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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

 

 

 

 

 

 

 

 

 

 

 

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. .’f;,/’;//////
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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
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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
<D ol T |
& gz ! ELEP - 972.0H
- =18 SS.R ~ JUEEP - 997.6H
4 gle _ - 1.5 in. Hg ABS
s ; 1 # Ul |1097.5H
d ~ £ o] £ ol .
8 . P 3|2 9l& - ———t
685,363 ' | - . = ~le c]& =) '
; o o ' | " h :
71 o g l
& |
I

 

 

 

 

 

 

 

® - w0sa#]| - " CONDENSATE
O—m O o : : PUMP
493,884% , o | | A
’ ' : : ' o 20005
| -‘ | | L — —- o
- | ' ' | : | | - SJAE
7Y 10 , : .
| . 1200P. Y10 se YD s¢ Y1o 6F¥ TD ot ¥ 1o
@ Ah=267 ' '

13,780,631# 365.8F 168.0P ' ‘ 4.40p \ 9.644,353=

e —— ——— 364.7F 363.5 316.5F B2.1F 215.6h 12.6F181.2h 148.7F ’ 93.3F

424.5F 402.6h 340.0h e o —— e ———— — I —————— e \
336.0h 287.0h 9,644,353% 117.1h 61.7h ‘

DL RFP 337.3h 10FDO_A 10FOC R/ 10FDCN 7 10FDC

 

10FDC

 

HTR BOOSTER |pOLISHING

| i
HTR. t .
I / . )
& | | Pos Han /s IR | HR-B ! PUMP UNIT
L2068921#3758F ) | Josoe# 7 1987.664% 2226F | 15786874 1587F 1' | 1033 7130 2143.436=
349.3 S ! 202.1F 261.7h 191.0n | - 1267h | e s e e s s e e
141362787 | |
367.5F 340.2h Ah=0.1 : '

: TOTAL TURBINE QUTPUT 1,141,644 kw GENERATOR QUTPUT " 1,109,358 kw

LEGEND - E'EXEED LOSSES . 3066 kW A .?""ARY POWER AT 4.32% - 47,924 kW

NERATOR LOSSES 14,120 kW NET SENT OUT 1,061,434 kW

B CALEY (Bru/ib STATOR COOLER ~ 13,100 kW NET STATION STEAM RATE 12.98 Ib/KWhr.
S ’ Btu/kWhr SENT QUT 10,451
: THERMAL EFFICIENCY 32.65%

Fig. 5.8. Typical 1000-MW(e) BWR turbine cycle heat balance diagram (from WASH-1230, Vol. II).

 

 

 
 

T e A e b e e

48

oS

 

ORNL~-DWG 74--6671

78’y

STty

/-conmmmeur

UPPER POOL

 

 

 

 

 

 

 

 

 

 

 

 

 

\
T~
-~

.
"

-
a
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FUEL A

 

    

TRANSFER G, / o /

LS s anatD

 

 

 

 

 

 

RN R

 

 

1PNl 4

T
o3

W

-
_
.

31 < REACTOR
/_ .

REACTOR
SHIELD WALL

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s

 

 

 

SUPPRESSION / ST e aS iR TRy s
POOL

 

 

 

et e
S ey

 

 

w1 I 7 3

 

piLide

 

SR

‘.“

 

.
¢

- Fig. 5.9. Typical Mark III BWR containment (from General Electric Company Report NEDO-10571).

the delay, the gas is passed through a filter and discharged to the atmosphere. The other 20% of the
‘activity follows the condensate and is treated by the condensate filter-demineralizers.

Radiation shielding is provided around the following areas:

1. main steam lines,
2. primary and extraction steam piping,

3. high- and low-pressure turbines,
 

 

49

feedwater pumps and turbines,

. moisture separators,

reactor feedwater system heaters,
. main condenser and hot well,

. air ejectors and steam packing exhauster,

condensate demineralizer,

10. off-gas lines.

Some of the equipment, such as the air ejectors, feedwater pumps, and heaters, are in individual

‘rooms, thus allowing part of the system to be shut down without interrupting plant operation.

The control room building houses the instrumentation and controls for reactor and

‘turbine-generator controls. It is designed according to seismic, tornado, and flooding criteria and

contains all the necessary instrumentation and control for plant operation under normal and
accident conditions.

The diesel-generator building is designed to withstand short-term tornado loading, including
tornado-generated missiles. This building houses the diesel génerat_ors that provide standby power.

Miscellaneous structures are required for mainténance shops, chemicals storage, water-intake
equipment housing, etc. Other balance-of-plant equipment and systems are similar to those required
for a conventional fossil-fired plant. Included are condensers, feedwater pumps, makeup water
treatment systems, circulating water systems, electric plant equipment, etc.

5.2.3 The PWR Power Plant

The nuclear steam system

A PWR nuclear steam system is made up of closed loops in which heat is transported from the
reactor core to the steam generators by circulating pressurized water. The system consists of a
reactor pressure vessel containing the reactor core, the steam generator, pumps for circulating the

.pressurized water, and a pressurizer that maintains and controls system pressure. A typical PWR
coolant system schematic flow diagram is shown in Fig. 5.10. Characteristics typical of a PWR

nuclear steam system (Babcock and Wilcox plant) are given in Table 5.9. .

Fuel for the PWR core is contained in sealed tubes (fuel rods) which are mounted vertically.
The fuel is cylindrical pellets of sintered, low-enriched uranium dioxide. The pellets are clad in
Zircaloy tubing and sealed by welded Z:rcaloy end caps. The basic fuel assembly is composed of fuel
rods, control rod guxde tubes, one mstrumentatlon tube assembly, segmented spacer sleeves, spacer
grids, and end fittings. The guide tubes, spacer grids, and end fittings form a structural cage to
arrange the rods and tubes in an array.

Core reactmty is controlled by control rod assemblles and soluble boron dissolved in the
primary reactor coolant. The control rods, which move vertically, are actuated by electrically driven
control rod drive mechanisms mounted on top of the reactor pressure vessel.

The reactor vessel contains the core and supporting structures, thermal shield, in-core
instrumentation, and other components. The main connections to the reactor vessel are the main

 
" DEMINERALIZED

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ORNL--DWG 74--5672R

KEY: |
ACS - AUXILIARY COOLANT SYSTEM

 

 

 

 

 

 

WATER AUXILIARY ~ STEAM CVCS — CHEMICAL AND VOLUME CONTROL SYSTEM
SPRAY (CVCS) OUTLET SIS — SAFETY INJECTION SYSTEM
1; WDS - WASTE DISPOSAL SYSTEM
STEAM
GENERATOR
PRESSURIZE
PRESSURIZER FEEDWATER
RELIEF TANK i INLET
X P T 1
Y CONTROL - REACTOR
' ROD DRIVE COOLANT PUMP
' MECHANISMS T
DRAIN HEADER { - -
(WDS) ' HERTER |~ < AUXILIARY COOLING (ACS)
CONTROL
= S SEAL WATER (CVCS)
COLD LEG HOT LEG
(TYPICAL) (TYPICAL)
SAFETY SAFETY INJECTION RESIDUAL LETDOWN
INJECTION]REACTOR SYSTEM HEAT REMOVAL LINE T
h (S1S) ‘ (SIS} LOOP (ACS) (CVCS)
RESIDUAL
CHARGING g JHEAT REMOVAL e—SPRAY LINE
LINE (CVCS) LOOP (ACS) |
< e
EXCESS
LETDOWN LINE -
(cves)

Fig. 5.10. Typical PWR reactor coolant systeri (from Westinghouse Electric Corporation).

 

 
 

 

51

Table 5.9. Design characteristics [3413-MW(t) PWR]

 

Thermal and hydraulic design
-Design core heat output, MW(t) 3413
Nominal system pressure, psia 2250
Total reactor coolant flow, 10° Ib/hr 139
Vessel coolant inlet temperature, °C CF) 301 (573)
Vessel coolant outlet temperature, °C CF) 332 (630)
Reactor vessel design _
Material ' SA-508, class 2 forging,
SA-533, grade B, class 1 plate
Design pressure, psig 2500 :
Design temperature, °C CF) 670
Inside diameter, ft-in. - 15-2
Overall height of vessel and closure head 23-317/8
cover, control rod drives, and instrument nozzles, ft-in.
Steam generator design
Steam conditions at full load
Flow, 10° Ib/hr 14.86
Temperature, °C CF) 318 (603)
Pressure, psia 1075
Feedwater temperature, °C CF) 245 (473)
Reactor coolant side
Flow, 10° Ib/hr 139
Inlet temperature, °C CF) 332 (630)
Outlet temperature, °C CF) 301 (573)

 

coolant lines on the side, control rod drive mechanisms on the top, and instrument lines on the
bottom. The vessel is fabricated of low-alloy steel and is clad internally with stainless steel.

The reactor core is cooled by demineralized water that enters the side of the vessel, flows
downward to the lower end of the vessel, upward through the core, around the fuel rods, and out the
pipe connections on the side of the vessel. The coolant is piped to the steam generator, to the main
circulating pumps, and back to the reactor vessel in a closed loop. It is necessary to maintain the
primary coolant system pressure high enough to prevent boiling. This is done by an electrically
heated pressurizer tied into the system that serves to control the coolant pressure and absorb some
volume variations of the primary coolant. Steam generated in the steam generators is piped to the
steam turbine, passed through the turbine, condensed, and returned by a boiler feedwater system in
the same manner as in a conventional fossil-fired plant. "

The reactor vessel, main coolant piping, steam generators, pressurizer, and coolant circulating
pumps are all located inside the containment structure. Steam lines penetrate the containment and.

“convey the steam to the turbine building, which is not a containment structure.

‘Refueling of the reactor is accomplished by removing the pressure vessel head and flooding the
volume above the vessel. Underwater handling of fuel and other reactor components is then possible.
Underwater storage of the irradiated fuel and reactor internals is accommodated by pool storage
facilities. ' |

The fuel loading of the large PWR core is generally based on a 3-year cycle. Approximately
one-third of the core is replaced annually. The minimum downtime required for depressurization,
cooldown, refueling, repressurization and startup is about 10 days. |

 
 

 

52

Auxiliary systems are provided to perform the follolwing functions:
1. charge the reactor coolant systém;
add makeup water;
purify reactor coolant water;
. provide chemicals for corr;)sion inhibition and reactor control;

. coo!l system components;

. remove residual heat whcn the reactor is shut down;
7. cool the spent-fuel storage;

8. sample reactor coolant water;

9. provide for emergency core cooling;

10. collect reactor coolant drains;

11. provide containment spray;

12. provide containment ventilation and cooling;

13. dispose of liquid, gaseous, and solid wastes;

14. provide seal water for pipes pefietrating containment following an LOCA;

15. provide cooling for containment penetrations with hot pipes;

16. provide redundant means of removing hydrogen from containment following an LOCA;

17. provide main coolant leak-detection system.

Balance of plant

The 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 employed to dry and superheat
steam between the high- and low-pressure turbine sections. A typical heat balance for a 1000-MW(e)
plant is shown in Fig. 5.11. - '

The containment structure completely encloses the entire reactor and reactor coolant system to
ensure that essentially no leakage of radioactive materials to the environment would result even on
gross failure of the reactor coolant system. The structure provides biological shielding for normal
accident conditions and is designed to maintain its integrity under tornado wind loading; impact
from tornado-generated missiles, storm winds, floods, earthquakes, tsunamis, and other natural
forces at their worst foreseeable intensity within conservatively established recurrence intervals. The
containment building is a concrete structure with a steel liner to ensure leak tightness. A typical
1000-MW(e) plant has a concrete containment structure with an inside diameter of approximately
135 ft and an overall inside height of approximately 67 ft. A typical PWR containment building and
nuclear steam system are shown in Fig. 5.12.

 
 

 

53

| | | ' ORNL- DWG 74—-5673A |
TOTAL TURBINE OUTPUT 127,017 kW

 

  
 
  
   

  

 

 

 

188 9492 - : o FIXED LOSSES - _ 3563 kW
— o - | . . GENERATOR LOSSES . 13920 kW -
1280.0H 153P STATOR COOLER - 13,100 kW
o ‘ - . _ GENERATOR OUTPUT - . 1,096,434 kW
13,780,631 960P ‘ 285% B.F.P.T. " AUXILIARY POWER AT 6.00% - 65,786 kW
&30 7F - 15.142kW ‘ . NET SENT OUT - 1,030,648 kW
T ne3H 1062 2.0 in. Hg ABS 1086.6H NET STATION STEAM RATE 13.34 u;mwm
0.47%M wle - NET STATION HEAT RATE 10,383 Btu/kWhr
13,163= | 2000= als _ : | _ |
@ttt () B OPERATING EFFICIENCY : 98%
1191.3H i Btu/kWhr SENT OUT 10,595 Btu/kWhr
ped - THERMAL EFFICIENCY 32.21%

 

 

  

:1086.6H
13,077.369%
1191.3H

§

7113# 1191.3H

 

 

  

 

 

 

 

  

 

 

 

       

 

 

 

 

 

 

 

 

 

 

 

  
   

 

 

 

 

 

 

 

 

 

 

 

   

 

 

 

 

 

 

 

 

 

   
   

 

 

 

 

 

 

 

 

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:4 537 912 ) £ FLOW (Ib/hr} \
ol ST P PRESSURE (psial .
"@.&l?b.--y F  TEMPERATURE (°F)
STEAM
HEATER DRAIN me=mee FEED WATER
PUMP ~= =~ DRAINS

Fig. 5.11. Typical 1000-MW(e) PWR turbine cycle heat balance diagram (from WASH-1230, Vol. I).

 

 
 

 

54

    

CONTAINMENT . .
BUJLDING

    
   
     

POLAR CRANE

    

LAYDOWN FOR
REACTOR "
MISSILE SHIELD

 

MISSILE SHIELD

   

     
  

ESSURI

  
 
 

MANIPULA

r—— e

RANE

   
  
 
 
 

EL. 1|
ft 0 in.

 
 
 

   
  

MISSILE
SHIELD

 
 
 

FUE

  

R CANAL |

  
   
 

  
  

  

oL
MECHANISM
LING
H

.
»

FUEL TRANSFE
CARRIAGE+

    

 
 
 

Fig. 5.12. Typical PWR containment (from WASH-1082).

IN—CORE INSTRUMENTATION LEADS

ORNL—-DWG 74—-5674R

 

SPENT
FUEL PIT

  
   

 
 

 

55

The control building houses the control room, auxiliary equipment, ventilation equipment, and
the reactor plant- cooling water system. It is a missile-protected building, since: it houses
safety-related equipment. The diesel-generator building is designed to withstand short-term tornado
loading, including tornado—geherated missiles. It houses the diesel generators that provide standby
power. The turbine-generator building contains the turbine generator and other equipment related to
the conventional portion of the plant. Building design is based on the same criteria that are used for
a fossil-fired plant turbine-generator building. :

Miscellaneous structures are required for fuel storage, chemicals storage, maintenance shops,
water-intake equipment housing, etc. Other balance-of-plant equipment and systems are similar to
those required for a conventional fossil-fired plant. Included are items such as the condensers,
feedwater pumps, makeup water treatment system, circulating water systems, and electric plant
equipment. '

5.2.4 The HTGR Power Plant
The nuclear steam system

The HT.GR plants use helium gas as the reactor coolant and graphite as the moderator and core
structural material. The fuel is a mixture of enriched uranium carbide and thorium oxide used in the
form of particles individually clad with ceramic coatings.

All major nuclear steam system components, including the steam generators, are housed in a
steel-lined, prestressed concrete reactor vessel (PCRV) which also provides the necessary biological
shielding. The PCRYV, in turn, is housed in a conventional reinforced concrete secondary
containment building. The design of the large HTGR was based on information developed in the
course of designing and constructing the Peach Bottom and the Fort St. Vrain plants.

The nuclear steam system of the 1160-MW(e) plant produces main superheated steam at 515°C
(955°F) and 2500 psig and reheat steam at 540°C (1002°F) and 571 psig. Overall performance data
for an HTGR plant are shown in Table 5.10. The nuclear steam system contains six independent
primary coolant loops, each with a helium circulator and steam generator. Helium, at a pressure of
about 710 psig, is circulated by means of steam-turbine-driven axial-flow helium circulators. The
helium flows downward through the reactor core and through the single-pass steam generators,
located in the PCRY in separate cavities around the main core cavity, before returning to the helium
circulators. The main superheated steam produced in the steam generators at 515°C (955°F) and
2500 psig passes to the high-pressure element of the steam turbine. The steam from the high-pressure
turbine exhaust is used to drive the helium circulators before pésSing to the reheat section of the
steam generator and on to the intermediate- and low-préssure sections of the steam turbine.

The, reactor core is made up of hexagonally shaped graphite fuel elements approximately 14 in..
across the flats and 31 in. high. Each graphite block has a central pickup hole for handling purposes,

‘coolant channels, and holes to accommodate fuel rods. Dowel pins in each block maintain

alignment. The fuel, in the form of coated particles of highly enriched uranium car'bide as the fissile
material and thorium oxide as the fertile material, is contained in bonded graphite rods. The fuel
elements are stacked in columns elght blocks high to form the core. This assembly is surrounded by
replaceable and permanent graphite reflector blocks. :

Reactor control is by control rods suspended from cables driven by electrically operated drlve
mechanisms. The control rods move in vertical passages in the central column of
elements in each refueling region. Emergency shutdown is accomplished by injecting
neutron-absorbing balls into the core cavities.

 
 

 

 

56

Table 5.10. Overall performance data for an HTGR plant

 

 

3000 MW(t) 2000 MW(t)
General _
Net plant output, MW(e) - 1160 770
Net nuclear steam system output, MW(t) 2979 1982
Net plant efficiency, % 39 39
Net plant heat rate, Btu/kWhr 8843 8900
Turbine back pressure, in. Hg (abs) 225 2.25
Main steam flow, 10° ib/hr 8.1 54
Reheat steam flow, 108 Ib/hr 8.0 5.3
Primary coolant system
Primary coolant Helium Helium
Helium pressure at circulator 710 710
discharge, psig
Core inlet temperature, °C CF) 320 (607 320 (607)
Steam generator inlet duct .- 741 (1366) 741 (1366)
temperature, °C (°F) _
Total helium flow rate to steam 11.2 7.5
generators, 10° Ib/hr
Number of steam generators 6 4
Number of circulators 6 4
System helium pressure drop, psig 20.7 20.7
Reactor core -
Number of fuel elements 3944 2744
Fuel residence time, years 4 4
-Average burnup, MWd/metric ton 98,000

98,000

 

Core fuel elements and reflector blocks are removed and replaced through access holes in the
top of the PCRV. The fuel loading is based on a 4-year cycle. Approximately one-fourth of the core
is replaced each year. The minimum downtime required for depressurization, cooldown, refueling,
repressurization, and reactor startup is estimated to be 14 days. Figure 5.13 illustrates the
arrangement of the core and other parts of the nuclear steam system within the PCRV. Dimensions

of the PCRYV are shown in Table 5.11.

Tablé 5.11. PCRYV dimensions

 

 

3000 MW(t) 2000 MW(1)
Overall height 91 ft 6 in. 91 ft 6 in.
Outside diameter 100 ft 94 ft
Central cavity diameter 37 ft 32 ft 8in.
Central cavity height 47 ft4 in. 47 ft4in.
Number of steam generator/circulator cavities 6 4
Diameter of steam generator/circulator cavities 14 £t 2 in. 14 ft 2 in.
Number of auxiliary cooling cavities 3 2
Diameter of auxiliary cooling cavities 7ft 8 ft2in.

 

 
 

HELIUM
PURIFICATION
WELLS -

. AUXILIARY
. CIRCULATOR

CORE AUXILIARY

HEAT EXCHANGER

PRESTRESSED
CONCRETE
REACTOR VESSEL

 

 

Fig. 5.13. 1160-MW(e) HTGR nuclear system.

 

ORNL-DWG 73-11166

CONTROL ROD DRIVE
AND REFUELING
PENETRATIONS

CIRCULATOR

STEAM GENERATOR

VERTICAL
PRESTRESS TENDONS

PRESTRESS CHANNELS

PCRV SUPPORT
STRUCTURE

LS

 

 
 

 

 

58

The intermediate cooling water system supplies the reactor systems with cooling water, which,
for safety reasons, is in turn cooled in a closed circuit loop. This system serves to cool the PCRV
lines, main and auxiliary helium circulators, fuel element storage systems, and helium treatment
systems.

