o S A S R -4995 1oNns L ORNL RO ke o - ‘¢ ial Energy Opt . -y . > Ise Anderson Bowers Bryan Delene H Jones Jr Klepper Reed iewak D . H G C E. H A Sp T. H R. J. E. J. O S . D - 15/ Based on Coal and Nuclear Systems An Assessment of Industr Printed in the United States of America. Available from National Technical Information Service U.S. Department of Commerce 5285 Port Royal Road, Springfield, Virginia 22161 Price: Printed Copy $10.60; Microfiche $2.25 This report was prepared as an account of work sponsored by the United States Government. Neither the United States nor the Energy Rescarch and Development Administration, nor any of their employees, nor any of their contractors, subcontractors, or their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness or usefulness of any information, apparatus, product or process disclosed, or rapresents that its use would not infringe privately owned rights. ORNL-4995 UC-2 — General, Miscellaneous, and Progress Reports Contract No. W-7405-eng-26 REACTOR DIVISION AN ASSESSMENT OF INDUSTRIAL ENERGY OPTIONS BASED ON COAL AND NUCLEAR SYSTEMS T.D. Anderson E. C. Hise H. 1. Bowers J. E. Jones Jr. R. H. Bryan 0. H. Klepper J. G. Delene S. A. Reed I. Spiewak Industrial Participants D. C. Azbill, Shell Oil Co. E. P. Scheu, International Paper Co. E. A. Bonham, Jr., Dow Chemical Co. J. T. Cockburn, Celanese Chemical Co. R. P. Gerke, Union Carbide Corp. H. G. Sommers, Crown Zellerbach Corp. E. J. Sundstrom, Dow Chemical Co. R. W. Wendes, Amoco Qil Co. A. G. Payne, Monsanto Co. R. L. Wright, Union Carbide Corp. J. L. Ragan, Celanese Fibers Co. JULY 1975 NOTICE work s prepased 3s o8 ‘““'“‘mo:hitm his reporl Wh Ty ited States GOVl 6 nergy mm:;fiedv sutes nor the ,:i';:fiam mor sny of the U nd Development Ad of theis contractors: ces, RoT ‘“IMIP , makes Any OAK RIDGE NATIONAL LABORATORY Oak Ridge, Tennessee 37830 operated by UNION CARBIDE CORPORATION for the U. S. ENERGY RESEARCH AND DEVELOPMENT ADMINISTRATION MASTER ¢ i o DISTRIBUTION OF THIS DOCUMENT UNLIMIEE’!) Contents ACKNOWLEDGMENTS ..................00u0n. ettt e e vii ABST RACT ... ittt ittt et titeseeasaneasissssanssasnnsenasosennns ix 1. INTRODUCTION ............. i et e e e e 1 1.1 Purpose and Scope ............ S 1 1.2 Need for Alternatives ........... e et ber et a e 1 1.3 Energy AlternativesConsidered .......... ... ittt 5 2. RESULTS ..ottt ittiittieieeee aeaeaenansnsassaeeneaseaensaensassenenananssens 6 2.1 Description and Status of Energy SYStems . .. ......ovurerenrneneenrnenenenerennanens 6 2.1.1 Large Nuclear Systems . ..........ouierii it iieaianneans 6 2.1 SMaAll PW R ..ottt i et it e 6 213 Direct Coal Firing ., .. .. .ottt it i ie i eintenneerntasssnsanannnen 7 214 GasfromCoal ... ... . i i i i et e ettt 8 2.15 Liquid FuelsfromCoal ... ... ... ... i i i ittt eenes 9 2.1.6 Solvent-Refined Coal (SRC) ......iviiiiiiit ittt erreernanoronnonaanens 9 2.2 ASSESSIMENt . ... .. .. it ittt e 9 22,1 ReSOUICES .. i v ittt v ienreennaeienansssessnassanssosasssasssnnsennnsnns 9 2.2.2 General Applicability ...... ... i e 11 2.3 Environmental Considerations . ..........ccuiiitiiinenrennerenenaneneneaenenanns 14 2.3 NUCIEAT . ..ttt i ittt ittt et easeeeneeeansaneananssosesesananss 14 2.3.2 Coal-Based Systems . ... ..c.viiiiinntirnnenraeransataneetnssassonaannsnnn 15 24 BCONOMICS . ... 0iiiiiiiniiiiitsneetonnnnnaeecannnnnans i eereeee i 17 T 24.1 Capital Investments ... ..........uuureeeunmennaneennaeeenaaenenaneeneans 17 24,2 FUuelCostS ...\ ittitit ittt teseeeeeneeanneeeanonnsasananoansnnnas ... 18 243 Energy Production Costs . ... .....0iiiitiiiitiinenenesnonnnnnnoennnnnnnnns 19 2.4.4 Effects of Cost Variables on EconomicResults ................coiviiniiinnnnn 21 3. CONCLUSIONS ..... TRy hesaaedaes e, et 24 3.1 The Energy Need «....0.ccvvunnnn... e 24 32 TheEnergy Resources ..........coeiveevennnnnnan eeeee i itateesenaeeeraee.s 24 3.3 TheEnergy System Choices ...... ..ottt ittt iiirieeareenannneacsnnns 24 3.3.1 Direct FiringofCoal .................. et teeeete ettt 25 3.3.2 On-Site Coal Gasification ....... bttt eateataieeanaaeaeaeaateae earaaanaasss 25 3.3.3 Mine-Mouth Coal-Conversion Processes ................. e heear e 25 334 Nuclear Energy ... ..ottt ittt cenrsanrenosnsoeensossosocnnneanonanss 26 4. RECOMMEND ATIONS ...ttt ittt ettt eeetaeretaeanaseeeseseaaaseasaanns 27 4.1 Coal Systems ..... ettt ee st e e s e erenaneseeerenaes 27 4.2 Nuclear Systems . ... e e 27 iv Part II. ENERGY SYSTEMS 5. NUCLEAR ENERGY SYSTEMS ... ittt ittt et ee et e ain e e 29 5.1 Assessment of Uranium ResOUICeS .. ... ..o it i tnn et eneanronnonnonannenans 29 5.1.1 Uranium Availability .......... ... it inriaannaanass .. 29 S12 UraniumDemand . ......... ittt int it iatereraneenoisetoansoanannsnns 31 5.1.3 Uranium Price Projections ............... it iiiiiiiiiiiiiiinneannns 31 5.1.4 Uranium Enrichment . ... ... ... . . i e e 34 5.1.5 Fuel Cycle Capital Requirements . ........................ et 38 52 Commercial NuclearPlants . .. ... .. ... i i i i it it s s e . 40 5.2, Introduction . .. ... it i i e e et e e 40 522 The BWR Power Plant .. ............iuiniininriienreranaraneseanonnoanan 42 523 The PWRPowerPlant . ... ... ... ... it inteeiniaaeernecnnenen 49 524 The HTGRPowerPlant .. ...... ... ... . ittt aeenann 55 5.2.5 Environmental Parameters ... ..........vuintiertnrinerrnnreeainaaaa.s 58 5.2.6 Operating and Maintenance ManpowerNeeds ..............c..civierrrerunnnnn. 62 5.2.7 Downtime for Refueling and Other Maintenance .....................c...covua, 66 5.2.8 Construction Schedule ................ e e e e 69 529 Economic Analysis . . ....covviveinnieniinninnnenn. S 71 5.3 Special-Purpose PWR forIndustry ..........cuiiriiiniiiinniinneenienneinanennns 88 5.3.1 Background and Statusof the CNSGReactor ............. ... ... .. ... ...... 88 532 Reactor Plant . ... ... ...ttt i e ettt s 89 5.3.3 Power-Conversion Plant .. ... ... ... . ittt it ittt 93 5.3.4 Description of 1235-MW(t) System . ....... ..o iuiiiiiiriniitiieiiennennannns 96 5.3.5 Economic Analysis .. ....ccoviiiinnintiiieinee it 96 CrfemMounted CNSG Reactor . ...ttt ittt e et e e ieninneaans 102 6.3 Fluidized-Bed Combustlon ..................................................... 170 6.3.1 Fluidized-Bed Boiler: General Descnptlon .................................... 170 6.3.2 Sulfur REMOVAl . ...ttt e e e 173 6.3.3 Regeneration of the Lime ......... et e e 173 6.34 NO, Formation ........ e S i 176 6.3.5 Development Problems........ e P e 177 6.3.6 Economic ANalyses . ... ... uun et e e e 177 6.3.7 Direct-Fired ProcessHeaters .. ................... e e, 179 6.4 Low-and Intermediate-BtuGas .................... e 180 6.4.1 General Description .. ................. e e ettt 180 6.4.2 State of Development and Commercial Avallablhty ............................. 181 6.4.3 System Characteristics . ... .o vttt ittt e it et e et e ettt ennenennn 181 6.4.4 Commercial Systems Presently Avallable ..................................... 182 6.4.5 New Systemsunder Development . .......... .. ittt ineennirrnnnns 188 6.4.6 GasPurification ...................... @ e e e e 188 6.4.7 Economic Analyses . .......c.iittiiiiinniit it iiniinnn i ... 189 6.5 HighBtuGas ................. e P 193 6.5.1 General Description .. ................i iuvinn.. et e e 193 6.5.2 State of Development and Commercial Avallablhty ............................. 196 6.5.3 System Characteristics . .. ... ... it ittt ittt et ittt s 196 6.54 Economic Analysis ................... et e e e e 203 6.5.5Availability.........t......, ..................................... e 205 6.6 Liquefaction and Clean Boiler Fuels from Coal ........... DU e 206 6.6.1 General Description . ... ........ ...ttt it e e 206 6.6.2 Technology for Coal Liquefaction .. ...... ... ... .. ... iiiiiiiviiaennn.. 207 6.6.3 State of Development and Commercial Avallablhty ............................. 209 6.6.4 System Characteristics . ... ... ittt e ittt it e ettt irea et eirnneeanns 209 6.6.5 Economic Analysis .. ... ..o itttniri it e e e e e 216 6.7 Methanol from Coal . ... ... .. i i e e 219 PART III. ASSESSMENT . ASSESSMENT OF ENERGY ALTERNATIVES ........... B 223 8 T3 (= Tl 2% 1T g N 223 7.2 Direct Coal-Fired Boiler ... .........ovuvuierainneineennnnaon.. e 226 7.3 Low-, Intermediate-, and High-Btu Gas from Coal e e e, 227 7.4 Solvent-Refined Coal and Liquid Boiler Fuel fromCoal ....................0 ... 229 7.5 Selected Comparison of Steam Costs from Alternative Processes ........................ 230 7.6 Retrofitting an Existing Gas-Fired Boiler (or Process Heater) s 232 7.7 Sensitivity Analysis ............conniiiinnn... s e PP 234 7.8 Conclusions ..............covanina.n.n e e et e ues et et et e 234 . INDUSTRIAL VIEW OF ALTERNATIVES ............ e e, 239 - 8.1 Pulp and Paper Manufactunng ....... et et de et it e 239 8.1.1 CrownZelletbach ...................... e e n et edee e et e 239 vi 8.2 Petrochemical Manufacturing . ... ...... ... i iinnanns et 242 8.2.1 Celanese Chemical Company ............... et ettt et eaat e ia e, 242 822 DowChemica, USA ... ... ... it 243 8.2.3 Monsanto Company ......... i ittt et aeereeee e e 244 8.2.4 Union Carbide Corporation (UCC) . ... .. ..ottt ittt iiiiaenan 245 83 Petroleum Refining . .......... .0 iiiinitiiiirnintionnrinnaternanrennsssannsn 248 8.3.1 AmMoco Oil Company ... ..t itiiiiiiiieiientsanetnonestnnsssannsnnannss 248 8.32 Shell Ol Company . .......ciuiiiiinenenreeennnenrosanaoaaeasseasansnannnnns 250 APPENDIX A. NUCLEAR FUEL CYCLE ANALYSIS ... ... it it ii i e aee s 257 APPENDIX B. STEAM LINE COST STUDY — BASIS OF COSTESTIMATE ................... 274 APPENDIX C. STEP-BY-STEP PROCEDURE IN AEC LICENSING OF ' NUCLEARPOWERREACTORS . ....... ..ot e e 276 APPENDIX D. STANDARD FORMAT AND CONTENT OF SAFETY ANALYS!S | o REPORTS FOR NUCLEARPOWERPLANTS ..... ...t iiin i annans 280 APPENDIX E. STANDARD FORMAT AND CONTENT OF ENVIRONMENTAL REPORTS FORNUCLEARPOWERPLANTS ....... ... . i, 290 APPENDIX F. POPULATION RISK PROFILES FOR TEXAS AND LOUISIANA INDUSTRIALIZED AREA . ... i i i i ittt it ineanananaas 293 vii Acknéwledgments The authors gratefully acknowledge the assistance of Oran L. Culberson, the University of Tennessee, in organizing the study and suggesting industrial participants and the guidance of J. O. Roberts and T. Beresovski, ERDA. ' M. L. Myers, 1. T. Dudley, and M. L. Winton assisted in the preparation of the nuclear cost studies. H. D. Duncan and J. W. Yarborough of UCNC Engineering Division provided data used in calculating the energy (steam) transport costs. Special thanks is in order for the many people who were responsible for coordinating and expediting the report. These include F. M. Burkhalter (illustrations), G. C. Bower and J. O. Brown (draft preparation), M. R. Sheldon and E. D. Williams (editing), ORNL Technical Publications Department (final composition), and B. S. Harmon (makeup). ix Abstract Industry consumes about 409 of the total primary energy used in the United States. Natural gas and oil, the major industrial fuels, are becoming scarce and expensive; therefore, there is a critical national need to develop alternative sources of industrial energy based on the more plentiful domestic fuels—coal and nuclear. This report gives the results of a comparative assessment of nuclear- and coal-based industrial energy systems which includes technical, environmental, economic, and resource aspects of industrial energy supply. The nuclear options examined were large commercial nuclear power plants (light-water reactors or high-temperature gas-cooled reactors) and a small [~300-MW(t)] special-purpose pressurized-water reactor for industrial applications. Coal-based systems selected for study were those that appear capable of meeting environmental standards, especially with respect to sulfur dioxide; these are (1) conventional firing using either low- or high-sulfur coal with stack-gas scrubbing equipment, (2) fluidized-bed combustion using high-sulfur coal, (3) low- and intermediate-Btu gas, (4) high-Btu pipeline-quality gas, (5) solvent- refined coal, (6) liquid boiler fuels, and (7) methanol from coal. Results of the study indicated that both nuclear and coal fuel can alleviate the industrial energy deficit resulting from the decline in availability of natural gas and oil. However, because of its ‘broader range of application and relative ease of implementation, coal is expected to be the more important substitute industrial fuel over the next 15 years. In the longer term, nuclear fuels could assume a major role for supplying industrial steam. Part I. Executive Summary 1. Introduction 1.1 PURPOSE AND SCOPE This study was a joint undertaking of the Oak Ridge National Laboratory (ORNL) and eight industrial firms representing paper, chemical process, and petroleum refining industries. The purpose of the study was to analyze alternative future sources of energy for industrial uses. The assessment includes technical, environmental, ecdnomic, and resource availability aspects of industrial energy supply. Since coal and nuclear appear to be the only domestic fuels with the potential for meeting an increased share of near-term energy demands and with an adequate long-term resource base, these were the only fuels considered. ' 1.2 NEED FOR ALTERNATIVES The industrial sector, the largest energy user in the United States, accounts for about 40% of the total primary energy consumption (Fig. 1.1). Natural gas and petroleum are the primary fuels currently used by industry; of the direct fuel uses, 519 is natural gas, 279% is oil, and 22% is coal. Both natural gas and petroleum are becoming scarce, and the prices are escalating rapidly. Perhaps an even greater concern to industry is that no longer can a long-term supply of gas or oil be assured regardless of price. As a consequence, industry will have to rely more and more on the plentiful domestic fuel resources (i.e., coal and nuclear) in the future. From a national energy viewpoint, the use of coal or nuclear fuel in industry would release gas and oil for other uses and would move us an important step toward the national goal of self-sufficiency in energy. Figure 1.2 shows the industrial consumption of gas and petroleum projected by the Department of Interior for 1980,' and, for ‘comparis.'on, the prbjected U.S. shortfall by 1980. As will be noted, the use of -substitute domestic fuels by industry would materially reduce our dependénce_on foreign supply. ~ Natural gas and petroleum are consumed in both fuel and nonfuel applications. Nonfuel uses include chemical feedstocks, lubricants, etc. Less than 7% of the natural gas and nearly 38% of the 1. W. G. Dupree, Jr., and James A. West, United States Energy Through the Year 2000, U.S. Department of the Interior (December 1972). ORNL.-DWG 74-12792 7%/77] FUELS USED TO GENERATE UTILITY ELECTRICITY 7,,/] CoAL oIL DIRECT FUELS NATURAL GAS 30 | ki 2272727 -— 40 . .’f;,/’;////// Y 77 IIl S b s r sl VA SIILSL 2% b s 77/l LS | s 7 s/ 1000000000 Y/ 2L LSS LSS, s s 222727 (1272020405 s a2 r Ll AT 32 vy 5 2 B 7% : Vi V] s g 20 - /////////// ~ o e i V) S - [ f . z = 2 222277 / A = s s {/, 7. / & /////////// /s /j[ // ) S5 5 ) B 2 = oo ese s /,,‘_:{:/.// z £ 0 Widded? g = 15— /;///////// hy B s 0400 ] 3 2 ke Ll 20 = 3 O 8 E S < 2 2 g uw s o < = < 2 w O i —{10 w AND COMMERCIAL Fig. 1.1. Energy consumption in the United States, 1971. petroleum -consumed by industry is used for nonfuel purposes. Although coal umay eventually be converted to forms suitable for chemical feedstocks, the best opportunity for industrial energy substitutions is in the area of fuels. ' ‘ | The Department of Interior projections to the year 2000 reported by Dupree and West' assumed that the rate of increase of industrial energy consumption would average 3.3%/year. The energy increases were assumed to be borne by natural gas, petroleum, and utility-produced electricity. Although the projections were quite reasonable in 1972, recent events suggest that the use ORNL-DWG 7412802 20 15 — F a o o © z -~ 10 - > a Q o O o« o = I L z 3 & i & = i »n3 [a - =2 DD O < S5— 1o I = =z W o -— }_g B35 a z NATURAL GAS PETROLEUM Flg 1.2. Comparison of industrial consumption and U.S. deficit of natural gas and petroleum in 1980. (Source ' West and Dupree.') of gas as an industrial fuel will decline because reserves are inadequate to meet demands. The increased use of oil for industrial fuel may, in fact, come about, but this is contrary to the goal of self-sufficiency in energy. . Another possible scenario developed from the Department of Interior projections is shown in Fig. 1.3. In developing these data, the following assumptions were made. 1. Total industrial energy use and the contributions of coal and electricity to the total are the same as those reported by Dupree and West. 2. The nonfuel energy sources are the same as those reported by Dupree and West.: 3. Natural gas for industrial fuel will be phased out linearly starting in 1975 and endingin 1985. ‘4. Oil for industrial fuel will be phased out linearly starting in 1980 and ending in 1990. The deficit in industrial fuels resulting from the assumed phaseout of oil and gas, illustrated in Fig. 1.3, would have to be made up by coal, nuclear, and other energy sources. According to this scenario, the rate of changeover in the decade 1975 to 1985 would need to be very great. For example, the new capacity of industrial boilers and process heaters added in that period, as shown in ‘Table 1.1, would be nearly 60% of the thermal energy capacity that will be installed by the electric —utlllty 1ndustry in the same time period. It should be noted that nearly threeé-fourths of the “new” industrial energy capacity for the 1975 to 1985 period will be obtained by retrofitting existing industrial plants. There is serious doubt as to _Vw_her'the_r the éés’umed rate of phaseout of gas and oil is feasible because (1) some promising methods of utilizing coal or nuclear for industrial fuels are not sufficiently developed for commercial application, and (2) equipment manufacturers and the fuel resource industries will be hardpressed to meet both the industrial and electric utility demands. ORNL—-DWG 7412794 2000 L bg " AL D g 1w W 220 | D20 o0 2w = o A A - o TZ%”V?Q. T > ZaaanTy a 1995 1990 1985 YEAR 1980 1475 g & & (Mg g,01) NOILJWNSNOD ASHIN3 1970 Fig. 1.3. Industrial energy supply to the year 2000 assuming phaseout of gas and oil. 5 27 B3 =28 i3 g% Z 9 - 8 - B -~ 2 8 - required to the year 2000 New capacity? [MW(t)] For period Period Annual average 57,800 89,900 44,400 25,200 25,100 48,500 289,000 449,500 1975-1980 19801985 222,000 1985-1990 1990--1995 126,000 125,500 1,212,000 1995-2000 Total 1975-2000 4Boilers and process heaters assumed to oper- ate at 90% plant factor and with a fuel-to-heat conversion efficiency of 85%. The present trend in industries that burn natural gas is to convert process heaters and boilers to oil. Although most industries recognize that this could be a stop-gap measure, there are essentially no other alternatives at the present time. Thus, there is an urgent need to develop energy options based on domestic fuels for the industrial sector. ' 1.3 ENERGY ALTERNATIVES CONSIDERED There are a number of ehergy systems options based on either coal or nuclear fuel. The nuclear options examined were large commercial nuclear power plants [light-water-cooled reactors (LWRs) or high-temperature gas-cooled reactors (HTGRs)] and a small [~300-MW(t)] special-purpose pressurized-water reactor (PWR) for industrial applications. Coal-based systems selected for study were those that appear capable of meeting environmental standards, especially with respect to sulfur dioxide; these are (1) conventional firing using either low-sulfur coal or high-sulfur coal with stack-gas scrubbing, (2) fluidized-bed combustion using high-sulfur coal, (3) low- and intermediate-Btu gas, (4) high-Btu pipeline-quality gas (5) solvent-refined coal (SRC), (6) liquid boiler fuels, and (7) methanol from coal. Although much of the assessment of energy systems is applicable to all regions of the country, the emphasis of the study was on the Gulf Coast area, since industries in this region are large energy consumers and the primary fuel is natural gas. Since both technical and economic data on energy systems are changing rather rapidly, it should be képt in mind that the assessment given in this study is based on data obtained during the first half of 1974. Furthermore, only those energy systems that have the potential for significant commercial implementation within the next 15 years were considered. Thus, energy sources such as breeder reactors, fusion, and solar were not examined. 2. Results 2.1 DESCRIPTION AND STATUS OF ENERGY SYSTEMS 2.1.1 Large Nuclear Systems Large nuclear power plants commercially available are the boiling-water reactor (BWR), the PWR, and the HTGR. Both BWRs and PWRs use slightly enriched uranium dioxide pellets as fuel and demineralized water as coolant and moderator. The fuel of the HTGR is a mixture of uranium carbide (highly enriched in **U) and thorium oxide, the moderator and core structure is graphite, and the coolant is helium. ' . ' | o , All present reactors were developed to serve the needs of the electric utility industry, and, with “one exception, all existing or planned large reactors are single-purpose electricity-generating plants. 'The Consumers Power Midland, Michigan, nuclear station, which will commence operation in 1980, is designed to produce both electricity for the grid ‘and'process steam for the Dow Chemical Company complex located nearby. _ _ _ _ _ Commercial nuclear steam supply sy‘stem-s are available in standard sizes, ranging from 1900 to 3800 MW(t) (Table 2.1). Typically, the BWRs and PWRs produce steam at 1000 psia saturated; the HTGR steam conditions are 2400 psia and 510°C (950° F). Table 2.1. Commerzcial nuclear steam supply systems Reactor type BWR PWR HTGR Number of U.S. manufacturers 1 3 1 Size range, MW(t) 19563833 1882-3818 2000-3000 Steam conditions, psia 1040 915-1125 2400 (sat.) (sat.) (950°F) As of Dec. 31, 1973, there were 42 large reactors operating, 56 under construction, and 101 planned or on order. The large size of the units, coupled with a relatively complex regulatory process, results in a long period of planning and construction totaling 7 to 10 years. After a reasonable shakedown period for new plants, it is expected that plant availability factors of ~80% can be achieved. 2.1.2 Small PWR _ The Consolidated Nuclear Steam Generator (CNSG) is a small [~300-MW(t)] PWR developed by Babcock and Wilcox for nuclear ship propulsion. Part of the developmental work was sponsored by the U.S. Maritime Administration. Conceptual studies of land-based and barge-mounted versions of the CNSG were made to assess, in a preliminary way, the potential value of this reactor for industrial applications. The basic technology embodied in the CNSG is similar to that for large PWRs, but the CNSG has some unique features. It is a very compact system; the compactness is accomplished: by placing the once-through steam generator inside the reactor vessel and by using a pressure-suppression containment system. Primary coolant pumps are placed on the reactor vessel, thus eliminating external coolant loops. Steam is produced at 700 psia and 237°C (458°F) (50°F superheat). Some of the unique features of the plant design, including the once-through steam generator, have already been demonstrated in the German nuclear ship “Otto Hahn™; this 38-MW(t) plant has operated successfully since 1969. The U.S. Maritime Administration is currently developing plans to apply the CNSG [313 MW(1)] to a 600,000-ton tanker. Start of construction is planned within | or 2 years. It would appear that only a small amount of development would be required to adapt the CNSG to industrial uses. ' Since the CNSG design allows a greater degree of shop assembly than large reactors, the planning and construction period may be reduced. Planning and construction may be about 6 years for the land-based plant and 4, years or less for the barge-mounted version. Assuming a mature technology, the plant availability factor is expected to be on the order of five percentage points higher than that for large reactors; the dlfference is attributable to less-frequent refueling and reduced refueling time. 2.1.3 Direct Coal Firing Within environmental constraints, there are three methods of directly uéing coal for boilers. Low-sulfur coal can be burned in a conventional boiler with precipitators to reduce particulate emission. High-sulfur coal can be fired in a conventional boiler equipped with stack-gas scrubbers to remove SO; or in fluidized-bed coal combustors with limestone injection. All these methods appear to also be applicable to process heaters. Coal-fired process heaters were once common, but they are not presently being m_annfactured in the United States; they were displaced by gas- and oil-fired heaters. Fluidized-bed process heaters would seem feasible, but no development work is currently being done. If coal of sulfur content low enough to meet Environmental Protection Agency (EPA) standards of 1.2 Ib SO; per million Btu heat input is available, a wide selection of coal-fired boilers is available from U.S. manufacturers. However, particulate-removal equipment, usually an ~ electrostatic precipitator, will be needed to meet the requirement of 0.1 Ib/ 10° Btu heat input set by EPA. Conventional coal-fired boilers are avallable to produce steam at temperatures and pressures “suitable for all mdustrlal apphcatlons in sizes ranging from a few hundred pounds per hour to several million pounds per hour. Planning and construction perlods are on the order of 2 years, and plant availability factors of near 90% are achievable. A conventional boiler or direct coal-fired process heater burning high-sulfur coal would require stack-gas scrubbing; over 100 such processes have been proposed, and about a dozen have reached “the . pilot plant or demonstration phase. The scrubbing systems may be divided into three broad groups: throwaway, regenerable, and 'd'ry processes. The throwaway processes generally dispose of removed sulfur as a waste sludge of calcium salts. The regenerable and dry processes convert | product solutions or solids to elemental sulfur or sulfuric acid. Many of the scrubbing processes remove SO; with an aqueous solution or slurry of alkaline material. The electric utility industry has placed greatest emphasis on the development and demonstration of lime and limestone slurry scrubbing, which are throwaway processes. Systems are being planned for over 20 power plants. However, operating experience to date has not been entirely satisfactory because of scaling, plugging, erosion, and corrosion. Fluidized-bed combustion of coal, a relatively new technology, appears to be very promising as an environmehtally acceptable method of burning high-sulfur coal. Combustion is accomplished in an inert bed, consisting mainly of ash and limestone, which rests on a plate containing nozzles. Combustion air introduced through the nozzles expands the bed to a level greater than its static depth. Crushed coal is injected into the bottom of the bed. Bed turbulence aids in transferring heat to the fuel and also provides intimate mixing of fuel and air, thus promoting rapid combustion. Bed temperature is controlled at 870 to 982°C (1600 to 1800°F) by removing approximately half of the heat through heat transfer surfaces immersed in the bed. The relatively low combustion temperature sharply reduces the formation of nitrogen oxides, and the conditions of temperature and turbulence in the bed favor the reaction of sulfur oxides and limestone. Thus the injection of limestone is very effective in reducing SO; emissions. Fluidized-bed boilers are not now commercially available but are under development. A demonstration boiler that produces 300,000 Ib of steam per hour [~ 100 MW(t)] is scheduled for completion in mid-1975. 2.1.4 Gas from Coal There are a number of processes for producing fuel gas from coal, some of which are in the development stage and others commercially available. The fuel gases produced are classified according to the higher heating value of the gas as follows: (1) low-Btu gas, 120 to 200 Btu/scf, (2) intermediate-Btu gas, 300 to 600 Btu/scf, and (3) high-Btu gas, 900 to 1000 Btu/scf. The high-Btu gas is similar to natural gas both in composition and heating value. Table 2.2 gives a comparison of compositions and heating values of the coal-derived gases. . Low-Btu gastfication is achieved by reacting coal with steam and air. Partial combustion of the coal provides the heat necessary to cause steam to react with carbon, producing hydrogen, carbon - monoxide, and small amounts of methane and other hydrocarbons. In addition to combustible gases, the fuel also contains significant quantities of CO; and nitrogen as shown in Table 2.2. Sulfur contained in the coal appears in the gas principally as hydrogen sulfide (H:S), which can be scrubbed from the fuel gas. Table 2.2. Representative properties of low-, intermediate-, and high-Btu gas Gas composition (% by volume) Low Btu Intermediate Btu High Btu Carbon dioxide 15 4-6 1 Carbon monoxide 15 30-41 Hydrogen 23 37-49 5 Methane 4 1-14 92 Nitrogen 42 4-6 2 Other hydrocarbons 1 0-7 Approx. higher heating 170 300-500 1000 value, Btu/scf C The production of intermediate-Btu gas from coal is similar to the production of low-Btu gas, except that oxygen or oxygen-enriched air is used in partially oxidizing the coal. Thus, the nitrogen content of the product gas is substantially reduced. There are a number of developmental processes for producing high-Btu gas from coal, but the process that is considered current technology is based on additional processing of intermediate-Btu gas. Two major steps are required. A shift conversion step reacts some of the carbon monoxide in the intermediate-Btu gas with steam to produce additional hydrogen. A methanation step reacts hydrogen with carbon monoxide to produce methane (CH.). El Paso Natural Gas Company is planning a coal gasification plant to produce 288 million ft’/day of pipeline-quality gas in the northwest corner of New Mexico; plans are for the plant to be completed in 1978. [Combustion of this gas would produce energy at the rate of about 3000 MW(t).] - 2.1.5 Liquid Fuels from Coal A number of processes are under development for the production of liquid fuels from coal. One point of emphasis in this program is the production of synthetic crude oil which could be refined into various products much like‘natural crude oil. The main problem in the conversion of coal to liquids is the transformation of a low-hydrogen-content solid into a liquid containing a large amount of hydrogen. The differences among the various processes are related primarily to the method of hydrogenation. Some hydrogen can be added without a catalyst, but a catalyst is generally required to make light fuel products. The Office of Coal Research is pursuing three processes for coal liquefaction, and it is expected that a commercial process will be developed by the early 1980s. 2.1.6 Solvent-Refined Coal (SRC) The solvent refining process was developed to produce a Iow-ash, low-sulfur boiler fuel from coal with a minimum of hydrogenation. The product is a solid at room temperature. In the SRC process, crushed coal is slurried with anthracene-oil solvent and hydrogen, the mixture is heated to ~427°C (~800°F) to dissolve the coal, and the resulting solution is filtered to remove the mineral residue. The product, which is low in sulfur, can be burned as a hot liquid or can be solidified ~ (cooled) for shipment and use as a solid fuel. Although there is some question about remelting, limited tests suggest that the product can be remelted and fired much as a heavy residual oil. A 50-ton/day SRC pilot plant, sponsored by the Office of Coal Research, is scheduled for startup in the fall of 1974. The plant would have a coal feed rate equivalent to about 14 MW(t). A smaller 6-ton/day pilot plant, built by the Southern Company and Edison Electric Institute, was completed in September 1973. This unit, operating on Kentucky No. 14 coal with 3.9% sulfur, produces a product with ;about 0.6% sulfur and a heating value near 16,000 Btu/lb. 2.2 ASSESSMENT ‘2.2.1 Resources Both coal and uranium are relatively abundant, but there are limitations to exploitation for each. Uranium, which is widely distributed in the earth’s crust, is more abundant than gold or silver 10 and about the same as molybdenum or tin, However, the average concentration in the earth’s crust is rather low (2 to 4 ppm), and extraction from dilute sources would be expensive. The present source of uranium ore in the United States is contained in sedimentary strata, particularly those found in the Colorado Plateau and in the Wyoming basin. The average concentration of uranium in presently mined ore is about 2100 ppm, and the market price is $6 to $10 per pound of UsOs. Known and estimated reserves in conventional uranium ore deposits are expected to be depleted by the end of the century. Assuming no new mining regions are discovered, the uranium supply will then shift to more dilute sources. : The Chattanooga shales contain 25 to 80 ppm of U3Os, and the cost of extraction is expected to be $50 to $100 per pound of U3Qs. Other sources of uranium include western lignite deposits (50 to 200 ppm), Conway granites (10 to 20 ppm), and the sea (0.003 to 0.004 ppm). The Chattanooga shales alone contain enough uranium to last over a century. Thus, the problem is not that we will run out of uranium but that its price and the environmental effects of mining low-grade ore will gradually increase until alternatives to present-day converter reactors may become more desirable. The expected trend in nuclear energy production cost based on converter reactors is illustrated in Fig. 2.1. However, studies by the U.S. Atomic Energy Commission (AEC) indicate that even to the year 2000, converter reactors will still be more economical than coal for base-load central-station ORNL-DWG 7412788 1.2 - . -t RELATIVE PROCESS HEAT COST - o 0.9 1981 1986 1991 STARTUP YEAR Fig. 2.1. Relative levelized cost of steam produétiori with a light-water reactor as a function of startup date (utility financing). o 11 power applications. The AEC expects that the breeder reactor, which is presently under development, will begin to relieve the stress on uranium resources by the early 1990s. The in-place reserves of coal that is minable with present technology amounts to about 394 billion tons. Assuming present mining recovery factors, the recoverable reserves amount to 220 billion tons, with 175 billion tons deep minable and 45 billion tons strippable. Of the strippable coal, 25 billion tons are low in sulfur and are located in the Rocky Mountain states. The total recoverable coal reserves are equivalent to about a 65-year supply at a rate of consumption equal to our total national energy use in 1970. I_t is evident that the coal reserves are adequate to meet almost any demand in the foreseeable future. The limitations on the exploitation of this resource are (l) environmental constraints on mining, (2) coal-industry development, and (3) transportation. Most of the present concern about environmental effects is related to strip mining. Because of low capital and operating costs and reduced time for mine development relative to deep mines, strip mining is on the increase and presently accounts for about half of our total coal production. Some form of national legislation to reduce the adverse effects of stripping seems inevitable. The nature of this leglslatlon could have a strong bearing on the rate at which coal resources can be exploited, especially in the west. Aside from the environmental constraints, there are other limitations to coal industry expansion. Large deep mines require about 5 years and substantial capltal for development. Much of the financing will need to come from ‘outside the coal industry. The transportation industry is also an important element of the coal energy supply system. Rail transportation is particularly important, and limitations on the rate of modernization and expansion of this industry will affect the rate of coal resource development. When all factors are taken into consideration, the National Petroleum Council believes that coal production can increase at 5%/ year. However, it appears that a rate of over 6% will be required over the next decade to simply hold the rates of oil and gas consumption in the utility and industrial sectors at their present levels. If the goal is to displace present uses of oil and gas, the coal expansion rate must be even higher. It appears that coal supply will be hard pressed to meet demand, at least over the next decade. : ‘ 2.2.2 General Applicability Industrial necds for energy include. steam, proccss heat, electricity, and chemical feedstocks. Blocks of energy vary in size from a few to several hundred thermal megawatts. Much of the current need for new energy systems is for retrofitting existing industrial plants that are presently burning gas or oil, but there is also a need for energy systems for expansion of present plants and for new “grass roots” industrial plants. The energy alternatives considered in this study exhibit different degrees of flexibility relative to meeting the various requirements for industrial energy systems. Size The question of how well the output of individual supply systems match the consumption of energy is of significance only for the nuclear systems. Genéfally, the commercial nuclear power plants produce more energy than individual industrial plants. can use. Even for large petroleum ~ refineries, which are among the most energy-intensive industrial operations, there is a mismatch between the output of commercial reactors and refinery energy needs.. For example, a 500,000-bbl/day refinery would require approximately 4000 MW(t) of energy input; 2000 to 3000 MW(t) of this would be based on purchased fuels, and the remainder would be supplied by 12 internally generated fuels. Thus, a refinery slightly larger than any presently operating in the United States could take the output of one commercial reactor. However, a single unit would not provide the reliability required; at least two or possibly three units would be needed. This leads to one important result concerning the use of large nuclear power plants for industrial energy: a multiunit station will be needed, and the output will be shared by a group of industrial plants or by one or more industrial plants and an electric utility. The latter situation is illustrated by.the arrangement between Dow and Consumers Power at Midland, Mich. Another consideration in supplying energy from a nuclear power station to outlying industries is that thermal energy, whether it be steam or process heat, may need to be transported over a considerable distance. ' In contrast to large commercial nuclear power plants, the output of small special-purpose reactors, such as the CNSG, could be consumed by some individual industrial plants in some cases. A two- or three-unit station would provide 600 to 1000 MW(t) of steam. Application by energy form Depending on the type of industrial plant, energy consumption may be in the form of electricity, steam, process heat, and chemical feedstocks. Table 2.3 shows the ranking of systems relative to the four potential energy needs. All energy sources could be used to produce electricity and steam, and all except the LWRs appear to be capable of providing process heat. Both the HTGR and the fluidized-bed combustor would require additional development before they could be applied to process heating. High- and intermediate-Btu gas and synthetic crude oil from coal could be used as sources of chemical feedstocks. Table 2.3. Ranking of industrial systems by range of application System Electricity Steam Process Chemical heat feedstock High-Btu gas X X X X Intermediate-Btu gas X X X X Liquid fuels X X X % Low-Btu gas X X X Solvent-refined coal X X X Fluidized-bed combustor X X xb Conventional firing X X x€ HTGR X X x® Small LWR X X Large LWR X X 2Synthetic crude oil can be processed in a petrochemical refinery much the same as natural. Heavy boiler fuels from coal would not be a source of chemical feedstocks. “ b Additional development required for process heating applications. “Direct coalfired process heaters have been used but are not presently manufactured in the U,S. 13 Ease of retrofitting Existing industrial plants, esi)ecially those that presently use natural gas, may need to be switched to another fuel in the future. The ranking of the energy sources by the ease of retrofitting existing gas-fired installations is as follows: . high-Btu gas, | . intermediate-Btu gas, . liquid fuels, . solvent-refined coal, low-Btu gas, fluidized-bed combustor, conventional firing with low-sulfur coal, conventional firing with stack-gas cleanup, . HTGR, 10 small LWR, 11, large LWR. »opo:-l_o«_u-num_ High- and intermediate-Btu gas from coal would require the least change in existing boilers and heaters. Liquid boiler fuels or synthetic crude oil would require about the same modifications as would residual oil. Solvent-refined coal might also be fired in a modified gas boiler or heater if remelting of the solid fuel product proves practicable. Low-Btu gas appears to be questionable as a fuel for retrofitted systems because of derating and loss of efficiency; however, these factors have not been thoroughly evaluated by test. The remaining energy systems (ie., the fluidized-bed and conventional coal systems and the nuclear systems) would require the installation of new equipment. Light-water reactors would probably be the most difficult to retrofit because in some plants industrial turbine drives would have to be changed to use the saturated steam produced by LWRs. Energy acquisition If an industry desires to obtain a new energy system, an important consideration is the number of options available in making the acquisition. Can the equipment be purchased independently or is the energy supply of such a nature that a joint undertaking with others is required? Table 2.4 shows the options for each of the energy systems. Generally, large reactors and the mine-mouth coal-conversion processes offer the fewest options. The output of large reactors must be shared because of their size. Mine-mouth coal-conversion plants would probably be owned by an energy company selling fuels. When an energy system will be avanlable is another 1mportant factor. Table 2.5 ranks the encrgy systems by year of availability. The only option avaflable in 2 years or less that is based on proven technology is conventional firing using low-sulfur coal. 14 Table 2.4. Ranking of industrial energy systems by user’s options for action Cooperate Purchase System ' egz;;;a:st - with fuelor : - others energy Low- and intermediate-Btu gas X X X Small reactors X X X Fluidized-bed combustor x X X Conventional firing X X X Large reactors X X Liquid fuels X X Solvent-refined coal x X High-Btu gas X. Table 2.5. Ranking of industrial energy systems by date of earliest commercialization or application System Date Conventional firing, low-sulfur coal 1976 Conventional firing, stack-gas cleaning? 1976 Low-Btu gas S 197678 Intermediate-Btu gas 1976—78 Fluidized-bed combustor? 1977-79 Solvent-refined coal? : 1979-81 Liquid fuels? 1981-83 Large nuclear power plants 1981-84 Small nuclear power plants? 1981-84 High-Btu gas? 19782 Not commercially demonstrated. DEasliest commercialization date is 1978; however, the capacity will not be large enough to have any impact on total gas supply. 2.3 ENVIRONMENTAL CONSIDERATIONS 2.73.1 Nuclear The environmental consideration of greatest concern with nuclear power is health and safety of the public. This issue is complex, but it basically involves protection of people against any harmful exposure to ionizing radiation. In the safety review of nuclear plants, the AEC considers both plant design features and environmental characteristics that could adversely affect the plant’s safety performance or the radiological consequences of accidents. Without exception, nuclear power plants 15 have been judged by the AEC on a case-by-case basis; thus, no general assessment can determine the acceptability of a given reactor at a given site. Nevertheless, this study addressed one general aspect of nuclear plant siting that is particularly important—the size of the proximate population. The prospect of using nuclear power for industrial energy raises the question as to whether it is reasonable to expect that such plants could be located in typical industrial areas. To provide some guidance on this question, population-risk estimates were made for several industrialized areas in Texas and Louisiana. The acceptability of the calculated population-risk factors was judged by comparison with risk factors estimated for existing approved reactor sites. It was found that all of the industrialized areas studied, with' the exception of the central city regions, would be quite favorable as nuclear sites, at least on the basis of population risk. 2.3.2 Coal-Based Systems All the coal-based energy systems examined in this study have the capability of meeting EPA emission standards. However, this does not mean that all systems are equal with respect to environmental impacts. Typical types and quantities of wastes resulting from the use of coal or coal-derived fuels are shown in Table 2.6. For direct-fired systems employing eastern coal, the use of lime or limestone slurry stack-gas scrubbing would result in the greatest environmental insult because the sludge produced is not even suitable as land fill unless it is subjected to further treatment for stabilization, provided some acceptable economical method can be found. Regenerable systems for stack-gas scrubbing are also commercially available or will be in the near future. Generally, these systems recover sulfur in the form of sulfuric acid or elemental sulfur, the latter being more acceptable from an environmental standpoint. Fluidized-bed combustion systems produce a solid, readily handled residue which would be suitable as land fill or possibly for road or masonry construction. The processes for coal-derived fuels produce some solid waste in the form of ash, char, or slag and elemental sulfur along with relatively small waste streams which can be renovated by biological treatment. On-site coal gasification plants will generate ash in amounts equivalent to direct-fired systems, and the ash can be handled in a conventional manner. For mine-mouth plants the solid wastes, including the inert elemental sulfur if it cannot be marketed, will be returned to the mine for fill. ' , "The coal-conversion processes examined in this study require varying amounts of water’ as shown in Table 2.7, which also lists water consumption rates for nuclear fuel processing and oil refining for comparison. The higher values of water consumption shown include that required for process or utility cooling, most of which is once-through;. While the general trend is toward closed evaporation systems to reduce thermal pollution, these systems have a greater evaporation loss than once-through systems, and, consequently, cooling water will continue to be the largest increment of water usage. Excluding cooling requirements, the water consumption for the coal-conversion - systems is modest. Typically in a liquefaction plant for producing fuel oil from coal, about 4% of the total water requirement is consumed in hydrogen production. About 25% is used for scrubbing or washing the gaseous and liquid product stream. ANl but a small fraction of this can be subjected to biological treatment and recovered for reuse. By comparison, the solvent-refined coal process requires only about one-fifth of the water needed for coal liquefaction processes. 2. Chem. Eng. News 52(30), 17 (July 24, 1974), Table 2.6. Typical wastes generated when using coal or coal-derived fuels for boiler or process heat fuel Method of coal utilization Characteristics of waste product 'Approximate quantity of waste available in fuel (Ib/10° Btu) Conventional firing Low-sulfur (western) coal (<0.5% S, 4-8% ash) High-sulfur (eastern) coal (3-12% S, 8—20% ash) Lime or limestone slurry SO, removal for stack gas Regenerable scrubbing to remove SO, from stack gas Fluidized-bed combustion using limestone injection for SO, abatement Coal-derived fuels Low- and intermediate-Btu gas from eastern coal No. 4 and No. 6 type fuel oils Solvent-refined coal High-Btu gas On-site utilization Dry ash, gaseous SO, Thixotropic siudge (30-60% water) mixture of lime, CaSQ3, and ash H,804 or elemental sulfur? and small waste stream of NaaSQ4, CaS04, or catalyst which can be recovered Dry residue composed of ash and CaSO, " Dry ash, elemental sulfur, acid wash water (which must be treated before disposal) Mine-mouth production (eastern coal) Elemental sulfur, waste gas (CO,), char, waste water Ash, waste water (treated), elemental sulfur Elemental sulfur, waste gas and water, slag 5-101b ash; <1 1b SO, 13—140 Ib sludge (300 £t>/ton sludge) 2—-10 Ib elemental sulfur; >2 Ib Na,SOg,, CaSQy,, or spent catalyst; 13—32 Ib ash 930 Ib of dry solids 91 13-32 Ib ash, 210 Ib sulfur, 1 Ib wash water 2-10 1b suifur, ~107 b waste gas, ~7 Ib char 1-5 1b sulfur, 13190 Ib ash, ~60 Ib waste water 260 Ib waste gas, 2—10 Ib sulfur, ~10 Ib slag, ~88 b waste water 4Sulfuric acid is less desirable, since it has limited commercial value and cannot be transported economically except for short distances. Elemental sulfur has commercial value and will therefore not necessarily be discarded as other waste products. 17 Table 2.7. Water usage for energy-conversion processes Process : Usage (gal/1 0° Btu) Uranium reactor fuel (including 14 power plant consumption for electricity used in processing) Qil refining . 7 Pipeline gas from coal (Lurg1 ‘ process) Water cooling . 72-158 Partial (85% of demand) air cooling 37-79 Oil from coal 31-200 Solvent-refined coal ' 6—40 2.4 ECONOMICS To provide a uniform basis for comparison, costs were estimated for producing steam with each of the energy systems considered. 24.1 Capital Investments The capital investments that must be made at the industrial site, shown in Table 2.8, range from $48 to $192/kW(t). The mine-mouthicoal-conversion processes (high-Btu gas,|liquid fuels, and SRC) require the least investment at the industrial plant, but, as will be discussed later, fuel costs are relatively high. Of the coal—ba_scd systems, low- and intermediate-Btu gas processes require the Table 2.8. On-site capital investments required per unit of steam production (early 1974 dollars) System Unit investment {$/kW(t)] High-Btu gas I © 488 Solvent-refined coal or liquid fuels , 4879 Conventional firing with low-sulfur coal 58 Fluidized-bed boiler 61 ~ Conventional firing with hlgh-sulfur coal B 78 and stack-gas scrubbing ' Commercial LWR, 2-unit station, 93 1875 MW(t) each B - _ . Commercial HTGR, 2-unit station, 105 2000 MW(t) each ‘ ' : Intermediate-Btu gas 129 - Low-Btu gas ' ' 141 - Barge-mounted CNSG, 2-unit station, 314 MW(t) each 154 Land-based CNSG, 2-unit station, 314 MW(t) each 192 9PDoes not include off-site investments required for mine-mouth coal-conver- sion processes. 18 largest on-site investment because the costs of the gasification equipment and boilers are both included. The nuclear plant investments do not include reboilers; these may be required to isolate the nuclear steam supply system from the industrial steam system. As will be noted, the CNSG requires the largest investment per unit of output. The barge-mounted version of the CNSG is expected to cost about 20% less than the land-based system because it is assumed that barge-mounted units would be factory constructed. 2.4.2 Fuel Costs The prediction of future prices of energy resources is difficult because of the current state of uncertainty concerning fossil fuels. In this study, levelized nuclear fuel cycle costs were estimated for reactor startup dates to 1991 for both utility and industrial financing conditions. The estimates of nuclear fuel costs were based on what seem to be reasonable projections of uranium ore resources and uses and expected trends in the cost of 2*’U separation (separative work), fuel fabrication, and fuel reprocessing. Since the electric utility industry is a major consumer of both coal and nuclear fuel, it was assumed that the long-term price of coal will stabilize at a level that will make it competitive with nuclear fuel for some types of electricity generation. The estimated nuclear fuel-cycle costs are summarized in Table 2.9. Depending on the type of reactor, the startup date, and the financing assumptions, estimated costs range from 27¢ to 68¢/10° Btu. Two sources of coal were considered in this study: eastern bituminous coal of high-sulfur content from southern Illinois or western Kentuckyland western subbituminous coal of low-sulfur content from Wyoming. Estimates were made for the costs of coal at the mine and delivered to the Gulf Coast area (specifically to Houston and New Orleans). The estimates are summarized in Table 2.10. Mine-mouth values of coal were selected so that coal would be competitive with nuclear energy for producing non-base-load electricity. The reference coal! values are 50¢/10° Btu for eastern high-sulfur bituminous coal and 30¢/10° Btu for western low-sulfur subbituminous coal. These values are somewhat lower than present market prices, especially for eastern coal, but it was assumed that present prices represent a response to a relatively short-term supply and demand situation. Table 2.9. Reference fuel-cycle costs (early 1974 dollars) Startup date System - 1981 1986 1991 Utility Industrial Utility Industrial Utility Industrial LWR ¢/10° Btu 27.3 32.7 31.0 38.0 34.6 434 mills/kWhr(e) 2.91 3.49 3.31 4.05 3.69 4.63 HTGR ¢/10° Btu 30.2 38.7 33.0 43.0 35.9 47.3 mills/kWhr(e) 2.67 3.42 2.91 3.80 3.17 4.17 CNSG : ¢/10° Btu 41.4 52.4 46.7 60.3 51.8 68.1 mills/kWhr(e) 4.86 6.15 5.48 7.07 6.08 7.99 19 Table 2.10. Cost of coal delivered to New Ofleans and Houston areas (early 1974 dollars) Cost (¢/10° Btu) : . Coal Total delivered cost Transportation (5o 1 mine) ————— Base ' Range Eastern high-sulfur coal To New Oreleans i8 50 68 55-81 area . To Houston area 24 50 74 60-88 Eastern low-sulfur coal - ' To New Orleans 18. 80 98 85-110 To Houston area 24 80 104 90-118 Western subbituminous coal To New Orleans 57 30 - 87 T71-103 area To Houston area Via New Orleans’ | 66 30 96 78-114 Direct unit train 45 30 75 60-89 2.4.3 Energy Production Costs The estimated costs of producing steam with new installations in the Houston, Tex., area are shown in Fig. 2.2. The steam production costs include capital charges, operation and maintenance, and fuel costs. The capital charges depend on the financing assumptions. The assumptions made in this study, shown in Table 2.11, are intended to be a representative set of conditions but not necessarily applicable to any particular industry. The results\given in Fig. 2.2 show that large nuclear plants offer steam at the lowest cost of any energy system investigated; steam costs from large nuclear plants range from 78¢ to 144¢/10° Btu, depending on reactor type, size, and method of financing. The nuclear plants are followed by the direct coal-fired systems—conventional firing and fluidized-bed combustion; steam costs range from 154¢ to 184¢/10° Btu. Solvent-refined coal is the most economical of the fuels derived from coal, with an estimated steam production cost of 215¢/10° Btu. The land-based version of the CNSG would produce steam for about 242¢/10° Btu. A factory-built, barge-mounted CNSG would be somewhat less expensive, but no overall energy cost estimates were made for this concept. The most _expensive energy systems are those based on liquid and gaseous fuels derived from coal; steam production ‘costs range from 266¢ to 345¢/10° Btu for liquid fuels and pipelinequality gas respectively. Methanol derived from coal (not shown in Fig. 2.2), the most expensive of all boiler fuels, would result in a steam production cost of about 400¢/10° Btu. The results discussed above are for new installations, but the largest near-term market for alternative energy sources is for retrofitting existing plants. Intuitively, it would seem that the coal-derived fuels, especially low- or intermediate-Btu gas, would make a better showing for the (‘s1efjop pL6} AlIeq) Ise0) AND 'S’ ‘wes fesnpur Sutonpoid Jo 51500 aaneredwo) 77 ‘81 STEAM PRODUCTION COST (¢/10% Btu) N . £ 0se N o o RESIDUAL OIL AT $9/bbl 1875 MW(t) LWR, 2—-UNIT STATION, INDUSTRIAL FINANCING 2000 MW(t) HTGR, 2—UNIT STATION, INDUSTRIAL FINANCING LOW—SULFUR WESTERN COAL, CONVENTIONAL FIRING HIGH-SULFUR EASTERN COAL, FLUIDIZED BED BOILER HIGH-SULFUR EASTERN COAL, CONVENTIONAL FIRING, STACK-GAS 314 MW(t) CNSG, 2-UNIT STATION (LAND-BASED) -LIQUID FUEL FROM COAL LOW—-Btu GAS, LURGI INTERMEDIATE- Btu GAS, LURGI 0z HIGLZL—¥L OMO-TINHO 21 Table 2.11. Financial assumptions Financial parameters (%) Utility Industrial Fraction of investment in bonds 55 30 Interest rate on bonds 8 8 Return on equity o 10 15 Federal income tax rate ' 48 48 State income tax rate 3 3 Gross revenues tax rate o 0 0 Local property tax rate 3 3 Interim replacements rate 0.35 0.35 Property insurance rate : 0.25 0.25 . Plant lifetime, years , 30 20 retrofitting case than for a new installation, since existing gas-fired heaters and boilers could be retained. Nevertheless, the analysis of this case showed that it will be more economical in most circumstances to replace existing gas-fired boilers with new direct coal-fired boilers. A comparison of selected energy systems for retrofitting is shown in Fig. 2.3. In interpreting the economic results, it should be kept in mind that the comparisons are on the basis of steam production. As discussed previously, there are marked differences among the energy systems relative to the potential for supplying other energy needs. All the coal systems might be useful for supplying process heat, whereas none of the present nuclear systems have that capability. However, the HTGR could be adapted to moderate-temperature (1000 to 1400°F) process heating. It should also be noted that the LWRSs (including the CNSG) produce steam at a lower temperature than either the HTGR or coal-based systems. Although the large LWRs have low thermal energy costs, the thermodynamic availability of the thermal energy is less than that of most other steam sources. If the comparison were on the basis of cost per unit of shaft work capability, the large LWR cost would be near that of the HTGR. Another factor in comparing the economics of large reactors with the other alternatives is that the cost to transport thermal energy will probably be higher'than for alternative steam systems. The reason is that, since large nuclear plants are expected to serve as dual-purpose, central station electricity and industrial steam plants, the nuclear station would likely occupy a site separate from that of the industrial plant. This study indicated that steam transportatlon would cost 6¢ to 8¢ / 10° Btu per mlle of _transport. 