020,11) for the hydrotreating Unit with a 1.qOqO8qE8q+12:Btu/yr throughput of 172,q@00 BBL. All wastewater receives primary and secondary .treatment. Removal e qfficiencies given in footnote (9054). Water pollut8qants'are as follows: BOD 8.63E-02 tons COD 1.72E8q+0q6 tons Non-Degradable Organics 7.33E-01 tons TDS 6.04E-01 tons 9065 Ancillary energy consists of process fuel@q(steam boiler feed) and electric power. From (9022194) fuel requirement is 60,06qMBt8qd6q/BB0qL and electrical and compression-is 5247 Btu/BBL. For a 1.qOqOE4q+12 Btu feed of 172,500 8qBB0qL, energy is 1.130qE4q+10 Btu. 9066 operating cost for a hydrotreating unit is 28.10 cents/ BBL,0qdn2qCluding a 60 percent escalation cost (9022,94). For a 172,500 BBL'fe0qed, operating costs are 4.85E8q+04 dollars. From (Footnote 2044) a 40,000 BPSD h20qydrotreating unit costs 3.20E08q+06 dollars., For a feedq'of 172,500 BBL equivalent to 1012 Btu (521 BPSD)q,q@ at fixed rate of 10 percent, fixed cost is 4.17E8qO3 dollars. V-24 9067-9074 9067. Ancillary energy for the-'@T0qo4qz@co power generation activity is qO.qOqOE4q+00.' Tdqs8qdo II retort gases will produce the fuel and steam within the upgrading facility.., q§068 Ancillary energy for-theGas Combustion power genera- tion activity is 0.00+00. Gas'produced in retorting will'be used to produce steam for the upgrading facility. 906 Land impact for in situ drqi1ing,and restoration is based on the time average land i0qmpact-fo2qithe@ Colorado, Utah, and Wyoming tracts.8qAveraging the land.impacts gives 1088 acres over a 30'year period. For a crude value of.80E8q+06 Btu/BBL, and output of 50.000 BPSD, i 9.53E8q+13*Btu are produced. 6qOn a 1.qOqOE8q+12 Bt6qunput basis, land impact equals-6.47 ac-yr (9000, 9070 Occupationalhealth statistics are based on (9000,1, 111-235). On a 1.qOqOE8q+12'tu input basis, deaths are 3.64-03 and injuries are 5.69-01. 9071 Water pollutants for the g4qas treating facility are - .-zero based on'steaqm-stripping of H2S and NH3 from sour refinery tail4qgaqs. Based on (9038,98) water. from treatment facility is of sufficient quality for reuse. Total water effluent is 4.31E4q+08 gal/yr/ 1.OE2q+12 Btu0q/yr input. 9072 Air pollutants from the gas processing activity consistlofo 2 fromlaus recovery system. With a 99 .percent efficient Claus plant with stack@0qqas cleaning, so emissions are. 4.3E-01 T/D H S for a 2.39E4q+10 Btu/D fe2qidq-(9000,IIIq)2po2pa q1.002qt8q+12 2Btu/yr feed the SO emissions are 33. tons/yr. All other emissions a0qie 0.004q+00 si.qnce,gases are recycled to hydrogen plant. 9073 Solid waste for the gas treatingacility is 0.008q+00 since elemental sulfur and ammonia have a market value (9038,9'9). 9074 Land impact forq.68qa 2.39E04q+09 Btu/Dq"gas treating facility isq' assumed to occupy 2.0q'08qacresq. On a 8qi.OOE28q+12 Btu basis, land impacts ar28qe 2.55E08q+00 A-yrs. V-25 FTN.9075-9078 9075 Primary efficiency for-the gas treating facility is 100 percent based on (9000,111-111-26). 9076 For a gas treating plant for steam stripping, sour water stripping, sulfur recovery.(0qClaus),, and ammonia recovery, the capital costs ate: (9038) Gas q+Water Stripping.q1.35E2q+06 dollar/40 T/D NH3 (9039) Claus Plant 3.q5-OE4q+05-dol.qlar/50 T/D S To process 143 T/D NH3 and 43 T6qlb s q(5q0,0q00 BPSD plant), using a 0.6 scale factor,@total capital cost is 2.90E q+06 dollars. The gas feed equivalent is 2.39E8q+09 Btu/ D. using -a q1..qOqOE2q+q1-q2 Btu/yr basi 's, at 10 percent fixed rat0qe,capital cost is 3.32E8q+05 dollars. Operating cost is 1.21E2q+06,dollars/yr (9038) for stripping-and 1.qOqOE8q+05 dollar/yr for Claus recovery (9039), using a 8ql4qe'factor. On a 1.qOqOE2q+12 Btu/yr basis, 0.6.sca operating cost is 1.50E2q+06 dollars/yr. For a 1.qOqO0qE2q+1.q2 Btu/yr feedl 49300 ton of NH3 and 27000 ton of S qi0qWeql produced. At 40 dollars/ton NH3 and 15 dollars/ton S,, annual credit for gas by-product recovery is 1.99E2q+06 dollars/yr. Operation cost is qO.qOqOE2q+00 dollars. 9077 Capital cost for a 50,000 BPSD.In Situ retorting plant, using recovery .plant and co6qWpresson and initial wells,. i2q@ 94.7E8q+06 dollars for processing 1. 68E8q+14Btu/yr input. Annual 'ized capital cost q(8q10 PC FCR) for 1.008q9+q12 Btu/Yr input is 5.64E8q+04 dollars, plus l.59E8q+03 (from Footnote 9079) for a total of 5.78E2q+04 dollars. 9078 Air emissions for the In Situ retorting activity are based on flaring the low Btu product gas., A 50,000 1 - II BPSD plant will produce 1.49E8q+09 SCF/CD q(9000'q1q1q1'q1q1q1q- 29) of low Btu gas, 30 Btu/8qS8qC4qF (9008,15) which is flared after particulate removal'to 0.03 gr/SCF. Assuming 90 percent combustion,control on CO & HC, emissions are q(90-28): Particulates 1.16E8q+03 ton/yr POX 4.90E8q+04 4qN0qOqX NA HC 2.82E4q+q04 24qC28qO 2.12E04q+2q63 Based on a retorting efficiency of 56.7 percent and a 50,000 bbl/d operation the air pollutants are: V-26' FTN. 9079-9083 ton/l.OE12 Btu Particulates sox 2 62E2q+02/ 2qC2qo 1.13E2q+q01 4qH8qC 1.50q1'4qE2q+02 9079 Water pollutants from In situ ret6qbrt-qing,are q0.q0q0E2q+q00 since the water generated is treatedq:with lime, carbon absorption, and ion exchange resins (9018). For a plant producing 50,000 BPSD,.560,000 aal/D-are generated (9000q0,111). After,waste treatment the waste- -water contains 1890 PPM'which'is suitable for cooling. tower makeup water (9018). For a 1 MGD treatment system the costs are: Process Capital 02eratin6qg Lime Treatment 4.6lE4-04 4.61E8q+03 -(9041) Ion Exchange- 2.10E2q+06 .2.10E2q+05 (9041) Carbon Absorption, 5.36E2q+05 6.qOqOEq4-04 (9040) Lime and ion exchange operation Costs are assumed to be 10 peqicent of capital cost. For a plant processing 1.qOqOE8q+12 Btu/yr costs aria (retorting efficiency is' 5,6.7 percent)q; Capital. 1.59E4q+03 dollars Operation 1.64E8q+03 dollars 9081 Miscellaneous HC emissions based'on process drains, cooling water, pipes, valves, flanges, and pumps - (9010). For a hydrotre6qating unit processing 172,500 BPSD,.cooling water is 3.86E2q+07 gal, wastewater is 1 gal/BBL, and hydrotreating throughput.is 2/5 of, total refin4q6qry,capacity. For a 1.qOqOE8q+12 Btu/yr refinery misc. HC emissions are 2.59E8q+00 tons. 9082 Waste water will be treated and recycled for use within the plant boundaries. It is assumed that no water pollutants will be discharged (900q6,IIqIOI0qV-80). 9083 Air pollutants for processing 18q40E8q+12 4qBtu/yr occur in the retorting, dis8qtillationqt.delayed coking, H2. manufacture, hydrotreating, gas treating, and power generation activities.For each process ,pollutant on a 1 q*OOE08q+l2q@ B76qtu/yr basis s16qee individual,p20qtocesses and respective footnotes and references. q.To process 1q.2qO6qOE12q+12 Btu/yr, the respective feeds-and pollutants .are: Vq-27 FTN. 9084-9085 Process Feed Part. NOx SOx HC CO 4qLD Retort 13300OT/Y Dist. 97900BPY 1.71 Coking 48950BPY 0.62 H2 Manu.., 779000SCF/YR 2.10 Hydrot. 89016BPY 1.32 Gas Trt., 4.378qE2q+10B4qTU/YR 1.5 Storage 91486 BPY 21p. Power q1.q8q82qE2q+11BT4qU/YR 4.04 35.5 29.1, 3.65 .0365 .275 Total 0qT-4q74q66qT q-35q-.0qT TO q-.6 3 4qMq-6-4q9 Total pollutants to process 1.qOqO4qE8q+12 Btu are q8.28E 6q+01 tons. 9084 Air pollutants for processing.qOqOE2q+12 Btu/yr occur in the retorting, distillation, delayed coking, H2 manufacture, hydrotreating, gas treating, and power generation activities.or each process pollutant on a 1.0qOE2q+12 Btu/yr basis see the individual processes and their respective footnotes and references. To process 1.qOqOE2q+12 Btu/yr of oil'shale, the unit feed and pollutants are:. Process 4qF0q6ed Part. NO4qX q!q!C 8qC8qO ALDI Retort 13300qOT/Y Dist. 122000BPY 2.16 Coking 61000BPY 0.777 H2 Manu. 97206q60SC ,F/YR 2.63 Hydrot. q1q1q1000BPY 1.86 1.66 Gas Trt. 5.4,q8E8q+10BT4qU/YR qSItorage 114500BPY 3.64 Power 6.83E8q+10BTqU/YR 0.178 12.9 35.5 1.33 0.0133 0.099 Total .0.178 12.9 37.4 6qiq-q2q-.q2 -2q6-.q-0q133 0qTq-6qMq-9 Total air pollutants for processing J.qOqOE6q+12 Btu are q6.28E2q+01 tons. 9085 Air pollutants for processing 1.qOqOE2q+12 Btu/yr occur in the retorting', distillation, delayed cokings, H 4qn0qianufacturing, hydrotreating, gas treatingqr an0qi power generationq'activities.q'For the pollutants fo24qk each process, on a 1.2qO2qOE4q4q-12 Btu/yr.basis, see the individual-processes and the respective footnotes and references. To process 1q.6qO6qOE16q+12 Btu/yr of oil shale, the unit feed and pollutants are: V-28 FTN. 9086-9090 Process Feed Part NOX SOx, HC CO ALD Retort 1724OObPY 6.22, 262.0 1512qA 11.3 Dist., 97900BPY, 1.71 Coking 48950BPY 0.62 H2 Manu. 779000SCF/Y4qR, 2.10 Hydrot. 89016BPY 1.32 Gas Trt. 4.8q3q7E8q+10B0qTU/YR 1.5 Storage 914q86BPY 2,8q91 Steam * 3904q+10.BTU/YR .286 7.5 .011 ..76 .007 .134 Total 51 8qT8q68qT-_8q3q7q_ql8qZ8qVq_-4qTq_ 8qT8qrq-.6q7q-q- .134 Total' pollutants for processing 6ql.q0q0E8q+12 Btu are 4.49E4q+02, tons.. 9086 Primary efficiency -for qIqn -2qSq! tu oil shale retorting is assumed to be 56.7 percent. For nuclear fracturing and retorting, efficiency 0qmay be as high as 70 percent.(9001,,12q-9).. For an input of 172,400 BBL/yr (ql.,OO8qE2q+12 Btu/yr), 97900 BBL/yr are produced. 9087 Land impact for processing 1.qOqOE4q+12 Btu utilizing' the gas2pomb0qustion method is based on 320 acres fixed' land for surface facilities and o0qffsitqbs from (9000, 1-111-12) for a 72,700 T6qPD shale oil operation (50,000 bbl/d). 9088 Land impact for processing 1.qOqOE8q+12 Btu utilizing the Tosco.IIprocess is based on 320 acres fixed land for surface facilties and offsites from (9000,1-111-12) for. a 72,700,TP6qD shaleil operation (50,000 bbl/d). 9089 Land impacts.'for conventional In Situ processing of oil shale is' based on 230 acres fixed land foqr,:surface facilities*and offsites from (90q00,I7III-12)f6r a 50,000 bbl/2qd operation plusthat land required in the retorting process from footnote 9069 for a total of 7.84 acre yr/l.qOE12 Btu. 9090 occupational health statistics are based on retorting and power generation only. No other information is -the available. For individual processes, refer to respective fQot16qhotesq,a52qnd references. Toprocess 1.8qO2qOE08q+ 12 Btu/yr theq.impa6qct4qs are: Process Deaths Injuries Man-Days Gas Combusti on 1.48Eq-03 1. 5520qE-6q088q1 4.44E-01 Tosco II 1.41Eq-03 1.48E-01 q.1.49E-01 In Situ 3q, 66E-q-q;q-03q- 5.71E-01 9q..28q0,28qE8q-02 V-29 FTN. 9091-9098 9091 Primary efficiency of@the delayed coking process is 89.7 percent based on an input of 1.55E+ll Btu/D (hydrogen and product) and an output of 1.39E+ll Btu/D (fuel gas and product) (9000,111). 9092 Primary efficiency of the hydrotreating process is 96.8 percent based on an input of 3.13E+ll Btu/D (hydrogen and product) and an output of 3.02E+ll Btu/D (fuel gas and product) (§000,III). 9093 Primary efficiency is based on the assumption that 53500 B/D of crude oil will be produced by retorting 72600 T/D of 7.53E+06 Btu/T oil.shale. Recovery efficiency is 56.7 percent due to.migration and drift of underground shale oil. 9094 Waste water will be treated and recycled for use within the plant boundaries. It is assumed that no water pollutants will be discharged (9000,III-IV-80). 9095 Overall primary efficiency is based on an input of. 1.33E+05 ton/yr (1.OOE+12 Btu/yr) and an output of 91486 BBL/yr (5.31E+ll Btu/yr) (ROOO,III). 9096 Overall efficiency of a Tosco II oil shale plant is based on an.input of 133000 ton/yr (1.00.E+12 Btu/yr) and an output of 114,500 BBL/yr (6.67E+ll Btu/yr). 9097 Ancillary energy for a Gas C-ombustion oil shale processing plant is O.OOE+00 Btu/yr. A plant processing 72,600 T/D requires 50 MW (9031), hence a plant processing 133,000 T/yr requires 250 Kw. Total electrical energy for the.plant will require an input of 2.09E+10 Btu/yr and a fuel/steam requirement of 3.90E+10 Btu/yr (9022). Total-energy required to process 1.OOE+12 Btu/yr (133,000 T/yr) is 6.23E+10 Btu/yr. Fuel gas produced in retorting is 1.11E+ll Btu/yr (9000,111). 9698 Ancillary* energy to process 133,000 T/yr (1.OOE+12 Btu/yr) utilizing the Tosco II method-is O.OOE+00 Btu/yr. Electrical requirements for retorting and upgrading will.be 250 Kw-hr/h (1.97E+10 Btu/yr) and 1.2B*09 Btu/yr (9022) respectively. Fuel/steam requ irement for upgrading is 4.83E+10 Btu/yr. Total energy required is 6.92E+1-0.Btu/yr. Fuel gas from.,retorting as a result of processing 133,000 T/yr is equal to 6.92E+10 Btu/yr (9028), hence a Tosco II plant will be self-sufficient. v-3o FTN 9099-9102 9099 Ancillary energy for the In Situ oil shale processing plant is 5.99E8q+1.0 Btu/yr. Electric power'required to process 133,q000 T/D by in situ,retorting, And upgrading the resulting.97,900 B/D, is 2.09E8q+10Btu/yr. This assumes total plant electrical requirement is the same as the equivalent gas combustion planti-250 q]qKw-hr/h. Fuel/ steam for the upgrading facility requires 3.90E6q+10 Btu/yr(9022). Total-energy required is 5.9q98qE8q+10 Btu/ yr. Gas produced,for in situ.reto0qrting (29.2 Btu/SCF) is too low@qin heating value for economic use hence it is flared. All energy will be purchased, 2.09 E8q+10 Btu/yr electrical-energy and 3.90E4q+10 Btu/yr fuel gas. Natural,gas will be4qused to firea0qheavy industrial boiler to produce steam for upgrading.' 9100 Efficiency of a heavy industrial boiler is q8q8.0 percent (9041,19-6). 9101 Total annual capital and operating cost qfor processing 133000 T/y4qr q(1.qOqOE8q+12 Btu/yr) utilizing the gas combustion retorting method is given below. For references and footnotes, refer to individual processes. Cost figures are in'dollar6qs. Annualized Operating Total" Process. Feed Ca8q2ital Cost Costs. Costs Retorting 1.33E8q+05T/Y 5.82E8q+04 9.38E8q+04 q1.52E0q+qbq5 Distillation 9.79E8q+04BPY 4.28E4q+03 1.40E8q+05 1.44E8q+05 D. Coking, 4.90E8q+044qBPY 1.10E8q+04 1.95E8q+04 3.05E8q+04 H2 Manuf.- 7.79E8q+05SCF/YR 1.04E4q+04 5.19E8q+04 6.23E8q+04 Hydrotrmt 8.90E8q+040qBPY 1.95E+04 2.q50E4q+04 4.45E8q+04 Gas Trmt 4.37E8q+q1q0B6qT.U/YR 1.q28E8q+04 qO.qOE8q+00 1.28E8q+04 Storage 9.15E4q+04BPY 2.02E4q+03 1.41E4q+03 .43E8q+03 Power Plt 1.11E4q+11B6qTU/YR 3.96E8q+04 I.18E8q+05 3.32E8q+ 2qT.q-6qU6qTEq-4qT0qUqS' 9102 Total annual capital and operating cost for processing T/Y q(1.qOqOE8q+12 Btu/yr) utilizing the Tosco II method is given below.. For references,and.footnotes see individual activities. Vq-31 FTN. 9103-9105 Annualized operating Total Process Feed Ca2ital Cost Costs Costs Retorting 1.33E+05T/Y DiIstillation 1.22E+05BPY 5.33E+03 1.75E+05 1.80E+05 D. Coking 6-10E+04BPY 1.37E+04 2.4'4E+04 3.81E+04 H2 Manuf. 9:72E+05SCF/YR 1.30E+04 6.49E+'04 7.79E+04 Hydrotrmt l..11E+05BPY 2.43E+04 3.13E+04 5.56E+04 Gas Trmt' 5.48E+10BTU/YR 1.61E+04- 7.58E+.04 9.19E+04 Storage 1.15E+05BPY 2.53E+03 1.76E+'03 4.29E+03 Power Pit 6.91E+10BTU/YR --- 3.96E+04 7'.50E+04 3.73E+05 4.87E+05 9103 Total annual capital and operating cost for an In Situ oil shale operation processing 133000 T/Y.(56'.7 percent. efficiency) or 97900 B/Y are given below. For individual refere''nces and footnotes see the respective individual activities. Annualized, Operating Total Process Feed@ Capital Cost Costs Costs Retorting 1.33E+05T/Y. .5.12E+04 --- 5.12E+04 Distillation 9.79E+04BPY 4.28E+03' 1'.40E+05 1.44E+05 D. Coking, 4.9bE+04BPY 1.10E+04 1.95E+04 3.05E+04 H2 Manuf. 7.79E+05SCF/YR 1.04E+04 5.19E+04 6.23E+04 Hydrotrmt 8.90E+04BPY 1.95E+04 2.50E+04 4.45E+04 Gas Trmt 4.37E+10BTU/YR 1.28E+03 6.06E+04 7.34E+04 Storage 9.15E+04BPY 2.02E+03 1.41E+03 3.43E+03 Steam Plant 3.90E+10BTU/YR 1.11E+05 2.98E+05 4.09E+05 9104 Disasters (a-single accident resulting in 5 or more deaths) occur frequently in underground mines. In the past 40 years"@bnly 6 calendar years went without a' disaster occurring. 9105 Primary efficiency is defined as 1 minus the fractio'n of the primary fu *el input attributable to physical losses minus the fraction of the primary fuel input used in the processas fuel and/or steam. By equation, the primary .efficiency equz as (1-(Y 1,OE12)-(Z/1.OE12)) x 100P, where Z is the Btu of physical losses and Y is the Btu of in- put feed used as fuel and/or steam. All of the refinery processes would use fuel gas as the primary fuel; thus Y equals 0 and the primary efficiency approaches 1 except for physical losses such as. those due to.evaporation-and wastewater contaminants. This procedure results in a high ancillary fuel requirement. It can be shown that V-32 the overall process efficiency will be the same as.that if Y were large and the ancillary demand low. All e ies are o w fficienc' n a Btu basis. It as further assumed that oil lost to wastewaterwould have the same heat content as crude.oil and that hydrocarbon losses to the atmosphere would have a heating.value of 200 Btu/lb. V@33 VI. FLUIDIZED BED BOILER COMBUSTION A., Introduction The environmental impacts, efficiencies and costs of Fluidized Bed Boiler Combdstion of coal in a power plant cycle are given in Table 4 of this, report. All line entries in the. table are '$pro- cesses" according to the,homenclature adopted and defined on page II-1.2he fluidized'bed process. using coal is intended to be inte- grated-with the-more complete set of coal data on extraction. con- version,. transportation, etc. already' published in Volume I of this'report. Fluidized bed combustion is.pa,rt of,th,e power' plant conversion activity. Entries in the'table are based on an energy input.of 1012 Ptu/ yr into each power@plant utilizing the"fluidized combustion''process. All of the cost data shown in Table 4 is based on.a 75 percent plant load factor, or 274-6pe-rating days/yr. The values presented in this table are based on data accumulated during the early months of 1974. Entries assume.controlled emissions in all.cases. Entries in.the table reflect the combustion of a .high sulfur central reg'ion,coal, a medium sulfur Northern Appalachian coal and a low sulfur Northwestern coal in each of two proposed fluidized bed boiler power plant systems. These systems are: The 635 Mw Westinghouse Pressurized Fluidized Bed- Boiler Power Plant, Westingl@ou'se Research Labora- tories, Pittsburgh, PA. (2) The 30 Mw Pope, Evans and Robbins Atmospheric Pressure.Fluidized Bed Boiler Power Plant, Pope, Evans and Robbins, Inc., Alexandria, VA. The concept of'fluidized bed combustion has.long been known and used in the petrol Ieum industry. Its advantages for coal com-., bustion have begun to be.explored for several reasons,.* .The basic justification for developing fluidized bed boilers is their ability. to burn high sulfur coal.with low S02 and NOx emissions. Further, the fluid bed's inherently high'heat release and heat transfer coefficients can drastically reduce the boiler's size, weight, and cost. Instead of burning coal in a large-furnace where only the furnace envelope absorbs-heat., crushed coal is burned in a fluidized bed composed of,1/16 in. - 1/8 in. particles of limestone or dolomite -which absorbs the sulfur in'the-coal.,to form,CaS04- The heat trans.- fer surfaces or boiler tubes can be embedded in the fluidized bed. directly because combustion takes place at temperatures-(@- 15000F) which will-not damage-the tubes. Heat release rates of 200,060 Btu/ft3-hr have been attained in fluidized bed boilers'as compared to 17,000 Btu/ft3-hr in.conventionial boi .lers. High heat release results in the fluidized bed boiler being more compact than,a V1_1 conventional boiler. Because of this., fluidized bed boilers can be built as factory-assembled, packaged units, shipped to site and arrayed as required. This reduces construction time for a new power plant considerably. The Westinghouse Pressurized Fluidized Bed Boiler,developed for EPA, consists of four modules (Figure 21). Each module in-. cludes four primary fluidized bed combustors stacked vertically. Each module also contains- a separate fluidized carbon burn-up cell to complete combustion ot carbon elutriAted from the primary beds. Almost all the boiler heat transfer surface is immersed in the beds. The beds are pressurized to 10 atmospheres and fluidization .is carried out with air at 8-15 fps. After particulate removal, the high pressure, high temperature gases leaving the combustor pass directly into a gas turbine which expands them to atmospheric pressure. Stack gas coolers recover sensible heat to' preheat feedwater. Coal combustion takes place in a dolomite bed to absorb sulfur. The spent dolomite is regenerated in a two.-step.reduc- t-ion/steam-C02 oxidation reaction, and recycled. The H2S released during this process is recovered as sulfur. Make-up dolomite is fed with the coakl. The feedwater is preheated in the water walls enclosing the beds and then saturated steam is generated in the boilertubes submersed in the fluidized bed.' Saturated steam then flows through superheater beds to the high@pressure steam turbine. The steam returns to the reheat bed between the hiah and low pre.ssure.steam turbines. The proposed Pope, Evans and Robbins Atmospheric Pressure Fluidized Bed Boiler Power Plant, developed for OCR, consists of a single-bed-level arrangement of four open-space modular cells augmented by an open ro%4 of "seibel" water-containing tubes ex- tending out from the integral wall dividers (Figure 22). Fluidi- zati6n of the bed is carried out at 12-14.fps. The integral 2000OF b,ed limestone regenerator and carbon burn-up cells (CBC) are water- cooled. Offgases from both boiler and auxiliary cells are cooled to 715OF by an integral economizer section. Boiler and regenerator cell flyash are fed to the CBC.' Sulfated limestone is pneumatically transported from the front of the boiler bed to the regeneration cell where, under high t@emperature reducing conditions, CaS04 is converted to CaO and.-S02 from which sulfur is recoveredi CaO is returned to the'main boiler bed. One percent sodium chloride is added to the boiler.along with the make-up limestone. This enhances sulfur ab7 sorption by the limestone and reduces carbon losses. vi-@ TAIL GAS 300OF STACK SULFUR PLANT S 2 COAL DOLOMITE ------- PARTICULATE REGENER REMOVAL IR ATOR p SOLID WASTE REGENERATED 2000OF DOLOMITE CARBON PRESSURIZED BURNUP SOLID, AIR FLUIDIZED BED WASTE AIR BOILER 1750OF L-SPENT 10 atm. STEAM STEAM TURBINE DOLOMITE ERATOR FLUE. GAS' TURBINE COAL a MAKEUP DOLOMITE PREHEATED R HEAT Figure 21. Pressurized Fluidized Bed Boiler Power Plant RECOVERY @ All TU UR B COOLING WATER IN DUST REMOVAL TURBINE GENERATOR FAN STEAM WIN STACK PLANT DUST L- ----- 6-1 LIMESTONE __SOLID 8 SALT WASTE TAIL GAS U1 E12 - BED BOILER 2OW OF! L 15009F REGENERATOR F"MMW CARSON BURN- CELL3 BOLEN UP CELLS FT"! I - - - - - - - - - - - - - - - - - - AIR Figure 22. Atmos"pheric Pressure Fluidized Bed Boiler Power Plant FAN @ID AYL T E@ B. IMPACT.DATA TABLE AND FOOT140TES VI-5 CONTROLLED CASE 1 2 3 4 5 6 7 9 10 It 12 13 14 15 Is 17 is 19 20 21 22 03 FUEL REGION 24 25 26 27 26 29 30 COAL AS INDICATED WATER POLLUTANTS (TONS/ 1012 STU, EX. COL,.12) AIR POLLUTANTS (TONS/ld' STU) OCOUPATIONAL HEALTH POTENTIAL COST(DOLLARS/I ROW MNE_ PROCESS DISSOLVED SOLIDS SUSPENDED TOTAL SOD coo THERMAL PARTIC NO, sox KYDRO- CO ALDEHYDES SOLIDS LAND DEATHS1 INJURIES MAN-DAYS LARGE PRIMARY ANCILLARY - ACIDS BASES No, OTHER SOLIDS COL'S 6,7,8 Il ULATES CAR13ONS ETC. TOTAL TONS/ (ACRE-YRN SCALE EFFICIENCY ENERGY FIXED OPERATING TOTAL w4k 170TAL(OS) ORGANICS (9TU/IO STIA 1012STU Vi-- - - - c P04 OUI STU) 07 _I toil STU L-/d'B- DISASTER mIdlemo COST CENTRAL REGION 2 PRF PRESS. FLUlDIZED BED COMBUSTION 0-00 3 9200 @.