The helium treatment system is provided for the removal of contaminants from the helium
coolant. The purification process takes place in a series arrangement of a high-temperature absorber,
dryer, low-temperature absorber, and hydrogen absorber.

Balance of plant

The reactor containment building provides a barrier against fission product release to the
atmosphere in case of an accident. It is a concrete cylindrical structure with a total height of 125 ft
and an inside diameter of 126 ft for the 1160-M W(e) nuclear steam system. The inner surface is lined
with carbon steel to ensure leak tightness.

The reactor service building houses new and used fuel storage wells and reactor auxiliary
systems that are not located inside the containment building. Provisions are also made for storage of
reactor moderator parts in this building, which is a multistory structure adjacent to the containment
building. ' ' - ‘ ,
~ The control building houses the control room, auxiliary equipment, ventilation équipment, and
reactor plant cooling water system. It is a missile-protected building since it houses safety-related
equipment. :

The diesel-generator building is designed to withstand short-term tornado loading, including
tornado-generated missiles. This building houses the diesel generators that provide standby power.

The turbine-generator building contains the turbine generator and other equipment related to
the conventional portion of the plant. Building design is based on the criteria used for a fossil-fired
plant turbine-generator building. '

Miscellaneous structures are required for storage of helium bottles, chemicals storage,
water-intake equipment housing, etc. ' ‘ |

The turbine generator and its controls act integrally with the nuclear steam system for turbine
load control. The type of turbine selected is subject to variations; however, a typical heat balance
diagram for a 3600-rpm tandem-compound turbine using four feedwater heaters is shown in Fig.
5.14. The circulating water system provides the major means of plant heat rejection.

Other balance-of-plant equipment and systems are similar to those required for a conventional
fossil-fired plant. Included are items such as the condensers, feedwater pumps, makeup water
treatment system, circulating water systems, and electric plant equipment.

5.2.5 Environmental Parameters

The construction of a power pla_ni, nuclear or fossil fueled, will inevitably affect the
environment, and some of the effects will be adverse. Effects are considered adverse if environmental
change causes some biotic population or nonviable resource to be less safe, less abundant, or less
aesthetically pleasing; if the change reduces the diversity and variety of individual choice or the
standard of living; or if the change tends to lower the quality of renewable resources or to impair the
recycling of depletable resources. The severity of adverse effects should be reduced to minimum
practicable levels.

 
 

 

 

 

 

 

 

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NET STATION HEAT RATE 8843 Btu/kWhr NSSS THERMAL POWER 2979.0MW
HELIUM OPERATING PRESS 725psia CIRC. WATER PUMP POWER 3.5MW
HELIUM PRESSURE DROP 20.71psi OTHER STATION AUX. POWER 14.5MW

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ORNL-DWG 74-5675A

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

   

 

 

* Fig. 5.14. Typical 1160-MW(s) HTGR turbine cycle heat balance diagram (from General Atomic Company).

" 6S

 

 
 

 

60

Prior to the issuance of a construction permit or operating license for a nuclear power plant, the
utility must submit a report on the potential environmental impacts of the proposed plant and
associated facilities.*’ Some of the environmental parameters considered in an environmental report
are as follows: - '

1. the site,

2. the plant, |

3. effects of site preparation and plant and transmission facilities construction,
effects of plant opefation, |

. efflfiént _measurerflent and monitoring,

. effects of accidents, |

. economic and social effects of plant constmction and operation,

. alternative energy sources and sites. |

In this study, attention is confined to the environmental effects of plant opération. The two principal
impacts are due to waste heat and radioactivity, although chemical effluents and others are
important.

‘Waste heat

Regardless of the thermal source in a power plant, about 60 to 70% of th¢ heat produced 1s
rejected to the environment. Figure 5.15 shows heat balances for three types of plants, each
producing 1000 MW(e). The LWR plant is assumed to have an efficiency of 33%, while the HTGR
and the fossil-fuel plants have efficiencies of 38%. It is assumed that 85% of the waste heat is carried
off by the condenser cooling water for the fossil-fuel plant and 95% for the nuclear-fuel plant. The
LWR plant deposits about 50% more waste heat in the condenser water than the fossil-fuel plant
and about 35% more than the HTGR plant. HTGR plants have about the same steam conditions as
fossil-fuel plants and are therefore given the same efficiency, but their miscellaneous losses are more
like those of the LWR plants.

The two major types of cooling systems in use are the open cycle and the closed cycle. The open
cycle is generally referred to as the “once-through” system, since the cooling water from the river,
lake, ocean, or other source is pumped through the condenser and then returned to the source. In

-the closed cycle, water is recirculated through the condenser after it has been cooled in a cooling

tower or pond. Cooling towers may be either wet or dry, natural draft or mechanical draft. Cooling
ponds may use large acreage (about 1 to 2 acres per megawatt of installed capacity) or sprays
to ensure the desired degree of cooling.

Cooling ponds and wet towers may cause objectionable fogs, icing, or plumes. In addmon the
size of the pond or tower may be objectlonable

 

21. Guide to the Preparation of Environmental Reports for Nuclear Power Plants U.S. Atomic Energy Commission,
Directorate of Regulatory Standards, August 1972.

 
 

 

 

 

61

' ORNL-D -
100 MW(t) TO ATMOSPHERE WG 74-5676

 

: ' LIGHT WATER
3030 MW/(t) emmwomniiiiun REACTOR e 1000 MW(e) TO LOAD

PLANT

 

 

 

1930 MW(t) TO
CONDENSERS

80 MW(t) TO ATMOSPHERE

 

2630 MW(t) i HTGR e 1000 MW(e) TO LOAD
PLANT .

 

 

 

1550 MW(t) TO
CONDENSERS

245 MW(t) TO ATMOSPHERE

 

2630 MW(t) ——gmel  FOSSILFUEL == 1000 MW(e) TO LOAD

 

 

 

1385 MW(t) TO
CONDENSERS

Fig. 5.15. Heat balances for LWR, HTGR, and fossil-fuel power plants.

 
 

 

 

62

The plume of the wet tower can be reduced or eliminated by using wet/dry towers.” In these
towers, only part of the heat is removed with water; enough heat is removed with the air-water vapor
mixture so that the relative humidity is much reduced. Such towers also reduce water consumption.

Radiological

During the operation of a nuclear power plant, radioactive gases are produced by activation of
such materials as argon, nitrogcn', and oxygen; iodine, krypton, and xenon are produced in the fuel
by fission. The amount of the latter three in the reactor coolant depends on the integrity of the fuel
elements. With the passage of time, the fuel cladding develops pinhole leaks, and the fission product
gas escapes into the coolant.

The plants are designed® to operate with fuel element leakage up to about 1%. In the BWR, the
gases released to the primary coolant are carried to the turbine and to the condenser along with the
steam. Steam is condensed back to water, but the noncondensable gases, including the very small
volume of radioactive gases, are vented to a cleanup system. After some time for decay the gases are
filtered and released to the environment through the stack. In the PWR, most of the radioactive
gases remain in the coolant water. When the system is opened for maintenance or refueling, the
gases are vented to a cleanup system from which they may be released to the atmosphere.

Also radioactive materials build up in the cooling water during reactor operation. Some of these
result from activation of elements in the water itself —the naturally occurring trace elements. Others

“are generated by neutrons absorbed by the metals, mainly stainless steel or Zircaloy in the reactor

system. Other radioactive products leak out of the fuel elements. In addition, tritium is produced in
the coolant and fuel elements. ‘ ‘

Liquids leaking into and recovered from various plant systems are collected and sent through a
special liquid-waste system where the radioactivity is concentrated and put in a form suitable for
shipping to disposal grounds. The effluent liquids left over are collected in monitoring tanks,
checked for radioactivity, and released at a controlled rate in the plant condenser cooling water.

Solid wastes are generally disposed of off site.

For an HTGR,” the sources of radioactive gaseous waste that result in release to the
atmosphere are 1%/year PCRYV leakage to the reactor containment and subsequent release to the
atmosphere and losses from the turbine steam system to the atmosphere. The gaseous activity
discharged to the atmosphere from the station during normal operation is (excluding tritium) about
4.4 Ci/year. The activity released from the station to the atmosphere due to losses from the turbine
steam system during normal operation is 180 Ci of tritium per year.

Radioactive liquids and solids are collected in drums and disposed of off site.

5.2.6 Operating and Maintenance Manpower Needs

The staffing of a commercial nuclear power plant with operating and maintenance personnel
requires careful selection and training of personnel as well as careful timing in the hiring of the staff.
The _complexity and newness of the work, the problems caused by radiation, and the high cost of

outage justify more than ordinary planning in the hiring and training of a staff.

 

22. K. A. Olesen and R. J. Budenholzer, “Economics of Wet/Dry Cooling Tower Show Progress,” Efectrical World,
Dec. 15, 1972,

23. J. P. Davis, “The Regulation of the Environmental Effects of Nuclear Power Plants,” Nucl. Safety 14(3), 165-81
(May-June 1973). _
24. Fulton Generating Station, Applicants Environmental Report, vol. 1, sect. 3.5.2.4.

 
 

 

63

The staff of a large utility may be divided into two large groups: the home office (or
headquarters staff) and the operating staff. It is assumed that the headquarters staff is already
functioning, and the emphasis is on the operating and maintenance staff. The following general
discussion can be applied to all types of reactors.

Operations and maintenance staff

Although plant staff organizations can reflect variations in company policies and practices, the
representative organization shown m Fig. 5 16 can be satisfactorily employed to operate a
current-generation single-unit station.”

Each operating shift crew consists of a senior licensed shift supervisor, two licensed control
operators, and two auxnliary operators Five such crews should be trained to handle all normal and
abnormal operatmg procedures. At least one replacement for each of the three categories should be
trained and available to maintain crew strength when job shifts, reSIgnatlons or retirements occur
and to accommodate on-site fuel handling procedures.

Direct day-to-day technical support_for plant operations is a necessity. The vital technical areas
are radiation protection, plant chemistry, instrumentation and controls, reactor, turbine generator,

 

25. Utility Staffing and Training for Nuclear Power, WASH-1130 (Rev.).

ORNL-DWG 74-5677

 

PLANT SUPERINTENDENT

 

 

 

ASSISTANT PLANT
SUPERINTENDENT

 

 

 

 

 

' ' ADMINISTRATIVE STAFF
SECURITY FORCE (11) CLERICAL, CUSTODIAL

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONS _ S ~ TECHNICAL . o ' - : MAINTENANCE
SUPERVISION } . . - o " SUPERVISION - - o ' SUPERVISION
OPERATING SHIET RADIATION 3 INSTRUMENTATION PLANT
CREW (8) PROTECTION PLANT CHEMIST AND CONTROLS PERFORMANCE
. ENGINEER ENGINEER ENGINEERS {3)
. '~ MAINTENANCE
I )  TECHNICIANS(9) j PERSONNEL (13)°

 

 

 

 

 

 

 

 

 

 

 

 

*Avgmented by 10 speciel eraft located off she

Fig. 5.16. Representative organization for a single-unit central station nuclear pdwer plant (from WASH-1130 Revised).

 
 

 

 

64

and balance-of-plant equipment. Functions include routine monitoring, surveys, sampling, analyses,

~ instrument checking and maintenance, performance analysis, test preparations, and evaluation of

results. : : ' :

Electrical and mechanical maintenance requirements noted ‘are largely aimed toward the
preventive maintenance program but will allow for some repair and corrective maintenance. Certain
specialized craft skills not routinely needed at the plant site may come from a more centralized
systemwide maintenance staff or from outside organizations.

A plant security force of 11 provides for a supervisor and 5 shift crews of 2 men each for
round-the-clock coverage. Due to the specialized training required for security force personnel, they
may be administratively attached to a separate organization reporting to headquarters.

The timing of the selection and appointment of personnel to a plant staff is an important
consideration to assure that full qualifications requirements are met by the staff when the plant is
ready. Management and key supervisory personnel should be on board not later than 4 years before
initial fuel loading. Operating crew personnel should be selected at least 3 years in advance of fuel
loading so that they will have completed virtually all formal and experience training requirements by
the time the preoperational test program begins. Technical support personnel should be selected and
assigned within the 2- or 3-year period ahead of fuel loading for training and familiarization
assignments. Security personnel may be required to protect property early in the construction period
but should be fully trained and on the job during preoperational testing.

The staffing of multiple-unit stations must provide for the performance of essentially the same
functions as are required for single units. There are considerations, however, which may make it
unnecessary to duplicate single-unit staff entirely. Some of these are (1) the degree of similarity in
design features and operating characteristics and the reflection of these in operability and
maintainability, (2) the extent to which some systems (e.g., waste management) are common, and (3)
the absence of overlapping startup and break-in periods for successive units during which manpower
demands may be heavier.

Tables 5.12 and 5.13 display the organizational breakdown for representative multiple-unit
stations. Study of the comparison shown with a single-unit station staff structure demonstrates the
potential applicability of the above factors, viz., identical units with a common control room and
some shared systems.

It will be noted that it also reflects an opportunity for more effective use of manpower through
specialization of the operational fuel management function on site. A fuel handling team should be
considered in lieu of additional “regular” operating personnel for multiple-unit stations. The team’s
responsibilities would cover all phases of fuel handling on site, from receipt, inspection, storage,
inventory control, refueling and unloading the core, spent fuel handling, cask loading, and shipment
of spent fuel. The lead fuel handlers (or foremen) of this team would be expected to qualify for
senior operator licenses which can be restricted to cover the scope of their activities.

Staff training

Concurrently with the obtaining of a staff so that the plant may be put in operation upon
completion, a training program must be in operation. Various standards have been prepared
describing the qfialification requirements for a variety of positions. The ANSI N18.1-1971 standard,
Selection and Training of Nuclear Power Plant Personnel, specifies minimum general qualifications
and specific education, training, and experience for all functional levels within an operating

 
 

 

 

 

 

65

Table 5.12. Staffing requirements for muitiple-unit nuclear steam-electric power plants

 

 

 

Plant size
1 unit - 2 units " 3 units 4 units

Plant management

Superintendent® 1 1 1 1

Assistant® 1 1 1 1

Clerks _ 5 5 5 5
Operations

Operations supervisors” 1 2 3 4

Shift supervisors” 6 6 12 12

Lead operators/foremen? 5 s 5

Control operators ' o 1n 16 26 31

Auxiliary operators 11 16 26 31

Lead fuel handlers/foremen® o 3 3 3

Fuel handlers 6 9 9
Technical

Technical supervisor 1 1 1 1

Professionals 6 9 12 12

Technicians 9 16 25 32
Maintenance

Maintenance supervisors 1 2 3 3

Crafts and repairmen 18 28 44 55
Security _ 11 16 16 16

Total ' 82 133 192 221

 

4Senior licensed operator qualifications.
bLicensed operator qualifications. _
€Special senior licensed operator qualifications.

Table 5.13. Staffing requirements for multiple-unit nuclear process steam plants

 

Plant size

 

 

1 unit 2 units 3 units 4 units
Plant management _
Superintendent® 1 1 1 1
Assistant? | 1 1 1
Clerks s 5 5 5
Operations '
Operations supervisors® 1 ) 3 4
Shift supervisors? 6 6 12 12
-Lead operators/fofemen" L 5 5 5
Control operators™ - . o1 16 26 k)
Auxiliary operators : 8 13 18 23
Lead fuel handlers/foremen® 3 3 3
Fuel handlers 6 9 9
Technical _ o
Technical supervisor 1 1 1 1
- Professionals 6 9 12 ‘12
Technicians 7 11 15 19
Maintenance = - :
" Maintenance supervisors 1 2 -3 -3
Crafts and repairmen ‘ 12 18 24 30
Security on 16 16 16
Total 71 115 154 175

 

4Senior licensed operator qualifications.
PLicensed operator qualifications.
€Special senior licensed operator qualifications.

 
 

 

 

66

organization that have a direct relatlonshlp to technical operatlonal and maintenance aspects of a
nuclear plant. . |

Figure 5.17 is a schedule for training senior operators and operators at the appropriate time.”
Other plant staff members new to the nuclear industry can benefit by participation in these programs
even though they will not need licenses.

Part of the training may be provided by reactor manufacturers, government agencies,
universities, or consultants. In general, most utilities provide their own design familiarization and

on-the-job training just prior to the initial fuel loading and power escalation program.

The typical schedule given in Fig. 5.17 assumes the individual has no prior knowledge of reactor
operations but has pertinent experience in steam plant operations. Trainees who already have or are
acquiring enough nuclear experience to qualify for the AEC license examinations prior to initial
operation of the station usually join the station staff group for further training and experience.

The training (for operators and staff) indicated in Fig. 5.17 is keyed to several dlfferent phases
considered standard.

Phase 1—Introduction to Nuclear Power. Participants receive instruction in basic nuclear
physics and mathematics refresher, reactor physics concepts (flux, reactivity, cross section), and
characteristics and operating behavior of power reactors.

Phase la—Demonstrations of Reactor Properties. A low-power research reactor is used in
conjunction with or immediately following phase 1.

Phase 2—On-Shift Participation. Extensive operative experience at a similar power reactor or a
combination of experience at a power reactor and a power reactor simulator serves both to give
experience and show the practical applications of theory learned.

Phase 3-—Design Familiarization. Lectures, together with study of plant systems and discussion
with various design groups at the nuclear steam supply system designer’s location, provide
familiarity with systems purpose and function.

Phase 4—On-the-Job Training. Details of the individual plant operation are learned by assisting
in the initial check-out, writing procedures, and operéting the various plant systems. In addition,

regularly scheduled training sessions should be directed toward design, nuclear characteristics,

operating procedures, and administrative controls.
Phase 5—Specialty Training. Specific job functions (e.g., radiation monitoring or instrument
maintenance) are generally taught at the appropriate time.

5.2.7 Downtime for Refueling and Other Maintenance

Most operating power reactors are refucled approximately once every year, with the first
refueling within 1 or 2 years after the start of commercial operation. Refuelmg is not necessarily, but
is invariably, accompanied by major maintenance outage.

A survey of the operating experience of ten reactors®® for the first half of 1973 shows that the
average downtime”” during refueling was about 62 days. The actual refueling time was
approximately 31 days. a

 

26. The reactors are Big Rock Point 1, Dresden 3, LaCfosse, Millstone Point I, Monticello, Nine Mile Point, Oyster
Creek, Point Beach 1, Robinson 2, and San Onofre.
27. T. R. Silson, M. 8. Hildreth, Jr., and G. C. Gower, Evaluation of Nuclear Power Plant Availability, OOE-ES-001

(January 1974),

 

 
 

- ORNL-DWG 74—'5678

 

" PLANT PROGRESS

YEARS BEFORE INITIAL CRITICALITY

GROUP INTERESTED

 

 

 

A 5 4 3 2

1. SUPERVISORY AND STATION TECHNICAL I THOSE WHO WILL PREPARE OPERATING
1572:: Elg:g'& , . PROCEDURES, AND TRAIN THE OPERATING

: CREWS . EVENTUALLY TO PROVIDE SENIOR
2. :fi;:gg‘:f“@" TO NUCLEAR POWER Q STAFF PERSONNEL FOR SUBSEQUENT POWER
3. DEMONSTRATION OF REACTOR PROPERTIES WILL OBTAIN ACC OPERATOR AND SENIOR

a)
4. ON-SHIFT PARTICIPATION 8:%13}3’“"“"553 PRIOR TO INMAL
(PHASE 2)
5. DESIGN FAMILIARIZATION (PHASE 3) - o
6. ON.-THE-JOB TRAINING (PHASE 4) S ]
7. SPECIALIST TRAINING {PHASE 5) o=
8. AEC LICENSING {COLD) ' _ :

' ?”22{‘3&?&:"“ | . o . OPERATING CREW CONTAINS THAT GROUP
2 STEaA DANT OPERATION . WHICH WILL OBTAIN AEC OPERATOR AND
3. INTRODUCTION TO NUCLEAH POWER o 2:’,','&'13’;5““"“ LICENSES AFTER INITIAL

- {PHASE 1) .

4. DEMONSTRATION OF REACTOR PROPERTIES

{PHASE 1a) :
5. DESIGN FAMILIARIZATION (ON- srre; O

{PHASE 3)
6. ON.THE-JOB TRAINING (PHASE 4)
7. ON-SHIFT. PARTICIPATION (PHASE 2) ~—
8. AEC LICENSING (HOT) x

 

 

 

 

 

 

 

 

* denotes a short period of 1 dey 10 2 weeks.