2.4.4 Effects of Cost Vanables on Econonnc Results There are a number of cost uncertamtxes that could affect the absolute values of estlmated | energy costs as well as the relative rankmg of the various energy systems investigated. Estimated capital investments are most certain for large nuclear stations and conventional coal-fired boilers and least certain for developmental systems such as fluidized-bed boilers, small 22 ORNL-DWG 74-7101R 250 [— g g é § é 2 = N E § 3 : N N & 2 ¢ N N ¢ £ = 8 N N :§ ° 3 > N NN B & & 150 | § \ E§§ N 0&M NENEENE NEENEENN TN 100 — § - §§ \ FUEL "N NN N VLA Y } N D NN D 50 |— \ \ \\ z N N N ¥ N NN ’ § § §§ gg - JcariTaL N N P ' e RETROFIT - NEW COAL FIRED BOILER Fig. 2.3. Selected comparison of steam cost for retrofit vs new coal-fired boiler. reactors, and coal-derived fuels. Whether the actual costs of these systems will be more or less than the estimates given in this study cannot be determined at the present time. The cost of money is another important economic variable, and the effects of changes in the effective cost of money on steam production costs were investigated. The higher the cost of money, the more pronounced the gap between the least expensive (direct fired) and most expensive (coal-derived fuels) coal-based systems. The economic position of utility-owned large nuclear plants relative to coal systems in not substantially altered by changes in the cost of money up to 50% greater than the reference values given in Table 2.11. The cost of energy production for the small CNSG reactor is relatively sensitive to the cost of money, since the CNSG is capital intensive. Even so the ranking of all energy systems by cost is unchanged from that shown in Fig. 2.2 for changes in the cost of money up to 50% greater than the reference values. 23 Current coal prices are substantially higher than the base values used in the present study. As discussed previously, the reference coal prices were selected on the assumption that coal 'prices will, in the long run, readjust to a competitive position with nuclear for some central station power applications. If coal prices do not decline, (1) the cost differential between the direct-fired systems and the coal-derived fuels will beéome even larger, because the direct-fired systems are more efficient converters of coal to thermal energy, and (2) the relative economic position of nuclear will be substantially improved. 24 3. Conclusions 3.1 THE ENERGY NEED Industry is faced with a period of transition in fuel sources. Presently, natural gas provides over half the on-site-produced industrial energy, but this resource is becoming scarce and is expected to be phased out as an industrial fuel within the next few years. The present trend is to substitute oil for natural gas in process heaters and boilers. Although the increased use of oil is contrary to the goal of national self-sufficiency in energy, industry has few other alternatives at the present time. Therefore, there is an urgent need to develop energy options for the industrial sector based on plentiful domestic fuels. This is especially important when it is considered that industry consumes more energy than any other economic sector., Coal and uranium are the only major domestic fuel resources that have a reasonable long-term resource base. The technologies required to use these fuels in an economical, environmentally acceptable way are under development and in some instances being applied. However, the motivation for such development has been primarily for applications other than industrial energy: the major emphasis by both the Federal Government and the energy equipment industry has been on central station power generation, Yet, relative to central station (utility) power generation, industry consumes nearly twice the petroleum and about three times the natural gés. Thus, a stronger national emphasis on the industrial fuel need is justified. 3.2 THE ENERGY RESOURCES The domestic uranium and coal resources are both sufficiently large to make either fuel a reasonable long-term alternative for industrial applications. Coal reserves are particularly large, and it is likely that a major portion of the deficit in oil and gas for industry will be made up by coal. Nevertheless, there are major intermediate-term problems in exploiting our coal resources. These problems relate to environmental constraints on mining and utilization, coal-industry capitalization, and transportation. When all factors are considered, it appears that the supply of coal will be hard pressed to meet demand, at least over the next decade. The current inflated price structure appears to be a consequence of the supply-demand imbalance, but in the long term it is likely that coal will stabilize at prices lower than the present values because of competition with other fuels, particularly nuclear. The high-grade reserves of uranium may be depleted by the end of the century. Assuming no new mining regions are discovered, the uranium supply will then shift to more dilute sources such as the Chattanooga shales. Even so, it is concluded that the total cost of nuclear energy will be relatively stable over at least the next two decades because the cost of energy production is not a strong function of uranium ore cost. 3.3 THE ENERGY SYSTEM CHOICES Coal and nuclear fuel can each serve as a basis for a number of potentially attractive industrial energy system choices. Both fuels can and probably will help alleviate the energy deficit resulting from the decline in availability of natural gas and oil. Because of its broader range of application and relative ease of implementation, coal is expected to be the more important substitute industrial fuel over the period of interest in this study (the next 15 years). In the longer term, nuclear fuels 25 could assume a major role for supplying industrial steam. Timing and extent of use of nuclear will depend, in part, on efforts expended to resolve institutional problems. Conclusions about specific coal and nuclear energy systems are given below. 3.3.1 Direct Firing of Coal Generally, the direct firing of coal in industrial boilers and process heaters will be more economical than the use of coal-derived fuels (gases, liquids, and solids). There are three methods for directly using coal to generate steam or process heat in an environmentally acceptable manner: (1) low-sulfur coal, (2) fluidized-bed combustion, and (3) high-sulfur coal with stack-gas scrubbing. The most realistic coal-based alternative at the present time is low-sulfur coal fired in a conventional boiler. If low-sulfur coal becomes available in sufficient quantities, this is the lowest-cost coal alternative in the Gulf Coast arca. The most promising method of using high-sulfur coal is the fluidized-bed boiler. If development goals are achieved, the process offers flexibility in fuel supply as well as low cost. Fluidized-bed combustion may also hold promise for process heating, but no development work is being done on fluidized-bed process heaters. Wet limestone scrubbing appears to be the least expensive and best developed of the stack-gas cleanup systems. With additional development, these systems will, no doubt, become workable, but overall operating experience has been poor. Wet limestone scrubbing and other throwaway processes have one distinct disadvantage for industrial applications: the large volume of waste sludge will be difficult to dispose of in many industrial areas. For this reason, it appears that widespread industrial use of stack-gas scrubbing must await the development of economical regenerable systems. -3.3.2 On-Site Coal Gasification Air-blown gasifiers producing low-Btu gas (~150 Btu/scf) and oxygen-blown gasifiers producing intermediate-Btu gas (~300 Btu/scf) are commercially available. Low-Btu gas is marginally lower in cost, but intermediate-Btu gas is a better choice for industry because (1) it can be used as a retrofit fuel for existing gas-fired boilers and process heaters and (2) it is more readily usable as a chemical feedstock. As fuels, however, low- and intermediate-Btu gases are more expensive than direct-fired coal. Extensive industrial applications of on-site coal gasifiers will require the development of a low-cost intermediate-Btu gas process. 3.3.3 Mine-Mouth Coal-Conversion Processes Methods are under development for converting coal to high-quality fuels at the mine mouth; the fuels to be produced include (1) solvent-refined coal; (2) liquid fuels, including synthetic crude, boiler fuels, and methanol; and (3) pipeline-quality (high-Btu) gas. Solvent-refined coal is potentially the least expensive of the coal-derived fuels and looks especially promising if it can be remelted and used in the same manner as residual oil. Liquid boiler fuels may have promise for the future, but the cost is likely to exceed that of SRC. | The technology for producing methanol from coal is well developed, but the cost is too high for its use as an industrial fuel. Methanol is presently an important chemical feedstock, and this is the most likely use for coal-derived methanol. 26 Although _high—Btu (pipeline-quality) gas from coal may find limited application in small industries, the large industrial energy user has several coal-based options that are less expensive. 3.3.4 ‘Nuclear Energy With present technology, nuclear energy can supply industrial steam and electricity. The commercially available nuclear systems are very large, ranging from about 1800 to 3800 MW(t). 'With further development, nuclear energy may have the capability to match most of the higher-temperature process heat applications of industry. Another developmental possibility is a smaller reactor that more nearly matches the energy demand of industrial plants. One important advantage of nuclear energy is the low fuel cost. The major drawbacks to nuclear are (1) the long lead times required in the planning and construction of power plants and (2) the difficulties in gaining site approvals and the administrative burden associated with regulatory requirements. Conclusions concerning specific nuclear alternatives are given below. Large commercial nuclear power plants offer industrial steam and electricity at the lowest cost of the energy systems investigated. The mismatch in output of currently marketed nuclear plants and the consumption rate of individual industrial plants, coupled with the need for multiple units to provide reliability, will limit applications to joint uses of a nuclear power station. One desirable arrangement is for an electric utility to generate both electrical energy for the grid and thermal energy for local industries. This arrangement would require steam transport for a few miles in most areas. _ Process heat at 1000 to 1400°F might be economically supplied from large HTGRs, but process heat HTGRs are not commercially available. Such units could be developed, if warranted by market potential, using essentially current technology. A related area of technological development that ‘would be required is an economical means of transporting high-temperature thermal energy from the nuclear plant to the processes. 7 If fully developed, small [~300-MW(t)] land-based PWRs could become competitive with oil (at $10/bbl) and most coal-derived fuels for producing industrial steam and electricity. To be competitive with the lowest-cost coal systems, the capital costs of small reactors need to be reduced below present estimates. The development of factory-assembled barge-mounted units has the potential for reducing capital costs. Justification for this development by reactor manufacturers will depend on their perception of market potential. Another question that requires serious consideration is whether a large number of small reactors would be more difficult to regulate to assure the same high level of safety expected with current reactors. 27 4. Recommendations It is recommended that both government and industry reexamine their existing programs on the development and implementation of new energy technology in light of the critical national need for substitute fuels in industry. The .existing programs should be supplemented, where necessary, to assure adequate consideration of industrial requirements. As a general guideline, the recommended priorities on industrial energy systems are as follows: Coal systems Nuclear systems 1. First priority 1. First priority Fluidized bed combustion Dual-purpose utility-industrial nuclear power plants Solvent refined coal 2. Second priority 2. Second priority Regenerable stack-gas scrubbing Small reactors for industrial uses Low-cost process for intermediate-Btu Process heat HTGRs gas from coal Some specific recomendations are given below. 4.1 COAL SYSTEMS ® Implement a program to demonstrate fluidized-bed boilers for industrial uses. This demonstration program should be a joint effort between the government and industry and should include two or more projects with unit outputs in the range of 50,000 to 500,000 Ib/hr of steam. ® Perform design and cost studies to determine the feasibility and benefits of developing fluidized-bed process heaters. | ® Conduct analyses and tests on typical industrial boilers and process heaters to determine the feasibility of retrofitting these devices to burn solvent-refined coal. 4.2 NUCLEAR SYSTEMS ® Undertake a study to examine one or more realistic applications of commercial nuclear plants for the supply of industrial steam in the Gulf Coast area. The purpose of the investigation would be to determine the desirability of undertaking actual projects at specific sites. The applications envisioned would be similar to the Dow-Consumers Power arrangement at Midland, Mich. The study should be a cooperative undertaking involving the government, a power company, and one or more industrial groups. , : : ® Undertake a market survey of the geographical distribution of the industrial steam demand in the U.S. Estimate what fraction of the demand could be supplied in 1975 by hypothetical steam -utilitiqs. If nuclear plants were built in the 1980s for this market, determine what fraction of industry might be served by 1990 and by 2000. \ » ® Make a more detailed design and cost study of a factory-assembled, barge-mounted small LWR for industrial applications. This work should be oriented toward resolving the question of whether expected benefits justify a development program. A similar study should be made for a small HTGR. 28 ® Undertake a broad assessment of the costs, benefits, and market potential of advanced u gas-cooled reactors for producing high-temperature process heat. @ Make a study to determine the feasibility and extent of potential application of central station generated electricity for process heating. Although this alternative was not examined in the present study, it is another means by which both coal and nuclear energy could be applied in industry. 29 Part II. Energy Systems This part of the report presents the characteristics of both nuclear and coal-based systems which were considered in the study. (Technologies and costs are based on data for the first half of 1974.) Chapter 5, on nuclear systems, is comprised of an assessment of uranium resources, descriptive and economic information on commercial nuclear plants and a smaller reactor that is under development, a study of thermal energy (steam) transport from nuclear plants, and a brief treatise on nuclear licensing and regulation procedures and siting considerations. Chapter 6, on coal-based systems, contains an assessment of coal resources and includes technical and economic data on conventional coal firing with and without stack-gas cleaning; fluidized-bed combustion; low-Btu, intermediate-Btu, and pipeline- quality gases; and liquid boiler fuels and methanol from coal. An assessment of how these various systems might be suitably employed as industrial energy sources is presented in Part III. 5. Nuclear Energy Systems 5.1 ASSESSMENT OF URANIUM RESOURCES The nuclear fuel cycle consists of several steps from the extraction of uranium ore to the disposal of radioactive wastes. The question to be covered in this section is whether an expansmn of the nuclear mdustry to meet an increased industrial process heat load will cause any serious dislocations, due to limitations in the ablhty to increase the load on any of the fuel cycle items. Of particular concern is the avaxlabnhty and price of uranium, possible problems in acquiring the needed enrichment capacities, and ~ the ability of the capital market to furnish the needed money for expansion. 5.1.1 Uranium Availability Uranium is widely distributed, with an average concentration of2 to 4 ppm in the continental crusts and 0.003 to 0.004 ppm in the oceans.' It is more abundant than gold or silver and about the same as molybdenum or tin and is scattered in small deposits or in low concentrations. The chief present source of ore in the United States is in sedimentary strata (“conventional” deposits), particularly those found in 1. J. A. DeCarlo and C. E. Short, “Uranium,” pp. 21942 in Mineral Facts and Problems, Bureau of Mines Bull. 650, 1970. 30 the Colorado Plateau and in the Wyoming basin geologic regions. Most of our known low-cost reserves are located in these areas.’ Table 5.1 is an estimate of the cumulative uranium resource up to various cost-cutoff levels. Information is provided as to the reasonably assured reserves and for the estimated additional or - potential reserves. This latter category refers to additional uranium which is believed to exist in favorable geologic regions primarily adjacent to areas of known reserves. It does not account for possible discoveries of new mining areas or districts. Table 5.1. U.S. uranium resource (10° tons U305) Cost cutoff Estimated Total ($/Ib UsOg) RE°TY® dditional reserves resource 8 273 . 450 . 723 10 340 770 1,110 15 520 1090 1,610 30 780 1650 2,430 50 ; 7,400 - 100 | | 15,400 Uranium below the $30/1b U;Os cutoff for the most part comes from conventional deposits. The $10 and $15/1b cutoff potential reserve figures include 70,000 and 90,000 tons, respectively, of U3Os available from phosphate and copper production through the year 2000. The estimated resource at cutoffs of less than$15/1b is based on Jan. 1, 1973, AEC estimates.”” These values change yearly as more exploration is done. The $50 and $100/1b cutoffs® include uranium in Chattanooga shales. One layer of this shale contains 60 to 80 ppm U;Oz ($50/1b), and another layer contains 25 to 60 ppm U0z ($100/1b). This shale may also contain up to 15 gal of oil' per ton of shale. If we are reduced to mining this substance for its uranium upon exhaustion of the lower-cost resources, the possibility of an interesting by-product relationship may be achieved with oil production. In 2000, we may need about 150,000 tons of U3Os per year. If this comes entirely from 80-ppm uranium, 15-gal/ton oil Chattanooga shale, 670 million barrels of oil per year (1.8 million barrels per day) could be produced. | _ The reliability of the resource estimates shown in Table 5.1 decreases with higher price levels. This is because there is both uncertainty as to extraction costs for lower grade ores and a lack of incentive on the part of the mining industry to explore for, and to develop information about, reserves costing séVéral times the current uranium market value. _ Other potential sources include uranium in the lignite deposits in the western Dakotas and eastern Montana, which have an estimated 5 million tons of recoverable uranium® with concentrations ranging from 50 to 200 ppm and at least one deposit averaging 0.7% uranium.® There has been a small amount of commercial development’ of high-grade uranium deposits, but no reserve cost estimates have been . Statistical Data of the Uranium Industry, GJO-100, Grand Junction Office (Jan. I, 1973). . Nuclear Fuel Supply, WASH-1242 (May 1973). R. D. Nininger, “Uranium Reserves and Requirements,” WASH- 1243 pp. 10-27 (April 1973). . Hydrogen and Other Synthetic Fuels, TID-26136, pp. 61-63 (September 1972). . Uranium from Coal in the Western United States, U.S. Geological Survey Bulletin 1055, 1959. . Coal Resources of the United States, U.S. Geological Survey Bulletin 1225, Jan. 1, 1967.- -IO~U1:J:.LAJN 31 found. Here also, some co-product economics might be beneficial. The possibility of using the lignite ina gasification, liquefaction, or hydrogen® production process and extracting uranium from the residue may be economically feasible at some point. : There are also Conway granites® (10 to 20 ppm) containing about 8 million tons of U;Os which may be extracted at about $200/1b. The ultimate source of uranium is, however, the ocean, which contains a resource of about 4000 million tons. Cost estimates for recovery of this uranium are in excess of $200/ Ib. 5.1.2 Uranium Demand The most detailed information on the growth of nuclear power generation and its effect on uranium resource use can be obtained from AEC nuclear power demand estimations. The results of a recent study® are summarized in WAS H-1139 (72). In this discussion, the reference case is the “most likely” case projection used in that study. This case projects an installed nuclear-electric capacity of 1200 million kW(e) by the year 2000. An effective 0.2% enrichment plant tails will also be used. The use of 0.2% tails instead of the present 0.3% will reduce ore requirements but, at the same time, raise the separative work requirements. There are several reasons for making this choice. Because of the present split tails policy, the 0.2% figure is the effective tails currently seen by the enrichment customer, the difference in ore requirements being made up from government surplus. Also, if the conservative assumption is made that little or no additional low-cost uranium resources will be found, it follows that the price of uranium ore must rise. This in turn will lead to a lower tails enrichment, both from an economic and a resource conservation standpoint. Any assumption of a continued 0.3% tails would include with it an expanding reserve picture. The cumulative U3Os requirements for the reference case are shown in Fig. 5.1. Along with the cumulative U3Os requirement for an assumption of enhanced industry growth. This enhanced growth was assumed to be caused by the impact of industrial i)rocess heat. Starting in 1981, uranium requirements are assumed to increase cumulatively by 1%/year over the reference case uranium requirements. This means that by 2000, the yearly ore requirements will be 20% higher than the reference rate. ' 5.1.3 Uranium Price Projections ~ The question now is what effect'the enhanced uranium demand will have on the market price of uranium and on the fuel cycle costs of reactors In making any pro;ectlons as to future price of a commodity matenal one is necessanly on shaky ground. When the recent prlce changes in other energy resources (coal, oil, and gas) are factored in, the uncertamtles increase. "In maklng these estlmatlons, several assumptlons were made regardmg resource avallablhty and prrce response as the resource is depleted An attempt was made to be conservative in the assumptrons, * resulting in prices which should be considered on the hlgh side. It was assumed that the ultimate resource vallablhty is as given in Table 5.1, which means that the dtscovery rate is only sufficient to balance 'mining losses such as would be encountered by leavmg low-grade ores behmd because they are not economic.’ - : - An orderly conversmn of potentlal to assured reserves was also postulated This conversion rate " was assumed to be price sensitive, since as prices rise the mcentwes to explore also rise. At $10 /16 U30s, 5% of the potential reserves was assumed converted to assured reserves; at $15/1b, 25%; at $20/ 1b, 50%; - 8. Nuclear Power 1973-2000, WASH-1139 (Dec. 1, 1972). 32 ORNL-DWG 74-6163 25 I 1 REFERENCE PROJECTION — e e = REFERENCE + 1%/yr ENHANCEMENT Z 20 e ©O 2 'é o 15 - 2 2 < o D w 1.0 2 z > 27 2 O 05 / 0 1980 1985 1990 : 1995 2000 YEAR Fig. 5.1. Cumulative uranium requirements. at $25/1b, 75%; and at $30/1b, 100%. Figure 5.2 shows the present assured and total reserves as a function of price level. Also shown is the assumed behavior of the available reserves as a function of price level. For example, the latter curve shows that when the price of uranium reaches $20/1b (U;0s), there will be an accumulative availability of about 1.25 X 10° 1b extractable at this price or less. The available reserve vs price curve, however, does not determine what the market price will be. First, this curve is for cost of extraction and does not include any profits. Second, since it takes a finite time to deplete a given mining operation, not all of the lower-cost reserves will be used up before mining of the higher-cost reserves is begun. Also it takesabout 8 years from the start of exploratory drilling until production of the uranium concentrate begins.’ Before a mining company will undertake the development of a high-cost reserve, it must have reasonable assurance that the venture will be economic, which usually means competitive at current prices. It is postulated that an 8-year forward reserve of uranium at current prices is needed to assure adequate production.* In this analysis, an 8-year forward reserve was assumed to exist. The ore price at a given time was assumed to be the cost cutoff at the cumulative use 8 years in the future. For instance, for 1980, based on the reference demand curve, the cumulative uranium use from 1973 to 1988 is about 610,000 tons of U30s. The price from Fig. 5.2 is about $13.20/1b for this cumulative use, which is our projected U;Os price at the end of 1980. 9. “Future Structure of the Uranium Enrichment Industry,” Part 1, Phase 1, Hearing Before the Joint Committee on Atomic Energy, Congress of the U.S., July 31 and Aug. I, 1973. AVAILABILITY (108 tons U;0g) 10.0 5.0 2.0 1.0 0.5 0.2 - 01 33 ORNL-DWG 74-579 ¥ 7 L /. / TOTAL ESTIMATED RESOURCE — — / |7 FUTURE AVAILABLE R AS A FUNCTION OF PRICE LEVEL ESERVE — - REASONABLY ASSURED R ESERVES 10 20 30 40 50 PRICE OF U,0g (S'Ib) Fig. 5.2. US. urahium resource., 60 70 34 Figure 5.3 shows projected U;O; prices through the year 2000. Included are our estimates for the reference case, AEC base and high projections for our reference ore use,'® a projection made for Northeast Utilities,'' and some recently reported sale and asked prices.'>"? All figures except those for the Northeast Utilities are in 1973 dollars. ' A ~ Figure 5.4 shows our projected ore costs as a function of time for the reference case along with the enhanced-demand case. The discontinuity in the curves at $30/1b results from the transition to mining the Chattanooga shale. In the year 2000, based on our projections, the impact of increasing electrical capacity by 20% over the base case isabout $1.70/1b U30s. This amounts to $2.4 billion per year in added ore costs when the increased sales at the higher price'a_re factored in. The relative effect of uranium price on the fuel cycle costs for PWR, HTGR, and CNSG systems is shown in Fig. 5.5. These costs are based on a constant uranium price over the reactor lifetime, a 0.2% tails enrichment, and the utility economic ground rules (see Table 5.15). These curves indicate thata $1/1b ore price increase will cost 0.96¢/ 10° Btu for a CNSG system, 0.71¢ fora PWR‘system, and 0.49¢ for an HTGR system. 5.14 Uranium Enrichment ~ The reactors considered in this study use uranium enriched in the **U isotope. Only 0.71% of natural uranium is **U; the balance is mainly of the ***U isotope. Currently, this enrichment is done at three government-owned plants that use the gaseous diffusion enrichment process.'* These plants take uranium in the form of UFs and return uranium of the desired enrichment in the same form. The enrichment capacity of the present plants is 17.2 million separative work units (SWUs) per year. These plants are expected to be updated® to a capacity of 27.7 million SWU/ year by 1982, which - will be adequate to supply projected U.S. enrichment needs until the early 1980s. If no disruption in nuclear power is to occur, new enrichment capacity must come on line no later than May 1983 if present “most likely” projections hold. Current plans are to add enrichment capacity in units of 8.75 million SWU/year. If May 1983 is the startup date of a new enrichment plant, a second plant will be needed about 5 months later. Two plants so close together could cause procurement problems due to the industrial impact of two nearly simultaneous large orders. To assure an orderly development of enrichment capacity, it is estimated that approximately 18 months spacing is needed between plants. Therefore, the first enrichment plant should come on line by mid-1982. It will take from 6 to 8 years from the time a new enrichment plant is approved until startup, A decision is therefore needed sometime in 1974, If a present diffusion plant site is to be used, the decision could be delayed for about a year. Any reduction in the nuclear plant lead times or increases in orders above projections would hasten the time at which new enrichment capacity will be needed. Any increase in lead time or drop in orders below projections would delay this time. Therefore, there is stilladequate time, but decisions will have to be made in the near future if no disruption is to occur in the nuclear business. Two major decisions (one technological and one political) will have to be made before the next enrichment plant is authorized. The technological decision is the type of enrichment process to use, and the political question is whether this plant will be publicly or privately owned. 10. J. A. Patterson, Chief, Supply Evaluation Branch, Division of Production Material Management, USAEC, personal communication, Jan. 8, 1974, L. A Study of Base Load Alternatives for the Northeast Utilities System, report prepared for Northeast Utilities by A. D. Little, Inc. (July 5, 1973). 12. Nucleonics Week 14(48) (Nov. 29, 1973). 13. Nucleonics Week 14(47) (Nov. 22, 1973). 14. R. G. Jordan, The Oak Ridge Gaseous Diffusion Plant, K-C-922 (Sept. 15, 1967). URANIUM PRICE {$/1b-U30g) 35 ORNL-DWG 74-580 50 A—==—(\ DENNISON SALE TO TOKYO ELECTRIC O-====<0 BIDS TO TVA AEC HIGH 40 PRESENT EVALUATION 7 NORTHEAST UTILITIES / 30 0 s AEC BASE 10 0 2000 1970 --.1980 : 1990 - ' - YEAR Fig. 5.3. Comparative uranium price projections. PRICE OF U, 0, ($/lb) 30 ORNL-DWG 74—6175 50 40 20 NORMAL + 1% NORMAL GROWTH / 10 / 1970 1980 YEAR 1990 2000 Fig. 5.4. Uranium price projections for various industry growth rates. 37 ORNL-DWG 74-6164 20 CNSG 15 / g - ha » Z .‘—3 LWR = @ o« - 3 o 10 & Q o 3 HTGR o Qo = 2 Z o o = 5 o 5 10 ' 16 20 URANIUM PRICE ($/1b—U30g) Fig. 5.5. Effect of uranium price on fuel cycle cost. - There are two types of enrichment processes under active consideration: the gaseous diffusion - process and the gas centrifuge process. A third process, laser separation, has recently been suggested;'’ however, many technological obstacles will have to be overcome before it can be used to obtain large commercial quantities of enriched uranium. Its major advantage, besides yet undefined costs, is the possibility of extending uranium reserves by reducing the tails enrichment. The major advantage of the gaseous diffusion process is that the technology is already well developed. The chief disadvantage is that it uses a great deal of electric 'power. An 8.75 million SWU/year plant needs 2400 MW of electricity-generating capacity to satisfy its needs. 15. Nucleonics Week 15(2) (Jan. 10, 1974). 38 The principal advantage of the gas centrifuge process is that it uses about 10% of the electrical power used by the diffusion process. As the price of power rises, this will be of increasing importance. Its principal disadvantage is that it is an unproven technology except in the laboratory. Before a large-scale plant is built, there is need for assurance that the laboratory technology can be converted into a commercial manufacturing technology. The question now relates to future separative work prices. Currently, the charge for separative work is $36/ SWU; however, indications'® are that this will rise to about $41 to $42 by mid-1974 due mainly to the recent increase in TVA power costs. : The estimated separative work costs for a new gaseous diffusion plant range from $51 to $65/SWU, depending on financial assumptions and ownership of the facility, public or private. These prices contain a $24/ SWU power cost based on 10-mill power. The estimated separative work charge for a new centrifuge plant ranges from $30 to $45/SWU for government ownership and $40 to $60/SWU for private ownership. In analyses of future price trends, we assume that, at most, one more d1ffus1on process plant will be built. This, as well as the first centnfuge plant, will be government owned. All subsequent plants will be centrifuge plants and will be privately owned. Our reference price schedule is for an increase to $41/SWU in 1974, followed by a $1/ year increase until 1983, and constant at $50/ SWU thereafter. The price range of uncertainty is from $40 to $60/ SWU, which is the expected private ownership price range for the centrifuge process. Figure 5.6 shows the effect of variations in the separative work charge on fuel cycle cost for PWR, CNSG, and HTGR systems. These costs are based on the utility economic ground rules and a (.2% tails enrichment. 5.1.5 Fuel Cycle Capital Requirements The capital requirements for the projected expansion of nuclear power are large. By 2000, the 1.2 million MW reference “most likely” nuclear electric capacity will have cost about $600 billion [$500/kW(e)], not counting transmission line expansion. A 20% increase in nuclear capacity by 2000, as used in this report for the impact of industrial process heat, willadd another $120 billion to this total. In addition to this, capital must be expended to expand mining, milling, and enrichment capacity and to provide the necessary fuel preparation, fabrication, and recovery capacities. The largest capital expenditures in the fuel cycle will probably be in the mining and milling industries. Estimates of these capital requirements, which cover a period from present until 1990, range from $8 to $10 billion.”""™"? One estimate® for the period until 2000 is $18 billion. For the most part, these estimates assume that adequate quantities of $8/1b ore will be available and that a 0.39% tails enrichment will be used at the enrichment plants. Based on assumptions of no new increase in reserves and 0.29% tails, the capital requirements will be substantially larger than previously estimated. We estimate $6.5 to $9.5 billion for exploration, $7.5 to $12.5 billion for mine and mill development for the conventional uranium deposits, and another $25 to $35 billion for the development of the Chattanooga shales. The total mining and milling capital requirements to meet the reference nuclear capacity are therefore from $40 to $60 billion. The 20% additional nuclear demand case will add from $6 to $12 billion to these figures. 16. Nucleonics Week 14(52) (Dec. 27, 1973). 17. Resource Needs for Nuclear Growth, Atomic Industrial Forum, 1973. 18. D. F. Shaw, “Fuel Cycle Capital Requirements,” AIF Seminar on Nuclear Fuel, Chicago, 1ll., May 24, 1973. 19. J. M. Valance, “Nuclear Fuel Capital Requirements 1973-1990,” AIF Seminar on Nuclear Power—Financial Considerations, Monterey, Calif., Sept. 19, 1973. 39 ORNL~DWG 74-6165 25 20 / 3 s CNSG N, = = o - 2 @ a - = 8 15 b V O 8 HTGR b7 4 & O = PWR [ 11) 2 '— Lo o < 0. % 10 == 5 ' , 50 . 60 30 - 40 ' SEPARATIVE WORK CHARGE ($/SWU) _ Fig. 5.6. Effect of separative wori: chafge on fuel cycle éost. , The second largest fuel cycle capital cost component is new enrichment plants. By the year 2000, eight additional 8.75 million SWU/year plants will be needed to satisfy the U.S. reference projection demands at 0.29% tails. The cost of a new 8.75 million SWU/ year diffusion plant will be $1.2 to $1.4 billion.” In addition, 2400 MW(e) of generating capacnty will be needed for this process. The capltal cost estimates for the centrifuge process range from $1.1 to §1.7 bllhon for an 8.75 million SWU/ year plant. In addition, the capital cost of the necessary electric capacity is about $0.1 billion. The total enrichment plant capital cost for the reference nuclear demand is from $10 to $20 billion, dependmg on the process used. An additional $2 to $3 billion will be needed for the 20% additional nuclear capacity by the year 2000. The other fuel cycle items include the conversion, fabrication, reprocessing, shipping, and waste disposal steps. Capital costs per unit of throughput and scale factors may be extracted from several 40 references.'’*° The capital requirements through the year 2000 for those items are estimated as $8 billion for the reference demand case and another $1.5 billion for the 209% additional demand case. The estimated capital requirements are summarized in Table 5.2. The additional capital required for the 20% additional capacity case ($9 to $16 billion) is considered to be small when compared with the $120 billion which may be needed to build the nuclear systems. Table 5.2. Capital requu'ements through the year 2000 ¢ x 10%) Addition for Item : Base case . 20% expansion Exploration, mining, mlllmg 40-60 6—12 Entichment 10-20 2-3 Others ' 8 1-1.5 Total 58-88 9-16 5.2 COMMERCIAL NUCLEAR PLANTS 5.2.1 Introduction Commercial nuclear plants presently available are BWRs, PWRs, and HTGRs. Both BWRs and PWRs use slightly enriched uranium dioxide pellets as fuel and demineralized water as coolant and moderator. The HTGR fuel is a mixture of uranium carbide highly enriched in ?**U and thorium oxide. The moderator and core structural material is graphite, and the coolant is helium. With one exception, all large nuclear plants in the United States are .single-purpose electricity-generating plants. Unit 1 of the Consumers Power Midland Plant is designed both to generate electricity and to produce process steam for the Dow Chemical Company at Midland, Michigan. The reactor plant for unit 1 will generate 10,200,000 Ib/hr of prime steam. Of this amount, 400,000 1b/hr will be used to generate high-pressure process steam at 600 psi and 9,800,000 Ib/hr will be delivered to the turbine throttle. Turbine extraction steam will be used to generate 3,650,000 1b/hr of low-pressure extraction steam at 125 psi. Unit 2 will be a single-purpose electricity-generating plant. Standard sizes available range from about 660 MW(e) [1956 MW(t)] to 1320 MW(e) [3818 MW(t)] Overall plant efficnencws are about 33% for the PWR and the BWR and about 38% for the HTGR. The commercial BWR was developed and is marketed by the General Electfic ‘Company. Dresden 1, the forerunner of the large BWR, is owned and operated by Commonwealth Edison Company. Commercial service began in August 1960 and the rated capability of 200 MW(e) was reached in 1962. 20. Simcha Goiarn‘ and R; Salmon, “Nuclear F uél Logistics,” Nuclear News (February 1973). 41 - As shown in Table 5.3, General Electric is currently marketing the BWR-6 nuclear steam system in five standard sizes. - ' The first commercial PWR nuclear steam system was developed and marketed by Westinghouse Electric Corporation. Westinghouse and Duquesne Light Company started construction of the demonstration PWR power plant (Shippingport) in March 1955. This plant reached its full rated power of 150 MW(e) in December 1957. Combustion Engineering, Inc., and Babcock and Wilcox Company are now also marketing commercial PWR nuclear steam systems. Both the Westinghouse and Combusiion Engineering systems produce saturated steam using U-tube steam generators, while Babcock and Wilcox systems produce slightly superheated steam using a once-through steam generator. o - ' The Babcock and Wilcox nuclear steam system utilizes two coolant loops, each of which contains a steam generator and two primary coolant pumps. Table 5.4 lists the three sizes of these units presently being marketed. Combustion Engineering manufactures the nuclear steam system with two coolant loops, each with a steam generator and two reactor coolant pumps. Four sizes are given in Table 5.5. Westinghouse offers standard nuclear steam system designs with two, three, and four coolant loops. Current ratings are given in Table 5.6. The two-loop system is not available in the United States but is marketed abroad. Table 5.3. General Electric nominal plant ratings Fuel assemblies ' 580 560 592 732 784 Thermal power, MW(t) 1956 2444 2894 3579 3833 Electrical power, MW(e) 660 830 985 1220 1290 Steam pressure, psia 1040 . 1040 1040 1040 1040 Table 5.4. Babcock and Wilcox nominal plant ratings - Fuel assemblies 145 205 241 Thermal power, MW(t) 2643 3621 3818 Electrical power, MW(e) 880 1244 1320 Steam pressure, psia 925 1060 1125 Table 5.5. Combustion Engineering nominal plant ratings " . Fuel assemblies 1m0 217 217 - 241 *'Thermal power, MW(t) - 2825 3410 3473 3817 Electrical power, MW(e) 980 - 1160 1190 1305 Steam pressure, psig 900 900 1000 1100 42 The HTGR plant is relatively new to the electric utility industry in this country. The first HTGR constructed in the United States was the 40-MW(e) prototype Peach Bottom unit I, which is ~owned and operated by the Philadelphia Electric Company. General Atomic Company was responsible for the design of the nuclear steam system associated with this plant and for the research and development on both the plant and the nuclear fuel; thcy also supplied the major components of the nuclear steam system. ' . : General Atomic Company is also serving as prime contractor to Public Service Company of Colorado to construct the 330-MW(e) HTGR Fort St. Vrain Nuclear Generating Station. Like the Peach Bottom reactor, it was built under the USAEC Power Reactor Demonstration Program. Fort St. Vrain is the first plant in this country to use a prestressed concrete reactor vessel (PCRY). | The HTGR nuclear steam system built by General Atomic Company is available in two standard sizes, as shown in Table 5.7. Table 5.6. Westinghouse nominal plant ratings Number of loops - 2 3 4 4 Fuel assemblies ' 121 157 193 193 Thermal power, MW(t) 1882 2785 3425 3817 Electrical power, MW(e) 600 900 1150 1300 Steam pressure, psig 920 984 1000 1100 Table 5.7. General Atomic nominat plant ratings Number of loops - 4 6 Thermal power, MW(t) 2000 3000 Electrical power, MW(e) 770 1160 Steam pressure, psia 2415 2515 5.2.2 The BWR Power Plant The nuclear steam system The nuclear steam system includes a direct-cycle, forced-circulation BWR that produces steam in the core for direct use in the steam turbine. A diagram showing the major parameters of the nuclear system for the rated power conditions of 3579 MW(t) is shown in Fig. 5.7. Desxgn characteristics of the system are shown in Table 5.8. Fuel for the reactor core consists of slightly enriched uranium dioxide pellets sealed in Zircaloy tubes. These tubes (or fuel rods) are assembled into individual fuel assemblies. Gross control of the core is achieved by movable bottom-entry control rods which are cruciform in shape and are dispersed throughout the lattice of fuel assemblies. The control rods are positioned by mdmdual .control rod drives. 43 ORNL-DWG 74-5669A LEGEND # = FLOW - F = TEMPERATURE (°F) Hh = ENTHALPY (Btu/lb) = % MOISTURE P = PRESSURE (psia) M"‘ ISOLATION VALVES ASSUMED SYSTEM LOSSES THERMAL 1.1 ' MW MAIN STEAM FLOW - 15,396,000 # < > e . 1190.8 H 04 M - 985 P : 7 'MAIN FEED FLOW 26,700,000 # i 15,512,000 # 15,358,000 # - _ 3579 MW(t) - ~ 534°F, 529.1 h * 420°F, 397.8 h 420.0%F 75h : TOTAL ' \ . 0 39 2 RECIRCULATION LOOPS | CORE 20 INTERNAL JET PUMPS FLOW : 436%F ios.o X L 415.6 h _ s _ A 10°.# CLEANUP h 1.3 'DEMINERALIZER o Jflfb SYSTEM h. =527.9 ‘ ' o 154,000 ; CORE THERMAL POWER 3579.0 MW(t) 525733 hl= . PUMP HEATING 1 +101 - _ , CLEANUP DEMINERALIZER B " SYSTEM LOSSES -51 [_r__l OTHER SYSTEM LOSSES - 1.1 - 4 : TURBINE CYCLE USE 3582.9 MW(t) ' o - | 38,000 # RODDRiVE | 48" " FEED FLOW '80°F - FROM CONDENSATE STORAGE TANK r : . . Fig. 5.7. Heat balance at rated pbwer (ffom General Electric Company BWR/6 S_tandérd Safety Analysis Report). 44 Table 5.8. Design characteristics [3579-MW(t) BWR] ‘Thermal and hydraulic design Rated power, MW(t) 3579 Steam flow rate, 10° 1b/hr 15 Core coolant flow rate, 10°® o/hr : 105 Feedwater flow rate, 10° Ib/ht | 15 System pressure, nominal in steam dome, psia 1040 Feedwater temperature, °C (°F) 216 (420) Reactor vesse] design Material , Low-alloy steel/partially clad Design pressure, psig 1250 Design temperature,°C °F) 302 (575) Inside diameter, ft-in. ' 19-10 Inside height, ft-in. ' 70-10 Each fuel assembly has several fuel rods with gadolinia (Gd»0Os) mixed in solid solution with the * UQ,. The Gd,0:; is a'burnable poison which diminishes the reactivity of the fresh fuel. It is depleted as the fuel reaches the end of its first cycle. The reactor vessel contains the core and supportmg structures; the steam separators and dryers; the jet pumps; the control rod guide tubes; the distribution lines for the feedwater, core sprays, and liquid control; the in-core instrumentation; and other components. The main connections to the vessel include steam lines, coolant recirculation lines, feedwater lines, control rod drive and in-core nuclear instrument housings, high- and low-pressure core spray lines, residual heat removal lines, standby liquid control line, core differential pressure line, jet pump pressure sensing lines, water level instrumentation, and control rod drive system return lines. : The reactor vessel is designed and fabricated in accordance with applicable codes for a pressure of 1250 psig. The nominal operating pressure in the steam space above the separators is 1040 psia. The vessel is fabricated of low-alloy steel and is clad internally with stainless steel (except for the top head, nozzles, and nozzle weld zones, which are unclad). The reactor core is cooled by demineralized water that enters the lower portion of the core and boils as it flows upward around the fuel rods. The steam leaving the core is dried by steam separators and dryers located in the upper portion of the reactor vessel. The steam is then directed to the turbine through the main steam lines. Each steam line is provided with two isolation valves in series, one on each side of the containment barrier. ; The reactor recirculation system pumps reactor coolant through the core. This is accomphshed by two recirculation loops external to the reactor vessel but inside the containment. Each external loop contains four motor-operated valves and -one hydraulically operated valve. Two of the motor-operated valves are used as- pump suction and pump discharge shutoff valves. The third motor-of)erated valve is a small shutoff valve used to bypass the large discharge valve to warm the pipeline during hot standby. The fourth motor-operated valve is in a bypass line that bypasses both the flow control valve and the discharge shutoff valve; this valve is manually set in a_ fixed position to adjust the bypass flow. The variable-position flow control valve in the main recirculation pipe allows control of reactor power level through the effects of coolant flow rate on moderator void content. . The internal portion of the loop consists of jet pumps which contain no moving parts. These pumps provide a continuous internal circulation path for the major portion of the core coolant flow © P® N @ oA 45 and are located in the annular region between the core shroud and the vessel inner wall. A recirculation line break will still allow core flooding to approximately two-thirds of the core height—the level of the inlet of the jet pumps. | Load following is normally accomplished by varying the recirculation flow to the reactor. This method of power level control takes advantage of the reactor negative void coefficient. To increase reactor power, it is necessary only to increase the recirculation flow rate, which sweeps some of the voids from the moderator and causes an increase in core reactivity. As the reactor power increases, more steam is formed, and the reactor stabilizes at a new power level with the transient excess reactivity balanced by the new void formation. No control rods are moved to accomplish this power level change. Conversely, when a power reduction is required, it is necessary to reduce the recirculation flow rate. When this is done, more voids are formed in the moderator, and the reactor power level stabilizes commensurate with the new recirculation flow rate. No control rods are moved to accomplish the power reduction. A power range of control of approximately 35% can be achieved through the recirculation flow control system. For power ranges beyond this level of control, the control rods are moved. Ramp load changes up to 30%/min are available through use of the recirculation flow control. Correct distribution of core coolant flow among the fuel assemblies is accomplished by the 'usev of an accurately calibrated fixed orifice at the inlet of each fuel assembly. Each orifice is located in the fuel support piece. They serve to control the flow distribution and hence the coolant conditions within prescribed bounds throughout the design range of core operation. The core is divided into two orificed flow zones. The outer ;zone- is a narrow, reduced power region around the periphery of the core, and the inner zone consists of the core center region. Refueling is accomplished by removing the pressure vessel head and flooding the volume above the pressure vessel, thus providing for underwater handling of fuel and other reactor internals. Underwater storage of the irradiated fuel and reactor internal parts is accommodated by special pool storage facilities. ' The fuel loadmg is based on a 4-year cycle. Approxunately one-fourth of the core 1s replaced each year. The minimum downtime required for depressurization, cooldown, refueling, repressurization, and reactor startup is estimated to be 8 to 10 days. Aucxiliary systems are provided to perform the following functions: 1. purify reactor coolant water; . cool system components; = . . N ~ N remove residual heat when the reaétor is shut down; . cool the sbent-fuel storage pool'; sample reactor coolant water; provide for emergency core cooling; collect reactor containment dréins; . provide containnient spray; , o . prorvide containment ventilation and cooling; 10. pfocess liquid, gaseous, and sdlid wastes; 11. provide seal water for pipes penetrating containment following a loss-of-coolant accident (LOCA); - 12. provide redundant means of removing hydrogen from the confainment following an LOCA; 13. provide primary coolant leak-detection system; 14, i_rijeci borated water by a standby emergency liquid control system. - Balance of plant Theé turbine-generator system design is subject to some variation. A typical 1000-MW(e) plant would have a tandem-compound 1800-rpm turbine with one high-pressure and three low-pressure sections. Six combination moisture separator-reheater units are used to dry and superheat the steam between the high- and low-pressure sections. A typical heat balance diagram for a 1000-M W(e) plant is shown in Fig. 5.8. ' The containment structure completely encloses the entire reactor and reactor coolant system and ensures that essentially no uncontrolled leakage of radioactive materials to the environs would result even on gross failure of the reactor coolant system. The structure provides biological shielding for normal and accident situations and is designed to maintain its integrity under tornado wind loading, impact from tornado-generated missiles, storm winds, floods, earthquakcs, tsunamis, and other natural forces at their worst foreseeable mtens1ty within conservatively established recurrence intervals. ‘General Electric Company is currently marketing a containment and nuclear design designated the Mark 111, which is a complex of three buildings—the reactor building, the auxiliary building, and the refueling building. The Mark HI containment, shown in Fig. 5.9, uses pressure suppression with the dry containment layout. The dry well, which surrounds the reactor and primary coolant system, is a pressure boundary that channels steam from the blowdown following a postulated LOCA through the suppression pool. This pool is located in the bottom of a dry containment. A weir wall and three rows of horizontal vents are used to distribute steam flowing into the suppression pool. The entire volume of the containment is open to the suppression pool. The Mark I11 concept features an upper pool which provides shielding during normal operation and refueling and is used with the suppression pool for dry-well flooding following an LOCA. The containment structure is similar to that of a standard dry containment and can be designed either as a free-standing steel containment surrounded by a concrete shield building or as a concrete pressure vessel with a liner. The dry well is not lined, since it is a pressure barrier used to channel steam from an LOCA through the suppression pool and is not a primary leakage barrier. Auxiliary buildings are provided to house the spent-fuel storage and handling facility, the core standby cooling system, and other reactor auxiliary equipment. The turbme-generator building requires radiation shielding because of the direct cycle of the BWR. Steam generated in the reactor core conveys some fission products to the turbine. Fission product gases, '°N, and some radloxsotopes enter the turbine and turbine condenser. Approxnmately | 80% of the activity is discharged via the air ejector on the main condenser to a system utilizing catalytic recombination and low-temperature charcoal adsorption. The catalytic recombiner recombines radiolytically dissociated hydrogen and oxygen, and charcoal adsorptidn beds selectively adsorb and delay xenon and krypton from the bulk of the carrier gas, which is principally air. After e e et e i e " e . - e Coeeaes s o . o i Ao e e L Ao i ¢ = st s e . e ¢ e i e s s st . - e e ki i e i i e e e o+ on i < i = e n o = e S 47 ORNL-DWG 74-5670A , 493,884# 13,780,631# 968P 1191 5H _ 938.2P ' 685,363% 21< = 1157.94 813 g : 1 g = . 2 o d )STEAM T * , 2 11,086 979 MOISTURE &S REHEATER|E @ STEAM 9,622,125% 186,421 = v y SEPARATOR |2 & A - 9 REHEATER . ‘ 1083.6H 175.6P ~ A %ETD = & 26F TD [ 1279.6H 168.8P 1279.6H 165.5F .3 2441 % - - i < 2 “ , h 2| F.p ___I !; RFPT = 15,142 . ; (:h_fififi.flfi}fi . 