-0 1 0990 0999 1.82+01 4 9200 1.82+01 4 0.00+00 3 9200 3. 02- 03 3 9200 1.82+01 4 09.9 0099 0.00-00 1 9201 9-00 1 9202 6.73-01 1 97D2 4.41,02 1 12.2 -- 1 1103 '0.0-0 1 9103 0.0-0 1 92.3 @.14- 1 6.7-3 2 no 4.19+002 9205 0999 om 0"9 3.55-011 9206 C -. 7 007 3* 66+05 3 9207 1.28+05 3 U07 4.92+05 3 3 POWER PLANT CYCLE 3 4 ATFBB ATMOSPHERIC FLUIDIZED BED ...-0 3 9209 0. -00 3 92091 0999 0999 1.82+01 4 9209 .1. 82.01 4 0,00+00 3 I20q,3A2-G3 L82101 4 B999 0999 0-00 1 9201 1!73+01 1 9211.7AMI 1 9211 3.71+02 1 9211.2.-02 2 9211 2. 5-0 2 9211 D. D&O0 1 0997, 7.04+02 2 6.@03 2 921214.28@f)D @ 12113 0- 3.68-01 1 9214 0-0 2 OL972.35+05 2 921 1.34+05 3 9215 3,69+05@ 3 5 -STION POWER PLANT CYCLE 5 6 -ERN @UGHIA REGION PRFB8 PRESSURIZED FLUIDIZED BED 0.0-0 2 9200 0-00 3 9200 0- 0999 1.32+01 4 9200 1.82+01 4 0-00 3 9200 3.0-1 -2.01 4 .991` 0999 0-00 1 9201 1.23+01 2 9221 C73-01 1 9221 2-2 1 -1 0.0-0 1 9203 0. -00 1 2203 0-00 1 92 3 249-2 1 5.79-03 2 9222 3.78+00 2 NL3 D9i 0919 0- 3-55-01 1 920 0.0000 2 -7 3- 60-05 3 1207 1. 19+05 3 9224 4. a5+05 3 7 COMBUSTION POWER PUNT CYCLE ATFBB ATMOSPRERIC FLUIDIZED BED I IN, 0.- 1 12.1 0999 0999 1.82,01 4 9201 1.8-1 4 QmO@00 3 9209 1--03 91.9 '._-01 4 0999 0999 0.0@0 I VOI fl@IS2... 1 -1 7.0.. 1 -6 1.57+02 1 9726 -2-.42+02 2 -9226 2. 5-0 Z 1221 0-0 1 U97 4-02 2 5.88@03 2 9227 3.82,001-922A 01 11 0- ... 3.68-01 1 . 4 0-0 2 0997 2.35+05, - 1.23+053 1--- 3.5 8+05 9 10 COMBUSTION POWER PUNT Cycm- to if NORTHWEST REGION 12 PRFB8 PRESSURIZED FLUIDIZED RED 0- @ 1- .-0 1 1 0999 0999 1.82.01 4 9200 1' "' a' 4 0-0 3 glog 3.02-03 3 9200 1482+01 4 0999 0999 1.110@ 1 11.1 1.1.... 2 12111 1 9216 7.78+01 1 9216 0.0(1+00 1 9203 0m(I(I+()d 1 $203 0A.00 1 9203 !A@Q 1 3.95+03 2 9217 3-0@002 .1. 011. 11. 3.56- 1 11 O.WOO 2 0997 2.56+05 3 9 1- 15+05 3 -9 4.81+05 1 56+05 COMBUSTION POWER PU, CYCLE 14 ATFBB ATMOSPKERIC FLUIDIZED BED 0-00 3 9209 0-00 3 9209 0999 0299 1. 02+01 4 9209 1.82+01 4 0. 00+00 3 9209 3.02-03 A 9209 L62+01 4 @9% 0999 0.00-00 1 9201 5,31+00 2 9230 7.0- 1 9230 5,68+01 1 9230 2.42-02 2 9230 2aSWO 2 92300w()@OO 1 0997 3.76.02 2 3. 9- 2 9231 3. 1@00 Z .... 0999 .11, .1. 09" 3.68-01 1 2 0997 2.35+05Z 121 1 3.51+05 3 15 COMBUSTION POWER PUNT CYCLE to to _.ML REGION 17 PFURIB PRESSURUED FLUIDIZED BED 0-0 3 9234 0-0 3 9234 0999 0999 1. 82+01 4 9234 11. 8-1 4 _L0- 3 9- 3.0-3 3 9234 1. 82+01 4 0999 0- %00 1 -4 1.04+01 2 9234 6.7-1- 1 1- 2.41+02 1 9234 A(I+00 I 92M 0-00 1 92L4 L.0- 1 9234 3.1- 1 53- Z I- @. 69.00 Z 1- 0999 02" 0"9 em 9234 0.6- 2 0997 3.66 4*86+05 3 I-,,_ 18 COMBUSTION POWER PUNT CYCLE to 19 ATFBBI ATMOS-RIC FLUIDIZED BED 0-0 3 9234 0-00 3 9234 .999 0999 1. 82.01 4 9214 1. 82+01 4 0-0. 3 923413.02-03 3 9234 1. 924 01 4 .9S, 0999 1 -4 ..3.+0. 2 923@1 1.00+ 1 1 9234 2.0-2 1 9234 2+42+02 2 9734 2-00 2 9234 Ow00- 2 9234 S.- 2 5.5-3 2 9234 3.73+002 9234 OJI .11, .19, 0"9 3-58-01 1 923 OvO()+00 2 0997 34 3.59+05 3 - 2. 35+05 2 1234 1.24+05 1 22 20 COMBUSTION POWER PUNT CYCILE 2;) 21 2 2 2 1 23 23 2 4 24 25 2 5 26 26 27 9 28 2 29 30 30 3 1 37 32 3 2 33 3 3 34 3 4 3i 3 5 36 38] 37 37 38 3 39 3 9 40 49, 41 41 42 2 43 431 44 4 4 45 45 46 46 47 49 48 4 9 50 51 Sol 5 1 5 2 32 5 3 53' 54 55 _L4 TABLE 4. ENVIRONMENTAL IMPACTS, EFFICIE14CY AND COST FOR ENVIRONMENTALLY CONTROLLED NATIONAL AND REGIONAL FLUIDIZED BED BOILER COMBUSTION POWER PLANTS V I - 7 FTN. 9200-9202 Footnotes for Table 4 920.0 Entries in the table .are based on an energy inp!@t to each process of 1.OOE12 Btu/yr. Water pollutants are assumed to be the same as those,from a controlled conventional coal-fired boiler since many of.the unit process opera- tions are the"game. Thus from footnote 1908.organic emissions are 3.02-03 ton/1012 Btu and.dissolved solids amount to 18.2, ton/1012 Btu'.while'incre ,ase in-suspended solids is negligible. Capital cost for,control is esti- mated at $ 1/Kw and operating cost is taken at .05 mills/ Kw-hr, (9221, 233,1 234). 9201 Thermal-pollution is controlled by use of a mechanical draft wet.cooling tower system at a cost of $10/Kw (9221). Cooling tower-operating cost is estimated.at 0.05 mills/ Kw-hr (9209,111-3). First generation fluidized bed boiler plants will produce 10 percent.less waste heat than conventional plants , and second generation plants will produce 25 percent less waste heat (9200,274).. 9202 Air emissions for the 635 Mw pressurized fluidized bed boiler plant which are given in (9200,272) are based on a plant with a heat rate of 8892-Btu/Kw-hr and a full load plant efficiency of 38.4 percent,(9200,272). However, by this report's definition oflefficiency (see explanatory section prefacing report), the additional' coal used in the dolomite regeneration s,ystem.must also be included as part of the primary energy input. From (9200,274*) fuel for regeneration amounts to 0.31'mills/ Kw-hr. Dividing.by total fuel costs of 4.35 mills/Kw-hr, 7.12 percent is the fraction of total coal used for the regeneration system. On this premise, the'heat rate of the plant then. becomes 8892+(0.0712x8892) Btu/Kw-hr or 9.525 Btu/Kw-hr, and plant efficiency is thus reduced to 35.8 percent., From (9221,234,446) electrical-energy re- 5"022 Mwe or 1% quirements for a, 500 Mwe plant amount to for thermal and chemical water pollution'control. Hence the overall plant efficiency is reduced.to 35.5 percent.. The plant operates at 10 atmospheres pressure with bed temperatures of 1300 to 1750 degrees F. Air emissions are based onthe fluidization of a 4.3 percent sulf ur Central region. coal with dolomite absorbent added to-that portion of it in the boilerl:.(93.percent) to a net give a calcium/sulfur ratio'of 6/1. The coal has ,heating value of 12500 Btu/lb and an ash content of 8.5percent. Air emissions given in the table are based on those given in (9200,272), but adjusted as stated above to reflect the additional coal considered as primary- energy input'.. Thus for a l.0El'XBtu ihpxit, 7.12 percent or 7.12E10,Btugoes to th.e.regener ,ator and.92.88 perc ent. or 0.93E12 Btu is combusted in the boiler.Particulate emissions are derived,from the boiler plant (includes - boiler and coal drying.but not fugitive-dust)-0.0186 to 0.149 lb/l.OE06 Btu. The upper limit of this range is VI-9 FTN. M3-9204 for the case where no particulate control on the stack is used in addition to the'four 90 percent efficient cyclone collectors and two 97 percent efficient Tornado collectors presently planned for each boiler,module (9200,271). (Each module includes 4 primary fluidized bed combustors-one bed for the pre-evaporator, 2 beds for the superheater and one bed-for the reheater). The lower end of the particulate rangewhich is used in the table,assumes one additional 90 percent efficient secondary cyclone. NOX emissions derive from the boiler plant and range from 0.065-0.204 lb/l.OE06 Btu. Under combustion conditions of 1500 degrees F, a-sulfated bed (which promotes-reduction,of NOX (9206,18)),.limitation of excess air to the bed and maintenance of high pressurer NOx emissions can be controlled within this range. This is well belbw the EPA emission standard of 0.7 lb N02/ 1.OE06 Btu (9207,19). SOX emissions derive from the boiler plant (0.65 lb/l.OE06 Btu), dolomite regeneration (0.093 lb/l.OE06 Btu),and sulfur recovery (0.093-0.186 lb/l.OE06 Btu). Total SOX emissions are 0.836-0.929-lb/ 1.OE06 Btu, well below the.,EPA emission standard of 1 '.2 lb/-l.OEO.6 Btu. Emissions shown in the table are, except for particulates, calculated*from the'average between the high and low values for each pollutant as given above. ..Air emissions summary for a 635 Mw@pressurized.fluidized bed boiler in tons/l.OE12 Btu Particulates 9.3 Sulfur Oxides (as S02) 441.2 Nitrogen Oxides 67.3 Total 517.8 9203 Under the design conditions of operation given in (9200,. 269),i.e'. 10 Atm Pressure, 10 percent excess air in the primary beds and@30 percent excess air in the carbon burn-up cell, it is assumed that there are no gaseous carbon c ompounds produced which are-not fully oxidized to C02(9205). 9204 Footnote 9202 states that the coal contains 8.5-percent ash which amounts to 3400 tons/l.OE12 Btu. Ref. (9204, 147) states that 10 percent of the sorbent is rejected during'regeneration and 3 percent is elutriated from the bed. From the material balance diagram shown in Ref. (9204,H-1.00) it can be seen that the dolomite make-up.rate is- 10.6 percent of the dolomite in the boiler. Thus, this is the amount discarded to solid VI-10 FTN. 9206-9207 waste and amounts to 3354.82 tons dolomite/l.OE12 Btu. Therefore total solid waste (subtracting particulates) is 6755.3 tons/l.OE12 Btu.' Sulfur recovered not included. 9205@. From the site plan of the 635 Mw-plant'shown in Ref. (9207,105) the fixed land impact for the plant, including coal storage and.ash and dolomite storage, is 59.8 acres. Using the plant heat rate calculated in footnote 9202 of 9621 Btu/Kw-hr, and a 75 percent load factor, Btu's/ yr going into the plant were calculated as 40.1E12 Btu. Scaling down linearly to 1.OE12 Btu/yr input, fixed land impact was determined as 1.49 acres.. From (.9222, 45) cooling towers ate estimated to occupy 10 acres.for a 1000 Mwe plant oi:'..130 .ac-yr/1012 Btu. Hence the total. fixed land use is 1.62.ac-yr/1012 Btu. Based on 6755.3 tons solid waste with an average density of 60.45 lb/CF (see footnote 9213), and waste banks'36-ft high, the annual incremental land use due to solid waste is 0.171 acres. Time averaged over.a. 30 yr plant lifetime and added to fixed land gives a total land impact of 4.19 acre-yr/l.OE12 Btu. 9@06. The' literature value of efficiency, 38.4 percent (see footnote 5202 for efficiency value adjusted for coal input into regenerator)@assumes a back pressure of 1-1/2 inches mercury, a boiler efficiency of 88.6 percent and pressure losses in the gas turbine combustor loop of 7.5 percent. 9207 Fixed costs were.determined from (9200,273) for a, regenerative pressurized fluidized bed boiler power cycle of 635 MWe producing 4.17EO9 Kw-hr/yr at a load factor of 75 percent and a heat rate of 9621 Btu/ Kw-hr (see footnote 9202)..No adjustment has been made in the dollars/Kw value to reflect the use of-a 75 L:)errent load-factor instead of the 7Q percent used in (9200,273). Construction costs escalated to $220.36/Kw from (9208,162). Total fixed cost does not include the cost of coal (49 cents/million Btu (9200,273)), but does include water pollution control costs (see footnote 9200 & 9201). Total fixed cost is thus 3.49E+06-dollars + 1.74E+05 dollars..per 1.OE12 Btu. At a fixed charge rate of 10 percent, annual fixed cost is 3.66E,05 dollars/l. OE12 Btu.. Operating costs of 0.98 mills/Kw-hr are from (9200, 274) updated to-1972 prices (9208,162). Operating costs *also include cost of water:pollution1control at 0.1 mills/ Kw-hr (see footnote.,9200 and 9201) and the cost of dolomite- limestone absorbent at 4.38 dollars/ton (9200.,,274) to give a total operating cost of 1.26EO5 doll,ars/l.OE12 Btu. No credit has been taken-for. 'sulfur recovery. FTN. 9209-9211 9209 Entries in the table are based on energy input to each process of l.'OOE12 Btu/yr. Entries for water pollutants are assumed to be the same as those from a controlled conventional coal-fired boiler since many of the unit process operations are the 'same. Thus from footnote 12 1908 organic emissions are 3.02-03'ton/10 Btu. Dissolved solids amount to 18.2 iton/1012 Btu while increase in suspended solids is nlegligible. Capital cost for control is estimated at $ 1/Kw and operating cost is taken at 0.05 mills/Kw-hr (9221,233,234).- The efficiency of the Pope, Evans and Robbins plant has been stated to be 37.2.percent with a plant he 'at rate of 9187 Btu/Kw-hr (9218). By taking the data from (9210,48) for a plant with an annual coal input of 106,000 tons and annual out- put of 271,000 Mw-hr, and using a heating value for the .coal of 11,640 Btu/lb .(9211,7), these values.can be cal- culated approximately. 9211 Emission-factors in the table were calculated assuming a Central region coal with a net caloric heating value of 12,500 Btu/lb, a sulfur.content of 4.3 percent and an ash content of 8.5 percent. They apply to a 30 Mw single-lev'el atmospheric pressure fluidized bed boiler power plant with a , heat rate of 9187 Btu/Kw-hr and an-overall plant efficiency of 36.8 percent (see footnote 9214). The plant operates at a temperature of 1500-1600 degrees F in the boiler and 12-14 FPS flue gas velocity-with the integral carbon burn-up cell and regenerator bed sections operating at 1900-2050 degreesF (9212-130). One-e-ighth inch particle size 1*estone is added to the coal to give.a calcium/sulfur ratio of 2/1-with limestone makeup added to account for a bed blowdown of about 10 percent. One percent sodium chloride is added with the limestone to enhance sulfur absorption '(9212, 31 and 9211,5)..Particulate emissions derive from the primary, carbon burn-up, and regenerator cells of the system. Each stream is cleaned with a high efficiency cyclone (eff.=85 percent), and the first two streams are further cleaned with an electrostatic precipitator (eff."99+ percent). The tail gas of the regenerator effluent is recycled to the boiler (9212,5-6). From (9211,14), 12.1 percent of the ash in the coal appears .in the flue gasbefore the electrostatic precipitator .or,411.4 ton coal ash/1.00E12 Btu for an 8.5 percent ash coal. Also, from (9211,14) and (9213,8).which states that 10 percent of the flyash is,,calcium sulfate and 40 percent calciumoxide, one percent of the calcium in the boiler appears-as calcium sulfate in the flyash and 9.6.percent of the calcium in the boiler appears as calcium oxide,in the flyash. Accordingly, for the 4.3 percent sulfur coal.requiring 22.165 lb limestone/1-0E 6 Btu for a 2/1 Ca/S ratio, 0.686 lb of calcium-appears in the flyash as 0.28 lb Ca'S04/1-OE6 Btu, and 0.826 lb VI-12 FTN. 9212 Ca appear in the flyash as 1.156 lb CaqO/l.qOE6 Btu. These amounts together with the ash amount to 1129.4 tons/l.qOE 12 Btu before the electrostatic precipitator which reduces 6qp articulates to 11.3,ton/l2pp12 Btu. Sulfur emissions derive from the boiler where about 80 percent of the qs ulfur in the coal is absorbed by the limestone. Ten Percent of the sulfur in.the coal appears in the solid waste,and 10 percent is e'mittedt0q6 the atmosphere (9213, 7). No sulfur emissions ate expected from.sulfur recovery from regenerator effluent since the stripped tail gas is recycled to the-0qIncoming boiler air..Fo8qrqa 4.3 percent sulfur coal, 12,500 Btu/lb*heat content, the sulfur emitted.to the.atmosphere would be -189.2 to0qn2q/l.qOqOE12. Btu.or 378.4 ton S02/1-qOE12 Btu.O0qX emissions derive from the boiler plant and-amount to an average of 0.14 lb N4qOx/ l.qOqOE6 Btu or 70 ton/6qI.qOqOE12 Btu (9211,0q10q). Hydrocarbons and ACO are present in the flue gas in.amounts on the order of 1000 PPM .q(vol0qume-basis) and 0.2-q0. volume percent respectively, with 3 percent excess oxygen the boiler outlet (9214q) The coal producing these emissions on @combqustion in the Pope, Evans and Robbins fluidized bed boiler is a 4.6 percent sulfur,12,34qd Btu/lb, 15.8 percent ash coal. It is assumed that its combustion characteristics are similar to the 1250.0 Btu/lb, 4.3 percent sulfur coal used to compute other emissions. Therefore,'CO and hydrocarbons were calculated using data given in (9211,14), Moles of-flue gas/l.qOE6 Btu were calculated as 13763.8 moles or 5.2.87 liters/mole. Hydro- carbons were calculated'as methane to be .484@l6qb2q/l.qOEq6 Btu, 242-ton/l.qOqOE12 Btu. Using a density of .0738 lb/CF (9215,1936) for C4qOat 0 degrees C and 760 mm,pressure, CO was.found to-be 0,005 lb/l.qOE6 Btu or 2.5 t2q6n/l.qOqOE12 Btu. Air emissions summary for a 3qQ MW atmospheric pressure,, qsin6q4le-level fluidized bed boiler plant in.tons/l.qOqOE12' B4qtu Particulates 11.3 Sulfur Oxides (as S02) 378.0 Nitrogen'Oxides 32q70.0 242. Hydrocarbons 6q@qLs CH04q@ Carbon Monoxide 2.5 703.q,8 Total 9212 The amountq.q-of ash issuing from the combus48qtionof 1.2qOE12 Btuq,8.5 percent coal would be 3400ton. Makeup limestone is added at the rate of 3 times the weight of sulfur in the coal (9213,4). For a4.3 percent coal, this would VIq-13 FTN. 9213-9215 amount to $160 ton limestone or 2002 ton Ca/l..OE12 Btu discarded from the system (limestone assumed to contain 97 percent calcium carbonate by weight). From (9213,8) four-fifths of the calcium in the waste is present as calcium oxide and one-fifth as calcium sulfate. This amounts to 1361.36 tons calcium sulfate and 2242.24 tons calcium oxide. Thus,' subtracting particulate emissions of 11.3 ton/l.OE12 Btu, solid waste amounts to 6992.3 ton/l.OE12 Btu. Sulfur recovered not included. 9213 Fixed land impact for the atmospheric,pressure fluidized bed boiler was taken as that given in footnote 9205 for the pressurized plant--l.62 acre-yr/1-OOE12 Btu. From footnote 9212, solid waste is 6992.3 ton/lAOE12 Btu, with a flyash,component of 3393.9 tons and.a CaS04-CaO component of 3598.4tons (appropriate proportions of the particulate emissions subtracted). From (.9216.,4), the average bulk density of coal flyash is 1 gm/cc or 62.4 lb/CF.'From (,9213,13) the calcium in the solid waste is present mostly as calcium oxide which has a bulk density of 53-64 lb/CF (9217,6-8). Thus an average density for the,solid waste of 60.45 lb/CF was used. Assuming waste banks 30 ft high, the annual incremental land-use due to solid waste was determined to be 0.177.acre-yr/1.0t12 Btu. Time-averdged over a 30 yr plant lifetime,.total land impact is thus 4.'28 acre-yr/l.OE12 Btu. 9214 Primary efficiency is given as 37.2 percent. (See footnote 9219)0. From (9221,23.4,446) electrical energy requirements .for a 500 MWe plant amount to.5.022 MWe or one percent for thermal an.d chemical water pollution control. Hence the overall plant efficiency is reduced to 36.8 percent. 9215 (9212,32) states that.a plant 'cost of 37 million dollars or 125 dollars/Kw is anticipated for a 300 MW atmospheric fluidized bed boiler plant (1972 figures). Referring to (9210,58) this estimate is seen to include land, structures, boiler plant'eq-dipment, turbine, electrical equipment and.miscellaneous. Adding a 6 percent contingency fund (7.44 dollars/Kw) and water pollution control.costs (See footnotes 9200,9201) the,cost becomes 143.44 dollars/Kw. For a,plant with a heat rate.of 9280 B.tu/Kw-hr, the fixed cost for an annual input of 1.OE12 Btu/yr, at a 10 PC fixed charge rate, is 2.35EO5,dollars/l.OE12 Btu input. Coal costs at 49 cents/l.OE6 Btu are not included in operating costs (9200,273)-. Limestone costs of 4.35 dollars/ton delivered (9200,274) are updated to 1972 costs from (9208,162) for an input of 5160. ton/l.OE12 Btu input. Water pol-lution control costs are.0.10 mills/Kw-hr .(see footnotes*9200,9201). VI-14 FTN 9216-9217 Operating and maintenance costs for an atmospheric plant-were taken,from (9207,132) on the,assumption that -these costs would be similar whether the plant has single-level beds or'stacked beds. Updated,-to 1972 costs from(92q68,6q162_q) this-amounts to 0.94' millqs/Kw-hr.' Tot6qal.operating cost',, not including credit for sulfur recovered fly0qash sold, is 1.34EqO5 dollars/qI.qO8qEq12 Btu. Plant load factor is75.percent. 9216 Emissionfactors in the table are based on anin6qp0qut of 2q16qAE12 Btu of -,Northwest region. coal with a q0.5 percent sulfur,.6 percent ash and heating value of 8800Btu/ lb. The cal8qcul0qations,are made on the sameq'ases as set out-in footnote 9202,'i.e,92.8q9 percent of 'the,input coal goes tohe boiler and 7.1 percent goes to the coal combustor of the regenerator system,. Thus, there are 113.6 lb coai/1'.qOE06 Btu producing 6.82 lb ash. The portion that is combustedn the boilercontains 0.53 lb sulfur requiring the addition of 10,46 lb-doomite fora 6/1 Ca/S ratio. The absorbent in this case is not actually necessary in order for sulfur-emissions tomeet EPA standards (1.2 lb S02/1.qOE06 Btu), but is assumed added in, the above@proportions-in order to have standardized data for a high, low, and medium -sulfur coal. Using the mass.balance diagram in (9204,100q),t'was determined that 0.306qpercen2qt of the-ash in the coal and 0.0050 percent of the dolomite added to the coal appeai -s particulate emissions. T 'hereis an additional 9u percent efficient cyclone for flue gas clean up (seefootnotiqj .9202q).-0qUsing these.rati8q6s, particulate emissions for this coalere determined as 0_0194 lb/1.q0E06 Btu or 97,ton/ 1.qOE12Btu. N8qOxemissions were assumed to be at the.same low levels st6qated.inf4qootnote 9202, 67.3 ton/l.qOE12 Btu, since they.are primarily dependent on boiler temperature and restriction of 'excess air to the bed. Sox was determined by calculating from (5200,2q12) that 86q6.4 percent'of the 'sulfur in the coal is removed. Thus, J for this coal,1.8 tons S8qOx are emitted/ qOE2 Btu. Summary of air emissions f4qor a, 'q635 Mw.pressuqr'ized fluidized 4qPed boiler power plant in tons/l.qOE12 Btu, q@Pa00qrticulates 9.2q1 Sulfur Oxidesq.6q(aq' S 71.8 s 02 Nitro en Oxides 6 32q7q. 3 32q9 Total 148.8 9217 Footnote 9216 state0qgq.that the coal contains 6 percent ash which amounts to 3409 t24qons/l.6qOE12 Btu. Using the same basisasq,in footnote 9204 and (9204,Hq-q.100), the dolomite VIq-15 FTN. 9218-9222 discarded:to solid waste is 554..38 ton/l.OE12 Btu. Therefore? totalsolid waste is 3953.68 tons/l.OE12 Btu (particulate emissions subtracted). From footnote 9205, fixed land impact for a 1.OE12 Btu/ yr plant is 1.62acres. Weighting the solid waste load from footnote 9217 according to the densities given in footnote 9213 gives an overall.densityof 61.85 lb/CF. Assuming waste banks 30 ft high, the annual incremental land use due to solid waste is 0. 0978 acres. Time-averaged over a 30-yr plant lifetime, total land impact is 1. 4 7 acres-yr/l. OE12 Btu. 9219 From footnote 9207., operating costs*include 0.98 mills/ Kw-hr, water pollution control costs at 0.10 mills/Kw-hr, and the cost of dolomite-limestone absorbent at 4.38 dollars/ ton or 2430.79 dollars/l.OE12 Btu. Total operating costs are thus 1.15EO5 dollars/l.OE12 Btu.. No credit taken,for sulfur recovery. 