Boxes denote @ time period for specific training or experience.
Broken lines denote a flexible schedule within the indicated period before criticality.

Solid lines denote training by doing the job.

Fig. 5.17. Schedule for training and experience (from WASH-1130 Revised).

L9

 

 
 

 

 

 

68

During refueling, there is generally a radial reshuffling of the old fuel, and about one-third of
the fuel is replaced. Sometimes the utility does the refueling, and other times a vendor refueling crew
under contract to the utility performs the service.

The amount of operating experience data for LWR plants that is representative of current plant

designs and power levels is still somewhat limited. Although 27 nuclear plants were licensed to

operate by the end of 1972, only 8 of these plants had operatéd 4 years or longer. Five of these eight
‘had a design power rating of 200 MW(e) or less, and they were in effect one-of-a-kind plants.

A study of the 1972 operating records of 19 licensed nuclear power plants was conducted to
examine plant availability and to assess the nature, cause, and significance of plant shutdowns.”’” In
addition, the operating records for 4 of these plants were studied for the total perlod of commercial
operation to provide a broader time base for comparison.

The average nuclear plant availability during 1972 was 73%, where plant availability is defined
as the time the generator was in operation divided by the total tlme during the period. Of the 19
plants studied, 7 achieved availabilities of 80% or above.

The 4 plants for which operating records were analyzed over the total period of commercial
operation had an average plant availability of 72%. These plants had been in operation from 2 to 3
years. Analysis indicates that, on the average, a break-in period of from 3 to 4 years is required for a
nuclear plant to achieve an availability factor of 80% or above.

The average percent of forced and scheduled outage for the 19 plants during 1972 was 11 and
16% respectively. For the 4 plants with longer service time, forced outages accounted for 12% of the
time and scheduled outages for 16% of the time since they began operation. '

Five of the 19 nuclear plants had forced outage factors exceeding 15% in 1972. Equipment
malfunctions and failures were the cause of 96% of the forced outages, while operator errors were
responsible for 49,. _ .

Identification of the portions of the plant causing forced outages revealed that 429 of the total
was attributable to nuclear-related systems and components. However, the nuclear-related
equipment accounted for about 56% of the downtime, indicating that the time required to repair
nuclear equipment was somewhat greater than the time required to repair conventional equipment.

The major equipment items contributing to forced outages were valves, pump seals, turbines
and their associated auxiliaries, control rod drives and associated controls, main electrical
generators, steam generators, condensers, and feedwater system pumps and controls.

Each of the forced outages was classified with respect to its actual or potential safety
significance. Outages resulting in the release of radioactive effluents from the primary coolant
pressure boundary and those resulting in the actual or potential violation of the technical
specifications were considered to be of potential significance to public health and safety. Evaluation
of the forced outages on this basis indicated that about 46% might be construed to be related to
safety. However, none of the forced outages resulted in any injury to a member of the public or a
release of radioactive materials in excess of permissible levels. |

Scheduled outages for the 19 plants were responsible for the plants bemg shut down an average

- of 16% of the time. In 6 of the 19 plants, the operating time lost because of scheduled outages was

well in excess of this average value. Operating reports indicate that a significant amount of time was
devoted to overhaul and repair of control rod drives, steam generators, valves, and turbines. In
addition, a considerable amount of time was devoted to examination of reactor fuel.

 
 

 

69

5.2.8 Construction Schedule

Figure 5.18 shows in schematic form the major elements of lead time for a multiple-unit nuclear
power plant project from “commitment” to commercial operation. This schedule is modeled after
single-unit plant schedules developed by the Atomic Industrial Forum.? The time allowances are
typical of the present generation of custom-designed plants but include no provision for major
delays caused by strikes, contested hearings, or design revisions.

Line 1 shows a 4, year on-site- construction period for the first unit, followed by a 6-month
period of test operation before commercial operation. Normally, on-site construction cannot
commence until issuance of an AEC construction permit. The second, thlI‘d and fourth units are
placed in operation at l-year intervals.

Line 2 shows the related time scale for fabrlcatlon and dehvery of long lead-time items of
equipment, such as the pressure vessels steam generators, main coolant pumps, and the turbine
generators. Shop space must be reserved at least 6 months in advance of fabrication,
which in turn is estlmated to require 3 years for the first unit. These major items of equipment are
usually scheduled for on-site delivery about 2 years before completion of construction. To meet this
schedule, major financial commitments must be incurred about a year before the completion of
administrative reviews and the issuance of an AEC construction permit.

Line 3 shows the two phases of the AEC safety review leading to the issuance of a construction
permit and an operating license respectively. The preliminary safety analysis report should be filed 2
years prior to the issuance of a construction permit, allowing | y_ear for internal AEC staff review,
and 1 year for the hearing required at the construction permit stage. The final safety analysis report
should be filed 1", years prior to the estimated date for completion of construction, when an
operating license will be required to permit core loading and initial operation. This allows 1 year for
the internal AEC staff review and 6 months for a supplementary hearing.

Line 4 shows the antitrust review proceeding in parallel with the AEC safety review at the
construction permit stage. . .

Line S shows that all necessary environmental approvals, state and federal, must be obtained
through concurrent proceedings before all interested agencies, and that this process will proceed in
parallel with the AEC safety review over a 2-year period. Allowance is made for an additional 2
years of intensive effort prior to the filing of formal applications. It is assumed that the first year will
be devoted to obtaining and evaluating preliminary environmental data on several candidate sites

“and the second will be devoted to an in-depth study concentrated on the principal site selected.

Line 6 shows the contractual arrangements necessary to support this schedule. It is assumed
that an architect-engineer will be selected at the outset to assist in the preparation of invitations for
bids and in the preliminary evaluatlon of potentlal sites. This permits selection of a manufacturer
and identification of the size and characteristics of the plant during the year while alternative sites
are being evaluated and allows an additional year for detalled engmeenng and preparation of the
PSAR and other permit applications. -

~ The total lead time for the selec_tlon-licensing-eonstruction process, as shown in Figs. 5.18 and
5.19 for a single-unit custom-designed plant, requires about 9 years, divided roughly as follows: 2
years for site and plant design selection, preapplication site reviews, and preparation of the

 

28. Resource Needs for Nuclear Power Growth, A Report of an Ad Hoc Forum Committee Atomic Industrial Forum,
Inc., 1973.

 
 

€.

 

 

 

Years to commercial operation

First unit
Second unit
Third unit
Fourth unit

. On-site construction

. Long lead-time equipment

. AEC safety review

. Antitrust review

. Environmental review in parallel

with AEC safety.revim

Contractual arrangements

i Legend

i 2,

3

4,

Line
1.

On-site construction

Long lead-time equipment

AEC safety review

Antitrust review

ORNL-—-DWG 74-65679

 

 

 

 

Fig. 5.18. Estimated lead time for multiple-unit nuclear power plant project.

Antitrust issue resolved; CP issues.

9 8 7 6 5 4 3 2. 1 0
10 9 8 7 6 5 4 3 2 1 0
1" 10 9 8 7 6 - B 4 . 3 2 1 0
12 1 10 9 8 7 6 5 4 3 2 1 0
11 12 13 12 13 12 13 12 13
b 1 1.1 1 L1 J
21 22 23 23 23 23
i 1 ] 1 1 )
3 32 33 34 35 36 36 36 36
L ] ] ] | | ] | |
41 42 43
%
51 52 53 54 85
L | ] ] }
61 62 63 64
11:  Construction permit issues, commence 5.  Environmental review 81: Environmental evaluation of candidate
" on=-site construction, sites. -
12: Construction complete, commence test 62: Selection of principal site, in-depth
operation, environmental evaluation; prepare
13: Commercial operation. environmental reports, all necessary state
. and federal applications.
21: Reserve shop space. 53: File applications.
22: Commence shop fabrication. 54: Hearings.
23:  Delivery of equipment at site §5: Al necessary environmental approvals,
permits, certifications issue concurrently
31: File PSAR, commence AEC staff review. with AEC construction permit.
32: CP hearing. ' . .
33: Construction permit issues. 6. . Contractual arrangements . 61:  Engage architect-engineer, invite bids.
34: File FSAR, AEC staff review. ‘ 62: Select manufacturer, determine size and
35: OL hearing, if required. type of reactor, establish detailed
36: Operating license issues. working arrangements, .
63: Detailed engineering, prepare PSAR and
41:  Applicant supplies required information, environmental applications.
commence review by AEC and 64: File PSAR and environmental
Department of Justice. applications.
:g: Hearing, if required.

0L

 

 
 

71

application; 2 years for construction permit reviews and hearings; and 5 years for construction,
operating license review, and operational testing.

As also shown in Fig. 5.19, standardization of plant designs in the next 3 to 4 years might make
possible a reduction of about 2 years in the total lead time.”” It is anticipated that about a year can
be saved from the time required for AEC review of the construction permit application, and, as

experience is gained in duplicating major portions of plants, it should be possible to reduce the
required construction time by a year.

ORNL-DWG 74--5680

 

 

 

 

 

 

 

 

 

 

 

    
 
 

 

 

 

1

PRESENT CYCLE: JSELECT SITE

CUSTOM PLANTS -l CONSTRUCTION ___ San+| 5.10 YEARS
PLANT <

cp o. |
APPLICATION REV/EW | REVIEW
SELECT SITE
NEAR TERM:
STANDARDIZED |SELECT CONSTRUCTION
pLaNts  leans 78 YEARS
cP

APPLICATION REV/EW REVIEW

 

 

Fig. 5.19. Estimated saving in lead time due to standardization.”

5.2.9 Economic Analysis

| Productlon costs were estlmated for large- and 1ntermed1ate-s1ze commercral nuclear electnc
plants and process steam plants in accordance with the economic ground rules shown in Tables 5.14
and 5.15. The estimates for large plants are for single units only, while the estlmates for the
intermediate-size plants are for one-, two-, three-, ‘and four-umt plants. In all cases the length of the
design and construction penod was held constant, although it could be argued that the construction
period for the smaller plants might be somewhat shorter. The fuel cycle costs for the
intermediate-size plants were assumed to be about l¢ to 2¢/10° Btu higher than

“those for the large plants.

- Table 5.16 shows a breakdown of the levelized fixed charge rates used in estimating the annual

fixed charges on capltal investment. The POWERCO code® was used to perform the drscounted

 

29, Meeting the Challenge to Nuclear Energy l-lead-On, Remarks by William O. Doub, Commissioner, U.S. Atomic
Energy Commission, Atomic Industrial Forum Annual Conf., San Francisco, Calif., Nov, 12, 1973.

30. Royes Salmon, A Revision of Computer Code POWERCO (Cost of Electricity Produced by Nuclear Power
Stations) to Include Breakdowns of Power Cost and Fixed Charge Rates, ORNL-4116 (August 1969).

 
 

72

Table 5.14. Economic ground rules for large commercial nuclear plants

 

Type PWR, BWR, and HTGR

Environmental systeni ' ' - All electric power plants use mechanical
- . draft evaporative cooling towers

Size (single unit) - ‘ -
LWR | 1200 MW(e), 3750 MW(t)

HTGR » 1200 MW(e), 3140 MW(t)
Net efficiency :
LWR ' : 32% (10,660 Btu/kWhr)
HTGR . 38.2% (8930 Btu/kWhr)
Capacity factor 80%
Location ' Texas
Design and construction period 8!/, years from purchase of nuclear steam system
- Workweek ~ 40hr o
Cost basis Early 1974 dollars; interest during construction
included in capital costs”
Fuel cycle costs (mid-1982) (¢/10° Btu) Utility Industrial
LWR | 28 34
HTGR _ 31 40
Financial parameters, % Utility Industrial
Fraction of investment in bonds 55 30
Interest rate on bonds 8 8
Return on equity 10 15
Federal income tax rate 48 ‘48
State income tax rate 3 3
Gross revenues tax rate 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

 

9No allowance for escalation during construction.

cash flow and levelizing calculations for the fixed charge rates. The higher fixed charge rate for
industrial ownership resuits from (1) the shorter lifetime, 20 years compared with 30 years for utility
ownership; (2) the lower bond fraction, 30% compared with 55%; and (3) the higher seturn on
equity, 15% compared with 10%. For property tax purposes the investment is deprecxated uniformly
and for income tax purposes by the sum-of-years digits method.

A different set of economic ground rules, especially the financial parameters, would result in a
different set of production costs and a different set of relative costs.

Large nuclear plants

Production costs for large commercial nuclear electric plants are summarized in Table 5.17 for
typical utility and industrial financing assumptions. For the three types of reactors (PWR, BWR,
and HTGR), total production costs are about equal—slightly over 11 mnlls/ kWhr for utility
ownership and just under 17 mills/kWhr for industrial ownership. ,

Production costs for large commercial nuclear plants producing only process steam are
summarized in Table 5.18 for typical utility and industrial financing. Total prime steam production

 
 

 

 

73

Table 5.15. Economic ground rules for intermediate-size commercial nuclear plants

 

Type

~ Environmental system

Unit size
PWR -
HTGR

Net efficiency
PWR
HTGR

Capacity factor
Location

Design and construction period

Workweek

Cost basis

Fuel cycle costs (mid-1982)
(¢/10° Btu)

PWR
HTGR

Financial parameters, %

Fraction of investment in bonds
Interest rate on bonds

Return on equity

Federal income tax rate

State income tax rate

Gross revenues tax rate

Local property tax rate

Interim replacements rate
Property insurance rate

Plant lifetime, years

PWR and HTGR

All steam-electric plants use mechanical draft
evaporative cooling towers

600 MW(e), 1875 MW(t)
382 MW(e), 1000 MW(1)
764 MW(e), 2000 MW(1)

32% (10,660 Btu/kWhr)
38.2% (8930 Btu/kWhr)

80%
Texas .

81/2 years from purchase of nuclear steam
systems to commercial operation of first unit;
additional units to be placed in operation
at 1-vear intervals

40 hr

Early 1974 dollars; interest during construction
included in capital costs; no allowance for
escalation during construction

Utility Industrial
29 36
36 46 [1000 MW(t)]
33 42 [2000 MW(1)]
Utility Industrial
55 30
8 8
10 15
48 48
3 3
0 0
3 3
0.35 0.35
0.25 0.25
30 20

 

Table .5.16_; Brezkdown of levelized fixed charge rates (%)

 

 

 Utility "Industrial
Recovery of capital R L
- Average interest rate 8.90 12.90
Sinking fund depreciation 075 - 1.25
" . Federal income tax - 142 . 504
State income tax 009 032
“Local property tax 213 2.13
Interim replacements . 0.35 S 0438
Property insurance 0.25 0.25
Total fixed charge rate 13.9 22.2

 

 
 

 

 

74

Table 5.17. Summary of levelized production costs for large
commezcial nuclear electric power plants

 

PWR ' BWR HTGR
10° $/year  mills/kWhr  10° $/year  mills/kWhr  10° $/year  mills/kWhr

 

 

 

 

 

 

 

 

Utility ownership
Fixed charges 65.9 7.84 65.9 7.84 66.6 7.92
O&M costs 5.2 0.62 5.2 0.62 54 0.64
Fuel costs - 25.1 299 25.1 2.99 23.2 2.76
Total 96.2 11.4 96.2 11.4 95.2 11.3
Industrial ownership
Fixed charges 105.2 12.51 105.2 12.51 106.3 12.64
O&M costs 5.2 0.62 5.2 0.62 54 0.64
Fuel costs 30.5 ‘ 3.63 30.5 3.63 30.0 3.57
Total 1409 16.8 140.9 16.8 141.7 - 168
Table 5.18. Summary of levelized production costs for large
commercial nuclear process steam plants
3750 MW(t) PWR 3750 MW(1) BWR 3140 MW(t) HTGR
10° $/year  ¢/10°Btu  10° $/year  ¢/10°Btu  10° $/year  ¢/10° B
Utility ownership . '
Fixed charges 37.2 42 35.9 40 39.9 53
O&M costs 3.7 4 3.7 4 3.8 5
Fuel costs 25.1 28 25.1 28 23.2 31
Total 66.0 74 66.0 72 66.9 89
Industrial ownership :
Fixed charges 59.5 66 57.3 64 - 63.7 85
O&M costs 3.7 4 3.7 4 3.8 5
Fuel costs 30.5 34 305 34 30.0 40
Total 93.7 104 91.5 102 97.5 130

 

costs are about equal for PWR and BWR plants, just over 70¢/ 10° Btu for utility ownership and just
over $1.00/10° Btu for industrial ownership. Total prime steam production costs are about 25%
higher for the HTGR plant, almost 90¢/10° Btu for utility ownership and almost $1.30/10° Btu for
industrial ownership. These higher costs for the HTGR reflect the higher capital cost of the HTGR
nuclear steam system. However, it should be kept in mind that the steam is of higher quality, 2500
psi and 515°C (955°F), when compared with ~1000 psi saturated steam for LWRs.

The capital cost breakdowns are summarized in Tables 5.19 through 5.21. Total capital costs for
the three electric plants are essentially equal, about $400/kW(e). As shown in Table 5.21, the higher
cost of the HTGR nuclear steam plant is balanced by the lower cost of its turbine plant. The process
steam plant costs do not include costs for reboilers and other equipment required for steam
distribution. Reboilers would most likely be required for all types of reactor plants, especially for the
BWR plant, to protect the steam distribution system from possible radioactive contamination and

 
 

75

Table 5.19. Capital cost estimate for 1200-MW(e) PWR steam-electric plants

 

Steam plant Turbine plant Total

 

_ Direct costs (16° $)

Land and land rights 1 0 1

Physical plant '
Structures and site facilities 39 : 8 47
Reactor plant equipment 87 0 87
Turbine plant equipment 0 88 88
Electric plant equipment 15 14 29
Miscellaneous plant equipment 3 _2 s
Subtotal (physical plant) 144 112 256
Spare parts allowance 1 1 1
Contingency allowance __1_0 __7 _11
Subtotal (total physical plant) 155 120 275

Indirect costs (10° $)
Construction facilities, equipment, and services 10 8. 18
Engineering and construction management services 25 19 44
Other costs 8 6 14
Interest during construction : _69 33 122
Subtotal (indirect costs) 112 86 198
Total costs

Total plant capital cost at start of project
‘Millions of dollars 268 206 474
Dollars/kW(e) 395

Dollars/103 Btu/hr : 21

 

also to protect the nuclear system from industrial contamination. Capital costs for LWR
steam-electric plants were estimated with an updated version of the CONCEPT code.” This
updated version includes costs of all environmental and safety-related equipment and systems
required as of early 1973. Cap1tal costs for HTGR steam-electric plants were extrapolated from
those reported in WASH-1230 for a 770- MW(e) plant.*? Capital costs for the nuclear process steam
plants were developed by appropriate modification of the electric plant estimates.

Tables 5.22 and 5.23 show estimated annual operation and maintenance expenses; not including
fuel, for nuclear electnc plants and process steam plants respectwely The costs for electric plants
were estimated using the methods outlined by Myers,” and the process steam plant costs were
estamated by approprlate modxficatlon of the electric p}ant estimates.

Intermediate-size nuclear plants

Production costs for intermediate-size commercial nuclear electric plants are summarized in
Tables 5.24 through 5.26 for single- and multiple-unit stations operating at 80% plant capacity

 

31 H. I Bowers et al,, C ONCEPT—Computenzed Conceptual Cost Est:mates fi)r Steam-Electric Power Plants— Phase
I User's Manual, ORNL-4809 (April 1973).

32. 770-MW(e) Central Station Power Plants Investment Cost Study—High Temperature Gas—Cooled Reactor Plant,
WASH-1230, vol. V1 (1974).

33. M. L. Myersand L. C. Fuller, Operating and Maintenance Cost Estimating Procedure for Steam-Electric Power Plants
(to be published).