493 884#% = kW 10841 552.2P 461.4h . #350.6P 534.8n | C) . = P,z 926.4 : ! i 186,421 :“' o 1002.4H 9,435,704 13,271,465# GENERATOR - [HIGH- 75 psig Hy Pressure _JPRESSURE 578.0F LOW-PRESSURE LOW-PRESSURE TURBINE l O o URBINE 8 5 o4 PRESSURE 5 TURBINE 14,120 Gen. Losses o o 3 ) gg B 161.5 5,066 Fixed Losses “ 5~ i o T D ‘ H I #i # Ry Hz BE 3l = ol = 2l 3 - \ ala |3 2 8 ol = o B il= gt gz " 5= P g’,‘ 5 = ~ o 6 0 o « T gl o~ \. @ o - : | CONDENSER and the process steam plant costs _Were estimated by modification of the electric plant estimates. | Prime steam for proccés,applica:tions from LWRs and HTGRs ‘Producing prime steam for process applications or extracting steam for process applications from an LWR is a matter of providing a reboiler and adjusting the turbine-generator size (or ‘eliminating it for total steam to process heat). Prime steara is approximately 1000 to 1050 psi and 288°C (550°F). Process steam can be generated at 850 psi and 274°C (525°F). The HTGR is a more complex system. Figure 5.20 illustrates the current HTGR concept and the limits of steam extraction conditions which can be achieved [approximately 500 psi and 399°C 84 Table 5.36. Annual operation and maintenance costs for 600-MW(e) " PWR stesm-electric plants (105 $) 1-Unit 2-Unit 3-Unit 4-Unit station station station station Fixed costs C - Staff 1.39 1.85 231 277 Fixed maintenance 0.95 1.69 2.30 3.06 Supplies and expenses 0.17 0.27 035 044 Insurance and fees 0.44 0.73 1.02 1.31 Administrative and general 0.25 . 0.38 0.51 0.63 Total fixed costs ' 3.20 492 6.59 921 Variable costs? Variable maintenance 0.47 0.88 127 1.65 Supplies and expenses 0.41 0.74 1.06 1.37 Total variable costs 0.88 1.62 2.33 3.02 Total annual O&M costs 4.1 6.5 8.9 11.2 “80% plant capacity factor. Table 5.37. Annual operation and maintenance costs for 1875-MW(t) PWR process steam plants (10° $) 1-Unit 2-Unit 3-Unit 4-Unit station station station station Fixed costs Staff 1.25 1.66 2.08 249 Fixed maintenance 0.49 0.85 1.20- 151 Supplies and expenses 0.11 0.16 0.21 0.26 Insurance and fees 0.44 0.73 0.49 0.61 * Administrative and general - 0.18 0.27 0.35 043 Total fixed costs 2.47 3.67 - 433 5.30 Variable costs? Variable maintenance 0.16 0.28 040 0.51 Supplies and expenses 0.13 0.20 0.27 0.34 Total variable costs 0.29 0.48 0.67 0.85 Total annual O&M costs 28 4.2 50 6.2 480% plant capacity factor. Table 5.38. Annual operation and maintenance costs for 764-MW(e) HTGR steam-electric plants (10° §) 1-Unit - 2-Unit 3-Unit 4-Unit station station station station Fixed costs Staff 1.66 2.22 2.77 3.32 Fixed maintenance 1.10 1.96 2.16 353 Supplies and expenses 0.28 0.31 042 0.51 Insurance and fees 0.45 0.76 1.06 1.37 Administrative and general 0.30 0.45 0.60 0.74 Total fixed costs 3.79 5.70 7.61 947 Variable costs® _ ' Variable maintenance 0.53 0.97 1.40 1.82 7 . Supplies and expenses 0.53 0.80 1.14 147 | Total variable costs . 106 1.77 254 3.29 Total annual Q&M costs 438 75 . 10.2 128 80% plant capacity factor. 85 Table 5.39. Annual operahon and maintenance costs for 2000-MW(t) HTGR process steam plants (10° $) 1-Unit 2-Unit 3-Unit 4-Unit station station station station Fixed costs . Staff o 1.50 1.99 249 299 Fixed maintenance 0.58 1.01 141 1.79 Supplies and expenses 0.17 0.19 0.25 0.31 Insurance and fees : 045 0.76 1.06 137 Administrative and general 0.22 0.32 042 0.51 Total fixed costs 2.92 _ 427 5.63 6.97 Variable costs® o Variable maintenance 0.19 0.34 047 0.60 Supplies and expenses 0.20 0.23 0.31 0.39 Total variable costs 0.39 0.57 0.78 0.99 Total annual O&M costs - 33 48 64 8.0 “80% plant capacity factor. Table 5.40. Annual operation and maintenance costs for 3832-MW(e) HTGR steam-electric plants (10° §) 1-Unit 2-Unit 3-Unit 4-Unit station station station station Fixed costs . e o Staff - 1,39 1.85 231 2.77 Fixed maintenance - ) 0.70 1.24 1.15 2.23 Supplies and expenses 021 023 0.30 0.38 Insurance and fees ) 036 057 0.79 1.00 Administrative and general 0.23 0.3 0.44 0.54 Total fixed costs 7 289 422 559 692 Variable costs® _ o , - Variable maintenance - 032 0.58 . - 0.84 . 108 Supplies and expenses - - 035 049 - 069 089 - Total variable costs - © 0.67 1.07 - 1.53 197 Total annua! O&M costs .. 36 53 . 71 89 80% plant capacity factor. Table 5.41 Annual operation snd maintenance costs for lOOO-MW{t) HTGR process steam plants (108 S) 1-Unit 2-Unit - 3-Unit 4-Unit ‘station ~ station = station station ‘Fixed costs _ . L e Staff ) ' 125 - 1.66 .. 208 249 Fixed maintenance - 063 066 - 092 134 Supplies and expenses : 013 ‘014, 018 - 023 Insurance and fees - 036 ... 057 0719 - 1.00 Admm:xtrativemdgeneral 0.20 025 032 0.41 Total fixed costs =~ . 257 0 328 . 429 547 Variable costs”. _ : ' o ' Variable maintenance - 013 022 031 . 039 Supplies and expenses - 014 017 022 027 Total variable costs ST 02T 039 053 0.66 Total annual O&M costs 28 - 3T 48 641 880% plant capacity factor. i = HELIUM i CIRCULATOR MAIN STEAM BUNDLE REHEATER BOILER FEED PUMP 571 psig by 10020F || Somm — - 1 5.3 X 105 tb/hr uP TO ! 53 106 § th/hr REBOILER AAAAARAAAAAADL VYUVVVV YV VYYY Fig. 5.20. 2000-MW(t) HTGR with process steam extraction. ORNL-DWG 745961 TURBINE GENERATOR . CONDENSER CONDENSATE PUMP 0 478°F FEEDWATER HEATERS 500 Ib/in.2 750°F o wm —=fpSTEAM TO PROCESS 250°F CONDENSATE RETURN 98 87 (750°F)]. The difficulty arises because the helium circitlators are an integral part of the turbine cycle; that is, the total prime steam flow passes from the high-pressure turbine through the circulator drives to the internal reheater No extractlon can be taken prior to the outlet of the reheater without rede51gn of the nuclear steam system. _ The nuclear system must be modlfied to prowde 650 psi and 399°C (750°F) steam. The helium circulator turbine would be rede31gned to utilize prime steam directly, and a resuperheater might be included in the cycle following the helium circulator. High-pressure, high-temperature steam [~2000 psi and 510°C (950°F)] would be available for power generation on site or for transfer through a reboiler to a secondary system for transport off site.* A preliminary evaluation has been made for the reboiler for isolation of the nuclear steam. For the LWR, heat is transferred from saturated steam at 1050 psi and 288°C (550°F) to saturated steam at 850 psi and 274°C (525°F). The log mean temperature dlfference is approxunately 14°C (25°F), and the heat transfer coefficient is assumed to be 1000 Btu hr L gy (°F)™" because of the favorable conditions of transfemng heat at saturated steam condmons on both sides of the tubes. For 10 Ib/hr steam, Quantity of heat U At A (surface area reQuired) = _ 980 X 10° Btu/hr 1000 (25) =39,200 ft?/10° Ib/ht . The direct cost of high-pressure feedwater heaters is typically $15 to $20/ft> of surface. It is assumed the reboiler would be of similar design. Assuming a total cost of $40/ft’ for the reboiler yields approximately $1,600,000 total cost for the reboiler or $1.60 per pound per hour of steam. The approximate unit cost for the reboiler, assuming industrial financing, would be . . $1,600,000 (0.222/year) 6 = 441106 ¢ cost = X 10° =4¢/10° Bt Unit cost = 000 000 To/hr (8760 hr/year) (980 Btu/lb) 0% = 44/10° Buu. The HTGR reboiler would have a ‘much higher temperature driving force but lower heat transfer performance in the supk:rheat regions. It is estimated to cost somewhat less than the LWR reboiler. The cost would depend on a - detailed analysns of the specific prime steam conditions ach:eved w1th the modified system *Recently the General Atomic Company proposed a “boosted reheat” cycle for HTGR process steam applicatidns. The - modified cycle is accomplished by adding a pressure control valve on the outlet line of the reheater. Other system components are identical to the HTGR cycle equipment. This cycle provides power from the high-pressure turbine and steam from the rcheater at 726 psia and 913°F rather than 571 psig and 1002°F as indicated in Fig. 2.20 from the conventnonal HTGR cycle. If a rebo:ler 1s used, steam to process would probably be about 650 to 675 psia and 750°F. 88 High-temperature process heat from the HTGR Modification of the HTGR to provide high-temperature process heat [in the order of 649°C (1200°F) or greater] would open up substantial additional opportunities for providing industrial energy. In a large modern refinery, approximately half of the energy requirement is in the form of process heat (other than steam) to heat fluids to process operatmg temperatures in the range of 260 to 538°C (500 to 1000°F). : There is not sufficient information at thls time to develop a cost estimate for a process heat HTGR. Indeed, substantial analysis and development work would be required to firm up a conceptual design for a process heat HTGR. The present average core outlet temperature is approximately 760° C (1400°F), and it is believed that a 899°C (1650° F) average core outlet temperature can be achieved with current fuel technology. This will require some analysis and proof testing, but it appears to be reasonably close at hand. Very preliminary estimates indicate that this may result in a fuel cycle cost increase of about 10%. Preliminary studies of providing process heat to a refinery illustrate helium as the secondary heat transfer fluid passing directly from the heat exchanger within the prestressed concrete reactor vessel (PCRYV) directly to the refinery. However, it is judged that this is not feasible for two major reasons: (1) isolation from possible radioactive or industrial contamination will very likely be required, and (2) helium is a poor economic choice as a fluid medium for transferring high-temperature heat over long distances. In the range of 871°C (1600°F), radioactive tritium can pass through the walls of the heat exchanger tubes and into the secondary fluid. The level of tritium concentration in the primary helium is maintained quite low, but the question of tritium must be evaluated and the additional attenuation of a secondary heat exchanger outside the PCRV must be considered. Conversely, the possibility of introducing industrial contaminants (petroleum, etc.) into the reactor vessel must also be considered and may in itself require a secondary heat exchanger. The allowable level of radioactive contamination in the fluid leaving the reactor site is too small to be measured by on-line instrumentation or monitors. A secondary heat exchanger allows samples to be monitored from the intermediate helium loop at frequent intervals with the added safety of an additional physical barrier. 5.3 SPECIAL-PURPOSE PWR FOR INDUSTRY 5.3.1 Background and Status of the CNSG Reactor The development of the Consolidated Nuclear Steam Generator (CNSG) for nuclear ship propulsion has been under way* at the Babcock and Wilcox Company since 1959. Some of the unique features of the plant design, including the once-through steam generator housed within the reactor vessel,.have already been demonstrated™ in the Federal German Republic nuclear ship “Otto Hahn,” which has operated successfully since 1969. The U.S. Maritime Administration has continued to sponsor work in the areas of design, testing, and evaluation of the CNSG concept, and current 34. R. W. Dickinson, S. H. Esleeck, and J. E. Lemon, “Nuclear Maritime—An Economic Revival,” paper presented at Spring Meeting of the Society of Naval Architects and Marine Engineers, Williamsburg, Va., May 24-27, 1972. 35. M. Kolb and W. Schumacker, “Performance of the First Core of the Otto Hahn,” Geselischaft Fiir Kernenergieverwertung, Germany, presented at the Symposium on Nuclear Ships, Rio de Janeiro, Brazil, May 31, 1972. . 89 efforts*are directed toward a 313-MW(t) application for propellmg a 600,000-ton tanker. Start of construction is hoped for within 1 or 2 years. The CNSG design is essentially based on current technology, and relatively little development would be required for process heat applications in the 300-MW(t) power range. If a construction contract were awarded in 1975, plant startup could take place in 1981. A larger land-based CNSG plant for generating 400 MW(e) of electrical power has been under study at Babcock and Wilcox for some time. The potential advantages of this type of plant in electric utility service include the ability to ,provide for utility power demand growth in smaller increments, thus reducing the temporary excess of installed capacity over demand, and shorter construction times than required for large nuclear central'stations Assuming that a detailed plant design could be developed in about 2 years and allowing about 8 years between project start and completion, plant startup might take place in 1985. - A detailed design has not been developed for this unit, and the plant costs are less well known than for the 313-MW(t) plant. The power costs presented for 600- and 900-M W(t) units are even more tentative, since they are based on interpolations of the major cost components of the 313- and the 1235-MW(t) plants. ' ' 5.3;2 Reactor Plant The CNSG is an integral water reactor with the core and steam generator inside the reactor vessel (Fig. 5.21) and an electrically heated pressurizer connected to the vessel externally.”” Four horizontally mounted reactor coolant pumps are located alternately with the steam nozzles at the reactor vessel nozzle belt. Feedwater nozzles are located in a nozzle belt below the steam generator. The reactor core consists of Zircaloy tubes _containirig slightly enriched uranium dioxide pellets enclosed by welded end plugs. The tubes are supported in assemblies by a spring-clip grid structure. The mechanical control rods are clusters of absorber rods that move in guide tubes within the fuel assembly. - : : : - The steam generator is a heltca]ly coiled, once-through unit located in the annulus above the top level of the core. The operation of the steam generator utilizes four sets of feedwater inlet and steam outlet nozzles. The steam generator incorporates counterflow heat transfer with tube-side boiling to produce steam at a constant pressure. The reactor coolant system operates at a constant average temperature over the normal load range. Majo'r" reactor parameters are shown in Table 5.42. The reactor containment shell (Fig. 5.22) is a free-standlng steel cylinder with elliptical heads. The containment vessel is supported at the bottom and has an operating floor approximately halfway up the containment. The center section of the upper head is removable for servicing and installation of major components and for refueling; it is fitted with a double seal. The personnel hatch, which is also a double-barrier design, is located near the operating floor, providing access for routine maintenance and inspection. The vapor-suppression pool is formed by a second cylindrical shell below the operating floor; the annular wet well is divided into eight separate compartments with one vent discharging into each compartment. A reactor building (Fig. 5.23) completely encloses the reactor and its pressure-suppression primary containment. This structure provides secondary containment when thc primary containment 36. “Shipbuilders Eye Nuclear Power Again,” Chem. Eng. News, July 29, 1974, 37. Preliminary Safety Analysis Report, Competitive Nuclear Merchant Ship Program, MA-940-01, prepared for the U.S. Maritime Administration by Babcock and Wilcox (February 1973). 90 ORNL—-DWG 74-7104 ' ROD DRIVE MECHANISM SUPPORT NOZZLE ci.osunl;‘ 00 0 REACTOR VESSEL - STEAM OUTLET DIFFUSER ROTATED FOR CLARITY ' . ‘2:__51! STEAM GENERA ROD GUIDES_AND CORE STRUCTURE FEED WATER INLET ROTATED FOR CLARITY CORE BARREL ASSEMBLY CORE SUPPORT ASSEMBLY "1 st "2—11" Fig. 5.21. Internal arrangement of 313-MW(t) reactor. 91 ORNL-DWG 74-7103 10" VALVE OUTSIDE ONLY 1ZER o , VALVE — INSIDE ...... \ , AND OUTSIDE ------- ’ t ' i |I i | e pamemamaaana CONTAINMENT COOLER e ceccc e w—— ! LETDOWN ] 38{_0" o | - REACTOR VESSEL | ( . . 'VAPOR *NOZZLE ROTATED %é'gEESS'ON A ' FOR CLARITY : Fig. 5.22. Containment arrangement of 31_3-MW(t) CNSG reactor. 1 CIRCULATING SYSTEM INTAKE 13 AND DISCHARGE 14 2 75-ton CRANE 15 VESSEL HEAD STORAGE 16 4 FUEL HANDLING POOL AND INTERNALS STORAGE 17- 5 125-ton CRANE 6 SPENT FUEL STORAGE 7 SPENT FUEL SHIPPING PIT 8 NEW FUEL STORAGE 9 REACTOR BUILDING 10 AIR LOCK 11 DEMINERALIZER 12 PRESSURE SUPPRESSION POOL Fig. 5.23. Nuclear steam supply for 313-MW(t) reactor with 90-MW(¢) turbine generator. 91-MW(e) TURBINE-GENERATOR REACTOR PRIMARY CONTAINMENT CONTROL ROOM SERVICE BUILDING PF ORNL-DWG 74-2333R 26 93 Table 5.42. 313-MW(t) reactor parameters System pressure, psia 1875 Core inlet temperature, °C (°F) 302 (574.5) Core outlet temperature, °C (°F) . 319 (604) Maximum thermal output, kW/ft 16.08 Operating pressure, psia 1875 Boiler feedwater temperature, °C (°F) 204 (400) Total steam generator flow, 1b/hr 1.254 x 10° Steam side design temperature, °C (°F) 343 (650) Steam side operating temperature, °C (°F) 287 (548) Steam side operating pressure, psia 700 is in service and forms the primary containment during fueling or tepair of the reactor system. The reactor building houses the refueling and reactor servicing equipment, new and spent-fuel storage facilities, and other reactor auxiliary or service equipment (demineralizers, standby liquid control system, control rod hydraulic system, and electrical equipment). From a safeguards consideration, the primary purpose of the secondary containment is to minimize ground level release of airborne radioactive materials and to provide for controlled and filtered release of the building atmosphere under accident conditions. 5.3.3 Power-Conversion Plant Three approaches for providing process energy from the reactor plant were evaluated: (1) electrical power only, (2) steam only, and (3) electrical power and steam. The CNSG power, steam, and feedwater conditions remained unchanged throughout. Under condition 1, steam at 700 psia and 287°C (548°F) (50° superheat) drives a 91,300-kW, 3600-rpm tandem-compound condensing turbine that exhausts steam at 2 in, Hg to a once-through water-cooled condenser. For conditions 2 and 3, it was assumed that the process steam would be generated in a reboiler in order to prevent the transfer of contaminants between the nuclear steam supply and the industrial processes. The process steam was assumed to exit from the reboiler at saturated conditions; the process steam flow rate is shown in Fig. 5.24 as a function of process steam temperature. The temperature of the returning process water was generally taken as 2°F below that of the reboiler. However, for process steam above 205°C (402°F), the returning water temperature was held constant at 400°F, corresponding to. the CNSG design feedwater temperature of 204°C (400°F). No makeup losses were assumed for the process steam system. The process heat delivered by the reboiler is shown in Fig. 5.25 as a function of process steam temperature. Under condition 2, CNSG steam at 700 psia and 287°C (548° F) flows through the tube side of the reboiler to generate 1.24 X 10° lb/ hr of 566 psia saturated steam on the shell side. To meet condition 3, electrical power is generated in a back-pressure turbine exhausting to a reboiler, which in turn genefates process steam. Turbine back pressures ranged from 67 to 515 psia, corresponding “to saturated process steam flows ranging from 934,000 Ib/hr at 49 psia to 1,218,000 Ib/hr at 423 psia respectively. Output from the turbine generator of course diminished with increasing back pressure, ranging from 5500 kW at 515 psia turbine exhaust pressure to 51,300 kW at 67 psia. The net generator output is shown in Fig. 5.26 as a function of process temperature. (X 10%) 09 PROCESS STEAM FLOW (Ib/hr) 1.0 94 ORNL-DWG 74—8845 1.2 1.1 300 | 400 PROCESS STEAM TEMPERATURE (°F) - Fig. 5.24. Process steam flow for 313-MW(t) CNSG as a function of steam temperature. 500 (X 10°) 1000 E 5 @ X 950 < I a2 w Q O 0@ . 900 95 ORNL-DWG 74-8842 ;0 - . . .. 400 . ~PROCESS STEAM TEMPERATURE (°F) - Fig; 5.25. Prodess heat for 313-MW(t) CNSG asa 'ffinction of steam temperature. 500 . ORNL-DWG 74-8844 75 25 \ NET GENERATOR OUTPUT [MW(e)) I 200 ’ 300 ' 400 500 PROCESS STEAM TEMPERATURE (°F) Fig. 5.26. Net generator output for 313-MW(t) CNSG as a function of process stcam temperature. 5.3.4 Description of 1235-MW(t) System Detailed plant designs for larger land-based CNSG stations have not been developed at this time. Studies by Babcock and Wilcox suggest that CNSG technology is directly applicable to power Jevels up to 500 MW(e), with power output limited by the size of the reactor vessel that can be fabricated in current manufacturing facilities. Plant operating conditions were assumed to approximate those of the 313-MW(t) CNSG described in a previous section. The reactor vessel diameter is about 17 ft 8 in., and vessel height is increased to about 38 ft; thermal output totals 1235 MW. The functional arrangement of the reactor containment, fuel-handling system, and reactor building remains as described for the 313-MW(t) plant. Two alternative power-conversion systems were evaluated. The first, intended for the genera- tion of electrical power only, consists of a 400-MW(e), 3600-rpm tandem-compound steam turbine-generator unit, supplied with steam at 700 psia and 287°C (548°F), exhausting at 2 in. Hg to a once-through water-cooled condenser. For the alternative system, intended for the production of process steam only, CNSG steam at 700 psia and 287°C (548°F) flows through the tube side of a reboiler to generate about 5 million Ib/hr of 566 psia saturated steam on the shell side. 5.3.5 Economic Analysis Capital and operating costs have been estimated for CNSG-type stations of 313 and 1235 MW of thermal capacity. The larger reactor has not been developed in as much detail as the 313-MW(t) shipboard-based design, and the cost estimates for the 1235-MW(t) station are therefore more tentative. However, the values derived are believed adequate for the purpose of evaluating the economic potential of the concept for industrial process energy applications. Plant capital costs Costs for the major components of the two CNSG nuclear steam supply systems summarized in Table 5.43 are approximately $63 million for the 313-MW(t) unit and $117 million for the 97 Table 5.43. Reactor system capital cost (103 $) 313 MW(1) 1235 MW(t) - Structures and 1mprovements - Yard work 800 800 Reactor building - 2,800 5,130 Diesel-generator building 150 300 Administration building 200 _ 200 Control room 500 500 Service building ' ‘ 200 200 Reactor containment - 2,340 3,070 : 6,990 10,200 Reactor plant equipment Nuclear steam supply, including radiation waste systems 33,900 49,000 Fuel-handling system 3 800 2,250 Radiation monitoring system 250 250 _ 34,950 51,500 Electrical plant equipment 1,300 4,000 Total reactor direct cost ‘ 43,240 65,700 Contingency 7 500 : 6,000 43,740 71,700 Construction facilities, equipment, services (6%) ' 2,624 4,302 Engineering and construction management services 4,374 10,755 Other costs (5%) ' 2,187 3,585 _ 52,925 - 90,342 Interest during construction (4 years at 10%) 9,791 Interest during construction (6 years at 10%) 26470 Total cost in 1974 B 62,716 116,812 1235-MW(t) system. These costs, which are given in 1974 dollars, include the interest during construction but exclude cost escalation for startup beyond 1974. The costs for the nuclear steam supply systems remained fixed in the economic evaluation of the two alternative power-conversion options examined. The capital costs given m Table 5 44 are for power—conversnon systems intended for the production of electrical power only Ll The cost of a reboiler and other components that might be requlred to utilize the process steam and to return the process water to the nuclear_steam supply system depends on the particular requirements of the energy user and is not included in the cost tabulations. The reboiler costs might increase the price of process steam from the 313-’MW(t) unit by about 4¢/10° Btu at an annual fixed charge rate of 13.9% and by 7¢/ 10° Btu for a 22.2% charge rate. The correspondmg values for the 1235-MW(t) CNSG are 4¢ and 6¢ /10° Btu respectively. Operatmg and maintenance costs The annual_'_operating and maintenance costs shown for the nu_éieér steam supply system in Tables 5.45 and 5.46 apply to both of the operating modes examined. The power-conversion system costs apply to the case of electrical power generation only. Operating and maintenance costs were not charged to the power-conversion system for the process-steam-only option. 98 Table 5.44. Power-conversion system capital costs (10> §) 313 MW(t) 1235 MW(t) Structures and improvements . Yard work _ 400 400 Turbine room and heater bay . _ 450 1,700 Intake and discharge structures 360 360 Administration building ' 100 100 .Service building 100 100 1,410 - 2,660 Turbine plant equipment ' " Turbine generator : _ 6,600 18,000 Turbine-generator foundation 150 400 Condensate, feedwater, other equipment 4,500 15,000 Instruments and controls ' - _L,100 1,100 12,350 34,500 Electrical plant equipment 2,000 6,000 Miscellaneous power-conversion equipment 900 3,000 Total power conversion system direct cost 16,660 - 46,160 Contingency (6%) . 1,000 2,170 17,660 48,930 Construction facilities, equipment, services (6%) 1,060 2936 Engineering, construction, management services (15%) : : 2,649 . 7,339 Other costs (5%) 883 2,446 _ 22,252 61,651 Interest during construction (4 years at 10%) 4,117 Interest during construction (6 years at 10%) | 18,064 Total cost in 1974 26,369 79,715 Table 5.45. Annual operatiné and maintenance éosfs a0’ s) for 313-MW(t) plant Turbine- generator - Nuclear steam Total plant . supply plant Operating staff . 150 .. 665 815 - Fixed and variable maintenance 132 437 569 Supplies and expenses - 30 . T4 104 Nuclear insurance 284 284 Operating fees , 25 25 Administration and general 50 200 250 In-service inspection 36 36 Total - 32 1721 2083 99 Table 5.46. Annual operating and maintenance costs (10° $) for 1235-MW(t) plant Turbine- Nuclear steam generator supply plant Total plant Operating staff : 180 : 855 - 1035 Fixed and variable maintenance Y 717 1084 Supplies and expenses 83 122 205 Nuclear insurance : ' 350 350 Operatingfees =~ = . : 80 80 Administration and genera - 60 240 300 In-service inspection . 36 ' 36 Total 690 2900 3090 Process heat and power costs Energy costs (in 1974 dollars) for 1981 startup of the process-steam-only plants are summarized in Tables 5.47 and 5.48. These costs are based on two alternative fixed charge rates, 13.9 and 22.29%/year, which are representative of utility and private industry financing re- spectively. Costs were levelized over a 30- and 20-year plant life respectively. A plant factor of 0.8, commonly assumed for large nuclear central stations, was used for the 1235-MW(t) CNSG plant. A Table 5.47. Summary of levelized production cost? for 313-MW(t) CNSG nuclear process steam plant . 13.9% Fixed charge rate 22.2% Fixed charge rate 108 $/year ¢/10% Btu 10% $/year ¢/10° Btu Fixed (':h_arges ' 8.9 . 111 141 178 Operating and maintenance costs 1.7 2 - 1.7 : 22 Fuel costs _ 3.2 ' 40 4.0 50 Total _ ' 13.8 173 19.8 o 250 %Costs in 1974 dollars; startup in 1981; 85% plant factor. Table 5.48. Summary of levelized production costs® for 1235-MW(t) CNSG . nuclear process steam plant 13.9% Fixed charge rate - 22.2% Fixed charge rate . 1 10° $/year #10°Bm .. 10° $/year ¢/10° Btu Fixed charges ~ . 16.8 57 26.8 91 Operating and maintenance costs 24 8 _ 24 8 Fuel costs 8.7 __1_3-(_)~ 10.7 35 Total 27.9 95 399 134 %Costs in 1974 dollars; startup in 1981; 80% plant factor. 100 plant factor of 0.85 was employed for the 313-MW(t) CNSG, since the smaller plant can be refueled more quickly. The basis for the fuel cycle costs is given in Appendix A. Process heat costs ranged from $1.73 to $2.50/10° Btu for the 313-MW(t) station and from 95¢ to $1. 34/ 10° Btu for the 1235-MW(t) plant. Tables 5.49 and 5.50 summarize the energy costs in 1974 dollars for the case of electrical power generation only, again considering fixed charge rates of 13.9 and 22.2%/ year. Electrical costs ranged from 26.0 to 38.0 mills/ kWhr for the smaller station and from 13.9 to 20.5 mills/ kWhr for the larger plant. ' | , Figure 5.27 shows the effect of changes in uranium ore prices on process steam costs for plant startup during the time period from 1981 to 1991. Over this 10-year span, the process energy costs for the 313-MW(t) unit increased by as much as 6%; the corresponding increase for the 1235-MW(t) plant is up to 9%. Costs are presented in 1974 dollars, and escalation is, of course, not accounted for in these comparisons. | For the two power levels investigated, the results show that the CNSG unit energy costs decrease considerably with increasing power level. Therefore, it became of interest to predict the power costs at intermediate power outputs in the range from 313 to 1235 MW(t). These results, shown in Fig. 5.28, were obtained by assuming that the plant capital costs could be represented by an equation of the form: | 4 ' ' Capital cost = A + (thermal power output)”, where A and n are constants. Experience has shown that this type of equation ca_h express the effect of unit size on costs reasonably well. Fuel cycle costs were derived from graphical interpolation. Table 5.49. Summary of levelized production costs® for 313-MW(t) CNSG nuclear electric plant 13.9% Fixed charge rate 22.2% Fixed charge rate 10® $/year mills/kWhr 108 $/year mills/kWhr Fixed charges 124 18.2 19.8 29.0 Operating and maintenance costs 2.1 3.1 2.1 3.1 -Fuel costs 3.2 4.7 4.0 59 Total 17.7 26.0 259 380 9Costs in 1974 dollars; startup in 1981; 85% plant factor. Table 5.50. Summary of levelized production costs” for 1235 -MW(t) CNSG nuclear electric plant 13.9% Fixed charge rate 22.2% Fixed charge rate 10° $/year mills/kWhr 10° $/year milis/kWhr Fixed charges 213 | 9.7 436 15.6 Operating and maintenance costs 3.1 1.1 31 11 Fuel costs 8.7 3.1 10.7 ' 38 Total 39.1 13.9 574 20.5 4Costs in 1974 dollars; startup in 1981; 80% plant factor. 300 200 ORNL-DWG 74-8843 | . 22.2% F C R. — e o T g @ 313 MWt % a 200 - l = ® - ' = 13.9% F.C.R. "‘B - 200 > 3 : :z T 1 ? w - ' & ' 139% F .C.R. Q - 8 100 |———u0 Q o a. 100 0 . 1981 1986 1991 YEAR OF PLANT STARTUP Fig. 5.27. Process heat cost as a function of plant startup time. ORNL—-DWG 74—8846 PLANT STARTUP 1981 . COSTS IN $1974 \22.2% F.C.R. . Sy 13.9% F.C.R. - MW(t) 800 1200 Fig. 5.28. Process heat cost as a function of plant capacity. 101 102 Although the costs shown are quite tentative, they are believed to be useful in illustrating the effect of reactor size on process energy costs for small- and intermediate-size special-purpose reactors. 5.3.6 Platform-Mounted CNSG Reactor The possibility of mounting large power reactors on floating platforms has been studied®® ™ for some time, and the commercial introduction of barge-mounted central-station type PWRs has been scheduled for 1985 by Offshore Power Systems of Jacksonville, Fla. One of the major incentives for - the development of floating nuclear power stations has been the scarcity of suitable reactor sites near the areas of large electrical power demand. Siting advantages probably will not be a major consideration in the: development of platform-mounted nuclear energy sources for industrial use; however, the advantages resulting from shipyard construction, including a shortened construction period, accelerated licensing procedures, and more economical construction, may be important. ~ The lower plant costs projected for shipyard construction are predicated on a market demand sufficient to result in the fabrication of a sizable number of duplicate units at one building yard. For example, a construction rate of four 3460-MW(t) PWRs per year is anticipated on a so called “mass production” basis at the Offshore Power Systems facility being readied at Jacksonville, Fla. A lower production rate of perhaps one or two units per year may be economical for small industrial energy reactors because they can be constructed in existing shipyards. | The potential impact of small floating industrial energy reactors on meeting the nation’s energy requirements is limited by the extent of the geographical region accessible to that type of plant. Thus, a brief survey was made to identify some of the waterways that might allow passage to a barge-mounted CNSG-type reactor plant. Figure 5.29 depicts the major inland waterways®' of the central and eastern United States; this extensive network of navigable channels includes nearly 7600 miles of waterways eithér completed or under construction with a minimum water depth of 9 ft. During part of each year, many of these waterways are maintained at a minimum depth of 12 ft, allowing passage of craft with as much as 11 ft of draft while allowing a 1-ft clearance beneath the hull.**™* Thus, a draft of up to about 11 ft appears acceptable for a barge-mounted industrial energy source. The beam and length of the unit are limited by the size of locks that must be passed through. These dimensions are 110 by 600 ft for the locks of the more extensively used waterways,*' "> limiting the barge beam to about 105 ft; the hull length permitted by the locks is considerably in excess of the length required for a small platform-mounted reactor plant. The vertical clearance under bridges places a further restriction on the dimensions of a floating power plant. A minimum 38. P. J. Daniel et al., A Floating Earthquake-Resistant Nuclear Power Statzon Report No. 182-1-1, prepared for the Oak Ridge National Laboratory (1968). 39. O. H. Klepper and T. D. Anderson, “Siting Cons:deratlons for Future Offshore Nuclear Power Stations,” Nucl. Technol. 22, 16069 (May 1974). 40. J. A. Ashworth, “Atlantic Generating Station,” Nucl. Technol, 22, 170-83 (May 1974). 41. “River Traffic and Industrial Growth,” Tennessee Valley Authority Information Office, September 1970 Revision, 42. U.S. Army Engineer Division, Ohio River Corps of Engineers, Cincinnati, Ohio, Division Bulletin No. I. 43. Personal communication from L. R. Hixon, Navigation-Engineering Branch, Tennessee Valley Authority, Knoxville, Tenn., Jan, 29, 1974, , 44. Letter from H. Boatman, Chief Operations Division, Department of the Army, Nashville District, Corps of Engineers, to O. H. Klepper, ORNL, Feb. 5, 1974, 45. Water Resources Development, Alabama, Department of the Army, U.S. Army Engineer Division, South Atlantic, Jan. I, 1973. C 103 ORNL-DWG 74-8840 & . g T w ..- [} STILLWATER v, ° 7 MiNNEAPOLIS (R 3 X st PauL MOl WIS, RED WING WINOW ?0}: &) LA CROSSE - — s S o PRAIRIE DU CHEWN : S "»..r*-;].___..__..._-._.._f \_'f'-h—"\- Q SIOUX CITY iOWA A . CLINTON Lo » B. MUSCATINE JQ 1 OMAHAY®) CoUNCIL BLUFFS w o N M‘APOL . ‘ '\, CINCINNATI B PORTSMOUTH B i o . W.VA. B Y el CHARLESTON / ) f TOPEKA® ' : I KANSAS CITY N R ) : SE/ Q- 3 AN & ¥ Y, : ' ‘ {s¥ L ouIRYILLE . . ! : : B arre, "\ __‘} MO Rpaear vt N ST . /.' e’ | KY. ) @ SPRINGFIELD A e ------ g e ] : h ; mn ¥ i —-" 1D Fad : -- R NGkt o CL:_L““ E/"J | . g i L NASHVILLE el KNOXYA T g A onE wie @ | GO ol oun mrer 3 K L A - ’ q E N N,‘ Q '-F‘-‘-—‘ '.-_' . @ ORLAHOMA CITY Q e o CHATTANOOGA eF S i ssEE B e - ! i "L SHEF FIELD S q.C. : gl & v 45 ' \ ot T TTLE ROCK @ Eh , ! v Y ' umr.nsymi \-.\ . | ‘-\ @ ALANTA < LM L : ; Bont SinMINGHA, ~ o ] GREENVILLE | , i . ® AUSTIN % ar AUMONT s V@Y G KE CHARL o.‘.' APALACHICOL o FLA PP PORT ARTHUR HOUSTON (o) ’ 7 GALVESTON MORGAN CITY VICTORIA ® TAMPA LEGEND ' | ¥ - % FT.DEPTH OR MORE 6FT. TO 9FT. DEPTH ! ' . : P UNDER CONSTRUCTION : : ’ * o . TENMESSEE VALLEY AUI’HORI" DIVISION OF . TENNESSEE - CUMBERLAND RIVER CANAL - MAVIGATION DEVELOPMENY & REGIONAL STUDIES REVISED JANUARY 1970 Fig. 5.29. Tennessee River and interconnected inland waterway system., 104 bridge height of about 57 ft is maintained over extensive regions of the waterways, *"***** allowing a total height of about 68 ft from the underside of the barge to the top of the superstructures. These dimensional restrictions can be met by the platform-mounted CNSG reactor concept developed by G. G. Sharp, Inc., under contract to the Oak Ridge National Laboratory,*® and on this basis it appears that many of the waterways shown in Fig. 5.29 would be accessible. For example, on the Mississippi River, passage is feasible as far north as mile 848, within 10 miles of Minneapolis, Minn. The Illinois River would be accessible to mile 231, within about 70 miles of Chicago, Ill. The Ohio River would be passable as far as Pittsburgh, Pa. The Cumberland River could afford passage to the floating unit as far as Clarksville, Tenn., and on the Tennessee River the barge could reach Chattanooga. Extensive regions of the United States East and Gulf Coasts would be accessible via the Intracoastal Waterway”™® and by coastwise voyage. Coastal bays, canals, and estuaries accessible to oceangoing ships provide further access routes to the sites of possible energy-- to 10-mile range of interest. ' Loss of heat is estimated to be 0.3 to 0.4%/ mile. Pressure drop is treated parametrically, with 12 psi pressure drop per mile being selected for an economic evaluatlon Figure 5.33 shows pressure drop as a function of steam rate. The steam line cost estimate includes a condensate return lme The estimate is believed to be conservative. It is substantially higher (by about a factor of 2) than other recent estimates of similar steam lines; however, sufficient information for a detailed comparison is not available. Table 5.54. Steam line cost study — cost estimate summa:jr Indirect costs Material _Lab or 25% Total 36-in.-diam pipe, 1 in. wall thick, $1,760,000 $1,190,000 $738,000 $3,900,000 6-in. insulation with Al jacket : o Mobilization and special equipment (6%) ) o 4 . 212,000 - . $3,900,000 Condensate return line (~15%) ‘ 600,000 Contingency (~10%) S | ' 400,000 Total cost per mile ’ B ' ' : o ' $4,900,000 24-in -diam pipe, sched 40, = ' $833,000 $596,000 - $357,000 $1,786,000 6-in, insulation with Al jacket o : : : ' Mobilization and special equipment (6%) _ : _ - : 114,000 | - ~ $1,900,000 Condensate return line (~15%) o . - 300,000 Conti'nggncjr (~10%) ) ' 200,000 Total cost per mile - . : ' - o ' - - $2,400,000 30-in.-diam pipe, 0.88 in. thick, (Extrapolation of 24- and 36-in. pipe estimates), 6-in. insulation with Al jacket Total cost per mile - - : - $3,600,000 20 *PRESSURE DROP PER MILE (Ib/in.?) 18 16 14 12 10 ORNL-DWG 74-12808 h-.-. 3 PiPE \ -~ 24 Pipg I O‘I n ~F \ 3 ‘ &, - \36‘\,0 / / "?’ / S ‘-."--_-‘-L 24 ) \12 ib/in.2 ‘PRESSURE DROP PER MILE HAS BEEN ASSUMED FOR DESIGN PURPOSES I/ / / ,/ /// | / ./i // / /_/‘ /S A 850 Ib/in.2, 525°F | wae === G50 Ib/in.2, 750°F *BASED ON 6000 ft EQUIVALENT STRAIGHT RUN PIPE l l '05 1.0 1.5 2.0 STEAM RATE (lIb/hr) Fig. 5.33. Pressure drop as a function of steam rate. 2.5 3.0 (X 105) ETT 114 The estimates are based on steam transportation via a single pipeline over the size range shown. For larger flows, it is expected that multiple lines would be required. Therefore the costs presented in Fig. 5.34 cannot be directly extrapolated to larger flows. Based on the estimate, the unit transportation cost per mile varies from 6¢/10° Btu at 2 X 10° Ib/hr to 7¢ to 8¢/10° Btu at 10° Ib/hr (Fig. 5.35). Considering the economic advantage of nuclear steam vs alternate fossil sources, one could conclude that transportation of nuclear steam up to about 10 miles is practical and economically attractive in comparison to alternate fossil sources that were considered. [Details of the steam line cost estimate are given in Appendix B.] ORNL--DWG 74-12808 6 ~ P 5 / = = [#1) o 2 7 5 3 -t O . a / = O S = s 2 ————— 850 Ib/in.2, 525°F — = — 650 Ib/in.2, 750°F . 12 Ib/in.2 PRESSURE DROP PER MILE 1 } 250°F CONDENSATE RETURN 0 0 ' 1 | | 2 MILLION POUNDS OF STEAM PER HOUR Fig. 5.34. Unit transportation cost vs flow rate, UNIT TRANSPORTATION COST PER MILE (¢/108 Btu) 115 ORNL-DWG 74-12795 e 8500 1b/in.2, 525°F ——— =650 ib/in.2, 750°F 12 Ib/in.2 PRESSURE DROP PER MILE 250°F CONDENSATE RETURN 05 100 1s MILLION POUNDS QF STEAM PER HOUR Fig. 5.35. Total capital cost vs flow rate. 20 116 5.5 NUCLEAR PLANT SITING, LICENSIfiG, AND REGULATION 5.5.1 Licensing and Regulation Introduction The acquisition and use of a nuclear power plant are subject to the restrictions of the Atomic Energy Act of 1954 (AEA), as amended. Generally, the AEA prohibits, except under AEC license, the transfer or receipt in interstate commerce, manufacture, production, transfer, acquisition, possession, use, import, or export of nuclear reactors and the materials used in or produced by nuclear reactors.”> The AEA authorizes the AEC to formulate rules and regulations and to issue general and specific licenses for these activities. The AEA prescribes conditions for various types of licenses and sets out the judicial review and administration procedures to be applied to regulatory actions of the AEC. Generally, the provisions of the Administrative Procedure Act™ are invoked. AEC regulatory actions are also subject to the requirements of the National Environmental Policy Act (NEPA) of 1969.% | A firm intending to use a nuclear power plant may be required by law to obtain one or more of the following types of licenses, depending upon the relationship of the firm to the necéssary facilities and activities: special nuclear material, source material, byproduct material, utilization facility. Individuals operating a nuclear reactor are licensed by the AEC also. Specialized terms used in AEC licensing Byproduct material. The term “byproduct material” means any radioactive material (except special nuclear material) yielded in or made radioactive by exposure to the radiation incident to the process of producing or utilizing special nuclear material.> : Financial protection. The term “financial protection” means the ability to respond in damages for public liability and to meet the costs of investigating and defending claims and settling suits for such damages.” , ' ' Nuclear reactor. “Nuclear reactor” means an apparatus, other than an atomic weapon, designed or used to sustain nuclear fission in a self-supporting chain reaction.” Operator. The term “operator” means any individual who manipulates the controls of a utilization or production facility.* | Person. The term “person” means (1) any individual, corporation, partnership, firm, association, trust, estage, public or private institution, group, Government agency other than the Commission, any State or any political subdivision of, or any political entity within a State, any foreign government or nation or any political subdivision of any such government or nation, or other entity; and (2) any legal successor, representative, agent, or agency of the foregoing.* 53. AEA, sects. 57, 62, 81, and 10i. Certain activitics conducted by the AEC, the Department of Defense, and their contractors are expected. 54. Public Law 404, 79th Congress, approved June 11, 1946, 55. Public Law 91-190. 56. Definitions quoted from AEA. 57. Definitions quoted from 10 CFR, Part 50. 117 Production facility. “Production facility” means: (I) Any nuclear reactor designed or used primarily for the formation of plutonium or uranium 233; or (2) Any facility designed or used for the separation of the isotopes of uranium or the isotopes of plutonium, except laboratory scale facilities designed or used for experimental or analytical purposes only; or (3) Any facility designed or used for the processing of irradiated materials containing special nuclear materials, except (i) laboratory scale facilities designed or used for experiméfital or analytical purposes, (ii) facilitics in which the only special nuclear materials contained in the irradiated material to be processéd are uranium enriched in the isotope U-235 and plutonium produced by the irradiation, if the material processed contains not more than 107 grams of plutonium per gram of U-235 and has fission product activity not in excess of 0.25 millicuries of fission products per gram of U-235, and (iii) facilities in which processing is conducted pursuant to a license issued under Parts 30 and 70 of this chapter, or equivalent regulations of an Agreement State, for the receipt, possession, use, and transfer of irradiated special nuclear material, which authorizes the processing of the irradiated material on a batch basis for the separation of selected fission products and limits the process batch to not more than 15 grams of special nuclear material.”’ Source material. The term “source material” means (l) uranium, thorium, or any other material which is_determined by the Commission pursuant to the provisions of section 61 to be source material; or (2) ores containing one or more of the foregoing materials, in such concentration as the Commission may by regulation determine from time to time. Special nuclear material. The term “special nuclear material” means (1) plutonium, uranium enriched in the isotope 233 or in the isotope 235, and any other material which the Commission, ~ pursuant to the provisions of section 51, determines to be special nuclear material, but does not include source material; or (2) any materlal art1f1c1ally ennched by any of the foregoing, but does not include source material.>. o | Utilization facility. “Utilization facility” means any nuclear reactor other than one designed or used primarily for the formation of plutonium or U-233.” AEC rules and regulations The AEC rules and regulations are modified in Title 10, Code of Federal Regulations, Chapter 1. The parts of this chapter of interest to prospective nuclear reactor licensees are as follows:’ l.-statcment of organization and general information; = 2. rules of pract"iCe; . | e 8. interprefations; 9. pubhc records, | 20. standards for protection against radlatlon | 30. rules of general applicability.to licensing of byproduct material; 31. general licenses for byproduct material; | 32 specific licenses to manufacture, distribute, or import exempted and generally licensed items containing byproduct material; 33. specific licenses of broad scope for byproduct material; 118 34. licenses for radiography and radiation safety requirements for radiographlc operatlons 35. human uses of byproduct materlal | | | 40 licensing of source material; 50. licensing of production and utilization facilities; 55. operators’ licenses; 70; speci_al nuclcar material; 71. packaging of radio-active material for transport and transpor'tation of radio-active material under certain conditions; 73. physical protection of special nuclear martcrial; 100. reactor site criteria; 140. financial protection requirements and indemnity agreements; 170; fees for facilities and materials licenses under the Atomic Energy Act of 1954, as amended. Nuclear power plant licensing is dominated by the processes of AEC safety and environmental evaluation of the nuclear reactor (the “utilization facility™) itself. The necessary materials licenses, subject to the appropriate parts of the regulations, are considered by the AEC as part of the utilization facility licensing process. - The rules and regulations, which are issued under statutory authority, are enforcible by the AEC through administrative action of the Commission itself and through judicial action in appropriate federal courts. ' Other official regulatory guides. The AEC has published numerous guides of interest to prospective reactor licensees. A consolidated series of Regulatory Guides was instituted in 1972. The distinction of guides from regulations is stated by the AEC as follows:*® “The primary purposes of Regulatory Guides are (1) to describe and make available to the public methods acceptable to the AEC Regulatory staff of the implementing specific parts of the Commission’s regulations and in some cases to delineate techniques used by the staff in evaluating specific problems or postulated accidents and (2) to provide guidance to applicants concerning certain of the information needed by the Regulatory staff in its review of applications for permits and licenses. Regulatory Guides are not intended as substitutes for regulations, and therefore compliance with these guides is not required.” The major divisions of the Regulatory Guides are as follows: 1. power reactor guides, 2. research and test reactor guides, ~ 58. U.S. Atomic Energy. Commission Dlrectorate of Regulatory Standards, Regulatorv Guides—Preamble, Dec, 12, 1972. 119 . fuels and materials facilities guides, environmental and siting guides, . materials and plant protection guides, . product guides, . trarisportation guides, . occupational health guides, O 9 oo o W . antitrust review guides, 10. general guides. The guides are predominantly technical in content, and those dealing with safety of power reactors (division 1) would usually be of greater interest to the designer than to the person owning and operating the plant. However, since ultlmate responsibility for safety would reside with the latter, he should be familiar with the guldes The hcensmg process The formal licensing process’ ? starts with the filing of an application for license (or construction permit) with the AEC and ends (if the license is issued) with the termination of the license through AEC-approved transfer or dismantling of the facility. The description of the process is presented in generally nontechnical terms to introduce the subject to persons not familiar with AEC licensing. Many details will be passed over casually; nothing more nor less than the AEC rules and regulations themselves would describe the licensing process precisely. Several formally distinct groups of people act for the AEC in licensing actions. These groups are identified in Fig. 5.36 and described below. Commission. The five-member Commission exercises the final authority with the agency with respect to determination of major or novel questions of policy, law, or procedure.”’ Licensing decisions or actions of an Atomic Safety and Licensing Appeal Board (ASLAB) may be reviewed by the Commission on its own motion in some circumstances. Atomic Safety and Licensing Appeal Board. A three-member tribunal reviews initial decisions arising from public hearings of an Atomic Safety and Licensing Board (ASLB) and considers any exceptions to such decisions as may be filed by a party to the proceeding. The Commission has authorized the ASLAB to exercise the authonty of the Comm1ss1on with respect to such appeals and will not entertain a request for rev1ew of an ASLAB decision or action. Atomic Safety and Licensing Board. This. board conducts hearmgs and issues decisions in proceedings to grant, suspend, revoke or amend licenses. ' Regulatory staff. The Director of Regulatlon of the AEC and the officials under his authority pelform the administrative review of an application for a license. They discharge other licensing functions, except where a final decision rests with an ASLB. The regulatory staff refers applications for power reactor licenses to the Advisory Committee on Reactor Safeguards (ACRS) and to the 59. A brief description of licensing of nuclear power reactors by electric utilities as published by the AEC is reproduced as Appendix C. 60. 10 CFR, sects. 2.762, 2.785, and 2.786. 120 ORNL-DWG 74-12811 ATOMIC SAFETY > AND LICENSING < - — APPEAL BOARD Ultimate level of appeal from parties in ASLB hearing — Final determination of decisions i | Y ATOMIC SAFETY AND LICENSING BOARD Conduct of public hearings Determination of initial decision PUBLIC ——————> APPLICATION, REQUEST, OR APPEAL —— — — & DECISION, ORDER, ADVICE, OR LICENSE Fig. 5.36. AEC licensing functions and relationships. CONMMISSION ADVISORY (The Five Commissioners) COMMITTEE ON REACTOR 'SAFEGUARDS o 1 Review of certain decisions Review and I and issues at own or Appeal report on | Board initiative applications | —— REGULATORY STAFF | Evaluation of - I - ] applications for - - o ficenses . ‘ Determination of ~ proposed licensing N decision \\ & Issuance of licenses - - - . APPLICANT 121 Attorney General (for review of antitrust matters). The regulatory staff is a party to the public hearing before an ASLB. The regulatory staff issues h(.enses and amendments to licenses, including those ordered by a board or the Commission. ' Advisory Committee on Reactor Safeguards. This committee, appointed by the Commission, is required by law to review and report to the AEC on each application for a power reactor license. The phases of the licensing process are listed in Table 5.55. Licensing may proceed with great variation in detail; therefore, only the general features of the process are described. The times indicated are also nominal representative values. - ' Before AEC licenses are applied for, the anticipated construction and operation would be planned and defined in sufficient detail to comply with the AEC guides for preparation of Environmental Reports (ERs) and Safety Analysis Reports (SARs). During the first step, the supplier of the nuclear steam supply system and the architect-engineer would be selected. Usually these firms prepare the portions of the SARs pertaining to their respective parts of the job. The SAR is the basis for the AEC’s safety decision. Information needed for the AEC’s consideration of environmental quality would also be developed for the ER, usually ‘with the assistance of consultants in specialized ficlds, like aquatic ecology, if the applicant lacks expertise. The scope and depth of these requisite documents are indicated by the tables of contents of the AEC guides shown in Appendices D and E. ‘ ' ' The AEA requires a two-step-licensing process: a construction permit and an operating license. This statutory constraint plus practical licensing problems have led to two-step applications. The Table §.55. Licensing steps for nuclear power plants " Time from start Step of construction ' Description (vears) 1 -3to —1'/2 Preparation of application for license (including a construction permit) 2 -1 1/2 | Application for license 3 -1 l/2.t0 —I/g Regulatory staff revnew, including review by the ACRS a.nd the Attorney General 4 ’ '-1/3 to -—'/5 ' ASLB public hearing (mandatory) ' 5 0o o " Issuance of construction permit 0 . On-site construction commences - 6 Oto$ _ Regulatory staff inspection of construction 7 3‘/2 to 41/2 Lo ' Submittal of any information required to complete the application for an . - _ _ope;ating license and to comply with the terms of the construction permit 3'/2‘ to'4% . Regulatory staff review of the amended application for license ASLB public hearing (if requued by circumstances) 10 5 Determination by regulatory staff that the facmty construction is complete in ' _ accordance with the constructlon permlt 11 5 ' Issuance of operating license - 5 Operation commences with initial fuel loading, followed by a few months of plant testing before routine operation begins 12 Sto4d5 Operation: regulatory actions include inspection, operatmg report evaluation, and authorization of changes in license conditions 13 40 Termination of license 122 application for a construction permit includes a preliminary SAR (PSAR), an ER, and other information concerning matters of financial qualifications, antitrust, and national security. It is also permissible to present at this time all the technical information requisite for an operating license. ~ While this has not been a useful option to date for applicants proposing to construct power reactors, the development of highly standardized designs could change this situation. , In step 2 the application is submitted to the Director of Regulation, who heads the AEC’s ‘regulatory staff. After a quick preliminary review (about 30 days), the regulatory staff determines whether the application is reasonably complete. If so, the staff review and other formal licensing processes commence. An application fee, prescribed by 10 CFR, Part 170, is required, as shown in Table 5.56. Applications for multiple-reactor installations may be combined, but separate licenses will be issued. - Table 5.56. Schedule of fees Application fee S . Annual fee after Facility for construction : .Consu:uctxc:!n O pera_tmgb issuance of . permit fee license fee . permit operating license Power reactor® $70,000 $60,000 + $30/MW(t) $125,000 + $95/MW(t) $12/MW(t) ‘ ($12,000 minimum) “When construction permits are issued for two or more power reactors of the same design at a single power station that were subject to concurrent licensing review, the construction permit fee for the first reactor will be $60,000 + $80/MW(t) and $30/MW(t) for each additional reactor. Thermal megawatt values refer to maximum capacity stated in the permit or license, ?When operating licenses are issued for two or more power reactors of the same design at a single power station that were subject to concurrent licensing review, the operating license fee will be $125,000 + $95/MW(t) for the first reactor and $95,000 + $60/MW(t) for each additional reactor. “For construction permits and operating licenses for power reactors with a capacity in excess of 3000 MW(t), the fee will be computed on a maximum power level of 3000 MW(t). The regulatory staff review, step 3, is the fundamental process in which all of the requirements of law and policy are applied to the case. The more visible parts of the staff evaluation deal with technical safety and environmental issues, but the staff also determines if the questions of financial qualification, national security, and antitrust are properly settled. Ancillary licenses for licensable materials are considered in due course to permit the receipt, inspection, and storage of fuel materials on site at the proper time. Without exception, the safety and environmental issues require preparation of supplementary information by the applicant. During the period of staff evaluation, the ACRS also considers the case. Numerous meetings of applicant, staff, and ACRS are usually held to exchange technical information, but the formal evaluation must rest upon the data formally submitted to the AEC. In step 4, the formal issues defined by law and regulation are considered in a public hearing conducted by an ASLB. The applicant and the regulatory staff are always parties in this hearing, and other interested persons may intervene either pro or con. The formal issues are summarized below: 1. health and safety of the public, 2. technical and financial qualifications, ¥ % N o wm oA W 123 common defense and security, | national environmental policy, consistency with antltrust laws (generally considered in a separate pubhc hearmg) confllctmg apphcatrons for fimited opportumty, , consistency with the AEA, “compliance witlr AEC regulations:,‘ useful purpose | | The applicant bears the burden of proof in favor of issuing a construction permlt The regulatory staff may favor or oppose this proposal, but as a practical matter, it is unlikely that an applicant would pursue his case to this point in the face of staff opposition. The ASLB issues an initial decision based upon the evidence presented. The decision may be appealed to the ASLAB by any part to the proceeding. The ASLAB may refer the case to the Commission for certain determinations or the Commission itself may initiate a review in certain instances. A decision to issue a construction permit is made by the Director of Regulation. . The construction phase, step 6, must be conducted in conformance with the terms of the permit. 