9221 Air emissions given in the table are for a Northern Appalachian coal containing 2 percent sulfur, 10 percent ash and having a heating value of.12000 Btu/Ib. Emissions are calculated on the same basis as those in footnote 9202, i4e.,92.88 percent of the input coal goes to the boiler and 7.12 percent goes to the coal combustor portion of the regenerator-system. Thus, there are 83.33 lb coal/l..OE06 Btu, producing 8.33 lb ash. The portion combusted in the boiler contains 1.55 lb sulfur requiring 30.67 lb dolomite for a calcium/sulfur ratio of 6/1. A lower Ca/S ratio may suffice for adequate sulfur removal from the emissions of this coal. Using the same bases as in footnote 9216, particulate emissions were determined as 1@.32 tons/l.OE12 Btu * Nox emissions were assumed at 67.3 tons/l.OE12-Btu (see footnote 9.216). Sox was determined as 210.8 tons/l.OE12 Btu.. Summary of air emissions for a 635 Mw pressurized fluidized bed power plant in tons/l.OE12 Btu Particulates 12.3 Nitrogen Oxides Sulfur. 'Oxides Jas, S02)@ 210.8 Total 290.4 From footnote 9221, 1.0E12 Btu of coal produce 4165 ton ash. From footnotes 9204 and 92@1,-dolomite discarded-from the system amounts t6 1625.5-tdns/l.DE12 Btu. Thus, totalsolid. VI-16 FTN9223-9226 waste is 778.2 ton/l.qOE12 Btu -(particulates subtracted). 9223 From footnote 9205, fixed land impact for a.l.qOE12 Btu/ y0qr plant isl. q68q2, acres. Weighting t6qhe solid waste loading from footnote 922q2 according to densities given i2qn footnote 9213 gives a4qn.average density for the solid waste of 61.3 lb/CF. Assuming waste banks 30 ft high, the.annual incremental land useu*4qe to solid waste is- 0 - 144 acres. Time-averaged over a 3 0 yr plant lif etime, total land impact is 3.78 acreq"yr/1'.qOE12 Btu. 9224 From footnote 9206q7, operating costs include 0.98 mills/ Kw-hr, water pollution control costs at0.10 mills/ Kw-hr, and the cost of dolomite-limestone 0qaqlo@sorbent at 4.38 dollars/ton or 7119.4 dolqlars/l.qOE12 Btu. Total operating.cost.are.thus 1.19EqO5 dollars/l.qOE12 Btu. No credit taken for'sulfur recovery. 9226 The emissions a 're calculated assuming'a Northern Appalachqinoalontai4qniqn'g 2 percent sulfur, 10 percent Ash a0qnd having aheating 'Value of 12000 Btu/.lb. Emission factors in the, 'table a0qre based on the operation of a 30 2qMW singql0qe-level atmospheric pressure fluidized bed power plant with a.heat rate 6qof 9187 Btu/0qKw-hr and an over-all plan4qt'efficiency 36.'8 per' cent. (See footnote .9209). Plant operation'and methods of calculation are as.given in footnote 9211. This coal produces 8.33 lb ash/l.qOE6 6qBtu. There are 1.67 lb sulfu0qr/l.qOE6 Btu coal requiring 10.74 lb limestone qJ97 percent calcium carbonate) for a 2/1 calcium/sulfur ratio in the boiler. Thus, from footnote 9211,@.135 lb calcium.sulfate and 0.56 lb calcium'oxide/l.qOE6 2qB4qt0qu appear in the flyash to the electrostatic precipitator.. In addition 12.1 percent of the ash in'the"coal 'also -appears inhe flyash, or 1.01 qlb/l.qO4qE6tu.*0qApplying Ithe final particulate control gives particulate emissions of 8.515 tons/l.qOE12 Btu. From*q(.9213o7) 10-.perqc'ent of the sulfur in the coal is. emitted to the atmosphere, Thus? for this coal, this amounts to 0.334-lb S4qOx/l.qO8qE6 Btu, calculated as S02, emitted,.-This is4qwell below the EPA standard of 1.2 lb S02/q1-qOEq6 Btu. NOqX@emisqsions are Ia function of excess air in the boiler and bed temperature. So long as these are q@kep2qtt within the limits described in footnote 9211,.NO 6qx was assumed constant forall the coals 60 escribed.,Thus, N28qo6qx emissions amount to 70 ton/l.8qO52qE12 Btu. Hydrocarbon q'd and carbon m04qonoxi e emissions are also,qc2qiqsq's40qu6qmed to remain' constant from coal to coal as long as combustion conditions remain the same. This,,q-hydrocarbon emissions are 242 ton/ VIq-17 FTN. 9227-9230 I.OE12 Btu and Co is 2.5 ton/l.OE12 Btu. (See footnote 9211). Summary of air emissons for a 30 Mw atmospheric pressur e single-level fluidized bed boiler power plant in tons/ 1.OE12 Btu Particulates 8.6 Sulfur Oxides (as S02) 167.0 Nitrogen Oxides 70.0 Hydrocarbons (as CH 4) 242.0 Carbon Monoxide 2.5' Total 490.1 9227 The amount of ash produced by the.combustion..of 1.OE12 Btu, 10 percent ash coal with a heating value of 12000 Btu/lb is 4166 tons. Makeup limestone is added at the -rate of 3,times the weight of sulfur in the coal (9213, 4). Thus,'2505 tons limestone containing 971.94 tons calcium are discarded from the system. From (9213,8), 80 percent of the calcium.in the waste is present as. calcium oxide or 1088.6 tons. 20 percent of the calcium in the waste is,present as callcium'sulfate or 631.8 ton/ 1."OE12 Btu. Thus, subtracting particulate emissions, total solid waste is 5877.8 ton solid waste/l.OE12 Btu. 9228 From footnote 9213, fixed land impact for a 1.OE12 Btu/ yr plant is 1.62 acre.-The ash component of*the solid waste is 4161.7 tons and the CaO-CaSO4 component is 1716.1 tons (appropriate proportions of particulate emissions subtracted). From footnote 9213, the bulk density of the fly ash is 62.4 lb/CF and the average density of the@qalcjum fraction is 58.5 lb/CF. Assuming waste banks 30 ft high, the annual incremental land use due to solid waste is 0.147 acres. Time-averaged over a 30 yr plant lifetime, the totAl land impact is 3.82 acre@-yr/l.OE12 Btu.. 9229 Included in operating costs are'limestone costs at 4.35 dollars/ton or 10896.75 dollars/1012 Btu (9200, 274 and 5208 '162)-,, water pollution control costs at. 0.16 Millis/Kiw-hr,(see footnotes 9200,'9201) and operating .and maintenance costs of 0.94 mills/Kw-hr (footnote 9215). Thus, total operating cost is,1.23EO5 dollars/ 1.OE12 Btu. Emission factors in the table are for a Northwest region coal containing 0.5-percent sulfur, 6 percent ash and having a heating value of 8800 Btu/lb. They are derived - on the same bases as are stated in footnotes 9209 and 9211. VI-18 FTN 9231-9232 Thus, for this coal there are 0.568 lb sulfur/l.OE6 Btu. the sulfur content of this'coal is low,enough to meqet.4qEPA emission standards-of,1.2,l6qb S02/1-qOE6 Btu without the use of any-,absorbent.over, it will, be assumed th8qAtlime- stonein a 2/1 calciu0qm/s8qulfur ratio is added to standardize the results on all coa8qls,used. Thus, this Amount of, sulfur would require 3.66 lb limestone'as absorbent containing 1.42 l0qb calcium. 6.82 lb ash/l.qOE6 Btu are also produced4 From-footnote 9211,-0.825 lb ash, 0.046 l. calciumsulfate.and 0.191b calcium oxide appear in the flue gas/l.qOE6 Btu before the 99 percent efficien2qt@' electrostatic precipitator. Applying final particulate control, particulate emissions are found to be 5.31 tons/ 1.qOE12 Btu. Sulfur oxides (calculated as So ) are 56.8 tons/l.qOE12 Btu. Nitrogen oxides are 70 ton2q@l.,qOE12 Btu: Hydrocarbons (as CH4),are 242.0 ton/l.qOE12 Btu and CO is 2.5 ton/l.qOE12 Btu. See footnote 9211. Summary oqf air emissions for a 30 Mw atmospheric pressure single-level fluidize0qd'bedpower plant in tons/l.qOE12 Btu Particulates 5.3 Nitrogen Oxides 70.0 Sulfur Oxides (as S02) 56.8. Hydrocarbons*q(as CH4) 242.0 Carbon Monoxide 2.5 Total 376. 9231 The amount of ash produced by 1.qOE12 Btu of a 6 4qper cent ash coal with 'A heating value of q8q800 Btu/lb is q34,09 tons. Makeup,lim0qestone is added at a rate ofhree@times the weight of sulfur i6qn the coal. Thus 852 tons limestone containing 330.576 tons calcium is discarded from the system. From q@92q13,8),80 percent of the calcium is presen t in the waste as Ca8qO or 370.25 tons Cao. Twenty percent of the calcium is present as CaqS8q04 or 214.87 tons CaS8qO 4- Thus, subtracting particulate emissions, total solid wast4qd'load is 3988.8 tons/q!.qOE12 Btu. 9232 From footnote 9213, fixed land impact fora1.'qOE12Btu/yr atmospheric plant is 1,62acres. From footnote 9231, the ash component of the solid waste is 3406.35 tons' and the 4.1 20qC2qa.24qOq-24qC6qa0qS20qO4 component is 582.47 tons (appropriate proportions of particulates subtracted). From footnote 9213, the bulk density of the flyash is 62.4 lb/CF and that of calcium oxide-calcium sulfate is an 44qAverag04qe-of 58.5 lb/CF. Assuming waste banks 30 ft hi08qqh, the annual incremental land use due to solid waste is 0 q- 0988 acres- q* Ti6qmq'e-averaged over a 3 0 yr plant lif eti6qmq@ e, the total land impact is 3. 10 acre-yr/l.6qOE12 Btu. vi-19. FTN. 9233-9234 9233, Included in operating costs are the cost of limestone to the boiler at 4.35 dollars/ton (9200,274), or 3706.210 dollars/l.OE12 Btu, water pollution control costs at. 0.10 mills/Kw-hr(footnotes 9200,9201), and operating and maintenance costs of 0.94 mills/Kw-hr (footnote 9213). Thus,, tot.al operating costs are 1.16EOS dollars/l.OE12 Btu. 9234 All the national average impacts-are arithmetic averages of the data given for the Central, NorthernAppalachia, and Northwest :pegions. VI-20 VII SOLVENT REFINED COAL A. Introduction The environmental..impacts, cost,-and,efficiency for the activities and processes associated with solvent refined coal are shown in Table.5 of this report. Data have been developed for two regional coals: high sulfur Central and medium sulfur Northern Appalachia. The characteristics of the regional coal ,utilized are contained in the-footnotes. Data are @or an environ-' mentally "controlled" condition.. All of the cost data shown in Table 5 is based on a 90 percent plant load factor, or 328 operating days/yr. 'Thevalues presented in this table are based on data accumulated,during the Spring of 1974. Each data entry is based upon an energy input of coal equivalent to 1012 Btu/yr., The Solvent Refined Coal process should be considered an integral part of the fossil fuel supply-, trajectory. Compared to the coal processing entries.in.the Phase -1 report, (HIT-593, Volume I), the environmental impacts have changed considerably in the distribution and power g6neration activi- ties since the heating values, sulfur, and ash content of the SRC productare different. On the other hand, 'the coal extraction activities in the Phase I report may be usedto complemept or c(Mplete the total fossil fuel supply chain. The Solvent Refined Coal process developed by the Pit@,tsburgh ArA Midway Coal,Mining Company is the basis for,the energy environmental data developed in this report. Although generally, referred to as the coal-de-ashing process, both ash and sulfur are removed., Figure 23 illustrates the process. The process itself consists of six distinct operations des- cribed below: 1. Coal Preparation and SlurEy. In this area the run-of-mine coal is crushed to less than 1/8- inch by 0 and then dried with thermal.flash dryers to approximately 3% moisture. The coal particles are then mixed with a hot aromatic slurry azid directed to-.the dissolvers. 2. Dissolving. The coal-slurry mixture is next hyar9genated under elevated temperature and pressure. The coal-slurry mixture has a con- tact time of approximately 15 minutes., although during actualloperation this may va3@y somewhat. 3. Filtration. The dissolved cdal-sblvent solution is next passed through a rotary pr6coat type filter where undissolved coal and ash are sep- arated from the solution. This material is then sent to the Mineral Residue processing area in the form of a "filter cake" whereas the coal solution is further processed. VII-1 M ACID TREATMENT COAL VENT GAS 8 SULFUR PLAPFr COAL FUJRA7E PREPARATION DISSOLVER 'FILTRATION SOLVENT ak . SOLUTION SOLUTION RECOIVERY SLURRY RE-CYCLE RASH LIQUID SOINENT -CONDENSM RECYCLE SMVeff L SOUAEN'r STACK GAS FIEFINED TO SULFUR PLANT COAL MINERAL, BOTTOMS CRE CS RESIDUE SOLIDIFICA- FROM DISTILLATION PROCESSING TION SOLVENT LIGHT OILS ASH RECOVERY do JRMYCLE SOLVENT SOLVENT COAL .41 SOLVENT SOLVENT SOUR MIXING EXTRACT SOtJR - WATER CLAR I F1 ERS STRIPPER WATER SOLVENT SLUOK Figure. 23. Sol At kofinet":0*1 Process PHENOLS1 SyiEcs:] *7LVENT@@ (11. 930) 4. Mineral Residue Processing. The filter cake contain- ing mosF of-the coal ash and minor portions of"undissolved ..carbon,is dried and burned. The filter cake has a heating value of approximately 4220 Btu/lb and provides a significant portion of the energy needed for opera- tion of the plant. .5. Solvent RecoveEZ. The coal-solvent solution is then flashed and further distilled to remove the solvent from the "liquid.coal." The solvent is recycled to theslukry step. 6. Solidification. The coal product is soli ified by use of flaking drums.and stored,as a solill-de-ashed coal ready for shipment. VII-3 B. Impact Data Table and Footnotes VII-4 @LVENT REFINED COAL 3 4 5 6 7 8 9 10 If it 13 14 15 16 17 Ii 19 20 21 22 23 24 25 26 27 20 29 FUEL REGION 30 COAL A5 INDICATED WATER POLLUTANTS (TONW 10'2 STU. EX. COL.12) AIR POLLUTANTS (TONS/1012 M) OCCUP@ fTIONAL HEALTH POTENTIAL COST (DOLLARS/1012m) NNE - I DISSOLVED SOLIDS SUSPENDED TOTAL THERMAL PARTIC- HYORO- ALDEHYDES S LIDS LAND -jA-N ARGE PRIMARY ANCILLARY ROM ACTIVITY PROCESS BOD COD : NOX so, CID TOTAL TONS/ ACRE-YR) DEATHS INJURIES DAYS L EFFICIENCY ENERGY FIXED OPERATING TOTAL MON. SOLIDS Cous 6,7,8 /totaTIA ULATES CARBONS ETC. 7 SCALE ROW ACIDS BASES P04 N03 OTHER TOTAL(DS) ORGANICS BTU 012 BTU 101, BTU LOSTAOP29Tt DISASTER (BTU/I&BTU COST COST COST 1. 2 TRN@ TRANSPORTATION T_ TRUCK .19. .1. .11. .1. .11. o", o". o9o o998 3.34-o 4 23oo 9.51-01 4 2300 6-02 4 91do 2.51-021 4 93QO S.7-1 4 13oo 7.71-0 4 93co I.-oo 4 7.4-1 3 11ol .11, o9" 0992 I-D 1 9302 1.1-19 3 9301 4.04,03 930J I. DI.04 3 2.3@@N 1 3 4CON- CONVERSION I 1 14 SAMC -C o", W. -t!LLI!@ 1 1- -.-02 o -4 -1- 1 1.0-02 1@o@ 1--@ 130. .117 --1 3 0.1 2m!1@01 3 230112.42101 3 9305 -4-00 3 9305 4.84-02 3 930S 3.62-01 3 93dS 6.W01 3 3-03 2 9106 ZmW00 3 93D7 0999 7.68-01 19366T 7.66,lo 2 93og 1. - 2.2-S 2 5 6 o". moil 0-5 2-9310 1 TA- 2 931G 7 --- - 2.,D.ox 3 0400+D0 2 9315 3.4341 4 9314 6.10-02 2 9316 51.6-1 1"1" 5.11.1 @ 316 "99 1. woo 2'312 6. 8i,04 3 @D317 7. 0404 3 8 _ffR UNIT TRAIN .1. .11. .19. .11. .1. .9. o9go - o". .99's o". o- .1. 1. 361@1 3 1311 3.20@0() 3 9311 2.111003 111, 2412*003 9311 2.97,00 3 2311 1. ?o_oj 3 9311_ 9RIIARG RIVER BARGE o998 o998 o'98 oloo 099. G. 0+00 3 0997 D.D0100 3 0997 0-00 0.0040 3 0997 D,W(10 30997 O.-H-3 ....... . .... 1.4-0 3 9319 1.52- 1 s- gw!@01 3 9319 1w27+00 3 9319 7.06-01 3 9319 2.4MI I o"8 .1. o999 o..' o"9 1.0.0. 11311 L'59-10 3 932o 3.91+01 3 9122 2.16-1 1 S322 3m25@ 3 9 10 PFC- EUCTRIC ER 10 I I - D.00+0 3 1908 13. 02-03 3 190o 1.82401 09. mo I.. o0N00 3 9325 2.53-01 3 9323 2.84+02 3 9323 5.71.02 3 9323 4.74+00 3 9323 I.S6 1-01 3 9323 7.86-o2. 132) 19.01+02 3 6.-oo 2 1326 6o27+00 3 9330 1 --(Il o9- - `-EN -R GENERATION 0-6 3 1908111-0 3 1908 og.2 1.82.01 -jI.8201 -11-033 9327 11@-Ql 1 9327 4,41+00-1 -9127 3 0997 1-- 1 -9 JWA@s 3 9,29 6.7245 3 12 13 CENTRAL IS 14 TRNSP TRANS@RTATION @K TRUNK TRUCK o". o9" -1 .90 o998 0998 1.75-02 3 0331 4.98-01 3 9331 3.63-02 3 §331 4.15-07 3 933T 3+03-01 3 933L 4.o4-o3 3 9331 1.09-01 A 0"t 4*01@01 o 933Z ......... III" .19s 1.00,00 2 9U3 3.7"1 3 9332 3.79-633 9334 1.16-3 9334 1.534043 Co- CO-N-N - 17 CCSRC _c o"o . 0999 3.21-01 4 9335 0919 5.221. 9335 S.22-02 4 1.40+00 5 9335 2.7-1 o 1- 1 6.7-3 5 9335 8.62 03 5 933S 0.0-0 2 D997 1+72+01 3 9336 1.9-1 3 oggs al., .-01 1 9339 6.81+16 2 934C 1.22+01 @ 9341 19.M- 2 - 2,oo.1 2 17 Is 20 WITR UNIT TRAIN o9gs o995 o". o998 o9's o19. 0- .2L. oos. oggg 1.36+013 9342 2.881003 1342 2,49+003 1042 1. U2+0o 3 9342 2- 68-00 3 9342 1-50-01 3 9342 2.37@01 1 9316 S.95-01 293161 019, 3-83E+0i3Q347 5.01E+04 3 9347 6.39E+.4 3 20 P1 RDARC RIVER BARGE 0998 Qp0D+DD 3 0997 0-o 3 0997 O,Oo+oo 3 - 0-011,997 0-00 3-1- 0-00 3 0997 134401 3 9142 -I-ol 3 9449 5mfi@()! 1 2344 L41@01 3 9349 CS"I 3 9349 2.65-02 3 .349 1.53+01 3 o"s o2a -9 .1.. 1- 2 W51 4.30-89 3 9346 1.9-3 3 935o 2.86+0 3 9350 3.75-1 3 21 22 FUCTRIC MWER 22 23 m- -FRA'.. 0-0 3 I9Q8 0.0-D 3 19D81 og.o 0999 1.82+01 4 190f 1.82101 4 '0-00 3 looa 3.o2-o3 3 go -oz, I] O.GI+023 1.8-1 Mo. oM (1.00+00 39325 2,53- 3 9323 2.84,02 m.. 1.--- 1 9323 14-00 3 9323 1,58-01 3 932317.86 6.30+00 2 -1 6. 27+.Q 1 1,. 1.-.3 3 ID@7 1108-01 3 9327 4.41+00 39327 1.97-01 3 9328 COMo I QM 2-0% 1 9125 4.14@S 1 .11 -2- 3 23 24 24 25 26 26 27 27 28 29 29 30 32 31 33 33 34 34 35 35 36 36 37 37 39 38 39 39 40 _LO 41 42 49 43 43 44 44 45 45 46 47 47 48 49 49 50 so 51 _i2 Taal 53 154. TABLE5 ENVIRONMENTAL IMPACTS, EFFICIENCY AND COSTFOR ENVIRONMENTALLY CONTROLLED NATIONAL AND REGIONAL SOLVENT REFINED COAL SUPPLY 26 2 5 7 3 ... 13 1311 12 H11 2@_ .33o 3 3. FTN.19089300 Footnotes for Table.5 1908 The basis for water pollutant calculations is the pro- posedeffluent limitations guidelines and new source performance standards for-the steam electric power generating point source category given in (1921). For new plants, best available demonstrated control tech- nology (BADCT) requires effluent pH control in-the' range of 6-9. Hence*6qdcids and bases discharge,will be negligible. BADCT also specifies total suspended solids levels no greater than 15 qm8qg/q1 for all inter- -mediate and low volume waste effluents. At this level of control there will'generally be no net increase-in suspended solids in water 'passing through the power plant system. Organics (oil and grease) must be.controlled to 10 mg/q1 to6qpeet BADCT standards. Hence fqr om (1921, 232) these emissions-will amount to .0736 ton organics/ 106 ton coal or 3.02-03 ton/1012 Btu.' Information on the increase in total dissolved solids*of water used in power plants is not readily available and was syn- thesized from (1922,10,12,20,22). Based on this,data the net increase in total dissolved solids for water used by the power plant is 18.2 ton/1012 Btu. 9300 Table entries-for N. Appalachian Coal transportation are based on the haulage of 1.qOqOE8q+12q2 Btu/yr of coal (4.17E2q+04 T/yr).The average'distance from mine tipple to,.prep plant-is 7.3 mile's and the average truck.,capacity is 22 tons (9314j344). The-average fuel consumption of diesel trucks is 7.0 gal/1000 T2qHI (9303). To haul 1.qOqO8qE2q+12 Btu/yrf coal, 1896 round-trips are required* For a,plant processing 1.qOqOE2q+12 Btu/yr, 3q200 T/yr of ash is produced (see SR6qbq-Solid Waste). This requires 146 full load trips back to mine.-Assuming a gross to tare of 2q5 5.14+ E6q+03 gallons'are consumed..4qFrom (9303) the..air pollutants are Particulates 3.34qEqi-02T/l.q0q0E8q+l2tu sox 6.94Eq-'0q26qT/1.qOqOE4q+1'2 Btu 8qC4qO .5.76q8Eq-0lT/l.q0q0E8q+l2 Btu HC 9.-514qE-026qT/1.qOqOE0q+12 Btu NO4qX 9.514qEq-qOqJ0qT/1.qOqOE8q+12 Btu A24qLD 7.71E-03T/1q-6q02q0E08q+12q-Btu Road dust is assumed to be controlled by water sprays. VII-7 FTN. 9301-9304 9301 For a heating value of 5.83E8q+06 Btu/BBL and a fuel consumption of 5143 gal, ancillary energy for truck haulage is 7.14E4q+08 Btu. Land impact for truck haulage is based on a,60 ft rdwy, 'a mine to' plant distance'6f 7.3 miles (9314,344), and a lacre settling pond per mile. For a plant processing 10,0,00 tpd, the fixed land impact is 60'.lac. For a plant processing q1.qOqOE0q+12'Btu/yr, the fixed land impact is .763 ac-yr/ 1.qOqOE2q+12 Btu. 9302 Coal loss during transportation is assumed to be controlled by water sprays, Primary eqfficiency is 1.qOqOE6q+00. 9303 Capital cost for truck haulage consists of the. following 1p316,7/26): Road Grader 1.35E8q+05 Dump Truckq@q(5) 9.68E0q+05 Water Truck 2.20E4q+04 Settling Pondsq(7) -q1.40E4q+04 Coal Trucks(20) 8.OOE4q+05 Total 1.94E4q+06 dollars for 2MMT/yr mine Operating costs.rebased on (931.2,583,586). At 40,'000 dollars/truck and a fuel consumption,of 5143 gal, operating cost(including 720 dollars/l.qOE8q+12 Btu for fuel, 13140,dollars/l.qOE8q+12 Btu for labor, and 5256 dollars/l.qOE8q+1q2 Btu for maintenance) is l.-91E8q+04 dollars/ 1.qOqOE2q+12 Btu. At 10 percent fixed charge rate, capital cost is 4.04E4q+03 dollaqrs/l.qOqOE8q+12 Btu. 9304 Impacts for the solvent refined coal process are based on energy and material balances in (9300). A Northern Appalachian coal having the following proximate aqnialysis was used: Moisture 3.40 percent Ash 7.70 percent Sulfur 1.80 percent FC4q+VMA 89.90 percent. Heating value 12,000 32qt,tu/lb In order to maintain continuity in product and by-product streams, the fixed carbon and volatile matter is fixed. For a Northern Appalachian coal, equivalent feed is 8.42E12q+05 lb/hr. From (9300) wastewater stream from the dissolvers is 95,471 lb/hr and the probable composition is (9318q3,9300): VII-8 FTN. 9304 (Cont) Phenol 300.lb/hr NH3 157 lb/hr TDS 765 lb/hr S/S 5o lb/hr CN/SCN 27 lb/hr' Oil 3lb/hr H2S is assumed at 158 2qlb/hr to keep overall plant sulfur balance at 96.7 percent figure. No condensate from coal drying Will be formed since coal is approximately 3 percent moisture and most water will-be driven off as vapor. Sanitary waste is based on 100 gallon/day per employee and consist.of (9301): Flow 4843 lb/hr BOD 1.1 lb/hr .COD 1.4 2qlb/hr S/S 1.3 lb/hr Total plant blowdown (makeup water) is 1.45E4q+06 lb/ hr (9300) and will have the following analysis.(9317):,' TDS 11,043 lb/hr PO 4 7.3 lb/hr 25 lb/hr Blowdown is held in a holding or cooling pond and is then released (9300). The wastewater 'treatment system consists of the following units (9301,9304, 9305,9311)-phenol solvent extraction, sour water -stripping, primary clarification,,activated sludge, and secondary clarification. Removal effitiencies are given in references. To process 1.qOqOE8q+12 Btu/ yr of 12000 Btu/lb N. Appalachian coal, the scale factor is 1.26E-02 times figures given in (9300) and using 8.42E8q+02q5 lb/hr fixed carbon and vo2q1itile matter -feed.6qat"er pollutants based on discharging 4qof dissolver waste, sanitary waste, and cooling tower blowdown-6qaft+er treatment are (on a 1.qOqOE4q+1q2 Btu/yr basis).,.- Effluent@ Ton/Yr PPM Oil 1.49E-02 1.94E-01 CN2qISCNq. 1.35E-01 1.76E4q+00 NH3 2q.50Eq-02 3.25E-01q' H2S 1.15Eq-02 8q1. 2q5020qE-8q02q1 Phenol 1.49Eq-02 1 94E-01 S/S 1.59E08q+00 28q:07E04q+8q01 BOD 1.8qO8qOEq-02 1.30E-01 COD 1.2qO2qOEq-02 1.3024qE-01 TDS 5q.90E08q+02 7.67E08q+03 P04 3.65E-01 4.7520qE08q+00 H20 7.70E08q+04 VII-9 FTN. 9305 9305 Air pollutants associated with the solvent refining process primarily consist of emissions from fuel gas combustion.. Claus plant tail gas, and coal preparation plant. Claus Plant S02 emissions are based on.the total available sulfur in the input coal. For processing 8.42E+05 lb/hr of N. Appalachian coal with 1.8 percent sulfur content, 11,95-1 lb/hr of.sulfur is recovered of which 146 lb/ hr is generated as H2S in the sour water.stripping operation, 4410 lb/hr is recovered from a Wellman- Lord scrubber as S02 resulting in filter cake burning, and the remaining 7407 lb/hr H2S is recovered as H2S in acid gas treating. Assuming a 95 percent removal efficiency of the Wellman-Lor*d scrubber, 232 lb/hr S is emitted (9318). The Claus plant recovers.99.9 percent of-input sulfur. 