 
 

 

 

 

76

Table 5.20. Capital cost estimate for 1200-MW(e) BWR steam-electric plants

 

 

Steam plant Turbine plant Total

Direct costs (10° §)

Land and land rights 1 0 1
Physica!l plant
Structures and site facilities 35 12 47
Reactor plant equipment 86 0 86
Turbine plant equipment 0 88 88
Electric plant equipment : 15 15 : 30
Miscellaneous plant equipment 3 ' 2 _5
Subtotal (physical plant) : 139 117 256
Spare parts allowance 1 1 2
Contingency allowance 9 _ 8 17
Subtotal (total physical plant) 149 126 - 275
Indirect costs (10° $)
Construction facilities, equipment, and services 10 o 8 , 18
Engineering and construction management services 24 20 : 44
Qther costs _ 8 6 14
Interest during construction 66 36 122
Subtotal (indirect costs) 108 90 198
Total costs
Total plant capital cost at start of project ,
Millions of dollars 258 216 474
Dollars/kW(e) 395
Dollars/103 Btu/hr 20

 

factor. Single-unit plants show a cost of about 1 mill/kWhr higher than multiple-unit plants for the

same type of reactor. Total unit costs for the 764-MW(e) HTGRs are estimated to be about !

mill/ kWhr lower than those for comparable 600-MW(e) PWRs, and the 382-MW(e) HTGRs have
total production costs about 3 mills/ kWhr higher t_hah comparable 765-MW(e) HTGRs.

Production costs for intermediate-size nuclear plants producing only process steam are
summarized in Tables 5.27 through 5.29. Total prime steam production costs for PWRs are
estimated to range from 82¢ to 89¢/10° Btu for utility ownership and $1.19 to $1.28/10° Btu for
industrial ownership, which compares with 94¢ to $1.03/10° Btu and $1.37 to $1.50/ 10° Btu for the
2000-MW(t) HTGRs and $1.16 to $1.34/10° Btu and $1.71 to $1.96/10° Btu for the 1000-MW(t)
HTGRs. Again the higher costs of process steam from the HTGR reflect the higher capital cost of
the HTGR nuclear steam system. The unit costs for the intermediate-size systems are 20 to 30%
higher than those for the large nuclear systems, mainly because of the unfavorable scaling effects in
capital costs and operation and maintenance costs for the smaller reactors.

The estimated capital cost breakdowns are summarized in Tables 5.30 to 5.32 for nuclear
electric plants and in Tables 5.33 to 5.35 for nuclear process steam plants. It is estimated that a
four-unit electric plant would cost in the neighborhood of $1 billion not including escalation during
construction, which at present rates would add another 30% to the plant capital cost. Estimated
capital costs for the four-unit process steam plants range from $500 million to almost $800 million.

 
 

77

Table 5.21. Capital cost estimate for 1200-MW(e) HTGR steam-electric plants

 

 

Steam plant Turbine plant Total
Direct costs (10° $)
Land and land rights 1 0 1
Physical plant
Structures and site facilities 49 6 55
Reactor plant equipment 91 0 91
Turbine plant equipment 0 81 81
Electric plant equipment 13 13 26
Miscellaneous plant equipment _3 3 6
Subtotal (physical plant) 156 103 259
Spare parts allowance - 1 v 1 2
Contingency allowance __1_9_ 7 17
Subtotal (total physical plant) ' 167 111 278
Indirect costs (106 $)
Construction facilities, equipment, and services 11 7 18
Engineering and construction management services 26 18 44
Other costs 8 6 14
Interest during construction 11 50 124
Subtotal (indirect costs) 119 81 200
| Total costs
Total plant capital cost at start of project '
Millions of doBars 287 192 479
Dollars/kW(e) ' 399
Dollars/10? Btu/hr | 27

 

Table §.22, Annual operation and maintenance costs for
large nuclear electric plants (10 $)

 

 

LWR . HTGR
Fixed costs . . ,
Staff ' . 1.66 : 1.66 -
Maintenance 132 1.34
Supplies and expenses - 0.26 - 035
.- -Insurance and fees - 059 055
* Administrative and general C 042 044
Total fixed costs : 425 434
_ Variable costs? _ : o _
Maintenance 0.53 - 0.51
* Supplies and expenses 045 - 0.50
Total variable costs - - 098 1.01
Total annual O&M costs 5.2 54

 

' “SO%VpIant capacity factor.

 
 

78

Table 5.23. Annual operation and maintenance costs for
large nuclear process steam plants (105 $)

 

 

LWR HTGR

Fixed costs

Staff 1.50 1.50

Maintenance 0.75 0.71

Supplies and expenses 0.16 - 0.21

Insurance and fees 0.59 0.55

Administrative and general 0.28 0.30

Total fixed costs 3.28 3.33
Variable costs?

Maintenance 0.25 0.26

Supplies and expenses 0.16 0.21

Total variable costs 0.41 0.47
Total annual O&M costs 3.7 38

 

280% plant capacity factor.

Table 5.24. Summary of levelized production costs for multiple-unit [600-MW(e)] PWR steam-electric plants

 

1-Unit station 2-Unit station 3-Unit station 4-Unit station
10 $/year mills/kWhr 10% $/year mills/kWhr 10° $/year mills/kWhr 10° $/year mills/kWhr

 

Utility ownership

Fixed charges 42.1 10.0 79.1 9.4 117.5 9.3 157.3 93
O&M costs 4.1 1.0 6.5 0.8 89 0.7 11.2 0.7
Fuel costs 13.2 31 264 341 396 31 52.8 31
Total 594 14.1 112.0 13.3 166.0 131 221.3 131
Industrial ownership

Fixed charges 67.3 16.0 126.3 15.0 187.6 149 251.3 149

- O&M costs 4.1 1.0 6.5 0.8 8.9 0.7 11.2 0.7
Fuel costs 159 3.8 318 38 47.7 38 63.6 38
Total - 87.3 20.8 164.6 19.6 2442 19.4 326.1 194

 

 

Table 5.25. Summary of levelized production costs for multiple-unit [764-MW(e)] HTGR steam-electric plants

 

1-Unit station 2-Unit station 3-Unit station 4-Unit station

 

10% $/year mills/kWhr 10° $/year mills/kWhr 10°% $/year mills/kWhr 10° $/year mills/kWhr

 

Utility ownership
Fixed charges 49.5 9.2 91.9 8.5 136.1 8.5 182.1 8.5
Q&M costs 49 09 7.5 0.7 10.2 0.6 12.8 0.6
Fuel costs 15.6 29 31.2 _29 468 _29 62.4 29
Total 70.0 13.0 130.6 12.1 193.1 120 257.3 12.0
Industrial ownership _ _
Fixed charges 79.0 148 146.7 13.7 2173 13.5 290.8 13.8
O&M costs 49 0.9 7.5 0.7 10.2 0.6 12.8 0.6
Fuel costs 20.1 fl 40.2 ' _3__8_ 60.3 fi 80.4 _38
Total 104.0 19.5 194.4 18.2 287.8 17.9 384.0 18.2

 

 
 

 

 

79

Table 5.26. Summary of levelized production costs for multiple-unit [382-MW(e)] HTGR steam-electric plants®

 

_ 1-Unit station ~ 2-Unit station 3-Unit station 4-Unit station
10° $/year mills/kWhr 10° $/year mills/kWhr 10° $/year mills/kWhr 10° $/year mills/kWhr

 

 

Utilify ownershfp , _ : o
Fixed charges 324 12.1 58.7 11.0 858 107 1129 10.5
O&M costs 3.6 1.3 53 1.0 71 09 89 0.8
Fuel costs 8.6 3.2 17.2 3.2 25.8 32 344 32
Total 44.6 16.6 81.2 15.2 118.7. 14.8 156.2 14.5
Industria! ownetshii: : : ‘ ' ‘
Fixed charges 51.7 19.3 - 93.7 175 137.0 17.1 180.3 16.8
O&M costs 3.6 1.3 5.3 1.0 7.1 0.9 89 0.8
Fuel costs 11.0 4.1 220 4.1 33.0 4.1 44.0 4.1
Total 66.3 24.7 1216 226 177.1 22.1 266.2 21.7

 

9Extrapolated from 770-MW(e) commercial plants.

Table 5.27. Summary of levelized production costs for multiple-unit [1875-MW(e)] PWR process plants

 

1-Unit station = - 2-Unit station ~3-Unit station 4-Unit station
10% §/year ¢/10° Btu 10° $/year ¢/10° Btu 10° $/year ¢/10° Btu 10° $/year ¢/10° Btu

 

 

Utility ownership
Fixed charges 24.2 - 54 45.3 -3 | 67.3 50 89.8 50
O&M costs 2.8 6 4.2 5 5.0 4 6.1 3
- Fuel costs 132 29 . 264 29 39.6 29 52.8 29
Total 40.2 89 759 85 1119 83 148.7 82
Industrial ownership 7 _ ' -
Fixed charges 38.6 - 86 72.4 81 107.4 80 1434 80
O&M costs 2.8 6 42 5 50 4 6.1 3
Fuel costs 159 _36 318 _36 47.7 36 63.6 _36
Total 57.3 128 108.4 122 160.1 120 213.1 119

 

»

!

Table 5.28. Summary of levelized production costs for multiple-unit [2000-MW(t)] HTGR process steam plants

 

* 1-Unit station . 2-Unit station 3-Unit station 4Unit station

10 $/year ¢/10° Btu 10° $/year ¢/10° Btu 10° $/year ¢/10° Btu 10° $/year ¢/10° Btu

Utility ownership ' ' ' .
Fixed charges 30.2 63 ~ 553 . 58 816 57 109.1 57
O&M costs 33 7 438 5 64 4 79 4
Fuel costs 156 33 312 33 468 33 624 33

Total 49.1 103 913 9% 134.8 9 1794 94

Industrial ownership S o : _ - S
Fixed charges’ 482 101 884 92 1303 91 1743 91
O&M costs - 33 7 48 5 6.4 4 19 4
Fuel costs 20.1 42 40.2 _42 60.3 42 80.4 42

Total 1.6 150 133.4 139 197.0 137 262.6 137

 

 
 

Table 5.29. Summary of levelized production costs for multiple-unit [1000-MW(t)] HTGR process steam plants

80

 

1-Unit station

2-Unit station
10° $/year ¢/10° Btu 10° $/year ¢/10° Btu 10° $/year ¢/10° Btu 10° $/year ¢/10° Btu

3-Unit station

4-Ynit station

 

 

 

 

Utility ownership - , o
Fixed charges 20.6 86 36.2 76 53.2 74 71.2 74
O&M costs 2.8 12 3.7 8 4.8 7 6.1 6
Fuel costs 8.6 36 17.2 fi 258 36 344 36

Total 32.0 134 571 120 838 117 111.7 116

Industrial ownership
Fixed charges 329 138 57.9 121 85.0 119 113.7 119
O&M costs 2.8 12 - 3.7 8 4.8 7 - 6.1 6
Fuel costs . 11.0 46 22.0 46 33.0 46 440 46

Total 46.7 196 83.6 17§ 112.8 172 163.8 171
Table 5.30. Capital cost estimates for 600-MW(e) PWR steam-electric plants
1-Unit 2-Unit 3-Unit 4-Unit -
station station station station
Direct costs (10° §)
Land and land rights 1 1 1 1
Physical plant
Structures and site facilities 27 50 72 94
Reactor plant equipment 57 113 170 226
Turbine plant equipment 5] 100 150 200
Electric plant equipment 19 36 52 68
Miscellaneous plant equipment _8 1 10 _12
Subtotal (physical plant) 158 306 454 600
Spare parts allowance 1 2 3 4
Contingency allowance _10 _20 _29 _39
Subtotal (total physical plant) _ 169 328 486 643
Indirect costs (l()6 $
Construction facilities, equipment, and services 13 20 27 35
Engineering and construction management services 31 50 70 90
Other costs 10 16 22 28
Interest during construction _19 154 239 335
Subtotal (indirect costs) 133 240 358 488
Total costs
Total plant capital cost at start of project
Millions of dollars 303 569 845 1132
Dollars/kW 505 474 469 472

 

 

 

 
 

81

Table 5.31. Capital cost éstimates for 764-MW(e) HTGR steam-electric plants

 

 

 

 

 

1-Unit 2-Unit 3-Unit 4-Unit
station station station station
Direct costs (106 %)
Land and land rights 1 1 1 1
Physical plant
Structures and site facilities 38 67 96 126
Reactor plant equipment 69 133 197 261
Turbine plant equipment ‘ _ 56 111 166 220
Electric plant equipment 20 k] - 54 70
Miscellaneous plant equipment o : 6 8 _14 _18
Subtotal (physical plant) 189 357 527 695
Spare parts allowance 1 2 4 5
Contingency allowance . 13 _gi _Z_ii 45
Subtotal (total physical plant) 203 383 565 745
Indirect costs (10° §)
Construction facilities, equipment, and services 14 23 31 40
Engineering and construction management services - 34 51 80 104
Other costs 11 18 25 32
Interest during construction __9_3_ l:l_?_ 2717 388
Subtotal (indirect costs) . 152 277 4 13 564
Total costs
Total plant capital cost at start of project
Millions of dollars ' 356 661 979 1310
Dollars/kW ' . 465 432 427 429
Table 5,32, Capital cost estim:_ntes for 382-MW(e) HTGR steam-electric plants
1-Unit 2-Unit 3-Unit 4-Unit
station station station station
Direct costs (10° §)
Land and land rights _ 1 1 1 1
Physical plant
Structures and site facilities 22 38 55 73
Reactor plant equipment _ , 46 88 ‘130 172
Turbine plant equipment : . 32 64 95 116
Electric plant equipment 13 24 - 36 47
Miscellaneous plant equipment 4 -8 10 - 14
Subtotal (physical plant) - : 117 222 326 422
Spare parts allowance : 1 2 2 ~ 3
Contingency allqwanoe - . _-_8 15 _2_1_ ' 28
Subtotal (total physical plant) . 126 239. 349 453
*Indirect costs (10° $)
Construction facilities, equipment, and services . S11 16 21 26
Engineering and construction management services 25 - 39 - 53 67
Other costs : ' 8 12 17 21
Interest during construction . 62 115 176 244
Subtotal (indirect costs) : 106 182 1267 358
Total costs
Total plant capital cost at start of project : :
Millions of dollars 233 422 617 812
Dollars/kW 610 552 538 531

 

 
 

 

82

Table 5.33. Capital cost estimates for 1875-MW(t) PWR process steam plants

 

 

 

 

 

1-Unit 2-Unit 3-Unit 4-Unit
station station station station
Direct costs (10° $)
Land and land rights 1 1 1 1
Physical plant
Structures and site facilities 22 41 59 77
Reactor plant equipment 57 113 170 226
Turbine plant equipment 0 0 0 0
Electric plant equipment 9 18 26 34
Miscellaneous plant equipment 2 4 5 6
Subtotal (physical plant) 90 176 260 343
Spare parts allowance 1 1 2 2
Contingency allowance _6 11 17 22
Subtotal (total physical plant) - 97 188 .279 367
Indirect costs (10° $) | .
Construction facilities, equipment, and services 7 11 15 20
Engineering and construction management services 18 29 40 51
Other costs - 6 9 13 16
Interest during construction 45 88 136 191
Subtotal (indirect costs) : 76 137 204 278
Total costs
Total plant capital cost at start of project .
Millions of doliars 174 326 484 646
Dollars/10° Btu/hr 27 25 25 25
Table 5.34. Capital cost estimates for 2000-MW(t) HTGR process steam plants
1-Unit 2-Unit 3-Unit 4-Unit
station station station station
Direct costs (10° $)
Land and land rights 1 1 1 1
Physical plant
Structures and site facilities 34 60 85 111
Reactor plant equipment 69 133 197 261
Turbine plant equipment 0 0 0 0
Electric plant equipment 10 19 27 35
Miscellaneous plant equipment _3 _4 _1 _9
Subtotal (physical plant) 116 216 316 416
Spare parts allowance 1 1 2 3
Contingency allowance _8 _14 20 _27
Subtotal (total physical plant) 125 231 338 446
Indirect costs (10° $)
Construction facilities, equipment, and services 8 14 19 24
Engineering and construction management services 20 34 48 62
Other costs 1 11 15 19
Interest during construction 36 107 166 233
Subtotal (indirect costs) 91 166 248 338
Total costs
Total plant capital cost at start of project
Millions of dollars : 217 398 587 785
Dollars/103 Btu/hr 32 29 29 29

 

 
 

 

 

83

Table 5.35. Capital cost estimates for 1000-MW(t) HTGR process steam plants

 

1-Unit 2-Unit 3-Unit 4-Unit
station station station station

 

Direct costs (10° $)

Land and land rights _ 1 1 1 1
Physical plant ,,
Structures and site facilities 20 34 49 64
Reactor plant equipment o . 46 - . 88 130 172
Turbine plant equipment 0 0 0 0
Electric plant equipment 6 12 18 23
Miscellaneous plant equipment _g __{ _5 _7
Subtotal (physical plant) 74 - 138 202 266
Spare parts allowance IR | 1 ' 1 2
Contingency allowance _ 3 9 _13 _18
Subtotal (total physical plant) 80 148 216 286
Indirect costs (10° $)
Construction facilities, equipment, and services 7 10 13 16
Engineering and construction management services 16 24 33 42
Other costs : : : 5 7 11 13
Interest during construction 4 . . 2 ___'_7_1_ 109 __1_5_4_
Subtotal (indirect costs) 67 112 166 225
Total costs
Total plant capital cost at start of project _
Millions of dollars 148 261 383 512
Dollars/10° Btu/hr 43 38 37 38

 

The process steam plant costs do not include costs for reboilers and other equipment required for
steam distribution. Capital costs for PWR steam-electric plants were estimated with the updated
version of the CONCEPT code.’' Capital costs for HTGR steam-electric plants are based on those
reported in WASH-1230 for a 770-MW(e) plant.*® Capital costs for the nuclear process steam plants
were developed by appropriate modification of the electric plant estimates. Since a 1000-MW(t)
HTGR is not commercially available, costs were extrapolated from the 2000-MW(t) HTGR
estimates. : B '

Tables 5.36 to 5.41 show the estimated annual operation and maintenance expenses, not
-~ including fuel, for both nuclear electric plants and process steam plants. The costs for electric plants
~ were estimated using the methods outlined by Myers,”®> 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

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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-<consuming
industries. _

No detailed assessment has been made of the number of potential industries located near
waterways or of the associated power requirements. It is believed that a more detailed analysis
would show a potential market sufficient to absorb the output of several facilities set up specifically
for the series production of small platform-mounted reactors.

The applicability of floating nuclear industrial energy sources will also be circumscribed by the
population distribution near potential operating sites. It is expected that the population separation
distance requirements for a barge-mounted unit would be about the same as those for a land-based
plant; thus the discussion of nuclear siting in later sections also appligs to the floating reactor
concept.

Platform description

The general arrangement of a platform-mounted 313-MW(t) [91-M W(e)] CNSG reactor plant is
depicted in Fig. 5.30. This configuration, designed for plant operation in a floating condition, forms
the base case for the plant arrangement and cost studies. However, design modifications for placing
the platform on a permanent dry foundation, as well as plants designed for the production of
process steam only, were also studied.*®

The major components of the nuclear steam supply system are identical to those of the
land-based concept described previously. The turbogenerator was also assumed to be the same as for
the land-based plant; however, the secondary plant auxiliaries (such as the condenser, circulating
pumpé, diesel generators, electrical gear, and fluid-handling systems) satisfy shipboard requirements.

The heavy reactor installation is located near the center of the barge, with the spent-fuel pit and
the turbogenerator at opposite ends, thus tending to balance out the individual effect on hull trim
(see Fig. 5.31). Similar to the arrangement of the land-based concept, a reactor building provides

 

46. Bridges over Navigable Waters of the United States, Gulf and Mississippi, U.S. Coast Guard Department of
Transportation, CG-425-2 (Oct. 15, 1971).

47. Light List, Mississippi River System of the United States, Department of Transportation, Sccond Coast Guard
District, CG-161, Corrected to Jan. 1, 1974, U.S. Government Printing Office, Washington, D.C., 1974.

48. Barge Mounted Nuclear Power Plant Study, prepared by G. G. Sharp, Inc., Marine Systems Analysis and Design,
100 Church Street, New York, N.Y. 10007, for the Oak Ridge National Laboratory, June 28, 1974,

49. The Intracoastal Waterway, Atlantic Section, U.S. Army Corps of Engineers, 1961, U.S. Government Printing
Office, Washington, D.C.

