PB82-232372
An Assessment of Central-Station
Cogeneration Systems for Industrial Complexes
Georgia Inst. of Tech.
Atlanta
Prepared for
Industrial Environmental Research Lab.
Cincinnati, OH
Apr 82
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EPA-600/7-32-017
April 1932
AN ASSESSMENT OF CENTRAL-STATION COGCNERAi'ION
SYSTEMS FOR INDUSTRIAL COMPLEXES
by
NeiJ B. Hilsen
George R. Fletcher
David L. Kelley
Jeffrey S. Tiller
Stephen W. Day
Georgia Institute of Technology
Engineering Experiment Station
Atlanta, Georgia 30JJ2
Contract No. 68-03-23^*
Project Officer
Benjamin L. Blaney
Energy Pollution Control Division
Industrial Environmental Research Laboratory
Cincinnati, Ohio 45263
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
U.S. ENVIrtO.NMEMTAL PROTECTION AGENCX
OFFICE OF RESEARCH ANt DEVELOPMENT
CINCINNATI, OHIO U5268
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TECHNICAL REPORT DATA
' Hi aw r, a*i liulrui IH'in un in, ,vi( r\, hi Inn i umplt ling
1 REPORT NO
II.>.»TV,-II ion
i COSATi I lelii/dioup
u B:STBIBUTION STATEMENT
EP* Form 1220-1 (R»« 4-77) »»E vous ECU "ON 9 ORIOLE ft
19 SECURITY CLASS
21 NO OF PAGES
7O SECURITY C^AS3 iThiipanel
22 PRICE
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory, U. S. Environmental Protection Agency (EPA), and approved for
publication. Approval does not signify tnat the contents necessarily reflect
the views and policies of the U. S. Environmental Protection Agency, nor
does mention of trade names or commercial products constitute endorsement
or recommendation for use.
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FOREWORD
When energy and material resources are extracted, processed, converted,
and used, the related pollutional impacts on our environment and even on
our health often require that new and increasingly more efficient pollution
control methods be used. The Industrial Environmental Research Laboratory-
Cincinnati (lERL-Ci) assists in developing and demonstrating new and improved
metnodologies that will meet these needs both efficiently and economically.
This document reports the methodology and results of an analysis of
the environmental, economic, and energy conservation aspects of the appli-
cations of cogeneration principles to form a cogeneration system. The
methodology concentrates on the comparison of systems that perform the
same functions by using conventional energy conversion techniques and by
using cogeneration techniques. Therefore, the methodology and conclusions
in this report can be useo by planners and policy makers in industry and
government to evaluate specific projects or concepts involving the large
scale application of cogeneration principles. This report will be of inter-
est to those who are involved in environmental, economic, and energy related
research. The Alternate Energy Sources Branch, Energy Polution Control
Division should be jontacted for further information on this subject.
David C. Stephan
Director
Industrial Environmental Research Laboratory
iii
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ABSTRACT
This report assesses the potential for (regeneration system development
based on an analysis of the economic, environmental, energy efficiency and
social aspects of such systems. The cogeneration system is an application
of the principle of cogeneration in which utill.y-sized power plants supply
both electrical and steam needs to one or more nearby industries Such a
system can result in increased energy efficiency, reduced pollutants, and
reduced overall cost. A number of methodological approaches, including
environmental impact analysis, were used to investigate the broad scope of
issues relevant to cogeneration system development. As the study considered
the subject from a general, comprehensive, planning-level perspective, the
quantitative results cannot be applied to other sites. However, trends
associated with the impacts of cogeneration development are identified, and
methodologies which are applicable to cogeneration systems in general are
employed.
The conclusions and recommendations reveal that cogeneration systems
are viable and attractive alternatives to conventional power systems.
Tnere are potentially important environmental benefits associated with
these cogeneration systems but also environmental problems.
This report was submitted in fulfillment of Contract No. 68-03-2394 by
the Georgia Institute of Technology under the sponsorship of the I) S. Environ-
mental Protection Agency. This report covers the period March 11, 1976, to
March 31, 1978. Work was completed November, 1981.
IV
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CONTENTS
Page
Disclaimer notice }*
Foreword ll-i
Abstract iv
Figures vii^
Tables .**
Note on units xiii
Application of SI Prefixes *iv
SI to English Conversion Table xv
Acknowledgements xvl
l. Introduction 1
Purpose 2
Scope limiting assumptions 3
Level of detail 3
overview 4
2. Conclusions 5
Technical 5
Energy and economic 5
Environmental and social 0
3. Recommendations 7
Cogeneration planning and design 7
Policy formulation 8
4. Overall Approach y
Cogeneration system definition 10
Basic methodology 1L
Industrial applications 15
Candidate industries 15
Thermal and electrical demands 16
Industry-power plant compatibility 16
5. Energy 2C
Energy analysis 20
Power plant model 20
Piping energy loss model 27
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efficiency model 27
Air pollution control energy loss model 27
Energy analysis example case do
t>. Environment 32
Environmental analysis 32
Air emissions 32
Water consumption 3d
Solid waste production 38
Wastewater combined treatment 39
Environmental analysis example case 40
Air emissions 41
Water consumption 41
Solid waste production 43
Wastewater combined treatment 43
7. Economic 49
economic analysis 49
Status quo system costs 52
degeneration system costs 55
Fuel cost? 59
Air pollution control costs 60
Ecnonic analysis example case 64
Capital costs 65
Operation and maintenance costs 66
Life-cycle costs 67
Sensitivity of cost variables 08
Sensitivity of fuel costs 69
Sensitivity cf discount rate oy
Sensitivity of the capital costs of power
plants 75
Sensitivity of energy transport distance T.
In-plant cogeneration 75
3. Institutional and Social Impact 78
Institutional constraints 78
Institutional inertia constraints 78
Capital formation constraints 78
Contractual constraints 79
Environmental regulatory constraints 79
FPC regulatory constraints 79
Licensing, oermits, arid right-of-way constraints . 79
Public approval constraints 80
Social impact analysis 80
Multiplier models 81
Social impact models 82
Social impact analysis example case 84
Cogeneration system 86
Large regeneration system in a large host
community 86
VI
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Pea* construction phase ........... 90
Phase just prioi to operation ........ 91
Full operation phase ............. 92
Large cogeneration system in a small host
community ............... 92
P .ak construction phase ........... 93
Phase just prior to operation ........ 93
Full operation phase ............ 94
Generalization of results ............... 91
........................... 97
BldLIOl^RAPHY .......................... 102
APHtN DICES
A. Cost-Benefit Analysis ................. Ill
3. Technology Survey ................... 114
C. Description of MAIES Computer Program ......... 1j6
U. Social Impact Analysis Multiplier Models ....... 157
vii
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FIGURES
Number
1.
2.
3.
4.
5. .
6.
7.
3.
y.
10.
n.
12.
13.
T4.
15.
10.
T7.
Basic methodology for evaluation of a cogeneration
systen
Cogeneration system analysis approach
Block diagram of power plant model
Reduction in emissions for a cogeneration system
compared to a status quo system
.Schematic diagram of system compontents
Cost of constructing coal -fired power plants ....
Pulvenzed-coal steam plant unit capital costs as
AFBC steam plant unit capital costs as a function
of plant capacity
Cost of fuels
Impact of first year coal price on net present
value
Impact of coal price escalation on net present
value
Impact of discount rate on net present value ....
Page
11
12
13
11
22
2*4
30
42
50
53
54
56
57
61
71
72
73
viii
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la. Impact or capital cost on net present value ..... 74
19. Impact of steam transport distance on net
present value .................. 76
2P. Population effects for the construction phase:
large cogeneration system concept in a large
host community ................. 83
21. Steps in social impact analysis ........... 65
22. Cogeneration system construction profiles ...... 87
23- Relative sizes of the cogeneration system
concept and the host community ......... 96
B-l. Steam-electric power generation ........... 115
B-2. Temperature-entropy (T-S) diagram of the basic
Rankine cycle .................. 116
3-3. Improvements in basic Rankine cycle
ri-4. Power cycle diagram of modern fossil fuel
power plant ................... 119
b-5. Material flows through coal fired boiler ...... 121
B-6. Pressurized and boiling nuclear power cycles . . . . 125
3-7. Potential increase in available energy from
steam extraction ................ 127
B-3. Effect of steam extraction on electrical power
production ................... 128
B-9. Effect of steam extraction on system efficiency . . . 128
C-l. Flowchart of the MAIES computer program ....... 1t2
D- 1 . Population effects for the construction phase:
large cogeneration system concept in a large
host community .................. 159
D-
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Long run population effects of the industrial
activity: large cogtuieration system concept
in a small host community 169
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TABLES
Number Page
1. Industrial energy requirements ............ 1b
2. Relationships between steam demands and power plant
steam source ..................... 21
3. Definitions of efficiencies, mass flow and
enthalpies for power plant model ......... 23
4. Enthalpies and efficiencies used in power plant
model calculations ................ 26
5. Energy penalties for pollution control methods on
coal barn ing boilers ............... 29
6. List of emission factors ............... 33
7. Level of emission control for utility and industrial
air pollution control methods ........... 33
d. Air pollution control systems used in analysis .... 3t
9. Estimated cost savings due to pollution control
reduction ..................... 43
10. Solid waste analysis of example case
11. Cost savings from combined treatment of wastewater
from various cogeneration system industries .... 46
12. Capital cost of pipins (1977 dollars) ........ 58
13. Turbine cost savings ................. 58
14. Cost savings due to reduced cooling requirements in
a cogeneration system with natural draft cooling . 59
15. Cost of additional generation ............ 60
xi
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1t>. Range of air and thermal pollution control equipment
costs for a 1000 Mw utility power plant 62
17. Range of air and thermal pollution control equipment
costs for a 12.6 kg/sec industrial boiler °3
18. Economy of scale factors for air pollution control
technologies 6U
19. Capital costs of example systems 65
20. Operation and maintenance costs of example systems . . 66
21. Fuel costs of example systems 67
22. Net present value computation 68
23. Ranking of cost parameters oy sensitivity 70
21. Large cogeneration system in a large host community . 88
D-1. Large cogeneration system in a large host community . 172
D-2. Large cogeneration system in a small host community . 174
D-3. Peak construction phase-comparison of changes .... 176
U-<4. Phase just prior to operation-comparison of changes . 178
D-5. Full operation phase-comparison of changes IdO
D-b. Peak construction phase-comparison of changes .... 182
U-7. Phase just priot to operation-nuclear power plant . . 181
D-8. Full operation phase-nuclear power plant 186
xii
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NOTES ON UNITS
The calculations performed in Che course of this study were Carried
out using English units of measure. In particular, all computer programs
cited in this report are in English units. After writing the report, the
text and all tables and figures were converted to the International System
of Units (SI), in order to conform with requirements for publications of
the Office of Research and Development, U.S. Environmental Protection
Agency. The only exceptions to this conversion are Appendix C which describes
the contents of the MAIES computer program and Figure 6 which illustrates
the mathematical equations and logic flow in the power plant model. These
two parts of the report were not converted because they describe basic
mathematical tools used in this study. All conversions made by the staff of
the U.S. EPA.
Xlll
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APPLICATION OF SI PREFIXES
Multiplication
Factor
1018
1015
ID"
109
106
103
102
ioi
10-1
10-2
10-3
10-6
10-9
10-12
10-15
10-18
Prefix
exa
peta
Cera
giga
mega
kilo
hecto
deka
deci
centi
milli
micro
nano
pico
ferato
at to
Symbol
E
P
T
G
M
k
h
da
d
c
m
f
n
P
f
a
XIV
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SI TO ENGLISH CONVERSIONS
TO CONVERT FROM TO MULTIPLY BY
kilograms (kg) pounds (Ib) 2.205
kilograms/sec (kg/s) tons/day (TPD) 95.2
kilograms/sec (kg/s) pounds/hour (Ib/hr) 7.94 x 103
cubic meters (cu m) gallons (gal) 2.64 x 10^
hectares (ha) acres (a) 2.47
meters (m) feet (ft) 3.28
degrees celcius (°C) degrees fahrenheit (°F) °F = 1.8°C * 32
pascal (Pa) pounds/sq. inch (psia) 1.45 x 10~^
(absolute pressure)
joules (J) British Thermal Unit (Btu) 9.48 x 10
joules/kilogram (J/kg) Btu/pound (Btu/lb) 4.31 x 10~*
xv
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\tXMU WLalXJMENTS
The significant contributions of the following people are gratefully
acknowledged: Mr. Robert P. Zimmer, overall project management; Or. Neil
B. Hiisen, project director; Dr. George H. Fletcher, technical integration;
Mr. Jeffrey S. Tiller, economic analysis; Mr. Stephen W. Day, environmental
analysis; Ms. Patricia 0. Mathiasmeier, editorial coordination. Significant
contnoutions were also made by Or. Oavid L. Kelly, Mr. Hoy 0. Wilkins,
Or. Peter 3. Sassone, Or. Jack M. Spurloctt, Ms. knita Montelione, Mr.
Armand A. Masse, and Mr. Josepn N. OiNunno. The staff at the Oak Ridge
National Laboratory provided valuable assistance and data. Guidance and
Lecnnical interaction wa. provided oy Doctors C. C. Lee, Harry E. Uostian,
and Benjamin L. Blaney from the Industrial Environmental Hesearcn Laboratory
of the Environmental Protection Agency.