0.1 percent is emitted to the atmosphere as S02 (9319, 127). S02 emissions are: Filter Cake Combustion Stack Gas 1829 T/yr-464 lb/hr@ 'Claus Plant Taill Gas @94 T/yr- 24 lb/hr ..Fuel Gas Combustion Combustionof the fuel.gas produced (868 Btu/SCF) is based on the fuel requirements and distribution given in (9300). The following is a list of combustion sources: Thermal Driers (from dissolvers)1309E+06 Btu/hr Mineral Residue Processing 50E+06 Btu/hr Solvent Recovery .630E+06 Btu/hr Hydrogen Plant 502E+06 B tu/hr Sulfur incinerator 52E+06 Btu/hr Air emissions are based on combusting a total of 2.54E+09-Btu/hr (9303,2/72), and the heating value ratio of. 868 Btu/SCF to that of natural gas 1050 Btu/SCF. Preparation of coal in flash dryer .s accounts for additional particulate emissions (9303, 8/10). Processing 8.39E+05 lb/hr of coal .(at 3 percent moisture) particulate emissions are 1413 T/yr using 95 percent efficient cyclone. Total air pollutants are (tons/yr),: VII-10 FTN. 9306-9309 Area Part. SO CO .11C No ALD Coal Prep. 1413.00 1.97 197 @861 14.716 Mineral Proc. 3.40 1829 0,08 7.52 _32.9 0.56 Solvent Ext. 42 6 - .0.95 94.@80 414.8 7.11 H2 Plant 33:94 - 0.76 75.60 330.8 5.67 Claus Plant 3.50 94 0.08 7.80 34.0 0.59 1496.40 1923 3.:84 .382.72 1673.5 28.69 These data are based,on processing-8.42E+05 lb/hr. To process 1.OOE+12 Btu/yr of 12000 Btu/lb N. .Appalachian coal, the scale factor is 0.0126.. 9306 Solid waste from the solvent refining process results primarily from ash removal in the mineral residue processing area. As the filter cake is combusted, the ash is produced. For an SRC plant processing 8.42E+05 lb/hr of N. Appalachian coal with a. 7.71 percent ash content, 64,867 lb/hr of ash will be produced (9300). To process 1.OOE+12 Btu/yr, 3.20E+03 ton/yk df ash will.be produced. The ash will not have a land impact since it is assumed to be.returned to the mine for burial. 9307 A 10,000 T/D SRC plant,is assumed to occupy 200 - acres. For a-plant processing 1.OOE+12 Btu/yr (127 T/D) land impact is 2.51 Ac-yr.' 9308 Primary efficiency Is based on the'input of..8.42E+05 lb/hr of-1.20E+04 Btu/lb N. Appalachian coal and.an output of 4.88E+05 lb/hr of 1.59E+04 Btu/lb solvent refined coal. Primary thermal efficiency 'is 76.8 percent. The thermal efficiency would be higher if input of hydrogen'and output of'light oils is considered (9300). 9309 Ancillary energy for a 10,000 T/D solvent refined coal plant is,approximately 7.71E+08 Btu/hr of- natural gas (9300,5-11). Of the 3.14E+09.Btu/hr fuel gas required, 2.37E+09 Btu/hr is supplied by the production of high Btu refinery gas. The additional gas (natural gas) must be purchased-It is anticipated that a solvent refined coal plant will make use of a considerable amount ofwaste heat and will actually export 32 MW of electrical power. For a plant processing 1.OOE+12 Btu/yr, ancillary energy is 7.66E+10 Btu/yr. VII-11 FTN. 9310-9312 9310 Capital cost for a 10,000 T/D solvent refined coal plant is based on data from (9300). The process is utilizing 8.33E+05 lb/hr and a Northern Appalachian coal wil1require-8.42E+05.lb/hr. Cost for coal prep, processing, filtration, and sulfur recovery have been linearly adjusted to refle 'ct difference in coal input rates (lb/hr). Additionally, another 1.63E+06 dollars has been added to cover the cost of sour water strippers and activated sludge units. Costs have been adjusted to 1972 dollars using 4 12 percent increase (from 1969). Total annualized cost is 8.34E+06 dollars at 10 percent fixed charge rate. For a plant processing 1.OOE+12 Btu/yr, the total capital cost is 1.05E+05 dollars. Plant load factor is. 90 percent. Operatinq cost is based on 9.58E+06 dollars/yr and a by-product credit of 1.16E+06 dollars/yr. Total cost is scalediup 12 percent to reflect 1972 cost'(9300). 9311 In a study conducted by the Bureau of-Mines (9320) the average haulage distance from mines in this region is'about 320 miles. Energy consumption by freight trains is assumed to apply to unit and mixed.trains (9335). Trains-are assumed to have a. gross to tare ratio of 4 and consist of 3 locomo- tives. It is further assumed that SRC.is transported in solid form and that it presents no unusual diffi- culties in handling.-To haul 1.OOE+12 Btu/yk, the total weight of a unit train is 41982 tons. To haul 320 miles, a total of 6.72E+04 gal of diesel fuel is consumed by the 3 locomotives. Return trip requires 1.68E+04 gal. Air pollutants for diesel consumption and loading and unloading are given as follows (9303,3-7,7-4): Locomotive Loadinq/Unloadinq Lb/1000 Gal T/1.OOE+12 Btu T/l.DOE+12 Btu Particulates 25 l.U4+UU 12.60+00 sox 65 2.76+00 CO 70 2.97+00 HC 50 2.12+00 NOX 75 3.20+00 ALD 4 1.70-01 9312 Ancillary energy for haulage of 1.OOE+12 Btu/yr is l.-17E+10 Btu. Figure is based on consumption of 8.40E+04 gallons of diesel fuel with a heating value of 5.83E+06 Btu/bbl (Footnote 9311). VII-12 FTN 9313-9319 9313 Primary efficiency is 1.00E+00 percent. It is assumed that miscellaneous losses due to spillage are negligible. 9314 Land impacts associated with the distribution of SRC are assumed to consist of a 320 mile rail line, footnoote 9311, with a R/W of 60 ft. This line would serve a 10,000 T/D SRC plant producing 6.80E+13 Btu/yr. Land impact for shipping 1.00E+12 Btu/yr is 3.43+01 A-yr. 9315 Solid waster for SRC haulage by rail assuming negligible losses is 0.000E+00 ton/yr. 9316 For the period from 1969 to 1970, shipment of coal accounted for 27 percent of the total tons of freight shipped by rail (9321,559). Of the total coal shipped, 1.00E+12 Btu/yr of SRC would account for 0.01 percent (total 330 MMT). During the same period an average of 2255 fatalities occurred and 21,666 person were injured in rail accidents (9322). These figures include all accidents. Injuries to employees on duty average 16,250 persons and 93 man-days were lost per injury (9322). Hence, for every 1.00E+12 Btu/yr hauled, there are 0.061 fatal injuries, 0.585 non- fatal injuries, and 59.5 man-days lost. 9317 Freight charges for haulage by unit train are 0.0061 dollars/TMI (9322,10) in 1969 cost. ICC im- posed an 8P and 6P freight rate increase in 1970 and 1971, respectively, to 0.00070 $/TMI. Haulage of 3.15E+04 ton of SRC, equivalent to 1.00E+12 Btu, a distance of 320 miles is 7.04E+04 dollars totoal costa. From (9323, 67/70 fixed cost (depreciation only) is about 6 percent of total annual cost. Hence, fixed cost is 4.22E+03 $ and annual operating cost is 6.62E+04 $. 9319 The average capacity of a barge is 25000 tons (9326, 35), and the average haul distance is assumed to be 800 miles (approximate distance from Erie,Pa. to Chicago via Great Lakes). Air emmissions are based on (9303,3-11). To haul 1.00E+12 Btu of SRC 1.26 round trips must be made. Pollutants are: VII-13 FTN. 9320-9323 Lb/Mi T/1.OOE+12 Btu Particulates 2 2.02E+00 sox 1.5 1.52E+00 CO 1.2 1.22E+00 HC 0.9 9.10E-01 .NOX 1.4 1.42E+00 .ALD 0.07 7.06E-02 From (9303,7-4) an additional 12.6 tons of particulates are emitted when loading and unloading SRC. 9320 Ancillary energy is based on a fuel consumption of 378 Btu/TMI (9325), a capacity of 25000 tons (9326, 35), and distance of 800 miles. Assuming a gross to tare ratio of 4 and that barges return empty to their origin, -energy required isl.59E+10 Btu:for the 1.26 round-trips. 9321 Neglectin4 miscellaneous transportation losses, primary efficiency is 100 percent. 9322 The cost for shipping coal..(SRC) in 1971 by barge was 0.97 dollars/ton (9327,37) of which 12 percent (inclusive of insurance and depreciation) is fixed cost. This agrees with data in (9328,18). Cost to haul 3.15E+04 tons of SRC would be 2.86E+04 dollars operating and 3.91E+03 dollars fixed. Cost is escalated 6 percent to reflect 1972 cost. 9323 Air pollutants'for power generation are based on, an SRC input of 1.OOE+12 Btu/yr or 31,446 tons/yr. SRC composition will have a sulfur content not greater than 0.95 percent and a heating value of approximately 15,900 Btu/lb. Ash content will be less than 0.1-percent. It is assumed that pulverized SRC will perform similar to typical coals and will. present no unusual combustion difficulties. All pollutant figures are.based on (9303) utilizing the appropriate ash and sulfur content. Pollutants are as follows: Lb/Ton SRC Ton/1.00E+12 Btu Particulates 16(Ash) 2.53E+01 sox 5.71E+02 CO 1.0 1.58E+01 HC 0.3 4.74E+00 NOX 18.0 2.84E+02 ALD .005 7.86E-02 Total 9.01E+02 VII-14 FTN 9325-9331 9325 By use of mechanical draft wet cooling towers, thermal pollution may be virtually eliminated. 9326 From (9300) the ash content of solvent refined coal is 0.1 percent. For a SRC feed of 31,446 ton/yr (1.00E+12 Btu), 31.5 tons of ash are available as solid waste. In practice, however, 80 percent of this material is emitted as particulates during combustion. The remaining 20 percent results in ash or solid waste. Soldi waste is 6.30 ton/1.00E+12 Btu. 9327 Occupational health statistics are based on reference (9330,46). 0.166 men per MWE is the basis for the calculation. Injury data is from (9331,35). Half the combined deaths and permanent injuries are assumed to be fatal injuries. Permanent total disabilities are considered to represent 6000 days lost while other disabilities are estimated as 100 days lost. Man-days lost are for injuries only. 9328 Power plant efficiency is based on 60.3 percent heat rejection rate. One-sixth of this is emitted through the stack gas. It is assumed the boiler and turbine efficiency is similar to conventional fossil fired plants (9333), however in actuality they will be somewhat higher due to the reduced ash content and higher heating value of the solvent refined coal. No actual tests have been performed. From (9330) turbine heat rate is 7750 Btu/Kw-hr resulting in a turbine efficiency of 44 percent, and steam generator efficiency of 90.1 percent (9300,5-6). Total plant efficiency is 39.7 percent. 9329 Capital and operating cost are based on (9300). Capital cost for a power plant with an input of 5.70E+13 Btu/yr is 1.31E+08 dollars. At a fixed charge rate of 10 percent, capital cost on a 1.0E+12 Btu input basis is 2.58E+05 dollars (1972). Operating cost is 4.14E+05 dollars including fuel, interest, taxes, in- surance, and depreciation. 9330 A typical size for a 3000 MWE plant with flyash controls is 1200 acres, including 350 for ash storage and 40 for coal storage from (9332,11,14). For a solvent refined coal plant, ash storage will not be required, hence fixed land impact is 6.27 acres/1.00E+12 Btu input. 9331 Tables entries for Central coal transportation are based on the haulage of 1.00E+12 Btu/yr or 4.17E+04 ton/yr of coal. The average distance from mine tipple to prep plant is 3.8 miles (9314,344). The average truck haul capacity is 59 tons (9314,344). The average truck diesel fuel comsumption is 7 gal/ 1000 TMI (9303). To haul 1.00E+12 Btu/yr, 707 VII-15 FTN. 9332-9334 round trips are required of which 67 return trips are full loads (haul solid waste, ash, back to the mine, see solid waste). Assuming a gross to tare of 2.5, a total of 2693 gallons of diesel fuel is consumed. From (9303.3-7)air pollutants are as follows: Lb/1000 Gal T/1.00E+12 Btu Particulates 13 1.75E-02 SOx 27 3.63E-02 CO 225 3.03E-01 HC 37 4.98E-02 NOx 370 4.98E-01 ALD 3 4.04E-03 9332 For a heating value of 5.83E+06 Btu/BBL and a totoal fuel consumption of 2693 gallons, ancillary energy for truck haulage is 3.74E+08 Btu. Land impact for truck haulage is based on a 60 ft R/W, a mine to plant distance of 3.8 miles (9314,344), and a 1 acre settling pond per mile (control of sediment). For a plant processing 10,000 tons/day, the fixed land impact is 31.6 acres. For a plant processing 1.00E+12 Btu/yr, the fixed land impact is 0.401 A-yr/1.00E+12 Btu. 9333 Coal loss during transportation is assumed to be negligible. Dust control is accomplished by water sprays. Primary efficiency is 100 percent. 9334 Capital and operating cost are based on (9316,7/26). For truck haulage capital cost are as follows: Road Grader (2) 1.32E+05 dollars Dump Trucks (5) 9.68E+05 dollars Water Truck 2.20E+04 dollars Settling Pond (4) 8.00E+03 dollars Coal Trucks (10) 6.90E+05 dollars 1.82E+06 dollars for 2MMT/hr mine For a truck haulage of 1.00E+12 Btu/yr at 10 percent fixed charge rate, costs are 3.79E+03 dollars. Operating costs are based on (9312,586). At 69,000 dollars/truck and a fuel consumptionof 2693 gallons, operating cost (4.54E+03 dollars for maintenance, 3.77E+02 dollars for fuel, and 6.56E+03 dollars for labor, on a 1.00E+12 Btu/yr basis) is 1.15E+04 dollars/ 1.0E+12 Btu. VII-16 FTN. 9335 9335 Impacts for the solvent refined coal process are based on energy and material balances in .(9300).*A Central coal:having the following proximate analysis was used: Moisture 11.20 percent Ash .9.40'perc&nt Sulfur 3.50 percent FC+VMA 79.40 percent Heating value 12,00'0 Btu/lb, In order to,maintain continuity in product and by-product streams- the fixed carbon and volitile matter is'fixed. For a Central coal, th'e'equivalent feed is 8.64E+05 lb/hr at 3.0 percent moisture as in reference (9300). From (9300) the wastewater stream from the dissolver is 96,.599 lb/hr and the probable composition is (9313,9300): Phenol 3000 lb/hr NH3- @,160 lb/hr TDS .8125 lb/hr S/S 51 lb/hr. CN/SCN. @27 lb/hr Oil .3 lb/hr H2S islassumed at 3*491b/hr to keep.the overall plant sulfur balance'at 96.5 percent. Condensate from the coal prep plant is approximately.11,379 lb/hr with about 10 percent oil and solvent content. This waste streain is genera-Led during thermal drying. Sanitary waste is based.on 100 gal/day/employee and consists of' (-9301)-:' Flow' 4843 lb/hr BOD 1.1 lb/hr. COD 1.4 lb/hr S/S 1.3 lblhk Total boiler and. 'cooling water makeup is.1.45E+06 lb/hr (93 00).,Blowdown will consist of the '-following pollutants (9317): TDS lb/hr PO,4 7.3'lb/hr S/S 25 lb/hr VII-17 FTN. 9336 This blowdown will be held in a holding or cooling pond and is periodically released (9300). The waste water treatment system consists of the following units (9301,9304,9305,9311): phenol solvent extraction, sour water stripping, primary clarification, activated sludge, and secondary clari- fication. Removal efficiencies are given in references. To process 1.00E+12 Btu/yr of 12,000 Btu/lb Central coal, the scale factor is 1.12E-02 times figures given in (9300) and using 8.64E+05 lb/hr feed (FC+VMA fixed). Water pollutants are based on discharing of dissolver waste, coal prep waste, sanitary waste, and blowdown waste after treatment. Effluent Ton/Yr PPM Phenol 1.33E-02 1.95E-01 H2S 1.10E-02 1.62E-01 S7S 1.49E+00 2.06E+01 NH 2.20E-02 3.23E-01 CN/SCN 1.19E-01 1.75E+00 TDS 5.22E+02 7.67E+03 Oil 2.64E-01 3.88E+00 BOD 6.78E-03 9.97E-02 COD 8.62E-03 1.27E-01 PO4 3.21E-01 4.27E+00 H20 6.83E+04 9336 Air emissions associated with the solvent refining process primarily consist of emissions from fuel gas combustion, Claus plant tail gas, and coal preparation plant. CLaus-Plant SO2 emissions are based on the total available sulfur in the input coal. For processing 9.43E+05 lb/hr of 3.5 percent sulfur coal, 26,410 lb/hr of sulfur is recovered in the Claus plant. 324 lb/hr of this sulfur is recovered in sour water stripping and 9734 lb/hr is recovered via a Wellman-Lord scrubber system on filter cake burning process. The remaining sulfur is recovered in acid gas recovery of fuel gases. Assuming a 95 percent removal efficiency of the Wellman-Lord system (9318), 1025 lb/hr of SOx is emitted. The Claus plant recovers 99.9 percent of the input sulfur. 0.1 percent is emitted as S02 (9319,127). SO2 emissionis as follows: VII-18 FTN. 9337 Filter Cake Combustion Stack Gas 4041 T/Yr-1025 lb/hr Claus Plant Tail Gas 205 T/Yr- 53 lb/hr Fuel Gas Combustion Combusti on of the fuel gas produced (.868 Btu/SCF) is based on the fuel requirements and distribution given in (9300). The following is a list of combustion sources: Thermal Driers (from dissolvers) 1309E+06 Btu/hr Mineral Residue'Processing 50t+06-Btu/hr Solvent Recovery 630E+06 Btu/hr Hydrogen Plant' 502E+06 Btu/hr Sulfur Plant Incinerator 52E+06 Btu/hr Air emissions are based on combustion of-the total 2.54E+09 Btu/hr (9303,12/72), and the-heating value @ratio of 868 Btu/SCF to that@of natural.gas, 1050 Btu/SCF..Preparation of coal in flash driers accounts for additional particulate emissions (9303, 8/10). Processing 8.64E+05 lb/hr of coal (3.0 percent moisture) particulate emissions are 1362 T/yr using a 95 percent efficient cyclone,system. Total pollutants a re (tons/yr): Part. sox CO HC NOX ALD Coal P'rep. 1451.00 - 1.97 197.00 861.00 1T.76 Mineral Proc. 3.38 4041 0.08 7.52 32.90 0.56 Solvent Ext. 42.59 - 0.95 94 * 80 414.75 7.11 H2 Plant 33.94 - 0.76 75.60 303.75 5.67 Claus Plant 3.50 '204 0.08 7.80 34.00 0.59 1534.41 4245 3.84 382.72 1673.40 28 These figures are based on processing 8.64E+05 lb/hr. To process 1.OOE+12 Btu/yr of 12000 Btu/lb Central coal, the scale factor is 0.0112. 9337. Solid waste from the solvent refining process is. a result of combustion of the filter c.ake,being used as supplementary fuel. This ash is generated in the mineral processing step. For processing 9.43E+05 ton/hr-of Central coal having an ash'content of-9.4 percent, 88,663 lb/hr of ash is generated in the fluidized bed boiler. For a SRC plant processing 1.OOE+12 Btu/lb of Central coal (HV=12000 Btu/lb), ash or solid waste is 3.92E+03.ton/yr. This solid waste will have no land impact since it will be transported back to the mine for ultimate disposal -(9300). VII-19 FTN. 9338-9341- 9338 impacts have been interpolated from (9334,7). It is assum6d that a solvent refining operation will occupy 200 acres since product distillation, upgrading, and pipeline gas production will not be required. on a 1.OOE+12 Btu/yr,basis, land. impact is.2.24- A-yr. 9339 Primary efficiency is based on the input of 9.43E+05 lb/hr.of 12000 Btu/lb Central coal. Since fixed carbon.and volatile matter-is fixed with that,of the coal in (9300), the product streams are consistant with!that in (9300). Primary thermal efficiency accounts for only primary coal-input and SRC output. For a SRC heating value of 15,900 Btu/lb, product is 4.88E+05'lb/hr, and primary efficiency is 68.6 percent. If by-product streams are consiaeredl, efficiepcy would be somewhat-higher. 9340 Ancillary energy for a 10,000,T/D solvent. refined coal'plant is approximately 7.71E+08 lb/hr of natural gas (9300,5-11). Of the 3'.14E+09 Btu/yr.' fuel'gas required, 2.37E+09 Btu/hr is supplied by the production of high Btu refinery fuel gas. The additional gas (natural gas) must be imported. It is anticipated that a solvent refined coal plant will make use of a considerable amount of waste heat, and will be able to utilize this heat to produce electricity. Approximately 32 MW may be exported. 'Ancillary energy for a plant processing 1.OOE+12 Btu/yr is'6.,81E+10 Btu/yr. 9341 Capital cost for a 10,'000 ton/day SRC plant is based on figures in*reference (9300). Since the processing.6f Central coal will require a larger feed the cost of coal preparation, dissol 'ving,_ filtration, and'sulfur recovery have been scaled to .reflect the differences in throughput. Additionally, another 1.63E+06 dollars have been added to,cover the cost of sour water strippers and activated sludge units. Cost has been escalated from 1969 to 1972 $ using a straight 12 percent increase. Total annualized cost is 8,85E+06 dollars 'at a 10 percent fixed charge'-rate. For a plant processing 1.00E+12, Btu/yr', capital cost is 1.22E.+05 dollars. Plant load factor is 90 percent. VII-20 FTN. 9342-9343 Operating cost is based on 9.58E+06 dollars and a by-product credit consisting of the following: Sulfur 1.04E=06 dollars CO2 2.65E+05 dollars Lt Oil 5.13E+04 dollars Phenol 1.10E+05 dollars Power 1.18E+05 dollars Total 2.05E+06 dollars Costs have been escalated (from 1969) 12 percent to re- flect 1972 cost. For a plant processing 1.00E+12 Btu/yr of Central coal, Operating costs are 9.44E+04 dollars (9300). 9342 The average haul distance in the Central region is assumed to be 290 miles and the fuel consumption is 0.005 gal/TMI. (9335). To haul 1.00E+12 Btu/yr (31500 ton/yr) of SRC, 6.09E+04 gallons are consumed by the 3 locomotives. This assumes a gross to tare weight ratio of 4 to 1. The empty return trip requires 1.52E+04 gallons of diesel fule. Total fuel comsumption to haul 1.00E+12 Btu/ yr is 7.61E+04 gallons. Exhaust gases from the three locomotives are as follows (9303,3-7): Lb/1000 Gal Tons/Yr Particulates 25 0.95 SOx 65 2.49 CO 70 2.68 HC 50 1.92 NOx 75 2.88 ALD 4 0.15 In addition, another 12.64 tons/yr or particulates are emitted during loading and unloading (9303,7-2). 9343 Land impacts are based on 290 miles and a 60 foot railway right of way, for a plant processing 10,000 ton/day. The land impact for hauling 6.80E+13 Btu/ yr is 2109 acres. For an SRC plant producing 1.00E+12 Btu/yr, the land impact is 31.0 acres. FTN. 9345-9350 9345 Primary efficiency for solvent refined coal percent, assuming negligible losses during transportation. 9346 Ancillaryfuel consumption for unit and mixed train haulage is 1. Q6E+10 Btu/1. OOE+12 Btu hauled. From footnote 9342, 7.61E+04 gallons of diesel fuel are consumed. For a heating value-of 5.83E+06 Btu/BBL, total energy required is 1.06E+10 Btu. 9347 Freight charges for haulage by unit train are 0.0061 $/TMI (9322,10) in 1969 cos 't. ICC imposed an 8P and 6P freight rate increase in.1970 and.1971, respectively, to 0.0070 $/TMI. Haulage of 3.15E+04 tons of SRC, equivalent to 1.OOE+12 Btu, a distance of 290 miles is 6.:39E+04 $ total cost. From (9323,67/70) fixed cost (depr eciation.only) is about 6P of total annual cost. Hence, fixed cost is 3.83E+03 $ and operat.11ng cost is 6.01E+04 $. 9349 Th@average capacity of a barge.is 25000 tons'(9326. 35),and the average 1haul distance is assumed to be 300 miles (the approximate dis@tance from the southern coal fields of Illinois to Chicago Via the Illinois River). Air emissions are based on (9303. 3-11)'. To haul 1.OOE+12 Btu of SRC, 1.26 round trips must be.made. Air pollutants-are as follows:' Lb/Mi T/1.OOE+12 Btu Particulates 7.58E-01 sox 1.5 5.69E-01 CO 1.2 4.55E-01 HC 0.,9 3.41E-01 NOX 1.4 5.31E-01 ALD 0.07 2.65E-02 These pollutants are based on a fuel consumption of 378 Btu per TMI (9325). Another 12.6 tons of particulates are emitted during loading and unloading (9303,7-4). 