'Regulatory staff inspectors check on-site and shop activities during this time. This phase is also generally the time when final designs and final safety evaluauons are developed by the applicant and his contractors. In the course of their construction permit review, the regulatory staff identifies subject areas in which additional or more definite information must be presented in the FSAR. The SAR guide also indicates areas, such as plant staffing, in which little specific information is needed until operation is imminent. The time for presenting this information to the regulatory staff, in step 7, can be chosen by the applicant; in any case, it should precede the expected date for loading nuclear fuel by at least 12 months. The operating license consideration by the regulatory staff, step 8, is similar to their earlier 7 review in that the basic issues are the same and the ACRS is consulted. The construction permit is not a guarantee that an operating license will be issued, and new safety issues may be raised. Houvever the normal continual contact between applicant and regulatory staff during construction has always provided adequate notification of any likely. complication or modlficatlon of safety standards ‘Therefore, this step is generally concerned with resolving particular questions that may ‘have been raised in the construction permrt review and other issues which were deferred by the apphcant . : : A second pubhc hearing, step 9 is not mandatory and generally would be held only if the applicant or an intervenor requested it. If the second meeting were held, the formal issues would be limited to contested questions appropriate to the operating license stage. The Director of Regulation publishes a formal notice of intent to issue an operating license, which he would proceed to do unless a hearmg is requested The license can be issued, unless the hearing decision should be adverse, as soon as the regulatory staff determines by inspection that the facility has been completed in accordance with the constructlon permit and the reactor. is ready to be loaded W1th nuclear fuel (steps 10 and 11). . \ : L , o : : The operatlng heense eonsrsts of the hcense to operate a “utlhzatlon factllty” under lO CFR Part 50. and all the ancillary AEC materials licenses needed. The licensee must, prior to licensing, 124 provide the financial protection and execute the indemnity agreements required by 10 CFR, Part 140, to ensure that the licensee will have the ability to respond in damages for public liability. The period of licensed operation, step 12, involves adherence to specific operating conditions, maintenance and surveillance requirements, and staffing requirements set out in “technical . specifications” incorporated in the license. These are concerned with maintaining the validity of the safety and environmental evaluations upon which the license was premised. The licensee must have a competent nuclear plant staff, including operators and supervisors licensed as individuals under 10 CFR, Part 55. Operating licenses require the submission of reports to the regulatory staff periodically and on the occasion of problems arising which may have safety implications. Inspections of licensed facilities are made regularly. Modifications in the facility design and operating program are restricted by the technical specifications with the intent that the licensee can generally make alterations without prior approval of the AEC if they would not involve unreviewed safety questions. Other modifications are generally considered on a case-by-case basis by the regulatory staff, and appropriate approvals are granted, frequently in the form of changes to the technical specifications. , Termination of an operating license, step 13, can take many forms. Generally, the AEC regulations anticipate that a licensee would have proved his qualifications to maintain his status as a licensee in good order until the licensed facility and nuclear materials are disposed of so as to terminate his responsibility. A license for a utilization facility may be issued for a term not exceeding 40 years, but the AEC is authorized to extend a license at any time to that limit. A licensee must obtain the consent of the AEC in order to transfer, assign, or in any manner dispose of a license or any right thereunder. 5.5.2 Siting General considerations - Nuclear power plant licensing is contingent upon satisfying the AEC with respect to the issues listed in the previous section, the most difficult of which is the question of health and safety of the public. This issue is a complex one in itself but basically involves protection of people against any harmful exposure to ionizing radiation. The necessities of nuclear safety have been the object of extensive research for more than 30 years, and experience with evaluation of the safety of individual nuclear power plants covers the last 20 years. Without exception, nuclear power plants have been judged by the AEC on a case-by-case basis; no two plants are exactly alike. To the extent that plants are alike, the AEC takes into account the way common safety problems have been resolved in the past. Thus water3%) 11,500 14 . 10-18 60 . 43-78 Low sulfur (<1%) 11,500 20 16-25 86 69-108 Subbituminous (western) - ' s ' Low sulfur (~0.5%) - 8,500 .. 4.25 3.40-6.80 25 20-40 Lignite (western) ' Low sulfur (~0.5%) 6,750 2.50 1.60-3.25 18 12-24 154 determining the future applicability of coal to industrial and other uses, it is necessary to judge whether the recent large price increases for eastern coal represent a response to a short-term supply-demand situation or whether they are permanent. This question is examined in the following _section. : Future prices. The usual response of coal industry representatives to the question of future prices of coal is that coal will be competitive with alternative sources of energy. In other times this observation might be useful, but with the present fluid situation on supply and price of other fuels, particularly petroleum, the analysis of *compet_itive positions of various fuels is highly speculative. Nevertheless, one point of competition for energy that is reasonably well defined is the electric power ‘industry. Most projections assume that nuclear and coal will be the basic fuels used in the future _expansion of the power industry. The cost of nuclear electric power should therefore influence the price . of coal. A cost study was made of central station nuclear and coal plants to determine break-even prices for coal (i.e., the price of coal that would result in coal-fired central station plants being competitive with nuclear). The basic cost assumptions used in the analysis are shown in Table 6.5. _ , o Lo . - Results for base-loaded (80% plant factor) plants are given in Table 6.6. For a coal-fired central station plant burning high-sulfur coal with stack-gas sulfur-removal equipment, the 1974 break-even value of coal is 24¢/10° Btu ($5.50/ ton) delivered to the power plant. The break-even value would be expected to increase to 50¢/ 10° Btu ($11.50/ ton) By 1991. For a plant using low-sulfur coal and no stack- gas sulfur-removal equipment, the break-even values are 49¢ and 75¢/10° Btu for 1974 and 1991 respectively. These figures indicate that the delivered value of low-sulfur coal is 25¢/ 10° Btu greater than that of high-sulfur coal. For power plants constructed to meet intermediate-load demands (40% plant factor), the competitive position of coal is considerably improved, as indicated in Table 6.7. The delivered break-even value for high-sulfur coal is 46¢/10° Btu in 1974 and increases to 87¢ /10° Btu in 1991, Table 6.5. Economic data for 1300-MW(e) central station coal and nuclear plants (1974 cost basis) Coal-fired plant Cost item Light-water " With Without reactor stack-gas stack-gas cleanup cleanup Capital investment (10° $) 546 . 450 385 Annuzl O&M costs (10° $) excluding fuel ' Fixed : 448 7.1 5.75 Variable? 1.90 12.82 3.36 Total 6.38 19.92 9.11 Fuel cost? {¢/1 0° Btu) 1974 startup 19.0 13)? 1981 startup 31.0 20)° Variable 1991 startup 41.0 23)° 9Based on 80% plant factor. bCosts related to burnup. 155 Table 6.6. Estimated break-even value of coal in competition with central station base-loaded (80% plant factor) nuclear plant" Year of startup 1974 1981 1991 Nuclear plant annual costs ao® s _ Capital 87.36 87.36 87.36 Fuel 18.22 30.52 40.36 0&M 6.38 6.38 6.38 Total 111.96 124.26 134.10 Coal plant annual costs with stack-gas cleanup (106 3 Capital : 71.97 7197 71.97 o&M 19.92 _ 19.92 19.92 Subtotal - 91.89 91.89 91.89 Available for fuel - 20.07 32.37 42.21 Coal plant annual costs without stack-gas cleanup 10® $) Capital 61.60 61.60 61.60 O&M 9.11 91 9.11 Subtotal _ 70.71 70.71 70.71 ‘Available for fuel - 41.25 53.55 63.39 Break-even value of coat (delivered) (¢/ 10° Btu) . High sulfur 239 38.5 50.2 Low sulfur 49.1 63.7 75.4 @Roth coal and nuclear plants assumed to be 1300 MW(e). b16% fixed charge rate on depreciating capital. Table 6.7. Estimated break-even value of coa! in competition with central station intermediate-load (40% plant factor) nuclear plant” Year of startup 1974 1981 1991 Nuclear plant annual costs 10° $) Capital 87.36 87.36 87.36 Fuel 12.00 20.67 29.04 o&M 543 543 5.43 Total ) . 104.79 113.46 121.83 Coal plant annual costs with stack-gas cleanup ao®s) - . ' Capital i . . 71.97 71.97T 71.97 0o&M ' 13.51 13.51 - . 13.54 . Subtotal o . 85.48 85.48 85.48 Available for fuel _ o 19.31 27.98 36.35 Coal plant annual costs without stack-gas cleanup ¢} 0® $ : Capital 61.60 - 61.60 61.60 o&M 743 7.43 7.43 Subtotal 69.03 £ 69.03 69.03 Available for fuel , -35.76 4443 52.80 Break-even value of coal (delivered) (¢/ 10_6 Btu) .. High sulfur o - 46.0 66.6 86.5 . Low sulfur 85.1 105.7 125.7 9Both coal and nuclear plahts assumed to be 1300 MW(e). _' b16% fixed charge rate on depreciating capital. 156 Values for low-sulfur coal are 85¢ and $1.26 per 10° Btu for 1974 and 1991 respectively. For intermediate-load central station plants, low-sulfur coal is 39¢/10° Btu greater than high-sulfur coal. The break-even delivered coal values are summarized in Table 6.8, which also includes estimated mine values for both eastern bituminous coal delivered to eastern power plants and western subbituminous coal and lignite delivered to eastern power plants. Mine values were derived using transportation costs of $2 and $10 per ton for eastern and western coal respectively. The eastern coal mine values are applicable to power plants located reasonably close (on the order of 200 ~ miles) to coal fields. Western coal values might be applicable to power plants located on the middle to lower Ohio River. _ _ Another source of information on possible future coal prices is the study made by the NPC.” They developed economic models for surface and deep mining applicable to coal produced east of the Mississippi. For deep-mined coal, and assuming a 159 discounted cash flow rate of return, the results indicated a sharp rise in price to the mid 1970s, leveling out at about 50¢/ 10° Btu (adjusted to January 1974 dollars). Surface-mined coal would rise at a lesser rate but over a longer period of time, reaching about 36¢/10° Btu by 1985. | Figure 6.6 summarizes the projections of the NPC, the break-even values estimated in the present study for high-sulfur eastern coal, historical trends in average coal prices, and early 1974 representative prices. Figure 6.7 presents similar data for western low-sulfur subbituminous coal. For eastern high-sulfur coal, it is concluded that the current price levels cannot be sustained if coal is to make a significant contribution to new central station power generation. On the other hand, it is also evident that prices will not fall low enough, at least in the foreseeable future, so that eastern high-sulfur coal will be competitive with nuclear plants for base-load central station power generation; competitive price levels of coal for this application would not give adequate profitability even for strip-mined coal. For purposes of the present study, a base price (f.0.b. mine) of 50¢/10° Btu, with a range of 40¢ to 60¢/10° Btu, was assumed, since this price level would appear to give an adequate return and still allow some degree of competitiveness with nuclear for non-base-load power generation. | Table 6.8. Summary of break-even values (¢/10° Btu) for coal in competition with nuclear for central station power generation in eastern markets Base load Intermediate load 1974 1981 -~ 1991 1974 1981 1991 Delivered values High sulfur 24 39 50 46 67 87 Low-suifur 49 64 75 85 106 126 Values at mine Eastern coal® High sulfur 15 30 42 37 58 78 Low sulfur 40 55 67 76 97 117 Western coal Subbituminous (low sulfur) 0 5 16 26 47 67 Lignite (low sulfur) 0 0 1 11 32 52 “Transport of eastern coal to eastern markets assumed to be $2 per ton. bTransport of western coal to eastern markets assumed to be $10 per ton. 157 ORNL—-DWG 74-2530R 140 | | | NOTE: ALL VALUES ADJUSTED TO CONSTANT JANUARY 1974 DOLLARS 120 | 100 - _LOW SULFUR 2 : REPRESENTATIVE ® EARLY 1974 PRICES S = N HIGH , w 80 SULFUR A INTERMEDIATE Z : - LOAD s [14] 2 _ o ' / COMPETITIVE 3 60 WITH . / N NUCLEAR > = e o e e o e o é _”’ - s w = © -~ BASE - - DEEP NATIONAL MINED PETROLEUM 20 v | COUNCIL PRICE — VERAGE PROJECTIONS PRICE ON SURFACE | (15% RATE OF OPEN MARKET MINED RETURN) 0 | | | 1965 1970 1975 1980 1985 1990 : ' YEAR Fig. 6.6. Eastern highasulfur coal values—trends and projections. Concermng western low-sulfur coals, it appears that (1) llgmte is not of great interest for distant markets because of high transportatlon costs and (2) subbituminous coal will have a Teasonable ‘amount of non-base-load use at prices hear current levels. For the present study a base price (f.0.b. mine) of 30¢/10° Btu, with a range of 24¢ to 36¢/10° Btu, was assumed. ) Transportatnon cost ong—drstance movement of coal is by rall barge, and in one case, prpelme Rall is by far the ~most important form of transportation, but barge movement on inland waterways is significant. Coal slurry pipelines are expected by some to become an important mode of transportation, especially for moving western coals to regions of high energy use. Rail. The average cost for coal shipment by rail is about 10 mills/ ton-mile.” Rates are influenced by a number of factors, the most important of which are (}) distance, (2) volume, and (3) mode of shipment (by individual cars or by unit train). TVA data™ for one particular power plant, ORNL-DWG 74-12801 100 AVERAGE OPEN NOTE: ALL VALUES ADJUSTED TO MARKET PRICES | CONSTANT JAN. 1974 DOLLARS O WYOMING ' _ ' 'V MONTANA ‘ _ 80 - COMPETITIVE WITH —— A NORTH DAKOTA {LIGNITE) NUCLEAR I INTERMEDIATE T e ~ €60 — REPRESENTATIVE PRICE, LATE 1973 a0 }—\\ - i .,JéJ 1 COAL VALUE, FOB MINE (¢/105 Bw) 0o° RANGE ASSUMED BY NATIONAL PETROLEUM COUNCIL 20 }—— R——J—— _J NATIONAL PETROLEUM COUNCIL A . — BASE 0 ' =1 . 1965 1970 1975 1980 1985 1990 1995 YEAR Fig. 6.7. Western low-sulfur subbituminous coal values—trends and projections. located approximately 100 miles from the mine, indicate rates of about 14 mills/ton-mile for individual cars and 13 mills/ton-mile for unit train. In a study of coal pipelines, Wasp and Thompson™ suggested 5 to 6 mills/ton-mile for long-haul unit trains. The NPC™ indicated a rate of 5 mills for some unit-train hauls. The 1970 National Power Survey® presented a range of 3.5 to 8 mills/ton-mile for unit train and 1.5 to 4 mills for integral coal trains. Burlington Northern’s estimate, as reported by Oak Ridge National Laboratory (ORNL),*” for unit train transport of western coal from Gillette, Wyo., to St. Louis, Mo. (1074 miles), is $5.94 per ton or 5.5 mills/ton-mile. | - ’ ‘For evaluation purposes, it is assumed that short-haul (~100 mlles) rail transport would cost 13 l‘l‘llllS/ ton-mile with a range of 10 to 15 mills/ton-mile. Long-haul (500 miles) rates were assumed to be 5.5 mills/ton-mile with a range of 4.5 to 6.5 mills. Barge. United States average barge rates are reported’ to be 3 mills/ton-mile and, with large-volume contracts, as low as 2.5 mills. An ORNL study89 indicated a rate of 3.5 mills/ton-mile for barge shipment of coal from St. Louis, Mo., to Madison, Ind. In the present study, a base rate of 3 mills/ ton-mile, with a range of 2.5 to 3.5 mills, is assumed. : 88. The 1970 National Power Survey—«Part 111, Federal Power Commission, p 111-3- 118 1970. 89. C. L. Bazelmans et al., Study of Options for Control of Emissions from an Exasung Coal-Fired E!ecmc Power Siation, ORNL—TM-4298 , . _ , 159 Pipeline. Wasp and Thompson™ derived slurry pipeline costs for various transport distances and capacities. For a 1000-mile pipeline, estimated costs ranged from 3 mills/ ton-mile fora capacity of 18 million tons/year to 6.5 mills/ton-mile for 6 million tons/year. A representative value of 4 mills, with a range of 3 to 6.5, was selected for the pi'esent study. Unit cost summary. Basic unit transportation cost data for long hauls assumed for the present study are summarized in Table 6.9. The costs (¢/ 10° Btu) for 100 miles of movement for three ranks of coal were derived using assumed heating values discussed previously. Delivered coal costs Cost estimates of various coals delivered to the Houston, Tex., and New Orleans, La., areas are shown in Table 6.10. These data were derived using previously discussed assumptions concerning coal and transportation costs. The source of eastern coals was assumed to be either southern Illinois or western Kentucky. Coal would be transported from the mine by rail (50 miles) and transferred to barge for delivery via the Mississippi River to New Orleans (1000 river miles) or to Houston (1500 miles). Western subbituminous coal was assumed to originate in Wyoming and be shipped to St. Louis by unit train (1100 miles), transferred to barge, and shipped to New Orleans (1075 miles) or Table 6.9. Coal transportation costs for various modes ‘of long-haul movement Cost per 100 miles (¢/10° Btu) Coal type Unit train : Barge ~ - Pipeline Base Range - Base = Range Base Range 1.1-1.5 17 13-28 Bituminous 24 20-28 13 Subbituminous = 3.2 26-38 1.8 15-21 24 1.8-3.8 Lignite 41 3.3-4.8 2:2. . 19-26 30 22-48 Table 6.10. Cost of coal delivered to New Orleans and Houston areas” © Cost (¢/10° Btu) . o CI y o Total delivered ' . 0a 7 cost fl‘ransportatxon (£.0.b: mine) _ , , ' e ~Base . Range. . Eastern high-sulfur coal oo . : S Lo ' To New Orleans area o - 18 . . : . 30 68 ‘5581 To Houstonarea - =~ 24 ‘ 50 74 6088 Eastern low-sulfur coal o _ “To New Orleansarea - 18 ' 80 - 98 85—-110 To Houston area 7 - 24 - 80 104 -~ 90-118 Western subbituminous coal - S s : - _ - To New Orleans area N 57 . . _ 30 87 . 71-103 To Houston area o ' . o o Via New Orleans - . 66 ' 30 -9 - 78-114 Direct unit train 45 30 75 60-89 aFirst quarter 1974 prices. 160 Houston (1575 miles). An alternative for the Houston area is shipment by unit train directly from Wyommg (1400 miles). 6.2 CONVENTIONAL FIRING WITH COAL 6.2.1 Low-Sulfur Coal with Conventional Boilers . Low-sulfur eastern and western coals may be used to fire steam boilers with no special stack-gas cleaning required, since sulfur dioxide (SO,) emissions generally do not exceed the Environmental Protection Agency (EPA) standard of 1.2 Ib per 10° Btu heat input. However, particulate-removal equipment, usually an electrostatic precipitator, will be needed to meet the requirement of 0.1 Ib/ 10 Btu set by EPA. A wide selection of coal-fired boilers is offered by U.S. manufacturers which will produce steam at various temperature and pressure conditions of interest for most industrial applications in sizes ranging from a few hundred pounds per hour to several million pounds per hour. Boilers employing either spreader-grate or pulverized-coal firing are offered in sizes up to about 0.5 X 10° Ib of steam per hour. Larger boilers are conventionally fired with pulverized coal. ' Eastern coals generally have a higher ash content (some up to 20 wt %) than western coals (typically 4 to 8 wt %); consequently, ash-handling and disposal costs will be higher for most eastern coals. Western coals generally have a higher moisture content, 12 to 37 wt % (eastern coals 1 to 6 wt %), and lower Btu content (8500 Btu/lb) than eastern coals (11,500 to 14,500 Btu/1b). Thus the type of coal used will influence the design and cost of boiler equipment. Coal sized for spreader-grate firing may not be readily available in some sections of the country, since relatively few mines have appropriate equipment to produce this size coal. For estimating purposes, a cost of $20 to $25 per pound of steam generated per hour appears reasonable for the installed capital cost of a complete coal-fired boiler plant in the size range of 1 to 3 X 10° Ib/hr using pulverized coal. Most steam plants built in temperate climates, such as the southwest and south central states, require only minimum shelter for protection against winter weather. Retrofitting an existing gas- or oil-fired boiler to use coal is generally not practical. 6.2.2 Conventional Boilers with Stack-Gas Treatment Environmental Protection Agency standards for new fossil-fuel-fired steam generators require that sulfur dioxide emissions in stack gases not exceed 1.2 1b per 10° Btu heat input (max 2 hr average) when solid fossil fuel is burned. This is equivalent to 0.7% sulfur for bituminous coal. Consequently, any coal containing more than about 0.7% sulfur which is to be used for firing a steam generator will necessitate some form of sulfur removal, either from the coal before it is burned or from the stack gas. - Over 100 stack-gas scrubbing processes have been proposed; however, only about a dozen have reached the pilot plant or demonstration stage; These processes may be divided into three broad groups: throwaway scrubbing, regenerable scrubbing, and dry processes. Almost all the scrubbing processes remove SO, (an acidic gas) with an aqueous solution or . slurry of alkaline material. These processes require a scrubber with liquid recirculation and mist elimination, gas fans, ductwork and dampers, and gas reheat to restore plume buoyancy. If fly-ash particulates are not removed by an electrostatic precipitator, the scrubber system generally must be 161 expanded to allow for particulate as well as SO; removal, especially with regenerable scrubbing, because particulates are usually unacceptable in the regeneration system. The scrubbing processes all require alkali-handling systems to provide for alkali makeup and for product recovery or disposal. The throwaway processes generally dispose of removed sulfur as a waste sludge of calcium salts and require greater than stoichiometric input of alkali. Since the regenerable processes convert product solutions or solids to sulfur or sulfuric acid and recycle alkali, very little alkali makeup is required. - 6.2.3 Throwaway Serubbmg The lime and llmestone slurry scrubbing processes have the greatest commercnal appeal to the U.S. utilities. The flue gas is scrubbed with a 5 to 15% slurry of calcium sulfite/sulfate containing small amounts of continuously added lime (CaO) or limestone (CaCOQO;). The solids are continuously separated from the slurry and usually disposed of in a settling pond. The processes are complicated by simultaneous dissolution and crystallization of the solids in the scrubber. Calcium scaling and plugging can occur in the scrubber and demister, and sufficient residence time and liquid recirculation must be provided for reaction of the solids with SO,. In addition, the high solids concentration tends to cause equipment erosion and corrosion. Not the least of the problems is disposal of the “solid” waste, usually a sludge “mud” composed of tiny crystals and containing about 50% water with dissolved calcium and trace metals from the fly ash. The lime/limestone scrubbing processes are being offered by a number of developers, and systems are being planned and constructed for over 20 plants.’ A number of developers are workmg on double-alkali systems, which regenerate the scrubbing solution by reacting it with lime or limestone to form waste calcium sulfite/ sulfate sludge and recycle alkaline solution. The waste solids should be washed to remove dlssolved sodium salts, but otherwise they present the same waste disposal problem as slurry scrubbing. The highly efficient sodium alkali solution permits use of very simple scrubbers, such as single-stage venturis, to remove both SO; and particulates. General Motors Corporation and Caterpillar Tractor Company are designing and constructing industrial boiler applications of double-alkali systems using lime regeneration. Major development of limestone regeneration has been carried on by Showa Denko and Kureha in Japan. A 200-MW Japanese system was scheduled to start up in 1973. EPA is supporting pilot plant work by A. D. Little to generate design data on alternate double-alkali processmg schemes. _ Chiyoda of Japan has developed a throwaway scrubbing process with a different mode of SO, removal. The SO; is absorbed in dilute sulfuric acid containing ferric ion, which complexes with it. In a separate vessel, the retained SO is air-oxidized to sulfuric acid. The product stream of dilute acid is neutralized with lime or limestone to form a high-quality large-crystal-size gypsum product that is easily disposed of and may even be marketable. The system has been tested on an oil-fired boiler and with simulated coal fly-ash impurities. One commercial system is operating in J apan and “several more are under construction. 6.2.4 Regexierable__ Scrubbing The three basic techniques for regeneration of a spent alkali scrubi:oing solution or slurry are (1) direct thermal treatment to produce SO, (2) acid decomposition of the alkali to SO, and sulfates followed by secondary conversion of the sulfates to acid and alkali, and (3) direct reaction of the scrubbing solution with hydrogen sulfide (H.S) or CO to produce sulfur or H,S. Thermal treatment ™ 162 is the most direct approach and is also better developed. Reaction with H;S or CO will probably be the most cost-effective approach, since it can directly produce sulfur rather than SO.. Many of the regenerable processes produce concentrated gaseous SO; as an intermediate product. Conversion of the SO, to sulfuric acid is straightforward via reaction with air in a contact acid process, but conversion to sulfur is more difficult. Allied Chemical Company has successfully operated a very large plant (500 tons/ day) that produces sulfur by reaction of methane with a smelter gas containing 15% SO; at temperatures greater than 816°C (1500°F). The primary reactor is followed by a secondary cleanup Claus system reacting residual H,S and SO; to sulfur. The process should work equally well on gases containing 95% SO.. Another approach involves reacting SO; with H; at 371°C (700°F) to form H,S, followed by reaction of the remaining SO, with H,S in a Claus system. Sulfur can also be produced by reaction of SO; with CO at 371°C (700°F). Regenerable processes that produce H,S can use the conventional Claus technology to make sulfur. The Wellman-Lord process uses direct thermal regeneration of sodium sulfite/bisulfite scrubbing solution. The solution is completely evaporated to crystallize sodium sulfite for alkali makeup and to generate water vapor containing the removed SO;. The SO; is concentrated to 95% by condensation of the water. Heat at 121°C (250°F) for the evaporator can be supplied by low-pressure turbine steam or a heat pump. Residual sulfate formed by SO; pickup or oxidation in the scrubber cannot be regenerated and is usvally purged as sodlum su]fate solids contammg 5 to 10% of the sulfur removed from the stack gas. : Wellman-Lord systems have been treating stack gas from a sulfuric acid plant since 1970 and from a Claus plant (sulfur recovery) and oil-fired boiler since 1971 (in Japan). Two new units treating sulfuric acid and Claus tail gas are being started up in the U.S. EPA is co-funding a 100-MW utility demonstration with Northern Indiana Public Service that is due to start up in late 1974. The demonstration will incorporate production of sulfur by the Allied Chemical process. - The magnesium oxide (MgQO) scrubbing process, developed in the U.S. by the Chemico Corporation, differs from the lime scrubbing system in that MgO slurry is used as the absorbent. The spent slurry is treated to recover the MgO for reuse, and by-product sulfuric acid is produced. As described by Chemico, the spent slurry from a number of plants would be processed at a central location, and the regenerated MgO would be returned to the user. They believe that the sale of sulfuric acid would pay for the reduction step and still give a satisfactory return on investment to the user. With EPA co-funding, Chemico has constructed a MgO scrubbing system for a 150-MW oil-fired boiler at Boston Edison Company. The calciner and acid plant are located at Rumford, R.1. A similar system has been constructed for Potomac Electric Company for a coal-fired boiler that will also use the calcining facilities at Rumford. Operation of the system at Boston has demonstrated utilization of the recycled MgO and better than 90% SO; removal, although numerous minor problems have been encountered with handling of solids. | | The Stone & Webster/ Ionics and the NH;-bisulfate processes use acid decomposition. The spent alkaline solution (mostly bisulfite salts) is reacted with strong bisulfate acid to produce concentrated SO, gas and sulfate salts. The Stone & Webster/Ionics process uses electrolysis to convert sodium sulfate solution to sodium hydroxide and sulfuric acid (or sodium bisulfate), and the NH;-bisulfate process uses thermal decomposition of molten ammonium sulfate to ammonium bisulfate and NHs. Sulfates produced in the scrubbers cannot be regenerated by acid decomposition, but they can be removed by neutralizing a portion of the bisulfate acid with limestone to produce gypsum waste. If sulfuric acid is produced from the SO, the Stone & Webster/ lonics process can purge sulfates as dilute sulfuric acid for acid plant water makeup. EPA and Wisconsin Electric Company are 163 currently co-funding a pilot plant demonstration of the Stone & Webster/Ionics process. Tennessee Valley'Au'th'ority has piloted ammonia scrubbing and acid decomposition. However, NH; scrubbing has a problem with the formation of an amrnomum salt partlculate fume that escapes from the scrubber. 6.2.5 Dry Processes Dry processes remove SQO; at temperatures in excess of 93°C (200°F) and require no reheat of treated gases as is required with scrubbing systems. Systems operating above 149°C (300°F) require power plant modifications to produce hot gas. Most of the systems produce sulfur or sulfuric acid. Catalytic oxidation of SO; at 454 to 482°C (850 to 900°F) will permit its removal as 75 to 80% sulfuric acid at 149°C (300°F). The Monsanto Company Cat-Ox process effects this conversion -using an extrapolation of contact acid technology. The flue gas must be cleaned in a high-efficiency electrostatic precipitator to prevent plugging of the catalyst bed. Hot gas would be taken from the boiler at ~454°C (850°F). The power plant economizer and air heater would be incorporated in the Cat-Ox process between the catalyst bed and the acid absorber, and a high-temperature precipitator would remove particulates at 454°C (850°F). The treated gas containing SO; is scrubbed with recycled acid to produce 80% sulfuric acid. It is expected that the system will require 3-day shutdowns every 3 months to clean the catalyst of residual particulate. Monsanto operated a 15-MW prototype of the process from 1967 to 1969. Activated carbon readily oxidizes SO, and absorbs it as H:SO4 at 93 to 149°C (200 to 300°F). The three approaches of carbon adsorption processes differ in their means of regeneration. The processes developed by Hitachi and Lutgi wash the loaded carbon with water to produce dilute sulfuric acid that can be neutralized with limestone to give high-quality gypsum. Systems developed by Reinluft, Sumitomo, and Bergbau-Forschung drive off 10 to 30% SO, by thermal treatment at 260 to 371°C (500 to 700°F). With EPA funding, Westvaco is developing regeneration at 149°C (300°F) by H.S to produce sulfur on the carbon. The eafbon is heated to remove one-fourth of the sulfur and treated with hydrogen at 538°C (1000°F) to generate H,S for recycle to the sulfur generation. Hitachi and Surmtomo both have large prototype mstallatlons in Japan, and the Lurgi Sulfacid process is being used on a number of small industrial sources in Germany. Since none of the processes have been used with coal-fired flue gas, there are uncertainties as to the effect of fly ash. All these systems suffer from attrition of carbon adsorbent though quantltatlve requirements have yet to be established. The Royal Dutch Shell group has developed a process utilizing the oxidation of SO; by copper loaded onto alumina to copper sulfate at approximately 730°F in reactors designed especially to contend with partlculates The process is cyclic; regeneratlon with hydrogen takes place at the same temperature to produee a concentrated SO; stream which can be recovered-as such, oxidized to ~ sulfuric acid, or further hydrogenated in part to H,S and fed to a Claus unit. A commercial installation was made on an oil-fired boiler in Japan in 1973, and a demonstration unit is in -operation in Tampa, Fla., using flue gas from a coal-fired boiler. The process is offered for license by Shell’s licensing agent, Universal Oil Products Company. Esso and Babcock and Wilcox (B&W) have developed a mmllar process using fixed-bed adsorption. No details have been released, but their process is probably similar to the Shell system’ or the alkalized alumina system worked on by EPA and the Bureau of Mines in the late sixties. A utility is considering demonstration of the Esso-B&W system. 164 The molten carbonate process absorbs SO; in a molten eutectic of lithium, sodium, and potassium carbonates at 427°C (800°F). The absorbed SO; is reduced to sulfide with carbon or H: reduc_:tant at 816°C (1500°F), and H,S is stripped from the melt with CO; at 538°C (1000°F). The melt is returned to the scrubber, and the H;S is converted to sulfur. Atomics International developed this process with EPA funding and is constructing a 10-MW prototype with the funding of a group of northeast utilities. None of the commercial applications are being designed for greater than 90% removal, but some of the processes could potentially get up to 99% removal, which may be required to control ambient sulfate particulates. ' Lime scrubbing and the Wellman-Lord processes appear to be about ready for widespread commercial application, with a number of processes with existing or planned application not far behind (e.g., Stone & Webster/ Ionics). An even greater number of processes have no commercial applications planned and can therefore have little impact on fneeting the ambient air quality standards for SO; in the near future. Table 6.11 summarizes the various processes and their state of commercial development. Table 6.11. Comparative levels of development — commercial systems Representative commercial Process applications Technology gaps Lime scrubbing 25 MW oil — 1970 Scaling and plugging 150 MW coal — 1972 Erosion 430 MW coal ~ 1971¢ Waste disposal Catalytic oxidation 100 MW coal — 19729 Effect of particulate, ~ flue gas reheat MgO scrubbing 150 MW oil — 197249 Demo sulfur production 125 MW coal — 1973 Solids handling Wellman-Lord Acid and sulfur plants Na; SO4 purge reduction 70 MW oil — 1971 Demo sulfur production 100 MW coal —- 1974 Double alkali BaSQg4kiln — 1971 Waste disposal 40 MW coal — 1973 Solids handling , 200 MW oil — 1973 Carbon adsorption 150 MW oil — 1972, Particulate handling (dilute HyS04) German industrial applications Carbon adsorption 60 MW oil ~ 1972 - Carbon attrition, (15% S0,) particulate handling CuQ adsorption Effect of particulate 50 MW oil - 1973 operation on coal %These systems have not yet successfully started up. 6.2.6 Environmental Impact Generally, all the systems can achieve 90 to 95% SO. removal, so this is not a valid consideration for ranking. Table 6.12 ranks the systems primarily on the basis of the form of the sulfur product. In order of increasing environmental insult, the products are elemental sulfur, sulfuric acid, gypsum (CaS0s), and calcium sulfite/sulfate sludge. Sulfuric acid is less desirable than sulfur because it is 165 Table 6.12. Comparative environmental impact Products and waste Process per ton of sulfur abated MgO scrubbing o 3 tons H3804 (100%) ' _or 1 ton sutfur Regenerable adsorption - "~ 1 ton sulfur; (carbon or CuQ) ) 0.01-0.20 ton spent adsorbent Regenerable sodium alkali scrubbing 0.95 ton sulfur;: ; 0.25 ton NaySQO4 or CaS0O, Regenerable ammonia scrubbing 0.95-1.0 ton sulfur; o ' 0.0-0.15 ton (NH4)2504,; NH3 and fume air emissions Catalytic oxidation S 3 tons H,804 (80%) Acid neutralization 5.5 tons dry CaSO4 {Chiyoda ot Hitachi carbon) - Lime throwaway scrubbing 6—9 tons CaS03/80,4 (slurry or double alkali) : wet sludge Limestone throwaway scrubbing 8-13 tons CaS03/S04 ' : wet sludge more difficult to ship and market and is not a disposable waste. Calcium sulfite/sulfate sludge is least desirable because of its chemical oxygen demand and large volume per ton of sulfur. Other considerations of environmental impact include the quantity and quality of waste materials from sorbent degradatlon The MgO scrubbing system is the cleanest process; no waste products are expected from its operation. -Limestone scrubbing would have the largest quantity of waste material, 8 to 13 tons of wet sludge per ton of sulfur removed. There is little doubt that regenerable prooesses making sulfur are far superior in environmental impact to throwaway processes making calcium sludge. The 'quality and quantity of calcium sludge product vary with the type of throwaway process. The Chiyoda and Hitaehil processes directly produce a high-quality marketable gypsum by neutralization of dilute sulfuric acid. Throwaway processes using lime produce less sludge than those using limestone because of greater utilization (lower stoichiometry) of the calcium. value. Improvements are under development in the sludge volume and quality from lime/limestone scrubbing systems. In disposal ponds, settled sludge from limestone scrubbmg is 40 to 50% water and occupies 300 ft* per ton of contained sulfur. The dry adsorption regenerable processes are surprzsmgly clean. Adsorbent attrition or poisoning is expected to result in a limited quantlty of waste adsorbent. Carbon adsorbent can be burned as coal, and inorganic adsorbents such as alkalized alumina and CuO on alumma must be " handled as waste solids. The regenerable scrubbing processes using sodium or ammonium alkali produce some sulfate that cannot be regenerated. Sodium sulfate can be marketed as such or converted to calcium sulfate for solid waste disposal. Ammonium sulfate can be marketed or decomposed to N» and SO.. Ammonia scrubbing processes may suffer from sulfite/ sulfate fume formation. There appear to be solutions to this problem, but their costs are not included in current cost estimates and their 166 feasibility has not been tested. In addition, ammonia scrubbing will emit 25 to 100 ppm of gaseous NH3. ' B L . Almost all the systems have potential for particulate emissions as entrained solids, slurry, or solution, but such entrainment is easily eliminated with solution scrubbing and can be eliminated for slurry scrubbing and solids contacting by properly designed mist eliminators and cyclones. The Cat-Ox process has the environmental advantage (and economic dlsadvantage) of complete capture of all remaining particulates in the catalyst bed. Most of the commercial applications of stack-gas cleaning are being designed for 80 to 90% SO; removal, but potentially most processes could achieve up to 95%. The Stone & Webster/ Ionics and Sulfoxel processes are immediately capable of 99% SO removal. If a stage of sodium hydroxide scrubbing were added to the Wellman-Lord and double-alkali systems, they could achieve up to 99% removal. Such effective SO; removal may be necessary for future abatement of sulfur pollutants. 6.2.7 Economic Analysis The cost of stack-gas cleaning is an important criterion in process evaluation, because it will ultimately determine the process to be used if other considerations are equal. At the same time, process economics is the most difficult criterion to generalize on a comparative basis. On the basis of cost information from contractors and other sources, the Control Systems Laboratory, EPA, prepared and presented information representing the costs of the major wet scrubbing processes.” This information base has been expanded to include the double-alkali, citrate, and Cat-Ox processes Essentially all economic comparisons published to date have been aimed at utility systems based on 500 MW generating capacity (or larger), 3.5% sulfur coal, a retrofit system, and 60% load factor. On this basis EPA®' estimates installed capital costs of $24 to $36/kW for throwaway systems and $39 (citrate) to $55 (Cat-Ox) per kW for recovery systems. These costs include particulate waste removal at $1 per ton, no credit for sulfur product, and no costs for waste disposal facilities, which are usually $5 to $10/kW. These published costs are considerably lower than recent estlmates prepared by the TVA® for throwaway lime or limestone slurry systems (Table 6.13). The variation of costs with source parameters (s:ze, sulfur content, load factor, etc.) is much greater than the variation of costs between processes. Depending on source conditions, the annualized cost of limestone scrubbing may conceivably vary from 40¢ to 90¢/10° Btu, while the greatest variation in process cost is from 90¢/10° Btu (double alkali) to $1.45/10° Btu (Cat-Ox). The annualized costs include operating costs and 22.2% capital charges for deprematlon and return on investment. ' Throwaway processes are favored by simultaneous particulate scrubbing and SO, removal, low costs of waste disposal, and lack of a sulfur product market; regenerable processes are favored by high waste disposal costs and good credits for by-product sulfur. However, sulfur credits do not ‘have a major impact on costs. The throwaway processes cost about the same as the regenerable 90. J. K. Burchard et al., “Some General Economic Considerations of Flue Gas Scrubbing for Utilities,” Proceedings of Conference on Sulfur in Utility Fuels: The Growing Dilemma, Drake Hotel, Chicago, Oct. 25-26, 1972 (Electrical World). . 91. G. T. Rochelle, “A Critical Evaluation of Processes for the Removal of SO; from Power Plant Stack Gas,” presented at the 66th Annual Meeting of the Air Pollution Control Association, June 2428, 1973. 92. “Tennessee Valley Authority Status Report—Control of Sulfur 0x1des,” presented at the Env1ronmental Protection Agency Hearmgs, October 1973, Washington, D.C, i i i ot 167 Table 6.13. TVA cost estimates of lime/limestone stack-gas cleaning systems? Installed cost Size (MW) Type ($/kW) 500 - Retrofit , 60 500 * New installation 50 100 Retrofit 70-90 21975 dollars; assumes developed technology. TVA estimates total operating cost for a S00-MW retrofit system, at 14.9% fixed charge rate, to be 2.7 mills/kWhr, about half of which is operating cost. processes because the added complexities of calcium slurry scrubbing balance the requirement for sorbent regeneration and product recovery. As viewed by EPA, the least costly processes are the newer systems under development represented by the double-alkali process. However, these new systems are only expected to reduce annualized costs 15 to 20%. The Cat-Ox process appears to be the most expensive system and is perhaps typical of the dry systems. We have no firm cost estimates of the other dry systems, but some evidence indicates that they will be more expensive than the scrubbing systems. In 1968, Kellogg® evaluated the alkalized alumina process and also considered a number of generalized cases applicable to most dry regenerable processes. In 1971, Kellogg® prepared estimates of several regenerable scrubbing systems on the same basis. The capital costs of the dry systems were about twice as large as those of the scrubbing systems. Similarly, capital costs of the Japanese carbon adsorptlon system appear to be about twice as large as those of the Japanese scrubbing systems.” The annualized costs are primarily composed of capital charges for depreciation, return on investment, and maintenance, but utilities and materials costs are significant. The energy requirements of the processes are represented in Table 6.14. The throwaway processes have the lowest energy requirements but the greatest material requirements. The lime scrubbing process would require a total increase in fuel consumptlon at the power plant of about 3.5%; Stone & Webster/Ionics would require 10.7%. The estimated annualized costs of removing sulfur d10x1de from the stack gases of a boiler generating 830,000 lb of steam per hour usmg bituminous coal containing 3.5% sulfur are summarized in Table 6.15. _ Thus, the followmg conclusions may be drawn for industrial boilers. 1. Reasonably waste-free flue gas cleamng processes are or w1ll soon be avallable at annuahzed costs of <50¢/10° Btu. , | S 2. Lime scrubbmg and the Wellman-Lord systems are in commercxal practice; other processes have specific development problems. 93. Econamtc Evaluation of Meral Oxide Processes Jor 50, Removal Jrom Power Plant Flue Gases, M. W. Kellogg Company, NTIS No. PB 200-882 (1970). " 94. Evaluation of SO, Control Processes, M. W. Kellogg Company, NTIS No. PB 204-711 (1971). 95. J. Ando, Recent Developments in Desulfurization of Fuel Oil and Waste Gas in Japan, M. W. Kellogg Company, NTIS No. PB 208-236 (1972). ' . 168 Table 6.14. Process energy requirements? Representative Energy (% of power plant output) process ' _ Power - Fuel Throwaway scrubbing Limestone scrubbing 2.2 - 1.6 Lime scrubbing ' 19 1.6 Chiyoda 2.2 : 1.6 Regenerable scrubbing (to sulfur) ' , . Wellman-Lord 4.5b 3.1 MgO 22 - 56 Stone & Webster/Ionics , 7.6 , 31 NHj-bisulfate 1.9 51 Citrate, Sulfoxel 2.0 31 Dry processes 7 Catalytic oxidation 20 3.2 Copper adsorption : : 20 55 9Based on coal with 3.5% sulfur. PIncludes 2.5% derating of power output for steam cohsumption (5% at 15 psig). Table 6.15. Estimated annual Operéfing cost of a limestone slurry system for sulfur dioxide removal® Capital charges at 22.2% fixed charge rate $1,378,620 Limestone (5 tons/ton of sulfur) at $8/ton 405,640 Grinding and slurry preparation (100 kWhr/ton limestone) 76,060 at 15 mills/kWhr Water (3000 gal/ton of sulfur removed) at 15¢/1000 gal 4,560 Repairs and maintenance materials (3% of capital) 186,300 Disposal (15 tons of 50% solids per ton of sulfur) at $4/ton 608,400 Labor ($14,520/year/man) 2.5 men/shift 108,900 Fringes at 40% of labor 43,560 Total annual operating cost : $2,812,100 Cost per ton of sulfur removed $2.77 Cost per million Btu of steam 37¢ @Basis: 830,000 Ib of steam per hour, 49 tons of coal per hour (23 X 10¢ Btu/ton), 3.5% sulfur, 90% plant factor, 75% scrubbing efficiency, equip- ment capital cost $6,210,000. 3. Cost differences between processes are rarely greater than 159%. Throwaway processes are significantly less costly only where waste disposal is cheap. 4. Regenerable processes offer less potential for environmental degradation by waste products, although sale of the by-product could be a problem. 6.2.8 Cost of Steam Using Coal-Fired Boilers Table 6.16 compares the cost of steam generation using low-sulfur eastern and western coals with no stack-gas cleanup and a 3% sulfur eastern coal with a limestone slurry stack-gas cleaning ‘_ Table 6.16. Estimated annual costs of steam generation using a coal-fired boiler Basis: 10 Ib steam/hr, 750°F, 650 psig, condensate returned at 250°F ~ Installed cost of boiler plant, $25,000,000; turnkey basis; Houston, Tex. ~ (includes all coal handling equipment, stacks, precipitators, etc.) Plant factor 90%:; boiler efficiency, 85%; 1 Ib steam equivalent to 1159 Btu of steam Eastern coal (12% ash) Eastern coal (12% ash) Western coal (4.3% ash) 3.5%S, 11,500 Btu/lb) (<1% S, 11,500 Btu/lb) (~0.5% S, 8,500 Btu/ib) Capital charges at 22.2% fixed charge rate $ 5,550,000 $ 5,550,000 $ 5,550,000 Operatmg - ‘ ' 467,390 tons of coal at 74¢/10° Btu 7,955,000 467,390 tons of coal at $1 06/10" Btu - 11,395,000 632,350 tons of coal at 75¢/ 10 Btu? ‘ o (8,063,000) Feedwater treatment at 15¢/1000 Ib feedwater, 2% makeup 26,280 26,280 26,280 Labor (1 shift supervisor at $12,600/year and 3 operators at $9360/yearlshlft) 122,040 122,040 122,040 Coal and ash handling (3 men, day shlft only at $8320/year) . 24960 24,960 24 960 Ash disposal at 2s¢/ton b 12,467 6,035 Maintenance Parts and materials ‘ o 30,000 30,000 30,000 Labor (1 supervisor at $12 600/year and 8-man crew at $9360/ymr/man) 87,480 87,480 87,480 Fringes at 40% of labor. 93,792 93,792 93,792 Total annual cost $13,890,000 $17,347.000 $14,004,000 Steam cost, ¢/10° Btu | 152 190 153 Limestone slurry sulfur removal at 37¢ll 0% Btu 37 Total steam cost, ¢/ 10° Btu 189 190 153 2Coal delivered by unit train. b Ash removed with sulfur, 691" 170 system. Steam costs are based on the pro_|ected price of coal dehvered to the Houston, Tex., areas, as discussed in Section 6.1.5. Based on the assumptions used for these computations low-sulfur western coal would provide the lowest steam cost (~$1.53/ 10° Btu), and <1% su}fur eastern coal would be the most expensive (~$1.90/10° Btu). 6.3 FLUIDIZED-BED COMBUSTION 6.3.1 Fluidized-Béd Boiler: General Description The coal-fired fluidized-bed boiler is a relatively new technology that at this point seems very promising. Combustion is accomplished in an inert bed, consisting mainly of coal ash, which rests on a plate full of nozzles. The combustion air is introduced through the nozzles and expands the bed beyond its static depth. The bed moves about and flows much like a liquid; hence the name fluidized bed. If the bed is raised to ignition temperature and crushed coal or any other combustible is introduced into the bottom of the bed, it will burn. The bed turbulence transfers heat into the fuel, promoting rapid ignition; the turbulence also provides intimate mixing of fuel and air, promoting combustion with very low excess air. Volumetric heat release rates of the order of ten times those of the powdered-coal suspension-fired furnaces are achieved. The adiabatic combustion temperature of coal-air exceeds 1649°C (3000°F), so heat transfer surface is placed in the bed to absorb about half the heat released and to control combustion temperature to 871 to 982°C (1600 to 1800°F). The remainder of the heat is removed in convection surfaces. Again, because of turbulence in the bed, the heat transfer coefficient of the surface submerged in the bed is three to six times that of convection surfaces. Further, because the combustion temperature can be controlled to 871 to 982°C (1600 to 1800°F), the superheater surface can be confidently designed for conservative wall temperatures and therefore can be made of relatively low-alloy material. A principal reason for the increasing interest in fluidized-bed boilers is that emission control is inherent in the combustion process. The relatively low combustion temperature sharply reduces the formation of oxides of nitrogen. The conditions of temperature and turbulence in the bed favor the reaction of sulfur oxides with limestone, so that the injection of about twice stoichiometric limestone into the bed is very effective in the removal of sulfur. Thus the bulk of the waste products are retained in the bed as dry solids, and, since the bed behaves as a fluid, the wastes can be continuously removed through an overflow pipe located at the desired maximum height of the expanded bed. Figure 6.8 presents a schematlc view of one concept of an industrial fluidized-bed boiler. Work on fluidized-bed combustion of coal began in the fifties. In some instances, the objective was to burn fuels such as anthracite fines, lignite, and washery tailings that did not burn well in other types of combustion systems. The bulk of the work was directed toward obtaining lower cost steam boilers by taking advantage of the high heat transfer coefficient in a fluidized bed. The most significant effort was started about 10 years ago in the United Kingdom by the Central Electricity Generating Board®® and has been continued at the British Coal Utilization Research Association Laboratory (BCURA).””*® Most of the work at BCURA has been with beds having a cross-sectional 96. J. S. M. Botterill and D. E. Elliott, “Fluidized Beds: Answer to Peak Power?” Engineering, p. 146, July 31, 1964. 97. A. M, Squires, “Species of Fluidization,” Chem. Eng. Prog. 58, 66 (April 1962), 98. Pressurised Fluidised Bed Combustion Progress Report No. 10, prepared for the Office of Coal Research, Department of the Interior, by the National Research Development Corporation, London SWL 651 (August 1973). k_/) . 171 . ORNL-DWG 74-8604 . NOZZLE BUTTON TO DISTRIBUTE FLUIDIZING 'AND COMBUSTION AIR - - -~ . ~ Fig. 6.8. Schematic of fluidized-bed boiler. area of about 8 ft’. Some of the British effort was supported by the Environmental Protection Agency (EPA), and BCURA’s program is continuing under a recent Office of Coal Research (OCR) contract. In the U.S., Pope, Evans, and Robbins, Inc., in Alexandria, Va., under both OCR and EPA funding, has . operated several beds at atmospheric pressure, including a bed having a cross-sectional areaof 10 ft’and fitted with a carbon-burnup cell.”*'® The objective in'work on the latter has been to develop a small 99. E. B. Robison et al.,, Study of Characterization and Control bf Air Pollutants from a Fluidized-Bed Combustion Unit: The Carbon-Burnup Cell, report from Pope, Evans, and Robbins to the Environmental Protection Agency, February 1972, ' ‘ . - ' 100. Development of Coal-Fired Fluidized Bed Boilers, Pope, Evans, and Robbins Final Report, vol. I, OCR R&D Report No. 36, Contract No. 14-01-0001-478 (February 1970). fluidized-bed steam generator mentioned above. 172 fluidized-bed combustion chamber and boiler of about 100-MW(t) output that would lend itself to shop fabrication and shipment by rail. The work has emphasized the solution of practical design and operating problems. More recently, basic heat transfer, flow, and performance data accumulated by the British have been supplemented, with EPA funding, by small-scale studies (using beds 6 to 12 in. in diameter) at the Argonne National Laboratory (ANL)'' and Esso Research.'”” Argonne and Esso explored the basic problems of fluidized beds, with the prime emphasis on optimizing the pollution control capabilities and developing a method for reconstituting the lime to eliminate the waste disposal problem for the large amounts of calcium sulfate that will be produced. Pope, Evans,and Robbins™ also worked on the lime regeneration problem. Both Westinghouse and Foster Wheeler have carried out plant design studies, and currently Foster Wheeler is working with Pope, Evans, and Robbins on the 103,104 - Fluidized beds have been used extensively for roasting sulfide ores.'