XVI
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SECTION 1
INTRODUCTION
Approximately 26 percent of the national fuel consumption is associated
with the production of electricity. Since electricity production is less
than 35 percent efficient, approximately 17 percent of the national fuel
consumption is waste heat that is associated with electricity production.
Efforts are, therefore, being made to conserve fuel by better utilization
of this wasted energy. One technique for utilizing the heat is to extract
steam from power plant turbine while it still can perform useful work.
The extracted steam can be used in a variety of ways, but a primary use
is for heat in industrial processes, agricultural activities, and heating
and cooling systems.
Europeans have taken the lead in waste heat utilization. Many countries,
especially those in colder climates, have extensive district heating systems
which utilize heat from electric power plants. Waste heat is also used
in agricultural applications, such as greenhouses and soil heating.
The applications investigated during this project concentrate on the
delivery of thermal energy to industrial processes. The general concept
of co-siting industrial operations LS considered in complexes that can
provide mutually beneficial utilization of energy as well as other resources.
A firm basis for co-siting has been established by Isard and others, (1)
and has been discussed in the literature under various names, such as Indus-
trial Complexes, Oecoplexes, and Industrial Parks. Isard and co-workers,
in the 1950*3, pioneered the metnod of industrial complex analysis in inves-
tigating a petrochemical complex for Puerto Rico. Recently, this method
has been extended to include environmental management activities, with
specific reference to a proposed coal power-plant complex in New York State.
A number of reports and papers have been published concerning investigations
of industrial and agro-industrial complexes centered around nuclear reactors.
These complexes are typically Designated as "nuplexes," an acronym derived
from nuclear complexes. Attention has been given to Decoplexes, a term
derived from development/ecology/complexes, which emphasize the grouping
of related industries around waste-treatment plants. Many petroleum and
chemical companies now use a variation of industrial complex analysis in
planning and developing their plant sites. In fact, at the present time
there are many economically sound and well-integrated industrial complexes
in operation or under construction in this country and abroad. Two examples
relating specifically to energy utilization include the electrical utility/
chemical facility at Midland, Michigan and the electric utility/refinery
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arrangement, in Baton Rouge, Louisiana.
Several studies nave reviewed the economic benefits from cogeneration
sys terns. The term co^enera: .on is used 'iere as a oo-nprenensive term whicn
•Jescrioes a power plant tnat supplies both electrical and tnermal energy.
In the United States, industries nave been somewhat reluctant to develop
cogeneration systems in the past due to institutional problems and inexpen-
sive petroleum. Although certain industries nave used oogcneration systems
successfully to satisfy tneir own needs, the full potential for the technique
has not been realized. In-plant cogeneration systems and the large scale
cogeneration systems utilize the same principles, the only difference is
one of scale. In the following report the term cogeneration is used to
refer to cogeneration systems.
In recent years, fuel oil prices have risen drastically to a current
average wholesale price of about $2.20 per CJ. In response, many indus-
tries have resorted to alternative fuels such as coal. However, low sulfur
content coal is in short supply in many parts of the country and the invest-
ment cost required to desulfunze coal makes tne use of high sulfur coal
generally pronibitive. An alternative to this apparent dilemma is to provide
the energy needs of groups of co-sited industries by a large central power
source that can take advantage of economics of scale.
Advantages of cogeneration include the ability to use cheaper fuels
such as nuclear or coal, increases in energy efficiency due to operition
at high temperatures and pressures, and decreases in pollutant emissions
resulting from hign energy efficiencies. Disadvantages include increased
piping and steam extraction cost, increased energy losses from transporting
process heat over large distances, and relatively concentrated pollutant
emissions. In addition to the technical problems, negative social impacts
may result from the construction of a large power plant and a number of
industries in a small host community.
Past studies, which have investigated the techrical and economic aspects
of a cogeneration system, have treated environmental and social impacts
only slightly. The present study addresses environmental and social impacts
as an integral part of a broad-based investigation of the potential impacts
of cogeneration.
PURPOSE
The purpose of the present study is to provide EPA with an up to date
analysis of the environmental, economic, energy efficiency, and social
impacts of integrating a number of industries into a complex and supplying
their energy needs (tiermal and electrical) from a large central source.
The study encompasses a broad area of impacts and tends to be more general
than specific. The results of the study are intended to provide guidelines
about cogi-nor jt nm, r.'ithor ilun .if i ion HIMUS related lo spvcific douils
of cogeneration power plant design.
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In order to fully evaluate the impacts of a new technology, an examin-
ation oT its economics are needed since profitability is a primary require-
ment for any technology to develop commercially. The economic analysis
performed in the study uses average estimates of the major components of
the alternative energy systems (boilers, power plants, air pollution control
equipment, fuel, etc.), rather than costing out specific components in
detail. However, many iapacts are treated separately from the economic
analysis, including air pollution, water consumption, solid waste, and
social impacts. These tyoes of impacts are of sufficient importance that
they are evaluated in detail in the study.
SCOPE LIMITING ASSUMPTIONS
The study is a comprenensive investigation of the planning level consi-
derations associated with cogeneration. It therefore relies heavily on
data that has been obtained from literature and from related studies.
Since tnis study is not site specific, it concentrates on the potential
environmental iapacts and tangible costs associated with practical applica-
tions that could be developed using existing technology.
Power piaiits of tne size 300-1300 Mw electric are considered. Botn
coal and nuclear fuel are considered because these fuels are anticipated
to oe abundant in the coming years, and the technology associated
with electric power production using these fuels is well established.
Fuel for industrial boilers is assumed to be coal, since shortages in fuel
oil and natural gas would limit their application and the purpose of the
study is to evaluate cogeneration, not fuel switching. A detailed engine-
ering design of power plants or specific pieces of equipment is not performed
here. Specific emphasis is placed on available technology and "off-the-
shelf" equipment is considered to be utilized. Industrial processes are
also considered to be unaltered. These assumptions are necessary in order
to limit the scope of the study to a manageable size.
The extent Co which nuclear power plants are considered in this study
is more limited than the analysis of coal-fired power plants. The study
bases the economic and energy efficiency analyses of cogeneration systems
using nuclear power on the assumption that the costs associated with past
nuclear power plants reflect adequate safety and environmental protection.
A more extensive analysis was deemed beyond the scope of this study. For
the same reason, no environmental impact analysis of nuclear power plants
was performed. The social impact analysis described in Section 8 considers
only the impacts of the demographic changes which .tie projected to arise
from either coal or nuclear power plant construction and operation as a
result of changes in the composition of the local workforce and related
impacts on the local economy.
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LEVEL OF JETAIL
The level of detail considered in this study is dictated by the need
for a DroaU-acale, planning level analysis. Specific interrelationships
between power system components are considered only in functional block
fashion, while topics such as steam extraction and piping; tnermodynaoic
energy balance of conventional and cogenerating power plants; and boiler,
piping, turbine, and generation efficiency impacts on total cogeneration
concept efficiencies are considered in greater detail. A power plant model
is used as a computational aid for investigating impacts of thermodynamics,
component efficiencies, and mass flows on cogeneration attractiveness.
The coacs of the components of the alternative energy systems are grouped
into initial investment costs, annual operation and maintenance costs,
and annual fuel costs. Externalities, intangibles and nonquantifiable
effects are not expressed in dollar terms, but are evaluated in the environ-
mental and social impact analysis. A procedure for discounting future
costs and benefits bac* to the present is used so that these items may
oe compared on a life cycle basis.
OVERVIEW
Section 2 of this report presents a summary of the major conclusions
from this study. The basis for these conclusions are addpassed separately
for areas dealing witn technical, economic, environmental, and energy conser-
vation aspects of cogeneration systems. The recommendations in Section
3 are oriented toward cogeneration planning and design as well as for future
policy research and development. Chapter 4 describes the analysis method-
ology and the remaining chapters describe the specific analyses. The energy
related analysis is discussed in Chappter 5 and Chapter 6 discusses the
environmental analysis. Chapter 7 presents tie economic analysis wnile
Chapter 8 closes witn the results of the institutional and social impact
analysis. There are four appendices which provide specific information
to support the material presented in the body of the report. The appendices
cover Cost-Benefit Analysis, and the multiplier model that was used in
tne social impact analysis.
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SECTION 2
CONCLUSIONS
In this study, investigations of various aspects of cogeneration are
made with emphasis on the concept of cogeneration as a total system. Thus,
the analysis is designed to provide conclusions and recommendations about
the concept rather than recommendations of specific technical aspects.
Conclusions can be classified as technical, energy, economic, environmental,
or social. A summary of the major conclusions follows.
TECHNICAL CONCLUSIONS
It is technically feasible to provide processed steam from the same
facility that produces electricity.
A cogeneration system has fewer requirements for cooling than a conven-
tional electrical utility system with a comparably sized boiler.
Less thermal energy would be ejected Into the environment in the form
of waste heat.
Better central transportation would result from a cogeneration system
because the facilities would all be located in close proximity.
ENERGY AND ECONOMIC
Cogeneration systems can realistically achieve an energy efficiency
that is almost twice that of a conventional steam electric power plant.
Consequently, a cogeneration system may have environmental benefits
because less fuel would be used.
Energy converted by a cogeneration system will cost less than energy
from conventional separate facilities; however, a cogeneration system requires
a higher construction cost.
In-plant cogeneration is an attractive option when an industrial complex
is not large enough to warrent the use of a power plant for cogeneration
system or the power plant is not located near the industries.
Numerous combinations of industries can be feasibly integrated. Most
are economically attractive if the requirement for low temperature process
heat is sufficiently large.
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In general, as more steam 13 extracted, the economics of uogeneration
improves. As steam transport distance increases, cogeneration system econo-
mics become less attractive.
ENVIRONMENTAL AND SOCIAL
The increased energy efficiency of a cogeneration system results in
reductions in national air emissions, national water consumption, national
solid waste generation, and land used for solid waste disposal compared
to the use of conventional systems. However, a cogeneration system may
contribute more pollution in the local area due to the increased concentra-
tion of industrial activity.
The integration of facilities in a cogeneration system can produce
economic savings in air and thermal pollution control, and in wastewater
treatment.
The main siting considerations are economic, resource, and environment-
ally dependent, as a cogeneration system can only locate where industries
exist or are planned.
The key environmental issue is whether is is significant that local
increases in air pollutant concentration, water consumption, land use,
and social impact that result from cogeneration development are offset
by national decreases in air emissions, water availability, and land usage
resulting from scattered siting of industry and the use of conventional
energy sources.
The social impacts of cogeneration, as measured by percentage change
in economic and service requirement parameters, are inversely related to
the size of the host community.
Larger host communities have greater capacity to accomodate the cogenera-
tion system needs using existing resources than small host communities;
in fact, a cogeneration system located in a sufficiently large community
would induce a moderately positive rate of economic growth and produce
generally positive changes in community patterns.
Changes in small host communities due to cogeneration system construction
and operation are likely to be so large and so 3udo«?n that they will be
detrimental.
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SECTION 3
RECOMMENDATIONS
The recommendations arising from this study are divided into two cate-
gories: 1) cogeneration system planning and design recommendations and 2)
identification of research areas which EPA may want to investigate further.
Planning and design recommendations are in the form of general guidelines
for use in investigating the potential for cogeneration development at a
specific site. The research recommendations identify areas where informa-
tion is needed to better elucidate the environmental problems and benefits
associated with industrial cogeneration systems.
PLANNING AND DESIGN GUIDELINES
Based on the analyses performed in this study, the following recommenda-
tions are made for optimizing the energy and economic benefits of central-
ized cogeneration, while minimizing the environmental control costs and
socioeconomic problems arising from development.
• Industries should locate as close to utility power plants as
possible.
• Steam extracted for industrial use should not exceed 7 MPa (1000
psi) or 430°C (800°F). The minimum pressure of transported steam
should be 0.7 MPa and should be at saturated conditions.
• Industries should require large quantities of low pressure steam
to obtain maximum system efficiencies. The industries should
condense the steam and return it to the power plant for reuse.
• The power plant should maximize the amount of low pressure steam
extracted for industrial use. Industrial processes should be
designed to interface with the cogeneration system.
• In-plant generation should be a better approach when distances
between industries and utilities exceed several kilometers. The
specific distance depends on technical and economic factors of
the specific system.
• Centralization of other facilities (e.g. transportation, air
pollution control and wastewater treatment) should be achieved
when possible. Industrial co-siting should be sought to provide
inter-industry resource needs, e.g., waste products from one
industry may be used as raw materials for another.
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• The ho Ft community of a laipt> cogeneration system candidate should
be greater than ?0,000 in totil employment and about 100,000 in
total population to avoid significant negative social impacts.
The construction schedule should be constrained when possible,
rather than allowing the capacity of the public facilities to be
exceeded. Manpower planning should be used to minimize the need
for new workers. Housing regulations should be used to control
short term housing problems.
FURTHER RESEARCH
The following areas should be considered for future environmental
research.
• Site specific impact analyses of hypothesized cogeneration systems
located in communities with different characteristics using ambient
air quality modeling, social impact analysis, and institutional
barrier identification and evaluation. The impacts are site
specific, however many of the results can be generalized.
• Study of potential for technology transfer from European countries
with cogeneration experience and from industries utilizing in-
plant generation.
• Identification of the types of sites with potential for current
or future cogeneration system development.