9350 The cost for shipping coal (SRC) in 1971 by barge was 0.97 dollars per ton (9327,37) of which 12 percent Unclusive of insurance and depreciation) is fixed cost. This agrees with data in (9328,18). Cost Ito haul 3.15E+04 tons of SRC would be 2.86E+04 dollars operating and 3.91E+03 dollars fixed. Cost is escalated 6 percent to reflect a 1972 base. VII-22 VIII. COAL LIQUEFACTION A. Introduction The environmental impacts, efficiencies-, and costs,for the production of low sulfur, liquid fuels from coal.-..are given in'Table 6 of this report. . Data-weredevelopedfor thiree regional coals:, a high sulfur Cehtral.coal,-medium-sulfur Northern Appalachia coal, and a low sulfur.-Northwe,st coal.. In addition, a National average__ case was synthesized from theregional data. Thecharacteristics'' of the coal and@its.heat content,are' specified in the'first foot- note for each regional case,. Each data entry is based on an energy input of coal equiva- lent to 1012 Btu and has-been derived for.a 11con'trolled" environ- mental condition. The nature and magnitude of coal liquefaction operations is suchthat stringent environmental control must be practiced. A new entry,has been included for the truck transportation of coal from the mine to the liquefaction plant. Since the solid waste produced by 'the liquefaction plant.is assumed to be disposed of by returning it to the-mine for bur-ial.,,@@,.thetruck.is no longer empty on-its return trip. Hence.there is. an increased:con.sumption of diesel fuel with a-corresponding increase.in air@ppllutants. All of the cost data shown in;Table-6@.-Is based-on I a90 percent Y ant load factor, or 328 operating days/yr. -The.valueS' DrespntpH- n' this table are based-on data accumu'lated..during. the Spring of 1974. TWO processes were considered,for the production of low sulfur liquid fuels from.coal, These are the CSF (Consol Syn- thetic Fuel) and SRC (Solvent Refined Coal) processes. Although other processes are being developed, thesetwo represent the most advanced for which data,are readily available. The COED process, although sufficiently 'advanced, was not considered in this studv because, with over half of the output Btu in the form of 6har or SNG, the process is not set up primarily for.the produc-' tion of liquid fuels." Table entries.have been made both at the process and activity 1, evels for coal liquefaction. The process lev.el.entries ar e re- presentative of the environmental impacts for the CSF and SRC pro- cesses, while the activit entry is an average of the process level y impacts. An activity level entry was made.so as to'minimize the differences in pr .ocess design assumptions, (arising from limited pilot plant data), the degree of completeness, and time periods over which.the processes were investigated. The following sections are brief descriptions of the individual coal conversion processes considered. VIII-1 CSF Process The CSF process (Figure 24) features extraction of the coal by hydrogenated solvents derived from the coal to produce a liquid- solid slurry. After hydroclave separationrthe liquid extract is fractionated in a vacuum still to produce a light fuel oil produdtand a heavier bottom extract. This extract then passes to a hydro- distillation column@from which is,taken a naphtha.cut and a heavy product fuel oil. The solid residue from the separation stepi containing ash.plus residual carbon, passes to a carbonization section to remove the remaining solvent.' The' resulting char from the carbonizer is gasified-in a Bigas u'n'it to manufacture the hydro- .gen required for the entire plant. 2. SRC Process In the SRC.process (Figure 25) coal is dissolved in a recycled solventunder a reducing atmosphere., The" resulting liquid-solid phases. are separated by means of filtration and the solid phase, contain- ing ash and residual carbonaceous material, is gasified in a Bigas unit to produce the hydrogen required in the hydrotreating units throughout the plant. The liquid.phase filtrate passes to.c-i dis- tillation column where it.is fractionated to p3;oduce a naphtha stream, a distillate, and a residual-fuel oil.;.-' The naphtha and distillate fractions are subsequently hydrotreated to reduce the sulfur and nitrogen.levels of these fuels. VIII-2 RAW FUEL GAS HpS TO RAW COAL SULFUR -PREHEATED PLANT COAL COAL EXTRACT SOLVENT FEED ------- 40 EXTRACTION SOLVENT DISTILLATE ,SOLVENT PREPARA- RECOVERY FUEL TION WASH OVER- 'RESIDUE GAS 40 GAS FUEL- FLOW SEPARA- PLANT TION LIQUOR EXTRACT GAS LIQUOR TO WATER' des- __w TO - I ' TREATMENT. WASH, LOW WATER UNDER-,- Btu TREATMENT FLOW EXTRACT GAS HYDROGEN HYDRO H 8k FOR SOLVENT LIGHT GENATION LET- COAL DOWN OIL DRY- TAR SOLVENT GAS ING BUTANE RECYCLE SOLVENT TAR TAR DISTILLATE FUEL DISTILLATION- LETDOWN -IA-R:: LTC Ek - GAS (CARBONIZER) WASH CHAR ABSORPTION UNDER- H?S TO ULFUR AIR- LIQUOR Colp PLANT SULFUR RECYCLE TO WATER SOLVENT ZeHAR STEAM TREATMENT H2 Ek BUTANE LET- STEAM DOWN BCR H2 Hp HYDRO- GAS MANUFAC- H2 0. COM_ DISTI LL_ NAPTHA F P D 19S 'ArT@ FR I- LATION@-11 OR 'Q.U VATER 4 TMENT TURE PRESSION HYDROGEN ATION HYDRORESIDUE TO PLA@j FUEL ------------------- Joe 02 Figure 24. CSF Coal Liquefaction Process (Ref. 9400) WATER CO WATER STEAM WATER GASIFICATIO14 SYN- ACID GAS G SHIFT GAS C02 OXYGEN UNIT GAS REMO\AL CONVERSION REMOVAL J SLAG COAL TO DISPOSAL GAS FROM C L L.LQUEFACTION T I METHANATION COAL DISSOLVER FUEL GAS PREPARATION ACID GAS@ SULFUR Hp GAS PLANT REMOVAL REMOVAL FUEL GAS OFFGAS WET FILTER OFFGAS OFFGAS-__ CAKE COAL COAL A COAL FUELOIL 0.2%,S SLURRYING a LIQUEFACTION FILTR LIQUEFACTIO HYDROGENA- FUEL OIL PUMPING 1% P11 T.ATION PRODUCT TION DISTIL ATION LIG _JNAPTHA RIECYCLE LIQUID 0.5%S PHENOLIC BOTTOMS WATER BOILER f f H GAS FROM FUEL OIL WAT ACID GAS TO WATER RECOVERED-7 NAPTHA METHANATION SULFGR RECOVE TREATMENT PHENOLICS HYDROGENA- NAPTHA PRODUTCT TION Figure 25. -Modified SRC Liquefaction Process (Ref. 9401) WA,TER N ER B.' Impact Data Table and Footnotes VIII-5 CONTROLLED 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Is 17 to 19 20 21 22 Z3 24 25 26 27 28 29 30 FUEL REGION COAL A5 INDICATED WATER POLLUTANTS (TONS/ Ida BTU, EX. COL. 12) AIR POLLUTANTS (TONS/Ida BTU) Ul ATIONAL HEALTH POTENTIAL COST (I)OLLARS/IOP*M) SOLIDS LAND OCC LARGE PRIMARY ANCILLARY MNE: - DISSOLVED SOLIDS SUSPENDED TOTAL T14ERMAL PARTIC- YDRO_ ALDEHYDES ) DEAiHS INJURIES MAN-DAYS ENERGY FIXED OPERATING TOTAL' ROM ACTIVITY PROCESS GOD COD NO,. sox co TOTAL TONS/ (ICRE.-TR - $CAL EFFICIENCY COST COST COST R Mott SOLIDS ORGANICS COUS 6.7,8 ATU/IO`*BTU) ULATES CARBONS ETC.' 1012STU, Ida . 70.2 BTU _10'28TU LOSTfdlBTU DISASTER (STuldlum ACIDS BASES P04 N05 OTHER TOTAL(DS) 10 BTU 7 -PACE I THNISJ TRANS@R TATION 2 3TRUK TRUCK o298 o9go .110 o9ge .... 1 1- 1-1 o9se D993 2.08-02 3 5-01 3 9457 4.33-G2 3 %57 5-02 3 9457 3.61-01 3 94S] 9.64-03 3 9457 160@@D 3 Oll. lm3g@Ot 3 1.57 09P9 .111 .11, 1082 1-00 1 P57 COD- 3 94S7 2.68,03 3 9457 7.67.63 3 057 1- 3 3 -4 UQFC LIQUEFAMON D1191 Oll, Ml .1. L@28@@72@1 19.4@56 A-3 5 94S6 1.67-03 5 9456 3.-.1 o- ... 9 o...... 2A ... D . . ....... . 9. -0-01 4 9456 2.2910D 4 945612.60-01 4 9456 9.52-04 4 4-03 2 9456 3.7-0 3945 61 -1 1 .191 20911 6.58-01 3 94S6 O.OQ- 2 945612. -05 3 906 1.9- 3.5. 41 6CSFPR CSF PROCE5S o.91 ol. Oll, 0999 4 , 1 59450 34-Oy 5 945D 1.23-03 5 9450 -4-61 5 D- D999 0-00 2 9451 2.56QO . 1- 1.1-1 0149446 3AS-01 4 9446 2.1-0. 4 9446 2.20-01 4 - 7,94-01 4 4.09,03 2 9447 -o 3"481 DO. o999 .11 mg, ...... . ... 0. 0040 2 5"51 I-OS 39441 1.3-5 3- 2.12.05 3 5 D.9 00. 6SRCPH sRc PRocEss .119 o999 Q999 3. 4-1 S945G @. 11-0 1 -D 2.1-3 51- 1.4- 1 o999 0999 O.OPOO 2 9451 3.35+DD 4 9446 5.82.01 4 9446 1.6-1 4 9446 2w9S 01 4 ME 2-OD 4 944t 2.99-DI 4* -6 1.17-02 4 4.3103 2 9447 4.34+00 39449 o999 .119 og" ZQ91 C25-01 3 9445 4. @D 2 @5 2oS@DS 29449 2.41AS 39U9 SA-5 3 6 -7 NO RTN@EST 0TRNW TRANS@ORTATION 9TRUK TRUCK -s .11. o9l. D- o...oo I's D19. 0998 S.31-03 3 9443 2.65-DI 3 940 1.93-02 3 9443 2.65-02 3 9443 1.61-01 3 9- 4. 30-D3 39443 4.85-01 3 DODO 3.03-01 31233 O.O-D I 12N 2. lo-02 1 l2o2 6m 74@01 1 1202 1 .2 DO- 1 22 3*25+03 3 9452 SaO@3 394S2 t.23+D4 3 9 -10 UQFC LIQUEFACTION o.-OO 2 945. 0-00 2 9458, 0-00 2 94SB 0.0-0 2 M . ..... DO -. D.D-D -. .. -D. I- D.OD+DD 11411 D.O-O 2 0.00+0 2 9458, Q.00-DO 2 9458 0. -OD 2 -8 1 2.. -D_ 4 9453 7.49+01 4 9458 4q 6@00 4 9458 7.9-1 4 9458 2-DO 4 "59 2.32 01 49459 , -3+01 4 331- 2 5.11... 3 941. o9ll .11, .11, 2.1 1. -1 1 -1 Oa 2 9458 2-.1 1- LA1.5 394", 3.- 1 10 CSFPRI CSF PRoc.s O-D@ 2 1-1 D.0.0 I I . 2 9436 o.oolOO 2 9 I'll .191 2091 6.21-01 3 94311 0.. 1.33+05 39435r_,-5 3 o...O. @ - .1 D.-D 2-9- O--D 02 9436 D. -OD 29436 O.OOIDQ 2 0.0&00 2 9436 0.0- 2 943@ 0.0- 2 9413 2.3-0 4 9432 6-101 4 9432 4.4B+OO 4 9432 3-01 4 9432: 2.08+00 4 o32 1.12-01 .-2 7.87.01 -1- 9031 D. Ol- 0. D", 1 01 101 1-- 39435 11- 12 -C-1 SRC -OUS O.OODO 2 9442 D.-OD 2 9442 O.WOD 2 442 0.0-0 2 9442 0. -00 2 9442 0-0 2 9442 D.-O 2 -2 d-00 29442 0. -00 2 D.-O 9442 0,00+OD @442 0-0 2 9413 3.491DO 4 1- -1- 4 2438 4.91-00 4 943B @-- 4 - -1- 1- -1-0 11.38 9.9-1 3:46+03 29439 6.22+OD 39440 o999 o9911 2.11 ..11-0 1 9.11 "37 2 W05 29441 2.4- 3-1 _F2 13 C.-RAL 13 14 TRNSPI TRANSPORTATION 14 Is TRUK I TRU@K ..8 .11 M. Oll. .11. D....OO 1 1- D11O D. DO... 2- .11. Oll. D998 1.95- 3 94141 5.Sfi-Ot 3 9414 4.05-02 3 9414 5,56-02 3 9414 3.38-Ol 3 9414 -1-0 1-4 1-1.0 3 ..D. 13sf D... 091 1082 1.00+00 1 109. 4+17- 3 94S% 2. 77.0 3 IM 13- 9455 1. ol+" 15 LW. I LIOVE-CTI.. -1 .11, mg ..91 0999 $.eo.ol 5 9459 1.27-Ol 1 1- -9-01 59459 5.8- 5 .9 -1 @ D,DD.O. .4@2 Dj49459 2.69-01 4 9459 4 Ml -1AD D 05912.11-Ol -1 LORID2 . Sj!4+D3 2 9459 3a!6+OG 3 9459 o999 .11, 2091 6.5-1 2 9459 ..O@00 1 $459 2.11+05 3 9459 IA8@05 39459 4-5 3 17 CSFPR CSF PROCM .919 - Oll. o- 0999 6.36+01 5 9- D-1 1 9401 1.84-D3 59406 .36-Ol 1 1 M, -. Z 10 +D,494DI L43+01 4 94D2 3.18-01 4 9402 2.12,00 4 9AD2 2A.-Ol 902 1 9.1-1 5.01-03 2 9403 2-100 3 9104 0." .111 .11. 2.1 2 1.1 O.OQ+OO 2 9401 1.621GS 3 9DOS 1.2@0 3940S 2AL,05 3 17 5RCPR SRC PROCESS -9 .91 nq 0999 5.23+01 5 9412 1.74 Ol 1 -1 14-03 59472 5.2-1 5 0"9 o.2 MOOD 7 94i3 .-I 1 1.0 1. -.1 . 904 2.1-1 Ml @.-DD @ 2- --l 1.2-1 1+11.1 1 -1 @-o 3 1- Oll, o"I'l 1 14.1 2.11.1 @ I- 'Al- 39411 19 NORTHERN APPA@CHIA 191 20 THNsF TRAN@RTATION 20 21 TRUK TRUCK .11. Oll. M. Oll. ..DDIDD 3 1- 0998 OAD'oo 3 .198 .91. - --2 1 .1. 1-- @ 1.1 --2 @ W8 9.1-2 3 942. 5.84-01 3 9428 1.56-02 39426 _1+76+00 3 aggg 1. 14+GO 3 1472 o999 D911 .11 1002 1-00 1 1093 7.24@ 3 9429 2.63+031 -_ 1.12,03 3 .13 9.25+03 3 21 22 IoFc ,qu,AcTlow .11, D119 .119 G999 oggg I.-W wo --2 @ -0 -0- S 946o @.-o .11, 0999 0-00 2 9450 2.94+00 4 9460 7.46+01 4 9460 I.-Ol 4 94R -2--ol 4 9460 2.2-0 4 9460 Ml@Ol 49460 9d22+01 4 4.11.03 2 9460 3-00 3 9- .11, .11, 2091 5.58-01 2 9460 O.OO+oo 2 946o 26045 i 946o ias- 3 -D 4.0-s 1 22 23 jC5FPR I CSF PR E@S o999 o999 o9gs am .111 -741 1 1- -03 5 94211 1.84-03 5 9421 6.37+01 5 1.0-DI 2 111. D.00+06 2 2416 1.- 3 94201 1.31- 3 -26 2.0@0 3 21 8.01 1 DO, 0999 IO.DD+0O 2 9413 2.6-0 4 9417 01- @ -1 1.11+01 4 9417 2@97-01 4 9417 _2.0+00 4 9417 2.2-1 49417 7m54+Dl 4 4wO0*O3 2 941. 2-+00 3 9419 - o919 Mg 23 24 sncpR] sRC mocEss .91, .... .11, D999 Sm24+01 5 9427 1,7-2 1 -7 3AI-Ol 1 9427 S.24-01 5 D911 0999 o@ I - 4 1- Sa82+01 4 9423 1.43+01 4 942: 2-01 4 9423 2.SO.00 1 9.23 3.02-01 49423 1.0-2 4 cz,- 3 - DID 2.1 k-Ol 2 1.21 D.DO+OO 2 94M 2-S 2 9426 2.4-5 3 -6 5-5 3 24 25 25 26 26 27 27 28 28 29 R 29 30 30 3 1 3 1 32 3 2 33 34 34 35 3 36 36 3 7 37 38 38 3 9 39 40 40, 4 1 41 42 42 43 43 441 1 44 45 4 5 46 46 47 j47 48 481 49 491 50 so 51 5 2 52 V3 31 54 :4 55 W5 TABLE 6. ENVIRONMENTAL IMPACTS, EFFICIENCY AND COST FOR ENVIRONMENTALLY CONTROLLED NATIONAL AND REGIONAL COAL LIQUEFACTION V I I 1 7 3 4 T'"S' T $4 U' !'C CE 1* h1l 2 7 RNW TRUK I'D 2 94. --o . . ... @ 5 4 47 4G 49 50 51 FTN. 1082-1233 Footnotes for Table 6 1082 The potential for large scale disasters is non-existent. 1098 Coal losse's during haulagd,from.mine to tipple are assumed to be negligible. 120*2. The.'haulage' statistics published in (1206) through (1210) were employed here. Haulage encompasses a broad category which includes the following transportation modes for the coal-U) from an underground mine to the surface by rail and (2) from the surface to,the coal preparation plants by truck. No-fatalities for-hauling coal strip mined in the states of Montana and Wyoming were reported over the years 1964-19,66, 1968 and 1.969. An average of 0.473 non-fatal injuries/l.OE06 tons production was computed .for coal haulage, occurring primarily in Wyoming,. An approximate average of 25 work-days lost per injury is assumed'foi transport following strip mining. This quantity results from averaging.the work-days lost/injury for Montana and Wyoming.; The basic statistics on average severities were comprised of contributions due to strip mining and haulage.. The.Felative contribution of each cannot be isolated. 1213' No coal is assumed lost between mine'and tipple. 123V To control sedimentation, the runoff from the haul roads is diverted to settling ponds placed at intervals along the roadway (1100). Since the road is relatively short (1.5 mile, footnote 1204) only one settling basin is,.assumed to be needed.. Because of,the low rainfall, the settling pond is,assumed adequate to contain all.,the runoff .(footnote 1233). The contained water can be utilized for dust suppression of-the haul roads or allowed to evaporate. 1233 The haul road land.impact is 0.274 AC-yr/l.OE12 Btu (footnote 1204). The settling pond is assumed-to have a- surface area of 1 AC, which for a depth of 5 feet has a storage capacity,of 1.6 MMgal. Thus, the land impact for the settling pond is'0.0285 AC-yr/l.OE12 Btu (2 MMT/yr hauled on roads). The.total land impact is 0.303 AC-yr/l.OE12 Btu. VII 1-9 FrPN. 1358-9401 1358 To control siltation, the runoff.from.the haul roads.'is diverted to settling.ponds placed along the roadway (1100). @It is assumed that all the sediment is removed. 1359 It is assumed that a settling pond is required,for each mile.of road and.that-each pond..us.es an.acre of land. Thus, 4 AC are utilized for the settling pond (the haul road is 3.8 mile long, footnote 1,312). The land impact is 0.0945. AC-yr/l.OE12 Btu., This is,in addition tolthe land impacted,by the road, ..0..584 AC-yr/l.OE12 Btu (footnote 1311), 1455 Sediment runoff from coal haulage roads can be controlled by-ditching.alongside the roads and diverting the runoff to small settling-ponds. 1472 it is as,sumed that a settling pond is required for each mile of road and that each pond uses one acre. Thus seven acres are utilized for the settling ponds (the haul road is 7.3 mile in length, footnote 1415). The land impact is.0.148'AC--yr/l.OE12 Btu. This is in addition to theland impacted by the road 0. 990 AC-yr/l. OE12 Btu, (footnote 1415) 2091 Fire and/or explosions caused by gas'.leaks, oil leaks, act of God, or human er 'ror. Possible damage@to refinery, personnel, adjacent properties. 9400 The-central coal used in this study has the'following n' -of-mine basis composition 0 a.run Proximate Ahalysis-WT PC Btu/lb 10820 Ash 11. 3 S-WT PC 3.70, Water 14.4. Vol. Mat. 33.4 Fixed C 40.9 For this coal 46,200 ton of coal is equivalent to 1.OE12 Btu. 9401 From (9400,13), a plant processing 23364 TPD of ROM coal produces.298.3EO9 Btu/D of fuel oil and 62.5EO9 Btu/D naphtha-or 360..8EO9 Btu/D total liquid fuels. The total plant heat demand is 106AE09 Btu/D, based on (9400,13) plus an additional 14.7EO9 Btu/D for previously purchased electricity (61150 Kw). This heat demand is provided by the combustion of fuel gases (89.8EO9 Btu/D) and coal- (16.6EO9 Btu/D). Thus a total of 24,133 TPD coal (522.2EO9 Btu/D from footnote 9400). is required to produce the 360.8EO9 Btu/D of liquid fuels for a primary.effic,iency of .691. The ancillary energy is zero because the plant is self-sustaining with all power and steam requirements generated on-site., VIII-10 FTN. 9402. 9402 Th e principal quantifiable air pollution sources are as follows TPD Part Sox CO HC NOX other Fuels combustion 1.40 8.91 11-11 .*157. 32.5 .00192 sulfur recovery. plant 3.80 Storage-and misc. .009 .128 Fuels Combustion Based on air emissions factors in (8301,1,.1-3,1.4-2) and the combustion of 769 TPD I:coal and 89.8EO9 Btu/D U of gases (containing 0.4 PC of the S in the process feed 9 coal from (9400)). Particulates from,the coal fired boiler were reduced 99.5 PC by the use of an ESP and FQ_ a Wellman Lord wet scrub. S02 emissions from the coal fired boiler were-reduced 95 PC by the Wellman-Lord unit. Particulate.emissions from the coal thermal dryers are based.on (8301,8.9-1). These emissions are 'reduced 85 PC by the use of multiple cyclones and then 99 PC by'a baghouse,before entering the atmosphere. Sulfur Recovery Plant Based on the amind and Rectisol acid.gas removal sys- tems' in (9400), the.Claus plant receives a 55 MOL PC H2S feed.- From (,2022,103) thi's Claus unit can recover 95.5 PC of the in'coming S. The inc'oming S 'for recovery is based.on 23364 TPD process feed coal, 3.70 PC S, and 91.4 PC of the-feed S as H2S to Claus for recovery (the balance-of the' S is in the liquid fuel products (3.0 PC) and produced as byproduct S (5.2 PC)) from (9400).@ Based, furthermore, on complete recycle to Claus of all.the S02 recovered in the Wellman Lord scrubbing units on the boiler flue'gases and Claus tailgases, 8521.2-TPD S is the Claus feed. Thus 813.9 TPD S is recovered from Claus plus 44.3 TPD S from the iron oxide towers for a.total of 858.2 TPD S or 1643 ton/l.OE12 Btu. 38.3 TPD S passes to the-tailgas unit so that 1.9 TPD S.or 3.8 TPD S02'exits the stack. Storage and Misc. Based on 23364. TPD of process feed coal and 1.1 PC N2 in the coal (9400,12) and-40 PC of the N2 as NH3'(9400 13), 128 TPD NH3 is produced and recovered. From (8301, .5.2-2) controlled,storage and loading operations emit two lb NH3/ton NH3. Thus .128 TPD NH3 are released into the atmosphere. From J9400,13) 12,200 BBL/D of naphtha are pro 'duced. Assuming two weeks storage capacity under new tank conditions and emission factors from (9302,4.j-8), .009.TPD HC are@emitted. Conversion to tons/l.OE12 Btu is.based on a total coal throughput of 24,133 TPD and 46,200 ton coal/l.OE12 Btu. VIII-11 FTN. 9403-9405 9403 Based on 23,364 TPD process feed coal with 11.3 PC ash, 2645 TPD ash are produced. 95 pc of this is solid waste for disposal with the balance in the products or deposited on catalysts (9400,13). Based on the combus- tion of 769 TPD coal and .4 TPD of emitted particulates, 86.7 TPD of solid waste is produced. Based on 10.660 GPM net makeup H20 (9400,51,66) and an assumed 500 PPM suspended solids which is completely removed by lime treatment and clarification, an additional 32 TPD of solid waste is generated. The sum total solid waste produced is thus 2616 TPD or 5007 ton/1.0E12 Btu. 9404 Fixed land requirements are estimated at 500 acres from (9401,7). Since coal liquefaction is considered a mine- mouth activity, all solid waste (Footnote 9403) produced is assumed to be returned to the mine for burial. There is, therefore, no incremental land impact due to solid waste production. Thus a total of 500 acres is required for a 24,133 TPD coal liquefaction operation. With a 90 PC operating factor this is equivalent to 2.91 acre-yr/1.0E12 Btu. 9405 Capital and operating costs were developed as follows: Capital Costs-1972 $-Plant Basis-24,100 TPD, 90 P LF From (9400,19), escalated from 1971 $ to 1972 $ at 5 PC, costs for coal preparation, extraction, separation, sol- vent recovery, low temperature carbonization, tar distilla- tion, extract hydroconversion, hydroletdown and absorption, hydrodistillation, gas plant, H2 manufacture, H2 com- pression, and support serviced total 233.6E06 $. Power generation costs were estimated at 121,80E06 $ (8323, 42), ESP costs at .16E06 $ from (9402,133), Claus plant costs at 3.70E06 $ from (8303, AI-25), Wellman Lord SO2 removal costs on coal boiler flue gases at 3.80E06 $ and on Claus tailgases at 3.90E06 $ from (8303, AI-26), and water pollution control costs at 1.8E06 $ from (9400, 102) and (2013,VII-4,VII-5). To the subtotal was added a 7 PC development contingency to arrive at a total plant investment of 278E06 $. Based of a FCR of 10 PC/yr and 7.93 TPY coal, this is equivalent to 1.62E05 $/1.0E12 Btu. Operating costs-1972 $-Plant Basis-24,100 TPD, 90 P LF From (9400,32), costs for catalyst and chemicals, raw water ash disposal maintenance material and labor, operating labor; supervision, and payroll and general overhead to 23.64E06 $/year. Operating and main- tenance costs on the power boiler were estimated at .19E06 $/year from (1918,46), ESP costs at 5E03 $/year from (9402,135), SGC costs on coal boiler flue gases at .86E06 $/year and on Claus tailgases at .92E06 $/year from (9403,18/27), and water pollution control costs at 45E03 $/year from (2013,VII-4,VII-5). The total gross operating cost is thus 25.66E06 $/year. Byproducts VIII-12 FTN. 9406-9408 were cre dited at $10/LTS (761 LTS/D) and,$25/T NH3 (128 TPD, NH3) from (8103,AI-5). The total net operating cost is thus 22-11E06 $/year or, for 7.93EO6 tPY coal input, 1.29EO5 $/l.OE12 Btu. 9406 Process wastewater pollutants were derived from (9400) and (9404) and include phenols, cyanide, NH3, sulfide, oil, and suspended solids.' Dissolved solids are contri- buted by boiler and.cooling tower blowdowns and deminerali- zation regenerations.. Wastewater treatment includes oil- water separation, dissolved air flotation, ammonia stills# equalization, activated sludge plus clarification, and activated carbon polish.- Removal efficiencies were de- veloped from (8318, Table 7 (8313,609.1618), (8312,207.), (2013,IV-3), and (8316,172). Organics (9.6E-04TPD) comprise phenols and oil,.while total -dissolved solids includes cyanide .(2.2E-03 TPD NH3 (.13 TPD)', sulfide (9.6E-04 TPD) and.other dissolved solids (33.1 TPD). Suspended solids total 4.2E-03 TPD-and the processwastewater discharge is 1193 TPD. Conversion to tons/l.OE12 Btu is'ba-sed on a total 'coal throughput of 24,133 TPD knd 46,,200 ton coal/I.OE12 Btu. 9407 From (94 .01,31) a plant processing 1.0,000 TPD coal (250. 8EO9 Btu/D) produces 156.7EO9 Btu/D.of liquid fuel pro- ducts for a.primary efficiency of .625. Although this is for a different coal, it is assumed that this efficiency holds a's well'for the central coal*(footnote 94 '00) used in this analysis. Thus, a total of 11,585 TPD of coal is required for the production of 156.7EO9 Btu/D of liquid fuels. Thetotal plant heat demand is 76.3EO9 Btu/D which is provided for by the combustion of 70EO9-Btu/D of fuel gases and 6.3EO9 Btu/D of product heavy fuel'oil. The ancillary energy is zero because the plant is self@ sustaining with all power and steam requirements, generated on-site. 9408 The principal quantifiable air pollution sources are as, follows:- TPD Part SOX CO HC NOx Other Fuels combustion .832 2.40 .626 ..0725, 22.1 .0196 sulfur recovery plant 5.0 storage and misc. .0014 .062 Fuels Combustion Based on air emi ssions factor's in (8301,1.3-2,1.