® Over 200 units are currently in operation to make sulfuric acid or sodium sulfite (for paper mills) or to obtain metal oxides for reduction to the metal, but usually for both purposes. The heat released in the roasting operation often requires heat removal from the bed; this is accomplished with boiler tubes in the bed. Work on fluidized-bed combustion in the U.S. has also included the incineration of solid wastes, both industrial and domestic. Copeland Systems, Inc., has about 30 units in service for disposal of industrial wastes, including not only obvious fuel materials such as sawdust but also slurries such as paper pulp mill waste liquor with as little as 35% solids.'” The heat of combustion of the solids is sufficient to sustain the reaction. Dorr-Oliver'® has about 80 incinerator units in service that burn mostly industrial and domestic sewage sludge in aqueous suspension. A fluidized bed for burning municipal solid waste has been under development at Combustion Power, Inc., under EPA contracts for about 8 years.'"”’ In this system, the compressor of a gas turbine feeds air to a fluidized bed of sand into -which shredded solid waste (mostly paper) is injected. The hot gases leaving the bed drive the turbine to produce a net electrical power output. The system has also been operated with coal as the fuel under a contract with OCR.'” Some insight as to the amount of operating experience that has been gained with fluidized-bed coal combustion systems is given by Table 6.17. 101. A. A. Jonke et al., “Pollution Control Capabilities of Fluidized-Bed Combustion,” paper submitted for publication in AIChE Symposium Series, Air 1971, April 1972, 102. A. Skopp et al., Studies of the Fluidized Lime-Bed Coal Combustion Desulfurization System, Esso Rescarch and Engineering Company, Government Research Division, Linden, N.J., 1971. 103. Evaluation of the Fluidized Bed Combustion Process, vol. I, Summary chort, Westinghouse Research Laboratories, Pittsburgh, Pa. (1972). ' 104. J. L. Stollery, “Fundamentals of Fluid Bed Roasting of Sulfides,” Engineering and Mining Journal, October 1964. 105. J. Kleinau, “Pulp and Paper Mill Sludge Incineration,” paper presented at the 1st Secondary Fibre Pulping Conference, Oct. 22-25, 1968. 106. R.S. Millward, “Refinery Waste Treatment and Fluosolids Sludge Combustion,” paper presented at the Antipollution Fair, Milan, Italy, November 1972, 107. D. A. Furlong and G. L. Wade, “Use of Low Grade Solid Fuels in Gas Turbines,” paper prepared for presentationat the ASME Winter Annual Meeting, New York, Nov. 17-21, 1974, 173 Table 6.17. Summaiy of operating experience with some fluidized-bed combustion systems Oreanizati ible £ : Sum totat (glan.lzatlog restfie or Fuel Objective operating esign and cons on time (hr) Copeland Systems, Inc. Wood waste, pulp Incineration; in some cases heat recovery ~108 mill waste, misc. R organic wastes Dorr-Oliver, Inc. Sewage sludge ~ Incineration ~10 Pyrites Roasting to yield SO, for acid or sulfite and/or ~3 X 7106 S © metal oxxde for reductlon SR ' BCURA ' .,Cdal | Research and development on fluidized-bed ~10* , combustion of coal and high-sulfur residual _ fuel oil _ Pope, Evans, and Robbins Coal Research and development on fluidized-bed ~9000 combustion of coal Argonne National Laboratory ~ Coal Research and development ofil'fl'ilidized-bed 700 combustion of coal and lime regeneration 7 Combustion Power, Inc. -Municipal solid Incineration with electrical energy asa - 4‘11: waste, wood by-product 271 waste, and coal _ _ Esso Research Coal Research and development on coal combustion ~100 and lime regeneration 9Total time on bed. ith turbine connected. 6.3.2 Sulfur Removal The effectiveness with which SO, emissions can be reduced by removing sulfur as CaSQy4 in a fluidized-bed combustion system depends on many factors. The two most ’im'portant are the calcium/ sulfur feed ratio and the bed operating temperature. The effects of these two parameters'™ on SO; reduction are shown in Fxgs 6.9 and 6.10. The matter is complicated by the fact that limestones from dxffcrent strata vary substantially in their charactenstlcs, mcludmg their effectlveness in removing sulfur. 108 6.3.3 Regeneration of the Lime It would be advantageous to regenerate the spent limestone and thus reduce both the consumption of limestone and the quantity of ash that must be hauled away. Processes have been investigated that would yield elemental sulfur, a saleable product. While somewhat different processes have been contemplated in the lime regeneration work carried out by ANL, by Esso, and by Pope, Evans, and Robbins, they all depend on roasting calcium sulfate under mildly reducing 108. Final Report on Reduction of Atmospheric Pollution, Fluidized Combustion Control Group, National Coal Board, London, prepared for the Environmental Protection Agency, September 1971, SO, EMISSION REDUCTION (%) SO, EMISSION REDUCTION (%) 100 o0 Q o o 40 100 80 D Q £ o 20 174 ORNL-DWG 74-12812 A""“'\A A\ BED DEPTH — 2 ft - NO RECYCLE R 1 36 in. COMBUSTOR - Ca/S MOLE RATIO - 2.2 A / . LIMESTONE 18 (-1680 pgm) - FLUIDIZING VELOCITY — 4 fps FLUIDIZING VELOCITY — 4 fps BED DEPTH — 2 ft SO=tr— Ot O..._ DOLOMITE 1337 (-1680 um) NO RECYCLE 36 in. COMBUSTOR Ca/S MOLE RATIO — 2.7 1400 1500 1600 ~ BED TEMPERATURE (°F) 1400 1500 1600 ~ BED TEMPERATURE (°F) TN AT < \ ' Ca/S = 0.6 O\ LIMESTONE 18 (-3175 um} DOLOMITE 1337 (-1587 ur_n)\ 'FLUIDIZING VELOCITY — 8 fps FLUIDIZING VELOCITY — BED DEPTH — 2 ft 8 fps o ' WITH RECYCLE BED DEPTH — 2 ft 27 in. COMBUSTOR WITH RECYCLE — Ca/S MOLE RATIO — 2.8 — 27 in. COMBUSTOR N O 1400 1500 1600 BED TEMPERATURE (°F) 1400 1500 - 1600 BED TEMPERATURE (°F) Fig. 6.9. Typical variation in nitric oxide concentration with oxygen content in the flue gas. 175 ORNL-DWG 74-12813 100 BED TEMPERATURE ~ 1550°F 27 in. COMBUSTOR ' VELOCITY — B fps BED HEIGHT — 2 ft - 9/ | wiTHReECYCLE - &7 & N - i/fl S 7y g | g c L, ¢©0 o 2. o 2 / w o = o S. - “ 40 = w ©~ S W 20 ) | / A PARTICLE SIZE — 3176 gm 'O PARTICLE SIZE — 150 um 0 . 2 3 4 5 Ca/S MOLE RATIO Fig. 6.10. Effect of calcium/sulfur ratio and additive partlclc slze on SO; reductlon (high fluidizing velocity) for Pittsburgh coal and limestone 18. , conditions to evolve a gas that is rich in sulfur dioxide. The re_generated lime has sharply less reactivity than fresh lime due to the high temperature necessary for the roast, about 1950°F. Fresh stone must be supplied at a rate amounting to an appreclable fraction of the sulfur to be captured, on a stoichiometric basis, and a comparable amount of lime must be withdrawn. for sale or disposal. To avoid this disadvantage, workers at The Clty College of New Yorkmg have proposed a regeneration scheme which would depend on reductlon of the calcium sulfate by a gas containing “hydrogen or carbon monoxide to yield calcium sulfide and on subsequent reactlon of the calcium sulfide with steam and CO; to produce CaCO; and H,S, from which sulfur may be produced in elemental form more readlly than from SO.. Westmghouse has carried out plant desngn studies'® that mcluded a ‘favorable economic assessment of The C1ty College scheme. 109. A. M. Sqifires and R. A. Graff, “Panel Bed Filters for Simultaneous Removal of Fly Ashand Sulfur Dioxide. 111. Reac- tion of Sulfur Dioxide with Half-Calcined Dolomite,” J. Air Pollut. Control Ass. 21, 272-76 (1971). 176 6.3.4 NO, Formation The low combustion temperature characteristic of fluidized-_bed combustion tends to keep the formation of NOx to a low level, but the gas transit time through the high-temperature region is sufficiently long that the equilibrium concentration of NO; can be reached. As shown in Fig. 6.11, this condition makes the NO, concentration in the stack gas quite sensitive to the amount of excess ORNL-DWG 74-12796 4000 — 2000 7 / // EXCESS AIR (%) / T / § 1000 / wl a > . o o £ 500 139 z V T8 Q : // 7 - £ | / /- c / Z 200 g / : / ; Q = o x / = 100 / 7 o o / oW ) 50 20/ . : 1600 2000 2400 2800 3200 3600 GAS TEMPERATURE (°F) Fig. 6.11. Effects of gas temperature and the amount of excess air on the calculated equilibrium nitricr oxide concentration in combustion products. 177 air,”® and this in turn places a premium on the use of a control scheme that will hold the amount of excess air to a low level. - | | Fluidized-bed combustion systems can be operated over a wide range of bed temperatures and amounts of excess air, but Fig. 6.11 indicates that there is a strong incentive to keep the excess air to less than 10% and the bed temperature to 816 to 871°C (1500 to 1600°F). These conditions pose certain constraints on bed operation which may require a sophisticated instrumentation system to control air and fuel during periods of changing steam demand. 6.3.5 Development Problems The major problems that have been experienced in the development work outlined above have been with the feed of the coal and limestone into the bed, flowthrough of fines and separation of these fines from the gases leaving the bed, and either the regeneration of the calcium sulfate to calcium oxide or finding some commercial use for the calcium sulfate—ash mixture produced from the process. Relatively little difficulty has been experienced in getting good combustion in the bed, the principal problem being the avoidance of excessive burning rates and hot spots at the points where the coal is introduced into the bed. Note that the bulk of the work carried out to date has been with beds having areas of 1 to 10 ft>, where agitation of the bed is reasonably effective in distributing the coal. However, the beds envisioned in commercial systems will have areas of 100 to 200 ft*; hence scaleup uncertainties include problems associated with devising provisions for a large number of coal feed points across the bed, the distribution of coal and limestone across the bed, the upper limits of gas velocity and bed depth, the size and spacing of heat transfer tubes, and the control of power level. The rate of c_:orrosiori/ erosion attack on the combustion side of the tubes in the coal combustion chamber has received relatively little attention; thus a phase of the future ANL program will be directed toward materials compatibility. | ~ Figure 6.12 presents the projected time schedule for the current national program to develop fluidized-bed combustion technology.'® The fluidized-bed boiler is not commercially available and cannot be expected to be until the prototype is evaluated. It should also be noted that most of the effort.is directed toward development of systems to be used by electrical utilities, although much of this technology should also apply to industrial systems. : 6.3.6 Economic Analyscs Since there are no fluidized-bed boilers commercially available, there are no commercial prices on which. to base an estimate. _ Pope, Evans, and Robbins'® presented a cost estimate for a complete plant of 500,000 1b/hr at 600 psi and 399°C (750°F). They itemized all capital equipment and operating costs for comparable fluidized-bed, spreader-grate, oil-fired, and gas-fired boilers. The owning and operating costs, less fuel, for the fluidized-bed boiler is 1.4 times that of the gas-fired boiler, and that for the spreader grate is 2.35 times that of the gas-fired boiler. The report rationalizes that the fluidized-bed boiler is significantly cheaper than the spreader-grate boiler because it is more compact, contains less surface, and can be factory assembled. | ’ ' B . 110. Personal communication from George Weth, Office of Coal Research, to Truman D. Anderson, ORNL. e ——— ey ORNL—-DWG 75—1966 - 1983 , FISCAL YEAR SUBPROGRAM 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 I 1 I START - EVALUATION I j . . INITIAL PROGRAM START COMPLETE CONTRACT INSTALL OPEFII:\TE ATMOSPHERIC 30 MW PILOT — o A = ATMOSPHERIC INDUSTRIAL PESIGN °°gSTRU°TA°PERATE ATMOSPHERIC 200—-300 MW PILOT SOFTWARE DESIGN CONSTR_UCT OPEHAT_E & B = B ATMOSPHERIC RETROFIT (20 MW) DESIGN _CONSTRUCT | OPERATE & =3 CPU 400 DESIGN CONSTRUCT OPERATE . CONSTRUCT OPERATE 0 START- PRESSURIZED 3 MW UNIT CONTRACT UP | TEST PRESSURIZED ADVANCED POWER DESIGN CONSTRUCT OPERATE CYCLE PRESSURIZED 100-300 MW PILOT DESL'?N CONSTRUCT QPEEATE COMPLETE COMPLETE PRELIMINARY COMPLETE VARIABLE SUPPORT DESI 630 kW PILOT (MINI—PLANT) GN DESIGN STARTUP TEST PROGRAM PROGRAM B3 A = A OPERATE 2nd . ' COMPLETEICONSTRUCT COMPLETE DESIGN CONSTI::CT GENER_ATION ' r 2nd GEN. 2nd GEN. - TRA \ DEVELOPMENT OF FLEXIBLE oesneg FACILITY.' PLANT PL&; nd GEN. 2n. DEMONSTRATION TEST FACILITY I [ ‘1“ ‘l‘ ‘ ‘f ‘I‘ i | © 1867 1968 1969 1970 1971 1972 1973 1974 FISCAL 1976 1976 YEAR Fig. 6.12. National fluidized-bed combustion program. 1977 1978 1979 1980 1981 1982 1983 8.1 179 In a telephone communication, Foster-Wheeler Company''! stated that they felt that the fluidized bed would cost about the same as a conventional coal-fired boiler; however, the total plant cost would be less because no stack-gas cleanup system is required. The cost estimate of Table 6.18 therefore is based on a “standard” coal-fired boiler cost of $25 per pound of steam per hour. Table 6.18. Estimated cost of steam using a fluidized-bed boiler ' Plant capacity, 3 X 10° Ib/hr Unit boiler capacity, 300,000 Ib/ht (10 units) 90% availability, 85% efficiency, 3.5%‘8—12% ash coal Item Axmuazl cost Unit6 cost | (10°%) (¢/10° Btu) | Capital cost — fuel and ash handling, flue gas 16.600 60.7 cleaning, building, and electrical calculated at ' $25/Ib/hr, $75 x 108 i Limestone injection (at $8/ton) . 1.82 6.6 Repairs and maintenance at 5% of capital -~~~ 375 13.7 Labor, 17 men/shift at $7.70/hr 1.225 4.5 Electricity, 33 X 105 kWhe/year at 1.5¢/kWhr 0.495 1.8 Ash and spent limestone disbosai at 2.5¢/ton | 0.099 04 Owning and operating cost, less fuel 24.039 | 877 Fuel, coal at 74¢/10° Btu | 23.865 87.1 Total - ' 17_9—- | 175 6.3.7 Direct-Fired Process I_-Ieaters' Fluidized-bed combustion can be applied to process fluid he'ating in two fashions. The fluidized- bed boiler can be used as a process fluid heater essentially by pumping the process fluid through the sub- merged and convective heat transfer tubing. Foster Wheeler, who is familiar with both the process heaters and the fluidized-bed boiler, has done a prehmmary study and feels the fluldnzed-bed boiler is su:table as a process flUId heater with the followmg reservations. : 1. The heat flux in the submerged surface is about five times that of convective or radlatlve surfaces, so the film coefficient of the fluid must be adequate to assure transfer to the bulk fluid B wnhout overheatmg at the wall 2. The heat capacity of the bed is high; so in the eve;nt of loss of 'flow,’even thotlgh the fuel is shut off, a significant heat addition to the fluid will contmue ‘The system must be designed to accommodate the results of overheatmg the process fluid. A flu1dlzed-bed burner (no submerged heat transfer surface) can be used as the heat source for conventional or existing process fluid heaters (or bmlers) by ducting the cleaned combustion gas to the heater. It may be desirable or necessary to install radiative surface above the bed for combustion 111, Private communication from Henry Phillips, Foster Wheeler Corporation to E, C. Hise, ORNL. 180 temperature control. The burners have been commercially available for over 12 years, have been built in sizes up to 300 X 10° Btu/ hr, and are conventionally equipped with heat recovery boilers and emission control equipment. They have been designed to burn liquid wastes, sludges, and wood wastes (including logs) and can be designed to burn any conventional fuel, including coal. Although there have been no retrofit installations of burners to existing heaters or boilers, one manufacturer stated a willingness to design and fabricate such units and is now preparing a conceptual design and cost estimate for a prospective client. This application represents a reasonable modification of existing technology, and the design and delivery time are felt to be comparable to those of conventional industrial equipment. 6.4 LOW- AND INTERMEDIATE-Btu GAS 6.4.1 General Description One possible way to burn coal and meet emission standards is through a two-stage combustion process in which the coal is partially oxidized in a gasifier, the particulates and sulfur are scrubbed from the gas stream, and the gas is burned in a boiler or radiant furnace. The process may be retrofitted to existing equipment burning gas, oil, or coal or may be integrated with new capacity construction. The gas produced has a heating value of 150 to 300 Btu/scf, depending on whether air or oxygen is used in the gasifier. Oxygen-blown gasifiers produce a gas with a heating value that is intermediate between low-Btu and pipeline-quality gas (1000 Btu/scf). Intermediate-Btu gas has a heating value range of about 300 to 500 Btu/scf. Because of the low-Btu content, the gas is not economical or suited for pipeline gas, but neither of these constraints apply to in-plant or perhaps regional distribution. The advantages of gasification as opposed to direct coal combustion followed by stack-gas cleanup, in addition to the fact that the gasifier may be retrofitted to existing gas- or oil-fired equipment, are that the volume of gas to be cleaned is appreciably less and that the sulfur is in the form of H.S as a result of the reducing atmosphere in the gasifier. Estimates of the fuel energy utilization of the processes range from 75 to 90%, depending on the specific process and the amount of heat recovery equipment installed. Estimates of existing furnace derating with low- or intermediate-Btu gas range from 5 to 30%, depending on the fuel it was designed for, the method of firing, and size.'" | There are at least four companies offering gasifiers commercially in the United States and - at least one industry firing its furnace with generated gas. However, that one installation is about 17 years old, and there have been no commercial gasifiers built in the United States in the interim. Processes for the production of low-Btu gas generally contemplate the use of a gasifier in which hot coal or coke is contacted with air or oxygen and steam at temperatures ranging from 927 to 1371°C (1700 to 2500°F) and pressures from atmospheric to about 450 psig. The oxygen in the air or from an oxygen generator reacts with carbon to form carbon monoxide, with the evolution of a 112. A. M. Frendburg, “Performance Characteristics of Existing Utility Boilers when Fired with Low Btu Gas,” presented at the Electric Power Research Institute Symposium on Power Generation—Clean Fuels Today, Monterey, Calif., Apr. 8-10, 1974, 181 considerable quantity of heat:'" C+1/20; — CO (AH = ~26,416 cal/g-mole) . This reaction supplies the heat needed for the endothermic water-gas reaction, in which carbon and steam react to produce carbon monoxide and hydrogen: C + H,O(g) — CO + H, (AH = +31,382 cal/g-mole) . The CO shift or water-gas shift reaction also occurs to a significant extent. In this reaction, carbon monoxide reacts with steam to yield carbon dioxide and hydrogen: CO + H;0(g) —~ CO; + Hi (AH = -9838 cal/g-mole) . Another important reaction is the formation of methane from carbon and hydrogen; C + 2H; —~ CH. (AH = -17,889 cal/g-mole) . However, this reaction takes place only to a small extent at the conditions used in the gas producers under consideration. Under the high-temperature conditions and in the reducing atmosphere of the reactor, sulfur compounds in the coal are decomposed principally to H,S, with small quantities of carbonyl sulfide (COS) and carbon disulfide (CS.) also being produced. The decomposition or cracking of large coal molecules also yields tars, oxygenated compounds such as phenols, and light hydrocarbons such as methane and ethane. Some of the processes claim complete gasification of these compounds. After particulate matter, tars, phenols, and sulfur compounds have been removed, the principal components of the low-Btu gas are carbon monoxide, hydrogen, nitrogen (if air is used), carbon dioxide, and methane. 6.4.2 State of Development and Commercial Availability , The principal prbcessés_ for producing low- and/or intermediate-Btu gas are summarized in Table 6.19. The Lurgi process is offered by the American Lurgi Company, New York, N.Y. 10017; the Koppers-Totzek -process is offered by the Koppers Company, Pittsburgh, Pa. 15219; the ~ Wellman-Galusha process is offered by the McDowell Wellman Company, Cleveland, Ohio 44114; and the Winkler process is offered by Davy Powergas, Inc., Lakeland, Fla. 33803. _6.4.3 System Characteristics Coal gasification processes may be categorized according to the type of equipment in which gasification takes place. First, there are the so-called fixed-bed processes, of which the Lurgi and Wellman-Galusha are typical. In these gasifiers, a bed of coal moves slowly downward and is contacted by an upflowing stream of hot gases. A second type is the vortex-flow combustion chamber - gasifier, typified by the Koppers-Totzek process. Pulverized coal and oxygen-enriched air are injected into a refractory-lined chamber in which rapid combustion and gasification take place, and molten ash (slag) is withdrawn from the bottom. A’ third type includes fluidized- or entrained-bed gasifiers, typified by the Winkler process. In these gasifiers, the coal particles are 113. Heats of reaction given'here are at 25°C (77°F) with H,O in the gaseous state. 182 Table 6.19. Proposed processes for the production of low- and intermediate-Btu gas from coal . Gasifier P Process G::f:r ‘ pressure o:;;z‘;g Comments (psig) Lurgi Downward moving stirred 300-450 Airor Process is in commercial operation bed, nonslagging oxygen '~ onsized, noncaking coal; plans ’ are under way to test operation on caking bituminous coal ' Koppers-Totzek Concurrent solid-gas - 1-5 Oxygen or Process is in commercial operation combustion, slagging oxygen-enriched using oxygen; offered in sizes to air 35 tons of coal per hour; tests are planned using enriched air; can _ handle any type of coal Wellman-Galusha Downward moving stirred 1-300 Air or Process is in commercial operation bed, nonslagging oxygen : using coke or noncaking coals, mostly in the steel and ceramics industries; offered in sizes to 7000 I per hour of bituminous coal; Bureau of Mines has a pilot plant operating on caking coal at pressures up to 125 psig, capacity about 20 tons/day; tests are planned at 300 . psig to increase throughput - Winkler Fluidized bed 15 Air or Sixteen installations were built oxygen outside the U.S. from 1926 to 1960 with generator capacities of 100300 X 10° Btu/hr; three installations are presently in operation; process description states it will operate on all coals; tests are planned at 15 atm suspended in rapid motion in an upflowing stream of hot gases. Several gasifiers, including the Bigas, Hygas, Synthane, CO, Acceptor, Burcau of Mines hydrogasification, and Union Carbide ash-agglomerating types, are under development. The three categories mentioned comprise most of the processes proposed thus far. Other types include the Kellogg process and the Atgas process, in which the gasification reactions occur in molten salts and molten iron respectively. The subsections that follow contain more detailed information concerning the various gasification processes and processes for removing sulfur compounds from the raw gas. 6.4.4 Commercial Systems Presently Available Lurgi process ~ The Lurgi'' gasifier (Fig. 6.13) operates at a pressure of about 300 to 450 psig. Sized coal enters the top of the gasifier through a lock hopper, and air and steam are blown in at the bottom. The gasifier may also be oxygen blown. The coal travels downward and, after gasification is completed, is discharged as a dry ash through a rotating grate. Raw gas exits from the top of the gasifier and is - routed to a scrubbing system where solids, tars, H,S, and COS are removed. The finished gas has a higher heating value of 150 to 230 Btu/scf and is at a pressure of about 290 to 450 psig. 114. The Lurgi Process: The Route to S.N.G. from Coal, American Lurgi Company, New York, N.Y. 183 '~ ORNL-DWG 73-12398 JACKET STEAM . TO GRATE COAL DISTRIBUTOR WATER JACKET Fig. 6.13. Lurgi dry-ash fuel gas generator. Many Lurgi gasifiers have been operated successfully on nonswelling coals. More than 50 units have been built, primarily in Europe. The capability of the Lurgi gasifier for operating on typical eastern U.S. bituminous coals, which tend to swell, become sticky, and cake, is now being demonstrated. | , ' LT ' , Commonwealth Edison Company'"’ is proceeding with an installation of three Lurgi gasifiers at their Powerton Station. The plant capacity to be sUpplied by low-Btu gas is 120 MW(e); startup is 115. J. Agosta et al., “Status of Low Btu Gas as a Strategy for Power Station Emission Control,” presented at the - A.L.Ch.E. Meeting, New York, Nov. 26-30, 1972, 184 expected to be in 1975. A feature of this installation is that the finished low-Btu gas will be expanded (not combusted) in a power recovery turbine to slightly above atmospheric pressure before being burned in the existing Powerton steam boiler. The turbine will drive a generator which will provide approximately 4 MW(e), furnishing the electricity needed to drive the compressor for the air supply to the gasifiers, plus some excess power. This scheme will permit the station to operate at full power with no derating. The net power efficiency of the low-Btu gas system is estimated at about 80% by Commonwealth; desulfurization efficiency is expected to be about 90%. ' Koppers-Totzek process In the Koppers-Totzek'™ process (Fig. 6.14), pulverized coal, oxygen (or oxygen-enriched air), and steam are injected into a refractory-lined cylindrical vessel operating at about atmospheric pressure. Tangential injection provides a high degree of turbulence. Combustion of the coal occurs within 18 in. of the point of injection, and the reduction reactions take place in the remaining space. Molten slag is tapped from the bottom of the gasifier, granulated by quenching, and removed 116. The Production of Gas from Coal Through a Commercially-Proven Process,_ Koppers Co., Pittsburgh, Pa. ORNL-DWG 73-12397 GAS OUTLET _—BOILER v/, v, PULVERIZED 22 m . / / ULVERIZED CAND / 74 GASIFICATION ////// COAL OXYGEN— 4 ZONE 2 o Np | A \ N \WATER-—SEALED s ASH REMOVAL GEAR SLAG ) ] Fig. 6.14. Koppers-Totzek gasifier. 185 through a water seal. The process has the advantage that it can gasify any type of coal; swelling or caking type coals present no problem. The process requires oxygen or oxygen-enriched air, which adds appreciably to the cost, but produces higher Btu gas. Wellman-Galusha process The Wellman-Galusha''’ gas producer (Fig. 6.15) utilizes a slowly descending bed of sized coal contacted by an upflowing air-steam mixture at about atmospheric pressure. Approximately 1000 of these units have been built to serve the open-hearth steel, ceramics, and other industries. The largest units built thus far have a capacity of about 100 tons of coal per day. Operation has been satisfactory on sized coke, anthracite, and nonswelling bituminous coals. No commercial experience 117. G. M. Hamilton, “Gasification of Solid Fuels in the Wellman-Galusha Gas Producer,” presented at Meeting of the American Institute of Mining, Metallurgical and Petroleum Engineers, St. Louis, Mo., Feb. 26, 1961. ~ORNL-DWG 73-12395 - TYPICAL BUILDING | -~ AND FUEL ELEVATOR V] OUTLINE WATER JACKET WATER SEAL [ AND DUST ' COLLECTOR AGITATOR i COMBUSTION GASIFICATION ZONE ZONE | J ' GROUND ' » & [ LEVEL L 1 5 - --—' _’- i i3 | Fig. 6.15. Wellman-Galusha fuel gas generator. fr . o e - —— - ] 186 has been accumulated on bituminous coals, such as those typically found in the eastern United States which tend to swell, become sticky, and cake when heated. There is considerable doubt that the standard Wellman-Galusha unit could handle coals of this type. However, methods for use with such coals are being investigated in a pilot-scale gasifier of the Wellman-Galusha type which has operated for several years at the U.S. Bureau of Mines facility''® at Morgantown, W. Va. This unit (see Fig. 6.16) has been operated successfully on caking coals at pressures ranging from slightly a‘bbve_atmosphe&ric to about 200 psig. Plans are under way to operate it at about 300 psig in order to increase throughput rates.'’® Caking is avoided by using a stirrer which has an up-and-down as well as a rotary motion. Rotati_onal speed varies from 7 to 30 min per revolution. The bed is supported 118. P. G. Lewis et al., Strongly Coking Coal Gasified in a Stirred-Bed Producer, Report Nd. 7644, U. S. Bureau of Mines, Morgantown Energy Research Center, Morgantown, W. Va. (1972). 119. Private communication by J. P. McGee, Morgantown Energy Research Center, Morgantown, W. Va., Feb. 27, 1973. ORNL-DWG 74-5697R HIGHEST OPERATING . POSITION ——— LOWEST ) OPERATING POSITION t=—AIR-STEAM "‘ L-—3f'r Gin.. ASH HOPPER Fig. 6.16. U.S. Bureau of Mines pilot-scale gasifier. 187 on a revolving grate,:and the ashes fall into a conical hopper at the bottom of the gasifier and are removed through a lock hopper system. . ‘ A major goal of the Morgantown pilot plant work has been to characterize the swelling-caking nature of United States coals. In increasing order of the difficulty of handling characteristics they are: Illinois No. 6, Elkhorn, Ky., and Logan, W. Va.—very easy; Upper Freeport, Ohio No. 6, and W. Kentucky No. 9 HVBB—satisfactory; and New Mexico bituminous (25% ash)—very difficult. Hydrogen sulfide removal was assumed to be accomplished by means of iron oxide absorbers. These absorbers are on stream for 8 hr and require 4 hr for regeneration. Regeneration is accomplished by blowing air through the absorber at about atmospheric pressure. The SO produced is then converted to ammonium sulfate using purchased ammonia. ' Winkler process In the Winkler process (Fig. 6.17), crushed, drled coal is transferred from fuel bunkers to the gas generators with variable-speed screws. A fluidized bed of coal partlcles is maintained in the gasifiers by the high-velocity gas stream of steam and oxygen flowing up from the bottom of the generator. Because of the relatively hlgh temperatures [800 to 1000°C (1472 to 1832°F)), all the tars and heavy hydrocarbons are reacted to form product gas. As a result of the fluidization, the ash particles are segregated according to size and density; the heavier particles fall down through the fluidized bed and pass into the ash discharge unit at the bottom of the generator, while the lighter particles are carried up out of the bed by the product gas o - ORNL -DWG 74 -5698 CONDENSATE - : - PRODUCT - i : s o /'\GAS ' , ‘ ' (T . FEED (L ‘ 'BUNKER | - S | | |wiINKLER | | | | [GENERATOR r ------ . ’ ny ' T e Lt SCREW COAL o] DRYE -' R Lonrey ASH SCREW ASH | BUNKER PROCESS STREAM - 02 OR AIR FEED WATER Fig. 6.17. Winkler fuel gas generator. — 188 to be further gasified in 't'heAS"pace_ above the bed. The manufacturer claims that great flexibility in capacity can be provided and that shutdown can be achieved in minutes; ¢.g., a generator with a nominal capacity of 2 X 10° scf/hr can be operated without appreciable loss of efficiency over the range of 0.5 X 10 to 3 X 10° scf/hr. — 6.4.5 New Systems Under Development Several additional coal gasifications schemes are under development but are not being offered commercially at the present.. Union Carbide ash-agglomeféting fluid-Béd procesé In this process,'” crushed coal is fed to the gasifier either as a water slurry or as a dry solid. It is subsequently contacted by steam and by the hot ash agglomerates produced by the combustion process. The hot ash agglomerates furnish the heat needed by the endothermic steam-carbon reaction. The gas produced contains carbon monoxide, hydrogen, and about 10% methane. - One of the advantages claimed is that the gas from the reactor is essentially dust free. A second advantage of this process is that the nitrogen in the air used for regeneration does not appear in the product gas (since the combustion gas from the regenerator is not mixed with the product gas from the gasifier). Another advantage is that the self-agglomerating characteristics of the gasifier help to collect the ash particles in the coal, thus producing a product gas that contains very little particulate matter. This simplifies the gas cleanup and facilitates use of the gas in an expander turbine for energy recovery. | The use of fluidized-bed gasification avoids the problems of swelling, stickiness, and caking that may be encountered in fixed-bed processes operating on eastern U.S. bituminous coals. If the process proves successful, it should be insensitive to the type of coal used and should be suitable for a wide variety of feedstocks, including eastern and western coal, lignites, or char. Atgas Process The Applied Technology Corporatibn Atgas process' 2 is a continuous process in which ground coal (1/8 to 1/4 in.} is dissolved by injection into a pool of molten iron. Simultancously, the dissolved coal carbon is oxidized to CO by air injected below the surface of the iron. Limestone is continuously added to react with sulfur present in the coal. The Bigas and CO, Acceptor processes, discussed in Sect. 6.5.3, can also produce low- or intermediate-Btu gas. ' . 6.4.6 Gas Purification When coal is gasified, most of the sulfur is converted to H,S, which subsequently appears in the raw product gas. Small amounts of carbonyl sulfide (COS), phenol, etc., are also formed. Gas treating processes are concerned principally with the removal of these sulfur compounds. The processes fall into 120. “New Processes Brighten Prospects of Synthetic Fuels from Coal,” Coal Age 79(4), 91-100 (April 1974). 189 two general classes: those in which the Hsz is absorbed by scrubbing with a solution of a regenerable absorbent and those in which the H,S is hbsorbed by' reaction with a solid material. A solid material absorption process that will operate at effluent gas temperature would i improve the economy and efficiency of gas1ficauon by climinating the gas:cooling step. Liquid scrubbing processes'*' for HzS removal have been in commercial use for many yearsand are highly developed. These processes can be dmded into two general categories: those in which absorption is accompanied -by chemical reaction and those in which’ absorption takes place by physncal solvent _ action alone. The latter came into prominence in the 1960s, whereas the former have been in use longer. Currently, the manufacturers of coal gasification equipment offer an alkali scrubbing system (e.g., potassium carbonate solution followed byla Claus unit to produce elemental sulfur). A Stretford plant is also offered as an alternate to produce elemental sulfur as well as several propnetary 'schemes. Additional processes are also available, as shown in Table 6.20. “Table 6.20. Summary of liquid processes for desulfurizing raw low-Btu gas - | S Temperature Pressure Product Process | Solvent§ : PCCR] (psig) Regeneration form Liquid chemical absorption : Monoethanolamine (MEA) 15-20% aqueous solution 32.2-54 (90-130) 1-10060 a H;S Diethanolamine (DEA) 15-20% aqueous solution 32.2-54 (90-130) 1-1000 a H,S Potassium carbonate 30% aqueous solution - .~ .- . . 110-127(230-260) = 1-1000 a H,S Benfield Potassium carbonate solution -110-127 (230-260) 1-1000 a H;S plus additives ‘ Alkazid Alkazid M or Alkazid DIK" 32.2-54 (90-130) 1-1000 a H;S Giammarco-Vetrocoke (H,S) Sodium arsemte-a:senate . ) - 32.2--54 (90-130) 1-1000 Air blowing 5 solution | L Stretford c 32.2-54 (90-130) 1-1000 Air blowing S Liquid physical solvent ' * - : absorption - Propylene carbonate Propylene carbonate . , H3S Sulfinol Sulfolane, diisopropanolamine H,S Selexol i Dimethyl ether polyethylene glycol o H;S Purisol -Methyl-z-pyrrohdone 32.2-54 (90-130) ~1-1000 d H,S Rectisol Methanol -17.8--16.7 (0-2) 600-1000 e H;S8 "Regenerate rich solution in a reboiler stripper column. BAlkazid M is the potassium salt of methyl amino propnonic acid, and Alkazid DIK is the potassium salt of dnmethyl amino acetic acid. The latter is preferred for the selective absorption of H, S. e ‘Aqueous solution of sodium carbonate, sodium vanadate and anth:aqumone dxsulfomc acid. 'I‘wo-stage flashing and stripping (see Ref. 120). ®Flashing and stripping (see Ref. 121). - | | i 1 i 6 4 7 Bconomlc Analyses The major items in the cost of gas productlon are coal, capital, labor, electrlclty, water, and maintenance. In an oxygen-blown gasnficgtlon plant, the capital and operating costs of the plant are also significant. As shown in Table 6.21, ithe oxygen required per pound of fuel differs considerably, depending on which of the commerc:lally available gasifiers is used. At oxygen-coal cost ratios between 1.5 and 2, the cost of oxygen represents about 50% of the raw material cost for the Lurgi process and about 60% for the Koppers-Totzek suspension gasifier. 121. C. D. Swaim, Jr., “Gas Sweetening Processes of the 1960's,” Hydrocarbon Process 49(3), 127 (March 1970). 190 - Four U.S. vendors of coal gasification equipment have supplied budgeting costs for turn-key plants with the two caveats that the amount of installed equipment is a function of the type of coal and that their unit cost estimates are being restudied and possibly will be revised. Further, there is little recent U.S. operating experience with coal gasification plants.- o — - Cost estimates are presented in Tables 6.22 through 6.25 for production of low-Btu gas (air blown) and intermediate-Btu gas from oxygen-blown plants using different gas producers and feed - coals. Oxygen plant costs were supplied by the Linde Division of Union Carbide Corporation, and coal preparation and handling costs were based on unpublished Bureau of Mines data. In some cases, vendor estimates were stated to be £50% of a firm bid cost, pending exact site location, availability of water, sulfur recovery scheme used, and delivery schedules. Because of the _uncertainties in cost data supplied by some vendors, we have presented two cost estimates each for low- and intermediate-Btu gas. We believe these estimates span the range of costs, and possibly the high estimate for low-Btu gas may be the most realistic. | - Estimated gas costs ranged from $1.86 per 10° Btu for low-Btu gas using eastern 3.5% sulfur coal delivered via New Orleans to the Houston area to $2.37 per 10° Btu for intermediate-Btu Table 6.21. Oxygen requirements of various commercial intermediate-Btu gasifiers . Oxygen required Gasifier type (Ib OfIb fuel) Lurgi 0.37 Winkler 0.49 Koppers-Totzek 0.80 Table 6.22. Estimated cost of producing low-Btu gas — eastern coal, 3.5% sulfur, 11,500 Btu/lb ' Annual production = 32.850 X 10'2 Btufyear of 120 Btufscf gas; air-blown slagging gasifiers; 80% coal conversion efficiency; gas producers, 62 units (6 are spares); $100.24 x 10° installed capital cost, including cost of coal handling and preparation equipment (first quarter 1974 dollars) Annual (10° $) Unit cost cost (¢/10° Btu) Capital charges at 22.2% fixed charge rate - ' 22.25 67.7 Repairs and maintenance materials at 2% of capital 2,52 6.1 Labor (includes 40% G&A overhead) ' 0.85 2.6 Water, 3959 X 10 gal at 35¢/1000 gal 139 42 _ Electricity, 18 kWhr/ton coal at $0.015/kWhr 0.65 20 Coal handling and ash disposal 0.30 09 Sulfur removal and recovery : 3.14 96 Annual cost less fuel S 7 30.58 93.1 Coal at 74¢/10° Btu 3039 925 Total | | 61.97 186 191 - ‘Table 6.23. Estimated cost of low-Btu gas Production: 1564 X 10° Btu/hs of 183 Btulscf gas = 11 646 % 1012 Btu/hr Conversion efficiency: 78% - Airblown pressunzeds, stirred, nonslaggmg gasifier, 85% on-stwam factor Illinois coal: 23 X 10” Btu/ton, 3.5% sulfur 6 gasifiers (1 is spa:e) $38.58 x 10° mstal]ed cost (first quarter 1974 dollars) - Annual Unit cost cost ($10%) (#/10° Btu) Capital charges at 22.2% fixed charge rate = ~ 8.56 73.5 ‘Repairs and maintenance materials at 2% of capital 1071 6.6 Electricity, 16 kWhr/ton coal (649 X 103 tons/year) 0.16 1.4 - at $0.015/kWhr Water D 020 1.7 _Treated for steam (502 X 10° lblhr steam) , 449 x 10° galfyear at 27¢/1000 gal Cooling tower makeup at 0.1% of 288,000 gpm at 2¢/1600 gal : Labor [4 shifts (includes 40% G&A overhead)] 0.88 16 12 operators/shift at $7.70/hr 1 supervisor/shift at $17,640/year : : ‘Coal preparation and ash handling - 058 50 . Annual cost less coal 11.15 - - 958 Coal at 74¢/10° Btu : 11.05 949 Total 22.20 183 | Table 6.24. Estimated cost of mtermed:ate-Btu gas Production: 2400 X 10° Btu/hr of 320 Btu/scf gas = 17 87 x 10'2 Btu/year Conversion efficiency: 78% Oxygen-blown stirred nonslaggmg gasifier; 85% on-stream factor oxygen requlrement 1500 tons/day Hlinois coal: 23 X 10° Btu/ton, 3.5% sulfur 7 gasifier uniits (1 is spare): $45 X 108 installed cost (first quarter 1974 dollars) ‘Oxygen plant: $12 X 10°® Total installed cost: $57 X 10° Annual Unit cost cost ($10%) (#/10° Btu) Capital charges at 22 2% fixed charge rate _ ' 12.65 70.8 - Repairs and maintenance materials at 2% of capital - 1.14 64 Flectricity at $0.015/kWhr . =~ - - = = i - -3.03 - 17.0 400 kWhr/ton oxygen , : 16 kWhr/ton coal (996 X 103 tons/yeat) S _ o Water S SRR 0.87 - 49 Treated for steam (625 X 10° Ib/hr steam), o 561 X 10° gal/year at 27¢/1000 gal . Cooling tower makeup, 0.1% of . 360,000 gpm at 2¢/1000 gal 'Oxygen plant cooling water, © 405 X 10 gal/hr at 20¢/1000 gal - oy S Oxygen plant supplies and maintenance ... L . _ . ... 028 16 Labor {4 shifts/(includes 40% G&A ovethead)}] o ) 1.28 7.2 Gas plant — 14 operators/shift at $7.70/hr, 1 supemsorlshxft at $17,640/year - : . Oxygen plant — 3 operatorslshlft at $7.70/hr, 1 asst. snpemsorls!uft at $14,700/year _ Coal preparation and ash dlsposal - _ 070 39 © Annual cost less coal _ i co T ' ' © 1995 111.8 Coal at 74¢/10% Btu ' 16.95 949 : Total annual cost 36.90 207 192 Table 6.25, Estimated cost of intermediate-Btu gas using vortex-flow slagging gasifiers Production: 2.86 X 10 Btu/hr of 266 Btulscf 21. 296 X 1012 Btu/year Conversion efficiency: 69.7% . Oxygen-blown, 4-headed gasifiers; 85% on-stream factor oxygen requn'ement 3214 tons/day Itlinois coal: 23 X 10° Btu/ton, 3 5% sulfur ‘ 7 gasifiers (1 is spare): $Sl % 10 installed cost Oxygen plant: $19 X 10° installed cost Coal preparation facilities: $3.6 X 10° installed cost : Total installed cost: $73.6 X 10% (first quarter 1974 dollars) . Annual Unit cost cost ($/10%) (¢/10° Btu) Capital charges at 22.2% fixed charge rate : o 16.33 76.7 Repairs and maintenance materials at 2% of capital : 1.47 6.9 Electricity at $0.015/kWhr 6.30 29.6 400 kWhr/ton oxygen 16 kWha/ton coal (1.328 X 10° tons/year) , ' Water 142 6.7 Treated for steam, 655,795 gpd at 27¢/1000 gal Oxygen plant coollng water, 20.832 x 10 gpd at 20¢/1000 gal Cooling tower makeup, 0.1% of 838 gpm at 2¢/1000 gal Labor [4 shifts (includes 40% G&A overhead)] 0.98 46 Gas plant — 8 operators/shift at $7.70/hr, 1 supervisor/shift at $17.640/year Oxygen plant — 6 operators/shift at $7.70/hr, 1 supervisor/shift at $17,640/year Oxygen plant supplies and maintenance 045 ' 2.1 Coal preparation and ash disposal ; 0.82 39 Annual cost less coal S 21.77 131 Coal (30.55 x 102 Btu) at 74¢/10° Btu . 22.61 106 Total annual cost 50.38 237 gas prepared from high-sulfur (Illinois) coal delivered via New Orleans. Also costs of intermediate-Btu gas varied with the type of gasifier used and the oxygen requirements per ton of coal. All installed plant costs and coal costs are based on a Houston area facility. Estimates of the cost of steam using low- and intermediate-Btu gas-fired boilers are presented in Table 6.26. Note that the installed cost of the plant using low-Btu gas was estimated to be about 16% higher than the plant using intermediate-Btu gas due to the additional costs for lairger ducts, fans, stack, etc., which would be required to accommodate the increased volume of gas resulting from the use of low-Btu gas. Resulting steam costs range from $2.64/10° Btu using low-Btu gas to $3.18/ 10° Btu using intermediate-Btu gas. : : Estimates of steam costs using low-Btu fuel assume new installations which have been designed specifically to handle low-Btu gas. There is some uncertainty about the use of low-Btu gas in existing boilers. ' 193 Table 6.26. Estimated cost of sfeam_ generhtion using low- and intermediate-Btu gas-fired boilers Basis: 10° Ib steam/hr at 750°F, 650 psig, 85% boiler efficiency; 90% plant availability; 1159 Btu/ib of steam with condensate returned at 250°F; turn-key basis, Houston, Tex.; installed capital cost of boiler plant: low-Btu gas, $17,500,000 and intermediate-Btu gas, $15,000,000 Annual cost ($ 105) Low-Btu gas Intermediate-Btu gas Capital charges at 22.2% fixed charge rate 3.885 3330 Feedwater treatment at 15¢/1000 Ib 0.026 0.026 feedwater (2% makeup) S Labor (4 shifts) 0.118 0.118 Operating — 1 shift supv. at ' $12,600/year; 3 operators at $9,360/year o Maintenance — 1 shift supv. at '$12,600/year; 5-man crew at $9,360/year Fringes at 40% of labor 0.047 0.047 Maintenance parts and materials 0.025 0.025 Annual operating cost less fuel 4.10 3.55 Annual gas cost (10.750 x 102 Btu/year): $/10° Btu 186 20.00 1.91 _ 20.53 2.07 22.25 237 7 _ 2548 Total cost : 24.10 24.27 25.8 29.03 Unit cost, ¢/10% Btu steam 264 270 282 318 | 65 HIGH-Btu GAS 6.5.1 General Description'*'® Basic chemistry ° The hydrogen content of coal, averaging about 5% by weight, is very low compared to that of methane (25%), which must be the major component of pipeline gas. Therefore, a key problem in conversion of coal to pipeline gas is the generation of large quantities of hydrogen which comes from . water decomposed by reaction with coal or char. The reaction of coal and steam is highly endothermic, requiring almost 60,000 Btu per mole of steam at temperatures -of about 871°C (1600°F) to 1038°C (1900°F) for acceptable reaction rates. Heat supply of this magnitude and temperature level is expensive and is an important factor in the cost of coal gasification. At sufficiently elevated pressure, hydrogen will react directly ‘with coal at the steam decomposition temperatures and liberate substantial quantities of heat (about 40,000 Btu per mole 122. H. C. Hottel and J. B. Howard, New Energy Technology: Some Facts and Assessments, MIT Press, 1971. 123. U. S. Energy Outlook: Coal Availability, National Petroleum Council, 1973, 194 of methane). Since 1 mole of methane is stoichiometrically equivalent to a mole of steam being decomposed, it is clear that the coal hydrogenation reaction can supply a major portion of the heat needed for the steam decomposition reaction if both reactions occur in the same zone. This will result in reducing the endothermic, high-temperature heat supply to one-third of the steam decomposition heat in the absence of hydrogenation, thus significantly reducing pipeline gas costs. To the extent that hydrogenation (i.e., hydrogen consumption) is incomplete, the reactor heat duty increases, and, in addition, synthesis gas generated at about 871°C (1600°F) flows from the high-tempera'ture reactor and must be converted to methane in a methanation reactor. This latter reaction, which occurs at about 316°C (600°F), releases almost 100,000 Btu per mole of methane formed from synthesis gas and requires a volumetric gas flow through a number of 'process steps four times as great as the equivalent volumetric flow of methane. Consequently, decreasing synthesis gas methanation is also important in reducing the cost of pipeline gas. | The various processes for pipeline gas production available or under development differ primarily with respect to the method of gas-solid contact, supply of heat to the steam decomposition reaction, and the extent to which direct hydrogenation of coal to methane is combined with steam decomposition in the high-temperature reaction system. Table 6.27 illustrates these key reactions. In addition to these two major process steps, the complete pipeline gas plant requires important facilities to prepare the coal for reaction, to purify and convert the high-temperature gases for methanation, and to dry the pipeline gas. Table 6.27. Reactions in coal gasification” Major reactions Steam decomposition C+H,;0->CO+H, —60,000 Btu/lb-mole Hydrogenation C+2H, - CH, +40,000 Btuflb-mole Methanation CO +3H; - CH4 + H,0 +100,000 Btu/lb-mole Auxiliary reactions Heat supply C+0y,—+C0Op +170,000 Btu/lb-mole Water gas shift CO +H,0—CO;y + Hy +14,000 Btu/Ib-mole “Heats of reaction at gasification temperature levels. High-Btu gas production A block diagram of the individual operations that must be carried out in sequence to make pipeline gas from coal is shown in Fig. 6.18. On being recovered from the stockpile, coal is crushed, ground, and dried. The coal is then charged to a pretreatment and hydrogenation operation, where it is reacted with hydrogen-rich synthesis gas and steam under pressures ranging from 400 to 1200 psi and temperatures from 649 to 871°C (1200 to 1600°F). In this operation, coal is hydrogenated to yield methane in amounts that depend on the pressure and coal activity, and the exothermic heat is transferred to the coal-steam reaction, decomposing water to generate a hydrogen—carbon monoxide mixture (synthesis gas). The process can be carried out in a commercially proved moving-bed system or under fluidized-bed or entrained solids conditions in several other processes under active S 195 ORNL-DWG 74--12806 CRUSHING PRETREATMENT HEAT WATER DRYING ' HYDROGENATION ) SHIFT HEAT SUPPLY STEAM | STEAM . CATALYTIC DECOMPOSITION |le—i SOEFFC | METHANATION - -SYSTEM DRYING ASH _PIPELINE GAS Fig. 6.18. Pipeline gas from coal—integrated facility. development. The products of the pretreatment-hydrogehation step are raw gas and hot char. In general, the pretreatment step is unnecessary for noncaking coals but is necessary for caking coals in some reaction systems such as moving or fluidized beds. | The hot char is transferred to a final gasification step, where it decomposes steam to generate synthesis gas for use in the hydrogenation step. The temperature in this part of the process will depend on the method of heat supply but could rise to above 1093°C (2000°F). Various processes available or under development combine the hydrogenation and gasification reactions in different ways. I | | The stream of gases leaving the hydrogenation section is passed through a waste heat recovery section which cools the gases to the temperature required for further processing. Depending on the rank and analysis of the coal and on the balance between the hydrogenation and water decomposition reactions used in a particular situation, the composition of this gas stream will vary “and may or may not be of suitable stoichiometry for the final methanation reaction. ‘Consequently, the cooled gas may be subjected to water-gas shift and punficatlon steps in such combination as is suitable for methanation. The methanatlon reactlon will provxde a final gas having no more CO, H,, and CO; than is permitted to meet pipeline | gas spemficatlon with good methanation catalyst life. After composition ad_]ustment and purification, the synthes1s gas is converted to pipeline gas in a catalytic methanation step using a nickel catalyst. ‘This reaction is used commercially in removing carbon ‘oxides from ammonia synthesis gas but its use in pipeline gas processmg represents an important extension of the available technology. This is a result of the much hlgher carbon oxides content of the gas, which results in much greater heat release durmg reaction. Dlss1patnon of this heat and control of temperatures are important considerations in adapting current methanation technology to pipeline use, but these are not considered major problems in pipeline gas development. 196 The extreme sens1t1v1ty of nickel catalysts requires a very thorough removal of all sulfur compounds in the punficatlon step. Hence, synthetic pipeline gas will stand out as a gas that 1S unusually sulfur free. : R After pipeline gas has been produced by methanation, the water produced by the reaction must be removed in order to meet dryness specifications for plpehne use. The major areas undergoing extensive development at the present time are the steam decomposition/coal hydrogenation steps. These are the processes that provide the best potential for cost reduction. Figure 6.19 is a comparison of high- and low-Btu gasification processes. 6.5.2 State of Development and Commercial Availability - A commercially developed process, available from the well-known firm Lurgi G.m.b.H., is well suited to most western coals and can handle the caking coals of the eastern fields after pretreatment, including agglomeration of the fines, which cannot be used in the Lurgi moving-bed reactors. ThlS coal preparation would require some modest development work. . Some development work is also needed for catalytic methanation, but this effort should be substantlally smaller than that needed for gasification. Other steps, such as crushing, drying, water-gas shift, and gas purification, are well known and available commercially. These would require very minor adaptation for pipeline gas operations. A number of coal gasification processes are currently under active development in the U.S. These are concerned largely with the coal gasification and coal hydrogenation reactions and with the method of heat supply. A development program between the Office of Coal Research (OCR) and the American Gas Association (AGA), now under way, is funded at the level of $30 million per year. The major emphasis of this program is on three processes: Hygas, CO; Acceptor, and Bigas. The Bureau of Mines is independently involved in work on two processes. The most advanced of these with respect to stage of development, is the Synthane process. Other processes which are bemg investigated include Atgas, Molten Carbonate and Hydrane.'? - : The Lurgi process and each of the four major U.S. processes under development (Hygas CO, Acceptor, Bigas, and Synthane) are described in more detail below. 6.5.3 System Characteristics Lurgi process The Lurgi process* offers a commercial method for producing high-Btu gas. El Paso Natural Gas Company is planning to operate a coal mine and build a coal gasification plant in the northwest corner of New Mexico. This facility, known as the Burnham Coal Gasification Complex (Fig. 6.20), will convert 28,249 tons/day of Navajo coal to 288 million ft’ of pipeline-quality gas. The complex | will utilize Lurgi coal gasification, purification, and enrichment technology to produce 972-Btu/ scf gas plus by-products such as sulfur, coal tar, tar oil, naphtha, crude phenol, and ammonia solution. In the Lurgi gasifier, crushed raw coal less than 1 in. in size is heated and then devolatilized by the countercurrent upward flow of hot gases generated by coal combustion and steam decomposition in the 124. El Paso Natural Gas Company, Burnham Coal Gasification Project, Docket CP 73~l3l Federal Power Commission, October 1973. : HIGH—-Btu GAS REMOVAL OF CARBON DIOXIDE METHANATIONE; 700°F NICKEL TO 850°F CATALYST LiauID § PURIFICATION SHIFT CONVERSION STEAM —m—e 197 ORNL—-DWG 75-1969 LOW—Btu GAS ¢ -\ CARBON MONOXIDE + HYDROGEN - 4 METHANE + CARBON DIOXIDE Q :) SUFLUR REMOVED ) SULFUR REMOVED 'PURIFICATION X CARBON DIOXIDE + HYDROGEN = CARBON MONOXIDE + STEAM 5 t - : - CATALYST ) OF TAR OF TAR : AND DUST - AND DUST - ———"sr—=1 CHAR + OXYGEN - GASIFICATION -';,;.; :‘::-: CHAR + STEAM - GASIFICATION \:.: sl 0 + NITRO ) -..'--'_": *s1 CARBON MONOXIDE + ] A ani, STEAM — |q2':):=" 2] HYDROGEN STEAM—= . wilin i el s ;-_f‘. CHAR + STEAM — OXYGEN CHAR + HYDROGEN —» METHANE COAL + HYDROGEN - XY METHANE + CARBON OXYGEN ................................ ----------------------------------------------------------------- - CHAR AND GAS CHAR AND GAS DEVOLATIZATION COAL PREPARATION Fig. 6.19. Comparison of high- and low-Btu gasification processes. HYDROGEN + CARBON MONOXIDE ORNL-D WG 74-12804 NITROGEN AlR OXYGEN PLANT = L Q > > o OXYGEN COAL _ BLOWN PREPARATION COAL GASIFIERS = T W FEED & COAL :‘ w =4 AIR AIR BLOWN FUEL GAS COAL GASIFIERS ET L4 L) | w TREATED WATER Fig. 6.20. Simplified process flow diagram of Burnham coal gasification complex (El Paso, 1972). TAR AND HoS T0 QUENCH ~ NAPHTHA — Ty INCINERATOR WATER 2 ATMOSPHERE BYPASS GAS L ELEMENTAL SULFUR . r— S TS S S q' - TAR ! SHIFT L’ GAé J COMP"ESS'ON PIPELINE SEPARATION > 1ON P METHANATION AND s CONVERSIO PURIFICATION DEHYDRATION GAS > LIQUOR NAPHTHA, TO STORAGE ASH P x = 9 WATER TO = 3 RAW WATER E 3 TREATMENT GAS LIQUOR POWER — AND AND STEAM EFFLUENT PLANT WATER TREATMENT POWER TO RECLAIMED WATER AQUEOQUS PLANT USERS i TO IN-PLANT USERS AMMONIA 3 | , TO PHENOLS ATMOSPHERE TO STORAGE 861 199 gasifier base. The gasifier is essentially a refractory-lined, water-cooled cylindrical shell approximately 12 ft in diameter with dry ash removed in granular form via a lock hopper. To prevent clinker formation, the highest temperature in the gasifier is held below the coal ash fusion temperature 1093 to 1482°C (2000 to 2700°F). Because the coal moves by gravity to a fixed grate at the base of the gasifier, it is sometimes called a gravitating-bed gasifier. Low-Btu producer gas leaving the gasifier atapproximately 510°C (950°F) and 300 psi is cooled to saturation temperatufe [160°C (320°F)] in a waste heat boiler and cleaned in a water scrubber to remove residual tar and dust. Sulfur compounds (H,S and COS) may be removed by any of a number of wet or dry processes. Most desulfurization systems absorb the sulfur compounds with a material which is subsequently regenerated. The H,S-rich gas from the stripper regenerator may then be sent to a Claus converter to produce elemental sulfur. Final processing includes the shift conversion and methanation, which will increase the heating value of the gas to about 972 Btu/ scf. Hygas process (Institute of Gas Technology) The main units in-this process (Fig. 6. 21) are a two-stage fluidized-bed hydrogasifier and a fluidized-bed synthe51s-gas generator, both operating at 1000 to 1500 psi in generally countercurrent flow of solids and gas. Caking coal (< Yo in.) i is first made nonagglomeratmg by pretreatment (partial devolatilization) with hot air in a fluidized bed at 1 atm and 399°C (750°F) (with off-gas not entering the product-gas stream) and is then mixed with light oil to form a slurry which is pumped into a fluidized drying bed, operating at 316°C (600°F) and 1000 to 1500 psi, where the light oil ' evaporates | | | ' Coal from the drymg bed passes successively through the first stage of the gasifier, where devolatilization and partial noncatalytic methanation occur at 704 to 816°C (1300 to 1500°F) in the presence of hydrogen-rich gas; then as char into the second stage, where partial gasification at 927 to 982°C (1700 to 1800°F) occurs by reaction with steam plus hydrogen-rich gas; then in part as a by-product char sidestream (sometimes oxygen) and in part as residual char into the synthesis gas generator for reaction with steam at 982 to 1038°C (1800 to 1900°F); and finally out as ash. Generally counter to the solids movement is the flow of steam and oxygen into the synthesis gas generator. The hydrogen-rich gas from the generator, together with more steam, goes to the second or bottom-stage gasifier for partial methanation, small in amount but sufficient to supply thermal “needs for the steam-carbon reaction; to the cooler first stage for more methanation; and then to the drying bed and out as product gas to the purification and catalytic methanation system:. Synthesis gas is produced from hydrogasifier spent char, steam, and oxygen in a fluidized bed " operating at the pressure of the hydrogasifier. The Institute of Gas Technology has developed a ~ controlled-divergence feed of the oxygen-steam into the fluidized bed that was found necessary to prevent local hot spots and associated agglomeration. The synthesis gas is shifted in composition by “steam addition, catalysis, and carbon dioxide removal. The hydrogen-rich gas is mixed with steam and fed to the second " stdge of the hydrogasifier. Because the oxygen is added in a separate reactor followed by shift conversmn and CO; removal, considerably less is requlred than in other processes which add oxygen directly to the gasifier. : ~_An 80-ton/day (1.5 X 10° £¢° '/day) Hygas plIot plant'® is 1ocatcd in Chicago_ and is currently ope_ratmg for periods up_ to 6 or 7 days. The_plant has been using the electrothermal method of 125. Dr. Roger Detman, C. F. Braun and Company, personal communication to J. E. Jones,J r.,ORNL, February 1974. 200 ORNL-DWG 7412805 sl 80% OF PURIFICATION SLURRY PREPARATION HYDROGASIFIER o SHIFT CONVERTER AND CARBON DIOXIDE REMOVAL STEAM GASIFIER Fig. 6.21. Hygas process. hydrogen production, which is a batch operation in the pilot plant, but the economic potential of electrothermal hydrogen is not good. The alternate, steam-oxygen, will be incorporated in -the middle of March 1974 with operation expected in May. Plans are to run the plant continuously for 30 days, which should be adequate to demonstrate the gasifier technology. CO:-Acceptor process (Consolidation Coal Company) In this process'?® (Fig. 6.22), lignite (s to ‘s in.) is devolatilized at 140 psia in the presence of steam, carbon monoxide, hydrogen, and dolomitic calcine (MgO-CaO) in a fluidized-bed devolatilizer kept at 816°C (1500°F) by addition of calcine at 1021°C (1870°F). Char from the latter is fed to a gasifier bed containing calcine and operating at 827°C (1520°F) and 150 psia in a fluidized-bed regenerator which receives separate streams of partially carbonated calcine (MgO-CaCOs) from the devolatilizer and gasifier, returns regenerated calcine to the same units, and sends waste gas to an energy recovery system. The circulating solid material, introduced as 126. George P. Curran et al., Development of the CO: Acceptor Process Directed Toward Low-Sulfur Boiler Fuel, Consolidation Coal Company, November 1971. 201 ORNL-DWG 75197 IZER . | COAL DEVOLATILIZER \cLonE METHANATION PR EPARATION ........... SYNTHETIC NATURAL NICKEL GAS fCATALYST _ s COMPRESSION PURIFICATION REGENERATOR CYCLONE HooLOMITE . (MgO CaO3l I. g ‘P.m - DOLOMITE] - AND CHAR A FLUE GAS 1500°F DOLOMITE (MgO'CaCO3l AND CHAR Fig. 6.22. CO:-Acceptor process, dolomite (MgCO;-CaCO3), evolves carbon dioxide with absorption of sensible and chemical energy in the regenerator and accepts carbon dioxide and releases both sensible and chemical energy in the devolatilizer and gasifier. Gas from the gasifier, rich in hydrogen and carbon monoxide, is fed with steam to the devolatilizer; the gas is ‘then purified, catalytlcally methanated, and compressed. The process is also designed to operate at about 300 psia, in which case temperatures in the regenerator and gasifier change to 1060°C (1940°F) and 857°C (1575° F), and the gasifier operates with a recycle stream. The 30-ton/day COz-Acceptor pxlot p.ant 123 s located in Rapid City,, S.D. The pilot plant simulates only the gasification part of the complete commercial plant and runs on lignite or subbituminous coal. The plant has had runs up to 100 hr producing synthesis gas; plans are to run the plant continuously for 30 days to demonstrate the gasifier technology Some current problems are agglomeration of the dolomite and sulfur corrosion, Bigas process (Bituminous Coal Research Inc.) 127 This process (Flg 6. 23) uses a vertlcal—axls two-stage gas:fier which operates at 750 to 1500 psi on either caking or noncaking coal. Pulverized coal is injected with steam near the bottom of the 127. Clean Energy from Coal Technology, U. S. Department of the Interior, Office of Coal Research, pp. 32-33, 1973. 202 ORNL-DWG 7412807 RAW GAS AND CHAR =l | —3 — : SHIFT CONVERTER GASIFIER . CTL 50—-100 atm PURIFICATION PISTON STAGE 2 FEEDER (ENTRAINED FLOW) 1400-1700°F |, I : : o _ CATALYTIC fe——sTEAM : METHANATION PIPELINE GAS | STAGE 1 (VORTEX FLOW) 2700--2800°F OXYGEN AND STEAM SLAG Fig. 6.23. Bigas process. top chamber [760-927°C (1400-1700°F)], where it mixes with synthesis gas rising from the lower chamber and volatilizes and partially methanates. The product gas—unreacted char mixture leaving the top passes through a cyclone separator from which the unreacted char stream (94% as large as the raw coal feed stream, which indicates only a little more than 509% reaction per pass, on the average) is then fed tangentially into the upper part of the lower cyclone gasification chamber where it gasifies with oxygen and steam under slagging conditions [1482-1538° C (2700-2800°F)]; the gas product is purified and catalytically methanated. The slag is water quenched to granular form and dropped to atmospheric pressure by means not yet specified. | A 120-ton/day pilot plant'* is under construction near Homer City, Pa. The pilot plant is to be completed in early 1975. Synthane process (Bureau of Mines) This process'”® (Fig. 6.24), operating at 600 psi (with proposal to go to 1000), gasifies pulverized caking or noncaking coal by passage in succession through the three zones of a gasifier: (1) a fluidized coal-pretreating top section [399° C(750° F)]inwhich the coal, injected with hot steam and oxygen, is partially devolatilized; (2) a dense fluidized bed in an expanded midsection that is fluidized by hot gases from below and provides the main residence time for completion of 128. G. Alex Mills, Gas from Coal—Fuel of the Future, Bureau of Mines, May 1973. 203 ORNL~-DWG 75-1972 1 DEVOLATILIZER : G;\SIF'ER_ CYCLONE SHIFT CONVERTER A . > DENSE PHA o P cge et -.«-fi 1100 l ] i] © fl F ' . - 1470 4 LiQuID CATALYST ~ PURIFICATION \'. . . -3 . *a e - I \' | OXYGEN o p{ 1YDROGEN PLANT MINING v HYDROGEN COAL | TO GAS PLANT am—m— PREP'N _ HEAVY SYN, CRUDE L - - (_8 MESH) - D CUIED SN SNany SN S GRS A S - C > . EAT | e . a8 CRUDE ‘ | | | -ll_ P 1 . I"@‘j _ - CYCLONE 375°F 4200 psi YDRO~ SLURRYING [}715°F | EXTRAC YCL( SOLVENT [() |WATER wASH psi HY 200% |35 pe] " ON (o pa]| SEPN [ =-®IRECOVERY|=# 580°F ® EXTRACT DISTILLA- P 7150F 500-700°F L_\ ps PLANT 1750 psi HYDRO- TION , GENATION N S SOLVENT - | + TAR LO. + e SOLVENT RICH OIL AMMON. SLURRY FROM GAS PLANT . SULFIDE SOL'N LOW--TEMP, v GAS TO GAS PLANT #— = — = CARBONIZA— TION PLANT l NOTE: P =PUMP CHAR HEAVY SYNTHETIC CRUDE AND RECYCLE SOLVENT (HYDROGEN DONOR SOLVENT) Fig. 6.26. CONSOL synthetic fuel process. 213 of the pilot plant (Foster Wheeler Corp., 1971). Funds were not made available to carry out the recommendations. This facility is now being converted to provide a facility for testing various coal liquefaction processes. COED process The Char Oil Energy Development (COED) process' ' developed by F .M.C. Corporation, is based on the multistage fluidized-bed pyrolysis of coal to produce oil, gas, and char. Catalytic hydrotreating of the oil yields a synthetic crude oil that is suitable as a petroleum refinery feedstock. The product gas can be re-formed to produce a high-Btu pipeline gas or hydrogen. The char product can be used as a boiler fuel for power generation or it can be gasified to produce synthesis gas. Figure 6.27 is an incomplete flowsheet of the process. Pulverized coal is fed through an air lock into two parallel trains of equipment, each of which includes a coal dryer, four fluidized stages.of pyrolysis, fluidized char cooler, and oil recovery and gas-recycle syStems. The heat and gas required to dry the coal and to fluidize it in the first stage are supplied by burning recycle gas from the oil recovery system. Dried coal leaves the dryer at 191°C (375°F) and flows to the stage 1 reactor. The bulk of the exit gases from the dryer (N2, CO», and H;0) is sent to or around the first stage, and the remainder is vented. Exit gases from stage 1 (N2, CO;, and H,0) are venturi scrubbed and used partly for fluidization in the char cooler and partly for recycle to the dryer; the oil and liquor from the scrubber go to a skimmer-decanter system in the second-stage recovery system. : Stages 2 and 3 are combined in one vessel. Product gas and recycle char at 871°C (1600°F) from stage 4 supply the heat required in the second- and third-stage reactors. Product gases from stage 2 flow to the oil recovery system. Product char from stage 3 at 538°C (1000°F) is heated to 871°C (1600°F) in stage 4 by combustion of a portion of the char with oxygen. Product char from stage 4 is cooled in a fluidized-bed char cooler. The product gas from stage 2 at 454°C (850°F) passes through a venturi condenser, where it is cooled to 77° C (170° F). Essentially all the oils are condensed and removed in the gas-liquid separator. The effluent gas flows through an electrostatic precipitator for fog removal and then to a spray tower to remove the last traces of oil. The gas leaving the tower at 38° C (100° F) is sent to a gas purification unit (not shown). The decanted oil, including that from the stage 1 recovery system, flows to an oil dehydrator, a filter for removal of char carried over from the second-stagé reactor,and an oil hydrotreating section. There the oil is pumped to 3100 psi, joined by recycle and makeup hydrogen, and heated to 343°C (650°F) by heat exchange on the product stream from the bottom of the hydrotreater. This stream is heated further to 413°C (775°F) in a gas-fired furnace prior to entering the top of the hydrotreater. Oil product is separated from the lighter hydrocarbons in a series of coolersand flash drums, and the product oil is pumped to bulk storage.- ' The product gas from the oil-recovery section is compressed to 410 psia. The H.S and CO; are removed by a purification system, followed by a zinc oxide guard for removal of sulfur traces. The hydrocarbon gases are then reformed and shifted with steam at approximately 300 psia, and the CO: is ‘removed. A methanation step then follows for the final removal of CO. A portion of the COED product gas is used as process heat for the reformer section and for the other areas where heat is required. Instead of using the COED process to make the three products listed above, the fuel gas (of about 500 Btu/ft’) can be used to make hydrogen at a claimed rate of about 12,000 ft’ per ton of coal for use in 136. S. K. Reed, Project COED (Char, Oil, Energy, Development), F.M.C. Corporation, September 1966. 137. H. A. Shearer, Economic Evaluation of COED Process plus Char Gasification, American Qil Company, September 1972. 214 ORNL-DWG 75-1968 TO VENT ¢ > TO VENT STACK 4 < rtq ) [ [ | ! ] 1 /E-"j\ '\T) 'sT’ ‘T STAGE 2 1 COAL ! -~ DRYER 850°F / { I e e Z — 77 ' COAL_| / /o | STAGE 3 CHAR (—200M) 375 | COOLER “ | : ‘ J 1000°F . T N | [y STAGE4| & > Yy v X ' 7 > } CHAR RECYCLE ; . GAS ' GAS T ) OXYGEN HEATER [p—® HEATER | _ N [ g—AND 1\ ' 7\ VW <« OAS STEAM , L ¢—AIR—p—T < - ST\ > ) . WATER v GAS(N,,CO,,H,0) WATER CHAR ] VENTURI ELECTROSTATIC .} SPRAY - 4= SEPARATORS | SCRUBBER .- PRECIPITATOR ™ TOWER > GAS » A < * v OIL SKIMMER HYDROTREATING L VENTURI o] GAS-LIQ, DECANTER > REACTOR —— OIL CONDENSER SEPARATOR FILTER 3100 psi 775°F , ‘ . T_. HYDR N WATER WATER DROGE Fig. 6.27. COED process. oil hydrogenation. Similarly, the char can be used to make synthesis gas. With a scale of operation large enough to consider the gas streams from COED as raw material for pipeline-quality gas, this process might be considered for integration with the methanation operations of one of the gas-making processes. ‘ A 36-ton/ day pilot plant'™ is located at Princeton, N.J. The COED process has operated well in pilot plants. | | ' The COED process is intended to maximize the gas yield obtainable by coal pyrolysis alone, with temperature staging to avoid agglomeration and countercurrent gas-char flow to minimize product decomposition. It produces about the same char yield as the standard ASTM proximate analysis for fixed carbon plus ash. The process is stated to have produced, on a 30-day run on Colorado bituminous i e e P 215 coal, the following yields based on dry coal feed: Pilot plant Bench scale (approx.) Char . 56.0% ' 60% Oil 18.7% 20% Gas ‘ 9000 scffton 8000 scffton o 16.9% 15% Gas heating value > 535 Btufscf The second column gives, for comparison, the results of earlier bench-scale experiments. These and other results, combined with product heating values, correspond to thermal efficiencies in the vicinity of 100%. Such a high value is not realistic, and it is not clear whether there were other thermal inputs; however, the data do - support the reasonable conclusion that this process operates at high thermal efficiency. The oil yield of 18.7% corresponds to about 1.2 barrels per ton of coal. H-coal process Hydrocarbon Research Inc. (HRI), under sponsorship of the Office of Coal Research, has developed a process for coal liquefaction by catalytic hydrogenation.”®'* Crushed coal (Fig. 6.28) is mixed with recycle oil to forma slurry which is pumped with hydrogen into a preheater operating at 2700 psi. The slurry and preheated recycle gas from the main reactor are pumped into the H-coal reactor, an ebullated-catalyst column operating at 2700 psi and 454°C (850°F). The catalyst, cobalt molybdate, settles below a point in the bed at which liquid product is drawn off to a hot atmospheric flash drum. There the product separates into an overhead stream that is split, part going to a vacuum flash drum which separates it into vacuum overhead product and bottoms slurry product and part to a return line to the slurrying operation. At the reactor the overhead vapors are partly condensed, and the uncondensed gas (containing most of the fuel sulfur as ‘H.S) is sent to a naphtha recovery operation, to acid gas removal, and finally to the hydrogen plant with other fuel gas. The flowsheet (Fig. 6.28) shows final products which must be subjected to further refinery operations. The char-oil product, containing unconverted solids, can be used as a fuel or can be carbonized to obtain more liquid product. The process™® has had bench-scale development in a 3-ton/day process development unit. A proposal has recently been made that a variation of the process, known as the HRI fuel-oil process, be teste'd at pilot-plant scale at the Cresap pilot plant of Consolidation Coal Company, under contract of “both compames to the Office of Coal Research The fuel-oil process will differ somewhat from the one described above. A two-reactor, two-stage conversion system will be used, with the light and middle distillate materials recycled with coal to yield the fuel-oil product stream. Residual materials remaining . unconverted would require separation and carbonization. 138. C. A, Johnson etal, Scaleup Factors in the H Coal Process, Hydrocarbon Research Inc,, presented at 65th Annual " A.LLCh.E. Mecting, November 1972. 139. Commercial Process Evaluation of the H-Coal Hydrogenation Pracess Hydrocarbon Research Inc., PB-174 696 (1965). 216 ORNL-DWG 73—4003 le VENT GAS o HYDROGEN 4 RECYCLE GAS COMPRESSOR fiis) RECYCLE GAS SCRUBBER CRUBBER FLASH GAS COAL WATER B SEPAR ATORS” MID-DISTILLATE PRODUCT REACTOR , - FEED PUMP 7~ VACUUM BOTTOMS SLURRY o .SLURRY OIL Fig. 6.28. H-coal process development unit. 6.6.5 Economic Analysis For both solvent-refined coal and clean liquid fuel, it is appreciably more economical to considera large mine-mouth plant that distributes product to several industries rather than a small plant at the industrial site. Both products are cheaper to ship than the coal and there are economic advantages of scaling to a large plant size. Solvent-refined coal A 31,100-ton/day (as received) SRC plant is considered to be located in the southern Illinois area."** The plant uses high-sulfur bituminous coal at an estimated cost of 50¢/10° Btu at the mine- mouth plant. The technical and economic data for this plant are tabulated in Table 6.31, and the unit cost of steam generation using SRC is shown in Table 6.32. ' 140. Staff Report, Study of Options for Control of Emissions from an Existing Coal-Fired Electric Power Station, ORNL- TM-4298 (September 1973). 217 ‘Table 6.31. Technical and economic data fora 31,100-ton/day SRC plant Coal required (as received) Unit coal cost Plant factor Annual coal cost Total capital investment _ ‘ Annual capital cost (at 22.2% fixed charge rate) Annual O&M cost (not including coal) Total annual cost By-products Light oil Phenol Cresylic acid Total SRC production Total production SRC unit cost Shipping cost To New QOrleans To Houston Total delivered SRC cost Houston New Qrleans 31,100 tons/day 50¢/10° Btu 09 ' $117.5 x 10° $339 x 108 $75.2 x 10° $35 x 10° $227.7 X 108 16,856 bbl/day (2697 tons/day) 90 tons/day 300 tons/day 3087 tons/day " 14,650 tons/day at 15,650 Btu/lb 17,737 tons/day = 5.83 X 10° tons/year = 182.5 X 10" Btu/year $227.7 x 10° —_— = $1.25/10° Btu 182.5 x 10'2 Btu ! $0.13/10° Btu $0.18/10° Btu $1.43/10° Btu $1.38/10° Btu Table 6.32. Cost of steam generation using SRC Basis: 10° Ib/hr of steam at 750°F, 650 gsia Estimated cost of boiler, $18.75 X 10 Annual cost Unit cost ($10%) (¢/10° Btu) Capital charges at 22.2% 4.16 45.5 fixed charge rate ' _ Operating and maintenance 0.31 34 (excluding fuel cost) - : : Unit fuel cost at production site - - 125 Shipping cost ' -8 130 Delivered fuel cost ' 1434 138% Steam cost (at 85% boiler efficiency) 217 211 2Houston. bNew Orleans. 218 Liquid boiler fuel Cost analyses have been prepared for producing liquid boiler fuel or syncrude using the direct hydrogenation method (H-coal) or a two-step extraction-hydrogenation method (using the basic SRC process plus hydrogenation).”"*'** These processes appear to have about equal economic potential at this time. . Table 6.33 presents a cost estimate for the extraction-hydrogenation process. Data are derived from an extrapolation of a Ralph M. Parsons Co. Report.'"? This estimate is considered to be more conservative than similar estimates for the H-coal process.'*> Two liquid boiler fuel products are produced plus by-product naphtha. The two products are roughly equivalent to No. 6 and No. 4 fuel oil. The boiler fuel cost presented does not distinguish between these two products. The unit cost of steam generation using the liquid boiler fuel from coal is shown in Table 6.34. 141. J. M. Holmes, ORNL, personal communication to J. E. Jones, Jr., ORNL, May 1974. 142. Demonstration Plant: Clean Boiler Fuels from Coal, Ralph M. Parsons Company, OCR R&D Report 82, undated. 143, “Coal Conversion Technology,” Chem. Engr., pp. 88—102, July 22, 1974, Table 6.33. Cost estimate for a 43,800-ton/day extraction/hydrogenation plant Coal required (as received) - 43,800 tons/day Unit coal cost 50¢/10° Btu Plant factor 0.9 Annual coal cost $165.5 X 10® Total capital investment $857 x 10° Annual capital cost (22.2% fixed charge rate) $190 x 10° Annual Q&M cost (not including coal) $32 x 10° Total annual cost $387.5 % 10° By-product naphtha production ‘ 7900 bbl/day Boiler fuel production 101,520 bbl/day = 627 x 10° Btu/day Total production 109,420 bbl/day = 676 X 10° Btu/day = 222 x 10" ? Btu/year : . $387.5x 10° . Boiler fuel unit cost 1. =$L75/10" Btu 222 x.10 “ Btu Our estimate of the confidence range of this estimate +10% Range of boiler fuel unit cost $1.58 to $1.92/10° Btu Shipping cost To Houston? $0.12/ 10° Btu To New Orleans $0.09/10° Btu Total delivered fuel oil unit cost Houston $1.87/10° Btu New Orleans $1.84/10° Btu 2 Assumed to be approximately half of the shipping cost of coal. -suitable for firing utility boilers. 219 Table 6.34. Cost of steam generation - using liquid boiler fuel from coal Basis: 106 Ib/hr of steam at 750°F; 650 psia; estimated cost of boiler, $15 x 10° Annual cost Unit cost - ($10°) (¢/10% Btu) Capital charges at 22.2% - 3.33 36.4 fixed charge rate Operating and maintenance 0.31 34 (excluding fuel cost) Unit fuel cost at production site 175 Shipping cost 1 9b Delivered fuel cost o 1se o eeb Steam cost (af 85% boiler efficiency) = 260 i 256 4Houston. bNew Orieans. 6.7 METHANOL FROM COAL The technology for making methanol is available. Several type_s of suitable coal gasifiers are available, and at least two methanol synthesis processes are in commercial use. However, no integration of this technology has ever been attempted on a currently commercial scale of production. Methanol via coal gasification would undoubtedly be produced at or near the mine mouth to obviate the extra handling and transport of raw coal. Selection of a gasifier for a methanol-from-coal plant would be significantly influenced by the site chosen for the plant and the type of coal used for feed stock. For example, foran eastern siteand caking bituminous coal, the Koppers-Totzek gasifier appears to be the optimum choice. On the other hand, for a western 81tc and noncaklng subbituminous coal, Lurgi gasifiers would be the likely choice. ' | There are many options for combining the.gasific'ation and the methanol synthesis steps required for the production of methanol from coal. Most economic evaluations which have been published have focused on the production of “methyl-fuels” for the automotive market.'**'** Because of its high cost, methanol holds no promise as a base fuel for utility boilers. However, since it can be readily transported and stored in conventional equipment, it might, under some ciréumStances, be of interest as a standby or péak-shaving fuel. A 2-week firing program carried out in 1973 by Vulcan Cincinnati, Inc., at the A. B. Patterson Steam Generating Station of New Orleans Public Serv1ce demonstrated that “methyl-fuel”is 146 . 144. T. B. Reed and R. M. Lerner, “Methanol A Versatile Fuel for Immediate Use,” Science 182(4ll9), 1299-1304 (December 1973). 145. G. A. Mllls and B. M. Homby, “Methanol—Thc New Fuel from Coal,” Chemtech Pp- 26—31 (January l974) 146. D. Garret and T. O. Wentworth,“Methyl-Fuel, a New Clean Source of Energy,” paper 9, presented at the American Chemical Society 1973 Annual Meeting, Division of Fuel Chemistry, Aug. 27, 1973. 220 Cost estimates for producing methanol via coal gasification are presented in Tables 6.35 and 6.36. The cost of steam generation using methanol fuel is estimated in Table 6.37. These estimates are based on an unpublished report which was prepared by three of the Atomic Energy Commission’s National Laboratories for Project Independence. The procss flowsheet and equipment costs were supplied by manufacturers of coal gasification and methanol synthesis equipment. Based on using a high-volatile bituminous coal having a mine-mouth cost of 50¢/ 10° Btu, the estimated cost of methanol (based on 9770 Btu/1b of methanol) would be approximately $2.90/10° Btu. o Table 6.35. Cost of methanol via coal gasification Basis: Oxygen-blown Koppers-Totzek or Winkler gasifiers; shift conversioni acid gas (H2S,CO;) removal; methanol synthesis using Imperial Chemical Industries low-temperature, low-pressure process with copper catalyst; coal feed: high-volatile bituminous A, 15% ash, 4% sulfur, 10,690 Btu/lb Raw materials As-received coal, tons/day 8260 Oxygen, tons/day 6700 Water, gpm ' 3320 Energy input, 10° Btu/day 177 Power for utilities and off sites As-received coal, tons/day 1650 Energy input, 10° Btu/day 35 7 Products and effluents Methanol (at 9770 Btu/Ib), tons/day 5000 Total energy output, 10° Btu/day 97.7 Sulfur, tons/day 390 Ash, tons/day 1260 Process efficiency Total energy output/total energy input, % 46 Estimated capital requirement (1973 dollars), $10° . «, On-site process units Gasification 54.5 Oxygen production 36.1 Gas shift conversion and purification 28.6 Methanol synthesis 38.1 Off-site units and utilities” 28.6 Contingency ' 186 Total plant investment 204.3 Interest during construction 34.5 Startup costs 9.7 Working capital : 4.1 %Includes overhead and profit and engineering and design costs, based on third quarter 1973 dollars. 221 Table 6.36. Estimated annual operating costs Cost ($10%) Coal (mine mouth) at 50¢/10° Btu 40.81 - Catalysts and chemicals 0.88 Raw water at 30¢/1000 gal 0.47 Labor | Process operating labor ($5.50/man-hour) 2.89 Maintenance labor (1.5%/year of total plant 3.50 investment) Supervision (15% of operating labor) 0.96 Administrative and general overhead (60% of total 440 labor, including supervision) Supplies Operating 0.87 Maintenance- 3.50 Capital charges at 22.2% fixed charge rate 4539 Total annual operating cost 103.67 Unit cost,? $/10° Btu 2.91 a 103.67 X 10° annual cost (5000 tons/day) (2000 Ib/ton) (9770 Btufib) (365) Table 6.37. Cost of steam generation using.methanol detrived from coal Basis: 106 Ib/hr of steam at 750°F, 650 psia; estimated cost of boiler, $15 X 10% Annual cost Unit cost ($10%) (¢{i0° Btu) Capital charges at 22.2% 3.33 364 fixed charge rate Operating and maintenance - 031 34 (excluding fuel cost) Unit fuel cost at production site 291 Shipping cost 12° ob Delivered fuel cost 3037 300° Steam cost (at 85% boiler efficiency) 396 393 “Houston. bNew Orleans. 223 Part III. Assessment Part I1I is an overall assessment of the various options described in Part II in the context of costs, commercial availability, and potential for retrofitting systems that are presently being fired with natural gas or oil. Individual assessments by the industrial representatives who participated in the study are included in this section. 7. Assessment of Energy Alternatives The following general assessment of _eoal and nuclear energy alternatives for industrial energy is specifically directed toward large industrial energy applications in the Gulf Coast region of the U.S., where industry has been using low-cost, high-quality natural gas almost exclusively. Natural gas is now quite expensive and, more importantly, may soon be unavailable to industry for steam generation and process heating at any cost. Conversion to an alternate energy source involves an almost unmanageable number of options and decrslons, many of whlch may be affected by national or mtematlonal policies beyond the control of the industries concerned. This assessment is intended to provrde some useful gurdelmes for the 1ndustr1es involved and to ontnbute along with mdustrtal mput toa better understandmg w1th1n the Federal Government of _energy system development needs for mdustnal appllcatlons Each system is evaluated in terms of its apphcatron in or near Houston Tex. Selectlon of thls reference site has tended to make western coal more attractrve as compared with some alternate site east of the MlSSlSSlppl vaer ‘The reader should be cogmzant of this factor in mterpretmg these results for altemate sites. | 7.1 NUCLEAR ENERGY Three nuclear systems were evaluated in various sizes: commercial LWRs (PWRs and BWRs), HTGRs and - the consohdated nuclear steam generator (CNSG) a small LWR development ‘concept. The cost of steam for a typical two-unit utility-financed reactor station is shown in Fig. 7.1. The 3750-MW(t) PWR and the 3000~ and 2000-MW(t) HTGRs are standard commercial sizes. The 224 ORNL-DWG 74—7093R 250 s 200 — s _ z g = 5 = g £ 3 = = g ~ il 10 o g w0l — = 8 = 8 = < a « 2 - - — TRANSPORTATION = ™ g I - —_ = « > —_— — - £ —_ — 7 ISOLATION = il — —_— — % 0&M « I — — — C — - - i FUEL . ) s \ N N CAPITAL V7 0 Fig. 7.1. Cost of steam from a utility~financed nuclear reactor. 1875-MW(t) PWR is marketed in Europe but not in this country currently. The 1000-MW(t) HTGR is an extrapolation of our cost information and is not presently being marketed. Steam costs, including an isolation loop, vary from 78¢/10° Btu for the largest LWR to $1.25/10° Btu for the 1000-MW(t) HTGR. The CNSG is not illustrated with utility financing. The cost of steam from a two-unit station with industrial financing is shown on Fig. 7.2. In this case, costs, including an isolation loop, vary from $1.08/10° Btu for the largest PWR to $2.41/10° Btu for the 314-MW(t) CNSG. | ‘Several comments are needed to qualify and explain these results. First, the cost difference between the equivalent PWR and HTGR sizes is compensated for by the higher quality of the steam generated in the HTGR. In terms of electricity production, these systems are equally competitive. However, the current HTGR design precludes the extraction of high-quality steam. Our estimate presumes a modification of the helium circulator design so that prime steam is available. Transportation of the HTGR prime steam or very high-temperature, high-pressure process steam which could be generated from an isolation loop is not economically attractive. We have assumed transportation of 650 psi, 750°F steam from the HTGR without any credit for by-product power which could be produced. e o At P P 0B 11 <8 i 5 e e 225 ORNL--DWG 74-7094R Q= gz : = = — g TRANSPORTATION 250 — § —_— - 22 ISOLATION : 5 — o O&M s g k£ s £ - S = N 200 }— s g o — — n — z 5 = o - FUEL g = o X 2 o e — B @ B F I - R ™~ - @ —— s : — — = 7 O —— " R 't U o—— ‘ f/// —_— / Z B3 \ | % = -’-’Z: v \ 't r’/// - — / - \ N 1 / 100 |— \ & 7 '/,,’/ CAPITAL N > LA ;\ 47 i s/ 77 7/ Yy 7 77 " 't 77 /7 77 7/ 77 7 v/, 77, /) /// /// /// 1 77 117 77 ,/ 50 (— 7 % b 11 Y w 07 " i 77 ¥/ /, o 4 " /) 7 vl /// /// /// /7 4 ’//, Y o0 0 M, e 77 Fig. 7.2. Cost of steam from an industry-financed nuclear reactor. Recently the General Atomic Company has-proposed a “boosted reheat” cycle for HTGR process steam application. This cycle provides a modest amount of power from the high-pressure turbine [130 MW(e) for a 2000-M W(t) reactor] and still providgs steam from the reheater at approximately 726 psia ahd_9l 3°F. A major advantage of this cycle other than the improved steam conditions is that the steam pressure is greater than the reactor helium pressure throughout the steam-generator/ reheater. Thus the potential for radioactive contamination within the steam is greatly reduced. The question of whethera reboiler is required in this case may be debatable, but even if it is required, industrial steam conditions of 650 to 675 psia and 750° F should be available. The modified cycle is acco’_mp'lished byaddinga pressure control valve on the outlet line of the reheater. Other system components are identical to the conventional HTGR cycle equipment. ' - o - A quick evaluation of the effect of this improved cycle on the cost of steam from an HTGR reveals that by allowing credit of 12 mills/kWhr for the power generated (17 mills/kWhr for 226 industrial financing) and estlmatmg the turbine generator costs, the net effect is a reduction in cost of steam of about 14¢/10° Btu for utility financmg and about 19¢/ 10° Btu for industrial financing. If the reboiler can be eliminated, there would be additional cost savings. The incremental cost increase due to the LWR reboiler is estimated to be 5¢/10° Btu. The steam conditions of the modified HTGR will probably be more favorable, although they are uncertain at this time. The same isolation loop cost (S¢/10° Btu) was arbitrarily applied to the HTGR. Steam transportation costs for the PWR and the HTGR are essentially the same. An average cost of 7¢/10° Btu per mile is applied in this analysis. It is assumed, because of the nature of nuclear reactor siting, that the nuclear ‘steam'supply may be farther away from the industrial application than alternate coal-based systems. Transportation costs must be separately evaluated in each case. The availability of a nuclear steam plant should be of the order of 85 to 90%. The question of a backup of standby steam supply to provide the 98 to 99% availability needed for the industrial applications is a difficult one. This backup is generally achieved through a muitiple of small units. The more economical nuclear units are very large. The CNSG is a much more attracuve unit size, but its small size results in a substantial economic penalty. If the industrial plant is, or can be, located near a large electric utility nuclear station, there is no doubt that nuclear energy is the best buy. | | It is also possible that a group of neighboring industrial plants could jointly utilize a two- or three-unit industrially financed nuclear station. Even so, it would be more attractive to induce the local utility to build and operate the facility either as an industrial energy supply only or as a dual-purpose industrial and electrical energy supply. 7.2 DIRECT COAL-FIRED BOILER Three direct coal-fired options have been evaluated: (1) low-sulfur western coal In a conventional boiler, (2) high-sulfur eastern coal in a conventional boiler with stack-gas cleanup, and (3) high-sulfur eastern coal in a fluidized-bed boiler. The cost of steam from these systems is shown in Fig. 7.3. Two costs are presented for low-sulfur western coal as a function of coal transportation costs. The steam costs are $1.53/10° Btu for western coal delivered by unit train to Houston and $1.78/10° Btu for western coal delivered by unit train to the St. Louis area and by barge to Houston. The mine-mouth coal cost is estimated at 30¢/10° Btu, and the total cost of coal delivered to Houston is 75¢/ 10° Btu and 96¢/ 10° Btu for the two routes. Once again we should point out that the major effect of transportation cost on western coal must be carefully considered for alternate sites. - High-sulfur eastern coal is estimated to cost 50¢/10° Btu at the mine mouth and 74c/ 10° Btu in ~ Houston. The cost of steam for a hlgh-sulfur eastern-coal-fired boiler with stack-gas cleanup is estimated to be $1.84/ 10° Btu. The stack-gas cleanup system cost, illustrated separately, is estimated to contribute 37¢/10° Btu to the total steam cost. The fluidized-bed boiler is currently under development The total steam cost from this boiler is estimated at $1.65/ 10° Btu. This estimate, which is admittedly a crude one, should be updated as the development and commercial design program progresses. However, it seems obvious at this time, barring some major setback in scahng up the concept, that the fluidized-bed boiler will be a most attractive approach for direct coal-fired boilers with high-sulfur coal. It may also be apphcable for process heaters using coal. 227 ORNL-DOWG 74-7095R 300 < < <« > - o £ 3 g E o © Z O z 250 |— g z i = Z u g = S @ i 2 z 2 z : w o« [T a o< ar} W 5 w D . - i -la:-l W 200 L— o = 20 T . w o v N S g% I 5 Q. w ‘a3z @ 3 2 S v z STACK—GAS CLEANUP = (XX Q = - - - 150 — F o&Mm w O O s < L .— w 100 }— FUEL 50 }— CAPITAL 0 Fig. 7.3. Cost of steam from a coalfired boiler. 7.3 LOW-, INTERMEDIATE-, AND HIGH-Btu GAS FROM COAL " The cost of steam from a gas-fired boiler is illustrated in Fig. 7.4. Two bars are illustrated for each process; the first représents the cost of producing the gas from coal, and the second represents the cost of steam from a gas-fired boiler utlhzmg the gas productlon cost (first bar) to develop the fuel cost for the boiler. B : : - The two processes illustrated for low-Btu gas, Wellman and Lurgi, show steam costs of $2.38 and $2.72/ 10° Btu respectively. The gas production costs are $1.57/ 10° Btu for Wellman and $1.86/ 10° Btu for Lurgi. This cost difference is almost entirely in capital cost of the equipment. Intermediate-Btu gas costs for the Lurgi and Koppers oxygen-blown gasifiers are $2.01 and $2.38/10° Btu respectively. In this case the processes are quite different, and the cost difference can be explained by the much higher oxygen and electricity requirements of Koppers process. The cost *J3[10q padij-523 B WOIJ WESIS JO 150D p'L "Fig GAS PRODUCTION BOILER GAS z PRODUCTION T FadaaNNNNNN BOILER STEAM COST (¢/108 Btu) LOW Btu GAS \\\\\\\\\\\ /////////////// ':::: WELLMAN PRI 7///// ///// 7, //////////////// 28 _\\\\Q\Ql\k\\k ‘0"0_ .4’542??2?2?222"’,42227' ,422222252222222" 2208 LURGI NONNNN AN NN INTERMEDIATE Btu GAS PNOUONRNNNNNNN I RN /// ///////// 5555353 LuRa! Z o g 8 g 3 & 8 I I I | [ | IAONNNNNANNNAY ARARNRVRRNNRYN HIGH Btu GAS \\\\\\\\\\\\\‘Qt\\\\\\\\\\\\\\\\ /////////////////////// 062 00 ARNRNRNNNNNNNY ' 77702/ 0777 IVEIdVYD 13and iz ////////////////////////////// iz §§§§§§§Z§§>}ss;~sss e TR RN A ‘ LURGI 22 SN NNNNNNNNNY /AR U.s. DEVELOPMENT PROCESSES . 960.—pL DMA—INHO 8¢C 229 of steam from the gas-fired boiler for these processes is $2.82/10° Btu for Lurgi and $3.26/10° Btu for Koppers. High-Btu gas productlon by the Lurg1 process is presented along with a projection of probable costs for the U.S. development processes. High-Btu gas is assumed to be a mine-mouth process at 50¢/10° Btu coal cost. Four major processes are under development in the U.S., and several others are receiving less emphasis. The composite projection assumes a 15% reduction in capital cost and a 5% increase in conversion efficiency as compared with the Lurgi process. The costs for high-Btu gas delivered to Houston are $2.39 and $2.19/10° Btu for the Lurgi and U.S. development processes respectively. Steam costs are $3.46 and $3.22/10° Btu respectively. Low-quality steam is pljoducéd as a by-product for all gasification processes. The Koppers process yields more steam than the others. In our analysis, no credit or value has been assumed for this steam. However, in a paper mill, where there is a large demand for low-quality steam for drying, this by-product steam could be of significant value. ' Two advantages of gasification, especially intermediate or high Btu, are ease of retrofitting and possible use as feedstock. The major dlsadvantage is obviously higher cost than some alternate methods of coal utilization. 7.4 SOLVENT-REFINED COAL AND LIQUID BOILER FUEL FROM COAL The cost of steam from an oil-fired boiler using solvent-refined coal (SRC) and liquid boiler fuel from coal is shown in Fig. 7.5. For comparison, the costs of steam from an oil-fired boiler using crude or residual oil at $1.50, $2.00, and $2.50/ 10_6 Btu are also presented. These are approximately equivalent to $9, $12, and $15 per barrel respectively. Solvent-refined coal is a developmental process in which the coal i is dissolved in a coal-derived solvent at about 700 to 800°F with a minimum of hydrogenation. Minerals are removed by filtration, and light oils and gas are removed by distillation. Inorganic sulfur is removed in the minerals, and organic sulfur is removed as H,S from the vent gas. The process shows great potential for producing a low-cost clean boiler fuel from coal. Solvent-refined coal solidifies at about 300°F and apparently can be remelted at about 400°F and fed as a liquid boiler fuel or pulverized and fed like coal. The product is about 0.6 to 0.7% sulfur and 0.1 to 0.4% ash with a higher heating value of 15,650 Btu/Ib. It should be suitable for oil-fired boilers or gas-fired boilers converted to oil. quuxd boiler fuel from coal is produced by extractlon-hydrogenatlon (the SRC process plus additional catalytic hydrogenation) or by the H-coal process. Both the SRC and liquid fuel processes provide 10 to 20% of the product in the form of high-quality gas and light oils. Qur analysis does not include any higher value credit; that is, these ~ by-products are considered to have the same value as the SRC or liquid boiler fuel. The cost of SRC is estimated to be $1.25/10° Btu at the mine mouth, and the cost of steam generation in Houston using SRC is $2.15/10° Btu. Liquid boiler fuel costs $1.75/10° Btu at the mine mouth, and the cost of steam generation in Houston using the liquid boiler fuel is $2.66/10° The cost of producing methanol fuel from coal was also evaluated but was not presented in Fig. 7.5 because it far exceeds any of the altel_‘natives. Methanol fuel from coal costs $2.91/10° Btu at the mine mouth, and the cost of steam generation in Houston using methanol fuel is $4.01/10° Btu. . 'ORNL-DWG 74-7097 - 230 -l w 2 s g g0L/# 0SZ LV 110 1vNAIS3Y HO 3ANkD o % B SsSS 1V 0 vnaisay g0 IANYD o&M R 7227777772777, mg g0L/# 08} 1V 710 IvNaIs3Iy¥ WO 3anyd NNINNY AR w4 anon S 1304 40 NOWLINAOBd B 7777 R S n Rt NANNARY V0D GaNId34 INIATOS v\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\‘\\\\\\\\\\\\\\\\k TN | - 73N4 30 NOILONAOUd m“m“mum"w§§,flunnnunufln_ _. | L | 300 — 250 g 3 g 8 ° - - (ma g01/4) 1S00 Wvals Fig. 7.5. Cost of steam from an oil-fired boiler. 7.5 SELECTED COMPARISON OF STEAM COSTS FROM ALTERNATIVE PROCESSES ._ Figure 7.6 illustrates steam costs for many of the alternatives previously discussed. This comparison and all analyses to this poirit have assumed all new equipment (boilers, etc). One point which seems obvious is that any process which is not competitive with crude or residual oil is of little near-term economic interest. Unfortunately, the long-term cost of crude oil is very uncertain. ‘ 'sassé:}md QAIIBWIS)E WOJJ $)S0D WIL3)S JO uosyédwoo p'aidg[gs' ‘gL B4 0 - 0§ - ' CRUDE OR RESIDUAL OIL AT 150 ¢/108 Btu STEAM COST (¢/10° Btu) — [63) o 001 002 0sc L HTGR 3000 MW 3-UNIT STATION UTILITY FINANCING | HTGR 2000 MW 2-UNIT STATION IND. FINANCING | LOW SULFUR WESTERN COAL FLUIDIZED BED BOILER | HIGH SULFUR EASTERN COAL SOLVENT REFINED COAL CRUDE OR RESIDUAL OIL AT 200 ¢/10° Btu g ‘ ' LURGI LIQUID FUEL FROM COAL LOW Btu GAS — LURGI V7777227227777 22222 ney, = & ~ l CRUDE OR RESIDUAL OIL AT 250 ¢/10% B » 860L—vL DMJ—INHO 1€¢ 232 7.6 RETROFITTING AN EXISTING GAS-FIRED BOILER (OR PROCESS HEATER) ~ All data to this point have been presented in terms of new capacity. The cost of steam from retrofitting an existing gas-fired boiler is presented in Fig. 7.7. High-Btu gas involves no capital expense; only fuel, operation, and maintenance costs are involved. We have assumed that conversion to intermediate-Btu gas or to oil will require 10% of the capital cost of a new boiler, and conversion to low-Btu gas will require 25% of the capital cost of a new boiler. It is presumed that adequate modifications are made, so that no loss of efficiency or capacity is incurred. ORNL-DWG 74-7089 = & FUEL CAPITAL ma go1/3 0sz [ - 7 7 ma O\ 00z RY 7/ A/, = ma g0/ 08t R 7777777777777 ~ 710 TVNQIS3Y HO 3aNnYY 7 \\\\\ \\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\ W I9YNT — SvH Mg MO1T V0D A3NId3H INIAT0S _._,\\\\\\\\\\\\\\\ 77 V0D WOH4 13nd aindin \\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\ 194N -~ SVvH Mg ILVIAIWYILNI _Om:.._ m(G mg IO:.._ _ L | 1 | 7227222220 Flg 7.7 Cost of steam from retrofitting an existing gas-fired boiler (or process heater). - - (Mg g01/8) 1SOD IVOD ? g 2 8 2 ° 233 It seems logical that gas-fired process heaters could also be converted to alternate fuels with similar capital expenditures. | Again, crude or residual oil is included for comparison. The cost of steam varies from $1.77/10° Btu for SRC to $3.03/ 10° Btu for high-Btu gas. | Figure 7.8 illustrates a selected comparison of steam costs for retrofitting vs new coal-fired boilers. The new coal-fired boiler for western low-sulfur coal at $1.53/10° Btu and the fluidized-bed boiler at $1.65/10° Btu are more favorable economlcally than any of the retrofit processes. Factors such as process heating or a hmlted plant life, which are not considered, would tend to favor the retrofit systems. ORNL-DWG 74-7101R | 3| | g % -l 5 T E3 250 — g g é % § 5 = N & & = : N N & : ¢ P RNRN o e 3 \ \ g\\ z CLEANUP \ " O\\ 5% ~ % 50 - N \ ‘7’\\ O&M 8 N N NN N N N I\ N A 100 — § \ §§ \ - FUEL N N N N N N N ¥ =~ N N N / NN N \ \ \\ Z . JcapiTaL v RETROFIT NEW COAL FIRED BOILER Fig. 7.8. Selected comparison of steam costs for retrofit vs new coal-fired boiler. 234 7.7 SENSITIVITY ANALYSIS The sensitivity of the cost of the coal-based processes to changes in coal prices, capital investment, and cost of money was evaluated. Occasionally, an evaluation such as this reveals the fact that certain processes are very sensitive to the ground rules assumed and perhaps much less (or more) attractive when assumptions are varied. In this case, the results in general do not change the order of preference of the processes significantly. Figure 7.9 illustrates the cost of steam from coal processes vs coal cost The high-Btu gas, hqmd fuel from coal, and SRC are mine-mouth processes at a reference coal cost of 50c/ 10° Btu. The low-sulfur western coal reference cost is 75¢/10° Btu delivered to Houston by unit train; the other processes are based on eastern coal delivered to Houston at 74¢/10° Btu. Figure 7.10 illustrates the cost of steam from coal-based processes as a function of the percent of reference design capital cost. The capital cost of conventional boilers was not varied; only the capital cost of the fuel process was varied. The high-Btu gas processes and liquid fuel from coal are the most capital-intensive processes. 4 Figure 7.11 shows the effects of changes in the cost of money on the cost of producing steam for ~ selected energy systems. As noted previously, the reference costs of money values used in this study are interest rate on bonds, 8%; return on equity for utility financing, 10%; and return on equity for industrial financing, 15%. Generally, the effect on the coal-based systems of increasing the cost of money is to widen the gap between the direct-fired systems based on processed coal (high capital investiment). Energy systems most sensitive to cost of money are the CNSG (small reactor) and high-Btu gas derived from coal. 7.8 CONCLUSIONS A general ranking of the various processes in other ways may provide additional insight. Table 7.1 presents a ranking by range of application. High- and intermediate-Btu gas processes are the only ones considered suitable as feedstock. Liquid fuels, low-Btu gas, and SRC could be used in process heaters. All systems are suitable for steam generation, and the HTGR and direct coal-fired systems may also be developed for process heat. The processes, ranked according to ease of retrofit to existing gas-fired equipment, are as follows: 1. high-Btu gas, intermediate-Btu gas, liquid fuels, solvent-refined coal, low-Btu gas, fluidized-bed boiler, conventional boiler with low-sulfur coal, - conventional boiler with stack-gas cleanup, I N I . HTGR, - STEAM COST (¢/10° Btu) 400 350 300 250 200 150 100 235 ORNL-DWG 74-7100 __—~ HIGH Btu GAS — LURGI l MM MM \ \ —~ INT'M. Bt GAS — KOPPERS — ~_~ HIGH Btu GAS — U.S. DEV. INT'M. Btu GAS — LURGI o - ] ,/ LOW Bty GAS — LURGI /LIQUID FUEL FROM COAL |~ LOW Btu GAS — WELLMAN N\ SOLVENT REFINED COAL / . ’ MM /H!GH SULFUR COAL — EASTERN] _— FLUIDIZED BED BOILER LOW SULFUR COAL — WESTERN \ A\ — = / | _— AN 30 -y O N D 0 70 (MINE MOUTH) l _ 70 COAL COST (¢/108 Btu) 80 90 (DELIVERED TO HOUSTON) Fig. 7.9. Cost of stcam from coal processes vs coal cost. STEAM COST (¢/10% Btu) 236 ORNL-DWG 74-7102 HIGH Btu GAS — LURGI | 400 - HIGH Btu GAS — US. DEV. INT'M. Btu GAS — KOPPERS 350 . // / INT'M. Btu GAS — LURGI - : LIQUID FUEL FROM COAL 300 — // / LOW Btu GAS — LURGI ™ | // | __——LOW Bu GAS - WELLMAN 260 o " FLUIDIZED BED BOILER 200 150 100 _ 50 100 150 PERCENT OF PROCESS CAPITAL COST Fig. 7.10. Cost of steam from coal processes vs capital cost. 237 ORNL-DWG 751970 450 HIGH-Btu 400 , / GAS 350 INTERMEDIATE—Btu AS /E!QUID BOILER FUEL e = = / 7 — 5 5 % = ' ot £ 280 / | _SOLVENT a — — , ~——="REFINED COAL — 2 . o CONVENTIONAL 5 |__—BOILER WITH 3 200 s ] SCRUBBER o ~ FLUIDIZED BED = L —BOILER = / ] ONVENTIONAL < " //gou LER, LOW— k= | SULFUR COAL 150 _,/__,/ | . LWR, 2—UNIT TATION, 1875 MW(t} EACH, UTILITY FINANCING 100 50 — 0 . : 40 -20 0 20 40 EFFECTIVE COST OF MONEY, PERCENT CHANGE FROM REFERENCE VALUES Fig. 7.11. Effects of changes in the cost of money on the economics of selected energy systems. 238 10. small LWR, 11. large LWR.- Tables 7.2 and 7.3 present date of rankings by the user’s options for action and by date of earliest commercialization or application respectively. In a sense, these are interrelated in that some of the promising developmental processes are not likely to reach commercialization on any reasonable schedule without interest and cooperation from industry as well as industrial influence on the government’s development programs. ‘ Table 7.1. Ranking of industrial energy systems by range of application at industrial plant System Steam Heat Feedstock X X 9 High-Btu gas Intermediate-Btu gas Liquid fuels Low-Btu gas Solvent-refined coal Fluidized-bed boiler Conventional firing HTGR Small LWR Large LWR Mob¢ M M b M M 3 M M 3 M M M M Table 7.2. Ranking of industrial energy systems by user’s options for action Purchase Cooperate Purchase System equipment with fuel or others energy Low-Btu gas X . X X Small reactors X X X Fluidized-bed boilers X X X Conventional boilers X x X Latge reactors X X Liquid fuels X X Solvent-refined coal X X High-Btu gas X Table 7.3. Ranking of industrial energy systems by date of earliest commercialization or application System Date Conventional boiler, low-sulfur coal . 1976 Conventional boiler, stack-gas cleaning 1976 Low-Btu gas 197678 Intermediate-Btu gas 1976-78 Fluidized-bed boiler 1977-79 Solvent-refined coal 1979-81 Liquid fuels 1981-83 Nuclear power 198284 High-Btu gas a “Earliest commercialization date is 1978; however, the prod- uct will be for pipeline and is not presumed to be available for industry. ‘ 239 8. Industrial View of Alternatives 8. I PULP AND PAPER MANUFACT URING 8.1.1 Crown Zellerbach Crown Zellerbach Corporation, a major producer in the wood indtistry, has sawmills and pulp and paper mills mainly located in the southern states and the west coast of America and Canada. The annual sawmill production is 589 million bd ft, and pulp and paper production is 2,636,000 tons. There are two pulp and paper operations located at St. Francisville and Bogalusa, La. The major difference in the operation of these two mills is that St. Francisville pulps continuously in a Kamyr digester and Bogalusa uses batch digesters. The energy requirements and problems are basically the same. The energy requirements for the Bogalusa operation, which are typical, are described here. The mill is located in the town of Bogalusa, some 60 miles north of New Orleans. The population of the total complex is 2230. ' The timber supply originates from local forests managed by Crown Zellerbach and others. The mill consumes about 600,000 cunits (=100 ft’ of solid wood) of southern pine and hardwood and produces 468,000 tons of paper annually. Twenty percent of this production is converted on the mill site to customer requirements, and the balance is converted at other Crown Zellerbach plants. Energy requirement - The overall process from wood room to finished product requires energy in the form of heat for process steam and electricity. This energy is used as follows: Wood room debarking and chipping 38 kWht/ton Pulping N 173 kWhr/ton 10,727,000 Btu/ton Paper machines . 429 kWhr/ton 9,128,000 Btu/ton Converting and power generation : 177 kWhr/ton - 10 355 000 Btu/ton ThlS amounts to a total of 817 kWhr/ton and 30 210, 000 Btu/ton of paper produced Present fuels are natural gas, bark, and black liquor from the pulping process The amounts - required per day are: natural gas, 32.5 X 10° ft’; bark, 240 cunits; and black liquor, 3,290,000 Ib solids. These fuels supply the requirements of 30,210,000 Btu/ton Special problems The major problem at the Bogalusa mill is the shortage of natural gas. The mill was designed to " burn 34 million ft*/day and has an installed generating capaclty of 55 000 kW. This allowed the mill to be mdependent of outside electrical supply except for emergencles With today’s gas shortage due to the depletion of the company’s reserves, about 24 X 10° ft*/day of gasisavailable. The plant does not have the ability to increase bark burning; therefore, the net result is that there is idle generating capacity and 18,000 kWhr must be purchased from the local authority. 240 Crown Zellerbach cannot purchase further gas supplies, and present gas reserves are depleting at a rate that they will be exhausted by December 1978 or earlier. To continue producing, the plant is bemg converted to use No. 6 fuel oil. A gas-fired boiler will be shut down and replaced with a 125 OOO-lb/ hr package unit which will burn No. 6 oil; this unit is to be on line Jan. 15, 1974, The line kiln will be converted to No. 6 oil by Jan, 15, 1974, and the first existing boiler will be converted to No. 6 oil Mar. 1, 1974. These three units will release 5 million ft’ of gas per day, which will only be banked to improve reserves. Plans are to convert an additional five boilers by the end of 1976, leaving two more to be converted in 1977 and 1978. Energy alternatives at Bogalusa 1. Short-term conditions are satisfied by converting from natural gas to No. 6 fuel oil. 2. Black liquor recovery boilers will continue utilizing the heat value of spent cooking liquor (6800 Btu/Ib). 3. The study is complete on conversion to coal as major fuel as follows: (a) install new 880,000-Ib/hr pulverized-coal-fired boiler (850 psig) with precipitator; (b) continue to operate 250,000-1b/hr wood waste and oil-fired boiler at 850 psig; (c) continue to operate two recovery boilers generating 380,000 1b/hr at 850 psig; (d) install new 40,000-k W double automatic extraction condensing turbogenerator; and (e) .continue to operate existing 15,000-kW single automatic extractlon condensing turbine. 4. Continue efforts to obtain a further gas supply. Increase of gas price to fuel oil equivalent price is resulting in increased activity in further explorations and to date indicates an upgrading of reserves ~ which may take this segment of industry through the next five years. This could change the near-term conversion plan to No. 6 fuel oil on all existing units. Recommendations Bogalusa outlined the following six recommendafions. 