• Study of the impact of environmental quality regulations on
cogeneration development, with emphasis on the impact of environ-
mental standards on proper siting of cogeneration systems.
• Study of the land use impacts of alternative pollution control
strategies, with emphasis on the impacts of disposing of flue gas
desulfurization and fluidized bed combustion wastes.
• Further investigation of the use of cogeneration and process
waste heat for pollution control, particularly wastewater
treatment. A guidebook for use by industrial developers would
be a useful product of such a study.
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SECTION 4
OVERALL APPROACH
The cogeneration systems were evaluated fron energy-efficiency, envi-
ronmental, economic, and social impact points of view. Evaluation of a
cogeneration system from a planning level requires a broad scale analysis.
The overall methodology developed compared proposed cogensration systems
concepts with a status quo system and emphasized determination of cost
differences.
The environmental impact comparisons were based on emission data, pollu-
tion-cent™ i-efficiency data, and relevant environmental quality regulations
and staniar's. The economic analysis employed a cost benefit analysis
approach wnere all future incurred costs and benefits were discounted back
to the present so that they could appropriately be compared with initial
investment costs. The energy efficiency analysis t.ypicrlly consisted of
computing the fuel conauied by the two systems and detei mining whether
the cogeneration systems were more energy efficient than the status quo
systems. Construction, operation, maintenance, fuel costs and annual bene-
fits of the two systems were covered in the economic analysis. The social
impact analysis determined the population impacts of a large cogeneration
system in large and small host communities, and included comparisons between
coordinated and uncoordinated construction.
The evaluation of cogeneration systems and status quo systems involved
a number of trade-offs between environment-1, technical, and economic paramet-
ers. A cogeneration jystem may have higher construction and operation
costs than a status quo system, but it has lower fuel costs. The cost
of a cogeneration system increases as the s»,eam transport distance increases;
thus, large power plants that wish to supply steam to a number of industries
may find the piping expensive. However, smaller plants designed to supply
a relatively small steam load would not benefit from the economies of scale
of larger facilities. The energy efficiency of a cogeneration system may
decrease as additional pollution control systems are added and as steam
transport piping increases in length. The centralization of industries
and powei plants in a cogeneration system may cause severe local environ-
mental and social impacts even though national impacts are lower than in
a status quo system. Cogeneration systems may be technically, economically
and environmentally sound, but may be constrained by institutional problems,
such as public opposition, or difficulties in negotiating industry-utility
contracts. The resolution of these trade-offs is part of the evaluation
area. Some trade-offs may require decision making and are included as
-------
recommendations to be considered during policy formulation.
The approach for comparing tl^a cogenerati'on system and the status quo
system stresses impact differences. Although it is not necessary or practi-
cal to assess absolute impacts of particular systems, relative impacts
are important. For example, in the economic and energy efficiency analysis,
although consideration was given to determining accurate estimates of capi-
tal, ooeration and maintenance costs of a cogeneration system, emphasis
was given to costing those items which significantly differed between the
oogeneration system and the status quo system (e.g., additional piping
costs, piping thermal losses, cooling tower costs, pollutant collection
efficiency, and costs of various air pollution control technologies).
In the environmental analysis, consideration was given to cost savings
achievable by combining effluents from to-located industries to speed the
process of biochemical oxygen demand treatment with major emphasis on the
reduction in treatment tank size.
COGENERATION SYSTEM DEFINITION
The cogeneration system, as described here, is a specific technical
approach by which a large electrical utility supplies both electricity
and steam to a group of centrally located industries. Figure 1 sketches
the primary elements of a cogeneration system. Industries are physically
grouped together, although the grouping may span a number of miles. Electri-
city is supplied from the cogeneration system to the industries in the
conventional sense of a large utility (e.g., a turbine drives a generator
whose output voltage is boosted to some appropriate level for transmission
over high voltage transmission line to the industries). The distinction,
however, between the cogeneration system and status quo system is that
in addition to supplying electrical energy, the utility plant also supplies
thermal energy to industries. The transport medium, once transported,
either may be returned (closed cycle operation) or discarded (open cycle
operation).
Power system backups may be either located at the industries or at
the power plant. All excess steam beyond industry requirements is passed
through a turbine for electricity generation and then condensed by cooling
towers or by heat exchange be-ween a local water supply such as a river.
The types of fuel considered for the cogeneration system include uranium
and coal of various levels of sulfur content.
A status quo system is defined for each cogeneration system concept
considered so that relative cogeneration system impacts may be gauged.
The status quo system consists of utility power plants which provide only
electricity and industrial power plants viiiich provide steam and sometimes
electricity. Fuels used by the industries include coal, natural gas, and
fuel oil; however, only coal is used for comparisons in order to separate
the evaluation of cogeneration as a concept from t*o problem of fuel switch-
ing. Any additional electricity needs are supplied by a conventional power
plant. This conventional powei plant may use either coal or nuclear fuel.
10
-------
O.OSED CTClJt
__*_ — -
POUCH PLANT
i^l
MEKCEHCT
lACKUn \
\
\
!
STEAM
ELECTRICITY
T"
1 .
\
\"
\
\
\-
— +
INDUSTRIAL
PROCESSES
m
EMERCEW
BACKUPS
CYCLE
n
/^E
V
ELECWICITT T0
CTID
Figure 1. Cogeneration system.
11
-------
BASIC METHODOLOGY
The basic methodology employed, as shown in Figure 2, was an interactive
analysis. The first step in the methodology was to ascertain industry
size (e.g., kg/-^a> of output products). Based on combinations and sizes
of industrial facilities, cogeneration system concepts were formulated
to supply the total energy needs. The economic, energy efficiency, environ-
mental, and social implications of the cogeneration system were then evalu-
ated. Similarly, a status quo system was formulated whose impacts were
then used to gauge the relative impacts of a particular copeneratlon system.
Determine
lapacts
Difference •
Relative lapaet
Figure 2. Basic methodology f-r evaluation of a cogeneration system.
The four types of analyses performed are shown schematically in Figure
3. For the economic and energy efficiency analysis, a computer simulation
was -developed for ease of changing scenario parameters and performing sensi-
tivity analyses. (A description of the program is given in Appendix C).
For the environmental analysis and the social impact analysis, a computer
simulation was not necessary since the results were less quantitative.
Outputs of the four analyses were then utilized to arrive at a total
impact assessment statement on cogeneration systems. Outputs of the analyses
were in terms of dollar savings, weight of air emissions, overall energy
efficiency, gallons of water saved, quantity of fuel saved, decrease in
thermal emissions, savings in waste water treatment, and sho-t-term popula-
tion changes during and after cogeneration system construction.
For the applications of several of these analyses, an example case
modeJ was developed. This example case analysis provides a general indica-
tion of the relative merits of a cogeneration system and is a useful tool
for making -^commendations at a planning level.
12
-------
The criteria for selecting an example case included applicability to
a numoer of sites, hijjh steam requirements, and high demand for electricity.
A plant of typical size (909 Mg of Cl2 producer por aay)w would require
61.1 kg/sec. of steam at 210 kPa and 290°C. To simulate a large cogen-
eration system complex, it was necessary to assume that the equivalent
of six 909 Mg per day chlorine plants were located in the same vicinity,
with ci nearby power plant providing the electrical and thermal requirements
of the industrial complex. It was also assumed that the steam be transferred
one-half mile to the industrial plants, condensed at the industries and
returned as feedwater to the power plant.
I TECHNOLOGY SURVEY I
ENVIRONMENTAL ANALYSIS
ECONOMIC AND ENERGY
ANALYSES
SOCIAL IMPACT ANALYSIS
PERFORM EVALUATION OF
COCENERATION SYSTEM
CONCEPTS
(COST BENEFIT ANALYSIS)
Figure 3. degeneration system analysis approach.
Figure 4 displays the example case cogeneration system with a coal-
fired power plant. The speJific values of the energy flows and the methods
of evaulation will be discussed in detail in Section 5. A status quo system
that would meet the same energy requirements is also shown. The low pressure
steam required by the industry is extracted at the crossover point. The
mass flow rate of steam piped is computeo to account for piping loss.
In the example case, the mass flow rate of steam piped is 367 kg/sec.
Extraction of this large quantity of steam at the crossover point reduces
the steam flow through the low pressure turbine anJ causes a 194 Mw reduction
in the electrical output of the power plant. To compare the two systems,
.supplementary utility capacity must be included in the cogeneration system
*1000 TPD C12
13
-------
STATUS QUO SYSTEM
STEAM
12.4 TJ/hr
(11,800 MBtu/hr)
A" fr
COAL
COAL-FIRED
UTILITY
660 Mw
llOOMwVZ^
INDUSTRY
5450 Mg/day
(6000 TPD)
ci2
363 kg/sec
1 (2,880,000 Ibs/hr)
COAL / \
f \ *— *
( GRID 1
COCKNERATION SYSTEM
12.4 TJ/hr
COAL
UTILITY
STEAM (CROSSOVER)
[ 36; kg/sec j
^CONDJNSATE _
906 MM
INDUSTRY
5450 Ng/day
C12
660 Mw
Figure 4 Example case
-------
co make up the loss in electrical capacity. The supplementary capacity
was assumed to oe provided by a large power plant in the grid as a part
of its load.
INDUSTRIAL APPLICATIONS
In order to evaluate the cogeneration concept from an energy efficiency,
environmental impact, and cost standpoint, it is necessary to look at the
energy requirements of specific industries. First, the energy requirements
are used to establish the technical feasibility of supplying thermal energy
to specific industries from a cogenerating power plant. The second step
is to insure that the selected industries represent a significant potential
market. Industrial process modifications are not addressed in this study
because they are beyona the scope of this study and have been addressed
in detail in another study. The energy requirements were also evaluated
to determine the potential for load matching between the industry and the
power plant.
Candidate Industries
Several energy intensive industries were selected to determine the
compatability of the thermal energy requirements of those industries that
could be supplied by a cogenerating power plant. The following energy
intensive industries were selected for initial consideration:
Aluminum Olefins
Aamonia Petroleum
Cement Phosphoric Acid
Chlorine and Caustic Soda Pulp and Paper
Copper Steel
Fertilizers Sulfur
Glass Textiles
Several of the industries were eliminated from consideration because
of the forms of energy required. Steel, glass, and cement all require
nigh temperatures that must be provided by the combustion of primary fuel
or electrical energy. Copper and aluminum require electrical energy.
Ammonia production uses steam that must be at least 540°C which is several
hundred degrees above the temperatures that can practically be supplied
by a utility power plant.
Petroleum and olefin industries are very closely related, and rely
on petroleum as feed stocks as well as a source of fuel. Much of the energy
is derived from by-products of the chemical processes. In fact, some petrol-
euro based industries presently use cogeneration systems for their own oper-
ation and still have excess by-product fuel. Therefore, these industries
are not a good potential market for thermal energy from a large scale cogen-
eration system.
The fertilizer industry covers a broad range of processes which includes
15
-------
phospnoric acid, phosphate rock, sulfur, and sulfuric acid. Therefore,
specific processes are considered ratner than fertilizer production as
a whole.
Thermal and Electrical Demands
The industries that were selected for preliminary analysis are shown
in Table 1. The most important characteristics of these industries are
the quantity and quality of steam required for the process applications.
Each industry requires relatively large quantities of steam at temperatures
and pressures that could be supplied by a cogeneration system. In general,
these industries use electrical energy and steam at pressure of 3.45 KPa
and below. The thermal and electrical demands of several industries are
discussed in the following sub-sections.
TABLE 1. INDUSTRIAL ENERGY REQUIREMENTS
Industry
Electricity
Mw
Haas Flow
kg/ sec
(1000 Ib/hr)
Steam
Pressure
MPa
(psig)
Temperature
°C
(°F)
909 Mg/day chlorine
(1000 I /day) and
1000 Mg/day caustic
soda (1100 T/day)
909 Mg/day phosphoric
acid (1000 T/day)
1818 Mg/day Kraft
pulp and pape.
(2000 T/day)
1818 Mg/day
C roundwood pu 1 p
and paper (2000 T/day)
110
7.56
94
185
66,900
textiles
(80,000 yd2 /day)
6 .5 (480)
0.370 (2.94)
152 (1205)
94.5 (750)
20.2 (160)
0.31 (30)
28.8 (550)
0.790 (100) 232 (450)
6.59 (705) 760 (1465)
0.55 (65) 168 (335)
1.58 (215) 193 (380)
Chlorine and Caustic Soda—
Chlorine and caustic soda are produced almost entirely by electrolytic
methods from fused chlorides or aqueous solutions of alkali metal chlorides.
Therefore, there is a large demand for electrical energy. There is also a
demand for steam used to cor.trol the temperature of the electrolytic solution,
and to purify and concentrate the brine solutions.
16
-------
Pnospnoric Acid—
Phospnonc acid is an important compound in the production of fertilizers
as well as several otrier chemical, products. Phosphate rock is tm=> basic
raw material that is used in tne production of pnosphoric acid and it is
found tnroughout the world.
The pnosphate rock oust be mined and separated from undesirable materials
such as sand and clay. Energy requirements for the mining are primarily
for mechanical energy that is supplied by electricity or oil powered engines.
Phospnate rich ore is then mixed with water to separate the phosphate rock,
and the slurry of phosphate root: and vtater is dried. This process requires
large quantities of thermal energy that can be supplied as steam or by
direct combustion of fuel.