. 90. The Intracoastal Waterway, Part I, Gulf Section, U.S. Army Corps of Engmeers, 1951, U.S. Government Printing
Office, Washington, D.C. ,

 
ORNL-DWS 74-5778

 

 

105

     

e
I

 

125-ton CRANE .‘
5 SPENT FUEL STORAGE AND SHIPPING PIT

6 REACTOR BUILDING

7 AIR LOCK

1 CIRCULATING SYSTEM DISCHARGE

2 75-ton CRANE

3 VESSEL HEAD STORAGE

4

 
 

N

Vi

 

9 PRESSURE SUPPRESSION POOL

10 91-MWi(e) TURBINE-GENERATOR

 

8 DEMINERALIZER

REACTOR

2 PRIMARY CONTAINMENT

       

  

6 CIRCULATING SYSTEM INTAKE

7 MOORING CABLES

5 STEEL BARGE

Fig. 5.30. Platform-mounted 313-MW(t) nuclear steam supply with 91-MW(e) turbogenerator.

 

 

 

 

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106

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Fig. 5.31. Arrangement of platform-mounted 313-MW(t) [91 MW(e)] CNSG reactor.
 

 

 

107

secondary containment -around the CNSG pressure-suppression primary containment. The building
also houses the reactor auxrhary systems, laboratory spaces, the reactor control room, the
radioactive waste systems, and the spent-fuel handling system. . : '

The turbogenerator is mounted outdoors on the main deck, an arrangement suitable for a warm
climate. The generator is protected by electrical switchgear mounted on the barge; however, the
switchyard was assumed to be located on shore. The main condenser is arranged in the hull
immediately below the turbine. Circulating water enters the hull through a submerged sea chest in
the barge end; the circulating system discharge pipe passes through the barge side to remove the
condenser waste heat. The bulk of the power-conversion system auxiliaries are located in the hull
compartments under the turbogenerator. A bllge-and-ballast system is required for maintaining hull
trim. :
Hull beam was limited to 105 ft in order to allow passage through the 110-ft-wide locks
commonly used on inland waterways. A barge length of 320 ft was required in order to minimize
fore and aft trim under operating conditions.

The draft during the tow to the operating site can be limited to less than Il ft by deferring the
installation of the concrete for the reactor shield and spent-fuel pit until after the barge is emplaced.
The total weight of the complete unit is about 20,000 tons, corresponding to a draft of 20 ft.
Preliminary stability calculations showed that wind loads produce quite moderate angles of hull
indication; the angle of heel for a 180-mph wind would be about 4°. The correspondmg value for a
300-mph wind is 11°.

For operation afloat the barge may have to meet the U.S. Coast Guard requirements’ for
nuclear ships. Thus the hull is designed to withstand the flooding of any two compartments without
sinking. Experience with the U.S. Maritime Administration layup'fleet in fresh and brackish water
has shown that hull corrosion can be controlled with cathodic protection systems, and the use of
such a system will obviate the need for periodic drydocking to carry out hull maintenance. A hull
constructed of concrete would have superior corrosion resistance; however, the hull weight could
increase by as much as 3000 to 4000 tons. Because of the limitations on draft and beam, the heavier
concrete. barge would have to be con51derably longer than a steel hull, resultmg in higher capital
costs. : .
A platform—mounted umt for the productlon of process heat only could be shortened to 260 ft, a
reduction of 60 ft, because of the absence of the turbogenerator and its auxiliaries.

A barge hull designed for emplacement on a dry foundation will be less costly than one to be
sited afloat. In the former instance, the unit will not be required to meet Coast Guard requlrements
 for nuclear vessels, and therefore the double bottom and some of the water-tight bulkheads will not
be needed. The overall length of a platform '1i1__1it for the production of 91 MW of electrical power
can be reduced to about 260 ft, since there will be no requirement for minimizing hull trim during
plant operatxon A hull length of about 230 ft w:ll suffice for a dry emplaced unit designed for the
production of process steam only. '

Platform-mounted reactor plant eapital costs

The capital costs for the various platform configurations are based on data :deveioped in Ref.
48, modified to place them on a consistent basis with the costs of land-based CNSG plants givenina

 

51. United States Coast Guard Rules and Regulations, Title 46, CFR.

 
 

 

 

108

previous section. The expenditures for the support facilities needed at the site of the industrial
energy user were not estimated at this time, since detailed site requirements have not been
determined. The extent of facilities already existing at the industrial site (such as electrical, steam,

-and process fluid distribution systems) will influence the cost of siting a platform-mounted reactor

plant. The local terrain, soil conditions, the type of barge emplacement (afloat or dry), and the

number of reactor units will also affect the site capital expenditures by several millions of dollars.

Because of these uncertainties, the present estimates are limited to predicting the capital cost for only
the items that comprise a platform unit. ' |

A representative platform building schedule- was developed (assuming shipyard construction
under a manufacturing license) in order to estimate the interest chargeable during the construction
of a 313-MW(t) platform-mounted plant (Fig. 5.32). For comparison purposes, a project schedule
for a 313-MW(t) land-based CNSG plant is also shown in the figure, indicating that actual plant
construction spans a period of 43 months compared with only 19 months for the barge-mounted
plant. The procurement of long-lead-time components consumes nearly two-thirds of the 55 months

ORNL~-DWG 74-8007

 

80

 

 

 

H COMMERCIAL OPERATION

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LOAD FUEL
60 60
a4 SET REACTOR VESSEL - FJ COMMERCIAL OPERATION
LOAD FUEL
| |@] | COMPLETE BARGE
ARRIVE AT SITE
DELIVER BARGE
@ START NON—NUCLEAR TESTING
E a0 40
o SET REACTOR VESSEL
= LAY KEEL
® START BARGE FABRICATION
-
START REACTOR 3
n BUILDING =
fi START SITE WORK
20 20
0 ULL- CONTRACT 0 Ju- CONTRACT
FIELD CONSTRUCTED -~ BARGE MOUNTED

Fig. 5.32. Schedule of events for 313-MW(t) steam-electric plant.

 
 

 

109

required to bring the barge unit on-line. Shortened procurement periods could reduce the overall
plant construction schedule by a sxgnlficant fraction.

Table 5.51 summarizes the capital costs for a 313-MW(t) platform-mounted reactor plant
designed to furnish 91 MW(e). Costs are given in 1974 dollars without escalation for startup beyond
1974. A shipyard profit rate of 5%, believed to be representative of average economic conditions,
was assumed. In estimating the labor costs, credit was taken for the economies resulting from the
repetitive production of a standard design. Towing charges are for a distance of 1400 miles at a

_speed of 6 knots. The cost category “secondary plant” also includes the cost of systems not directly

associated with the turbogenerator; thus this cost category cannot be directly compared with the
power-conversion system costs given in Table 5.44. The total cost of $68 million for a floating plant
represents the base case for the configuration shown in Fig. 5.30. Capital costs for a platform
designed for operation on a dry foundation will be about $1 million less.

The capital costs for a 313-MW(t) barge-mounted reactor for the production of process heat
only (1.24 million Ib/hr of 566 psia saturated steam generated in a reboiler) are listed in Table 5.52

Table 5.51. Cost summary for 313-MW(¢) [91- MW(e)] platfonn-mounted reactor plant

 

 

 

 

 

 

 

(in thousands of 1974 dollars)
. ' . Dry emplaced
Floating plant plant
Nuclear plant
Nuclear steam supply, including radiation waste system : 30,767 30,767
Fuel-handling system - - 650 650
Radiation monitoring system and health physics laboratory 274 274
Reactor shield and spent-fuel pit 1,189 1,189
Reactor containment 881 881
33,761 33,761
Secondary plant
Turbogenerator 6,018 6,018
Auxiliary systems 5,997 5,997
o : 12,015 12,015
Electrical plant - , 2,168 2,168
Barge and equipment _ L _;
“Hull and structures ' ' ) ' - ' 2,474 o
-Outfit, insulation, and joiner work . : : - 520 - 2,606
Coatings and cathodic protection =~ . . - 157 . ' _
Crane for turbogenerator ' 350 350
3,501 2,956
© -Total directcost - -~ SRR 51,445 50,900
Shipyard overhead (115% of direct labor) - : ' 4,049 - 3,756
Shipyard profit (5%) : 2,775 2,545
Engineering and drafting (d:stn’buted over f' ve umts) - 337 337
- Insurance ’ o ' 350 350
: ' o S - 58,956 57,888
Interest during construction (10%/year) 9,138 8973
. e L o 68,094 66,861
Towing ' : ‘ - 60 : 60
Tow insurance 200 200

Total cost exclusive of site improvements 68,354 67,121

 

 
 

 

110

Table 5.52, Cost summary for 313-MW(t) platform-mounted reactor plant -
for production of process heat

 

 

 

 

 

 

(in thousands of 1974 dollars)
. , Dry emplaced

Floating plant plant

Nuclear plant .
Nuclear steam supply, mcludmg radlanon waste system - 30,767 30,767
Fuel-handling system o 650 650
Radiation monitoring system and health physxcs Jaboratory _ 274 274
“Reactor shield and spent-fuel pit ‘ 1,189 1,189
Reactor containment 881 881

' o ' 33,761 33,761 °
Secondary plant - . 2,611 2,611
Electrical plant | - 1,110 ' 1,110
Barge and equipment : '
Hull structures, outfit, insulation, joiner work, : : 2,765 2,404
coatings, and cathodic protection

Total direct cost 7 40,247 39,886
Shipyard overhead (115% of direct labor) 3,568 3,376
Shipyard profit (5%) 2,191 2,163
Engineering and drafting (distributed over five units) 263 263
Insurance 273 273
46,542 45,961

Interest during construction (10%jyear) 7,214 7,124
' 53,756 53,085

Towing ' 60 60
Tow insurance 160 160
Total cost exclusive of site improvements 53,976 53,305

 

for a floating and for a dry emplaced unit. Deletion of the turbogenerator allows shortening the hull
by about 60 ft; the resulting cost reduction is about $400,000. The cost of a reboiler and other
components that might be required to utilize the process steam and to return the process water to
the nuclear steam supply system have not been included in the total cost. The total amount for a
plant operating afloat is about $54 million; dry emplacement reduces the platform cost by about
$700,000.

The capital costs for the various platform configurations are given in Table 5.53 along with
costs for the corresponding land-based CNSG reactor toncepts. A fair comparison between
land-based and platform-mounted concepts requires that site improvement costs be added to the
costs tabulated for the latter concepts. Therefore the total capital cost for the land-based platform
units may increase by up to several million dollars; however, it appears that substantial savings (on
the order of 20%) will still be achievable relative to field-constructed plants. An overall comparison
between these two approaches must await a more detailed definition of the site facilities required for
platform-mounted reactor plants, so that the capital costs as well as station maintenance and
operating costs can be assessed.

 
 

 

 

111

Table 5.53. Capital costs for various 313-MW(t) [91 MW(e)]
reactor plant configurations
_ (in millions of 1974 dollars)

 

Platform mounted

 

 

emplacement emplacement '
" Process steam only plant 54 . . 53 64
91-MW(e) generating plant 68 : Y 89

 

Site facilities

The support facilities needed for operating a platform-mounted reactor plant will depend on the
characteristics of the site and of the industry that uses the energy produced by the reactor plant. A
detailed determination of these requirements for representative applications is beyond the scope of
the present study, and this is merely a broad outline of the major requjrements that must be met by
the site facilities.

Basic to the plant concept is the idea that the reactor will be started up and operated at one site
only and that no provision be made for moving the unit subsequently for operation elsewhere. This
approach simplifies the plant design and avoids the difficulties associated with the movement of a
radioactive “hot” reactor plant. A case by case determination probably is required to determine if
towing the plant away for decommission . will be advantageous. A central facility for
decommissioning floating offshore nuclear power plants has been suggested previously;*’ that facility
might also be suitable for final disposal of platform-mounted reactor plants of the type studied here.

For sites accessible only by fairly shallow navigation channels, construction equipment must be
available to complete the installation of the concrete for the reactor shield and the spent-fuel pit. The
top of the reactor building will have to be erected at the site if bridges or power lines encountered
enroute to the site do not allow passage of the complete structure. Other site construction work will
include emplacement of the barge (either afloat or on a foundation) and the installation of electrical,
process, and other systems needed to connect the energy source to the industrial plant and to the
local electrical grid. ' : . : :

The facilities for mooring a floatmg power plant must be capable of w1thstandmg ‘wind and
‘wave forces imposed -on the barge; changes in ‘water elevation must also be accommodated. The
plant must also be protected against ship collision and consequent fire or explosion if the site is
exposed to these hazards. Plant sinking in shallow water can be accommodated by enclosing
equipment essential to reactor safety in water-tlght compartments S
| - Emplacing the platform on a dry foundation is one alternative to mooring the barge This could
be accomphshed by dredging out a basin alongside a waterway with water admitted after a concrete
‘foundation has been constructed below the waterway level. The barge could then be floated over the
foundation and the water pumped out from the basin after the latter has been sealed off. The
advantages of dry emplacement include absence of hull motion, avoidance of ship collision
possibility, and hull accesszbll:ty for inspection and repairs. An effective connection is essential

 

52. A Survey of Unigque Technical Features of the Floating Nuclear Power Plant Concept, U.S. Atomic Energy
Commission, Directorate of Licensing (March 1974).

 
 

 

112

between the hull-and the foundation to resist seismic forces and to prevent hull movement should the
basin be flooded inadvertently. Refloating in this eventuality can be prevented by installing ballast in

the barge and by providing flooding openings in some hull compartments. -

54 THERMAL ENERGY TRANSPORT FROM NUCLEAR PLANTS

The transmission of energy in the form of high-quality steam was evaluated in conjunction with
the nuclear concepts, since nuclear reactors appear to be the most likely source of energy for large
blocks of thermal energy transmission. It is assumed that process steam is available at 850 psia and
525°F from an LWR and at 650 psia and 750°F from an HTGR. Producing process steam requires
the use of a reboiler for the LWR and more major system modifications for the HTGR. These
factors are discussed in Section 5.2. '

The HTGR prime steam was originally considered for transport, but the extremely high
pressure-temperature condition appears to be impractical for long-distance transportation

Transportatlon costs, summarized in Table 5.54, are evaluated on a per mile basis and should
be valid over the '/>- 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 water<cooled reactors of the
BWR and PWR types and gas-cooled reactors of the HTGR type used for generating electricity are
well developed in terms of safety and licensability. The use of PWRs commercially for production of
process steam has precedence in the Midland, Michigan, case, in which a power plant operated by
the Consumers Power Company will supply process steam to a Dow Chemical Company plant.

The case-by-case evaluation of nuclear power plant safety is prompted by several factors that
distinguish one plant from another: (1) changing technology, including differences in design details;
(2) safety perspectives that change with time; (3) different operating organizations; and (4) different
plant sites. None of these factors will be neglected in an AEC licensing review of new applications
for nuclear process heat plants, but site acceptability is a qualification of special importance.

There are two kinds of safety questions concerning siting of nuclear power plants. First, what
are the environmental characteristics that could adversely affect the plant’s safety performance?

 
 

 

125

Second, how do environmental characteristics affect the potential radiological consequences of
accidents? . o

The plant environment provides the commonly accepted elements required by an mdustnal
facility, including adequate structural foundation, operating space, and adequate water for coolant
makeup and heat rejection. Although these elements are so well recognized as to make it unlikely
that they would be neglected in planning a nuclear facility, their importance to safety requires that
uncommon care be exercised in providing the desired support for nuclear power reactors. This
_special concern for safety, on the other hand, has had- little influence on site selection. Sites
otherwise acceptable for heavy industrial facilitics have, with only one exception, been adequate in
this respect. The only natural feature that has ever completely disqualified a site is tectonically active
faults, The AEC rejected a California site, after several million dollars were spent in site
development, because of geologic evidence of active faulting. The AEC did not at that time, and
probably would not in the near future, accept an engineered accommodation of active faulting. The
detailed criteria for geologic evaluation of sites is a part of the AEC regulation, Title 10, Code of
Federal Regulations, Part 100, “Reactor Site Criteria.” Texas and Louisiana have several proposed
nuclear power plants under active review at this time, and there is no indication of any unusual
concern with faulting in this region. |

The second basic site-related question—environmental characteristics affecting radiological
~ consequences of accidents—is also a subject of the AEC’s “Reactor Site Criteria.” As with active
faulting, the size of the proximate population is the only impediment of this second category
of site problems that has not been and cannot be resolved by engineering alone. A few formally
proposed sites have been rejected by the AEC.

Population risk-factor estimates

The prospect of using nuclear power reactors for process heat raises the general question as to
whether it is reasonable to expect that such plants could be located safely in industrial areas. For the
purpose of providing practical guidance on siting, we have evaluated the Houston Ship
Channel-Galveston Bay area in Texas and areas along the lower Mississippi River in Louisiana.
This study consisted of a survey of population distributions and densities throughout these two
areas. The particular method utilized should yield a good indication of whether, from the standpoint
of population risk, large nuclear power reactors would be licensable in such areas, inasmuch as
hypothetical sites in the areas are compared with real reactor sites already evaluated and accepted by
the AEC. ‘ : - '
" The areas of interest in Louisiéha and Texas have been evaluated by calculating a population

risk factor for a set of points within each region. The particular points for which the calculations
were made are hypothetical sites only in the broadest sense. Hundreds of such points have been
evaluated by this process in order to scan the reglons wnth sufficient density to permit some
conclusive characterizations to be made. : '

* The areas evaluated in Texas and Louisiana are shown in Figs. 5.37 and 5.38 respectlvely Risk
‘scans were made along straight-line traverses within each of the 11 quadrangular areas in Texas and

Louisiana. The precise locations of the traverses are described in Table 5.57. Generally the scans
covered the areas with a spacing of 1 to 3 km, although some scans were made at about 0.5-km
intervals. 7 o

The population risk profile of each traverse is displayed graphically in Figs. 5.39 through 5.49.

A complete set of profiles is given in Appendix F.

 
 

 

126

ORNL-DWG 74-12737 .

 

 

 

= HOUSTON

SHIP CHANNEL

 

 

 

 

FREEPORT

 

 

 

 

 

 

 

q

 

 

 

    
 

'CHOCOLATE
. BAYOU

 

 

 

GULF OF MEXICO

Fig. 5.37. Industrialized areas in Texas evaluated for population risk.

 

 

 
 

 

127

ORNL-DWG 74-12738

 

  
 

LAKE
PONTCHARTRAIN

 

 

 

 

 

NEW ORLEANS

 

 

 

A = —CA a

 

 

 

Fig. 5.38. Industrialized areas in Louisiana evaluated for population risk.

 
 

 

 

 

 

128

ORNL—DWG 74-12729

 

20

6 HOUSTON SHIP

1.8
16 |

1.4 |

RISK FACTOR
o
T

10 |
08

0.6

 

 

 

 

0.4 : ;;;;;;;;;;;; it 1
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32
DISTANCE (km)

 

Fig. 5.39. Population risk profile for Houston ship channel, traverse 6.

 
 

 

 

RiSK FACTOR

0.52

0.50

0.48

0.46

0.44

0.42

0.40

0.38

0.36

0.34

™Y |rtrr1}r

129

ORNL—-DWG 74-12730

 

2 BAY PORT

vlrrrv|rrvr|ITT

LE B

rjrreryyry

vyryyrvjrvveeygvyy

 

 

 

-m

 

lllllnlllljll.llll!llllllj!l.lllllllllllllllllllllllllhlll.AlllllllllAlAllllllllllllllLl'llllllllllllll'llljllllllllll

o 1 2 3 4 85 6 71 8 9 10 1 12
DISTANCE (km)

Fig. 5.40. Population risk profile for Bay Port, traverse 2.

 
 

130

ORNL-DWG 74-12731

 

062 F——
3 TEXAS CITY

 

060 |
0.58 F
0.56 F
054 F

0.52

 

S 050 F

- C

o

S o048k
| ¥
| » z
3 « 046 F
| 0.44 F
042 F

  

0.40 E

0.38 E

 

0.36 ¢

DISTANCE (km)

Fig. 5.41. Population risk profile for Texas City, traverse 3.

  
    
     

 

 
 

 

RISK FACTOR

0.1520 |

0.1515

0.1510

0.1505

0.1500

0.1495

0.1490

0.1485

0.1480

0.1475

131

ORNL-DWG 74-12732

 

 

2 CHOCOLATE BAYOU

- - S -

2 4 & 8 10 12 14

~ DISTANCE {km) |

Fig. 5.42. Population risk prbfilc for Chocolate Bayou, traverse 2.

 

16

 
RISK FACTOR

 

132

ORNL-DWG 74-12733

 

 

3 FREEPORT

 

 

 

4 6 8 10 12
DISTANCE (km)

Fig. 5.43. Population risk profile for Freeport, traverse 3.