1. continue study on mass produced CNSG; | . further develop barge-mounted application of CNSGs; . examine commercial reactors to use m industrial park development concept; 2 3 4. use fluidized-bed boilers as base load units and incinerator capabilities; 5. cdntinue development of SRC, aiming toward end product as a liquid; 6 . continue research and development on low-Btu gas. Pfiorities Priorities were established as follows: 1. conventional boilers with stack-gas cleaning, 2. low-Btu gas, 3. CNSG, barge mounted, 241 4. fluidized bed, 5. SRC, 6. large reactors applied to industrial park. 8.1.2 International Paper Company Most International Paper Company mills are located in areas which made natural gas the primary fuel for many years, and most of the equipment was purchased and installed on this basis. This equipment has since been converted to have fuel oil capabilities. Fuel oil is now the primary fuel. Also keep in mind that in our industry we self-generate (black liquor and bark) some 40% of our fuel requirement. Also, we generate practically all of our electrical requirements through the use of extraction turbines, Recommendations The application of nuclear systems for industrial energy is not feasible at present, and future opportunities would appear to be limited. One of the most significant limitations is the availability factor of a nuclear steam plant Dual plants or a backup steam and power supply of some type would be essential. | If the development of factory-assembled barge-mounted units should progress to the point that a multiple of such small units could be justified, nuclc:ir, energy could certainly become feasible. However, under the present state of the art, this approach is not economically possible. Another possibility of future nuclear power for industrial application would be through establishment of an “energy center,” that is, the location of a large nuclear station and industrial plants so that the utility could furnish steam and power to the industries. This appears to be a remote possibility but is worthy of possible future consideration. Here again, multiple units or backup of some type would have to be provided. ' The preferred method of a coal-based system would be direct firing, both from an economical standpoint as well as maximum utilization of existing equipment. Recognizing that there will not be sufficient low-sulfur coal economically available, the preference would be high-sulfur coal with stack-gas cleémup. Present stack-gas scrubbing systems are not satisfactory, and more research is needed in this area for industrial boiler application. The direct coal-fired boiler with high-sulfur coaland an im- - proved stack-gas cleanup system is the most pro'misingtsyst'em, both for application to existing equip- ment as well as for new installations. More study is needed to better define the harmful elements of stack gas in relation to real and more meaningful requirements giving full consideration to feasibility and side effects or consequences, and the overall net effect obtained toward achieving the desnred results. Fluidized-bed boilers could have apphcatlon for new installations, but they are handicapped for 1ndustr1al apphmtlon due to poor load change charactcrlstlcs One base-loaded fluldlzed-bed unit in a plant with other boilers to carry the load changes could offer good future pOSSlbllltleS On-site gasification does not appear feasible for application at this time due to high cost of gasxficatlon equipment, as well as the problems of coal, availability, transportatlon, disposal, etc., associated with direct finng It smply does not make sense to expend huge amounts of capztal material, equipment, and manpower to gasify coal at the plant site instead of firing the coal in a boiler designed for coal firing. - 242 Mine-mouth conversion processes appear to offer good application but would probably still be more expensive than direct firing with coal. Solvent-refined coal appears to be the best possibility of the mine-mouth processes. | Based on the above, we recommend study program preferences as follows: 1. stack-gas cleanup for direct firing with high-sulfur coal system; solvent-refined coal; m'ine—moath coal:gasification;intermediat¢ and high Btu; . fluidized-bed combustion; | . energy center, process steam and power from multiple units, utility plant to industrial plant; N oA W N small shop-assembled industrial plant reactor. 8.2 PETROCHEMICAL MANUFACTURING 8.2.1 Celanese Chemical Company A hypothetical plant in the Houston, Téx., area was assumed for this study. The plant produces oxygenated petrochemicals for the bulk market with an annual capacity in excess of 2 X 10° Ib. Steam consumption is approximately 1.5 X 10° Ib/hr at 650 psig and 750°F, and electrical consumption is in the order of 25 MW(e). Direct process heat is required in a single furnace, ‘designed exclusively for fuel gas, and is not considered part of the problem. Only a small portion of the 600-psig steam is utilized in process heaters Most of the steam is broken down across turbines to 150 and 50 psig steam and condensed at that pressure. All electricity is purchased. Because of the costs and hazards involved in shutdowns, the steam plant reliability must be essentially 1009, with each individual boiler at 98.6%. Sufficient capacity is installed to allow the largest single boiler to be down without a total shutdown of a unit. 'About the only near-term option available for this plant is low-sulfur western coal. There is no way that nuclear reactors in this size range can be economically installed prior to the depletion of gas, which should be around 1980. While this is actually a near-term option, once the money is committed for boiler replacements, it becomes the primary long-term option. There are some suboptions, such as direct firing of solvent-refined coal or the char products from some of the liquefaction processes. Since coal-fired boilers could probably be easily adapted to these fuels, they represent the only long-term option. Their justification would probably be based on freight savings and by-product recovery. They must be relegated to a second-generation step, since it is difficult to imagine full commercialization on a significant scale prior to the time boilers would be ordered for 1980 operation. Also, it would probably be in the early 1980s before freight is escalated sufficiently to justify an approach of this sort. Another possible suboption is the use of fluidized-bed boilers. It appears that the cost will be essentially the same as that of the conventional coal-fired “boilers; however, there is an advantage in the ability to run high-sulfur coals. This advantage would be more pronounced in areas where high-sulfur coal is located. Oil was considered as an option due to its lower capital requirements and other intrinsic advantages. Low-sulfur No. 6 oil is probably the only oil which will be avallable but this is only in limited supply. Whether oil is viable over the long term depends on the availability and cost relative to coal. This could vary among companies, dependmg upon whether they hold reserves and other 243 factors. In this particular case, no reserves or refining capacity is available; therefore, while judgmental, it appears that oil cannot compete with coal. : There are several major problem areas in implementing-a conversion to coal. First is the capital required in a relatively short period of time. Of almost equal importance is the technical manpower required for the program. Equipment delivery could also be a problem, not only for the plant but for rolling stock as well. Railroad reliability could be questioned as the existing lines become loaded. In essence, the future of this particular plant is reasonably well established insofar as fuel supply is concerned. Continued study is required, however, for the plants of the future. This could be accomplished by keeping the current progra'tn, but on a much lower key (e.g., an update of the presentation plus new developments every 6 months). Currently, participating companies would probably be willing to furnish representatives for industrial input. In addition, special studies might be requlred from time to time, and provisions for these studies should be made in a request for appropriations. In connection with research and development requirements, it is felt that a new program should be initiated, perhaps with the same participants, to give direction to the research and development funds currently furnished by the Federal Government. It would seem today that the research and development effort is much too fragmented to be effective, and there seems to be appreciable misdirection. For example, most liquefaction processes seem to be directed toward heavy oils for power plants where coal could be used. It would seem more appropriate to direct this effort toward lighter fuels and petrochemical feedstocks. One of the longer term goals of a national program should be the marriage of manufacturing and power plants for economy and reduction of thermal pollution. How ORNL could motivate power companies to enter into arrangements of this type is not known; however, this does require acceleration of the HTGR program. The one overall problem which will continue to be an impediment to the use of nuclear power in chemical plants and refineries ‘is the lead times required. It is felt that the AEC should take the initiative in reducing these lead times. Just how this could be done through ORNL is not known, but it is a must if we are to avoid economic stagnation. - o 8.2.2 Dow Chemical, USA The Dow Chemical plant complex in Freeport T'ex' is a large integrated plant. The product mix includes chlorine, caustic, magnesium metal, and- petrochemicals such as ethylene glycol ethylene oxides, polyethylenes and styrene. The basic energy requirements are supplied from five power plants delivering approximately 6 million Ib/hr of process steam and 1 million kWhr of electricity. A block of power is also purchased from the local utility. These plants, Whlch range in age from 30 years to 4 years, are presently fueled by natural gas. The power plants have conventional-fired ‘boilers and also several advanced | combmed-cycle gas turblne—waste heat steam turbme systems The power plants, toa degree, use the chemical plant heat smk to generate electric power. - The altematlves in energy use are being studied and are somewhat hmlted Gas turbmes and * waste heat boilers require premium fuels such as natural gas and No 2 diesel oil due to metallurglcal restraints and heat-recovery surface conditions. These fuels are becommg mcreasmgly scarce and prohibitlvely expensive. Our power plants will soon have the capability of burning any oil from crude to No. 6. The petroleum fuels do not seem to be a firm alternative. 244 Coal is an alternative, but it requires new facilities to supply, transport, unload, burn, and generate steam and power. Ash handling, stack-gas treatment, and other environmental considerations are staggering in their capital and land use requirements. Designing and building coal-burning equipment require a firm coal supply that will last for the life of the plant. Boilers must be designed with the ash constituents known in order to have a highly reliable, maintainable system. Industrial power plants operate in 2 much more demanding environment than the typical public utility. The last alternative is nuclear power. The HTGR has a steam cycle that is quite attractwe to a large base-loaded industrial plant, and its low fuel cycle costs insist that it be conmdered However, the problems are large, varied, and complex; the largest plant to date—the 300 MW(e) Fort St. Vrain Demonstration Plant—has taken much too long to get to full power. The 10- to 12- year lead time and large capital cost are way out of the normal industrial planning and decision-making envelope. It is difficult to commit to a specific technology and not be able to use it for 12 years into the future and also not be able to react to new technology. This study has done a tremendous job in bringing together the present alternatives in coal and nuclear. The computer code ORCOST is a good tool to evaluate costs for large utility plants. It would be difficult to expand the model to include smaller units and industrial backpressure turbine units, but this kind of tool is needed for our evaluations. We are waiting for the results from the demonstration of the fluidized-bed coal-burning boiler. This has the potential of aliowing industrial plants to use much advanced steam cycles with an improved heat rate and still use marginal coals that otherwise would be environmentally unacceptable. The solvent-refined coal research is interesting and should contribute to future energy systems Coal technology needs much continuing research and development. More research and development are needed on underground mining to develop new technology to remove more coal from the seam. Coal preparation should be able to upgrade raw coal to remove more ash, in particular, sulfur compounds at the mine site. This particular study has reviewed stack-gas cleaning and showed how difficult and expensive this tail-end effort is. Much more work needs to be done on the front end before we contaminate the combustion air. The fluidized-bed boiler is being demonstrated for small utility use (300,000 Ib/hr). There is a very great need for a smaller size to replace the numerous package boilers that are capable of burning gas or oil. 8.2.3 Monsanto Company For plants such as our two at Texas City and Chocolate Bayou, Tex., as well as our nylon plant at Pensacola, Fla., the near-term energy options are probably (1) a transition from natural gas to residual fuel oil for boiler fuel and (2) the installation of new coal-fired boilers. Fluidized-bed combustion appears to be the choice for new coal-burning units. During the near-term period, we would hope to be able to continue the use of natural gas for direct-fired process heating. Over the longer term, we must seriously consider nuclear energy. The small HTGR seems best suited to our overall requirements. Siting limitations, while perhaps less severe than originally anticipated, may still be one of the major obstacles to overcome. Long lead times, capital costs, and operational reliability are other critical factors. In the area of future research and development priorities, fluxdlzed-bed combustion should be given added emphasis immediately, since it has the potential for solving the stack-gas problems 245 associated with.the use of coal as a basic energy source. Both industrial and central station utility energy problems should be lessened if fluidized-bed combustion yields the results it seems to offer. For the petroleum and petrochemical industries, a high priority should be given to the smail HTGR. One further area for research and "development effort should be transport of high-temperature fluids. A central station energy source with the capability for producing and transporting high-temperature fluids for use by customers presently being supplied with electric energy only could have a major impact on the industrial energy supply problem. The approximate energy use for the Texas City and Alvin, Tex., plants is as follows: . Alvin Tgxas City (Chocolate Bayou) Product o Stynne monomer Ethylene Pounds per year , - 13x10° 05 x10° Energy use _ . ' Steam, Btu/hr 1500 x 10° 2100 X 10 . Fuel (natural gas) for process 350 x 10° (1600°F) 1400 x 10° (1400°F) heaters, Btu/hr ' 7 7 Electricity purchased, kW - 36,000 60,000 Annual load factor, % | 90 ' 96 8.2.4 Union Carbide Corporation (UCC) A typical UCC Chemicals and Plastics Division plant is located on the Gulf Coast. This location was dictated by the availability of low-cost gatqral gas and of ethane and propane derived from this gas and usable for chemical feedstock. A typical plant contains one or two units for the production of ethylene and propylene. First-line derivatives of ethiylene and propane are manufactured, including polyethylene, ethylene oxide, ethanol, butanol, isopropanol, etc. Second-line derivatives of some of the first-line derivatives are also produced. Shipment from these plants may range from 1.0 to 4.0 X 10° Ib/ year. Energy requirements in these plants obviously will vary considerably, depending on the products made at the location. Energy requirements for one of the larger plants are outlined below. Steam requirements® Pressure level (psig) = - . Usage ao® _lblhr) e 1500 200 ' ‘650 - -10/10 | | 350 Total - . 2500 ‘@gee also Fig. 8.1.° Some o_f the steam requirementsk are made available by by-product recovery from the process units. 246 ORNL-DWG 751967 NATURAL GAS STEAM 1000/600 it —- BOILERS e STEAM TURBINE : GENERATOR 40 MW GAS TURBINE GAS TURBINE GENERATOR 20 MW WASTE HEAT - BOILERS PROCESS HEATERS, COMPRESSOR DRIVES RAW MATERIALS — Fig. 8.1. Typical energy cycle of UCC E&P Division. Power requirements are about 80 MW, These requirements may be supplied by a combination of topping turbines, a minimum of condensing turbines, gas turbine generators, and purchased power. - Projections indicate a trend to higher power requirements in relation to the steam requirements. In addition to the fuel required to generate steam and/or power, the plant has a fuel usage of 75 X 10° Btu/day; 50 X 10° Btu/day is produced as by-products from processing units, particularly Olefin units, and the balance must be purchased. This fuel is required for process heat, compressor - drives, and raw materials. Economics have dictated that the energy sytems havea 99+ availability to the consuming units. GENERATOR 20 MW s — = 600 Ib ——— H E (- Q 200 b To 2 fmme e PROCESS BOILERS, o uNIT SUPPLEMENT > & L7010 > FIRED S o 247 UCC is currently assessmg altemate energy sources for the Gulf Coast plants. The possibilities follow: Fuel source Natural gas Liquid natural gas Fuel oils (3) Crude oil - Coal, direct fired Coal, gasified, high Btu Coal, gasified, intermediate Btu Coal, gasified, low Btu Coal, liquefied, solvent refined Coal, liquefied, hydrogenated =~ | Nuclear, large - ! Nuclear, small Methyls UCC by-product, liquid UCC by-product, gas Purchased power Purchased steam Fuel type Gas, high Btu Gas, low Btu Liquid, distillates Liquid, residues Solids, lumps Solids, fines Fuel user Boilers, direct . Boilers, combined cycles Gas turbines Reciprocating engines Raw materials Process furnaces In general, UCC conclusions parallel those of the ORNL study; UCC does not expect that natural gas will be available for the intermediate term. Fuel oils are acceptable alternatives in many situations, but pricing problems are apparent. Union Carbride‘ agrees that the direct use of coal to generate steam is a likely prospect for the Gulf Coast plants. Problems in sizing, timing, and reliability will preclude the use of nuciear plants in the early 1980s. s : A particular problem to UCC will be to supply the process heat reqmrements that cannot be met with steam. Some of the requirements are not readily adaptable to fuels oils, particularly the heavier residues. Second-generation coal gasification technology will not be available until the early 1980s. Gasification is a logical choice for supplying those requirements. The major problem areas in implementing conversion of Gulf Coast plants to coal revolve around environmental considerations. Uncertainties in'_rg'ove'rn_rnerital policies regarding leasing of federally owned coal deposits in the west and in restrictions regarding restoring stripped areas make planning difficult. Uncertainties regarding future EPA regulations on sulfur dioxide removal also present a problem. Other problems include lengthening equipment delivery times, particularly for the mxmng equipment; fmancmg for the conmderable investment required; and competition for engineering and construction labor 248 Regarding future studies, ORNL. could serve a very useful purpose as a focal point for updating the current studies. As technology develops further information will be forthcoming on coal gasification and liquefaction. ORNL could serve as a focal point for industry assessment of these alternates. - . Perhaps ORNL could also fill a role in assessing the economic impact of overly restrictive government regulations. The cost/ benefit ratio of environmental restrictions needs to be determined. Opinions of an independent agency such as ORNL may carry more weight than a presumably biased industrial opinion. Possible items for intensified research and development include: 1. development of a small nuclear reactor sized for industrial plants and with an investment per unit low enough to make nuclear energy available at lower cost than coal-based energy, 2. development of coal liquefaction and gasification technology, 3. development of the fluidized-bed burner for steam or process requirements, 4. use of electrical energy for process heat requirements above 1000-Ib steam temperatures. 8.3 PETROLEUM REFINING 8.3.1 Amoco Oil Company A typical oil refinery processes raw crude oil into a large number of products, including gasoline, kerosene and jet fuels, heating and diesel oils, industrial fuels, waxes, lubricating oils and greases, asphalts, petroleum coke, and chemical plant feedstocks. Amoco’s largest refinery currently can process 330,000 bbl of crude oil per day. Energy requirements Fuel usage in most existing refineries averages about 8 to 109 of crude charged. This represents the entire heat requirement, including steam and electric power generation and coke burned in the regeneration of catalyst. A new modern refinery is estimated to require only about 7 to 9% of crude charged for its fuel requirements. Energy consumed at our largest refinery, including the needs of a styrene unit and two ammonia units, is projected to be: ' Electricity, kW 106,000 Steam, Ib/hr 5,250,000 Fuel, 10° Btu/hr (net) Steam generators A 3700 Process heaters - 6600 Gas turbine generators . 370 ' Gas turbine mechanical drives © 830 Steam and gas turbine generators produce 68,000 kW, and 38 ,000 kW will be purchased. Of the steam requirements, 2,600,000 1b/hr will be produced by recovery of process heat including CO boilers and heat-recovery units on process heaters. 249 The energy requirements of a new 330,000-bbl/day grass-roots refinery is estimated to be: 600 psig 750 F steam ' 1,200,000 1b/hr 150 psig 500°F steam -300,000 Ib/hr Electricity 82,000 kW High-temperature process heat duty: At 650—700°F 1000 X 10° Btu/hr At 800°F 500 x 10° Btu/hr At 950-1000°F 900 X 10° Btu/hr At 1650°F - | 200 x 10° Btufhr Energy supply for refinery. operations must be highly reliable, because disruptions can result in hazardous operating conditions and costly damage to processing equipment. Also, the continual escalation in cost of increasingly sophisticated refinery equipment makes high operating factors imperative to hold down capital charges against production costs. A temporary unscheduled loss of about 25% of energy supply can be tolerated with minimal economic penalty. An unscheduled loss of more than 30 to 35% of energy supply can result in hazardous operating conditions and substantial economic penalties. Planned reductions in energy supply can be handled safely, but large reductions for extended periods of time, as may be needed for refueling of nuclear reactors, are not acceptable from an economic p'oint of view. A planned maintenance shutdown of an entire refinery or a large part thereof to coincide with an outage of energy supply is impractical. The large amount of trained manpower and equipment required for such an operation just would not be available. Energy sources Amoco’s refineries currently use gas and oil supplemented by purchased electric power to supply all energy needs. In the near-term future, we expect to increasingly use oil in place of gas as the sources of gas decrease. This will require retrofitting of fuel-firing equipment in areas where natural gas was previously low in cost and plentiful as in the southwest. If the cost of liquid fuels continues to increase faster than the cost of coal, as current projections indicate, gasification of coal will become an attractive source of fuel for existing refinerjes. It requlres the least amount of retrofittlng of existing fuel-firing equipment. Along with the advent of coal gasification, new steam-generating equlpment in existing refineries probably will be coal fired using either low-sulfur coal in conventional boilers or high-sulfur coal in a fluidized-bed boiler, The choice will depend primarily on delivered cost of coal and reliability of supply. The same coal (or petroleum coke) would be used for both gasification and steam generation. In cases where low-sulfur coal is available, it will cost less to replace existing gas-fired steam generators with coal-fired units rather than go the coal gasification route. Electric power will be purchased from electric utilities wherever supply is reliable and its cost reasonably reflects the true cost of delivery.' A nuclear-based electric utility should be able to deliver energy at a lower cost than industrial self-generation systems using fossil fuels. Economy of scale and the relatively stable cost of nuclear fuel should be unbeatable. However, if industrial utility rates are leveled or made regressive in the erroneous belief that this will lead to the conservation of energy or to subsidization of the cost of electricity to the consuming public, self-generation will quickly become attractive. Industrial energy plans must allow for such an eventuality. 250 The energy supply to a new grass-roots refinery probably will be coal based. The purchase ot both steam and electricity from a nearby electric utility would be an attractive alternative. Steam supply will be via process heat recovery and coal-fired steam generators. Process heaters will be designed to use fuel oil and a mixture of refinery by-product gas and low-Btu coal gas. Low-sulfur coal-fired crude heaters also would be a likely alternative. In the foregoing, other energy alternatives were tentatively ruled out for reasons stated below: Liquid fuels _ High cost High-Btu gas from coal High cost Solvent-refined coal More development work needed; 400°F melting teinperature Stack-gas scrubbing Fluidized-bed combustion appears preferable at present stage of development ' ' - for steam generation Nuclear reactors General 'Lead time too long; siting problems Small reactors (CNSG) Capital cost too high o : ‘Large reactors - LWRs cannot supply energy at high temperature levels needed for about 50% of total refinery energy demands; it is feasible to use HTGRs to supply process * heat at high temperature levels, but further development work is needed; - neither LWRs nor HTGRs appear economic in sizes of less than about 2000 MW(t); 2 single HTGR of this size would furnish all the energy needs of a 500,000-bbl/day oil refinery; in view of the need for multiple units for reli- ability, no single refinery can justify a nuclear system on its own Recommendations Continue the cooperative study of industrial energy alternatives to monitor developments in all forms of energy systems and to provide a forum for the exchange of information between government and industry. Promote the idea of large-scale industrial parks with a centrally located electric utility furnishing all industrial energy needs, including steam, electricity, and possibly high-temperature process heat. State governments concelvably could sponsor such parks as means of attracting industry to their areas. _ Develop a HTGR designed to furnish process heat at high temperature levels and study alternative methods for transmission of a high-temperature heating medium. Continue development of the CNSG or a similar shop-assembled package type nuclear reactor with emphasis on reduction of cost and delivery time. 8.3.2 Shell Oil Company Introduction The hypothetical eomplex conceived for this study would require 500 acres of usable land to accommodate the processing equipment, wharf, and tank farm. Additional land requirements would include (1) exclusion zones for a nuclear complex; (2) coal handling, storage, gasification, etc., if coal is used; and (3) some acreage for a surrounding green belt as required by appropriate state or local agencies to reduce the visual impact on the neighborhood. o A - 251 Since the future use of natural gas by industry could be severely curtailed and the supply and demand balance for petroleum products will continue to be critical, alternate energy sources or a combination of direct fired and gasified coal into a grass-roots complex will be required. Characteristics of the plant and environs The intended product slate would include a full petroleum product line (i.e., light products, middle distillates, heavy oils, and chemicals). Production rates of any given product would vary depending upon the need at the time (i.e., heating oils in the fall and winter and gasoline during the spring and summer) and the type of crude being processed. The production rates would be maximized based on a crude intake of 300,000 bbl/calendar day. It is assumed that the necessary land will be available to accommodate the needs of the project. The site would be adjacent to a major waterway or coastline on land zoned for heavy industrial use. Easy access to water transportatlon is most desirable; however rail, truck, and pipeline access will also be required. ' : Process requirements for cooling can be part1ally satlsfied with air coolers; however, approximately 8500 gpm of makeup cooling water would be required. An additional 3000 gpm of makeup water is needed for process steam requirements. Water required for reactor cooling, steam for electrical generation, etc., is not included in this figure. ' Due .to the size and weight of normal processing equipment, wind' loading designs of tall columns, etc., relatively good soil conditions are required. Unusual geological conditions such as faults are as undesirable for process equipment as they are for reactors. Meteorological conditions will affect process design; however, petrochemical complexes can and do operate in all climates and under almost any weather conditions. - . - : Petrochemical complexes are designed for safe and orderly shutdowns under all normal and abnormal conditions (abnormal conditions include total power failures). This complex would be designed to satisfy all known conditions relative to protecting the environment. Energy requirements Energy requirements, classified by temperature and pressure, are as follows: Pressure (psig) , | ’Temperature (OF)' ' Quantity tequirecl (103 Ib/hr) 1250 © 900 1500 650 750 - 2000 200 . 500 . . o 7507 50 o 300 : 5504 Depressured from 1250/650 pressure levels through toppmg turbmes .md not mcluded in total steam generated ’ Normal des1gn contmgencles will require enough excess capacxty SO that normal operations will not be affected by a shutdown of the largest. smgle steam—generatmg unit, . " The quantity of steam used is based on a total of the normal demands for each of the refinery/chemical processes. On the ba81s _of _ Iong oper_atmg intervals experienced between maintenance shutdowns by most operating processes (frequently up to3 years), an annual utilization factor of 95% has been selected. 252 The direct furnace heat required is given below. - Heatabsorbed Transfer temperature (10° Btu/hr) - CP 30 ' 470 90 ' 525 230 _ - 550 90 600 170 ' 650 260 : - 700 580 725 70 ' 740 80 ' 750 180 : 805 170 , 930 140 - 950 280 1010 1800 1500 The heat absorption rates shown above are for individual blocks as listed for the particular temperature, , In a conventional petrochemical complex, each unit within the complex has its own independent heaters; therefore, only a single unit is shut down if a heater fails. Process units are shut down for normal maintenance either individually or in groups, depending upon their reliance on each other. In any design utilizing waste heat for process heat, some sectionalizing would be required to minimize the need for large blocks or even total complex shutdowns. : Most refinery/chemical processes (including direct-fired heaters) have operating onstream factors of 95% or higher. Therefore, a direct furnace heat utilization factor of 95% has been selected. This complex would require approximately 200 MW of power, assumedly all self-generated. The method of generation will depend on the levels of steam available vs the levels required by the process. Some turbines will probably be extraction type to balance the steam needs and the remainder condensing units. | Energy alternatives The systems showing the greatest promise from technological and economical standpoints are as follows: 1. Coal-based systems A. Direct firing: low-sulfur coal; high-sulfur coal and stack-gas scrubbing; and fluidized-bed ‘combustion. B. Coal conversion: pyrolysis—char, gas, or liquid fuel; solvent-refined coal; and liquid fuels, including methanol. | C. Gasification: gasification coupled with a combined cycle for improved efficiency. 2. Nuclear systems (commercial plants) A. Utility or cooperative ownership producing electricity and low-cost process steam; maximum steam transport distance is limited to about 10 miles. | B. Small PWRs for individual industrial electricity and steam needs. C. Process heat reactors producing heat to 1200 to 1400°F. 253 The major problem relative to direct firing of coal concerns transportation to the plant site. Unit trains are satisfactory to a point however, the amount of coal that can be burned becomes self-hmltmg as available land for process units is used for coal yards, train swuchmg trees, etc. Slurry plpelmes could be one answer to this problem. : : Grass-roots sites for petrochemical complexes in themselves are hard enough to find, but that factor, coupled with sites for a nuclear package, may be an insurmountable obstacle. Siting/ EPA/AEC restrictions must be resolved before any serious investigations of the use of " nuclear energy are warranted. Except for direct firing of low-sulfur coal, none of the systems presented in the study are developed to the extent required for full-scale “commercial” operation At this point in the study, it appears that the following systems should rate the hlghest prlonty for research and development efforts: 1. Near term (alternate fuels): stack-gas scrubbing; coal pyrolysis—char for bo;ler fuel and/or liquid or gas for process heaters; and flmd:zed-bed combustion. 2. Intermediate term (alternate raw materials): solvent-refined coal; lower cost process for producing gas from coal coupled with a combined cycle for improved effici_ency; process heat reactors using HTGRs; and small PWRs. : ' - 255 - Appendices ' 257 -/ Appendix A Nuclear Fuel Cycle Analysis The nuclear fuel cycle consists of all steps involved in supplying fuel for the nuclear reactor to the disposal of waste products. Figure A.l shows a simplified picture of these steps.' Uranium is purchased, enriched, and fabricated into fuel elements. In the case of the HTGR, thorium must also be purchased for use as a fertile material. This fuel is placed into the reactor, and energy is produced 'ORNL-DWG 74-6167 URANIUM PURCHASE | | [t ENRICHMENT e BTAILS (0.2% 235U) l | THORIUM PURCHASE - ¢——— (HTGR ONLY) . FABRICATION | - FISSILE l RECYCLE REACTOR = |——e—t/f\p ENERGY - S | - FISSILE " URANIUM| RECOVERY . - — —— SALES WASTE u Fig. A.l. Nuclear fuel cycle. 258 from nuclear fission and fissile. material is produced from neutron capture in the fertile matenals (Th and **U). When the fuel is removed from the core, it is shipped (after a cooling period) to a reprocessing plant where the fission products are separated from the uranium and plutonium. The uranium is sent back to the enrichment plant for further use. Bred fissile material may either be sold or be recycled back through the system SYSTEM MASS BALANCES | | Thlrty-year fuel cycle mass balances were used for an HTGR a PWR and a CNSG system. ‘The PWR fuel cycle was used for both the PWR and BWR systems. Although some difference in cost exists between the two systems, this difference is small. The PWR uses an annual refueling scheme. A non-recycle mode is used where all plutonium produced is sold. Reprocessed uranium is returned to the enrichment plant for reuse. The CNSG system uses a biannual refueling, with the sale of any bred plutonium. Reprocessed uranium is returned to the enrichment plant. | The HTGR system considered uses highly enriched uranium as fuel and thorium as the fertile material. Bred “*U is recycled continuously throughout the reactor life, and the remaining inventory _at the end of the reactor life is sold. The reprocessed uranium from the fuel elements containing the highly enriched uranium has a large proportion of 2°U. Because of this, the credit received when this material is returned to the enrichment plant is reduced ‘to 70% of what uranium-of the returned enrichment would ordinarily be worth. The HTGR has an annual refueling scheme. A 0.5% fabrication loss and a 1.0% reprocessing loss are used for non-recycled fuel. For the recycled **U and its produets in the HTGR, a net loss of 1% is used. UNIT COSTS Estimations of the nuclear fuel cycle unit costs in 1974 dollars were made for a period of from present until the year 2022. As one might expect, there is considerable uncertainty in predicting prices 40 to 50 years in the future, even on a constant dollar basis. These uncertainties not only involve technology and the ability to find the necessary uranlum but also uncertainties as to the degree of penetration of various nuclear systems. Increased penetration will lead to reduced unit costs due to the economics of scale in items such as fabrication and reprocessing plants. With these caveats in mind, we have put together our best estimates of unit prices. An attempt is also made to give the degrees of reasonable uncertainty. Raw Material Price The price ‘of U;O0s was discussed in Section 5.1. The reference price schedule used in the economics calculations is that for the 20% above the AEC “most likely” demand case by the year 2000. The price after 2000 is assumed to rise linearly to $46.80/1b by 2022. This price schedule is also considered to be the high price in the range of reasonable uncertainty. The lower range of uncertainty was taken as the AEC base ore use-price estimate, assuming an added 20% to nuclear capacity by the year 2000. We further assumed for this price schedule that enough low-grade ore will be found so that the price never rises above $30/1b of U30s. Plots of uranium price vs time are shown in Fig. A.2. e i o \o/ 259 ORNL--DWG 74-6166 50 p // REFERENCE-~HIGH 40 & s 3 / s . ,'. | & / Q z / w ! S ¥ 5 7’ [-1~ . 0 . - - 1970 1980 1990 - 2000 2010 2020 2030 ' ' YEAR Fig. A.2. Uranium ore price. The effect of thorium price on system economics is small even if thori_um is not recycled. In this study we use the current value recommended by General Atomic' of $9/kg of ThO,. This price is not varied with time. ' ' S I. C. H. George, Fuel Projects Department, General Atomic Company, personal communication to L. L. Bennett, Oct. 10, 1973. 260 In our economics calculations, the cost of converting UsOs to UFs as needed in the enrichment plant is included with the uranium purchase price. This is not a major expense. Present prices are around $1/Ib of U;0s. This price was assumed to be an invariant throughout the study. Separative Work ~ Separative work was discussed in Section 5.1. The reference price schedule used in this study starts at $42/SWU in 1975 and increases by $1/SWU each year until it reaches $50/SWU; it remains constant at $50/SWU thereafter. The range of reasonable uncertainty is assumed to be the range of uncertainty in privately financed centrifuge enrichment plants, or-$40 to $60/SWU. The high side price schedule starts at $44/SWU in 1975 and increases $2/SWU per year to 1983 and then remains constant at $60/SWU, The low price schedule assumes a constant $40/ SWU throughout. Figure A.3 shows a plot of these prices. ORNL-DWG 74-86168 70 HIGH 60 P D D SR D S e SR S TR W — e TR S GRS S G S S — I ! ! —- ! 2 ! & y @ s % / 3 ’l x 50 ’ REFERENCE o . Y = ! ! / = ! < I o < ! & w ' 40 —— e e G o e S S s S ——— -—--—LEW——- 30 1970 1980 1990 2000 2010 2020 2030 : YEAR Fig. A.3. Separative work cost. S ettt b 4 i e e e 261 Fabrication Since each system has a different fuel element, the fabrication cost is different for each. Our reference unit fabrication plus reconversion costs for the PWR and HTGR systems are those used in the current cost/benefit analysis done as part of the LMFBR environmental impact statement.” In attempting to establish a range of reasonable uncertainty for this cost, we assumed that the PWR costs have a great deal of near-term reliability. By 1980 we assumed a +109% reliability and by 2000 a +209% reliability. The PWR fabrication cost vs time is shown in Fig. A 4, ~The HTGR unit fabrication cost estimation has more uncertainty because of the variety of HTGR fuel cycles and greater uncertainty as to penetration. A £$50/kg uncertainty was applied to the reference fabrication cost. These costs are also plotted in Fig. A 4. The unit costs for the CNSG fuel element fabrication were estimated based on fabrication in a PWR fuel element plant. Costs were assumed to be the same as for PWR fuel, with cost penalties caused by cleanup of the fabrication facility due to'changeover to and from the CNSG element and additional materia! unit costs in fabricating the shorter CNSG element. The cleanup cost is assumed to be carried 100% by the CNSG fuel. This cost is dependent on plant size and may be expected to increase fabrication costs by approximately 1.6 to 2.4 times the unit costs without cleanup.” We estimate that the increased hardware costs would increase unit fabrication costs by 1.12 to 1.24 times the price of a standard PWR fuel element. The net effect is that the CNSG fuel fabrication will probably cost 1.8 to 3 times the unit cost for PWR fuel. Our reference price schedule uses 2.4 times the PWR reference unit fabrication price. The range of uncertainty is 1.8 and 3.0 times the PWR costs. These prices are also plotted in Fig. Aa. | - When doing the economics calculations, shipping costs of the fresh fuel were included with the fabrication costs. These costs are not varied in this study and are given in Table A.l. 2. Studies and Evaluations—_._Civilian, HEDL Monthly Resume, December 1973, Hanford Engineering Development Laboratory, Jan. 9, 1974. . e ‘ 3. J. A. Lane et al, Evaluations of an External-Loop Pressurized-Water Reactor Steam Supply for Maritime Applications, ORNL-4453 (Special) (November 1969). Table A.1. Economic data Conversion of U303 to UFg, $/1b U303 1.00 Thorium price, $/kg ThO, 9.00 Fresh fuel shipping cost, $/kg LWR-CNSG fuel - 3.50 HTGR 7 . 25.00 Spent-fuel shipping cost, $/kg -~ ' LWR-CNSG fuel _ 6.50 CHIGR R -~ 50,00 262 ORNL—DWG 74-6168 400 T~ =~ | HTGR HIGH - \\ \ _ s...\ 150 ] =~ "\ . - \ . o . — <] HTGR REFERENCE 200 ” - ”~ / / / HTGR FABRICATION COST ($/kg) \ \s\ A s \ Sl . \ ™ - . \ e ~ 0@ s s O TG G g ‘m \ h-—-——-—-l--—u—'-— L I = B = , . 2 | HTGR REFERENCE ' \\ \\ \ "'~.__s S Sl LWR REFERENCE ~ _ \\ - 0 ' : 1970 - 1980 1990 2000 © 2010 2020 - 2030 " YEAR Fig. A.5. Fuel recovery unit costs. 264 -The HTGR recovery costs used in the LMFBR cost/benefit analysis work are based on current estimates of General Atomicl:.l We have arbitrarily applied a 320% uncertainty to these numbers. - Bred Material Worth The light-Wat_ef reactors produce saleable quantities of plutonium; HTGRs produce *U which may also be sold. The values of these fissionable materials will probably be determined by the price of enriched uranium, sinice they are a competitive fuel with *’U in some types of fuel cycles. The price of plutonium will also be strongly influenced by its use in fast breeder systems beginning toward the end of the century. N Plutonium price estimates®’ range from about $6 to $9 /g for use in plutonium recycle in PWRs and between $15 to $25/g in fast breeder systems.® However, these estimates are based on uranium ore price projections lower than those used in this study. Previous studies’ at ORNL have used a plutonium price of 5/6 that of fully enriched uranium. We also chose to use this price schedule as our reference in this study. A range of uncertainty of +1/6 the value of highly enriched uranium is also considered. _ ' Whereas Pu is less valuable than »*°U for use in thermal reactors, **U is somewhat more valuable. The price of **U used in this study is 7/6 + 1/6. the value of highly enriched uranium. The price projections for fissile plutonium and #*U used in this study are plotted in Fig. A.6. COST EVALUATION METHODS Average fuel-cycle costs calculated in this study for a 30-year reactor lifetime were based on present value discounting technlques. The average, or levelized, fuel cost was determined by computing the present value (value discounted to reactor startup) of all fuel costs and credits and dividing this by the discounted amount of energy sold during the life of the plant. In the discounted cash flow procedure used here, the sum of the present-worthed cash incomes must equal the sum of the present-worthed cash expenditures. Theése expenditures include direct costs such as ore purchase and fuel fabrication as well as taxes. For income tax purposes, the direct costs are assumed to be deductible on a pro-rata basis with poWer production. The fuel cycle cost is made up of two components, the direct cost and the indirect charges associated with an item of cost. The direct cost contribution is obtained by summing up all costs and credits during the reactor history and dividing this by the total energy sold with no discounting, or =M Zn _ , Al DEn__ (A.1) st where D is total direct éost, Z, is total fuel costs and credits during period n, and E, is energy. produced during period 7. The indirect charges consist of return on outstanding investment, interest payments, taxes, etc. To calculate the indirect charges, we first determine the total discounted present value of all direct 6. R.G. Schwiégel', “The Nuclear Fuelecle: What’s Happening Today?” Power, September 1973. 7. R. R. Henderson and D. J. Bauhs, “Fuel Management Simulation Studies at Westinghouse,” paper presented at Nuclear Utilities Planning Methods Symposium, Chattanooga, Tenn., Jan. 16-18, 1974. . 265 . ORNL-DWG 74-6171 40 S ' - fl% PRICE _—""239p, pRiCE FISSILE MATERIAL PRICE ($/g) o _ Q e /, /. 1970 1980 1990 2000 2010 2020 2030 ' YEAR ' - Fig. A.6. Bred material price. fuel costs over the reactor lifetime and divide this by the discounted amount of energy delivered, or E (1+x)7" Z, S EE (A2) ~ where x is discount factor and T is total cost before pro-rata effect. The result is the total cost, if all expenses can be deducted for tax purposes as they occur. The total indirect charge, mcludmg the pro-rata effect, is the difference between this total cost and the direct cost multiplied by 1.0 - A3 a-na=9 “A-3) 266 or 1.0 I=(T-D) ——————, (A.9) I=I=D) =y a=s where ¢ is federal income tax rate, S is state income tax rate, and 7 is total indirect cost. The discount factor to be used with this procedure is given by x=(1-b)i+(1 -8 -9 biy, ' : (A.5) where b is fraction of investment from debt; 7, is earnings rate on equity after taxes; and i is interest rate on debt. The total fuel cycle cost (Crc), including taxes, is the sum of the direct and indirect charges Cpc=D+I. | ; (A.6) It is assumed in doing these calculations that debt and equity remain in constant proportion throughout the life of the project. For calculational purposes, we assumed that income from energy generated or fissile material sales during a semiannual accounting period is received at the end of the period. Costs such as fuel purchase, fabrication, and reprocessing were charged at the beginning of the period in which they occurred. The accounting lead and lag times used in the fuel cycle are shown in Table A.2. Table A.2. Fuel cycle lead times Number of 6- month periods First core U30g purchase to startup Separative work purchase to startup Fabrication purchase to startup Reloads U30g purchase to recharge _ Separative work purchase to recharge Fabrication purchase to recharge N oWoWw Discharge to reprocessing payment Discharge to fissile sale 2 = =N FUEL CYCLE COSTS Fuel cycle costs as a function of discount factor before income tax are shown in Figs. A.7 to A.9. These costs were calculated using Eq. (A.2) and are based on our reference unit cost structure and mass balances for the PWR, CNSG, and HTGR reactor systems. Also tabulated on these 267 _ORNL -DWG 74-6174 50 DIRECT COSTS {¢/MBw) 1981 STARTUP = 19.23 1986 STARTUP = 20.37 1991 STARTUP = 21.39 _ o ) , 1991 45 : ‘ ' ' STARTUP —— 1986 ISTARTUP 2 40 m 1= . . 2 [%2] o O 1981 w STARTUP o - > o - w z 35 30 5 10 . 15 20 'DISCOUNT RATE (%} Fig: A.7. LWR fuel cycle costs. ' figures are the direct costs calculated usmg Eq (A 1). Three startup dates Jan, l 1981 1986, and 1991, -are consndered Usmg these curves and Egs. (A 4) to (A 6), the total fuel cycle cost may be calculated for a wxde variety of tax ‘and financial assumptions. For example usmg Eq. (A.5) and the utlhty reference case assumptions, we have 10% after tax return on equity, 8% cost of borrowed money, 55% of investment on borrowed money, 48% federal income tax rate, and 3% state and local income tax rate. The discount factor from Eq. (A.5) is 6.72%. For a 1986 startup of an LWR (PWR or BWR), the fuel cycle cost before income taxes from Fig. A.7 for this discount rate is 26¢ per 106_ Btu. The direct cost is 22¢/10° Btu. The indirect 268 ORNL-DWG 748173 70 - : , DIRECT COSTS {¢/MBtu) 1981 STARTUP = 26.37 1986 STARTUP = 28.60 1991 STARTUP = 30.46 1081 STARTUP 60 1986 STARTUP - 1981 _ 2 %0 STARTUP I ' > 2 Q o . o : / ‘ 0 . -J o / | - / / 20 205 10 15 . 20 DISCOUNT RATE (%) Fig. A.8. CNSG fuel cycle costs. charge multiplier from Eq. (A.3) is 1.983. From Eq. (A.4), the total indirect cost is 9¢/10° Btu, and the total fuel cycle cost from Eq. (A.6) is 31¢/10° Btu. | All the fuel cycle costs given here are based on an 80% plant factor. For other plant factors, the indirect costs will be inversely proportional to the plant factor, while the direct costs will be unchanged. - ' | ' A summary of the fuel cycle costs calculated for the utility and industrial reference cases is given in Table A.3. Tables A4 and A5 glve the value of the initial core and the average yearly direct fuel cycle expenses respectively. ' The fuel cycle costs calculated for the PWR and HTGR reactor systems are fairly close for the same startup dates and economic groundrules. The calculated heat cost for the HTGR is slightly FUEL CYCLE COSTS (¢/MBtu) 25 L 50 45 40 30 269 ORNL-DWG 74-6174 DIRECT COSTS (¢/MBtu) 1981 STARTUP = 19.23 1986 STARTUP = 20.37 1991 STARTUP = 21.39 1991 STARTUP — 1986 ISTARTUP 1981 STARTUP T T g _ DISCOUNT RATE (%) . Fig. A9. HTGR fuel cycle costs. ' 270 Table A.3. Reference fuel cycle costs for three startup dates : 1981 : 1986 o 1991 System — - — — - ; : Utility Industrial Utility Industrial ~ Utility Industrial ¢/10% Btu 273 327 31.0 38.0 34.6 434 mills/kWhr(e) 2.91 3.49 3.31 4.05 3.9 463 HTGR ' _ ¢/10° Btu 30.2 38.7 33.0 430 359 473 mills/kWhr(e) 267 342 o291 3.80 317 447 CNSG ' | ' ¢/10° Btu 41.4 524 46.7 60.3 51.8 68.1 mills/kWhr(e) 4.86 6.15 548 7.07 6.08 799 Table A.4. Value ($10°) of initial core for three startup dates System 1981 1986 1991 LWR 29.2 35.2 410 HTGR 407 46.5 51.0 .CNSG 62 7.3 83 Table A.5. Average yearly direct fuel cycle expenses? ($10%) System 1981 - 1986 1991 LWR 16.20 17.57 18.75 HTGR 13.80 14.63 15.36 CNSG 197 2.14 2.28 %ncludes initial core. higher than that for the PWR. However, since the HTGR syétem has a higher thermal efficiency, its electrical energy cost is slightly less than that for the PWR. The fuel cycle cost for the CNSG is significantly higher than that for the reference HTGR or the PWR. This is mainly due to the higher fuel enrichment in the CNSG when compared to larger LWRs. This higher fuel enrichment is necessitated because of the higher relative neutron leakage from the small CNSG core. A CNSG reactor of the same size as a PWR system should have the same fuel cycle costs if operated in a like manner, including similar fueling schedules. C 27 FUEL CYCLE COST SENSITIVITIES The effect on the fuel cycle costs of vanatlons in the unit costs were calculated for the utility reference economic conditions. ‘The hlgh and low unit cost price schedules mentioned previously were used. The results are given in Table A.6. ' It can beé scen from this cost breakdown that the largest dlrect cost component is the uranium cost, followed by separative work cost. There is a large fissile sales (Pu) credit for the PWR and CNSG systems. The HTGR, which recycles the bred ***U, has a lower fissile credit which arises from the sale of the core at the end of life. The fabrication and reprocessing costs, although significant, are smaller than the enriched uranium cost (uranium purchase plus separative work). For 1981 startup, the fabrication and reprocessing together account for about 209% of the PWR and CNSG direct costs and about 32% of the HTGR direct cost for the reference (base) unit price conditions. These percentages become smaller for later startups due to the decrease in these unit costs with time compared to the rise in ore cost with time. Table A.6. Fuel cycle cost breakdown (¢/10° Btu) 1981 startup - " 1986 startup 1991 startup Base High Low Base High Low Base High Low PWR | Uranium purchase ~ 13.53 - 1353 - 7.83 1579 15.79 942 1769 1769 1093 Separative work 848 1013 6383 8.53 1024 6.83 853 1024 = 683 Fabrication 174 199 150 1.63 1.88 1.38 1.55 1.81 1.28 Fuel recovery 2.13 245 1.80 201 233 168 195 2.29 1.62 Fissile sales (6.03)% (522) (494) (642) (5.54) (5.33) (6.75) (5.79) (5.66) Total direct cost? 1985 2288 1302 2154 2470 1398 2297 2624 15.00 Indirect charge® 745 155 594 9.44 9.76 596 1163 12.00 7.05 Total fuel cycle cost ~ 27.30 3043 = 1896 3098 3446 1994 3460 3824 2205 HTGR | , | Uranium purchase 8.10 8.10 480 9.1 9.51 569 1077 10.77 6.59 Separative work 6.86 8.17 5.56 6.95 8.34 5.56 6.95 8.34 556 Fabrication 384 464 3.04 3.64 4.44 2.84 3.44 4.24 2.64 Fuel recovery 228 254 202 216 243 1.89 2.16 243 1.89 Fissile sales (185) (226) (1.16) (1.89) (31 (L16) (193) (235 (L.16) Totaldirectcost? 1923 2119 1426 2037 2241 1482 2139 2343 1552 Indirect charge® 1094 1249 816 1265 1449 8.10 1450 1636 8.85 Total fuel cycle cost ~ 30.17 3368 2242 3302 3690 2292 3589 39.79 24.37 CNSG | | - | o S Uranium purchase -~ 1533 15.33 875 1817 1817 1072 2054 2054 12.56 - Separative work L1110 1323 896 1120 1344 - 896 1120 1344 . 896 ' Fabrication 364 452 276 3.38 420 257 321 398 244 Fuel recovery 191 . 220 1.62 1.82 2.11 151 177 207 147 Fisslesales =~ (5.61) (485 . (461) " (597 (5.14) (496) (626) - (5.38) (5.26) ‘Total direct cost? - - 2637 3043 1748 2860 3278 1880 3046 3465 20.17 Indirect cost’ 1501 1608 1149 1814 1945 1162 2138 - 2272 1296 Total fuelcyclecost - 41.38 . 4651 . 2897 ~ 46.74 ~ 5223 . 3042 51.84 §7.37 33.12 “Numbers in parentheses indicate fuel cycle credxt PDirect costs are independent of financing assumptions. €Indirect charges for utility reference case; assume 80% plant factor. 272 The fissile credit shown for the high and low cost cases is not the absolute highest (more 'positive) or lowest (more negative) cost. This cost is consistent with the uranium and -separative work costs and a pnce range of 5/6 % + 1/6 times the value of hlghly enriched uranmm for plutomum sales and 7/6 + 1/6 the value of highly enriched uranium for **U sales. The total cost shown for the high and low condmons are simply the totals of the md1v1dual hlgh and low cost components. It is not expected that all costs will be high or low in tandem. Except for the fact that Pu and 233’U prlces are based on the highly enriched uranium price, interactive effects were . not considered. Such interactions could be caused by the avallablhty of ‘more low-cost uranium, leading to the low uranium purchase cost estimate. If this were to occur, the enrichment plant tails would probably be higher than the 0.2% used here. This would ihcrease the ore usage and decrease the separative work required. Also, if more uranium is available, the plutonium recycle optlon in LWRs will be less attractlve, and the incentive for fast breeder reactors wxll also be reduced. This could lead to a decrease in plutomum demand, which would be reflected ina reduced price. ALTERNATE SIZE REACTORS Fuel cycle costs were also estimated for a 1900-MW(t) PWR, a 1235-MW(t) CNSG system, and for both a 2000-MW(t) and a 1000-MW(t) HTGR. Lifetime fuel cycle calculations were not made for these alternate systems. The fuel cycle costs shown in Table A.7 are based on extrapolations from the reference size PWR [3420 MW(t)] and HTGR [3000 MW(t)). Table A.7. Fuel éycle costs (¢I_106 Btu) for alternate size reactors Syst Size 1981 1986 1991 sitem [MW(D)] Utility Industrial Utility Industrial Utility Industriat - PWR 1900 282 . 338 321 39.3 35.9 449 CNSG 1235 294 36.1 33.5 42.0 37.5 482 HTGR 2000 318 - 40.7 349 454 38.0 50.1 1000 34.8 44.6 38.3 50.0 419 55.3 1If the size of a reactor system is decreased, there will be a greater neutron leakage from the smaller core. A larger fissile material loading is then needed to compensate for this increased leakage. This causes an increase in the fuel cycle costs. The fuel cycle cost for the 1900-MW(t) PWR was estimated by computing the change in fissile loading required to compensate for the increased fractional neutron leakage from the smaller core. The results are consistent with a companson ofa 600-MW(e) and a 1000-MW(c) PWR reactor as given in WASH-1082.