The production of phosphoric acid from the phosphate rock is done by
one of two major processes, the wet process or the furnace process. In
the furnace process, temperatures of 1600°C to 2700°C are required which
requires electric or direct combustion furnaces. The wet process requires
some thermal energy that can be provided as a by-product of sulfuric acid
production which is used in the wet process.
Pulp and Paper—
The paper industry is an energy intensive industry. Steam and electri-
city are the major forms of energy consumed; however, some fuel is required
for direct combustion as part of chemical recovery processes.
Paper is made by separating wood fibers and reassembling them into
a desired form. To process the wood fibers into the final form, the fol-
lowing general sequence is followed: 1) pulp wood acquisition, 2) debarking
of roundwood, 3) cnipping of roundwood, U) pulping, 5) pulp bleaching,
b) papermaking, and 7) converting. The most energy intensive steps are
chipping, pulping and papermaking.
Chipping is the cutting of logs into small chips that can be used in
later processes. This requires mechanical energy that can be supplied
by either electric motors or steam turbines. Electric motors are used
moat often.
Pulping is the process of separating individual fibers into a form
that can be used to make paper. There are several different methods of
making pulp. Some require mechanical while others require thermal energy.
But all are energy intensive.
Paper is made by arranging fibers into an interlocking matrix by suspend-
ing the wood fibers in water and pouring the suspension onto a screen.
Water is removed and a sheet is formed. This sheet is pressed between
rollers and further dried oy heating. The drying process is very energy
intensive and normally uses large quantities of low pressure steam.
Textiles—
The textile industry is very diverse in its type of operations. There
17
-------
13 a wide range of material?, and manufacturing techniques. Most of the
energy required during the manufacturing stage is mechanical. The energy
requirement of yarn production 13 very dependent on specific materials.
The one energy intensive process that most textile operations have
in common is drying. At some point In most textile operations, water must
be removed. For many years drying has been accomplished with hot gases
that are the combustion by-products of a clean fuel such as natural gas.
However, steam dryers are being used more and more often as natural gas
becomes harder to obtain. The energy required for steam drying represents
a significant energy requirement for low pressure steam.
The loss of energy due to transportation can be compensated by supplying
steam at a higher pressure from the power plant. However, the energy loss
results in a net loss of efficiency that is proportional to the distance
the steam is transported.
Industry-Power Plant Compatibility
Industries and power plants require reliability and availability; how-
ever, the operating requirements associated with meeting these criteria
may be different.
In general, industries : -at require large amounts of energy normally
operate on a year-round bas.:, 24 hours a day. However, utilities usually
must shut down for extended periods, a few weeks to several months, for
major maintenance. The difference in the modes of operation between the
utility and industrial operations could cause significant difficulties
for an industrial energy consumer that must rely on a utility or large
scale power plant for its source of energy. The difference in the operating
schedules and maintenance procedures are primarily dictated by the objective
of the utility and industries. For example, the maintenance of a utility
power plant is based on maximizing the availability and reliability of
the total system, which may consist of a large number of utility power
plants. To maximize the reliability of the system, the utility will shut
down power plants at regular intervals for major and preventive maintenance.
In contrast, an industry that supplies its own energy is operating in a
relatively isolated environment. Since the objective of the industry is
to maximize the product output, the production of energy is only a means
to that end. In this mode of operation, the power plant in an industry
will be operated for maximum availability, 24 hours a day, all year. When
it is necessary to shut down the power plant for major repairs, it is of
great financial importance that all repairs and maintenance be performed
as rapidly as possible, and the plant be put back into operation. To meet
the operating requirements of the industry, it nay be necessary to design
the cogenerating power plant with sufficient redundant systems (i.e., multi-
ple boilers with header systems) tha*. the required availability can be
satisfied. Although there will be additional cost in designing the cogen-
erating power plant to provide the reliability and availability required
by the industries, the net result could still be a power system that is
18
-------
more reliable and has higher availability than ii.Dividual power systems
in eacn industry. Therefore, if the cogenerating system offers sufficient
economic advantage over tne status quo system, the availability and relia-
bility requirements would be primarily an economic consideration.
19
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SECTION 5
ENERGY
ENERGY ANALYSIS
The energy analysis included an investigation of the total energy utiliza-
tion for both cogeneration systems and status quo systems. An analysis
of energy production and consumption must include a detailed treatment
of boiler-turbine-generator efficiencies, enthalpies of steam at extraction
points, and thermal energy losses due to extraction control equipment.
A computer model was employed to calculate the significant operating param-
eters of the total energy system. The energy system included the boiler,
turbines, generators, and piping. Energy demands are based primarily on
industries that produce their own steam. No attempt was made to optimize
the grades of steam provided to satisfy particular industry needs. Instead,
energy was assumed to be provided at the same grades in the cogeneration
system as is presently providM in the status quo system. Industries in
a particular grouping may have demands for steam that are slightly different
in temperature and pressure. In practice, matching of steam conditions
is accomplished by pressure regulation equipment at the point of use.
The energy modeling approach taken here is to keep the energy supplied
to a particular industry constant for a given grade, and then supply this
energy demand from tne most likely extraction point of the power plant
turbine. Losses due to the mismatching of steam source with demand were
not included in the energy analysis.
Power Plant Model
A power plant model was developed which includes an appropriate level
of detail so that relationships between steam extracted for industries
power plant fuel requirements, efficiencies, and ejected heat could be
investigated. The same power plant model was used for computing mass flows,
fuel requirements and electrical energy outputs for conventional power
plants, cogeneration systems and industrial boilers. Discussion of the
model essentially begins with the mass flows M., M_, an-1 M^ of process
steam extracted and piped to the industries at grades GI( G2, and G^, respec-
tively. The term steam grade refers to the specific characteristics of
the steam that is defined by pressure and temperature. For conventional
power plants, mass flows were set equal to zero.
Industries may have demands for steam that are slightly different tempera-
20
-------
tures and pressures. Since, in actuality, matching of steam conditions
is accomplished by pressure regulation equipment at the point of use, mass
flows from the cogeneration system at a particular grade are determined
by keeping the energy supplied to the industry at a given grade constant
and allowing temperature and pressure to vary. Table 2 presents the rela-
tionships between Industry steam demands and power plant steam source.
TABLE 2. RELATIONSHIPS BETWEEN STEAM DEMANDS AND POWER PLANT STEAM SOURCE
Power plant steam source
Industry steam demand Nuclear Coal Industrial
High (M )
Intermediate (M )
None
Primary
Primary
Cold
reheat
None
Primary
Low (M.) Crossover Crossover Crossover
Figure 5 presents a block diagram of the power plant model. Definition
of variables for efficiencies, mass flows, and enthalpies are given in
Table 3. The general form of the model includes a tnree-stage turbine.
A given power plant may effectively be either two or three stages. For
example, a nuclear power plant or an industrial fossil-fuel power plant
has only two stages, whereas a conventional coal-fired power plant is modeled
as having a three-stage turbine.
It will be noted in Figure 5 that two mass flows are labeled Mg. This
is due to the possibility of steam being extracted from either point (but
not both) and used for feedwater heating. For a nuclear power plant, M_
would be extracted from point B, whereas from a fossil-fuel power plant,
MQ would be extracted from point C.
Figure 6 illustrates the mathematical equations and logical flow of
computation in the power plant model. The equations are based or. mass
flow and energy balance reia*'onship.j for the Rankine cycle for backpressure
turbines. The model is used for computing fuel requirements and electrical
energy produced by cogeneration systems and conventional power plants using
nuclear or coal fuel as well as industrial boilers using fuel oil, coal,
or high Btu gas.
In Figure 6, HTOTAL is the total rate of thermal energy supplied by
the power plants. For large nucloar utilities, H-0-., is set to 3750 Mw..
21
-------
WASTE
HEAT
Figure 5. Block diagram of power plant model.
22
-------
TAJ..LE 3. DEFINITION OF EFFICIENCIES, MASS FLOW AND
ENTHALPIES FOR POWER PLANT MODEL
Variable Description
N Eificiency of Isc stage of turbine
N- Efficiency of 2nd stage of turbine
N- Efficiency of 3rd stage of turbine
N, Efficiency of boiler
M Mass flow to industries at high T & P
M_ Mass flow to industries at intermediate T & P
M- Mass flow through boiler for reheat or
moisture removal
M. Mass flow to industries at low T & P
4
M Mass flow to condenser
M_ Mass flow of make-up water
MO Mass flow of return water from industries
M- Mass flow for steam used for feedwater heating
h Enthalpy of high pressure steam
h_ Enthalpy of intermediate pressure steam
h_ Enthalpy of reheat steam
h Enthalpy of low pressure steam
h. Enthalpy of steam input to condenser
h Enthalpy of steam output from condenser
6
h? Enthalpy of make-up water
h0 Enthalpy of industrial condensate return
o _______
23
-------
Taa
roti'si a Lara, \ lto
Canute
oo Lodiiatry
Piping Lo»»«»
Coapute Total Boiler hass Flow
Calculatt Electrical Energy Output
CaJeulat* Ucctrlcal taaraj Output
-H9)
-------
Clmtd Cycl. Opm Cycl*
V°
Figure 6. (continued)
-------
and for large coal utilities, HTOTAL is set to 2650 Mwth. These sizes
are typical of present utilities.
The mass flow rates to the industries MI , M,,, and M^ are computed based
on industry energy demands and piping and extraction energy losses in trans-
porting the steam to the industr
-------
By-product fuel may be burned in industrial boilers. For industrial
power plants, a check is made to see whether industry demands can be met
with by-product fuel alone. If not, industrial boiler mass flow is set
equal to total mass flow demanded by the industrial process. Additional
fuel requirements are then computed. If the particular industrial power
plant also provides electricity, then the electricity generated is computed.
Condensing in the industrial utility only occurs when HTOT,, exceeds indus-
trial energy needs.
Piping Energy Loss Model
Energy losses due to transporting steam occur due to friction in the
pipes and losses through pipe insulation. Therefore, the energy loss will
depend on the temperature and velocity of travel of the steam and the dis-
tance the steam is transported. In general, pipe size and insulation are
selected based on economics in such a way that the losses can be assumed
to be a function of the distance the steam is transported. As a result,
the total mass of steam that must be supplied by the power plant can be
approximated by (J).
MS '
MD
/(1 -
where
Ms = mass shipped in 106 lb/hr (=• 7. 94 x 103 M£ (Kg/hr))
MD = mass demanded in 106 lb/hr ( = 7.94 x 103 Mft (Kg/hr))
L » fraction lost per mile (=» 1.61 L1 (Km'1))
x = number of miles (= 0.621 X1 (Km))
Energy Efficiency Model
Energy efficiency is defined as the ratio of useful energy output to
fuel energy input. For the case of conventional power plants, the only
useful energy output is in the form of electrical energy produced. Ineffi-
ciencies in energy production occur due to 1) boiler heat losses, 2) extrac-
tion and piping thermal losses, 3) turbine thermal and f notional losses
and 4) electrical generator losses. The primary source of energy loss,
however, is the amount of heat ejected into the environment from condensa-
tion. Modern power plants have maximum total efficiencies on the order
of 38 percent.
Industrial boilers are much more efficient due to the extraction of
low grade steam for use in the industrial processes. Much of the heat
wasted from the condensation is eliminated. Total energy efficiencies
may be as high as 90 percent.
Cogeneration systems benefit from the same advantages as industrial
sized boilers but on a much larger scale. By operating at higher tempera-
tures and pressures, thermal energy may be produced even more efficiently.
27
-------
However, much of the advantage of larger scale operation may be cancelled
by tne additional piping energy losses from piping extracted steam over
larger distances.
The total energy efficiency, N_, for each power plant is computed based
on the useful electrical and thermal energy produced and the amount of
fuel consumed as given in the following equation:
TH_ •*• EL
where THg = total thermal energy supplied to the
industries, Mwthernal
EL s total electrical energy produced, Mw ,
THp = total thermal energy in the fuel consumed,
*** thermal
As noted earlier, all efficiencies of boilers and turbine stages are
included in the power plant model and therefore are already included in
the quantities TH- and EL. For a conventional power plant, TH<, is zero.
Air Pollution Control Energy Loss Model
Table 5 presents the energy penalties, P , for air pollution control
methods used on coal burning boilers. The energy penalty is defined to
be the percent of plant output consumed. Pollution control systems consist
of some combination of these control devices. The total control system
energy efficiency, N,, is computed as follows:
u
n
N_ = 100 X II (0.01) X (100-P )
° e=l e
where TT = indicates taking products
n = number of control devices
P = energy penalty for a given device, %
NC = total energy efficiency, %
ENERGY ANALYSIS EXAMPLE CASE
Figure 7 displays the hourly fuel demands of the example case energy
systems. All boilers use coal. In the status quo system, the industrial
boilers burn 5.0 terajoul.es of coal hourly. In both Che cogeneration
system and status quo system, the power plane consumes 12.5 terajoules
of coal per hour. To replace the electrical capacity lost, 2.2 terajoules
of coal are combusted hourly in the supplementary utility. Thus,
to produce the same amount of electricity and steam, the cogeneration system
uses about 15 percent less fuel. If the industrial boiler in the scat us
quo system burned natural gas or fuel oil, replacement of the example case
28
-------
TABLE 5. ENERGY PENALTIES FOR POLLUTION CONTROL METHODS
ON COAL BURNING BOILERS
(PERCENT OF PLANT OUTPUT CONSUMER = PENALTY)
Control method
Penalty
1.2
Electrostatic precipitator
Flue gas desulfurization
(non-regenerative limestone scrubbers)
Combustion modification
Flue.gas treatment(dry)
Simultaneous flue gas treatment
(wet and dry)
Fluidized bed combustion, first
generation(atiuospheric and pressurized)
Fluidized bed combustion, ultimate
0.2Z
5.0Z (3.6 - 7.0Z Range)
Negligible
3.0Z (3.0 - 7.0)
7.0Z
5.0%
OX
These penalties represent a starting point for an analysis and not espe-
cially hard data. A sensitivity analysis with respect to the energy penal-
ties would be in order to determine the true impact they may have on cogen-
eration system and status quo system economics. This is especially true in
regards to flue gas treatment, flue gas treatment simultaneous, atmospheric
fluidized bed combustion, and pressurized fluldized bed combustion values
which are not well documented.