——

 
 

 

 

 

 

 

 

 

 

133
| |
ORNL-DWG 74-12734R
| 0.50 [
5 POINTE COUPEE
045 |
| !
|
| 0.40 |
0.35
g L
O 0.30
Q
<
e
& 0.25 [
m b
0.20 }
0.15 |
0.10 |
0 2 4 6 8 10 12 14 16 18.20 22 24 26 2830 32
‘ DISTANCE (km) .
. Fig. 5.44. Population risk profile for Pointe Coupes, traverse 5.
i
|

 
 

RISK FACTOR

 

 

1.5 E

14

134

ORNL-DWG 74-12735

 

E 5 BATON ROUGE

 

 

 

DISTANCE (km)

Fig. 5.45. Population risk profile for Baton Rouge, traverse 5.

 

 
 

 

RISK FACTOR

0.50
0.45
0.40

0.35

o
W
o

o
N
o

0.20

0.15

0.10 |

0.05

135

ORNL-DWG 74-12739

 

v v T v

"ll’""""I_I

¥ ' T ¥ v ¥ [ v v T

II'TV_TY_TTI'I

 

 

2 LAFOURCHE P

 

 

 

 

 

 

4. 50 60 70 80

0 20 30 40
DISTANCE (km)

Fig. 5.46. Population ‘riskrprofilc for Lafourche, traverse 2.

 
 

 

RISK FACTOR

136

- ORNL-DWG 74-12740

 

4.5

 

0-0-11.

5 NEW ORLEANS

 

A l A A A A l A 1 A A l L R A A . i i A A l i A e A l A A L l A A

 

 

5 10 15 20 25 30
- DISTANCE (km)

Fig. 5.47. Population risk profile for New Orleans, traverse 5.

 

 

35 40

 
 

RISK FACTOR

 

0.48

0.46

0.44

0.42

0.40

0.38

0.36

0.34

0.32

0.30

0.28

0.26

0.24

0.22

0.20

137

ORNL--DWG 74--12741

 

'VT""'I’I'T"T"’I’TI’

l'll'

l'lr"

-vv'vrfv—‘-v

"I’I"'Trrl'l"

 

0.18 %

2 PLAQUEMINE

 

 

2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32

DISTANCE (km)

Fig. 548. Population risk profile for Plaqueminé, traverse 2.

 
 

 

 

 

0.44

RISK FACTOR

138

ORNL-DWG 74-12742

 

5 TAFT
0.42 |

0.40

0.38

036

0.34
0.32
0.30
0.28
0.26
0.24
0.22

0.20 . ——EF

- 0.18

0o 1 2 3 U 6
DISTANCE (km)

Fig. 5.49. Population risk profile for Taft, traverse 5.

 

 

 

 
 

139

Table 5.57. Quadrangte and traverse parameters”

 

Number Geographic coordinates of corners (deg)
Quadrangle of _ A C . B , C D
traverses yatitude Longitude Latitude Longitude Latitude Longitude Latitude Longitude

 

 

Texas : : o '
Houston Ship Channel 7 29.8100. . 95.2900 29.6900 95.2900 29.8100 94.9600 29.6900 94.9600
Bay Port 7 29.6600  95.1200 295400 95.1200 .29.6600 95.0000 29.5400 95.0000
Texas City 7 29.4400  94.9900 :29.3200 949900 29.4400 949000 - 29.3200 949000
Chocolate Bayou 7 29.2800  95.2200 29.1600 95.2200  29.2800 95.0600 29.1600  95.0600
Freeport 11 29.0600 954583 289167 954583 29.0600 95.2917 289167 95.2917

Louisiana ) ‘ ' - ' - . ,
Point Coupee 5 30.7500 91.5000 30.8295 91.2865  30.5000 = 91.3802  30.5795  91.1667
Baton Rouge 8 30.5000 91.4433  30.6447  91.0982  30.0000 91.1637 30.1447 90.8186
Lafourche 9 29.7500  91.1300 30.1300 91.1300 29.7500 90.4000  30.1300 90.4000
New Orleans 7 29.7500 - 90.4000 30.0230 - 904000 29.7500 - 90.0000 30.0230 90.0000
Plaguemine 7 30.2600 91.2500 30.2600 91.1800 30.5300 91.2500 30.5300 91.1800
Taft ' 13 29.9600 90.5000 30.0800 905000 299600 90.4000 30.0800 90.4000

 

“Quadrangles are approxnmately rectangular and are covered by the number of stralght-hne traverses tabulated. Corners (A,
B, C, and D) are shown on area maps in Figs. 5.37 and 5.38 and are specified by the tabulated geographic coordinates as
determined from U.S. Geological Survey maps, Western United States series, scale 1:250,000, sheets NH 15-6,-7,-9,and -10. The
origins and terminal points of the traverses of a quadrangle are evenly spaced along lines ABand CD respectwely Line ACisthe
first traverse of a quadrangle, and line BD is the last.

The significance of the population risk factor is in its representation of the cumulative risk to
the entire population from potential exposure to the radioactive materials released by accident from
a particular hypothetical site. It is obtained by computing a weighted average of the surrounding
population. The weighting function approximates the relative radiation exposure of a single
individual; this relative exposure is a function of distance and was chosen for this study to vary with
distance (r) as r'°. This particular exponent was used in order to simplify the comparison of this
study with information contained in an internal AEC regulatory staff working paper.’’ The
population risk factor used for this study has also been normalized in the same way as the AEC’s,
namely, by requiring the risk factor to have a value of 1.0 for a site having a uniform population
density of 1000 individuals per square mile within 50 miles of the hypothetical site and a density of
zero beyond. A zero densxty, for normalization, within 0.3 km of the site, to account for a nominal
plant exclusion distance, was also assumed in the present study.
~ The site evaluation utilized data from the official 1970 census of the United States in the form

that gives the greatest detail available in the actual geographical location of each population
segment. These data are the populations and geographical coordinates of each official “enumeration
district.”** An enumeranon district is a geographically contlguous area having nommally 1000 or
* less resident persons

 

61. AEC Regulatory Staff, Population Dismbunon Around Nuclear Power Plant Sites, AEC Press Release T-160, Apr
9, 1974,

62. U.S. Bureau of the Census, U.S. Census of Populauon 1970, Number of Inhabitants, Fmal Report PC(1), A series.

63. U.S. Bureau of the Census,. Census of Population and Housing: 1970, GEOGRAPHIC, Identification Code Scheme,
Final Report PHC(R)-3.

64. National Data Use and Access Laboratories, Arlmgton Virginia, Master Enumeration District File Extended with
Coordinates, MED-X Census Data Tapes.

 
 

 

 

140

The calculations of this study differ from those described in the referenced AEC document in

two respects: (1) the AEC lumped the entire population around a site (within 50 mlles) into ten
annular areas of assumed uniform density, whereas this evaluation considered each enumeration

district separately; and (2) the AEC used population data evidently extracted from various licensing

documents, while the basis in this study was the 1970 census.

- The influence of these differences in procedure have been analyzed in detail for the Indian Point
site. This is the site of a three-unit nuclear power plant owned by Consolidated Edison Company of
New York, Inc., and is one of the few power reactor sites in the United States near a metropolitan
area. A comparison of hypothetical sites with this important site, already evaluated and accepted by
the AEQ, is a significant test of the acceptability of the former. -

- The AEC procedure of lumping the population into large segments gives a “site populatlon
factor” for this site about 0.5% less than the population risk factor, provided the 1970 census basis of
this study is used for both calculations. It was already known that the effect of lumping should be
small in any case except with respect to that part of the population close to a site. Therefore, it is
reasonable that the two procedures should give similar results for the Indian Point site, since the
population distribution is dominated by the large number of people living beyond five miles, as

‘shown in Table 5.58. This more distant population contributes about 80% to the total value of the
- Indian Point site population factor. In an area where the population density is more nearly uniform

or is more concentrated near the site, the lumping of the population would not be as good an
approximation of the ideal population risk factor. -

Lumping the population near the Indian Point site leads to an underestimate of the populatxon
risk of about 13%, if only the population within 5 miles is considered. This is unimportant in the

Indian Point case, as explained above, when the entire population is considered. In a test case in the

Houston area, the effect of lumping is more pronounced and, as with Indian Point, is an
underestimate of the population risk. Therefore, the more precise procedure developed for this study
has been used for the evaluation of all hypothetical sites.

In order to evaluate the effect of using population data different from that of the AEC, the two
population distributions shown in Table 5.58 were used for computing the site population factor in

Table 5.58. Comparison of AEC population distribution
and 1970 census distribution for Indian Point

 

 

 

Distance Cumulative population Ralt;c‘;gf AECto
. census
(miles) AEC? 1970 census population data
1 3,300 1,300 2.54
2 18,000 10,700 1.68
3 30,000 217,500 : 1.09
4 40,000 41,500 0.96
5 65,000 65,600 1.07
10 263,000 201,900 1.30
20 1,684,000 896,200 1.32
30 . 4,410,000 4,002,400 1.10
40 10,630,000 10,177,300 1.27
50 16,500,000 16,007,000 1.03

 

®Estimated from crude graph.

 
 

141

accordance with the AEC procedure. The values of this factor, as a function of distance, are shown
in Table 5.59. This tabulation demonstrates the significant effect of using imprecise population data
close to the site. Although the total populations differ by only 3%, the site population factors differ
by 17%. This disproportionality of the site population factor with respect to total population is
evident in Tables 5.58 and 5.59 at all distances. o

In order to be consistent in the evaluation of all sites, the value of the population risk factor
computed from the 1970 census data for Indian Point was considered to be the relevant value for
that site.

A site is generally at lcast as good as the Indian Point site if the populatlon risk factor is no
greater than 1.29. The profiles of Figs. 5.39 through 5.49 (and Appendix F) show that almost all the
areas scanned are much better than Indian Point. Of all the Texas areas, only small areas along the
west and south edges of the quadrangle covering the Houston Ship Channel would be of
questionable acceptability. In Louisiana, a small central area in Baton Rouge and the central city of
New Orleans are unfavorable. ,

As can be observed from the population risk profiles, there is a wide variation in the merits of a
site with respect to this one factor. If all other qualities of alternative sites were equal, one would
want to choose the site having the lowest population risk. The AEC would give some consideration

to this possibility. Conversely, it is important to recognize that the AEC acceptance of existing
nuclear power plant sites has taken such alternatives into account and would, indeed, in the future
make allowance for the fact that a plant may need to be in a particular locatlon in order to be useful.
The Midland nuclear plant, which will supply process stem to an industrial facility, would probably
have been located farther from the city of Midland had there not been a special need in that case.
Other factors, such as size of plant, also favor the industrial process heat case in comparison with
the real power reactor sites. These factors make the conclusion all the more reasonable that all the
industrialized areas studied, except for the central city regions included in the survey, would be quite
favorable as nuclear process heat plant sites, at least on the basis of population risk.

~Table 5.59. Comparisoh of site population factors
computed according to AEC procedure from different
' lumped population distribu tions for the

 

 

 

Indian Point site

D . Site population factor

istance :

mil _

( e-fi) data o _1970 census
1 1.05 S 0.41
2 1.20 058
3 1.12 ' 0.67
4 1.03 ‘ 0.67
5 1.01 0.69

10 0.96 0,71
20 1.12 : 0.72
30 _ 1.24 : 0.95
40 . 1.45 1.20

50 1.51 1.29

 

 
 

 

 

142

6. Coal-Based Systems

6.1 ASSESSMENT OF COAL RESOURCES, AVAILABILITY, AND COST
6.1.1 Resource Basc

.Coal deposits are widely distributed throughout the United States as shown in Fig. 6.1. The
coal resource base is estimated to be 3.21 X 10" tons,* equivalent in energy content to over 1000
years at the total energy consumption rate of the U.S. in 1970. Approximately one-half, or 1.56 X
10" tons, lies in beds more than 14 in. thick at depths of 3000 ft or less in mapped and explored

_areas. The distribution of the 1.56 X 10" tons by rank (type of coal) and by state is shown in Fig.

6.2. Of the total bituminous resource, two-thirds is located east of the Mississippi, with Illinois
containing the largest quantity of any state. Subbituminous coal is predominantly contained in the
Rocky Mountain states of Montana, Wyoming, and Colorado and in Alaska. New Mexico also has
substantial reserves. About 98% of the nation’s lignite is located in North Dakota and Montana.

6.1.2 Recoverable Reserves

The coal resource base described above does not constitute a usable resource because of both

‘technical and economic constraints. Coals considered to be available at present prices with present

technology are the measured and indicated reserves with 1000 ft or less of overburden and in beds of
thicknesses 28 in. or more for bituminous and anthracite and 5 ft or more for subbituminous and
lignite. On this basis,” available reserves total 394.1 X 10° tons (about one-eighth of the total
resource base) distributed by rank as follows: bituminous, 66%:; subbitu'n'iinou's 18%; lignite, 13%;
and anthracite, 3%. A breakdown of available reserves by rank and state is ngen in Table 6.1.

Of the 394.1 X 10° tons cons1dered to be available, 45 X 10° tons are strippable; most of this
would be recoverable since the recovery factor for strlp-mmed coal exceeds 90% For deep-mmed
coal, however, the recovery factor with present mining practices is about 50%; so that of the 394.1 X
10° tons of deep-minable reserves, only about 175 X 10° tons are recoverable. The recoverable
reserves are equivalent to about 65 years at a rate of consumption equivalent to the total national
energy use in 1970.

Most of the low-sulfur coal is located in the western United States in the form of strippable
subbituminous coal and lignite. As shown in Fig. 6.3, of the 45 X 10° tons of strippable reserves,
about 25 X 10° tons are low-sulfur coal located in the Rocky Mountain states.®

6.1.3 Availability
It is evident that the coal reserves are adequate to meet almost any demand in the foreseeable

future. The limiting factors on the use of coal are (1} environmental constraints on mining and
combustion, (2) coa! industry development, and (3) transportation.

 

65. Paul Averitt, Coal Resources of the United States, USGS Bulietin 1275, Jan. 1, 1967.
66. Strippable Reserves of Bltummous Coal and Lignite in the Umted States Bureau of Mines Information Circular
8531, 1971.

 
 

 

ORNL-DWG 74—-12791

 
    

1l

I

<]

 

llll"””

 
 
  

I

 

143

l "' ;. Y

 
    

m SUB—BITUMINOUS
- ANTHRACITE

   
     

Fig. 6.1. Coal fields of the conterminous United States.

 
 

144
\
|

ORNL—DWG 74—12810

ANTHRACITE:
PENNSYLVANIA

OTHER STATES

BITUMINOUS:
ILLINOIS
WEST VIRGINIA
MISSOURI
PENNSYLVANIA
KENTUCKY
COLORADO
OHIO
INDIANA
UTAH
_ALASKA
KANSAS _ ] PRODUCTION AND MINING LOSSES
ALABAMA : ' (72 REMAINING RESERVES
WYOMING '
VIRGINIA
NEW MEXICO
OTHER STATES
SUBBITUMINOUS:
MONTANA
WYOMING
| ALASKA
NEW MEXICO
; COLORADO
WASHINGTON
OTHER STATES

 

 

LIGNITE:
NORTH DAKOTA

MONTANA
OTHER STATES

 

0 20 40 6 80 100 120 140 350.9
RESERVES (10% short tons) '

Fig. 6.2. Estimated U.S. original and remaining coal reserves by rank, Jan. 1, 1965.

 

 
 

 

DWG 74-12793

ORNL

145

v
2
o
w £ W
= -
& w o
% = 2 w E Z
“b . = - @-
% &% /, W = | e
-7 TG LN FE o 8§ =z
_Z)\z\0 m 4O ©»n o«
¢ S . .
N ~ oL b

      
 

    

                

 

  

        

 

  
 
         

 

 

3~_ . i

..w % i

Y ____,__
] ___fi? i __i=____._..,_ ..,.,“.e..”...h.._

 

 

 

 

.

ALASKA

Fig. 6.3. Strippable reserves of the conterminous U.S. by region.

 
 

 

 

146

Table 6.1. Total estimated remaining measured and indicated coal reserves
'(10° tons) of the United States as of Jan. 1, 1970°

Source: U.S. Energy Outlook — Coal Availability, p. 116, National Petroleum Council, 1973.

 

Anthracite and

 

 

 

 

 

 

State Bituminous Subbituminous Lignite semianthracite Total
Alabama - 1731 0 b 0 1,731
Alaska ' 667 5,345 c d 6,012
Arkansas 313 ' 0 b 67 380
Colorado - 8,811 - 4453 - Q 16 13,280
Georgia . 18 0 0 - 0 18
Mlinois = - 60,007 0 0 0 60,007
Indiana 11,177 0 0 0 11,177
Iowa 2,159 0 0 0 2,159
Kansas ' 328 0 0 0 328
Kentucky (west) 20,876 0 0 0 20,876
Kentucky (east) 11,049 -0 0 0 11,049
Maryland - : 557 ) 0 0 557
Michigan : 125 . 0 0 0 125

" Missouri : 12,623 -0 0 0 12,623
Montana 862 31,228 6,878 0 38,968
New Mexico . - 1,339 779 0 2 2,120
North Carolina e 0 0 0 b
North Dakota 0 ' o - 36,230 0 36,230
Ohio 17,242 - 0 ) 0 0 17,242
Oklahoma 1,583 0 0 0 1,583
Oregon ' - f - 0 0 f
Pennsylvania - 24,078 0 0 12,525 36,603
South Dakota 0 0 757 0 157
Tennessee . 939 0 0 0 939
Texas f 0 6,870 0 6,870
Utah 9,155 150 0 0 9,305
Virginia 3,561 0 0 ‘125 3.686
Washington - 312 1,188 0 0 1,500
West Virginia 68,023 0 0 0 68,023
Wyoming 3.975 25,937 c 0 29,912
Other states f : f 46 0 46

Total 261,510 69,080 50,781 12,735 394,106

 

9Figures are reserves in ground, about half of which may be considered recoverable. Includes all
beds with less than 1000 ft of overburden and over 28 in. in bed thickness for bituminous and
antlu:acue and § ft or more for subbituminous and lignite.
bSmall reserves of lignite in beds less than 5 ft thick.
€ Small reserves of lignite included with subbituminous reserved.
9Small reserves of anthracite in the Bering River field believed to be too badly crushed and folded
to be economically recoverable. '
€Negligible reserves with overburden less than 1000 ft.
Data not available to make estimate.

Environmental constraints

Most of the present concern is related to the effects of strip mining on land ‘and water.
However, it should be noted that underground mining also has adverse impacts, including death and
injury rates approximately five times higher than those for strip mining.*” The Coal Mine Health

 

67. Council on Environmental Quality, Energy and the Environment: Electric Power, August 1973.

 
 

147

and Safety Act of 1969 set tighter standards to reduce the hazards of underground mining. A
side effect of the Act was a decrease in productivity and an increase in capital investments required
for deep mining. As a consequence, strip mining accelerated because of the improvement in the
relative competitive position of this form of mining. Strip mining now accounts for approximately
one-half of the total coal productlon With the trend to more stripping and the vast devastation of
land and water resources that have been experienced in some areas, many proposals, ranging from
improved reclamation practices to outright bans, have been made to reduce the adverse effects of
strip mining. Reclamation of strip-mined areas involves backfillmg, compacting, soil conditioning,
regrading, and revegetation to achieve a natural appearance. Current estimates®”® for reclamation
range from $2000 to $6000 per acre, the latter figure corresponding to 20¢ to 30¢ per ton of coal (for
coal yields of 20,000 to 30,000 tons/acre). For western coal from thick beds, the surcharge for
reclamation might be only 3¢ to 4¢/ton. It would appear, if these figures are correct, that the issue in
strip mining is not reclamation costs, since the contribution to the cost of coal would be minor.
Rather, the issue seems to concern the question of what constitutes acceptable reclamation. There is
no reasonable way to restore stripped land to its original condition—only to a condition that some
would consider acceptable. Ultimately, society must make the judgment concerning benefits and
costs of surface mining. If, as some have suggested, surface mining were banned, the ability of coal
to satisfy a larger portion -of our nation’s energy needs would be seriously impaired. The National
Petroleum Council (NPC)” estimated that the coal production would decline Iby over 40%, at least
until 1985, if stripping were banned. '

Coal production and coal processing in some western states pose additional environmental and
societal problems. Water use associated with strip reclamation, slurry pipelines, and, in particular,
coal gasification plants could be significant. Such use would be in direct competition with
established agricultural and industrial activities. The water question will be an important issue in the
expansion of the coal industry in the West.”" |

Coal mining expansion

" The NPC™ estimated that a maximum growth rate of 5% year could be sustained by the coal
mining industry. This growth rate, and probably a higher figure, would seem to be supported by
historical evidence. Figure 6.4 shows coal production over the period 1935 to 1970. In the years just
prior to and durmg World War II, underground rmmng increased at an average. rate of 8%/ year.