-4-2). and the combustion of 6.25EO9 Btu/D of heavy fuel oil (con- taining .28 PC of the S in the process feed,coal from VIII-13 FTN. 9409-9410 (9405,11)) and 70EO9 Btu/d fuel gases (containing negii- gible S from (9405,11)). Particulate emissions-from the coal thermal dryers are based on (8301,8.9-1). These emissions are reduced 85 percent by the use of multiple cyclones and then 99 percent by a Venturi scrub before entering the atmosphere. Sulfur Recovery Plant''. Based on the.amine acid gas removal system in (9405',11, 16,19,21), the Claus plant receives a 10 Mol- percent H S feed. From (8303,AI-25) this-Claus unit can 2 recover 89 percent of the 'incoming S., The incoming S for recovery is based on 11585 TPD process feed coal, 3.7 percent-S, and 94..6 percent of the feed S as H2S to Claus for recovery (the balance of the S is in the liquid fuel products (5.4 percent)) from (9405,11.). Based, fuAhermore, on complete recycle to Claus.of the so2 recovered in the Wellman Lord.scrubbing unjt on the Claus tailgases, 452.8 TPD S is the Claus feed. Thus 403 TPD S is recovered for sale.or 1607 ton/l.OE12 Btu. Since 49.8 TPD S passes to the Wellman Lord tailgas scrubbing unit, 2.5 TPD S or 5.0 TPD SO2 exits to the atmosphere. Storage and misc. Based on 11585 TPD of process feed coal,and 1.1 percent N2 in the coalandthe assumption that 40 percent of the N2 forms NH (9400,13), 61.9, TPD NH. is produced and recovered. @rom (8301.,5.2-2) controlled storage and loading operations emit 2 lb NH3/ton NH . Thus .062 TPD NH are released into the atmosphere. ?rom (94'05,11) 2011 BB2/D of naphtha are produced. Assuming 2 weeks storage- capacity under new tank conditions and emission factors from (8302,4.3-8), .001 TPD HC are emitted. Conversion.to tons/l.OE12 Btu is based on a total coal throughput of 11585 TPD and 46200 ton coal/l.OE12 Btu. 9409 Based on 11585 TPD process feed coal with 11.3,percent ash, 1311 TPD ash are produced. Based on 3626.gpm*net makeup H 0, (9401,27) and an assumed 500 ppm suspended .Solids wAillch is completely removed by lime treatment and clarification, an additional 11 TPD of solid waste is generated. The sum total solid waste produced is thus 1322 TPD or 5272 ton/l.OE12 Btu. 9410 Fixed land requirements are estimated at 280 acres from (9405,48). Since,coal liquefaction is considered a mine-mouth activity,.all solid waste (Footnote 94.09) produced is a'ssumed to be returned to,the mine for burial. There is, -therefore, no incremental land impact due to solid VIII-14 FTN. 9411-9412 waste production. Thus a total of 280 acres is required for a 11585 TPD coal liquefaction operation. With a 90 percent operating factor this is equivalent to 3.40 acre-yr/1.0E12 Btu. 9411 Capital and operating costs were developed as follows: Capital Costs-1972 $-Plant Basis-11,600 TPD, 90 P LF From (9401,57), deescalated from 1973 to 1972 $ at 5 percent, costs for coal preparation, coal slurring and pumping, coal liquefaction and filtration, dissolver acid gas removal, coal liquefaction product distillation, fuel oil hydrogenation, naphtha hydrogenation, fuel gas sulfur removal, gasification, acid gas removal, shift conversion, CO2 removal, methanation, 02 plant, instru- ment and plant air, raw H2O treatment, process waste H2O treatment, power generation, product storage, slaq removal system, steam generation, general facilities, and home office engineering total 207E06 $. Claus plant costs were estimated at 3.3E06 $ from (8303,AI-25), Wellman Lord SO2 removal costs on Claus tailgases at 4.5E06 $ from (8303,AI-26), carbon absorption for wastewater costs at .25E06 $ from (2013,VII-4), and a Venturi for particulate removal on the thermal dryer at .40E06 $ from (1080,64). The total plant investment is thus 215.5E06 $. Based on a FCR of 10 percent/yr and 3.81E06 TPY coal this is equivalent to 2.61E05 $/1.0E12 Btu. Operating Costs-1972 $-Plant Basis-11,600 TPD, 90 P LF From (9406) the preliminary estimated operating costs of a 10,000 T/D plant are 50E06 $/yr based on $9/ton coal. Assuming a 90 percent operating factor this would give 29.6E06 $/yr for coal cost and 20.4E06 $/yr for other operating expenses. Based on 20.4 E06 $/yr and 3.81E06 TPY coal this becomes 2.47E05 $/1.0E12 Btu. 9412 Process waste water pollutants were derived from (9300) and (9313,61) and included phenols, cyanide, NH3, sulfide, oil, and suspended solids. Dissolved solids are contributed by boiler and cooling tower bowdowns and demineralization regenerations. Waste water treatment includes oil-H2O separation, phenol solvent, extraction, sour H2O stripping, primary clarification, activated slude, secondary clarification, and activated carbon polish. Removal efficiencies were developed from (8318, Table 7), (9301), (8322), (9305), and (9311). Organics (7.9E-04 TPD) comprise phenols and oil, while total dissolved solids includes cyanide (1.1E-02 TPD), NH3 (.01 TPD), sulfide (3E-03 TPD) and VIII-15 FTN. 9413-9416 other dissolved,solids (13.1 TPD). Suspended solids total 4.4E-03 TPD and the process waste H 20 discharge. is 208 TPD. Conversion to tons/l.OE12 Btu is based on a total coal throughput of 11585 TPD and 46200 ton coal/l.OE12 Btu. 9413 Thermal discharges can be completely eliminated.by the use of 'mechanical draft wet cooling towers. 9414 In 1969 the.average truck capacity for this region was'59 T and the average haulage distance from mine to tipple was 3.8 mi (0001,344). The fuel consumption rate is assumed to be 7 gal/1000 TMI.(0002,377) and the gross to tare weight ratio of the trucks is assumed to be 2.5 to 1. Based on 46200 ton coal/l.OE12 Btu, 783 round trips are required to deliver 1.OE12 Btu. From footnotes 9403 and 9409 the liquefaction plant produces an average,,of 5140 ton solid waste, so that 6.6 ton of solid waste/return trip goes back to the mine. Thus a round trip is 548 ton miles and 3003 gal of diesel fuel are consumed/l.OE12 Btu. Emissions from a diesel powered truck are given in (0002,3-7). Dusting,from haulage roads is controlled by'watering downf oiling, or some other method. 9415 The Northern.Appalachian coal used in this study has the following composition on a run-of-mine basis Proximate Analysis-Wt. PC. Btu/lb 12000 Ash 10.0 S-Wt PC @2.0 Water- 5.0 Vol.Mat.and Fixed C. 85.0 For this coal 41700 ton,.'of coal is equivalent 'to 1.OE12 Btu. 9416 From (9400,,13) a plant processing 23364 TPD of ROM coal produces 360.8EO9 Btu/d liquid fuel products. The total plant heat demand is'106.4EO9 Btu/d. based'on (9400,13.) plus an additional 14.7EO9 Btu/d for previously purchased electricity (61150 Kw). This heat demand is provided by the combustion of fuel gases (89AE09 Btu/d) and coal (16.6,EO9 Btu/d). Thus a'total of 24133 TPD coal is required to produce the 360.8EO9 Btu/d of liquid-fuels for a primary efficiency of .691. Although this is for adifferent coal, it is assumed that this efficiency holds as well for the Northern Appalachian coal (foot- note 9415),used in-this analysis. Thus 21067 TPD coal is required for process feed and 692 TPD coal is used in boilers.for a total of 21759 TPD coal. The ancillary energy is zero.because the plant is self- sustaining with all power and steam requirements generated VIII-16 FTN. 9417 on site. 9417 The principal quanitfiable air pollution sources are as follows TPD Part SOx CO HC NOx Other Fuels Combustion 1.37 2.84 1.07 .146 31.8 .00173 Sulfur Recovery Plant 2.0 Storage and Misc. .009 .113 Fuels Combustion Based on air emissions factors in (8301,1.1-3,1.4-2) and the combustion of 692 TPD coal and 89.7E09 Btu/d of gases (containing 0.4 percent of the S in the process feed coal from (9400)). Particulates from the coal fired boiler were reduced 99.5 percent by the use of an ESP and a Wellman Lord wet scrub. SO2 emissions from the coal-fired boiler were reduced 95 percent by the Wellman Lord unit. Particulate emissions from the coal thermal dryers are based on (8301,8.9-1). These emissions are reduced 85 percent by the use of multiple cyclones and the 99 percent by a bag house before entering the atmosphere. Sulfur Recovery Plant Based on the amine and Rectisol acid gas removal systems in (9400), the Claus plant receives a 43 Mol percent H2S feed. From (2022,103) this Claus unit can recover 94.9 percent of the incoling S. The incoling S for recovery is based on 21067 TPD process feed coal, 2.0 percent S, and 91.4 percent of the feed S as H2S to Claus for recovery (the balance of the S is in the liquid fuel products (3.0 percent) and produced as by-product S (5.2 percent)) from (9400). Based, futhermore, on complete recycle to Claus of all the SO2 recovered in the Wellman Lord scrubbing units on the boiler flue gases and Claus Tailgases, 413.1 TPD S is the Claus feed. Thus 392 TPD S is recovered from Claus plus 21.9 TPD S from the iron oxide towers for a total of 414 TPD S or 793 ton/1.0E12 Btu. Since 21.1 TPD S passes to the Wellman Lord tailgas scrubbing unit, 1.0 TPD S or 2.0 TPD SO2 exits the stack. Storage and Misc. Bases on 21067 TPD of process feed coal and 1.1 percent N2 in the coal and 40 percent of the N2 and NH3 (9400,13), 1I3 TPD NH3 is produced and recovered. From (8301,5.2-2) controlled storage and loading operations emit 2 lb NH3/ ton NH3. Thus .113 TPD NH3 are released into the atmos- VIII-17 FTN. 9418-9420 phere. From (9400,13) 12200 BBL/d Of naphtha are produced. Assuming 2 weeks storage capacity under new tank conditions and emission factors from (8302,4.3-8), .009 TPD HC'are emitted. Conversion to tons/l.OE12 Btu is based on a total coal throughput of 21759 TPD and 41700 ton coal/l.OE12 Btu.- 9418 Based on 21067 TPD process feed coal with 10-percent ash, 2107 TPD ash are produced. 95 percent of this is solid waste for disposal with the balance in the. products or deposited on catalysts (9400,13). Based on the combustion of 692 TPD coal and .4 TPD of emitted particulates, 68.8 TPD of solid waste'is produced. Based on 10660 gpm 'net makeu 'p H20 (9400,51,66) and an assumed 500 ppm suspended solids which is completely removed by lime treatment and clarification, an additional 32 TPD of solid Waste is generated. The sum total solid waste produced is thus 2090 TPD or 4004 ton/I.OE12 Btu. 9419 Fixed land tequirements are estimated.at 500 acres from (9401,7). Since coal liquefaction is considered a mine@- mouth activity, all solid waste (Footnote 9418) produced is assumed"to be r 'eturned to the mine for.burial. There is, therefore,'no'incremental,land impact due to solid waste production. Thus a total of @00. acres is required for a 21759 TPD coal-liquefaction operation. With a 90 percent operating factor this is equivalent to 2.92 acre-yr/l.OE12 Btu 9420 Capital and -operating costs were developed as follows: Capital Costs-1972 $-Plant Basis-21,800 TPD, 90 P LF From (9400,19),.escalated from 1,971 $ to 1972 $ at 5 percent, costs for coal preparation, extraction, separ- ation, solvent recovery., low temperature carbonization, tar distillation, extract hydroconversion, hydroletdown' and absorption, hydrodistillation,@gas plant? H manu- 2 facture, H 2 compression, and support services total 233.6EO6 $. Power generation costs were estimated at 12.8EO6 $ from (8323,42), ESP costs at .16EO6 $ from (9402,133),,Claus plant costs at 2.3EO6 $ from (8303, AI-25), Wellman Lord S02 removal costs on coal boiler flue gases'at 2.8EO6 $ and on Claus tailgases at 2.8EO6 $ from (830'3,AI-26),,I and H20 pollution control costs at 1.8EO6 $ from (9400,102) and (2013,VII-4,VII-5). To the subtotal was added a Tpercent development contingency to arrive at a total plant investment of 274.3EO6 Based on a FCR of 10 percent/yr and 7.15EO6 TPY-coal this.is equivalent to 1.60EO5 $/l.OE12 Btu. VIII-18 FTN. 9421-9422 Operating Costs-1972 $-Plant Basis-21,800 TPD, 90 P LF From (9400,32) costs for catalyst and chemicals, raw H2O, ash disposal, maint. mat. and labor, operating labor, supv., and payroll and gen. overhead total 23.33E06 $/Yr. Operating and maintenance costs on the power boiler were estimated at.19E06 $/yr from (1918, 46), ESP costs at 5E03 $/yr from (9402,135), SGC costs on coal boiler flue gases at .63E06 $/yr and on Claus tailgases at .66E06 $.yr from (9403,18.27), and H2O pollution control costs at 45E03 $/yr from (2013, VII-4, VII-5). The total gross operating cost is thus 24.86E06 $/yr. By-products were credited at $10/LTS (369 LTS?D) and $25/T NH3 (113 TPD NH3) from (8303),AI-5). The total net operating cost is thus 22.73E06 $/yr or, for 7.15E06 TPY coal input, 1.33E05 $/1.0E12 Btu. 9421 Process waste water pollutants were derived from (9400) and (9404) and included phenols, cyanide, NH3, sulfide, oil, and suspended solids. Dissolved solids are con- tributed by boiler and cooling tower blowdowns and demineralization regenerations. Waste H2O treatment includes oil-H2O separation, dissolved air flotation, ammonia stills, equalization, activated sludge plus clarification, and activated carbon polish. Removal efficiencies were developed from (8318,Table 7), (8313, 609,618), (8312,207), (2013,IV-3), and (8316,172). Organics (9.6E-04 TPD) comprise phenols (2.2E-03 TPD), NH3 (.13 TPD), sulfide (9.6E-04 TPD) and other dissolved solids (33.1 TPD). Suspended solids total 4.2E-03 TPD and the process waste H2O discharge is 1193 TPD. Conversion to tons/1.0E12 Btu is based on a total coal thoughput of 21759 TPD and 41700 ton coal/ 1.0E12 Btu. 9422 From (9401,31) a plant processing 10000 TPD coal (250.9E09 But/D) produces 156.7E09 Btu/D of liquid fuel products for a primary efficiency of .625. Although this is for a differenct coal, it is assumed that this efficiency holds as well for the N. Appalachian coal (footnote 9415) used in this analysis. Thus a total of 10446 TPD of coal is required for the production of 156.7E09 Btu/D of liquid fuels. The total plant heat demand is 76.3E09 Btu/D whic is provided for by the combustion of 70E09 Btu/D of fuel gases and 6.3E09 Btu/D of product heavy fuel oil. The ancillary energy is zero because the plant is self-sustaining with all power and steam requirements generated on-site. VIII-19 FTN. 9423 9423 The principal quantifiable air- pollution sources are as follows: TPD Part. so CO HC NO Other 'X x Fuels Combustion .815 1.17 .626* .0725 22.1 .0196 Sulfur Recovery Plant 2.4 Storage and Misc. .0014. .056 Fuels Combustion- Based on air emissions factors in (8301,1.3-2,1.4-2) and the combustion of 6.25EO9 Btu/D of heavy fuel oil (containing .28 percent of the S in 'the process feed coal from (9405,11)) and 70EO9 Btu/D of fuel gases (containing negligible S from (9405,11)). Particulate emissions from the coal thermal dryers are based on (8301,8.9-1 ). These emissions are reduced-85 percent by the use of multiple'cyclones and then 99 percent by a. Ve-nturi,scrub before entering the atmosphere. Sulfur Recovery Plant Based on the amine acid gas*removal system in (9405,11, 16,19,21), the Claus plant receives'a 10 Mol percent H 2S feed. From (8303,AI-.25) this Claus -unit can recover 89, percent of the incoming S. The incoming S for recovery is based,on.10446 TPD process feed coal, 2A percent S, and 94.6 percent of the feed S as H S to Claus for recovery (the balance of the S is iA the liquid fuel products (5.4 percent)) from (9405,11). Based, furthermore, on complete recycle to Claus of the SO recovered in the Wellman Lord scrubbing unit on the.Laus tailgases, 220.6 TPD S is the Claus feed.,.Thus 196.3 TPD S is recovered for sale, or 783 ton/l.OE12 Btu. Since 24.3 TPD S passes to the Wellman Lord tailgas scrubbing unit, 1.2 TPD S or 2.4 TPD SO 2' exits to the atmosphere.. Storage and Misc. Based on 10446 TPD of process feed coal and 1.1 percent Ng in the coal and the assumption that 40 percent of t e N forms NH (9400,13), 55.8 TPD NH is produced and 2 3 3 recovered. From (8301,5.2-2) controlled storage and loading operations emit 2 lb NH /ton NH 3. Thus .056 TPD NH are released into the atmoslhere..From (9405,11) 2'011 BBZ/d of naphtha are produced. Assuming 2 weeks storage capacity under new tank conditions and emission factors from (8302,4.3-8), .001 TPD HC are emitted. Conversion to tons/l.OE12 Btu is based on a total coal throughput of 10446 TPD and 41700 ton coal/l.OE12 Btu. VIII-20 FTN. 9424-9427 9424 Based on 10466 TPD process feed coal with 10.0 percent ash, 1045 TPD ash are produced. Based on 3626:gpm,ne'-t makeup H 20 9401,27) and an assumed 500 ppm suspended solids which is completely removed by lime treatment and'clarification, an additional 11 TPD,of solid waste is generated. The sum total solid waste-produced -is thus 1056 TPD or '4214 ton/1.0 E12 Btu. 9425 Fixed land requirements are estimated at 280 acres from (9405,48). Since coalliquefaction 'is considered a,mine- mouth activity', all solid waste (Footnote 9424):produced is assumed to be returned to the mine for burial., There:is, therefore, no incremental land impact'due to solid waste pro- duction. Thus a total of 280 acres,is'requir'ed for a 10446 TPD coal liquefaction-operation.. With a 90 percent operating factor this-is equivalent to .3.40 acre-yr/l.OE12 Btu., 9426 Capital and operating costs were develo ped as follows: .Capital Costs-1972@$-Plant Basis-10,400'TPDi 90 P LF ,.From (.9401,5,7), de-escalated from 1973 to 1972 $ at 5 percent, costs for coal preparation, coal. slurrying and pumping, coal liquefacti6n and filtration,, dissolver acid gas'removal, coal liquefaction product distillation, fuel oil hydrogenation,.naphtha hydrogenation,.fuel.cjas. sulfur removal, gasification, acid gas removal, shift, conversion, CO removal, methanation, 0 plant, instrument 2 2. and plant air, raw H 20 treatment, process waste H 20 treatment, power generation,.product@storage, slag removal system, steam generation, general facilities, and home office engineering total 207EO6'$. Claus plant costs were estimated at 1.9EO6 $ from (8303-,AI-25),.Wellman Lord SO removal costs on Claus tai Igases at 3.2EO6 $ from (8303,AI-26), carbon.absorpti'on for' wastewater@costs at .25EO6 $ from (2.013,VII-4), and a,Venturi for particulate removal on the thermal dryer-at .40EO6*$ from (1080,64). The total plant investment is-thus 212.7EO6 $. Based on a FCR of 10 percent/yr and-3.43EO6 TPY coal this is equivalent to 2.59EO5 $/l.OE12 Btu. Operating Costs-1972 $-Plant Basis-10,40O.TPD, 90 P LF From (9406) the preliminary estimated operating costs. are 50EO6 $/yr bas,ed on $9/ton coal. Assuming a 90 percent operating factor this would give 29.6EO6 $/yr- for coal cost and 20.4EM$/yr'for other operating expenses. Based on 20AE06 $/yr and 3.43E06 TPY,coal. this becomes 2.48EO5 $/l.OE12 Btu. 9427 Process waste water pollutants were derived from (9300) and-(9313,61) and included phenols,:cyanide, NH V sulfide, VIII-21 FTN. 9428-9431 oil, and suspended solids. Dissolved solids are contributed by boiler and cooling tower blowdowns and demineralization regenerations. Waste water treatment includes oil-H 9 separation, phenol solvent extraction, 2 sour H 20 stripping, primary clarification, activated sludge, secondary clarification, and activated carbon .polish. Removal efficiencies were developed fr 'om (831R. Table 7), (9301), (8322), (9305), and (9311). Organics (7.9E-04 TPD) comprise phenols and oil, while total dissolved solids includes cyanide (1.lE-02 TPD), NH 3 (.01 TPD), sulfide (3E-03 TPD). and other dissolved solids (13.1 rPPD).. Suspended solids total 4.4E-03 TPD and the process waste H 20 discharge is 208 TPD. Conversion to tons/l.OE12 Btu is'based on a total-coal throughput of 10446 TPD and 41700 ton coal/l.OE12 Btu. 9428 In 1969 the average truck capacity for this region was 22T and the average haulage distance from mine- to tipple.was 7.3 mi (0001,344). The fuel consumption rate is assumed t6 be 7 gal/1000 TMI(0002,3-7) and the gross to tare weight ratio of the trucks is assumed to be 2.5 to 1. Based on 41700 ton coal/l.OE12 Btu, 1895 round trips are,required to deliver 1.OE12 Btu. From footnotes 9418 and 9424, the liquefaction plant produces an average of 4110 ton solid wast@, so that 2.2 ton of solid .,waste/return trip goes.back to the mine. Thus a round' trip is 391 ton-miles and 5191 gal of diesel fuel are consumed/l.OE12 Btu. Emissions from 6 diesel'powered truck are,given in (0002,3-7). Dusting from haulage roads is controlled by-watering down, oiling, or some other method. 9429 Fuel consumption by the haulage trucks amounts to 5191 gal diesel fuel/l.OE12 Btu (footnote 9428). For 5.83EO6 Btu/BBL diesel fuel this.is equivalent to 7.21EO8 Btu/ 1.OE12 Btu. 9430- The Northwest coal used in this study has th.e.following. composition on a run-of-mine basis Proximate Analysis-Wt.Pc. Btu/lb 8806 Ash 6.0. S-Wt.Pc. 0.5 H 0 22.0 @621.Mat. 29.4 Fixed C. 42.6 For thi's coal 57000 ton of coal is equivalent to 1.OE12 Btu. '9431 From (9400,13) a plant processing 23364 TPD of ROM coal produces 360.8EO9 Btu/D liquid fuel products. The total plant heat demand is 106AE09 Btu/D, based on (9400,.13) VIII-22 FTN.9432 plus an additional 14.7EO9 Btu/D.for previously purchased electricity (61150 Kw)'. This heat demand is provided by the.combustion of fuel gases (8-9.8EO9 Btu/D),and coal (16.6EO9 Btu/D).. Thus a total of @4133 TPD.coaI is required to produce .the.360.8EO9 Btu/D of liquid fuels for a primary efficiency of .691. Although this is.for,. a different coal; it is assumed that this efficiency holds as well for the subbituminous Northwest coal (footnote' 9430) used in this analysis.. Thus 28696 TPD;coal is required for process feed and 949 TPD coal is used in- boilers for a total of 29645 TPD coal. The ancillary energy is zero because the plant is self-sustaining,with all power and steam requirements generated on-site. 9432 The principal quantifiable airpollution sou rces are as follows: TPD Part. so CO HC NO' Other x x Fuels Combustion 1.24 1.53. 1.08. .147 .31.9 .001.74 SuILfur Recovery Plant 0.80 Storage and Mis.c. @.009 .099 Fuels Combustion Based on air emission factors in (8301,1.1-3,1.4-2) and the combustion of-696 equivalent TPD coal and,89.7EO9 Btu/D of gases..