The natural draft cooling tower energy penalty was built into the system
baseline efficiency data. Data indicates the penalty can range signifi-
cantly from 1-12 percent with an average of 2 - 4 percent. (Based on
information in Development Document for Effluent Limitation Guidelines and
New Source Performance Standards for Steam Electric Power Generation Point
Source Category, U.S. EPA, Oct. 1974, p. 625.)
(References: 4, 5, 6, 7, 8, 9, 10, 11, 12, 13)
29
-------
STATUS QUO SYSTEM
12.4 TJ/hr
(11.800 MBtu/hr)
A
COAL
COAL-FIRED
UTILITY
660 Mw
STEAM
INDUSTRY
5450 Mg/day
(6000 TPD)
C12
363 kg/ sec
| (2,880,000 Ibs/hr)
BOILER
^ . A
*" COAL /\
OVERALL EFFICIENCY = 45.62
COCENERATION SYSTEM
STEAM (CROSSOVER)
sec~~l
1
1 I2'
/ iT"
1
2.
4 TJ/hr
22 TJ/hr
COAL
UTILITY
__ — .
BUPPLEMEN-
rARY UTILITY
_J
A.CONDENSATE _
906 M»
BACKUP ]
194 Mw '
n
f
INDUSTRY
5450 Mg/day
C12
1100 Mw
1
1
.660
OVERALL EFFICIENCY = 53.01
Figure 7. Coal-fueled example case.
-------
industrial boilers with extracted steam would save about 35 trillion Btu's
of tnese critical fuels annually, although an additional 15 trillion Btu's
of coal would be combusted.
The example case cogeneration system consumed 20 trillion Btu's less
fuel than the status quo system annually, or 15 percent of total combined
utility and industrial consumption. The Afficiencies of the cogeneratic-i
and status quo systems can be computed as discussed earlier. The efficiency
of the status quo system power plant ("_,.--) is computed as follows:
N _ electrical output 1100 Mw x 3.601 GJ/Mwhr
SQPP " fuel consumed - 12,416 GJ/hr
= o.31«i.
The efficiency of the status quo industrial boilers ("-,,) is assumed to
be do percent. The overall efficiency of the status quo system can then
be deter mined by dividing total work output by total fuel input:
M .(1100 X 3.60-DCJ/hr * 397i GJ/hr _ 0
SQ fiT^l6 GJ/hr * 4971 GJ/hr
The efficiency of the cogeneration system power plant (Nncpp) can be
'determined by dividing the total electrical output plus the industrial
work output (equal to that in the status quo system) by total fuel consump-
tion.
M (906 X 3.601)CJ/hr * 3977 GJ/hr . 0.567.
WCSPP s 12,416 GJ/hr
The power plant efficiency improvement is quite substantial, as the cogener-
ation system power plant is almost twice as efficient as the status quo
power plant. However, to compute the overall efficiency of the cogeneration
system («„_), the efficiency of the supplementary utility must be included.
Thus,
M (906 X 3.601 * 3977 * 194 X 3.601)GJ/hr , 0 530
NCS = (12,416 «• 278C)GJ/hr
which represents a 17 percent improvement in overall efficiency.
The fuel savings and energy efficiency improvements found in the example
case energy analysis are an important factor in favor of cogeneration sys-
tems. As current national goals are directed toward energy conservation,
cogeneration systems are definitely in the national interest. To put things
in perspective, annual fuel consumed by electric utilities totaled aoorov-
imately 21 exa joules in 1977. If one third of all electric genera-
tion had occurred in cogeneration system-type configurations with efficiency
improvements similar to t*ie example case, total fuel consumption would
have declined 2.8 exa joule? , which is 3 2 percent of 1977 energy
consumption.
-------
SECTION 6
ENVIRONMENT
ENVIRONMENTAL ANALYSIS
One of the primary concerns of this study was to investigate how environ-
mental considerations impact the viability of cogeneration systems. Four
specific environmental aspects are considered in this study: 1) air emis-
sions, 2) water consumption, 3) solid waste production, and U) wastewater
treatment. The following subsections contain the methodology, analysis,
and regulations related to each aspect.
Air Emissions
The quantity of air pollutants produced by a power plant is determined
basically by the concentration of the pollutant in the fuel and the quantity
of fuel burned. The basic form of the equation used for computing air
emissions is given below.
E4 = EP x 8760 x FUEL x PF x (1-N ) (10~3)
A C
where E, = annual emissions of pollutant in kilograms
EF = emission factor for pollutant in g/CJ of heat
obtained from fuel burned
FUEL = fuel consumption in GJ/hr at rated boiler capacity
PF = power plant factor
N = efficiency of pollution control
The five v.ypes of air pollutants considered in this study were: 1)
particulates, 2) sulfur oxides, 3) nitrogen oxides, 4) carbon monoxide,
and 5) hydrocarbons. An emission factor (EF) is associated with each pollu-
tant for each fuel considered. Table 6 presents emission factors for each
fuel considered. A number of pollution control technologies exist. Table
7 gives the types of air pollution control equipment considered along with
efficiency of collection, N , for particulates, sulfur oxides and nitrogen
oxides. Since eieetpogtatie precipitators are considered to be present
in all power plants using coal or high Btu natural gas, it is assumed for
simplicity that all particulates 'collection is due to electrostatic precipi-
tators with no collection due to any other control equipment.
Air pollution control equipment is grouped into six system types for
32
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TABLE 6. LIST OF EMISSION FACTORS (g/CJ)
Fuel
Coal
Nuclear
Fuel Oil
Parciculates
2690
22
Sulfur
oxides
1560
6.0
Carbon
monoxide
18
.086
Hydro-
carbon
6.0
9.0
Nitrogen
oxides
335
292
(Reference: 14)
TABLE 7. LEVEL OF EMISSION CONTROL FOR UTILITY AND
INDUSTRIAL AIR POLLUTION CONTROL METHODS
Percentage of emission eliminated
by pollutant type
Method of control Particulates Sulfur oxides Nitrogen oxides
Electrostatic precipttaiors
98.5%
Flue gas desulfurization
(Non-regenerative lime-
stone scrubbers) - 90% -
Combustion modification
-
Dry flue gas treatment
Simultaneous dry flue gas
treatment - 90Z
Simultaneous wet flue gas
treatment - 90%
Atmospheric fluldized bed
combustion - 90%
Pressurized fluldized bed
combustion - 90%
50%
90%
90%
90%
60%
80%
(References: 12, 13, 15, 16, 17, 18, 19, 20, 21)
33
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large utilities ~*<* three types for industrial boilera (1t). The air
pollution control systems are defined as in Table 8.
TABLE 8. AIR POLLUTION CONTROL SYSTEMS USED IN ANALYSIS
Utility Systems*
Industrial Systems
Electrostatic Precipltators
+ Flue Gas Desulfurization
+ Combustion Modification
Electrostatic Precipltators
+ Flue Gas Desulfurization
+ Dry Flue Gas Treatment
Electrostatic Precipitators
+ Dry Flue Gas Treatment, Simultaneous
Electrostatic Precipltators
+ Wet Flue Gas Treatment, Simultaneous
Electrostatic Precipitators
+ Atmospheric Fluidized Bed Combustion
Electrostatic Piecipltators
+ Pressurized Fluidized Bed Combustion
Electrostatic Precipitators
+ Flue Gas Desulfurization
+ Combustion Modification
Electrostatic Precipitators
+ Fluidized Bed Combustion
Electrostatic Precipitators**
* Assumed natural draft cooling tower used to control thermal emissions in
all rases unless othervise indicated.
**Assumed SO control not necessary.
Siting of cogeneration systems can be impacted by a number of environ-
mental concerns and regulations. Nsu source performance standards are
air emission standards for seventeen types of new or substantially modified
stationary sources that have been established by EPA. The only one of
these source types relevant to thia discussion is coal-burning steam-elec-
tric generators having a heat input greater than 264 GJ/hr. These
standards described below limit the amount grams/GJ of particu-
lates, SOX and NOX emitted &y the enig3lon 3Ource (22K u ls nQt antl(j_
ipated that these standards would have a constraining effect on the develop-
ment of cogeneration systems, at Least no more so than on a conventional
utility. 197L standard, were used.
-------
(a) Participate Matter:
(1) 43 grams/GJ heat input (0.1 Ibs per million Btu).
(2) No more than 20 percent capacity visible emissions, except
for 2 minutes in any hour visible emissions may be as
great as 40 percent capacity.
(b) Sulfur Dioxide:
(1) 340 g/GJ heat input (0.8 Ib per million Btu) when oil is fired.
(2) 520 g/GJ heat input (1.2 Ib per million Btu) when coal is fired.
(c) Nitrogen Oxides (as NG^):
(1) 86 g/GJ heat input (0.20 Ibs per million Btu) when gas is fired.
(2) 130 g/GJ heat input (0.30 Ibs per million Btu) when oil is fired.
(3) 300 g/GJ heat input (0.70 Ibs per million Btu) when coal is fired.
National ambient air quality standards were developed in 1971 for six
pollutants to reflect thresholds of atmospheric concentrations above which
the pollutants are thought to have significant deliterious effects on human
health and/or on plant and animal life and property. These pollutants
are particulate matter, sulfur oxides, nitrogen oxides, carbon monoxide,
photochemical oxidants, and hydrocarbons. The national ambient air quality
standards are expressed in terms of primary and secondary standards. The
primary standards are specified to protect public health, and the more
stringent secondary standards are set to protect against effects on soil,
water, vegetation, materials, animals, weather, visibility, and personal
comfort and well being. The primary standards are to be met nationwide
in each air quality control region by 1982 and the secondary standards
are to be met in a reasonable time thereafter, as determined by the EPA
(22). Of the six pollutants, only three are of significant importance
to the burning of coal from a stationary source. These are particulate
matter, sulfur oxides (measured as sulfur dioxide) and nitrogen oxides
(measured as nitrogen dioxide). The other three pollutants, carbon monoxide,
photochemical oxidants and hydrocarbons are of more importance when analyzing
emissions from mobile sources such as automobiles.
These standards can work to help or hinder development of cogeneration
systems depending on conditions in the local air quality control regions.
Because a cogeneration system is more efficient than a status quo system,
it produces less emissions per unit of time. However, even though the
total emissions are less than in a status quo system, and even though it
can meet new source performance emission standards, there is the possibility
it could cause national ambient air quality standards to be degraded locally.
Thia is because a cogeneration system is a centralized complex. Industrial
process emissions are not reduced in cogeneration systems because they
are a result of the manufacturing process and not the fuel combustion pro-
cess. Therefore, a cogenera tion system centralizes these emissions.
35
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However in the status quo system, the industrial plants may be miles apart (often
in different air quality control regions), thereby allowing better dispersion
of the air pollutants and impacting national ambient air quality standards
less severely. Also, if the-supplementary utility capacity of the cogener-
ation system is located on site (rather than have the lost generating capac-
ity made up at a different location, perhaps in another air quality control
region), then the cogeneration system would nave an increased negative
impact on the national ambient air quality standards.
In the example case, if the cogeneration system is oversized by the
supplementary utility capacity (194 Mw), then it is producing at least
20 percent more emissions at that point (ignoring cogeneration system indus-
trial process emissions) than a status quo power plant at the site. The
status quo industries could be scattered many miles away producing more
pollution overall but having a much better chance for dillution. However,
it is doubtful that these differences would significantly impact the cogener-
ating system siting in a particular air quality control region unless the
region's pollutant concentrations are nearing the pollution limits or if
the region has non-attainment status. Cogeneration systems would not nor-
mally be excluded from areas where large utilities locate and should always
be acceptable in small locales where a conventional utility and industries
could site with no problems. In an area where air quality limits are becom-
ing critical but industrial development is being encouraged, cogeneration
would be a more favorable approach than status quo development (assuming
development is fairly concentrated).
A more recent regulatory development is the prevention of significant
deterioration standards which has a greater potential to directly affect
the placement of coal burning devices. These standards, promulgated under
the Clean Air Act as amended in August 1977, state how much of an increase
a single source can add to the ambient air quality of a particular region
for particulate matter and sulfur dioxide. There are three classes of
prevention of significant deterioration standards. All areas of the country
will be designated as either Class I, Class II, or Class III for application
of the these deterioration standards. Class I standards allow the smallest
incremental increase in the ambient air quality. Congress has already
designated areas of pristine air quality, such as certain national and
international parks and national wilderness areas, as Class I regions.