Since 1954 strip mining has increased at an average rate of 6. l%/ year Potential limitations to

expansion include the avallablhty of capital, equlpment and manpower. The NPC estimates that up
to $15 billion 1970 dollars in capital will be required over the period 1970 to 1985. Although this is a
significant sum, the capital required to mine the coat will be small relative to the capital needed to
use it. Much of the capital required for expansion must come from outside the industry, and -
investors generally require long-term contracts for the output of a new mine before offering
financing. Present uncertainties concerning the possibilities of future restrictions on certain kinds of
mining and the envirdnmental acceptability of certain types of coal encourage caution on the part of

 

- 68. Federal Council for Science and Technology, Committee on Energy R&D Goals Panel Report on Extraction of Energy
Fuels, June 1972.
69. C. L. Wilson, “A Plan for Energy Independence, Foretgn Affairs, pp. 657-175, July 1973,
70. U.S. Energy Outlook, Coal Availability, National Petroleum Council, 1973.
71. Business Week, Feb. 9, 1974, p. 14a, “Letter from Powder River.”

 
 

 

 

148

ORNL-DWG 74-12799

S

 

700
600 - /\ \/\ _ TOTAL COAL PRODUCTION

 

 

 

 

 

 

 

 

 

 

 

o .|
400 eV / 1
L 7\ MAXIMUM UNDERGROUND BITUMINOUS
UNDERGROUND .
@ PRODUCTION /{/-\ /
S 300 e |
— v \___«
3 8% GROWTH PER ANNUM IN ~T~ -
s C UNDERGROUND PRODUCTION /
] ]
200 | SURFACE BITUMINOUS "

 

100 ' ‘AM
: : / ANTHlRACITE\\ '

 

 

 

o — [

 

 

 

 

 

 

 

 

1935 1940 1945 1950 1955 1960 1965 1970

YEAR

Fig. 6.4. Production of bituminous coal (including lignite) and anthracite (1935-1970).

lenders. Nevertheless, the availability of capital would not appear to be seriously restrictive relative
to the growth of the mining industry.

The time required to develop a new mine is a- definite limitation on the rate at which the coal
industry can respond to increased demands. It is estimated that the time required to develop a new
mine and bring it to full production is 5 years for a deep mine and 3 years for a surface mine.”
Delays in equipment procurement could increase these times. Examples of present equipment
procurement problems are new drag lines for stripping (lead times of 4 to 5 years) and roof bolts for
underground mines. Some believe that demands for heavy equipment will exceed the supply
capabilities of U.S. manufacturers and that some equipment will need to be imported.” Other
studies™ conclude that equipment delivery will pose no serious problem in expanding mining
capacity. Although there may be some near-term equipment delivery problems, it seems reasonable
that the long-term develdpment of coal mining capacity will not be limited by equipment
availability. 7 _

Although there are differences in opinion on the question, it would appear that skilled
manpower may be one of the more serious limitations on the rate of mining expansion. The

 

72. Personal communication, Wilbur Helt, National Coal Association, T. D. Anderson, Oak Ridge National
Laboratory.

73. Personal communication, Zane Murphy, U.S. Bureau of Mines, T. D. Anderson, Oak Ridge National Laboratory.

74. Report of the Comell Workshops on the Major Issues of a National Energy Research and Development Program,
published by the College of Engineering, Cornell University, December 1973.

o

 
 

 

149

National Coal Association (NCA) points out that, because of a period of stagnation in coal mining,
the present work force is concentrated in two age groups: over 45 and under 30. The 30- to 45-year
age group, which would normally be expected to fill leadership roles in an expanding industry, is
essentially missing. One specialty that is especially important for underground mining is mining
engineering, and mining engineers are in short supply.”

Transportation

Rail is by far the most important mode of transportation for coal, but water shipments are
significant and are increasing rapidly. Coal slurry (50 wt % water) pipelining may also become
1mportant in the future, especially for western coals that must be transported long distances to
markets.” : |

During the 1960s, rail coal traffic increases averaged 2.4%; year.”” A greater rate of expansion in
the future would seem to be required if coal is to play a more significant role in energy supply. The
railroad industry currently suffers from severe financial problems, and it is generally agreed that the
Federal Government will need to underwrite the necessary modernization and expansion of
railroads. The general financial problems of the rail industry have not had a noticeable effect on the
investment required for coal shipmént; one reason for this is that some of the new investment for
coal cars and terminal facilities has come from outside sources, principally the electric utilities. Aside
from future financial problems, there is substantial room for improvement in existing investment.

‘For eXample, in 1968, open-top hopper (coal-carrying) cars spent only 7.7% of the time in line-haul

service (loaded and empty movement in trains).”’ The trend to greater use of unit trains would be
expected to improve car utilization in the future. |

Barge movement of coal, where applicable, is the most economlcal mode of transportation. A
significant portion of coal movement is by joint rail-water transportation. Long-haul movements are
the most rapidly growing portion of internal waterborne coal carriage. One of the more notable
long-haul movements is the carriage of southern Illinois and Ohio Basin coal to Gulf Coast
destinations such as New. Orleans, Galveston, and western Florida. Coal for coastal areas is
transported to New Orleans by barge and transshipped by oceangoing vessels. Transshipment™ in the
New Orleans area increased from 0.6 million tons in 1960 to 3.1 million tons in 1969. The NPC
believes that a serious impediment to long-haul coal movement is the inadequacies of locks at the
central interchange of six navigable rivers on the boundary of southern Illinois. The economic
capacity of these locks has already been exceeded, and, although construction of new facilities has
been initiated, the bottleneck will not be removed before the latter 1970s.

Transportation system expansion is particularly crucial if there is to be extensive use of the vast

reserves of low-sulfur strippable coal in the west, especially in Wyoming and Montana.
Some expansion is in the planning stage., The Burlington Northern Railroad and the American

- Commercial Barge Line plan to develop a rail-to-barge coal terminal on the Mississippi River in

north St. Louis County.”” The facility is expected to be completed in 1976 and will handle about 20
million tons of coal per year. Low-sulfur coal will be delivered to the terminal by unit train from
Wyoming and Montana and will be transferred by barge to users served by the Mississippi River

 

75. The Potential of Coal to Meet the Enerzv Cnszs, National Coal Association, Dec. 20 1973

76. E.J. Waspand T. L. Thompson, “Slurry Pxpehnes—Energy Movers of the Future,” il Gas J. 71(52), 45-50 (Dec. 24,
1973).

77. “Plans for 2 New Port Facilities Announced,” St. Louis Globe-Democrat, Jan. 30, 1974.

 
 

150

and its tributaries. Other plans for pipelines into the midsouth and to Texas have been rumored, but

‘no confirmation is presently available.

- 614 Demand

The NPC’° estimated that the demand for coal (Table 6.2) would grow from 590 million tons in .

1970 to 1 billion tons in 1985. As noted earlier, the NPC also estimated that the potential productive
capacity of the coal industry could increase by 5%/ year, resulting in a potential capacity of 1.57
billion tons in 1985. Thus, according to this view, there will be an excess of potential capability over
demand. _ o : _
The NPC analysis was made before the energy supply disruptions of 1973. The general
viewpoint now is that the United States should strive for energy independence. One important
element that will contribute to energy independence is the substitution of coal for oil and gas where
it is feasible to do so. The industrial and utility sectors are the most adaptable to coal as a substitute
for other fossil fuels. To gain some insight into the effect of this substitution on coal demand, it is
assumed that the projected growth of fossil fuel use in the industrial and utility sectors after 1975
will be based on coal. Table 6.3 shows that this substitution would result in an increase in demand of
300 million tons per year by 1985; adding this increase to NPC’s original estimate would indicate a
total demand for coal of 1.3 billion tons in 1985. The NCA believes that the coal output in 1974 will
be 640 million tons. An increase in annual production from 640 million to 1.3 billion tons in 11 years
would imply an average growth rate of 6.4%/ year. Thus, if the growth of industrial and electric
htility fossil fuel use is to be based on coal, the growth of coal production must exceed the maximum
rate of 5%/ year assumed by the NPC,

Table 6.2. Coal demand by market sector ao® tons/year)

 

1970 1975 1980 1985

 

Coking coal
Blast furnaces 86 102 110 116
Foundries and miscellaneous 10 10 10 10
Total 96 112 120 126
Domestic coal (U.S.) ’
Residential/commercial 10 7 5 3
Industrial 91 - 87 84 80
Electric utilities - 322 415 525 654
Total 519 621 T34 863
Export coal
Coking coal 56 76 94 120
Electric utility 15 16 17 18
Total : ' T 92 111 138

Total® 590 713 845 1001

 

AThese quantities are less than the total demand figures shown in
the NPC’s U.S. Energy Outlook: An Initial Appraisal 1971—1985, vol.
1 (July 1971), because they do not include “Assumed Replacement for
Shortfall in Other Fuel Supplies.” The added quantities for coal, in
terms of tons of coal, would be 30 million tons in 1975; 65 million tons
in 1980; and 70 million tons in 1985. :

 
 

151

Table 6.3. Effect of substituting coal for petroleum and natural gas
for industrial and electric utility uses on coal demand

 

Annual energy consumption?

 

 

(1012 Btu) Coal equivalent
: : °£ increase
nerease (10° tons/year)
1975 1985 1975-1985
Petroleum 10,090 15,780 5,690 247
Naturat gas 15,540 16,690 1,150 - 50
Total 25,630 32,470 6,840 297

 

@Projections from United States Energy Through the Year 2000,
U.S. Department of Interior, December 1972.

6.1.5 Coal Costs
- Coal values at mine

Trends, past and present, ‘After a long period of stability, the price of coal started rising signifi-
cantly after 1969. From 1965 through 1969, the U.s. average price (f.0.b. mine) of coal sold on the open
‘market was about 25¢/10° Btu (constant 1974 dollar basis).”™”® By 1972, the average price had risen
to about 35¢/10° Btu. Figure 6.5 shows the price trends through 1972, the last year on which

complete data are available. The U.S. average prices tend to reflect the value of coal mined east of

the Mississippi. Also shown in Fig. 6.5 are prices for subbituminous coal and lignite produced in
selected western states; generally, prices for western coal have tended to decline with time—at least
through 1972,

The data of Fig. 6.5 are based on reports by the U.S. Bureau of Mines’®*® and the National
Coal Association.”*' Modlficatlons to the original data were made to convert from cost per unit
weight to cost per unit energy and to convert to a constant 1974 dollar basis. Although the heating
value of coal varies substantially even within a given rank, the following values, used by the NPC,”

were adopted for this study:

 

Ranl ' Heatmg value
- (to® Btu/ton)
--Bituminous. - : 23
" Subbituminous - 1
Lignite . 135

. Price ad]ustments to January 1974 were made usmg the wholesale price index for 1ndustr1a1

 commodities.

A]though there are no compflatlons of current coal prices, it is evident from various reports that
coal pnces along w1th those of other fuels, rose dramatlcally in late 1973 and early 1974,

 

78. U.S. Bureau of Mines, Mineral Yearbook 1971, vol. 1, “Metals, Minerals, and Fuels.”

79. National Coal Association, Bituminous Coal Data—I1970 Edition, March 1971.

80. U.S. Bureau of Mines, “Coal-Bituminous and Lignite in 1972,” Mineral Industry Surveys, Nov. 15, 1973.
81. National Coal Association, Bituminous Coal Facts—1972.

 
 

152

ORNL-DWG 7412800

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

90 -
NOTE: ALL PRICES ADJUSTED TO |
CONSTANT JAN. 1974 DOLLARS @ EASTERN
LOW-SULFUR
80
70
HISTORICAL PRICES
: O U.S. AVERAGE
_ A MONTANA HIGH—SULFUR
2 V NORTH DAKOTA
© (LIGNITE)
o REPRESENTATIVE
3 JAN. 1974 PRICES
‘ w 50
| Z
| s
o
O
L
g 40
o
a.
- |
<
O
o
30
@WESTERN
SUBBITUMINOUS
: 20 o WESTERN
? \ LIGNITE
10
|
|
|
0
1964 1966 1968 1970 1972 1974

YEAR

Fig. 6.5. Trends in coal prices.

 
 

 

153

The Tennessee Valley Authority (TVA)® reports that prices range from $8 to $30 per ton (f.0.b.
mine), depending on the type of contract, quality of coal, and location. A reasonable range for
high-sulfur (3 to 4%y strip-mined coal from western Kentucky and southern Illinois is $12 to $18 per
ton (f.0.b. mine) or 50¢ to 75¢/10° Btu. Coal purchases®’ for AEC plants in Kentucky and
Tennessee made in the fall of 1973 were at a price of $9.75/ton. Recent (January 1974) prices were
about $15 per ton (3.4% sulfur, 12,500 Btu/Ib) or 60¢/ 10° Btu. The South Carolina Public Service
Authority reported® a coal price increase of 39% in the last five months of 1973. As of Jan. 1, 1974,
the delivered price was $17.25 per ton. After allowing for transportation, the mine price is inferred to
be $12 to $14 per ton. Public Service Electric & Gas Company (New Jersey) (PSE&G) paid an
average of $25.36 per ton for low-sulfur coal delivered during January 1974.% This represented a
44% increase from the average price in October 1973. The range on January 1974 delivered prices
paid by PSE&G was from $22,90 per ton for coal under contract to $29.51 per ton for spot
purchases. These figures suggest a mine price of $18 to $25 per ton for eastern low-sulfur coal.

~ Recent data available on western coal prices are sketchy. Nebraska Public Power District
purchased Colorado and Wyoming low-sulfur coal for 55¢ to 62¢/ 10° Btu (delivered) during
October and November 1973. Allowing $5 per ton for dehvery to plants at Lincoln and Bellvue, the
derived mine cost would be 30¢ to 43¢/10° Btu.

November 1973 purchases by Black Hills Power and Lighting®’ of subbituminous low-sulfur
coal from Wyoming for plants at Osage, Wyoming, and Lead, S.D., ranged in delivered prices from
20.3¢ to 32.8¢/10° Btu. Since the power plants are relatively near coal fields, the transportation cost
would presumably be on the order of 5¢/10° Btu. Recent delivered prices*’ of lignite at plants in
North Dakota and Montana ranged from 11.6¢ to 28.7¢/10° Btu. Since these power plants are near
the lignite deposits, the transportation component of the delivered price should be small. The general

“impression is that western coal prices have not increased as substantially as those for eastern coal.

Representative prices derived from the sources described above, shown in Table 6.4, range from

18¢/10° Btu for western lignite to 86¢/10° Btu for eastern low-sulfur bituminous coal. In

86487

 

82. Personal communication, Frank Aiford TVA Chattanooga, T. D. Anderson, Oak Ridge National Laboratory, Feb.
15, 1974,

83. Personal communication, Marvin Schwenn, Union Carbide Nuclear Division, Oak Ridge, Tenn., T. D. Anderson,
Oak Ridge National Laboratory, Feb. 15, 1974.

84. Public Power Weekly Newsletter, published by American Public Power Association, No. 74-04, p. 4, Jan. 25, 1974,

85. “Soft Coal Prices Soared 118, 5% in 3 Months, Marginally Efficnent Mines Are Reopening,” The Wall Street
Journal, Feb. 8, 1974.

86. Weekly Energy Report, Vol. 2(3), Jan 21, 1974,

87. Elecmcal Week, Feb. 11, 1974,

Tablc 6.4. Representative prices (f.0.b. mine) for coal as of first quarter 1974

 

 

 

H:;t::g Cost ($/ton) _ Cost per 10° Btu (¢)
(Btu/lb) Value Range Value Range
Bituminous (eastern) :
High sulfur (>3%) 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 <N :{ METHANATION
. ,_1
' \ ] NICKEL CATALYST
OXYGEN —p. 1. ;
STEAM §
$ DUST AND SYNTHETIC
TAR - NATURAL GAS

RESIDUAL CHAR [#

 

 

Fig. 6.24. Synthane process.

devolatilization and for uncatalyzed methanation at 593 to 799°C (1100 to 1470°F); and (3) a hot,

‘dilute fluidized bed in the contracted bottom section, where entering oxygen and steam furnish
_reaction heat and material for producing, at 954 to 1010°C (1750 to 1850°F), the synthesis-gas mixture

(H-CO) entering zone 2. Char residue is withdrawn at the bottom of the gasifier, and the gas product
leaves the system at a point between zones 1.and 2. The product gas is cleaned, passed through a water-
gas shift converter, scrubbed almost free of sulfur compounds and carbon dioxide, and methanated
catalytically. = N S L o _

~ A 72-ton/day (1.3 X 10° ft*/day) pilot plant'*® is under construction by the U.S. Bureau of Mines

“and is scheduled for completion by the end of 1974.

6.5.4 Economic Analysis B
Lurgi process . |

The Lurgi process' is the only commercially available process for producing high-Btu gas from
coal. An excellent source of economic data for this process is from El Paso’s Burnham Coal Gasification
Project (Table 6.28). ’ '

 
 

204

 

 

Table 6.28. Burnham Coal Gasification Project data® , \./
Gasification technology Lurgi

, Plant capacity ' | 288 x 10° scf/day
3 Coal required 28,249 tons/day
'} Coal analysis (est. average)
: Btu/lb _ 8664

Ash ' : 19.3%

Moisture - 16.2%

Volatiles 30.7%
! Fixed carbon _ : 33.8%
Sulfur , 0.69%
High-Btu gas (higher heating value) 972 Btu/scf
Gross investment . $491.36 million
Employment " 833 fulltime employees
; Site area (gasification plant) 960 acres
- Annual water required for gasification - 8253 acre-ft
| plant '
- Annual operating and maintenance cost $31.97 million
: (excluding coal cost)
Bv-products ~ Sulfur, coal tar, tar oil,
naphtha, crude phenol, and
: ' ammonia solution
l Annual income from by-products $15.86 million
1‘ Projected load factor 0.91
! “Cost data in mid-1973 dollars.

Using the example ground rules of 22.29% fixed charge rate and 50¢/10° Btu for mine-mouth
subbituminous coal, the cost of high-Btu gas from the Lurgi technology can be determined as follows:

288 X 10° scf/day plant (Lurgi)

Annual cost capital = $491.36 X 10°

= $109.08 x 10°
Annual cost O&M = $31.97 x 10°
Annual cost coal = (21,283 tons/day)(2000 Ib/ton) (11,500 Btu/lb) = 489,500 x 10° Btulday
Cost per day = ($0.50/10% Btu)(489,500 X 10° Btu/day) = $244,750/day
Annual cost = ($244,750/day)(365 day/year)(0.91 load factor) = $81.29 X 10¢
Total annual cost = $222.35 X 10°

Annual pmductlon high-Btu gas = (288 X 10° sct‘lday)(365 day/year)(0.91 load factor)
= 95,660 X 10° scf/year
= (95,660 X 10° scf/year)(972 Btu/scf) =92.98 X 10'2 Btu/year

$222.35 X 10% /year
/ = $2.39/10° Btu

High-Btu gas product cost = ~—————— o .
s g P 92.98 X 10'2 Btu/year .

 

e —————— e
 

 

205

Economic potential of developmental processes |

Estimates of the investment and operating costs of the gasification processes under development
have been published.'? These figures are based on small-scale test data and are quite variable. Until
pilot plant verification of the assumptions used in plant designs and cost estimates becomes available, it
appears proper to use these estimates primarily to guide the research and development programs.
Nevertheless, it is possible to derive an idea of the potential of the cost savings these processes may

provide upon satisfactory completion of the work now under way.

| The available estimates differ widely and are based ona variety of coals and on a variety of means of
carrying out the required reactions. The plant investments for capacities of about 250 million scf/day,
including utility facilities, range from about 55 to 95% of the Lurgi estimates on an equivalent basis.
Although the first plant of any of the processes under development will cost more because of allowances
that will have to be included to ensure dependability, it seems reasonable that some of the new processes
should provide savings over the established process. Real savings would appear to be available as a
result of the incorporation of increased direct hydrogenation in the gasifier and decreased downstream
catalytic methanation, resulting in an important decrease in endothermic heat requirements.