} The fuel cycle costs for the 1235-MW(t). CNSG were estimated based on information furnished by Babcock and Wilcox with adjustments for economic assumptions and fuel element size. 8. Current Status and Future Technical and Economiq Po'tent'ialv of Light Water Reactors, WASH—IOSZ {March 1968). | | | | 273 Information on the fissile material loading for a 3000- and a 2000-MW(t) HTGR was obtained from preliminary safety analysis reports.”'® The specific inventory (kg/kW) of the 1000-MW(t) HTGR was estimated by extrapolating from the respective 3000- and 2000-MW(t) values. The fuel cycle costs for the 2000- and 1000-MW(t) HTGR reflect the cost penalty of the higher specific inventories of these two systems when compared to the 3000-MW(t) reference design. - 9. Preliminary Safety Analysis Report, Fulton Generating‘ Station, Units ! and 2, Philadelphia Electric Company, January 1974, , : . 10. Preliminary Safety Analysis Report, Summit Power Station, Delmarva Power and Light Company, December 1973. 274 Appendix B ~ Steam Line Cost Study—Basis of Cost Estimate | This estimate is based on conceptual assumptions furnished by John Yarbrough of the Engineering Mechanics Department, UCC Nuclear Division. The material listed covers the - requirements for 1 mile of line. The pipe is assumed to be in 20-ft lengths with ends beveled for welding. The calcium silicate insulation will be installed in 2-in. layers of material premolded in segments conforming to the diameter of the pipé.'Three layers will be applied, and the insulation will be covered with aluminum jacketing. Supports will consist of concrete footings with concrete piers extending above the ground and saddles of metal plate. Rollers will be used to allow for expansion and contraction. ' It is assumed that road and small stream crossings can be accommodated by the arrangement of expansion loops which are included. No provisions are made for wide stream crossings or rugged terrain. Average accessibility and terrain conditions are assumed. Escalation must also be applied after July 1974. Labor prices are those which are current in the Oak Ridge, Tenn., area and will need adjusting to the area in which the work is planned. The costs as shown indicate construction funding per mile of proposed line. No provisions for costs of land, land rights, easements, or engineering are made in this estimate. The calculations in Tables B.1 and B.2 were made in order to estimate the cost of a steam pipeline, either 24 or 36 in. diameter, to deliver steam from a generating facility to distribution points. The pipeline is 5 to 10 miles long. No actual geography was considered, and it was assumed that all obstacles, such as roads, could be cleared by the expansion loops (10 loops/mile) (Fig. B.1). Any larger obstacles, such as wide rivers, would require special consideration and would result in considerable cost increase. The design parameters obtained were not optimized or refined but are representative for purposes of estimating cost. The steam operating condition considered was 850 psig, 525°F. An additional condition of 2400 psig, 950°F steam was included initially but was dropped due to excessive wall thickness requirements. The design was based on seamless pipe: A-106 grade B for the 850 psig, 525°F condition; and SA-199 grade 3b for the 2400 psig, 950°F condition. From availability considerations, welded pipe may have to be substituted. This may affect the cost. Steam traps were not included in the design but should be covered (costwise) within the 5% contingency. ORNL~-DWG 75-8145 - W H ot} ——————————m Fig. B.1. Expansion loop details. b | et i 275 Table B.1. Desxgn summary® . 850 psig, 525°F 2400 psig, 950°F 24 in. 36 in, 24 in. 36 in, Pipe n . Material o o A106B A-106B SA-199 SA-199 Length,? ft/mile _ 6200 6200 6200 6200 Wall thickness, in. - . Sched. 40,0687 . 10 2.7 4 Cost, $/ft TS ~165 Expansion loop . v , 528 L 528 528 w, ft - ’ 150 150 150 H, ft 35 , 40 35 No./mile o . - 10 -, 10 10 Distance between supports,°ft -~ 56 » - 65 Insulation _ . Thickness, in. _ 6 , 6 8 9 Cost, $/ft - . ~24 , ~33 ~35 ~47 90° Ells - . 4 . . ' Number/mile . 40 490 40 40 -~ Cost each, R ~1100 ' " ~3800 360 360 Welds.d number/mile (approximate) - 360 360 ‘ 9All prices ciu'rent, ~5/1/74. : bTo buy in 20-ft lengths (6400 ft in 40-ft lengths). - €Assumes hydrostatic test (will hold water). _d20-ft lengths, 220 welds/mile for 40-ft lengths. Table B2, Steam liné cost study , N _ e Matesial : Labor Material and description Quantity .- Unit - | Unit cost ($) Total (§) Hours Rate($/hr) Total (§) 36-in. pipe, 1-in. wall (steel) . , . ‘ In place only - 6200 LF 175 1,085,000 2 9.25 114,700 Welds (circumference) . 360 Each - - 100 36,000 80 9.25 266,400 Radiograph (welds) . 360 Each " 100 36,000 4.00 144,000 Stress relieve 360 Each 100 © 36,000 4.00 144,000 Supports 120 Each - 500 - 60,000 10.00 120,000 Rigid anchors _ 10 Each 500 5,000 20.00 20,000 90° ells (in place only) 40- Each 4000 160,000 12 9.25 4,440 ~ Insulation (St. sect.) 6200 LF 35 217,000 4 9.75 241,800 ~ Insulation (ell)® . 40 Each 630 25200 64 9.75 24960 - o ' - ' 1,660,200 1,080,300 Misc. e S 99,800 - 109,700 e e . 1,760,000 1,190,000 24-in. pipe,sched 40 o § , o e . Inplaceonly -~ 6200 LF 75 465000 @ 1 9.25 57,350 _ Welds (includes align)) ~ 360 _Each 50 - - 18000 40 9.25 133,200 _Radiograph welds 360 ~ Each 50 18,000 2.00 72,000 Stressrelievewelds -~ 360 - Each .50 18,000 2.00 72,000 Supports - 120 Each 400 48,000 6.00 72,000 " Rigid anchors o 10 ~ Each 400 4,000 10.00 - 10,000 90° ells (in place only) 40 Each 1200 48,000 4 9.25 1,480 Insulation (Calsil® -~ 6200 :LF 25 155000 2 9325 114,700 Insulation (ells only)® 40 Each 300 12,000 24 925 8,880 o ' - 786,000 541,610 Misc. - . - _ 47,000, 54,390 833,000 596,000 | SLF = linear feet. BIncludes aluminum jacket. 276 Appendix C Step-by-Step Procedure in - AEC Licensing of Nuclear Power Reactors* | RADIOLOGICAL SAFETY AND ENVIRONMENTAL IMPACT REVIEW 1. An electric utility planning to build and operate a nuclear power plant for the purpose of generating electricity for distribution to its service area must seek approval from the Atomic Energy Commission. 2. The AEC licensing process for a nuclear power plant involves a two-stage procedure. The initial stage consists of the filing and processing of an application for a construction permit. The second stage consists of the filing and processing of an application for an operating license. Construction of a nuclear power plant may not begin until a construction permit has been issued by the AEC. Similarly, a nuclear power plant may not be loaded with fuel or operated until an operating license has been issued by the AEC. 3. A construction permit application is prepared with the assistance of the utility’s contractors including the contractor for the nuclear steam supply system. The application contains a detailed description of the proposed site and proposed design of the plant, an accounting of the financial qualifications of the utility as well as other information which is generally provided for in the Commission’s Regulations on “Licensing of Production and Utilization Facilities.” At the time the application is submitted the applicant must also submit to the AEC an environmental impact report relating to the proposed plant. Guides to the preparation of the reports, detailing the kind of information required to be included, have been developed by the AEC Regulatory Staff. 4. The AEC arranges for documents and correspondence relating to the case to be available for _public inspection at a local public document room (usually in a public library) established in the vicinity of the proposed facility as well as in the AEC Public Document Room in Washington, D.C. ‘ 5. Each application is initially reviewed by the AEC Regulatory Staff to determine whether the application, including the preliminary safety analysis report and the environmental report, contains sufficient information to satisfy the AEC requirements for a complete application. In addition, a substantive review and inspection of the applicant’s quality assurance program covering design and procurement is conducted. If the application is not sufficiently complete and/or the quality assurance program is not acceptable, the application is rejected. If the application satisfies the AEC requirements it is formally accepted for detailed review. The initial acceptance review takes about 30 days. -6. AEC is required under the Atomlc Energy Act to hold a public hearing before issuance of a construction permit. The hearing is conducted by a three-man Atomic Safety and Licensing Board, the Chairman of which is a lawyer qualified in the conduct of administrative proceedings and two *Reprodliccd from a booklet: U.S. Atomic Energy Commission, Office of Information Services, “Now a Word about Step- by-Step Procedure in AEC Licensing of Nuclear Power Reactors—Radiological Safety and Envnronmental Impact Review,” Washmgton, D.C., July 1973, : 277 other members who have appropriate qualifications. Within a few weeks of acceptance of an application, the Commission issues a notice of the public hearing which will be held after the safety and environmental reviews have been completed. The notice of hearing includes the basic issues which must be considered at the hearing. Opportunity is afforded to interested members of the public to intervene as a party to the proceeding or to participate in the form of a “limited appearance” simply to express their views. An intervenor in the proceeding may take a position either in support of or against the proposed construction permit. The notice of hearing is issued at this early stage of the licensing process, even though the actual hearing will not be held for several months, in order to provide for full public participation in the decision making process. Because of the quasi-judicial nature of the hearing, there are specific requirements for becoming a full party to the proceedings by intervention. A petition to intervene, accompanied by a supporting affidavit, must state in reasonably specific detail, the petitioner’s interest, how that interest may be affected by the proceeding, the specific aspects of the case on which he wishes to intervene and the basis for his contentions. In addition, the petition must be filed within the time specified in the notice of hearing. Participation by limited appearance is less formal and the only requirement is that a request be made to the Commission or the Licensing Board. The Regulatory Staff may hold meetings with potential intervenors to discuss their concerns. Within 60 days of publication of the notice of hearing in the Federal Register, a special prehearing conference is convened to consider the petitions to intervene; to permit identification of the issues in controversy, if any; to determine the need for discovery by the parties (obtaining further information and documents); and to discuss a further schedule of actions. 7. In the- meantime, the AEC Regulatory Staff has begun its comprehensive study of the application for the purpose of determining whether there is reasonable assurance that the plant as proposed can be built to operate safely with minimum environmental impact. This study which takes several months involves a review of the technical reports submitted by the applicant, meetings with the utility and nuclear supply system manufacturer and others as necessary to discuss the design of the plant and details of the proposed site from the radiological safety standpoint. After the Staff formulates its final position with respect to radiological safety, it issues a Safety Evaluation which also is made available to the public. The safety aspects of the application then are reviewed by the independent statutory Advisory' Committee on Reactor Safeguards. The ACRS furnishes its advice on the safety of the ‘reactor in writing to the - Atomic Energy Commission. This letter becomes a part of the pubhc record. , S : ' The Regulatory Staff also prepares and circulates a draft';enVironmental statement on the impact of the proposed plant for concurrent study by other Federal and State agencies as required under the provisions of the National Environmental Policy Act, and the regulations of the Council on Environmental Quality and the AEC implementing that Act. After evaluation of comments received on the draft; the Regulatory Staff prepares a Fmal Envxronmental Statement whxch is made available to the publlc : - - : : ' ‘ The Final Environmental Statement and Safety Evaluation, including changes in’ des1gn or other aspects of the apphcatlon will be offered as ev1dence by the Regulatory Staff at the pubhc hearing. - 8. The public hearing begins normally at the nearest smtable place in the vicinity of the proposed plant site. If the hearing is uncontested, it may require as little as one day. In an uncontested case, the presiding Atomic Safety and Licensing Board’s function is to consider, without duplicating the review already performed by the Regulatory Staff and the ACRS, whether the 278 application and the record contain adequate information to support the issuance of the construction permit. However, if the hearing is contested, it may require many weeks of testimony by expert witnesses. The time will depend on the nature of the matters in dispute and the vigor with which opposing intervenors present their case. In a contested case, the Licensing Board must decide the ‘issues in controversy. - 9. After the public hearing is completed the Atomlc Safety and Llcensmg Board issues an initial decision. Under the Commission Regulations, if the initial decision authorizes the issuance of ‘a construction permit, the AEC may issue the construction permit promptly on the basis of the _initial decision. Any party to the proceeding may file exceptions to the initial decision, but such exceptions do not interfere with any authorization to issue a construction permit or. require that construction be stopped if the permit has been issued pending any action by the Appeal Board. 10. The initial decision and any exceptions are reviewed by an Atomic Safety and Licensing Appeal Board. Normally, the administrative review process will end with the Atomic Safety and Licensing Appeal Board; however, the Commissioners can, on their own initiative, review particular issues. : : 11. AEC Regulatlons prohlbxt the beginning of construction of nuclear power plants and other licensed facilities until a construction permit has been issued. This includes activities such as clearing of land, excavation, construction of non-nuclear facilities (such as turbo-generators and turbine ‘buildings), or other substantial action that would adversely affect the natural environment of a site. However, certain activities such as preconstruction monitoring to establish background information related to the suitability of the site or to the protection of environmental values are permitted. This includes geologic, seismic, hydrologic, and meteorologic investigations and such clearing and building of roads and physical structures as are reasonably necessary for the purpose of determining site suitability. These activities must be conducted in a manner that would keep their environmental impact to a minimum. In some cases, the AEC can issue specific exemptions which authorize certain other preconstruction permit activities where good cause exists. However, these exemptions are made ona case-by-case basis. 12. After about two years of construction work, the utility files with the AEC a final technical safety analysis and another environmental report in support of its application for an operating license. These are subjected to the same kind of thorough safety review by the Regulatory Staff as was the case at the construction permit stage. The ACRS again reyiews the project and furnishes its advice to the Commission. The environmental review at this licensing stage takes into account any environmental impact matters which are significantly different from those considered earlier. 13. Soon after acceptance of the operating license application, the Commission publishes notice that it is considering issuance of the license. The notice provides that any person whose interest may be affected by the proceeding may petition the AEC to hold a hearing and specifies the period of time within which such petitions must be filed. The requirements for a valid petition are the same as those described earlier at the construction permit stage. If no hearing is requested, the AEC issues an operating heense after the safety and environmental reviews are completed and the facility is inspected to be sure it has been satisfactorily completed and ready for fuel loading. If a request for a hearing is received and granted, the hearmg process proceeds in much the same fashion as for the construction permit stage. Obviously, if a hearing is held at the operating 279 license stage, it will be a contested one and authorization of an operating license would depend on a favorable decision of the Atomic Safety and Licensing Board. The “appeals process” in the event exceptions are 'filed to an initial decision at the operating license stage is the same as indicated above for the c_onsiruction permit stage. 14. During this entire process, from the start of construction through the operating lifetime of the facility, routine monitoring is carried out by the Directorate of Regulatory Operations to insure compliance with specifications set forth in the permit or license and other AEC Regulations. 280 Appendix D Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants CHAPTER 1.0 — INTRODUCTION AND GENERAL DESCRIPTION OF PLANT 1.1 Introduction 1.2 General Plant Description 1.3 Comparison Tables | 1.3.1 Comparisons with Similar Facility Designs 1.3.2 Comparison of Final and Preliminary Information 1.4 Identification of Agents and Contractors 1.5 Requirements for Further Technical Information 1.6 Material Incorporated by Reference CHAPTER 2.0 — SITE CHARACTERISTICS 2.1 Geography and Demography 2.1.1 Site Location 2.1.2 Site Description 2.1.3 Population and Population Distribution 2.1.4 Uses of Adjacent Lands and Waters 2.2 Nearby Industrial, Transportation and Military Facilities 2.2.1 Locations and Routes 2.2.2 Descriptions 2.2.3 Evaluations 2.3 Meteorology 2.3.1 Regional Climatology 2.3.2 Local Meteorology 2.3.3 Onsite Meteorological Measurements Programs 2.3.4 Short Term (Accident) Diffusion Estimates 2.3.5 Long Term (Routine) Diffusion Estimates 2.4 Hydrologic Engineering 2.4.1 Hydrologic Description 2.4.2 Floods 2.4.3 Probable Maximum Flood (PMF) on Streams and Rivers 2.4.4 Potential Dam Failures (Seismically Induced) 2.4.5 Probable Maximum Surge and Seiche Flooding 2.4.6 Probable Maximum Tsunami Flooding 2.4.7 Ice Flooding 2.4.8 Cooling Water Canals and Reservoirs 2.5 o3 3.2 3.3 34 3.5 3.6 3.7 281 2.4.9 Channel Diversions 2.4.10 Flooding Protection Requirements 2.4.11 Low Water Considerations 2.4.12 Environmental Acceptance of Effluents 2.4.13 Groundwater 2.4.14 Technical Specifications and Emergency Operation Requirements Geology and Seismology o 2.5.1 Basic Geologic and Seismic Informatlon 2.5.2 Vibratory Ground Motion 2.5.3 Surface Faulting 2.5.4 Stability of Subsurface Materials 2.5.5 Slope Stability CHAPTER 3.0 — DESIGN OF STRUCTURES, CO_MPONENTS,‘EQUIPMENT, AND SYSTEMS Conformance With AEC General Design Criteria Classification of Structures, Components and Systems 3.2.1 Seismic Classification 3.2.2 System Quality Group Classification Wind and Tornado Loadings 3.3.1 Wind Loadings 3.3.2 Tornado Loadings Water Level (Flood) Design 3.4.1 Flood Elevations _ 3.4.2 Phenomena Considered in Design Loading Calculations 3.4.3 Flood Force Application 3.4.4 Flood Protection Missile Protection 3.5.1 Missile Barriers and Loadings 3.5.2 Missile Selection 3.5.3 Selected Missiles 3.5.4 Barrier Design Procedures 3.5.5 Missile Barrier Features Protection Against Dynamic Effects Associated With the Postulated Rupture of Piping- 3.6.1 Systems in which Design Basis Piping Breaks Occur - : 3.6.2 Design Basis Piping Break Criteria 3.6.3 Design Loading Combinations 3.6.4 Dynamic Analyses 3.6.5 Protective Measures Seismic Design 3.7.1 Seismic Input 3.7.2 Seismic System Analysis - 3.7.3 Seismic Subsystem Analysis 3.7.4 Seismic Instrumentation Program 3.7.5 Seismic Design Control 282 3.8 Design of Category I Structures 3.8.1 Concrete Containment 3.8.2 Steel Containment System 3.8.3 Concrete and Structural Steel Internal Structures of Steel or Concrete Contamments | 3.8.4 Other Category I Structures ' 3.8.5 Foundations and Concrete Supports 3.9 Mechanical Systems and Components 3.9.1 Dynamic Systemn Analysis and Testing 3.9.2 ASME Code Class 2 and 3 Components 3.9.3 Components Not Covered by ASME Code 3.10 Seismic Design of Category I Instrumentation and Electrical Equlpment 3.10.1 Seismic Design Criteria 3.10.2 Analyses, Testing Procedures and Restraint Measures 3.11 Environmental Design of Mechanical and Electrical Equlpment 3.11.1 Equipment Identification - 3.11.2 Qualification Tests and Analyses . 3.11.3 Qualification Test Results 3.11.4 Loss of Ventilation CHAPTER 4.0 — REACTOR 4.1 Summary Description 4.2 Mechanical Design 4.2.1 Fuel 4.2.2 Reactor Vessel Internals 4.2.3 Reactivity Control Systems 4.3 Nuclear Design 4.3.1 Design Bases 4.3.2 Description 4.3.3 Analytical Methods 4.3.4 Changes 4.4 Thermal and Hydraulic Design 4.4.1 Design Bases 4.4.2 Description 4.4.3 Evaluation 4.4.4 Testing and Verification 4.4.5 Instrumentation Requirements CHAPTER 5.0 — REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.1 Summary Description 5.1.1 Schematic Flow Diagram 5.1.2 Piping and Instrumentation Diagram 5.1.3 Elevation Drawing 283 5.2 Integrity of Reactor Coolant Pressure Boundary 5.2.1 Design of Reactor Coolant Pressure Boundary Components 5.2.2 Overpressurization Protection | 5.2.3 General Material Considerations 5.2.4 Fracture Toughness | 5.2.5 Austenitic Stainless Steel 5.2.6 Pump Flywheels . 5.2.7 Reactor Coolant Pressure Boundary Leakage Detectlon Systems . 5.2.8 Inservice Inspection Program 5.3 Thermal Hydraulic System Design 5.3.1 Analytical Methods and Data- 5.3.2 Operating Restrictions on Pumps 5.3.3 Power-Flow Operating Map (BWR) 5.3.4 Temperature-Power Operating Map (PWR) 5.3.5 Load Following Characteristics 5.3.6 Transient Effects 5.3.7 Thermal and Hydraulic Characteristics Summary Table 5.4 Reactor Vessels and Appurtenances 5.4.1 Protection of Closure Studs 5.4.2 Special Processes for Fabrication and Inspection _ 5.4.3 Features for Improved Reliability 5.4.4 Quality Assurance Surveillance 5.4.5 Materials and Inspections 5.4.6 Reactor Vessel Design Data 5.4.7 Reactor Vessel Schematic 5.5 Component and Subsystem Design 5.5.1 Reactor Coolant Pdmps 5.5.2 Steam Generators 5.5.3 Reactor Coolant Piping 5.5.4 Main Steam Line Flow Restrictions 5.5.5 Main Steam Line Isolation System 5.5.6 Reactor Core Isolation Cooling System 5.5.7 Residual Heat Removal System ~5.5.8 Reactor Coolant Cleanup System 5.5.9 Main Steam Line and Feed Water Pxpmg 5.5.10 Pressurizer 5.5.11 Pressurizer Relief Tank 5.5.12 Valves 5.5.13 Safety and Relief Valves 5.5.14 Component Supports 5 6 Instrumentatxon Requlrements 6.1 6.2 6.3 6.4 6.X 7.1 7.2 1.3 7.4 7.5 7.6 284 CHAPTER 6.0 — ENGINEERED SAFETY FEATURES General Containment Systems 6.2.1 Containment Functional Design 6.2.2 Containment Heat Removal Systems 6.2.3 Containment Air Purification and Cleanup Systems - 6.2.4 Contzinment Isolation Systems 6.2.5 Combustible Gas Control in Containment Emergency Core Cooling System 6.3.1 Design Bases 6.3.2 System Design 6.3.3 Performance Evaluation 6.3.4 Tests and Inspections 6.3.5 Instrumentation Requirements Habitability Systems -6.4.1 Habitability Systems Functional Design Other Engineered Safety Features 6.X.1 Design Bases 6.X.2 System Design 6.X.3 Design Evaluation 6.X.4 Tests and Inspections 6.X.5 Instrumentation Requirements CHAPTER 7.0 — INSTRUMENTATION AND CONTROLS Introduction 7.1.1 Identification of Safety Related Systems 7.1.2 Identification of Safety Criteria Reactor Trip System 7.2.1 Description 7.2.2 Analysis Engineered Safety Feature Systems 7.3.1 Description 7.3.2 Analysis Systems Required for Safe Shutdown 7.4.1 Description 7.4.2 Analysis Safety Related Display Instrumentation 7.5.1 Description 7.5.2 Analysis All Other Systems Required for Safety 7.6.1 Description 7.6.2 Analysis C 285 7.7 Control Systems Not Required for Safefy 7.7.1 Description | 7.7.2 Analysis CHAPTER 8.0 — ELECTRIC POWER 8.1 Introduction 8.2 Offsite Power System 8.2.1 Description 8.2.2 Analysis 8.3 Onsite Power Systems 8.3.1 A-C Power Systems 8.3.2 D-C Power Systems CHAPTER 9.0 — AUXILIARY SYSTEMS 9.1 Fuel Storage and Handling 9.1.1 New Fuel Storage 9.1.2 Spent Fuel Storage 9.1.3 Spent Fuel Pool Cooling and Cleanup System 9.1.4 Fuel Handling System 9.2 Water Systems 9.2.1 Station Service Water System v 9.2.2 Cooling System for Reactor Auxiliaries 9.2.3 Demineralized Water Make-Up System 9.2.4 Potable and Sanitary Water Systems 9.2.5 Ultimate Heat Sink | 9.2.6 Condensate Storage Facilities 9.3 Process Auxiliaries - 9.3.1 Compressed Air Systems 9.3.2 Process Sampling System 9.3.3 Equipment and Floor Drainage System 9.3.4 Chemical, Volume Control, and quuld Poison Systems 9.3.5 Failed Fuel Detection System B 9.4 Air Conditioning, Heating, Cooling, and Ventilation Systems 9.4.1 Control Reom | 9.4.2 Auxiliary Building 9.4.3 Radwaste Area 9.4.4 Turbine Building 9.5 Other Auxiliary Systems ~9.5.1 Fire Protection Sys{ém 9.5.2 Communication Systems 9.5.3 Lighting Systems 9.5.4 Diesel Generator Fuel Qil Storage and Transfer System 9.5.5 Diesel Generator Cooling Water System 9.5.6 Diesel Generator Starting System 9.5.7 Diesel Generator Lubrication System 286 CHAPTER 10.0 — STEAM AND POWER CONVERSION SYSTEM 10.1 Summary Description 10.2 Turbine-Generator 10.2.1 Design Bases 10.2.2 Description 10.2.3 Turbine Missiles 10.2.4 Evaluation 10.3 Main Steam Supply System ~ 103.1 Design Bases 10.3.2 Description 10.3.3 Evaluation 10.3.4 Inspection and Testing Requirements 10.3.5 Water Chemistry © 104 Other Features of Steam and Power Conversion System - 10.4.1 Main Condensers 10.4.2 Main Condensers Evacuation System 10.4.3 Turbine Gland Sealing System 10.4.4 Turbine Bypass 'System 10.4.5 Circulating Water System 10.4.6 Condensate Clean-Up System 10.4.7 Condensate and Feedwater Systems 10.4.8 Steam Generator Blowdown Systems CHAPTER 11.0 — RADIOACTIVE WASTE MANAGEMENT 11.1. Source Terms 11.2 Liquid Waste Systems 11.2.1 Design Objectives 11.2.2 Systems Descriptions 11.2.3 System Design 11.2.4 Operating Procedures 11.2.5 Performance Tests 11.2.6 Estimated Releases 11.2.7 Release Points 11.2.8 Dilution Factors 11.2.9 Estimated Doses 11.3 Gaseous Waste Systems 11.3.1 Design Objectives 11.3.2 Systems Descriptions 11.3.3 System Design 11.3.4 Operating Procedures 11.3.5 Performance Tests 11.3.6 Estimated Releases 11.3.7 Release Points 287 11.3.8 Dilution Factors 11.3.9 Estimated Doses 11.4 Process and Effluent Radiological Monitoring Systems 11.4.1 Design Objectives | - 11.4.2 Continuous Monitoring 11.4.3 Sampling ' 11.4.4 Inservice Inspections, Calibrétion, and Maintenance 11.5 Solid Waste System - 11.5.1 Design Objectives 11.5.2 System Inputs 11.5.3 Equipment Description 11.5.4 Expected Volumes 11.5.5 Packaging 11.5.6 Storage Facilities 11.5.7 Shipment 11.6 Offsite Radiological Monitoring Program 11.6.1 Expected Background 11.6.2 Critical Pathways 11.6.3 Sampling Media, Locations and Frequency 11.6.4 Analytical Sensitivity | 11.6.5 Data Analysis and Presentation 11.6.6 Program Statistical Sensitivity CHAPTER 12.0 — RADIATION PROTECTION 12.1 Shielding 12.1.1 Design Objectives 12.1.2 Design Description 12.1.3 Source Terms 12.1.4 Area Monitoring 12.1.5 Operating Procedures 12.1.6 Estimates of Exposure' 12.2 Ventilation o 12.2.1 Design Objectives 12.2.2 Design Description 12.2.3 Source Terms _ . 12.2.4 Airborne Radioactivity Monitoring 12.2.5 Operating Procedures | 12.2.6 Estimates of Inhalation Doses '12.3 Health Physics Program - 12.3.1 Program Objectives 12.3.2 Faéilities and Equipment 12.3.3 Personnel Dosimetry - 13.1 13.2 13.3 13.4 13.5 13.6 13.7 14.1 14,2 15.1 288 CHAPTER 13.0 — CONDUCT OF OPERATIONS Organizational Structure of Applicant 13.1.1 Corporate Organization 13.1.2 Operating Organization 7 13.1.3 Qualification Requirements for Nuclear Plant Personnel Training Program '13.2.1 Program Description 13.2.2 Retraining Program 13.2.3 Replacement Training 13.2.4 Records Emergency Planning Review and Audit 13.4.1 Review and Audit — Construction 13.4.2 Review and Audit — Test and Operation Plant Procedures Plant Records 13.6.1 Plant History 13.6.2 Operating Records 13.6.3 Event Records Industrial Security 13.7.1 Personne! and Plant Design 13.7.2 Security Plan CHAPTER 14;0 _ INITIAL TESTS AND OPERATION Test Program 14.1.1 Administrative Procedures (Testing) 14.1.2 Administrative Procedures (Modifications) 14.1.3 Test Objectives and Procedures " 14.1.4 Fuel Loading and Initial Operation 14.1.5 Administrative Procedures (System Operation) Augmentation of Applicant’s Staff for Initial Tests and Operation 14.2.1 Organizational Functions, Responsibilities and Authorities 14.2.2 Interrelationships and Interfaces 14.2.3 Personnel Functions, Responsibilities and Authorities 14.2.4 Personnel Qualifications CHAPTER 15.0 — ACCIDENT ANALYSES General 15.1.X Event Evaluation CHAPTER 16.0 — TECHNICAL SPECIFICATIONS 289 CHAPTER 17.0 — QUALITY ASSURANCE 17.1 Quality Assurance During Design and Construction 17.1.1 Organization 17.1.2 Quality Assurance Program 17.1.3 Design Control . 17.1.4 Procurement Document Control 17.1.5 Instructions, Procedures, and Drawings 17.1.6 Document Control | 17.1.7 Control of Purchased Material, Equipment, and Services 17.1.8 Identification and Control of Materials, Parts and Components 17.1.9 Control of Special Processes 17.1.10 Inspection : 17.1.11 Test Control 17.1.12 Control of Measuring and Test Equipment 17.1.13 Handling, Storage, and Shipping 17.1.14 Inspection, Test and Operating Status 17.1.15 Nonconforming Materials, Parts or Components 17.1.16 Corrective Action | 17.1.17 Quality Assurance Records 17.1.18 Audits 17.2 Quality Assurance Program for Station Operation 290 Appendix E Stahdard Format and Content of Environmcntal Reports for Nuclear Power Plants 1. PURPOSE OF THE PROPOSED FACILITY 1.1 Need for power 1.1.1 Load characteristics 1.1.2 Power supply 1.1.3 Capacity requirement 1.1.4 Statement on area need 1.2 Other objectives 1.3 Consequences of delay 2. THE SITE 2.1 Site location and layout 2.2 Regional demography, land and water use 2.3 Regional historic, scenic, cultural and natural landmarks 2.4 Geology 2.5 Hydrology 2.6 Meteorology 2.7 Ecology 2.8 Background radiological characteristics 2.9 Other environmental features 3. THE PLANT 3.1 External appearance 3.2 Reactor and steam-electric system 3.3 Plant water use 3.4 Heat dissipation system 3.5 Radwaste systems 3.6 Chemical and biocide wastes 3.7 Sanitary and other waste systems 38 Radioactive materials inventory 3.9 Transmission facilities 4. ENVIRONMENTAL EFFECTS OF SITE PREPARATION, PLANT AND TRANSMISSION FACILITIES CONSTRUCTION 4.1 4.2 4.3 Site preparation and plant construction Transmission facilities construction Resources committed 291 v 5. ENVIRONMENTAL EFFECTS OF PLANT OPERATION. 5.1 Effects of operation of heat dissipation system - 5.2 Radiological impact on biota other than man 5.2.1 Exposure pathways 5.2.2 Radioactivity in environment 5.2.3 Dose rate estimates 5.3 Radiological impact on man 5.3.1 Exposure pathways 5.3.2 Liquid effluents 5.3.3 Gaseous effluents 5.3.4 Direct radiation 5.3.4.1 Radiation from facility 5.3.4.2 Transportation of radioactive materials 5.3.5 Summary of annual radiation doses 5.4 Effects of chemical and biocide discharges 5.5 Effects of sanitary and other waste discharges 5.6 Effects of operation and maintenance of the transmission system 5.7 Other effects 5.8 Resources committed 5.9 Decommissioning and dismantling 6. EFFLUENT AND ENVIRONMENTAL MEASUREMENTS AND MONITORING PROGRAMS 6.1 6.2 6.3 Applicant’s pre-operational environmental programs 6.1.1 Surface waters 6.1.2 Ground water 6.1.3 Air 6.1.4 Land 6.1.5 Radiological surveys Applicant’s proposed operational monitoring programs 6.2.1 Radiological monitoring ' 6.2.2 Chemical effluent monitoring © 6.2.3 Thermal effluent monitoring - 6.2.4 Meteorological monitoring - 6.2.5 Ecological monitoring Related environmental measurement and monitoring programs 7. ENVIRONMENTAL EFFECTS OF ACCIDENTS _ 7.1 7.2 “Plant accidents involving radioactivity Other accidents 8. ECONOMIC AND SOCIAL EFFECTS OF PLANT CONSTRUCTION AND OPERATION 8.1 8.2 Benefits Costs 292 9. ALTERNATIVE ENERGY SOURCES AND SITES , . 9.1 Alternatives not requiring the creation of new generating capacity 9.2 Alternatives requiring the creation of new generating capacity 9.2.1 Selection of candidate areas , 9.2.2 Selection of candidate site-plant alternatives 9.3 Costeffectiveness comparison of candidate site-plant alternatives 10. PLANT DESIGN ALTERNATIVES ' : 10.1 Cooling system (exclusive of intake and discharge) 10.2 Intake system - 10.3 Discharge system 10.4 Chemical waste treatment 10.5 Biocide treatment ' 10.6 Sanitary waste system 10.7 Liquid radwaste systems 10.8 Gaseous radwaste systems 10.9 Transmission facilities 10.10 Other systems 11. SUMMARY BENEFIT-COST ANALYSIS 12. ENVIRONMENTAL APPROVALS AND CONSULTATIONS 13. REFERENCES TABLES Table 1 Benefits from the Proposed Facility Table 2 Monetized Bases for Generating Costs _ Table 3 Environmental Factors to be Used in Comparing Altemnative Plant Systems Table 4 Basic Tabulation to be Used in Comparing Alternative Plant Systems Table 5 Basic Tabulation to be Used in Comparing Alternative Transmission Routes Table 6 Cost Description of Proposed Facility and Transmission Hookup APPENDICES 1. Questionnaire for Eliciting Data for Radioactive Source-Term Calculations 2. Example of Charts Showing Radiation Exposure Pathways 293 Appendix F " Population Risk Profiles for Texas and Louisiana Industrialized Areas g | 294 ORNL-DWG 7412743 PART A 15 16 € 1 HOUSTON SHIP 2 HOUSTON SHIP 14 1.3 12 1.1 10 5 5 £ o9 5 & w " o8 ¥ o @ 0.7 06 05 04 0.3 02 L 1 L 1 L L i L L 1. 1 L L 1 L 03 L i ) 1 L 1 aadaaaaliasalasaatasaadoaaals L L 1 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 0 3 0 2 4 6 8 10 12 14 16 18 20 2 24 26 28 30 I DISTANCE {km) DISTANCE {km} 17 18 3 HOUSTON SHIP 4 HOUSTON SHIP 16 1.7 15 18 14 15 14 1.3 ] 13 1.2 x T 2k o oV 5 5 « x = 1t ¥ 1.0 ¥ o 0 « & 1.0 09 3 1 09 08 0.8F 07 otk 06 0. 05 0! o‘ i L L L 4. A L L L L i L A i L o‘. 1 i A A L L .ul..‘.l.;A.l....I‘;‘ A i basaols L O 2 4 8 8 10 12 14 16 18 20 22 24 28 28 X 32 0 2 4 8 8 10 12 14 16 18 20 22 24 26 2B 30 N DISTANCE (km) Fig. F.1. Population risk factors for Houston ships channel. DISTANCE (km) RISK FACTOR RISK FACTOR 2.2 295 ORNL-DWG 74-12743 PART B i L 1 i L 5 HOUSTON SHIP -20 " RISK FACTOR M T - o rr 08 0.8 i i L A i L i 6 HOUSTON SHIP aiabassadasantosastasasdsssalansalosasl i ol 4 i 0.4 0 2 4 ¢ B O prrrrrrrere 10 12 t4 18 18 20 22 24 DISTAN_CE {km) 20 7 HOUSTON SHIP Lot 1 L Llaoaald i L i adssaak i 0.2 0 10 12 14 16 18 20 22 24 26 .28 30 32 DISTANCE (km} ) Fig. F.1 (continued) 2 4 10 12 14 16 DISTANCE (km) 18 20 22 24 26 28 0 X2 i E ORNL--DWG 7412744 E PART A ; 0.62 052¢ | [ R E 2 BAY PORT j 1 BAY PORT ‘ ‘ 0.60 . 050 058 0.48 056 & 054 | 046 T 052 b « F ‘ e 2044} . 2 ((, L j w 050 F I ! . - i 0 0 042} T o4} = ‘ ! 046 | 0.40 044 | L i 0.38 | oaz | | | 036k 1 0.40 b .1 ) 0.38 L 1 A L ,. 2 s 2 3 L L 1 A 1 i L 0.3_" 1 2 l' 2 L L 5 X 3 1 2 3 3 . . . 1 ; 0 2 3 4 S5 6 7 8 9 10 n 12 o 1 2 3 4 5 6 7 8 9 .10 1N 12 i DISTANCE {km) _ DISTANCE (km) 0.47 045 , [ 3 BAY PORT ‘ 4 BAY PORT § 0.46 044 045 F 043 : 044 | 0.42 | 043 & | 0.41 ! g 042 F = .f £ £ 040 ! o b £ | % ¥ 03 : < 040 f « 0.38 03 i 0.37 : 038k 037 0.36 036 | 0.35 ! 0.36 dasasl Ranaadas st s gl q 3 ) i o 1 0'340.1234_56189101112 ! DISTANCE (km) : ’ DISTANCE (km} Fig. F.2. Population risk factors for Bay Port, Tex. E RiSK FACTOR RISK FACTOR 0.48 0.47 0.45 0.45 0.44 0.43 0.42 0.4t 0.40 0.39 0.38 0.37 0.3 035 0.M 0.33 0.32 0 050 ° 048 0.46 044 042 0.40 0.38 0.35 -0.34 0.32 0.30 297 ORNL-DWG T4-12744 PART 8 rreTey TYTETYYTYYY T 5 BAY PORT 0.54 6 BAY PORT 0.52 0.50 o s RISK FACTOR o S 0.38 0.36 0.34 DISTANCf {km} 7 BAY PORT — A 5 8 7 8 P 1w 1n 12 . - DISTANCE (km) Fig. F.2 (continued) DISTANCE {km) RISK FACTOR 298 0.266 5 1 TEXAS QITY . 0262 f > 0260 f 0.258 | 0.266 | 0.254 | 022 0.260 0.248 0.246 0.244 0.242 0.240 |- 0.236 | 0.23 Loimnits DISTANCE {(km} 0.62 3 TEXAS CITY 0.60 058l o56F 0.54 0.52 050 [~ 2048 wn K 0.46 044f 0.42 040F 038E 0.364 0.34 Adebdiiiaal i 1 L A A 1 A i A L A i " L A RISK EACTOR 0 1 2 3 4 5 6 7 3 DISTANCE (km) 037 ¢ RISK FACTOR 036 | 035 0.34 0.33 0.32 031 | 0.30 0.28 0.59 0.58 057 0.56 o £ o 2 o 3 0.51 0.50 0.49 0.48 ORNL-DWG 74-12746 PART A 2 TEXAS CITY DISTANCE (km) o & 4 TEXAS CITY i PPN faaas] . 1 dasiadaiaibanialosisdacasl laassl 1 2 3 4 5 6 7 8 9 DISTANCE (km) Fig. F.3. Population risk factbrs for Texas City, Tex. RISK FACTOR RISK FACTOR 299 ORNL-DWG 7412746 PART 8 DISTANCE (km} Fig. F.3 (continued) 0.54 1033 5 TEXAS CITY i L 0.52 8 TEXAS CITY 0.32 _ 0.50 0.31 0.48 0.46 1 0.30 0.44 ok 0.42 « g 0.28 0.40 g X o7k ¥ 0. 0.38 2 i 0.36 0.26f 0.34 e § 0.32 b 0.24f \\\_ 0.30 3 T 0.28 ' 0.231 A ; | | 0.26 . i 1 - i i i i i ] 0.2- i 2 loaasd 4 A 3 A 1 1 1 L . N 0 2 3 4 5 8 2 ‘o 1 2 3 4 5" 7 8 9 DISTANCE (km) DISTANCE (km) 0.230 ' 7 TEXAS CITY 0.228 0.226 0.224 0222 0.220 0218F 0.218 0.214 0.212 0210 .0.208 o.m i A i A 1 A rad L i L i 2 3 4 6 8 9 RISK FACTOR RISK FACTOR 0.1645 0.1640 0.1635 0.1630 0.1625 0.1620 0.1615 0.1610 0.1605 0.1600 0.1595 0.1590 0.1585 0.1580 0.1575 0 0.1435 0.1430 0.1425 0.1420 0.1415 0.1410 0.1405 0.1400 0.1395 0.1390 0.1385 0.1380 0 300 rYrrry t CHOCOLATE BAYOU DISTANCE {km) 3 CHOCOLATE BAYOU - 8 DISTANCE (km) " 01810 [ RISK FACTOR RiSK FACTOR 0.1520 01515 | o - 2 o 0.1490 | 0.1485 0.1480 | 0.1475 0 01345 0.1340 0.1335 Q.1330 0.1325 F 0.1320 | 01315 0.1310 0.1305 0.1300 01295 | 0.1200 01285 0 ORNL—DWG 74--12745 PART A 2 CHOCOLATE BAYOU 3 10 12 14 16 DISTANCE (km) 4 CHOCOLATE BAYOU 1 1 i i . i . 1 A 1 . i i i . 2 4 6 8 10 12 1] 16 DISTANCE {km} : Fig. F.4. Population risk factors for Chocdlate Bayou, Tex. RISK FACTOR 301 ORNL-DWG 74-12745 PART 8 0.128 0121 E 5 CHOCOLATE BAYOU _ 8 CHOCOLATE BAYOU 0127 | 0120 ¢ ' ‘ o1 § 0.126 o118 E 0.125 017 0.124 0118 ¢ @ ] goms 3 0.123 = : %ok 0.122 & E 0113 § o1 | o2 f om k- o ' 0.120 F _ \ - om0 § : \ N 0.119 . i 0.108 - . \‘ 0.118 4 - 0.108 _ X J ul ‘ 1 L i 1 . i i L . i \'A 0 .2 4 6 -8 w0 oz " 16 e - 2 4 6 8 10 12 t4 16 DISTANCE {(km} DISTANCE (km) 0.118 RISK FACTOR 7 CHOCOLATE BAYOU 0114 0.112 0.110 0.108 0.106 0.104 0.102 0.100 o.m A 1 i 1 A A A 1 A i 1 L L A i e .1 0 2 4 s 8 10 12 14 16 DISTANCE (km) Fig. F.4 {continued) RISK FACTOR 302 ORNL DW( 74 1274BH PART A 0.115 ¢ ‘ 1 o 1 POINTE COUPEE 2 POINTE COUPEE 0.110 | 3 ‘ g 013 0.105 0.100 0.12 b 0.095 o & 0.090 g Z0.10 0.085 ¥ @ a 0.080 009 0075 0.08 0.070 0.07 0.065 boso i s 1 s ! o - - 0.06 2 1 i 1 ¢ 2 4 6 8 1 1 L L 10 12 14 16 18 “DISTANCE (km) A i i A L i L 20 22 24 26 28 0 R g 2 4 6 B 0.18 0.17 | 3 POINTE COUPEE Laoiad i A d Lo L 1o i 0 2 4 6 8 A L 10 12 14 16 18 DISTANCE (km) Fig. F.5. Population risk factors for Pointe Coupee, La. laaasbasasl 20 22 24 26 28 0 R 10 12 14 16 B 20 22 24 DISTANCE {km) 28 30 32 RISK FACTOR 0.24 0.22 0.20 0.18 o - o o = n 0.12 0.10 303 ORNL DWG /4 127481 PART H [ 4 POINTE COUPEE 0.50 5 POINTE COUPEE 0.45 0.40 0.35 o 8 RISK FACTOR o ) 2] 020} 0.15 0.08 0,10} 4 0.06 A 1 i L A 1 L 1 i A i L L lasaol 005 A FOY L i 1 Laaiad i basaad 1 1 1 1 g 2 4 8 8 10 12 14 16 18 20 22 24 26 28 N I 0. 2 4 8 10 12 14 1% 18 20 22 24 26 28 30 32 DISTANCE (km) Fig. F.5 (continued) DISTANCE {km} DISTANCE {km} ORNL -DWG 74-12747 PART A on - 0.34 1 FREEPORT 2 FREEPORT 0.20 0.32 0.19 0.30 0.18 0.28 o-'T 0-26 024 g 0.16 - o~ g S 2t 2 Font Los x x 0 g 0.20 <014 & 018 0.13 E 016 0.12 o 14 E .11 : 0 012f \ 6.10 \ 010 "&.‘__ . - 3 T 1 0.09 - 1 i i . i d i 1 L A i 1 i n.m 1 1 4 i i 1 X 1 2 1 2 1 i 1 i 0 4 8 8 10 12 " 16 18 0 2 4 6 8 10 12 14 16 18 * DISTANCE {km) DISTANCE {km} 0.44 034 3 FREEPORT 4 FREEPORT 0.42 0.22 0.40 0.38 0. 0.36 0.28f 0.34 ok 0.32 030 024} & 022 S0 O Q Jo2s o020 x x o0 =0 2018 0.22 0.16 0.20 0.18 0.14 0.16 012 0.14 3 0.10 012} 0.0 0.08 0.% _ 1 o'w L A 1 i L ad 1 i 1 L 1 L 1 1 L i 4 6 10 12 14 16 18 0 2 4 6 8 10 12 14 18 18 DISTANCE (km) Fig. F.6. Population risk factors for Freeport, Tex. 305 017 5 FREEPORT 016 | 0.15 | 014 & o - (2] T RISK FACTOR e ! & T 0.140 ORNL-DWG 74-13747 PART B 8 FREEPORT o 0.10 |- . 009t 008 | e 007 i i i 1 A 1 i i A 1 L 1 A i i 0 2 4 6 8 10 12 14 16 - 18 DISTANCE (km) DISTANCE {km} 019 0.30 7 FREEPORT 8 FREEPORT st 0.28 017} 026 016 E 0.24 0.15 | E 0.22 014k & & 0.20 o013 £ = o8 éO.IZ - é « €0.18 on b , ¥ 0.14 oo} 0.12 0.09 F 008 | 0.10 007 E 0.08 0.06 2 1 i i 2 1 i . 1 i A faaand 1 i 0.06 teeuss 1 ’ 1 1 1 Lasial 1 i 0 2 4. 6 12 14 16 8 g 2 10 12 14 B 18 8 10 DISTANCE (km) Fig. F.6 (continued) a 10 DISTANCE {km} -« 0.24 o 038 306 ORNL-OWG 7412747 PART C 0.36 0.34 0.32 030 f 028 | 0.268 b 2022 L w 0.20 w T o018 016 014 f 0.12 0.10 008 | 0.06 9 FREEPORT 0.13 012 011 f 0.10 F RISK FACTOR o 2 o 8 0.07 0.06 10 FREEPORT 0.04 0 0.074 8 10 12 14 16 18 0 DISTANCE (km) 0.072 0.070 0.068} 0.066 0.064 0.052| 0.050 0.048 0.046 11 FREEPORT L dbadeal A 1 A Aaiasd i A 0.044 0 8 10 DISTANCE {km} Fig. F.€ {continued) o DISTANCE {km) RISK FACTOR 307 ORNL - DWG 74-12749 PART A 0110 FOUGE 0.19 1 BATON ROUG E 2 BATON ROUGE 0.18 0.105 0.17 0100 [ 0.18 0.095 0.15 T g 0.14 0.0%0 & 4 § 0.13 @ 0.085 0.12 o.n 0.080 ‘ 0.10 0.075 { 0.09 0.070' 1 L L adasaadas L L L i L A Laaas) - 0080t sl s e o s st e aalaa ol iy a b aaadaaaal 1 5 10 15 20 25 30 3 4 45 5 5 60 8 g .5 10 5 20 25 30 35 40 45 S0 5 &0 &5 DISTANCE tkm) DISTANCE - (km) 0.21 0.38 E 3 BATON ROUGE 4 BATON ROUGE 0.20 0.3E 0.34 0.19 0.2 0.18 0.30 0.17 0.28¢ g 018 5 0.26f 5 2015 & o24f % % 014 « 0.22F 0.20 0.13 0.18 0.12] ' 0.16 o.11 0.14§ 0.10 0.12 0_09 sl 1 i sk L 1 adaaaadaaaalaagala L L P D.!Q 0 S5 10 15 20 25 30 3 40 45 650 55 60 65 0 5 10 15 20 25 30 35 40 45 S0 S5 60 65 S . DISTANCE (km) o _ DISTANCE {km) Fig. F.7. Population risk factors for Baton Rouge, La. RISK FACTOR RISK FACTOR o ® 308 o © o N e o e o €& BATON ROUGE RISK FACTOR o (- ORNL-DWG 7412749 PART B 6 BATON ROUGE 09 o8 e ~ o o o o 03 0.2 O.I 1 L 1 b aalassalasaanless, - 4 0.1 L 1 i 1 L il 1 0 5 10 15 20 2 30 35 4 45 6 & 60 6 0 & 10 15 20 26 30 35 40 45 SO 55 60 DISTANCE (km} DISTANCE (km) 0.601 0.28 - [ 7 BATON ROUGE 8 BATON ROUGE 0.55 o26F 050 F 0.24} 0.45 E [ 0.22F 0.40[ i x gazo - 0.35f g o @ 018f @ 0.30 0.18 025 0.20, 0.14 0.15 0.12F O.Qle A 1 1 i i 1 obdadasl saar vl s L il i 1 o'!e 1 1 i 1 1 1 1 1 i 1 j 1 i i 0 20 25 30 35 40 45 50 65 60 65 6 5 10 15 20 25 30 35 40 45 5 655 60 65 5 10 15 ‘ DISTANCE (km) Fig. F.7 (continued) DISTANCE {km) RISK FACTOR o ) = 3 o - o o 2 0.06 et st 1 309 ORNL-DWG 74-12750 PART A 050 1 LAFOURCHE t 2 LAFOURCHE b - o4s| E 040l 03l ] S E 0.30 | b ) o - ' o ! x ] ¥ 0.25 ‘ x L ! . 3 { 0.20 i - / / 'f i 0.15 £ i / ! ] / o010 el i a ! L 1 . i . 1 X 1. L 1 L J - 0.05 daasalaaeataaaad : 1 . 1 2 ) 10 20 30 40 50 ‘80 70 80 40 50 60 70 80 DISTANCE (km} DISTANCE (km) 3 LAFOURCHE 1 e - - / B-a, ] # / A 7 o 7 / ’ 3 # 7 3 4 ’ A i A L A 1 A L A 1 i 4 0 10 20 . 30 40 50 60 70 80 DISTANCE (km) Fig. F.8. Population risk factors for Lafourche, La. 310 ORNL-DWG 74-12750 PART B 0.24 0.26 E 4 LAFOURCHE L & LAFOURCHE : 0.22 3 6.24 ., ; 020 0.22 1 | 0.20F 018 i 5 b | 018} ' gme & i § g E l w Xotsf ! ¥ ¥ ! =014} w - i &« = b 014f 0.2 - 032} 0.10 010 % : i A\ ; k : 0.08 o.cet | :: s o‘m A 1 A L A 1 i 1 i L i L i L Al o.w i Lok 1 A 1l L 1 L ] A i i L akia Lo i 0 10 20 30 40 50 60 70 80 0 10 20 0 40 50 60 70 a0 DISTANCE (km) DISTANCE (km) 0.30 t 6 LAFOURCHE RISK FACTOR o.m bl L i A L i i dasasd aad i ) i 1 4 40 DISTANCE (km) Fig. F.8 (continued) RISK FACTOR 311 ORNL—DWG 74-12750 PART C RISK FACTOR 024 0.2¢ 4 7 LAFQURCHE f 8 LAFOURCHE 02E 0.24 0.22 020 F 0.20 I8 L $ [ 0.18 | : b » [ @016 @« G141 0.14 012 012 - . 0.10¢ z/“ Tom 0.10 ." V E 9 o'm A 1 i 1 A 1 i A 1 A .l 1 i i Lodil u'm adasaalaasadas L i 1 i 1 dedhbdaalaasabaassdlssaadasasala n 0 10 20 0 40 50 60 70 _ 80 o 10 20 0 40 50 60 70 80 DISTANCE (km) DISTANCE (km}) 0.18 . 3 9 LAFQURCHE 017 0.16 | 0.156 | 0.14 | 013 F o2 o1 F 010 0.00 b.' L A oaand ada 1 0 i - 1 : i 1 -t i o . 10 20 o 49 50 60 70 80 DISTANCE {km) | Fig. F.8 {continued) 0.25 0.24 0.23 022 F 0.20 e © RISK FACTOR o @ 055 0.50 0.45 o 8 RISK FACTOR o ® 0.20 0.25 312 1 NEW ORLEANS RISK FACTOR DISTANCE (km} 0.36 0.3 a3 0.30 e 2 o a o ® 0.2 018 o.1é ORNL-DWG 74-12751 PART A t 2 NEW ORLEANS P L bemad. Amn i | 0 5 0 1 20 DISTANCE (km) 3 NEW ORLEANS A A L L 18 4 NEW ORLEANS 20 25 kY » DISTANCE (km}) 0 5 10 15 20 DISTANCE {km) Fig. F.9. Population risk factors for New Orleans, La. N o RISK FACTOR N o ~ =) RISK FACTOR o o © o = » ~w m w o o » . D4 03 313 ORNL-DWG 7412751 PART B 45 5 NEW ORLEANS : [ & NEW ORLEANS 4l as [ AWt ~N o vy RISK FACTOR N o ¥ b . 1 1 1 X L 1 1 L o-o 1 1 L 1 i A 0 5 10 16 20 % - 30 35 40 0 5 10 15 20 % 0 s 40 DISTANCE (km) DISTANCE {(km} 7 NEW ORLEANS t 0.2 . 1 i L i 1 1 0 5 10 15 20 25 20 35 40 DISTANCE (km) Fig. F.S {continued) RISK FACTOR RISK FACTOR 314 ORNL-DWG 74-12752 PART A 0.30 . .1 PLAQUEMINE 048 s 2 PLAQUEMINE .04 b 0.44 |- 042 F paoE 0.38 E 1 036 o : Sox - b L 50.32 - e 03 02 F 026 F 024 F 02k 020 | 0‘1-'. 1 1 i 1 L 1 L i . 1 1 1 1 i 1 i Q‘s .,.j.;..l..;..l abassalasaalaasal 1 L L L i g } 0 2 4 6 B 10 12 14 16 18 20 22 24 . 2% ¥ 32 0 2 4 6 B8 10 12 14 16 18 20 2 24 26 28 N R DISTANCE (km) DISTANCE {km) - 0. 40, 3 PLAQUEMINE %% [ 4 pacuemne 0.38 0.60 0.36 055 0.34 0.50 0.32 045 0" b 0.30 g X040 028 % ® 035 026 0.30 0.24 022 0.25 0.20 0.20 o‘ls 1 1 1 L X 1 1 1 1 1 i dalsaaalsssalaa i o.'s i L 1 1 ) L i 1 A lesaal 1 aalass 0 12 14 16 18 20 22 24 26 0 2 DISTANCE (km) 2 4 6 8 10 Fig. F.10. Population risk factors for Plaquemine, La. L L 1 12 14 18 18 20 2 24 26 8 X 2 DISTANCE {km) 0.75 0.70 0.65 060 | 0.55 t o z RISK FACTOR o - n 0.25 0.20 0.15 315 ORNL-DWG 7412752 PART B 5 PLAQUEMINE dasss 1 1 1 1 i aalaasal 1 1. 09 0.7 RiSK FACTOR o o o n 0.3f 0.4} | 6 PLAQUEMINE 1 i 1 dasaala 1 10 12 14 16 18 20 22 24 26 28 30 3 DISTANCE {km} RISK FACTOR o o o © < ~ 05 04 03 0.2 -0 7 PLAQUEMINE 1 12 14 16 18 20 22 24 26 28 30 32 DISTANCE {kem) Fig. F.10 {continued) 10 12 L 1 ilas 4 168 18 20 22 24 26 28 0 R DISTANCE (km} i RISK FACTOR RISK FACTCR o 8 316 ORNL-DWG 74-12753 PART A 0.27 0.28 1 TAFT L TAFT 026 0.27 025 f 0.26 0.25 0.24 0.24 023 s E Fon < 0.22 w % 022 « 021} 0 020 F 0.20 19 e 0.19 0.8 0.18 0.17 A L L Y al A 1 A L 1 L 1 1 i i adaasalasaalaas o_'7 A i 3 1 i lesasdosaadl L L A 1 Frewed | 4 L L F A 0 1 2 3 4 5 6 7 8 9 10 0 1 2 3 4 5 6 7 8 ] 10 DISTANCE {km} DISTANCE (km) 028 0.27 0.26 0.25 0.24 023 o 0.20} 0.19 018 DISTANCE {km) ) DISTANCE {(km} Fig. F.11. Population risk factors for Taft, La. ( RISK FACTOR RISK FACTOR 317 0.44 0.42 0.40 o W R o W o o N . @ 0.26 024 F 0.22 4 5 6 DISTANCE (km) 029 0.28 0.27 o A & e N & o [ & Q N W 0.22 5 DISTANCE (km) 0.42 0.40 0.38 0.36 RISK FACTOR 0.24 0.22 0.20 0.18 ORNL-DWG 74.-12753 PART B8 DISTANCE {km} Fig. F.11 (continued) 318 0.250 0.245 Ty 0.240 + 0.235 0.230 0.225 RISK FACTOR 0220 |- 0.215 | 0210+ 0.205 | 8 TAFT 0.200 4 5 6 DISTANCE (km) 0.238 0.236 | 0234 f 0232} 0230 f 0.228 0.226 0.224 0222 RISK FACTOR 0.220 0.218 0.216 0.214 0212 0.210 0.208 10 TAFT DISTANCE (km) ORNL-DWG 74-12753 PARY C 0231 ozl 0.230 0.228 o226k 0.224 §o.222 - S o220 Zo2s 0216f 0.214 0.212 0210 0.208F 0.206 DISTANCE {km) Fig. F.11 (continued) A —— 319 0.3 11 TAFT 032 on 0.30 0.29 RISK FACTOR o B o 2 N 8 e A & 0.23 0.22 021 0.20 DISTANCE (km} 0.42 E 13 TAFT RISK FACTOR o"a A 1 A 1 i adasiidas DISTANCE (km) 0.40 RISK FACTOR ORNL-DWG 74-12753 PART D 12 TAFT Fig. F.11 {continued)} DISTANCE (km} R et o+ 4 e e e 1-200. 201. 202. 203. 204. 205. - 206. 207. 208. 209. 210. 211. 212. 213. 214, 215. 216. 217. 218. 219. 220. 221. 222. 223. 224 256. 257-259. 260—262. 263. 264, 265—-267. 268. 269-271. 272. 273. 274, 275. 321 ORNL-4995 UC-2 — General, Miscellaneous, and Progress Reports INTERNAL DISTRIBUTION T.D. Anderson - ' 225, O.H. Klepper S.E. Beall 226. R.N. Lyon L.L. Bennett ' , 227, G.B. Marrow H.L. Bowers ' 228. J.W. Michel R.H. Bryan" o 229. J.C. Moyers R.S. Carlsmith : - 230. J.B. Nichols H.D. Cochran o _ 231. T.W. Pickel O.L. Culberson 232. H. Postma F.L. Cuiler - 233. S.A. Reed J.G. Delene 234. M.W. Rosenthal H.D. Duncan | 235. Royce Salmon G.G. Fee 236. Myrtleen Sheldon R.C. Forrester : - 237, G.P. Smith A.P. Fraas - 238, 1. Spiewak W. Fulkerson - 239. D.B. Trauger C.W. Gehrs : 240. M.E. Whatley W.R. Gambill : 241. G.D. Whitman V. O. Haynes ’ i 242, W.J. Wilcox R.F. Hibbs ' o 243. J.W. Yarborough E.C. Hise ' 244. ORNL Patent Office JM. Holmes = : ' 245-247, Central Research Library J.K. Huffstetler - ' : » 248, Y-12 Document Reference Section J.D. Jenkins 249-254. Laboratory Records Department J.E. Jones 255. Laboratory Records (RC) S.I. Kaplan ' EX TE RNAL DIS‘TBIBUTION C.J. Aas, Administrator, Coal Utthzatlon Programs Northern States Power Co., 414 Nicollet Mall, ' Minneapolis, Minn. 55401 D.C. Azbill, Shell il Co., P.O. Box 2463, Houston, Tex. 77001 Enos A. Bonham, Jr., Dow Chemical Co., Plaquemine, La. 70764 _ W.C. Bull, Director of Research, The Plttsburg and Midway Coal Mining Co.; 9009 West 67th St., Merriam, Kans. 66202 Neill Cochran, U.S. Energy Research and Development Adrrumstratlon Fossnl Energy—Coal Conversion Utilization, 2100 M St., NW, Washington, D.C. 20545 _ I.T. Cockburn, Celanese Chemical Co., 777 South Post Oak Rd., Houston Tex 77027 E.N. Cramer, S. California Edison, Box 800, Rm. 453, Rosemead, Calif. 91770 P.F. Cunningham, Monsanto Co., Mail Zone F3EB, 800 N. Lindbergh, St. Louis, Mo. 63166 E.L. Daman, Vice President, Foster-Wheeler Corp., Livingston, N.J. 07039 Roger Detman, C.F. Braun and Co. , Athambra, Calif. 91802 C.D. Dickinson, Energy Services, Evans and Co., Inc,, 300 Park Ave., New York, N.Y. 10022 R.L. Dunning, Westinghouse Electric Corp., Energy Utilization Project, 700 Braddock Ave., ~East Pittsburgh, Pa. 15112 276. 271. 278. 279. 280—-282. 283. 284. 285. 322 William Eckert, Research Director, U.S. Bureau of Mines, Morgantown Energy Research Center, Morgantown, W. Va. 26505 D.M. Eissenberg, Union Carbide Corp., 270 Park Ave., New York, N.Y. 10014 H. Falkenberry, Tennessee Valley Authority, Chattanooga, Tenn. 37401 A.P. Foster, Vice President, International Paper Co., 220 East 42nd St., New York, N.Y. 10017 R.P. Gerke, Union Carbide Corp., P.O. Box 8361, South Charleston, W. Va. 25303 M.J. Goglia, Vice Chancellor-Research, Regents, University System of Georgia 244 Washington St., SW, Atlanta, Ga. 30334 F.L. Green, Manufacturing Development General Motors Co., G.M. Technical Center, Warren, Mich. 48090 Tom Gross, Office of Industrial Programs, Energy Conservation and Envuonment Federal - Energy Agency, Washington, D.C. 20461 286. 287. 288. 289. 290. 291. 292, 293. 294, 295. 296. 297. 298, 299, 300, - 301. 302. 303, 304. 305. 306. 307, 308. 309—311. 312. 313. 314. A.R. Hakl, Manager, Program Development, Astronuclear Laboratory, Westirighouse Electric Corp., P.O. Box 10864, Pittsburgh, Pa. 15236 H.M. Hart, Research and Development Department, American Qil Co., P.O. Box 431, Whiting, Ind. 46394 Anne R. Headley, Federal Energy Administration, Office of Conservation and Enwronment Washington, D.C. 20545 J.L. Henderson, Manager, Administration Services, Champion Papers, Pasadena, Tex. 77501 Maxwell Hill, Union Carbide Corp., 270 Park Avenue, New York, N.Y. 10017 J.F. Jones, Manager, Project COED, FMC Corp., Chemical Research and Development Center, P.O. Box 8, Princeton, N.J. 08540 A.E. Kakretz, Manager, Gas Reactor Development General Electric Co., Falrfield Conn 06430 J.M. Kovacik, General Electric Co., Schenectady, N.Y, 12305 G.A. Kemeny, Manager, Advanced Systems Concepts, Power Circuit Breaker Division, Westinghouse Electric Corp., Trafford, Pa. 15085 ' W.E. Kessler, Consumers Power Co., 1945 Parnall Road, Jackson, Mich. 49201 H.R. Linden, Executive Vice President and Director, Institute of Gas Technology, 3424 South State St., Chicago, Ill. 60616 . Elmer Mays, Assistant Plant Manager, Crown Zellerbach Corp., Bogalusa La.. 70427 W.J. McCarthy, Jr., Vice President, The Detroit Edison Co., 1450 Pilgrim Rd., Birmingham, Mich. 48009 J.P. McGee, U.S. Bureau of Mines, Morgantown Energy Research Center, Morgantown, W.Va. 26505 B.J. McKinney, Environmental Resource Section, Tennessee Valley Authority, 524 Power Building, Chattanooga, Tenn. 37401 A.T. McMain, Jr., Manager, Advanced Reactor Projects Marketing, Gulf General Atomic, P.0. Box 81608, San Diego, Calif. 92138 Alex Mills, U.S. Energy Research and Development Administration, Fossil Energy—Coal Conversion Utilization, 2100 M St., NW, Washington, D.C. 20545 R.C. Mitchell, Nuclear Energy Division, General Electric Co., 175 Courtner Ave., San Jose, Calif. 95114 Z.E. Murphy, Division of Fossil Fuels u. S Bureau of Mines, Arhngton Va. 22210 J.B. O’Hara, The Ralph M. Parsons Co., P.O. Box 54802, Los Angeles, Calif. 90054 G.W. Oprea, Jr., Executive Vice Pre31dent Houston Lighting and Power Co., P.O. Box 1700, Houston, Tex. 77001 _ Henry Plulhps Foster Wheeler Corp., 110 S. Orange Ave,, Livington, N.J. 07039 R.N. Quade, General Atomic Co., P.O. Box 81608, San Diego, Calif. 92138 J.L. Ragan, Celanese Fibers Co., P.O. Box 1414, Charlotte, N.C. 28201 E.H. Reichl, Vice President, Consolidation Coal Co., Research Division, Library, Pa. 15129 J.L. Renzetti, Naval Nuclear Power Unit, 13101 Pelfrey Lane, Fairfax, Va. 22030 J.0. Roberts, Special Studies Group, Nuclear Regulatory Commission, Bethesda, Md. 20555 o . { v Y \ . - 315. 316. 317-319. 320. 321. 322. 323-325. 326. - 327, 328-330. 331. 332. 333. 334. 335. 336. 337-339. 340. 341. 342-344. 345-346. 347-351. 352. 353. 354. 355. 356. 357. 358-546. 323 James Samuels, Power Generation Group, Babcock and Wilcox, P.O. Box 1260, Lynchburg, Va. 24505 Kenneth Schepple, Vice President, Gibbs and Hill, Inc., 393 Seventh Ave., New York, N.Y. 10001 E.P. Scheu, International Paper Co., 220 East 42nd St., New York, N.Y. 10017 H.M. Siegel, Manager, Synthetic Fuels Research Dept., Esso Research and Engineering Co., P.O Box 101, Florham Park, N.J. 07932 A.J. Smith, President, Power Systems Engineering Inc., P.O. Box 19398, Houston, Tex. 77024 W.R. Smith, Nuclear Power Generation Division, Babcock and Wilcox, P.O. Box 1260, Lynchburg, Va. 24505 H.G. Sommers, Crown Zellerbach Corp Vancouver, Wash. 97663 Michael Stollmeyer, Engineering Division, U.S. Army, Engineer Power Group, Building 2377, Ft. Belvoir, Va. 22060 | W.G. Sullivan, Dept. of Industrial Engineering, University of Tennessee, Knoxville, Tenn. 37916 E.J. Sundstrom, Dow Chemical Co., Texas Division, Freeport, Tex. 77541 George Switzer, Gilbert Associates, Inc., P.O. Box 1498, Reading, Pa. 19603 J.J. Taylor, Vice President and General Manager, Advanced Nuclear Systems Division, Westinghouse Electric Corp., P.O. Box 355, Pittsburgh, Pa. 15230 Marion Thomas, American Potato Co., Blackfoot, Idaho 83221 S.A. Trumbower, Westinghouse Electric Corp., Energy Utilization Project, 700 Braddock Ave., East Pittsburgh, Pa. 15112 Raymond E. Vener, U.S. Energy Research and Development Administration, Fossil Energy—Coal Conversion Utilization, 2100 M St., NW, Washington, D.C. 20543 A M. Weinberg, Oak Ridge Associated Universities, P.O. Box 117, Oak Ridge, Tenn. 37830 R.W. Wendes, Amoco Qil Co., M.C. 1105, Box 6110Z, Chicago, ill, 60680 R.S. Wishart, Union Carbide Corp., 270 Park Ave., New York, N.Y. 10017 0.G. Woike, General Electric Co., Building D, P.O. Box 15132, Cincinnati, Ohio 45215 R.L. Wright, Union Carbide Corp., P.O. Box 186, Port Lavaca, Tex. 77979 Director, Division of Reactor Research and Development, U.S. Energy Research and Development Administration, Washington, D.C. 20545 T. Beresovski, Division of Reactor Research and Development, U.S. Energy Research and Development Administration, Washington, D.C. 20545 7 J.C. Montgomery, Division of Reactor Research and Development, U.S. Energy Research and Development Administration, Washington, D.C. 20545 Kermit Laughon, Division of Reactor Research and Development, U.S. Energy Research and Development Administration, Washington, D.C. 20545 Director, Reactor Division, U.S. ERDA, ORO Research and Technical Support Division, U.S. ERDA, ORO R.L. Philippone, U.S. ERDA, ORO (Bldg. 4500) John Shacter, UCC-ND (Y-12) Given distribution as shown TID-4500 under Category UC 2 (mcludmg 25 copies to NTIS) ru. s. GOVERNMENT PRINTING OFFICE: 1975.748.189/18