Areas designated for application of Class II standards are allowed a larger
incremental increase in ambient air quality, though not as large as allowed
in Class III areas. National ambient air quality standards will act as
an overriding ceiling to any otherwise allowable increment. This includes
all specified national ambient air quality standard pollutants—not Just
particulate matter and sulfur dioxide. The prevention of significant deter-
ioration statutory scheme will not be fully effective until the states
and/or EPA undertake further rul'.-making activity. The prevention of signi-
ficant deterioration regulations state that all areas not clas?1fied as
Class I will be designated Class II (23). A reclasslfloation process is
involved in changing any area to Class III. This reclasslfiuation involves,
among other items, specific approval from the governor of the affected
36
-------
state after consultation with the state legislature and with local govern-
ments representing a majority of the residents in the area which is to
be redesignated.
Major pollution-emitting facilities are required to have a prevention
of significant deterioration permit before construction can begin. The
permit acknowledges that all prevention of significant deterioration emission
requirements will be met by the facility; that the proper procedures have
been undertaken (hearings, review, analysis of air quality impact, etc.);
that the best available control technology for each pollutant is obtained;
and that proper air quality monitoring will be done. Twenty-eight specific
emitting facilities are defined in the Clean Air Act (some of which are
steam electric power plants with more than 264 GJ/hr (250 MBtu/hr) input, Kraft
pulpmills, and Portland cement plants) as requiring permits if they emit
one hundred tons or more of any air pollutant annually. Also the permit
requirements include other facilities which are not specified but which
have the potential to emit two hundred and fifty tons or more per year of
any pollutant. These permit requirements also apply to major modifications
to existing facilities. *
Prevention of significant deterioration standards could inhibit cogenera-
tion system siting even though new source performance standards would be
met and national ambient air quality standards would not be exceeded.
"Prevention of significant deterioration requirements, however, can deny
the use of a site for a power plant even though the best available control
technology is used" (22). Studies have indicated that in many areas preven-
tion of significant deterioration requirements would dictate emission con-
trols significantly more stringent than new source performance standards
or that overall facility size would be limited (25). It would be difficult
for a cogeneration system to site in a Class I area. Host conceivable
cogeneration systems should not have problems siting in a Class III area.
The Class II areas, in which most of the country will be located, are where
site specific conditions will determine cogeneration system acceptability.
Local weather conditions can have significant impacts on prevention of
significant deterioration evaluation. It is also in these Class II areas
that innovative engineering approaches and systems designs may play a crucial
role in the acceptability of cogeneration systems.
Local vs. Nati< > il Concerns—
A paradox ^out cogeneration system is that because combustion is centra-
lized it is more efficient and less emissions are produced. Yet combustion
occurs at one facility in a centralized manner and therefore prevention
of significant deterioration regulations would impact cogeneration systems
more severe*ly than a status quo configuration. This is because each of
the decentralized industries and the utility component of a status quo
system would be considered as individual point sources. Therefore, their
incremental additions to ambient air concentrations are expected to be
less than that made by the cogeneration system as an emission source, al-
*
For update on prevention of significant deterioration regulations, see
"Prevention of Significant Deterioration: Workshop Manual," EPA 450/2-80-081
(October 1980).
37
-------
though the total status quo additions could well exceed the cogeneration
system additions. Thus, from a national viewpoint cogeneration systems
can reduce air pollution when compared to status quo systems, but from
a local viewpoint tney can have much more severe impacts. This dilemna
raises the issue of whether cogeneration systems should receive special
treatment in regard to prevention of significant deterioration.
Hater Consumption
Steam power plants have two major requirements for water. The first
is as a working fluid and the second is as a cooling medium.
Hater that is used in the boiler is normally recycled many times.
Therefore, the only water requirement is that used to replace water that
is lost 'from leaks and control measures such as blowdown. For conventional
power plants, the water requirement for replacement of boiler feedwater
may range from 10 to 100 gallons per minute. The replacement of feedwater
is minimized because it must be treated and conditioned to satisfy a very
exacting set of conditions which is very expensive.
Hater requirements for cooling are much larger than for that used in
the boiler. For every kW hr of electrical energy produced, 5000 to 8000
kJ must be eliminated the form of waste energy. To dissipate this heat
into cooling ponds, cooling towers, etc. between 2300 and 5230 cu cm
water are required for each kW hr. This is a significant water requirement
(i.e. 49 to 114 cu m/min). Tharefore, it is the cooling water that
causes the most severe problem.
A cogeneration system reduces water consumption because of its increased
efficiency in comparison to a status quo system. From a national viewpoint,
significant amounts of water can be saved. Water requirements depend on
the industries within the complex. Therefore, there is the possibility of
the combined cogeneration system and industrial complex water demands being
high at a point source thereby causing perturbations on a local scale even
though national water savings occur.
Solid Haste Production
Solid wastes are assumed to be proportional to volume of fuel burned.
The major source of this solid waste arises from the control of sulfur
oxides. V following equation relates area (A), in hectares, used for waste
disposal to amount of fuel burned:
A = BE
s
where B = hectares/million tonnes
E = solid residuals in tonnes/year
9
and ES s (Hc) x FUEL x EF x PF (10~3)
38
-------
where NC = efficiency of control equipment
FUEL = fuel consumption rate in GJ/hr
EF = emission factor for pollutant in kg/GJ of heat
PF = power plant factor.
For a conventional boiler, ^ is assumed to be 275 hectares/(million
tonnes«vear) for ash and flue gas desulfurization sorbent solid waste and
is based on ponding to 9.2 in depth for 30 years. 6 is assumed to be 178
hectares/(milliop connes-year) for ash and fluidized bed combustion sorbent
solid waste. This is making a pessimistic assumption since ash has been
used for many years as a filler in construction materials, in which case
the waste can oe disposed of as a useful product instead of requiring land
for disposal. Experience with the ash and limestone sorbent from the
fluidized bed combustion unit at Georgetown University indicates that both of
these materials are suitable for use in- construction materials (26).
In a cogeneration system, land devoted to the disposal of solid waste
is reduced in comparison with a status quo system by the percentage increase
in efficiency if industry has controls of comparable efficiency. If flue
gas desulfurization is used for control of surfur oxides emissions, the
reduction in land required is important because the land committed for dis-
posal of flue gas desulfurization solid waste (sludge) usually cannot *>e used
for any other purpose because of the thixotrophic nature of the sludge.
Substantial amounts of land will be used by coal cogeneration for disposal
of solid waste.
Wastewater Combined Treatment
Municipal and pulp and paper plants costs were assumed to include raw
waste dumping, preliminary treatment, primary clarification, aeration tanks,
diffused air system, secondary Clarification, two-stage lime clarification,
recalcination, anmonia stripping, multi-media filtration,, carbon absorption,
break point chlorination, sludge thickening, anerobic digestion, dewatering,
truck hauling, sanitary landfill, administration and lab facilities, site
working and piping, engineering, legal and other costs.. The Economy Scale
Equations are the following (1 MGD • 0.044 cu.m./sec).
1) New Facility Capital Cost
x ,,„„, „ /New Facility Capacity in MGD ^ *8683
(
y
tion and Maintenance Cost in $/MGD / ., _ .... \.i
. / New racuity \
_/ 20 } „ .-« ,. „ I Capacity in MGD I
"\New Facility Capacity in MOD/ **"•* * y 2Q ^p y
2) Operation and Maintenance Cost in $/MGD / ., _ .... \.5702
These potential savings derived form several plants in close proximity
are in addition to those which would result from the increased thermodynamic
efficiency of cogeneration.
39
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Water and Solid Waste Regulations—
Wastewater treatment of industrial processed wastes are not directly
affected by a cogeneration system. However, combined wastewater treatment
can lower costs (i.e. economy of scale benefits). Even though a cogenerat'on
system could meet effluent guidelines and new source performance standards
in the same manner as a status quo system, there is the possibility that
water quality degradation can occur, because of the close proximity of
the industries. The cogeneration system effluent discharge could be consid-
ered one point source even if the different wastewater streams are not
treated together. The treated effluent streams in a cogeneration system
eater a receptor (probably a river) at basically one point. This potentially
causes a much higher concentration of water pollutants than would occur
in the status quo system. The water discharge from the status quo plants
would be released miles away from one another causing a lower concentration
at any one point in the effluent receptor.
It is possible for treated wastewater to meet EPA effluent guidelines
and new source performance standards and exceed state water quality standards
which are subjective in nature. A water quality definition for the state
of Georgia is based on acidity, bacteria levels, water temperature, and
•freedoms," ("free from materials associated with municipal or domestic
sewage, industrial waste or any other waste which will settle to form sludge
deposits that become putrescent, unsightly, or otherwise objectionable")
(22). It is easy to see the subjective nature of the definition and how
similar types could possible impede cogeneration system siting.
In a cogeneration system that combines municipal and industrial waste
treatment facilities, institutional constraints would have to be overcome.
Many industries would rather pay a penalty fee for treatment of their efflu-
ent by a municipal waste treatment plant and write that fee off on their
taxes than build their own plant and undertake the financial risks involved
(27). The penalty fee could be applied to cogeneration system, as ^>ie
municipality could own and operate the integrated wastewater treatment
complex. Wastewater treatment plants constructed by industries are usually
meant to have shorter lives than municipal facilities because of the risks
surrounding process changes and changes in wastewater regulations. A Joint
venture in a wastewater treatment facility involves negotiations on who
pays for what, and usually this is not a very straightforward process.
A municipal system can be built using longer term, lower interest bonds.
Municipal ownership can overcome some institutional barriers. Problems
may represent somewhat of a barrier to cotreatnent facilities in a cogener-
ation system. However, municipal and industrial facilities have engaged
in Joint ventures in construe.ing wastewater treatment facilities.
ENVIRONMENTS. ANALYSIS EXAMPLE CASE
The environmental example case analysis examines the major impacts
of cogeneration systems on the surrounding physical environment. The anal-
ysis emphasizes air emissions, water consumption, solid waste production,
and wastewater treatment. With the exception of wastewater treatment,
the impacts are treated in comparative fashion; that is, the results are
40
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the net increase or decrease in the effect of the impact due to the cogener-
ation system. Combinations of wastewater treatment facilities are treated
as additional options available in a cogeneration system.
Air Bnissiona
The major determinants of the amount of air pollutants emitted from
combustion are amount of fuel consumed and types of pollution control devices
installed. The combustion activities in the example case cogeneration
system include the main power plant (972 Mw), back up power plant and the
supplementary power plant (191 Mw). The cogeneration system substitutes
for combustion in industrial boilers and in the conventional power plant.
The example case cogeneration systom consumes 17 percent less fuel than
the comparable status quo system. Therefore, because air emissions are
proportional to the amount of fuel burned, there are 17 percent less pollu-
tants produced by the cogeneration system than the status quo system.
Figure 8 shows the net reductions in emissions in a cogeneration system
versus the amount of steam extracted from the utility and transferred to
the industrial plants in a cogeneration system. The analysis assumes that
the saae pollution control systems are used by the cogeneration system
and status quo system (ESP * FGD + CM). The figure indicates that as more
steam is extracted from the utility, there is a greater reduction in net
emissions. This is because the overall efficiency of the cogeneration
system is increasing as more steam is extracted. The amciint of pollution
reduced in the example case is represented by the far right portion of
the lines in Figure 8. The decrease in emissions in the example case is
as follows:
particulates - 8.2 x 105 kg/yr
sulfur oxides (SOX) =3.6 x 106 kg/yr
nitrogen oxides (NOX) = 3.2 x 106 kg/yr
carbon monoxide • 8.6 x 1()5 kg/yr
hydrocarbons = 4.1 x 105 kg/yr
The significance of the reduction in air emissions can be determined
by computing the cost of controlling a kilogram of pollutant and multiplying
by the amount of reduction. Table 9 displays the procedure by which the
cost of control is quantified. The total reduction in air emission control
costs is approximately $7.02 million. The regulatory and other related
issues concerning this beneficial aspect are discussed in a previous subsec-
tion.
Water Consumption
Reductions in water consumption can be achieved in a cogeneration system
because the increase in thermal efficiency results in less evaporative
loss from cooling towers. In the cogeneration example case, 0.15
cu m of wat°r per sec are saved from evaporation, enough water to meet
-------
200 300
Amount of Steam Extracted (kg/sec)
400
Figure 8. Reduction in emissions for a cogeneration system compared to a
status quo system.
42
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the daily needs of 28,000 people. The annual cost savings in demineralized
make-up water (which are included in the computation of the net present
value) are $919,800 for 3873 cu.m. (1,022,000 gallons).
TABLE 9. ESTIMATED COST SAVINGS DUE
TO POLLUTION CONTROL REDUCTION
Cose savings in
cogeneration system due to
Cost of control decreased fuel consumption
($/CJ burned) (millions of 1977 dollars;
Particles
Sulfur oxides
Nitrogen oxides
Total
0.05
0.30
0.03
0.88
5.61
0.53
7.02
Solid Waste Production
Table 10 displays the amount of solid waste produced and the amount
of land necessary for the disposal of the solid wastes from flue gas desul-
furization, fluidized bed combustion, and electrostatic precipitation in
the example case. Even though less solid waste is produced by the flue
gas desulfurization method, the fluidized be
-------
TABLE 10. SOLID WASTE ANALYSIS OF EXAMPLE CASE
Ash and flue gas
desulfurization sorbent
*Ponding
Solid waste Acreage
(109 kg/ required
year) (hectares)
Ash and fluidized bed
combustion sorbent
**Landtill
Solid waste acreage
(109 kg/ required
year) (hectares)
Status quo system
Cogeneration system
Amount reduced
1.06
.88
.18
292
241
51.0
1.52
1.25
.27
271
224
47.3
BASIS
. Status quo system - 16.8 GJ/hr, 80 percent annual load factor.