A potential savings in capital investment of perhaps 15% would appear to be possible, and a 5%
increase in fuel economy may be achieved. Based on these estimates, one can project a reasonable
anticipated cost for the developmental process of $2.19/10° Btu. In terms of add-on costs over and above
the coal cost, these may be interpreted as $1.89/10° Btu for the Lurgi process and $1.69/ 10° Btu for the
developmental processes, as shown below.

250 x 10° scf/day plant (developmental U.S. processes)

Capital cost = $363 X 10°

'Annual cost of capital = $80.5 X 10°

Annual cost of O&M = $28 X ‘106

Annual cost of coal = 66 X 10° (at.SOdll(]6 Btu)

Total annual cost = §174.5

' Annual revenue requn-ed from hlgh-Btu gas= $125 X 106

Annual productlon of hlgh-Btu gas = (250 x 10° scf/daY)(365 dayslyear)(O 9 load factor) X (970 .
* Btufscf) =79.66 X 1012 ‘Btu '

$174.5 X 10°

6
e e—ee—— = 3 2. t
79.66x 10" Bru 5219/10° B

I-hgh-Btu gas cost = '

6.5.5 'Availabmty |

The Lurgi process is currently avallable Fora 250 X 10° scf, / day plant the antlclpated construction
period (from start of construcuon) is 3 years. '

The developmental processes could be available in about 5 years. This assumes a demonstratlon
plant is started in about 1 2 years with 2'/; years construction time and 1 year for operation. Allowingan
additional 4 years for construction of a plaht, one can see that it will be at least 9 year§ before high-Btu
gas could be available from the developmental processes. -

The cost of steam generation using high-Btu gas from coal is given in Table 6.29.

 
 

 

 

206

Table 6.29. Cost of steam generation using high-Btu gas from coal

Basis: 10° Ib/hr of steam at 750°F, 650 psia;
estimated cost of boiler = $15 X 109

 

 

Annual cost  Unit cost
(10°$) (¢/10° Btu)
Capital charg&s at 22.2% fixed charge rate ;‘ 3.33 42
Operating and maintenance (excluding fuel cost) 0.31 3
Unit fuel cost at production site ‘ '
Lurgi ' ‘ - 239
U.S. developmental - 219
' Houston . -New Orleans
Shipping cost . 18 12
Delivered fuel cost T '
. Lurgi 257 251
U.S. developmental 237 231
Steam cost (at 85% bofler effic:1ency) ;
Lurgi 347 ' 340
U.S. developmental ‘ : . 324 317

 

6.6 LIQUEFACTION AND CLEAN BOILER FUELS FROM COAL

129,130

6.6.1 General Description

The production of synthetic liquid fuels from coal involves the development of technology in two
areas: conversion of coal to liquids by hydrogenation and production of hydrogen from coal at a lower
cost than that available from existing technology.

The main problem in the conversion of coal to liquids is to transform a low-hydrogen-content solid
into a liquid containing substantially higher amounts of hydrogen. The extent of the hydrogen addition
is illustrated in Table 6.30. In normal petroleum refining, the hydrogen consumption may be in the order
of 500 to 1500 scf/barrel, depending on the specific type of processing used and the properties of the
refinery feedstock. Experience in coal liquefaction has shown that much more hydrogen processing is
needed, requiring large amounts of hydrogen and severe processing conditions. To convert the organic
material in coal to a petroleum-like liquid theoretically requires about 5000 scf/ barrel. This amount of
hydrogen would suffice to remove the sulfur, oxygen, and nitrogen compounds and yield a liquid
containing about 13% hydrogen without producing any substantial amounts of light hydrocarbon gases.

In practice, the hydrogen consumption is much higher, ranging from 6000 to 10,000 scf/ barrel, due
primarily to a substantial production of light hydrocarbon gases and to loss of hydrogen into the
unliquefied solid residue. As a result, the production of hydrogen represents a major factor in coal
liquefaction and the processing of coal liquids.

Other problems arise from the nature of coal itself. The presence of organic nitrogen compounds
inhibits many of the reactions in converting the coal liquids. Further, the presence of ash has several

 

129. U.S. Energy Outlook: Coal Availability, National Petroleum Councfl 1973.
130 H C. Hottel and J. B. Howard, New Energy Technology: Some Facts and Assessments, MIT Press, 1971.

 
 

207

Table 6.30. Typical analysis (wt %)
of coal, solvent-refined coal (SRC),
and crude liquid from coal®

 

 

Analysis Bituminous coal "~ 8RC Petroleum
c 60.0 ' 88.4 86
H 4.1 5.2 _ 13
0 - 63 ' 3.7
N | 1.2 , 1.8 0.1
S 2.4 0.8 0.9
H,0 - 16%
Ash 10 0.1

Total 100 : 100 100

 

“Approxunate H, reqmrements (Ib H, /ton coal) syncrude,
130; SRC, 25 to 30.
Moisture varies widely with coal source.

harmful effects. In carrying out catalytic reactions, the ash can cause plugging of the bed and
deactivation and permanent damage to the catalyst. The ash and unconverted organic residues also pose
a waste disposal problem, which may be costly and also require substantial antipollution measures. A
further technical problem arises in separating the heavy liquids from the solid resid ues. The unconverted
solids have a small particle size, many being below 10 u, requiring appreciable and careful processing to
prevent a loss of liquid yield due to sticking or occlusion with the fine solids.

' Many of the techniques for processing coal are geared to circumventing various aspects of the
above problems. Some of the general techniques are described in the following sections.

6.6.2 Technology for Coal Liquefaction

Pyrolysis

The general technique of pyrolysis seeks to recover liquids from coal by the application of heat
without the direct addition of hydrogen. In essence, this technique would reject carbon as a solid and
recover a liquid containing a substantial amount of hydrogen. Pyrolysrs processes, in general, operate at
temperatures above 427°C (800°F) and at atmospheric pressures. The specific temperature used is
normally determined by the desired quality and end use of the char product. In general, pyrolysis makes
a very low oil yield, usually less than about 0.8 barrel per ton of coal. '

Fischer-Tropsch process -

" The Flscher-Tropsch process was ongmally developed in Germany for the synthes1s of
hydrocarbon liquids from gaseous CO and H». The synthesrs gas could be made from steam reforming of
‘methane or by gasxfymg coal. The liquid product is a highly oxygenated 11qu1d If high-quality motor
fuel is desired, the oxygenated llqlud must be further processed with hydrogen to remove most of the
oxygen o : '
~ Some appllcatlon of this process was rnade in Germany from 1936 to 1939. This process and others
were also employed in Germany during World War II. Immediately after World War 11, a large pilot
plant was built in Brownsville, Tex., using methane as the primary feed. However, severe technical
difficulties were encountered in the synthesis reactions, and the project was abandoned.

 
 

 

 

208

In general, the economics of the Fischer-Tropsch process are considered unfavorable for fuel
products. '

Catalytic hydrogenation

The processes which have been studied most extensively for the conversion of coal involve the use of
a catalyst. It is possible to react hydrogen directly with coal in the presence of a catalyst and a slurry oil
vehicle to produce gas, oil products, and a solid residue. Many catalysts were developed in Germany
prior to World War II and have been extensively studied in the United States. Early work involved the
use of cheap “throwaway” catalysts such as iron oxide and iron oxalate, which were discarded with the
solid residue. The general reaction conditions were extremely severe—pressures generally in the range of
5000 to 10,000 psia and temperatures usually 454° C (850° F) or higher. Immediately after World War 11,
the U.S. Bureau of Mines built a large demonstration plant for this process at Louisiana, Mo. In general,
the plant operated successfully, but the economics of the process were extremely poor.

Subsequent research into this type of processing has been aimed toward (1) developing better
catalysts so as to lower the severity of reaction conditions (with accompanying improvement in yields)
and (2) developing new technology for gas/solids contacting.

Hydrogen donor solvents

Another approach to coal liquefaction is to remove the coal ash by dissolving most of the coal in a
hydrogen donor solvent prior to the catalytic hydrogenation step. The basis of this process is to heat coal
in the presence of a hydroaromatic material, such as tetralin or its analogs, at 371 to 454°C (700 to
850°F) and 200 to 1000 psia pressure. The coal gradually dissolves, and the large coal molecules are
stabilized by the transfer of hydrogen from the donor solvent to the coal fragments.The unconverted coal
and ash are filtered from the solution of solvent and extract. The spent solvent is subsequently recovered
from the extract and rehydrogenated for recycle. This procéss was originally developed in Germany and
is known as the Pott-Broche process. It was applied to some extent in Germany during World War II
and has been pursued in the United States by CONSOL. In general, the liquid product is an extremely
heavy extract—its molecular weight is well above 1000, thus requiring that the extract be upgraded
substantially to make fuel products. This upgrading can be accomplished by adding hydrogen
catalytically (e.g., using an ebullating bed of catalyst). A fixed bed can also be used if the extract is
essentially free of solid particles. |

Low-sulfur fuel oils from coal

Heavy fuel oils can also be produced from coal. Since a great deal of the sulfur in coal is tied up as
inorganic constituents of the ash, it is possible, by liquefaction and removal of the ash, to produce a
heavy fuel oil (or de-ashed coal) from which a portion of the sulfur has been removed. This materialhasa
high melting point [above 93°C (200° F)]. The sulfur content of the de-ashed coal depends on the coal
feed. The usual type of processing consists in contacting coal (in a slurry oil vehicle) with hydrogen at
1000 to 5000 psia and 399 to 454°C (750 to 850°F). Under these conditions, the coal depolymerizes
suff_icierntly, 30 that the total mixture can be filtered to recover the heavy oil product and a solid residue.

 
 

 

209

6.6.3 State of Development and Commercial Availability

Coal liquefaction is not as close to commercialization as coal gasification. However, there are some
definite advantages to liquefaction as compared with high-Btu gasification which merit consideration.
Less hydrogen is required to convert coal (CHo.7-.9} to a liquid fuel (about CH () than is needed for
production of pipeline gas (CHa), and synthetic fuel oil is easy to store. Costs for transportation of oil are
about half those for pipeline gas. The energy conversion efficiency of coal liquefaction is considerably
better than that for high-Btu gas production from coal and approximately equalto that for low-Btu gas
production with present technology. -

Four major processes that offer merit in coal liquefaction are being funded by the OCR (over $20
million each). These processes (solvent-refined coal, CONSOL, COED, and H-coal) are described in
more detail in the following section.

6.6.4 System Characteristics

Solvent-refined coal'*'™'*

If the only objective of coal treating is to produce a c_leein fuel, hydrogenation to produce solution
can be minimized and be followed by ash separation and conversion of sulfur to removable form.
Solvent refining was initiated with the limited objective of producing ‘a low-cost antipollution
alternative to residual oil and natural gas for use under boilers.

A process flowsheet is given in Fig. 6.25. Coal from crushers (~1/8 in.yis slurried with anthracene-
oil-type solvent and 30 to 40 Ib of hydrogen per ton of coal. The slurry is heated and passed to a high-
pressure flash vessel at a temperature such that the liquid is filterable. The vapor stream from this stage is
processed through a series of flash vessels at successively lower pressure and temperature to separate
various fractions for hydrogen recycling, phenol and cresylic acid recovery, and acid gas removal.

The liquid portion of the dissolver effluent is flashed to the filter pressure and passed to precoated
rotary filters for the removal of the mineral residue, which includes nearly all the ash, all the pyritic
sulfur, and half the organic sulfur in the coal (bringing the sulfur content below 1% for most American
coals). The residue is solvent-washed and stored for use as a fuel. Gas from the filter is removed and
combinéd with the condensate from the vapor removed from the dissolver effluent for treatment.

The liquid filtrate is heated and flashed in'a vacuum vessel. The liquid residue from this stage can be
used either in liquid form as a fuel or solidified to form the final fuel product. The solidification process
at commercial scale is likely to require considerable development, but Stearns-Roger has indicated the
use of flaking drums and silos for product solidification and storage.

The condensate from the vapors removed by the vacuum flash stage passes through two
fractionators to recover various products. The first separates coal solvent from the wash solvent for the
mineral residues and light oil products; and the second separates wash solvent from the light ends.

' Vapors from this process are recovered for processing in the acid gas removal plant, while the final liquid
yields phenols, cresylic acid, and light oil. An additional planned by-product of the plant will be sulfur,

 

131. B.K. Schmid and W. C. Bull, Production of AshIess Low-Sulfur Boiler Fuels from Coal, Pmsburghand Midway Coal
Mining Company, September 1971,

132, Economic Evaluation of a Process to Produce Ashless, w-SuI_’fur Fuel from Coal, Pittsburgh and Mldway Coal
Mining Company, OCR R&D Report 53 (November 1959).

133. Everett Huffman, Southern Services, Inc., personalcommunication to J. E. Jones, Jr., ORNL, February 1974 and June
1974.

 
 

 
   
       
    
  
 
 
    

PULVERIZER

HYDROGEN

" ASH AND RESIDUE

  

SLWRRY

SLURRY PRE-HEATER

MIX TANK

     

RAW GAS

COAL SLURRY

 

|, SOLVENT _ RECY

SOLVENT

. RECOVERY
PRODUCT UNIT
FILTER AND SOLVENT ‘

   
   
 

i 800°F, 150 psi

TO HYDROGEN 'SOLVENT REFINED COAL " §
PRODUCTION AND
ASH DISPOSAL

Fig. 6.25. Solvent-refined coal process.

RECYCLE
HYOROGEN

ORNL-DWG 73-7747

SULFUR

 

ABSORBER LIQUID

 
 

L,

01¢C

 

 
 

 

211

coming from a Claus process running on the H.S from the acid-gas-removal unit and the SO; from the
flue gas generated by burning the mineral residue from the filters.

A variation of the original process is the splitting of the liquid de-ashed product stream into two
parts, one of which goes through a delayed coking process which adds coke, coke gas oil, and more light
oil to the original products. -

A 50-ton/day SRC pilot plant located near Tacoma, Wash,, is essentxally complete and scheduled
for startup about Sept. 1, 1974. A smaller SRC pilot plant (6 tons/day) has been built by the Southern
Company and Edison Electric Institute in Wilsonville, Ala. This plant was completed about Sept. 1,
1973, and is presently in the shakedown and development stage. -

The 6-ton/day plant uses Kentucky No. 14 coal, which is 3.9% sulfur, roughly half organic and half
pyritic. The process is expected to remove cessentially all the pyritic sulfur and 60% of the organic sulfur.
A recent sample of the SRC product has 0.6% sulfur and a 15 840- Btu/lb higher heating value.

A 45-day continuous run at two-thirds of full design load was recently completed. The first part of
the run was concentrated on the front end of the process and the mineral filter was only on line during
the last 20 days.

Hydroclones are presently being 1nstalled which will be tested as an alternate to the rotary precoat
filter.

CONSOL process

In the CONSOL process'* for synthetic crude production (Fig. 6.26), coal containing 2% moisture
is crushed to 8 mesh or finer, slurried at 93°.C (200° F) with a process-derived hydrogen-donor solvent in
the ratio of 1 part coal to 2.5 parts of solvent, and heated to 371 t0 427° C(700 to 800° F), where the coal
undergoes a complex dissolution and cracking process from which gases and water are evolved. The
remaining liquid is a high-molecular-weight black oil having a melting temperature around 204°C
(400°F) and consisting of solvent and 50 to 70% moisture- and ash-free coal in solution, with
undissolved coal and ash in suspension. The black oil extract is cooled to 260 to 371°C (500 to 700°F)
and put through cyclone separators to form a relatively solids-free stream and a solids concentrate. The
latter is sent to a low-temperature carbonizer where it undergoes severe cracking to produce char and
synthetic distillates. : -

The filtrate or cyclone overflow stream is flashed, and the bottoms are washed with water at 1750
psi and 304°C (580°F) to remove the residual ash. The resulting ash-free extract is hydrogenated with
zinc chloride catalyst in an ebullated bed operating at 4200 psi, and the hydroproduct is dropped in
pressure and separated by distillation into heavy recycle solvent bottoms (containing the hydrogen
donor) and synthetic crude product. The solvent bottoms are retumed to the coal-slurrying point.

The Consolidation Coal Company has for many years ‘been developmg processes for making
synthetic liquid fuels from coal, leading in 1963 to a contract with the Office of Coal Research for design
of a pilot plant.'*® The plant, dedicated in 1967, was intended to make liquids in the gasoline range and
was christened Project Gasolme (Consolidation Coal Co.; ;1970). Later studies indicated the advisability
of changing the objective to the manufacture of 1ow-su1fur synthetlc crude oil; the latter process was

described above.

This process has been subjected to detailed exammatlon by a Natlonal Academy of Engmeermg

" Panel and the Foster Wheeler Corporation, resulting i in a recommendation for extensive modifications

 

134. Engineering Evaluation and Review of CONSOL Synthetic Fuel Process, Foster Wheeler Corp., February 1972.
135. J. B. O’'Hara, Ralph M. Parson Company, personal communication to J. E. Jones, Jr., ORNL, February 1974.

 
ORNL-DWG 741806

 

FUEL GAS——>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
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= il — —_— — % 0&M
« I — — —
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s \
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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

 

  
    
    
     
    
  

 
    

    

        
      
  

 
    

      

 
    
 

  
   
     

 

 

 

    

 

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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
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= (XX Q
= - -
- 150 — F o&Mm
w
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<
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.—
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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

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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

 

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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

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STEAM COST (¢/10° Btu)

—
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| HTGR 2000 MW 2-UNIT STATION IND. FINANCING
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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

 

 

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- -

(Mg g01/8) 1SOD IVOD

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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’
<zt 20 ,’
[
S /

/
/
/
/
/
/
/
/
,/
10 >
[-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
~<d -~ ‘
~"'h \.-
~ ~ HTGR LOW
“ -~
\\ ot -
\\'
-
100 ~ — - S 100

™

\ ) .
s,‘_c_r_es_c; HIGH

\\\ \
\,

 

 

 

~—dee o S_CNSG REFERENCE
. ~
-
-
-~ el
\ - 1
50 \\ T - - o = o -,
e ““

PWR, CNSG FABRICATION COSTS ($/kg)

\' .
Mool T ke twRHeH
"'---....\..._ LWR REFERENCE
o LWR LOW

 

 

 

 

 

 

 

 

1970 1980 1990 2000 2010 2020 2030
YEAR

Fig. A4. Fuel fabrication unit costs.

Fuel Recovery

In our economic calculations, the fuel recovery costs include shipping of spent fuel, fuel |

reprocessing, waste disposal, and conversion of uranium to UF; for retumn to the diffusion plant.
The unit shipping charges, assumed to remain constant in time, are given in Table A.1.

For the fuel recovery cost, excluding the shipping charge, we use the cost structure assumed in
the LMFBR cost/benefit analysis work. The values used here for the PWR unit costs represent a

 
 

 

 

263

445

significant increase in estimated cost when compared with previous estimates.”” The current

estimates represent a more realistic approach to costs of a yet unbuilt plant and to the costs of waste
disposal. The range of uncertainty for the PWR fpel reprocéSsing unit costs was taken at £10% in
1980, increasing to +200 in the year 2000. These unit costs are plotted in Fig. A.5. The CNSG
recovery costs were assumcd to be the same as those for other hght-water reactor fuels.

 

4. Reactor Fuel Cycle Costs for Nuclear Power Evaluauam', WASH-1099 (December 1971).
3. Guide for Economic Evaluation of Nuclear Reactor PIant Designs, NUS-53I NUS Corporation (January 1969).

ORNL--DWG 74-6170

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

250
200
=
%
E
§ 150
[r =
I
Z
@
-
[7]
Q
O
>
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
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294

 

 

 

ORNL-DWG 7412743
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Fig. F.1. Population risk factors for Houston ships channel.

DISTANCE (km)

 
 

 

 

RISK FACTOR

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295

ORNL-DWG 74-12743
PART B

 

 

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2

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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
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0.39
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297

ORNL-DWG T4-12744
PART 8

 

 

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7 BAY PORT

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. - DISTANCE (km)

Fig. F.2 (continued)

DISTANCE {km)

 
RISK FACTOR

 

298

 

0.266 5
1 TEXAS QITY

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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
\
.

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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