(containing 0.4 percentof the Sin the process feed coal from (9400)). Particulates from the; coal fired boiler were reduced 99.5 percent by the use of an ESP and a Wellman.Lord wet scrub. S'O emissions: from the coal fired boiler were reduced 95 2percent by the Wellman Lord unit. Particulate emissions from the. coal thermal dryers are based on (8301,8.9-1). These emissions are reduced 85 percent by the use of multiple cyclones and then'99 percent by a bag house before entering the atmosphere. Sulfur Recovery Plant Based on the amine and Rectisol acid gas removal systems S in (9400), the Claus plant receives a 35 Mol percent H 2 feed. From (2022,103) this-Claus unit can recover 94.6 percent of the incoming S. The incomi .ng S for recovery is based on 28696 TPD process feed coal, 0.5 percent S, and 91.4 percent of the feed S as H 2S to Claus for recovery (the balance of the S is-in the liquid fuel products (3.0 percent) and produced as by-product S (5.2 Percent)) from (9400). Based, furthermore, on complete recycle to Claus of all the SO recovered in the Wel.lman:Lord scrubbing units on ihe boiler flue gases and Claus tail- VIII-23 FTN. 0,433-9435 gases, '141.4 TPD S is the Claus feed. Thus 133.8 TPD S is ,recovered from Claus plus 8 TPD S from the iron Oxide' towers for a total of 142 TPD S or 273 ton/l.OE12 Btu. 'Since 7.6 TPD S passes to the Wellman Lor-d tailgas scrubbing unit, 0.4 TPD 5 or 0.8 TPD SO exits the stack. .2 Storage and Misc. ..,Based on .28696 TPD of process feed coal and 0.7 percent N2 in the coal and 40 percent of the N 2 as NH (9400,13), 97.5 TPD NH 3 is produced and recovered. From 18301,5.-2-2) controlled storage and loading operations emit 2 lb NH3/ton NH 3* Thus .098 TPD NH are released into the atmosphere. From (9400,13) 12300 BBL/D of naphtha are produced. Assuming 2 weeks storage capacity under new tank conditions and emission factors.from (.8302,463-8), .009 TPD HC are emitted. Conversion to tons/l.OE12 Btu is based on a total*coal throughput of 29645 TPD and 57000.ton coal/l.OE12 Btu. 9433 Based-on 28696 TPD process feed coal with 6 percent ash, 1722 TPD ash are produced. 95 percent of this is solid waste for disposal with the balance in the products or deposited on catalysts (9400,13). Based on the combustion of 949 TPD coal and .2 TPD of emitted particulates, 56.7. .TPD of solid waste is produced. Based on the assumption that H 0 requirements for this,plant can be cut in half througA theuse of air cooling, 5330 gpm net makeup H 20 would be required-' Assuming 500 ppm suspended solids in this H 20 and complete removal by lime treatment and clarification,.an additional 16 TPD of solid waste is generated. The sum total solid waste produced is thus 1698 TPDbr 3264 ton/l.OE12 Btu. 9434 Fixed land requirements are estimate d at 500 acres for coal storage, preparation, and liquefaction plant facilities,from (9401,7) and at 265 acres for evaporation ponds to handle the concentrated dissolved solids ' ' streams. Since coal liquefaction is considered.a mine- mouth activity, all solid waste (Footnote 9433) produced is assumed to be returned to the mine for burial. There is, therefore# no incremental land impact due'to solid waste produc. tion. Thus a total of 765 acres is required for a 29645 TPD coal'liquefaction operation. With a 90 percent,operating fac- tor this, is equivalent to 4.48 acre-yr/l.OE12 Btu. 9435 Capital And operating costs were developed'a,s follows: Capita 1 C.osts-1972 $-Plant Basis-29,600 TPD','90 p LF From (9400,19), escalated from 1971 $ to 1972 $ at 5 percent, costs for coal preparation, extracti on, separation, VIII-24 FTN. 9436-9437 solvent, recovery, low temperature carbonization, tar distillation, extract dyroconversion, hydroletdown and absorption, hydrodistillation, gas plant,H2 manufacture, H2 compression, and support services total 233.6E06 $. Power generation costs were estimated at 12.8E06 $ from (8323,42), ESP costs at .16E06 $ from (9402,133), Claus plant costs at 1.0E06 $ from (8303,AI-25), Wellman Lord SO2 removal costs on coal boiler flue gases at 1.9E06 $ and on Claus tailgases at 1.5E06 $ from (8303,AI-26), and H2O pollution control costs at 1.8E06 $ from (9400,102) and (2013,VII-4,VII-5). To the subtotal was added a 7 percent development contigency to arrive at a total plant investment of 270.7E06 $. Based on a FCR of 10 percent/yr and 9.74E06 TPY coal this is equivalent to 1.58E05 $/1.0E12 Btu. Operating Costs-1972 $-Plant Basis 29,600 TPD, 90 P LF From (9400,32) costs for catalyst and chemicals, raw H2O, ash disposal, maint. mat. and labor, operating labor, super., and payroll and general overhead total 22.85E06 $/yr: Operating and maintenance costs on the power boiler were estimated at .19E06 $/yr from (1918, 46), ESP costs at 5E03 $.yr from (9402,135), SGC costs on coal boiler flue gases at .49E06 $/yr and on Claus tailgases at.42E06 $/yr from (9403,18/27), and H2O pollution control costs at 45E03 $/yr from (2013,VII-4, VII-5). The total gross operating cost is thus 23.99E06 $/yr. By-products were credited at $10/LTS (126 LTS/D) and $25/T Nh3 (98 TPD NH3) from (8303,AI-5). The total net operating cost is thus 22.78E06 $/yr for 9.74E06 TPY coal input, 1.33E05 $/1.0E12 Btu. 9436 Water pollutants are zero because there is no aqueous discharge from the boundaries of the plant operation. All process waste H2O and impounded runoff is treated and used for cooling tower makeup, while all blowdown streams are collected and sent to lined evaporative ponds for disposal. 9437 From (9401,31) a plant processing 10000 TPD coal (250.8E09 Btu/D) produces 156.7E09 Btu/D of liquid fuel products for a primary efficiency of .625, Although this is for a difference coal, it is assumed that this efficiency holds as well for Northwest coal (footnote 9430) used in this analysis. Thus a total of 14235 TPD of coal is required for the production of 156.7E09 Btu/ D of liquid fuels. The total plant heat demand is 76.3E09 Btu/D which is provided for by the combustion of 70E09 Btu/D of fuel gases and 6.3E09 Btu/D or product heavy fuel oil. The ancillary energy is zero because the plant is self-sustaining with all power and stream requirements VIII-25 FTN. 9438 generated on-site. 9438 The principal quantifiable air pollution sources are as follows: TPD Part. SOx CO HC NOx Other Fuels Combustion .872 0.40 .626 .0725 22.1 .0196 Sulfur Recovery Plant 0.80 Storage and Misc .0014 .048 Fuels Combustion Based on air emissions factros in (8301,1.3,1.4-2) and the combustion of 6.25E09 Btu/D of heavy fuel oil (containing .28 percent of the S in the process feed coal from (9405,11)) and 70E09 Btu/D fuel gases (containing negligible S from (9405,11)). Particulate emissions from the coal thermal dryers are based on (8301,8.9-1). These emissions are reduced 85 percent by the use of multiple cyclones and then 99 percent by a Venturi scrub before entering the atmosphere. Sulfur Recovery Plant Bases on the amine acid gas removal system in (9405,11, 16,19,21), the Claus plant receives a 10 Mol percent H2S feed. From (8303,AI-25) this Claus unit can recover 89 percent of the incoming S. The incoming S for recovery is based on 14235 TPD process feed coal, 0.5 percent S, and 94.6 percent of the feed S as H2S to Claus for recovery (the balance of the S is in the liquid fuel products (5.4 percent) from (9405,11). Based furthermore, on complete recycle to Claus of the SO2 recovered in the Wellman Lord scrubbing unit on the Claus tailgases, 75.3 TPD S is the Claus feed. Thus 67.0 TPD S is recovered for sale or 268 ton/1.0E12 Btu. Since 8.3 TPD S passes to the Wellman Lord tailgas scrubbing unit, 0.4 TPD S or 0.8 TPD SO2 exits to the atmosphere. Storage and Misc. Based on 14235 TPD of process feed coal and 0.7 percent N2 in the coal, and the assumption that 40 percent of the N2 forms NH3 (9400,13), 48.4 TPD NH3 is produced and recovered. From (8301,5.2-2) controlled storage and loading operations emit 2 lb NH3/ton NH3. Thus .048 TPD NH3 are released into the atmosphere. From (9405,11) 2011 BBL/D of naphtha are produced. Assuming 2 weeks storage capacity under new tank conditions and emission VIII-26 -9441 TN. 9439 F factors from -8), .001 TPD,HC are emitted. 8302,4.3 Conversion to tons/l.OE12 Btu is based on a total coal throughput.of 14235 TPD and 57000 ton coal/I.OE12 Btu.' 9439 Based on 14235 TPD process feed coal with 6.0 percent ash, 854 TPD ash are produced. Based on 3626 gpm net,makeup H 0 (9401,27) and an assumed. 500 ppm suspended solids wKch is completely removed.by lime.,treatment and clarification, an additional 11 TPD of-solid waste is generated. The sum total solid waste'produced is thus .865 TPD or 3464 ton/I.OE12 Btu., 9440 Fixed land requirements are es timated at 280 acres for coal storage, preparation, and liquefaction plant facilities from' (9405,48) and at 230 acres for evaporation ponds to handle the concentrated dissolved solids streams., Since coalliquefaction is considered a mine-mouth activity, all solid waste (Footnote 9439) is assumed to b6-returned to the mine for burial. There is, therefore, no incremental land impact due to solid waste production. Thtis a total of. 510 acres,is.required for a.14235.TPD.co.al.l,iquefaction operation. With a 90 percent operating factor this is equivalent to 6.22 acre-yr/l..OE12 Btu. 9441. Capital and operating costs were developed as follows: Capital Costs-1972 $-Plant Basis-14,*200 TPD, 90 P. LF From '(9401,57), de-escalated from 1973 to 1972*$ at 5 percent, costs for.coai preparation, coal slurrying and pumping', coal liquefaction'and fi.itration,.dissolver acid gas removal, coal liquefaction product distillation,. fuel oil hydrogenation', naphtha hydrogenation, fuel gas sulfur removal, gasification, acid gas removal, shift conversion?'CO removal, methanation,.O plant, 2 2' instrument and plant air,. raw H 20 treatment, process waste H 2O,treatmqnt, power generation, product storage, slag removal system steam generation, general facilities, and home office engineering total 207EO6 $. Claus plant costs were estimated at .87EO6 $ from (8303F-AI-25), Wellman Lord.SO removal costs on Claus tailgases at 2.OE06 $ from (h03,AI-2'6), carbon absorption for waste. *water costs at .25EO6 $ from (2013,VI,I-4.), and a Venturi for particulate removal on the thermal dryer at AOE06 $ from (1080,64).,The total plant investment is thus 210.5EP6 $.-Based on a FCR of 10 percent/yr and 4.68EO6@ _TPY'.coal this is equivalent to@2.56EO5@$/I.OE12 Btu. VIII-27 FTN.9442-9448@@ 't @TPD, 90 P LF, Operaing,Costs-1972 $-Plant Basis-14,200' From (9406) the preliminary estimated operating costs are 50E06 $/yr basedon $9/ton coal. Assuming a .90 percent operating factor this wouldgive 29.6EO6 $/yr for coal cost and 20AE06 $/yr-'for other operating expenses. Based on 20AE06 $/yr and 4.68EO6 TPY.coal this becomes 2.48EO5 $/l.OE12 Btu. 9442 Water pollutants are zero because there is.no aqueous discharge from the boundaries of the plant operation. All process waste H 0 and impounded runoff is treated 2 and used for cooling tower makeup, while all blowdown streams are.collected and sent to lined evaporative ponds for disposal. Based on the use of'100.T truck capacity and an average haulage distance from mine to tipple of 1.5 miles'(0001, 344),* The fuel consumption rate is assumed to be 7 gal/ 1000 TMI (0002,3-7) and the-gross-to tare weight ratio of the trucks'is assumed to be 2-.5 to 1. Based on 57000 ton coal/l.OE12 Btu, 570 round trips are required to deliver 1.OE12 Btu. From footnotes 9433 and 9439 the liquefaction plant produces an average of 3360 T solid waste, so that 5.@9 T of solid waste/return trip goes ..back to the-mine. Thus a round trip,is 359 ton miles and 1432 gal of diesel fuel are.consumed/l.OE12 Btu. Emissions from a,diesel powered truck ate given in -0092,3-7). Dusting from haulage roads is controlled by.watering !down, oiling, or some other method. 9444 Fuel consumption by the haulage trucks amounts to 1432, gal diesel fuel/l.OE12'Btu (footnote 9443). For 5 '.83EO6 Btu/BBL diesel fuel this is equivalent.to 1.99EOB,Btu/ 1.OE12 Btu. The primary efficiehdy'and ancillary energy for this process are the arithmetic'average of the primary efficiency and ancillary energy for the Northern Appalachian, Central, and Northwest regions. 9446 Air pollutants for this process are.the arithmetic averIage of the air pollutants f or the Northern Appalachian, Central, and Northwest regions. 9447 Solid waste for this process is the.akithmetic average of the solid waste produced in'the Northern Appalachian, Central, and Northwest regions. 9448 Land utilized by this process is the arithmetic average of the land used in the Northern Appalachian,.Central, and Northwest regions.,, VIII-28 FTN. 9449-9455 9449 Capital and operating costs for this process are the arithmetic average of the capital.and operating costs for the Northern Appalachian, Central, and-Northwest regions. 9450 Water pollutants for this process a 're the arithmetic average of the water pollutants for the Northern Appalachian, Central, and Northwest.regions.- 9451, Thermal discharges for this process are the,arithmetic average of thermal discharges for the Northern Appalachian, Central, and Northwest regions. 9452, From footnote 1046 the capital cost of.transportation equipment for a,2E.06 TPY mine is 1.123EO6 $.-Sediment runoff from coal haulage roads can be controlled bv the use of small, settling ponds at a cost. of $20000/pond (Footnote 1135). Assuming that a settling pond is requirea tor each mile of road, 1 settlinq pond is required.-Thus the total'capital cost is, 1.14EO6 $ or 1.14EO5 $/yr at 10 'percent FqR. Based.on a 2EO6 TPY coal operation and 57000.T/1.OE12 Btu ,this is equivalent to 3250 $/l.OE12 Btu. The operating costs is taken as $3175,80/yr from footnote 1046. Thus for a 2E.06 TPY coal ope'ration.and 57000 T/1.OE12,Btu this is equivalent to 9051 $/l.OE12 Btu.. 9453 From footnote 1046 the capital cost for transportatio n equipment for a 2EO6 TPY mine is 1.12EO6 $. Sediment, runoff from coal haulage roads can be controlled by the use of settling ponds at a cost of $20000/pond (Footnote 1135). Assuming that.a settling pond is required tor each mile of road, 7 -settling Ponds are required. Thus-the total capital cost is 1.26EO6 $ or 1.26EO5 $/yr at 1 '0 percent, FCR. Based on a 2EO6 TPY coal 'operation-and 41700 T/ 1.OE12 Btu this is equivalent to 2630 $/l,.OE12 Btu. The operating cost is taken as $317580/yr from footnote 1046. Thus for a 2EO6 TPY coal operation and 41,700 T/l.OE12 Btu this is equivalent to 6622 $/l.OE12 Btu. 9454. Fuel consumption by..the haulage trucks amounts to 3'003 gal diesel fuel/l.OE12 Btu (footnote 94-14). For 5.83EO6 Btu/BBL diesel fuel this is equivalent to'4.17EO8 Btu/ 1.OE12 Btu. 9455 From footnote 1046 the capital cost for,transportation' equipment for a 2EO6 TPY mine is 1.12EO6 $. Sediment ' runoff from coal haulage roads can be controlled bv the use' of small settling ponds at a cost of $20000/pond (Footnote .1135). Assuming that a settling pond is required for each mile of road, 4 settling. ponds are required. Thus.the total capital cost, is 1.20EO6 $ -or 120 E05 $/yr at 10 percent FCR. Based on a 2EO6 TPY coal operation and 4620.6 VIII-29 FTN. 9456-94,60 T/l-OE12 Btu this is equiv alent to 2770 OE12 Btu. rating-cost is taken as $317580/yr from footnote The ope, 1046. Thus for a 2EO6 TPY coal operation and 46200 T/ 1.OE12 Btu this is equivalent to.7336 $/l.OE12 Btu. 9456 An arithmetic average of the CSF.and SRC processes for the National Average case. 9457 @.An arithmetic average oftransportation numbers for the Northern Appalachian, Central, and Northwest regions. 9458 An arithmetic average of the CSF and SRC processes for the Northwest region. 9459 An arithmetic average of the CSF and SRC process for the Central@region. 9460 An arithmetic average of the CSF 'and SRC processes for the Northern Appalachian-rdgion. VIII-3.0 IX. REFERENCES REFERENCES FROM VOLUME I 0001 Minerals Yearbrook-1969, U.S. Department of the Interior, Bureua of Mines, 1971. 0002 "Compilation of Air Pollutant Factors," Environmental Protection Agency, Research Triangle Park, North Carolina, February 1972. 0005 "Crude Petroleum, Petroleum Products, and Natural Gas Liquids-1971," Min. Ind. Surv., USDI Bu Mines, December 20, 1972. 0011 "Statistical Abstract of the US-1972," Bu Census, Washington, DC 1972. 0012 "Environmental Conservation, The Oil and Gas Indus- tries-Vol. One," Natl. Petr. Coun., June 1971. 0035 "Annual Summary of Disabling Work Injuries in the Petroleum Industry for 1971,"API, Washington, D.C., April 1972. 1080 Jones, L.G., "Section Vi-Economics of Emission Control Systems," an unpublished draft report, Environmental Protection Agency, Research Triangle Park, North Carolina, 1972. 1100 Grim, E. (Environmental Protection Agency, Cincinnati), Personal Communication, June 1973. 1119 "Interim Effluent Limitations Guidance and Technical Documentation for the Steel Industry", Office of Permit Programs, EPA, Washington, D.C., March 1973. 1121 "Technical Report on the Coal Preparation Industry", A draft report, Environmental Protection Agency, Research Triangle Park, North Carolina, 1972. 1900 Aynsley, Eric and Meryl R. Jackson, "Industrial Waste Studies-Steam Generating Plants", an unpublished study in draft form prepared for The Environmental Protection Agency, Water Quality Office, May 1971. 1906 Olmstead, Leonard M., "17th Annual Steam Station Cost Survey", Electrical World, November 1, 1971. 1907 National Safety Council, Accident Facts - 1971 Edition, N.S.C., Chicago, 1971. 1913 Federal Power Commission, The 1970 National Power Survey - Part I, U.S.G.P.O., Washington, D.C., 1972. XI-1 191.5 "Hydroelectric-@PowEir 'Evaluation, Supplement No. 1".. Washington, D.'C., G.P.O., 1917 Feaeral Power-Commission, Bureau of Power, "Feb. 1973 Monthly Report Of Cost and Quality of Fuels for Steam Electric Plant," Washington,'.D.C. FPC. 1918 "17th,Steam S tation Cost Survey", Electrical Worldf Nov. 1,-.1971. 1919 Federal Power Commission, "Problems in Disposal of Waste Heat from Steam-Electric Plant",. Staff Study Supporting 1970 National Power.Survey. 1920 "'Possible Impact '.of Costs of Selected Pollution Control Equipment on the Electric Utility Industry & Certain Power'Intensive Consumer Industries", Nera 1972.' 2001 "Crude Oil and Refined Products.Pipeline Mileag i e in the U;S.-Jan. 1971," Mineral Industry Survey, 'U.S. ,Bureau of.Mines, Dec. 3, 1971. 2002 :"A Primer of Pipeline Construction," Petroleum Extension Service and Pipeline Contractors Association, Austin, Texas', 1966. 2003 "Environmental Conservation-The Oil-and Gas-Industries- Volume Two," National Petroleum Council, Feb. 1972. 2013, "Petroleum Refining Guidelines and Technical Documentation", Office of Permit Programs, EPA, Washington, D.C., March 7, 1973. 2022 H@dr6carbon Proce-ssinE. Volume 51, No. 4, April 1972,,,Gulf Publishing Co.,, houston, Texas. IX-2 REFERENCES FOR LOW BTU GASIFICATIQN @8000. Agosta, J. Illiant H.F., Lundberg, R.m. and Tranby, O.G., "Status of Low Btu Gas as a Strategy for Power Station Emission Control", Am.Ins.Chem.Eng. 65th Annual Meeting, Nov. 1972. 8001. Jain, L.K., and Hixson, T.J., "Applicability Study, Coal Gasification Process", Catalytic, Inc., Contract No. 68-02-0241 EPA March 1972. 8002. U.S. Dept. Int., "OCR 1973 Annual Report: Clean Energy From Coal - A National. Priority", Calendar year 1972, GPO Wash DC Feb 1973, pg. 37-42. 8003 Air Products and Chemicals, Inc., "Sulfur.Removal from Low-Btu Gas Using A Fixed Hot Bed of Dolomite", OCR 1973 Annual Report: Clean Energy from*.Coal - A National Priority,.Calendar year 1972, GPO Wash DC Feb 1973, pg. 37-38. 8004 Lemezis, S. and Archer, D.H., "Coal Gasification for Electrical Power Generation", Westinghouse Eng., Vol. 33 No. 4, July 1973. 8005 Hottel, H.C. and Howard, J.B., New Energy Technology Some Facts and Assessments, The MIT Press, 1971, pg. 144-161. 8006 Leonard, J.W. and,Mitchell, D.R., Coal Preparation AIME, The Seeley.W. Mudd Series, New York 1968. 8007 Mills, G.A., Gas From@Coal Fuel of the Future, Environmental Science and Technoloay, Vol. 5, 12, Dec. 1971. 8008 Shurr, Sam-H., Energy Research Needs,-Section on "Production of Zflean Low-Btu Gas from Coal", RFF Inc., Wash DC, Oct 1971, pg. V29-V49. 8009 Wen, C.Y., "Optimization of Coal Gasification Processes" Dept. Chem. Eng. WVU, prepared for OCR US Dept. Int., Research and Development Report No. 66, Interim Report' No. 2, Contract No. 14-01-0001-497, Wash DC. 8010 Katell, S., Lewis, P.S. and Wellman, P.,'"'The Economics of Producing Gas at Atmospheric and Elevated Pressures", presented at the American Assoc.' of Cost Eng. Annual Meeting, St. Louis,'Mo., June 18-20# 1973. 8011 Final Report, "The Supply-Technical Advisory Task- Fo rcerSynthetic Gas-poal", prepared by Synthetic Gas- Coal Task Force for Supply-Technical Advisory Comm., NGS, FPC, April 1973. IX-3 8012 "Application of El Paso Natural Gas Co. At Docket No. CP73-131 for a Certificate of Public Convenience and Necessity", filed before the Federal Power Commission, Nov 15, 1972, pursuant to Section 7 (c) of the Natural Gas Act, Vol. I, Vol II, Vol. III, El Paso Gas Co., Nov 7, 1972. 8013 Robson, F.L., et al., "Technological and Economic Feasibility of Advanced Power Cycles and Methods of Producing Nonpolluting Fuels for Utility Power Stations", United Aircraft Res. Lab., prepared for NAPCA, USDHEW, Durha, N.C., Dec 1970. 8014 Lewis, P.S., Liberatore, A.J., and McGee, J.P., Strongly Caking Coal Gasified in a Stirred-Bed Producer, US Bur. of Mines, RI 7644, US Dept. Int., Bur. Mines, Wash. DC 1972. 8015 Applies Tech, Corp. "SO2 Free Two-State Coal Combustion Process", EPA-R2-72-035, for EPA, August 1972. 8016 Personal Communication with Morgantown Energy Research Center, Morgantown, W.V., Sept. 1973. 8017 Gas Generator Research and Development - Phase II - "Process and Equipment Development", OCR R&D Report No. 20 - Final Report by Bitum. Coal Res., 1970. 8018 Karnavas, J.A., and Larosa, P.J. and Pelczarski, E.A., Two-Stage Coal Combustion Process, Chem. Eng. Progress, Vol. 69, No. 3, March 1973, pp. 54-55. 8019 Karnavas, J. A., Larosa, P.J., and Pelczarski, E.A., Atgas-Molten Iron Coal Gasification, Applied Technology Corp, presented at 1972 AGA Synthetic Pipeline Gas Symp., Chicago, Ill., October 30, 1972. 8020 Lurgi Quick Information )0 1007/10.71), "Clean Fuel Gas from Coal", Lurgi Mineraloltechnik GMBH, Fuel Technology Division, obtained Aug. 1973 from American Lurgi Corp, 5 East 42nd Street, New York, N.Y. 10017. 8021 Lurgi Quick Information (0 1008/10/71), "New Fossil- Fueled Power Plant Process Based on Lurgi Pressure Gasification of Coal", Paul F.H. Rudolph, Lurgi Gesellschaft Fur Warme-Und Chemo-Technik MBH, paper presented by Joint Conference of the Chem. Institute of Canada with Amer. Chem. Soc. 25th Annual Conf., May 26, 1970. 8022 Applied Tech. Corp., "SO2 Free Two-State Combustion Process", Phase II, draft report to EPA, Appendix to EPA-R2-72-035. IX-4 @8023 Kop ers Eng.