. Cogeneration system • 82.4 percent of status quo system fuel consumption,
80 percent annual load factor.
. Atmospheric fluidized bed combustion and pressurized fluidized bed
combustion waste output assumed equal at 13 kg/GJ which includes
ash and sorbent. Different estimates for atmospheric fluidized bed
combustion (1.22 kg/GJ), and pressurized fluidized bed combustion
(13.4 kg/GJ) were calculated but were combined into one value because
of the uncertainties involved in the estimates.
. Flue gas desulfurization waste output is 9.0 kg/GJ which includes
ash and sorbent.
. Ash waste composes approximately 4.3 kg/GJ of the waste output
coefficients used, the rest being composed of sorbent.
* Ponded to 9.2 m depth for 30 years.
** Filled to 9.2 m depth for 30 years.
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facilities other than energy production and supply, including transportation,
pollution control, and utilization of waste products. Hastewater treatment
presents intriguing possibilities in a cogeneration system. Haste products
froa an ammonia plant and a phosphoric acid plant can be used to treat
the effluent froa a pulp and paper plant. Effluent from a textile mill
and pulp and paper plant can be combined with municipal wastewater to create
a large wastewater treataent plant (2). The following combinations are
analyzed.
I) 10.5 kg/s (1000 TPD) Kraft pulp and paper plant with an effluent of
1.5 cu ra/s (35 MGD), 0.66 cu m/s (IS MGD) of municipal wastewater from
a municipality of 120,000 people, and 2.19 kg/s (208 TPD) textile
(carpet) mill with a 0.1S cu m/s (3.5 (CD) effluent flow.
II) the 10.5 kg/s pulp and paper plant and the 0.66 cu m/s municipal
treatment facility.
Ill) the 10.5 kg/s pulp and paper mill and the 2.19 kg/s textile mill.
IV Che 2.19 kg/s textile mill and 0.66 cu m/s of municipal wastewater.
V) a 10.5 kg/s phosphoric acid plant, a 10.5 kg/s pulp and paper mill,
and an ammonia plant. (The chemical plant's waste streams supply
phosphorous and nitrogen as nutrients to aid in the biological treat-
ment of pulp and paper effluent.)
A summary of the benefits arising from the different wastewater treatment
combinations analyzed in the study are presented below.
I) Pulp and paper (Kraft), municipal wastewater, textile (carpet) mill
Economy of scale derived capital and 04M coat savings
Municipal wastewater supply N and P nutrients for biological treatment
of pulp and paper and textile wastewater
II) Pulp and paper (Kraft) and municipal wastewater
Economy of scale derived capital and 04M cost savings
Municipal wastewater supply N and P nutrients for biological treatment
of pulp and paper wastewater.
Ill)Pulp and paper (Kraft) and textile (carpet) mill
Economy of scale derived capital and 04M cost savings
IV) Textile (carpet) mill and municipal wastewater
Economy of scale derived capital and 04M cost savings
V) Pulp and paper (Kraft), ammonia, phosphoric acid
Amnonla and phosphoric acid supply N and P as nutrients tor biological
treatment of pulp and paper wastewater
Table 11 displays the capital and annual operating and maintenance
cost savings for the various cogeneration system wastewater treatment combin-
ations considered. The cost savings achievable in Cases I-IV reflect the
advantages.of economy of saale when centralizing treatment processes.
The savings are computed aa the difference in costs between the SUB of
separate waste treatment facilities, as in the status quo system, and the
cost of the centralized cogeneration system facility. Case V includes
the coat saving due to utilization of effluent froa the ammonia and phos-
phoric acid plants aa a chemical in the treataent of biological waste froa
-------
TABLE 11 . COST SAVINGS FROM COMBINED TREATMENT OF WASTEWATER
FROM VARIOUS COGENERATION SYSTEM INDUSTRIES
Cogeneration system
vastewater Total flow
treatment combinations (cu m/s>
Capital cost
savings
(1977 dollars)
Annual operating
and maintenance
cost savings
(1977 dollars)
I.
II.
III.
IV.
V.
Pulp and paper,
municipal and
textile
Pulp and paper,
and municipal
Pulp and paper,
and textile
2.34
2.2
1.69
Textile and municipal 0.810
Pulp and paper,
ammonia, and
phosphoric acid
4.350,000
3.260,000
980,000
710,000
Not applicable
1,380,600*
727,900*
495,200
372,800
72,800*t
1.5+
Basis: A 10.5 kg/s Kraft pulp and paper plant (1.5 cu m/s); municipality
of 120,000 people (0.66 cu m/s); 2.19 kg/s textile (carpet) mill
(0.15 cu m/s); 10.5 kg/s ammonia plant; and a 10.5 kg/s phosphoric
acid plant with waste flow of roughly 8.5 (-5) cu m/s. See
Appendix 1 for calculation of economy of scale benefits.
* $72,800/year in N and P chemical cost savings are included based on
values of $14.6/kg for anhydrous ammonia, 6.6^/kg for 35% phosphoric acid;
BOD5=N:P « 100:5:1; 0.035 kg/kg of pulp and paper plant wastewaters;
602 deficiency in N and P; and 340 operating days/year for all plants.
+ Spill rates of phosphoric acid of 0 - 2.5 (-3) kg/kg (0.1 (-3) kg/kg
average) and 1.2 (-3) - 1.8 (-3) kg stripped ammonia/kg condensate supply
enough P and N to supply the nutrient needs unless phosphoric acid waste
flow drops below its average level.
Note: In the footnotes to this table powers of ten are shown in parenthesis.
For example, 8.5 (-5) is 8.5 x 10"5.
-------
the other plants. The largest cost savings occur when the pulp and paper,
textile, and municpal waste treatment functions are combined in a 2.34
cubic meters per sec fici.li.ty, which is the largest of Che four central-
ized cases. Savings on the order of $1.3 million in capital costs and
$1.1 million in annual operation and maintenance costs are achieved. Savings
in the other cases are directly related to the amount of centralization
achieved, which is reflected in the size of the facility as measured in
cubic meters per sec. The smallest savings occur when phosphoric acid
and ammonia waste streams are used to supply nitrogen and phosphorous in
the pulp and paper waste treatment facility. Their savings, approximately
$72,800 per year, may be reduced substantially by the added coats of channel-
Ing the ammonia and phosphoric acid waste streams in the proper amounts
to the pulp and paper treatment facility. The economy of scale cost savings
are significant, especially when large volumes of wastewater are involved.
The net present value of the 2.34 cubic meters per sec treatment facility
is $21.5 million, assuming a 7 percent discount rate over a 30 year life.
If the net present value of the cogeneration system in Case I is in the
range of $200 million before including the wastewater treatment benefits,
the net present value could increase by 10 percent to over $221 million
if wastewater treatment is centralized.
Another aspect of wastewater treatment that a cogeneration system can
impact is in decreasing the cost of the waste treatment process through
heat addition. Increases in wastewater temperature within specific limits
can increase the efficiencies of tne physical, biological, and chemical
techniques of wastewater treatment. Data indicates that the greatest cost
savings occur from heat addition to biological (secondary treatment) compon-
ents of wastewater treatment systems. The concept of operating the waste-
water treatment component of a cogeneration system at elevated temperatures
provides two opportunities for economic benefits. First, cost savings
are possible through a reduction in size of the more efficient wastewater
treatment facilty, and second, heat from the cogeneration system power
plant which otherwise would be wasted can be utilized with a potential
savings through the reduction in size of heat rejection equipment. A study
by the New York State Atomic 6 Space Development Authority that examined
the costing of nuclear power plants, wastewater treatment plant, and water
distillation plant looked at the potential of the usage of heat in the
wastewater treatment process (27). Because the addition of heat increases
biological activity and settling rates, smaller size equipment can be used
to achieve the same level of performance that existed without heat addition.
That study estimated that an increase in temperature from approximately
20 °C to 30 °C could allow reductions in the size of the following equipment:
grit chambers (27 percent smaller)
primary settling tanks (22 percent smaller)
aeration basins (18 percent smaller)
final clarifier (22 percent smaller)
gravity thickener (23 percent smaller)
vacuum filter facilities (11 percent smaller)
-------
In the case of the 2.34 cuoic meters per sec centralized treatment
facility (Case I) an average 18 percent reduction in the *ize of the treat-
ment facility would save $6.45 million in capital cost and $295,000 in
annual operation and maintenance costs when compared to the non-heated
centralized facility. However, the cost of heat exchangers (which can
be expensive) needs to be subtracted from the cost savings. It is not
clear that the necessary heat exchanger technology exists at a low enough
price to make heat addition economically sound. Heat exchanger fouling
is also a problem in configurations where the heat exchanger is in contact
with 'che wastewater. The heating of the air that is pumped through the
secondary treatment unit, which supplied oxygen for stimulating the growth
of the biological mass, may be an easier mode of transferring heat to the
wastewater than direct heating of the wastewater through the heat exchanger.
The concept of heat addition to wastewater has had little study in the
past. Heat exchanger heat transfer coefficients, heat exchanger fouling,
heat exchanger costs, and alternative modes of heating wastewater need
to be investigated in greater detail to determine if wastewater heating
is a technically and economically viable means of reducing wastewater treat-
ment costs.
The advantages of centralizing wastewater treatment facilities can
be significant. However, the cost savings achievable will probably not
be a primary impetus for the development of a cogeneration system as they
are dwarfed by the cost savings due to energy efficiency improvements.
The advantages of centralization just serve to increase the overall attrac-
tiveness of cogeneration systems.
-------
SECTION 7
ECONOMIC
ECONOMIC ANALYSIS
The economic analysis methodology evaluates the economic viability
of cogeneration systems. The cost-benefit analysis, described in Appendix
A, is the basic economic analysis technique used. To facilitate the compar-
ison of cogeneration systems with non-cogenerating alternatives, the MAJES
computer model was utilized. A complete description of the computer model
is given in Appendix C. However, the basic purpose of the model was to
insure that comparisons were made in a concise manner. In addition, the
computer model made it possible to make a large number of comparisons that
could be used to generalize results. The computer model contains capital
cost data, operating cost data and performance data for a wide range of
components.
The cost curves used in the study are based on private industry and
public sector documents, literature and interviews. The major cost compon-
ents investigated are shown in Figure 9. The figure indicates which compon-
ents are common to both status quo and cogeneration systems. The major
substitution achieved by cogeneration is the replacement of industrial
Boilers with supplementary utility capacity. The steam conventionally
derived from the industrial boilers is supplanted by steam extracted from
a modified utility power plant. Supplementary capacity is needed because
steam that is extracted from the modified power plant can no longer produce
electricity. The total electrical output of the power plant is therefore
reduced, and electricity from another power plant must replace the capacity
lost to keep total energy supplied the same. This allows a comparison
to be made between the cogeneration and status quo systems based on a tabula-
tion of costs, which does not require an assessent of the value of difference
in energy produced. The cost of conventional utility power plants are
well documented, however, there are very few instances of cogenerating
systems that utilize utility size power plants. Therefore, the approach
used to calculate the cost of a cogeneration system was to define a conven-
tional or status quo power plant and then calculate the differences in
cost of specific components to determine the cost of the cogeneration system.
For example, some equipment, such as cooling towers and turbines, are smaller
in the cogenerating power plant due to decreased steam flow ?fter the extrac-
tion point. The sub-sections discuss the cost models used for the specific
components of the two systems, define the specific values and assumptions
inherent in the calculations, and present specific examples of comparisons
-------
STATUS QUO SYSTEM
COGENERA?TON SYSTEM
>X INDUSTRIES \
DILI
MM
PROCESSES
1
•
sCObtlNG;
ITOHW
INDUSTRIES N.
PROCESSES
«•——-._—
!iHs
.-: '
ii'M'Vii
Figure 9. Schematic diagram of system components.
50
-------
between cogenerating and non-cogenerating energy supply systems.
The cost models compute capital, operation and maintenance and fuel
costs. The net present value model compares the two systems in an economic
context. Costs which are incurred at different point in the 30 year tiioe
stream are discounted back to the present. Costs have been projected in
real dollars; that is, only costs which will escalate faster or slower
than the average inflation rate have been projected. Costs are projected
using escalation rates, which do not include the average inflation rate.
Thus, a cost that increases annually at 5 percent in current dollars when
the average inflation rate is 5 percent, would have an escalation rate
equal to zero. A cost increasing 8 percent annually would have an escalation
rate of 2.85 percent. A real dollar discount rate must also be used in
the analysis. The following are categories of costs which may be assigned
different escalation rates.