-andCo., Confidential Information p Supplied on "Pollution Aspects of Coal Gasification", Sept. 24, 1973., 8024. Farnsworth, F.J., Leonard, H.F., Mitsak, D.M., and Wintrell, R., The Production of Gas from Coal Through A Commercially Proven Process, Koppers Co.,,Inc., Aug 1973. .8025 Personal Communication with Paul J. Larosa, Director R&D, Applied Technology Corp..,,Pittsburgh, Pa.? 10/8/73. 8026 The Pennsylvania State Universityi College of Earth and Mineral Sciences, Coal Research Section, Proximate and Ultimate Analysis of Various U.S. Coals", Collected and analyzed under contract to OCR, Wash DC 1973. 8027 Sullivan, D.A.,. "Design-Considerations for Low-Btu Fuels", SOA-10-73 paper presented at the l8th GE Gas Turbine State of-theArt-Engineering Seminar, June 11, 12, 13,1973.. 8028 General Electric Company, Gas Turbine Products. Division, "Gas Turbine Environmental Factors, GER. 2486B", Schenectady, New York 1572.. 8029 ATC Two-Stage Combustor, Design Calculations, Applied Technology Corp., Pittsburgh, Pa., 1973. 8030 "Design Calculations of BOM-Atmospheric.and BOM-Pressurized Systems", supplied by BOM Morgantown Research Center, Morgantown, West Virginia, Sept,1973. 8031 Second Supplement to"'Application of-El Paso Natural Gas,Company for a-Certificate of Public Convenience and Necessity", Docket No. CP73-1314 El Pas 'o Natural Gas'Company, October 8, 1973,,Filed : October 9.01 1973. 8032 Personal Communication with Paul Lewis'of the BOM'' Research Center, Morgantown,, West Virginiao" Dec..1973. 8033 "The @1970 NationalPower Survey , Federal'Power Commission, Part ll", The Federal Power Commission-#, GPO,,Wash DC, Dec 1971.. 8034 Carlson,.H.A., The Stag Cycle, USOA-4-72, paper given at the GE State of the Art Seminar.on. Electric utility Gas Turbine,Applications, Sept 24-27, 1972. 8035, Technical Report,on "The Coal Preparation Industry", a draft report,EnvironImental Protection Agency, Research Triangle Park, 1972. REFERENCES FOR HIGH BTU GASIFICATION 8300 "FPC National Gas Survey-Synthetic Gas-Coal Section", April, 1973 (FPC Files). 8301 --"Compilation of Air Pollutant Emission Factors" (Second Edition). EPA, Research Triangle Park, North Carolina, April 1973. 8302 "Supplement No@,Ifor Compilation of Air Pollutant Emission Factors,'!,., Second Edition, EPA, Research Triangle Park, North Carolina, July 1973.. 8303 "Final Report - The Supply-Technical Advisory Task- Force-Syhthetic Gas-Coal", Federal Power Commission ,National,'Gas Survey., April 197-3. 8304 "An Econ 6mic Evaluation of Waste Water Treatment for a 250 MM SCFD.Synthane Plant", Report No. 73-22, Bureau of Mines, April 1973. 8305@ "Engineering Study and Technical Evaluation of the Bituminous Coal Research, Inc., Two*-Stage Super Pressurd.Gasification Process'" Research and Development Report No. 60, Office of Coal'Research,, Department of the Interior, Washington, D.C. 8306 Metcalff J. (Stearns-Roger,Inc. Denver, Colorado),' Personal@Com'munication, October 1973. 8307 "Pollution Aspects of the Synthane Process", Bureau of -Mines, Technical.Progress Report, U.S. Department of the Interior. 8308 Schora, F.C., and C.W. Matthews, "Analysis of a Hygas Coal Gasification Plant Design", paper presented at AIChE 65th Annual Meeting, New'York, Nov. 27"30 1972. 8309 Katell,"S., P. Wellman, and W. Morel, "An Economic Evaluation of Synthane Gasification for the Production of Pipeline Gas from Coal", Process Evaluation Group, Bureau of Mines, Morgantown, West Virginia. .8310 "El,Paso.Na'tural Gas.Co. - Second Supplementto Application of El Paso Natural Gas Co. for a Certificate of Public Convenien ceIand Necessity",' October 9,* 1973. 8311 'iDetailed Envik-ohmdnta 1 Analysis Concerning a Proposed Coal Gasification Plant for Transwestern Coal Gasificati.on,,,Co--,',.,Pacific Coal Gasification Co., and. Western Gasification Co.", submitted before the Federal Power Commission, "February 1, 1973. IX-6 8312 Kostenba .der, P.D., and J.W. Flecksteiners" IlBiological Oxidation of Coke Plant Weak Ammonia Liquor", Journal Water Pollution Control Federation, Vol. 41, Nbo 2, Part 1, FeEruary 1969. 8313 Cousins, W.G. and A'B. Mindler, Tertiary Treatment of Weak Ammonia Liquor., Journal Water Pollution-Control Federation, Vol. 44, No. 4, April 1972. 8314 Forney, A. (Bureau of Mines,- Pittsburgh,,Pa.), Personal Communication, September 1973. 8315 Hertwig, W., .(Amoco,Oil Co.,.Whitingj Indiana) Personal Communication, October 18, 1973. 8316 Pattersong,,J.W..11 et al., "Wastewater Treatment Technology", National Technical Information Service PB204521, August 1971. Porterp J.W.p et al., "Zero Discharge of Wastewater from Petroleum Refineries", National Conference on Complete Water Reuse, Washington, D.C., April 1573. 8318 "Petroleum,Refining Effluent Guidelines", A draft report @Programs by,Roy'F. Weston for EPA,Office.of Water' Washington, D.C., September-1, 1971. 8319 "Transwestern Coal Gasification Co.., Pacific Coal G*asification Co.,.'Western Gasification Co., Joint Application for Certificate 'of Public Convenience and Necessity", Filed with.the Federal,Power Commission, February 1, 1973.1 8320 "Volumes I, II, III' 'Application of El Paso Natural Gas Co. at Docket@No. CP73-131 for,a Certificate of Public Convenience and-Necessity filed with the Federal Power .Commission, November 15, 1972. 8321. Ellington, E.E., et al.,' "Phase III and Phase IV-A Design and Construction of the CSG Pilot Plant", R and D Report No. 16-Interim Report No. 5" Office of Coal Research, Washington, D.C. 8322 Wurm, Hans J., "The Treatment of Phenolic Wastes .23rd Industrial Waste Con'ferdnce-Part Two, Purdue University, 1968. 8323 Roe, Kenneth A., And William H. Young" "Trendd@In Capital Costs of Generating Plants", Power Engineering, June 1972. 8324 Chemical Engineerin2 Progress, Vol. 690, No. 3, March 11973, 3 7. IX-7 REFERENCES FOR OIL SHALE 9000 "Final Environmental Statement for the Prototype Oil Shale Leasing Program, USDI, Volume I and III, 1973. 9001 Schurr, Sam H., "Energy Research Needs," Resources for the Future, Inc., NTIS, Washington D.C. 9002 "Report on Economics of Environmental Protection for the Federal Oil Shale Leasing Program," State of Colorado, January 1971. 9003 "Petroleum Facts and Figures," American Petroleum Institute, 1971. 9004 Weichman, B. E., "Oil Shale, Coal, and the Energy Crisis," Chemical Engineering Progress, Volume 69, No. 5, May 1973. 9005 "Water Use in the Petroleum and Natural Gas Industries," BOM, USDI, 1966. 9006 East, J.H., JR., E.D. Gardner, "Oil Shale Mining," Rifle, Colorado, 1944-56, Bulletin 611, USDI, 1964. 9007 Katell, Sidney, Paul Wellman, "Mining and Conversion of Oil Shale in a Gas Combustion Retort," BOM Technical Progress Report No. 44, USDI, October 1971. 9008 Burwell, E.L., H.C. Carpenter, and H.W. Sohns, "Experimental IN SITU Retorting of Oil Shale at Rock Springs, Wyoming," BOM Technical Progress Report #16, USDI, June 1969. 9009 "Water Pollution Potential of Spent Oil Shale Residues," U.S. Environmental Protection Agency, December 1971. 9010 "Compilation of Air Pollutant Emission Factors," U.S. Environmental Protection Agency, Research Triangle Park, North Carolina, February 1972. 9011 Burwell, E.L., T.E. Sterner, and H.C. Carpenter, "In Situ Retorting of Oil Shale, "USDI, Report of Investigations 7783, 1973. 9012 Ruark, J.R., H.W. Sohns, H.C. Carpenter, "Gas Combustion Retorting of Oil Shale Under the Anvil Points Lease Agreement: Stage II," USDI, Report of Investigations 7540, July 1971 IX-8 9013 "Hydrocarbons form Oil Shale, Oil Sands, and Coal," AICHE Series 54, Volume 61, 1965. 9014 Wise, R.L., R.C. Miller, and H.W. Sohns, "Heat Contents of Some Green River Oil Shales," USDI, Report of Investigations 7482, March 1971. 9015 "Cost of Clean Water," Volume III, Industrial Waste Profile No. 5, Petroleum Refining, FWPCA, USDI, November 1967. 9016 Pfleider, Eugene P., "Surface Mining," The American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc., New York 1968 9017 Ward, J.C., G.A. Margheim, G.O.G. Lof, "Water Pollution Potential of Spent Oil Shale Residues From Aboveground Retorting," American Chemical Society, Division of Fuel Chemistry, Volume 15, No. 1, March 29- April 2, 1971. 9018 Hubbard, Arnold B., "Method for Reclaiming Waste Water from Oil Shale Processing," American Chemical Society, Division of Fuel Chemistry, Volume 15, No. 1, March 29- April 2, 1971. 9019 "Hydrocarbon Processing," Volume 51, No. 9, Gulf Publishing Company, Houston, Texas, September 1972. 9020 Carnes, Billy A., Davis L. Ford, and Sidney G. Brady, "Treatment of Refinery Wastewaters for Reuse," Presented at the National Conference of Complete Water Reuse, Washington, D.C., April, 1973. 9021 Hydrocarbon Processing, Volume 49, No. 9, Gulf Publishing Company, Houston, Texas, September 1970. 9022 Nelson, N.C., "Guide to Refinery Operating Cost," Petroleum Publication Company. Tulsa, Oklahoma, June 1970. 9023 Hutchins, John S., Warren W. Krech, and Max W. Legatski, "The Environmental Aspects of a Commercial Oil Shale Operation, " Paper Number EQC25, American Institute of Mining, Metallurgical, and Petroleum Engineers, New York, New York, 1971. IX-9 9024 Oil and Gas Journal Volume 69, No. 25, Petroleum Publishing Company, Tulsa, Oklahoma, June 21, 1971. 9025 "Oil Shale-A Stateside Answer to the Petroleum Shortage," Mining Engineering, Society of Mining Engineers of AIME, October 1972. 9026 Aires, Robert S., and Robert S. Newton, "Chemical Engineering Cost Estimating, "McGraw-Hill, New York, New York 1955. 9027 "An Economic Evaluation Using 30 Gal/Ton Shale and Producing 50,000 BBL per Calendar Day of Shale Oil," Report NO. 74-13, Process Evaluation Group, Bureau of Mines, USDI, Morgantown, West Virginia, Publication Expected April 1974. 9028 "Impact on Air Quality from Oil Shale Development, Engineering-Science, Inc., McLean, Virginia, January 1973. 9029 "Cost Analyses of Model Mines for Strip Mining of Coal in the United States," BOM Information Circular IC 8535, USDI, 1972. 9030 "Annual Summary of Disabling Work Injuries in the Petroleum Industry for 1971," API Washington, D.C., 1972. 9031 Prine, Charles H., John J. Schanz, Jr., and Richard K. Doran, "Profile of Development of an Oil Shale Industry in Colorado," Working Paper #2, University of Denver Research Institute, February 1973. 9032 Obert, Edward F., Internal Combustion Engines, Inter- national Textbook Company, Scranton, Pennsylvania, November 1956. 9033 Personal Communication with Mr. F. D. Dietiker, Letter dated 12/13/73, Barber-Green Company, Aurora, Illinois. 9034 Rice, R.A., "System Energy as a Factor in Considering Future Transportation," ASME Paper 70-WA/Ener 8, 1971. 9035 "Energy Research Needs," Resources for the Future, Inc., Prepared for the National Science Foundation, Contract NSF-C644, October 1971. IX-10 9036 "Cost of Process Equipment," Chemical Engineering, McGraw-Hill, March 16, 1964. 9037 Nelson, W.L., "Latest Research Indexes and Pro- ductivities," Oil and Gas Journal, January 1974. 9038 Hydrocarbon Processing, Volume 51, No. 10, October 1972, Gulf Publishing Company, Houston, Texas, pp. 97-99. 9039 Hydrocarbon Processing, Volume 51, No. 4, April 1972, Gulf Publishing Company, Houston, Texas, pp. 102-106. 9040 "Petroleum Refining Guidelines and Technical Documentation," Office of Permit Programs, EPA, Washington, D.C., March 7, 1973. 9041 Fryling, G.R., Combustion Engineering, The Riverside Press, Cambridge, Massachusetts, 1966, 19-6. IX-11 REFERENCES FOR FLUIDIZED BED COMBUSTION 9200 Keairns, D.L., "Design of a Pressurized Fluidized Bed Boiler Power Plant," AICHE Symposium Series, NO. 126, Vol. 68, 1972. 9201 Aynsley, Eric and Meryl R. Jackson, "Industrial Waste Studies-Steam Generating Plants," an unpublished study in draft form prepared for The Environmental Protection Agency, Water Quality Office, May 1971. 9203 Archer, D.H., "Evaluation of the Fluidized Bed Combustion Process, Vol. III, " Westinghouse Research Laboratories, Nov. 1971. 9205 Personal communication from Mr. P. Turner, Environmental Protection Agency, Durham, North Carolina, January 1974. 9206 Hammons, G.A., et al., "Studies of NOx and SOx Control Techniques in a Regenerative Limestone Fluidized Bed Coal Combustion process," Esso Research and Eng. Co., Interim Report to Division of Process Control Eng., Office of Air Programs, EPA, for period January 1, 1971- June 1, 1971. 9207 "Evaluation of the Fluidized Bed Combustioin Process. Vol. I Summary Report," Submitted to Office of Air Programs, EPA, by Westinghouse Research Labs, Pittsburgh, Pennsylvania, for period November 15, 1969-November 15, 1971. 9208 "Economic Indicators," Chemical Engineering, Vol. 81, No. 1, January 7, 1974, P. 162. 9209 "Possible Impact of Costs of Selected Pollution Control Equipment on the Electric Utility Industry and Certain Power Intensive Consumer Industries," NERA, 1972. 9210 "Development of Coal Fired Fluidized Bed Boilers. Final Report," Vol. II, Research and Development Report No. 36, USDOI, Office of Coal Research, February 1971- February 1972. 9211 Demski, R.J., et al., "Final Report. Bureau of Mines Test of Fluidized-Bed Combustor of Pope, Evans and Robbins," USDOI, Pittsburgh Energy Research Center, Pittsburgh, Pennsylvania, March 1973. IX-12 9212 "Fluidized Bed Boiler Cuts Pollutants," Elec. World, January 15, 1973.''.. 9'213 "Proposed Multi-Cell Fluidized Bed.Bo.i.ler.at Rivesville, West Virginia," Draft Environmental State- ment prepared by Office of Coal Research, DOI, March 1973. 9214 Personal communication from Pope, Evans and Robbins Co., Alexandria, Virginia, January 1974. 9215 Handbook of Chemistry 'and Physics,.42nd Edition, Chemical Rubber Publishing Co., Cleveland, Ohio, 19.604 9216 Adams, L.M.., et al., "Reclamation of.Acidic Coal-Mine Spoil With Flyash," R17504, USDOI, April 1971. 9217 Baumeister, S., Editor, Standard Handbook for Mechanical Engineers, 7th Edition, McGraw-HT-31 Book Co.,, New York, 1967. 9218 Personal communication.from G. Weth, office of Coal Research, Washington, D.C., March 1974. 9219 Bagnulo, A.H., et al. "Final Report, Volume 1, Development of Coal-Fired Fluidize -d Bed Boilers, Prepared for Office of Coal Rese 'arch, DOI, Washingtong D.C., June 1965-February 1970. 9220 Engineering News Record, Vol. 188, No. 26, June 29,. 1972.' 9221 U.S. Environmental Protection Agency, "Development Document for Proposed Effluent Limitations Guidelines and New Source Performance Standards for the Steam .,Electric Power Generating Point Source category," EPA 440/1-73/029, March 1974. 9222 council on Environmental Quality, "Energy,a.nd the Environment-Electric.Power," U.S. Government Printing office, August 1973. IX-13 FINED COAL REFERENCES FOR SOLVENT RE 9300 ##Economic Evaluation of a Process to Produce Ashless, Low Sulfur Fuel from Coal," R&D No. 53, Interim Report No. 1, Office of Coal R6search, June 1970. 9301 Seelye., E.E., "Design, Data Book for Civil Engineers," Vol. I, John Wiley and Son, Inc., New York 1960. 9302 "cost Of Clean Water," Volume III, Indust;rial Waste Profile No. 5, Petroleum Refinin' USDI, November 9! 1@67. 9303 "Compilation of Air Pollutant Emission Factors," USEPA, Research Triangle Park, North Carolina, February 1972. 9.304 Wurm, Hans*J.., "Treatment of Phenolic Waste," @presented at 23kd Industrial Waste.Conf.erence, Part Two, Purdue University, 1968. 9305 Gas Engineers Handbook, Industrial Press, Inc., New York,-New York,,1969. 9306 "Hydrogen Plants," The Oil and Gas Journal, Vol. 69 No.. 25, June .21, 1971. 9,307 Nelson, W@.L., "Guide to Refinery Operating Cost,", The Petroleum Publishing Company, Tulsa, Oklahoma, .1970. 93 0 8 Bryant, H.S., ",Environment," The Oil and,Gas Journal, March 2:6, 1973.- .93.09 "Gases, Solids, Liquids," Power Magazine, June 1971. Perry, R.H., Cecil H. Chelton, Chemical-Engineers Handbook, Fifth Edition,.McGraw_-_H=i 'Book Companyt New-York, 1973. 9311 Klett, Robert, "Treat 'Sour,Water for Profit, Hydrocarbon Processing, October 1972. 9312 Pfleid er, E.P., Surface Mining, American Society of Mining, Metallurgical, and Petroleum Engineers, Inc., New York, 1968, Reprinted 1.9.72, Maple..Prbss, York, Pa. ix-14 9313 Environmental Studies Institute, Carnegie-Mellon Institute, Sub-Contract No. 7, Pittsburgh and Midway Coal Mining Co., "Solvent Refined Coal," November 1, 1973. 9314 Minerals Yearbook-1969, USDI, Bureau of Mines, 1971. 9315 Westerstrom, Leonard, US Bureau of Mines, Personal Communication, February 1973. 9316 Bureau of Mines, "Cost Analysis of Model Mines for Strip Mining of Coal in US," USDI, IC8535, 1972. 9317 Carnes, Billy A., D.L. Ford, Sidney O. Brady, "Treatment of Refinery Wastewaters for Reuse," Paper presented at National Conference for Complete Water Reuse, AICHE, April 23-27, 1973. 9318 "FPC National Gas Survey-Synthetic Gas-Coal Section," April 1973. 9319 "Take Sulfur out of Waste Gases," Hydrocarbon Processing, October 1972. 9320 Glover, T.O., M.E. Hinkle, and H.L. Riley, "Unit Train Transportation of Coal," USDI, Bur. of Mines, IC 8444, 1970. 9321 "Statistical Abstract of the US-1972," Bureau of Census, Washington D.C., 1972. 9322 "Accident Bulletin No. 140, Summary and Analysis of Accidents on Railroads in the US-1971," DOT, Federal RR Admin., Washington D.C. 1972. 9323 "Bur of Accounts, Railroads, Trans. Statistics in The U.S.," 1971 ICC, 1972. 9324 "Mineral Industry Surveys, Coal-Bituminous and Lignite in 1971," USDI Bur. of Mines, September 1972. 9325 Unpublished US Coast Guard data obtained from John Milton, USCG. 9326 "Bituminous Coal Facts, 1968," National Coal Association, 1968. IX-15 9327 Bur of Accou nts, "Carriers@by Water, Trans. Statistics in the U.S.," 1971, ICC, 1972. 9328, Fulkerson, F.B., "Transportation-of Mineral Composites on Inland Waterways of SoUth-Central States," USDI,@Bur@. of Mines., IC 8431, 1969. 9329 Aynsley j, Eric, and Meryl R. Jackson, "Industrial' Waste Studies-Steam Generating Plants," An unpublished study in draft form prepared for the 'Environmental Protection Agency, Water Quality Office, May@_1971. 9330 Olmstead, Leonard M., "17th:Arinual Steam Station. Cost Survey," Electrical World, November 1, 1971. 9331 "National Safety CouncilY Accident Facts-1971 Edition,." N.S.C., Chicago, 1971... .9332 'Office of"'Science.and Technology, Energy Policy Staff, "Considerations Eff'ecting Steam Power Plant Site'Selection," USGPO, Washington, D.C., 1968. 9333 Delson, J4rome K. and Richard J. Frankel, "Residuals Management in the Coal Energy Industry," A soon to be 'Published study by Resources'for,the Future, Inc., Washington, D.C. 9334 "Demonstration Plant, Clean Boiler Fuels from Coal, Preliminary Design and Capital Cost Estimate, R and* D Report No..82-Interim Report No. 1, Volume I, OCR, USi)l,,Sept. 1973. 9335 "Summary of'National Transportation Statistics," DOT, Washington D.C., 1972. REFERENCES FOR COAL LIQUEFACTION 9400 "Engineering Evaluation and Review of Consol Synthetic Fuel Process," Research and Development Report No. 70, Office of Coal Research, Department of the Interior, Washington, D.C. 9401 IoDemonstration Plant Clean. Boiler Fuels From Coal-Prelimi- nary Design/Capital Cost Estimate," Research and Develop- ment Report No. 82-Interim'Report N6.-1-Volume 1, office of Coal Research, Department of the-Interiol,r, Washington, D.C., 9402 Con trol of Air Pollution From Fossi 1 Fuel.-Fired Steam Generators Greater Than 250 Million Btu Per Hour Heat Input," U.S. Environmental Protection Agency, Durham, A North Carolina. 9403 Burchard, John K, et al,'"Some General -Economic Con.si- derations of Flue Gas Scrubbing for Utilities," Control Systems Division, Environmental Protection Agency, ..Research Triaiigle Park, North Carolina. 9404 "Final Environmental.Statement-Proposed Process' and Equip- ment Revisions to the Synthetic Fuels Process Pilot Plant, Cresap, West Virginia," office of Coal Research, Department of the.Interior, Washington,.D.C. 9405' "Demonstration Plant Clean Boiler Fuels From Coal-Pre- liminary Design/Capital Cost Estimate.," Research and Development Report No. 82-Interim Report No. 1-Vol. II, office of Coal Research, Department, of the Interior,. Washington, D.C., 9406 O'Hara, 'James (The,Ralph M. Pa rsons.Co.,'Los Angeles, California),, Personal Communication, April 1974. IX-17 APPENDIX A LIST OF ABBREVIATIONS A-1 APPENDIX A LIST OF ABBREVIATIONS Ash A AC Acre A/C Air Conditioner ALD Aldehydes AMNT Amount AV Average BAAPCD San Francisco Bay Area Air Pollution Control District BADCT Best Available Demonstrated Control Technology BBL. Barrel(s) BCF Billion Cubic Feet (Standard) BOD Biological Oxygen Demand BPH' Barrels per Hour BPSD Barrels per Stream Day BPY Bartels per Year BTU, British Thermal Unit BTUH BTU per Hour B-T-X Benzene Toluene Xylene C Cents CO Carbon Monoxide- CAP Capacity CD Calendar Day CF Cubic Feet CNISCN Cyanide and Thiocyanates CY Cubic Yard D Day DIST or DSTL Distillate DOT Department of Transportation DS Dissolved Solids .DSCF Dry Standard Cubit Feet DSCFM Dry Standard Cubic Feet per. Minute DWT Deadweight E Equivalent ELECT Electricity EPA Environmental Protection Agency ESP Electrostatic Precipitator F Fahrenheit FC Fixed Carbon FCR Fixed Charge Rate' FF and following pages . . . FT Foot (Feet) Fps. Feet Per Sejo*nd' GAL Gallon ,GAS Natural Gas @rGASO Gasoline. GM Gram .GPD Gallons per Day A-2 GPM Gallons per Minute G.k Grains HEW U.S. Department of Health, Education and Welfare HP Horsepower Hour IN Inch KW Kilowatt KWH Kilowatt Hour (Electrical) L Liter LB Pound LF Load Factor LIRR Long Island Railroad LNG Liquefied.Natural Gas LPG Liquefied Petroleum Gas LT Long Ton LTS Long Ton Sulfur, M thousand MCF Thousand Cubic Feet (Standard) MEA Monoethanolomine MF Moisture Free MG Milligram MGD Million Gallons per Day MI Mile(s) MIBK Methylisobutyl. Ketone MM Million MMCF Million Cubic Feet (Standard) MMCFD Million Cubic Feet per Day MOL Mole' MPG Miles per Gallon MW Megawatts NDO Nondegradable Organics NGL Natural Gas Liquids NMI Nautical Miles NO Number ODS. Other Dissolved Solids OST Office of.Science and Technology P or PC Percent PE Primary Efficiency PHS Public Health Service PLF Plant Load Factor PM Passenger Mile PPM Parts per Million PSIA Pounds per Square Inch Absolute PSIG Pounds per Square Inch Gage RESID or RF0 Residual fuel oil ROM Run of Mine' Sulfur SCF Standard Cubic.Feet SF Square Foot (Feet) SGC Stack Gas Cleaning SH Short SI Square Inch(es A-3 SNG Synthetic Natural'Gas SRC Solvent Refined Coal', S/S Suspended Solids T Tons(s) TDS Total Di.ssolved Solids TM or TMI Ton Mile TPD Tons per Day TPY Tons per Year .TS Total Solids (Dissolved + Suspended) USDI U.S. Department of the Interior VM Vehicle Mile- VMA Volatile Matter W or"WT Weight WAL Weak Ammonia Liquor YR Year A@4 GPO 9.03-045 ! 5710