Capital costs
Utility power plants
Industrial boilers
Operation and maintenance costs
Utility power plants
Industrial boilers
Steam Piping
Fuel Costs
The present worth factor when considering both escalation and discount
rates is as follows:
PWF(d, e) =
where
x(1+x)n (x-1)xn
d = discount rate
e = escalation rate
x = 1^4
* 1 + e
n = lifetime of facility, (years)
The net present value (NPV) can then be computed as follows:
NPV = (C^ - C) * (04MSQ - OiM) PWF(d,eQ&M) + (0*MIW)) PWF(d,eIMD)
- <04MPIPE) PMF (d'ePIPE} * (FSQ * FIND) "*<»• V
where
C = Capital costs
04M = Operation and maintenance costs
P = Fuel Costs
IND = Industrial systems
51
-------
Status Quo System Costs
Figures 10 and 11 display cost estimates for conventional coal and
nuclear power plants, respectively. Causes of such wide variance in esti-
mates of coal fired power plant costs include: (28)
1. Failure to consider the same cost components (e.g. air pollution
control devices, contingency fees, interest during construction).
2. Use of region specific variables.
3. Variation in the year in which the estimate was made.
4. Different assumptions for economic variables (e.g. capital recovery
factor and the wholesale price index).
5. Use of estimtes obtained from different companies.
The cost curves used in the model are the lines plotted in the figures.
These curves are based on Oak Ridge National Laboratory's ORCOST II model
(29). All of the costs are adjusted to the same time frame in order to
insure that the relativ- re^ui^ Indicate trends that are correct even
if the magnitude is not exact. The curve for the coal-fired power plants
are adjusted upwards v making these plants more expensive) to reflect differ-
ences between the ORCOST model estimates and other estimates. Both curves
show an economy of scale factor which results in lower unit costs of power
plants with increasing size. The dotted line displays this relationship.
The model for cost of a power plant with no pollution controls is as follows:
Coal power plant cost = 1.915 (Mw capacity) *763
657
Nuclear power plant cost = .50 (Mw capacity) *
Operation and maintenance cost estimtes also show significant variance.
The operation v\ maintenance costs for similar plants differ markedly
in any one year. Thus, any estimated reflect average annual values. The
ORCOST II model was used to approximate these costs and can be represented
in equation form as follows:
Nuclear power plants = 1.532 (Mw capacity) "3
388
Coal power plants = 0.924 (Mw capacity) '3
Estimates of tne cost of cooling towers for coal-fired plants are as
follows:
Natural draft cooling towers = .523 (Mw capacity)*
Forced draft cooling towers = .372 (Mw capacity)'
Operating and maintenance costs of cooling towers are assumed to be equal
to 5 percent of the construction costs. The construction cost of cooling
towers in nuclear plants is estimated by calculating the capacity of a
coal fired plant that would eject the same amount of heat and using this
capacity in the above equations. Therefore, the cooling tower model reflects
the dependence of cooling tower costs on the amount of steam to be condensed,
52
-------
a
91
O
U
U
U
CO
O
U
O
U
900
800
700
600
500
400
300
200
Represents literature estimates,
some of which include pollution
control equipment
Cost in $/kv
Assumed Cost of Base
Power Plant ($ Million)
(No Pollution
Control)
300 600 900 1200
Capacity of Power Plant (Megawatts)
Figure 10. Cost of constructing coal-fired power plants.
53
-------
900
800
Represents literature estimates,
some of which include pollution
control equipment
CO
I*
10
o
Q
g
o
09
O
u
700
600
500
400
300
200
Cost in $/kw
Assumed Cost of Base Power
Plant (? Million)
(No Pollution
Control)
300 600 900 1200
Capacity of Power Plant (Megawatt)
Figure 11. Cost of constructing nuclear power plants.
-------
not the amount of electricity generated. Operation and maintenance costs
of cooling towers for nuclear power plants are assumed to be equal to 5
percent of the construction cost.
Industrial boilers must be designed to deliver steam at the pressure
and temperature needed for industrial processes. The cost of industrial
boilers can vary widely depending on alternatives and special features
required by the specific application. For purposes of comparison, the
industrial boilers will be assumed to supply only thermal energy in the
form of steam. The cost relationships were extracted from reports prepared
for Oak Ridge National Laboratory (31)• The relationship between capital
cost and unit capacity is illustrated in Figure 12 for industrial size
power plants.
In addition to presently utilized technologies, the atmospheric fluidized
bed combustion boiler has the potential of providing cost effective alterna-
tive to the high expense of air pollution control equipment (3D. This
technology would replace present technology for both boilers and pollution
control equipment. Discussion of the technological aspects of boilers
is contained in Appendix B, and the projected costs of this type of boiler
are illustrated in Figure 13.
Cogenoration System Costs
The construction cost of the cogenerating power plant is based on the
cost of a conventional plant. The following modifications must be taken
into account to estimate cogenerating power plant costs.
1) The cost of piping, steam extraction, and back-up equipment must
be added to those of the conventional power plant.
2) Since steam is being extracted from the power plant, the intermed-
iate and low pressure turbines can be smaller.
3) Also, due to steam extraction, less condensing and cooling require-
ments exist; thus, savings in the cost of this equipment can be
achieved.
4) Because the status quo utility generates more electricity than
the cogenerating plant, additional capacity must be added elsewhere
in the system.
The cost estimates for piping include facilities for transporting process
heat to and returning condensate from the industries. There are two compon-
ents of this piping, the cost of extraction and the cost of piping itself.
The cost of extraction is a function of the total amount of steam extracted,
while the .-oat of piping is a function of the amount of steam shipped to
each individual industry over a specified distance. Table 12 gives the
estimates to be used for piping costs. Maintenance costs are assumed to
be 5 percent of construction costs.
To calculate the savings in turbine costs, the following procedure was
used:
55
-------
10
6
M
O
High-Btu Coal
I
I
50
100 150
Boiler Capacity (kg/sec)
200
250
Figure 12. Unit capital costs of pulverized-coal steam plants. (Covers
single-unit plants delivering 6.3 to 63 kg/sec, two-unit plants
delivering 12.6 to 126 kg/sec, and four-unit plants delivering
23.2 to 232 kg/sec of steam.)
56
-------
u
s
X
6 4
a.
a
U
I
I
100 50
Boiler Capacity (kg/sec)
200
250
Figure 13. Unit capital costs of AFBC steam plant. (Covers single-unit
plants delivering 6.3 to 63 kg/sec, two-unit plants delivering
12.6 to 126 kg/sec, and four-unit plants delivering 23.2 to 232
kg/sec of steam.)
57
-------
1) The coat or turbine/generators in the status quo utility was com-
puted baaed on the ORCOST II coat breakdown.
2) The coat of turbine/generators in the cogenerating power plant
was estimated, baaed on the actual electrical output of the plant,
using ORCU3T II coat breakdown.
3) The coat savings are estimated aa 1) minua 2).
TABLE 12. CAPITAL COST OF PIPING (1977 DOLLARS)
Technology
Cold reheat/
primary steam
Crossover steam
Coal extraction
Piping coat/km
$ 2.33 [MFRj
,.679
Nuclear extraction $502.50 [MFR]
Piping coat/km $ 33.14 [MFR]"7059
$ 2.21 (MFR|
+ $380,833
'7658
$ 90.54 [MFR]'
$ 9.33 [MFR]
$ 17.14 [MFR]-903*
MFR • Mass Flow Rate in pounds/hour * 2.20 (Mass Flow Rate in kg/hr)
The formula for calculating turbine coat aavinga ia ahown in Table 13.
Thia coating procedure ia admittedly an approximation, but ia well within
the margin of error that exists in available aourcea of data.
TABLE 13. TURBINE COST SAVINGS
Type of power plant
Cost (1977 dollars)
Coal-fired plant
Nuclear pressurized
water reactor
$466,751 (Statua quo system capacity in MW )
.71738
/Cogeneration system electrical! -71738
(generation in MW I
\
$505,707 (Status quo system capacity in MW )
.71738
/Cogeneration system electrical^-71738
\generation in MW
7
58
-------
The cost savings achievable due to reduced condensing and cooling require-
ments can be related directly to total mass flow through this section of
the power plant. Since the amount of steam extracted is known, reduced
cooling costs can be computed based on the extracted steam. In general,
a
Savings a [Cost of Conventional Cooling FacilityJX
MF
1 -
e
t_
where
MF s total steam condensed in cooling systea
MF s amount of steam extracted
a s economy of scale factor
Table 14 shows the cost savings for different types of power plants. Opera-
tion and maintenance costs are reduced proportionately.
TABLE 14. COST SAVINGS DUE TO REDUCED COOLING REQUIREMENTS
IN A COGENERATION SYSTEM WITH NATURAL CRAFT COOLING
Type of power plane
Cost (1977 dollars)
Coal-fired plant
Mass Extracted ]|" /status quo system \
Total Mass Cooled ft ^cooling tower cost/
Nuclear pressurized
water reactor
Mass Extracted
Total Mass Cooled ^ V cooling tower cost
x/status quo system j
st/
Capital cost of additional capacity is computed based on the assumption
it is provided by a conventional power plant located elsewhere on the utility
network. The cost of additional generation is estimated to be a fractional
component of the total cost of the power plant. Table 15 shows how to
compute this cost. Operation and maintenance costs are computed similarly
and added to the cost of the cogeneration system.
Fuel Costs
Fuel costs are the most critical variable in the analysis, and yet
they are the least predictable. Eastern bituminous coal is presumed to
be the primary fuel in the analysis, although alternative industrial fuels,
such as Western coal and gasified coal, are also considered. Nuclear fuel
is considered as an alternative for coal in utility size power plants.
59
-------
The current and projected costs for fuels are shown in Figure 14.
The fuel costs model is straightforward. The power plant model computes
annual fuel consumption which is multiplied by the cost of fuel to determine
the annual cost of fuel. Fuel for providing industrial back-up steam require-
ments (Y) are computed as follows:
v (D) (8760 Hours/yr) BPF
hB * Np
D = Hourly energy demand for steam at industry
BPF = Back-up Plant Factor
hg s Enthalpy of back-up steam
N = Efficiency of back-up facility.
TAi'LE 15. COST OF ADDITIONAL GENERATION
Type of power plant Cost (1977 dollars)
Coal-fired plant FracX 2,056, 175 (status quo system. ..)'
Nuclear pressurized _ v . . ,. _, . . ..6573
K FracX 4, 434, 861 (status quo system . )
water reactor capacity
Fr.cX5.U1.750(.t.t0. ,uo
(status quo systeincapacity)-(cogeneration 3y8temcapacity)
-- ^ -
Air Pollution Control Costs
The costs of individual pollution control devices a^e listed in Tables
16 and 17. Table 16 displays the costs of the air and thermal pollution
control devices for a 1000 Mw power plant and Table 17 di^olays the costs
60
-------
12
10
ft
s
•H
J*
9)
ft.
U
5
s
U
6
c
1975
1980
1985
1990
1995
2000
Figure 14. Cost of fuels.
61
-------
TABLE 16. RANGE OF AIR AND THERMAL POLLUTION CONTROL EQUIPMENT COSTS
FOR A 1000 MW UTILITY POWER PLANT
CAPITAL ($/tai)
O&M ($/kwhr)
fS/ke) (S/GJ)
Particulate
Electrostatic
precipitator
SO
X
Flue gas
desulfurization
NO
X
Combustion '
modification
Dry flue
gas treatment
SO and NO
X X
Simultaneous
treatment
Dry flue
gas treatment
Wet flue
gas treatment
Fluidized
High
30
7.0
120
27.9
10
2.4
30
7.0
131
30.3
110
25.3
Chosen
25
5.9
87
20
8
1.8
28
6.6
122
28.3
96
22.2
Low
10.8
2.4
48
11
6
1.3
28
6.6
65
1.5
96
22.2
High
.0003
.030
.0053
.530
.00033
.033
.0017
.170
.0044
.440
.0049
.490
Chosen
.0002
.020
.0014
.140
.0002
.020
.0011
.110
.0033
.330
.0045
.450
Low
. 00004
.004
.0008
.080
.0001
.010
.0011
.116
.0033
.330
.0041
.409
bed combustion
atmospheric
Fluidized
182
42.2
107
24.9
32
7.5
.013
1.30
.001
.995
.000
0
bed combustion
pressurized
Natural draft
Cooling tower
273
63.4
64.1
15
198
50.0
33.0
7.7
120
27.9
12.2
2.9
.021
2.10
.0048
.480
.0065
.650
.0048
.480
.000
.000
.0001
.010
(References: 7, 13, 33, 3U, 35, 36)
62
-------
of the air and thermal pollution control devices for a 12.6 kilogram/sec
industrial boiler. Both capital costs and operating and maintenance costs
are given. Operating and maintenance costs include all on-site non-capital
costs such as maintenance and energy costs plus off-site waste disposal
costs (such as for flue gas desulfurizatiun of fluidized bed combustion
systems). They do not account for capacity additions necessary for make-
up of power consumed by the control devices. Table 16 displays utility
pollution control capital costs in both $/kw and $/kg. Steam and operation
maintenance costs in $/kwh and $/GJ for easy comparison with the industrial
pollution control costs are given in Table 17. Most costs for the pollution
control devices vary over a wide range. This is usually due to the uncer-
tainty surrounding new control technologies or site specific considerations.
High, low, and chosen values are specified in each table with the high
and low values representing the extremes of the ranges and the chosen value
being the value used in the economic analysis. Fluidized bed combustion
costs presented are only the additional costs of a fluidized bed combustion
boiler when compared to a conventional boiler. These additional costs
are assumed to be the costs for pollution control.
TABLE 17. RANGE Of AIR AND THERMAL POLLUTION CONTROL EQUIPMENT
COSTS FOR A 12.6 KG/SEC (100,000 LB/HR)INDUSTRIAL BOILER
High
Capital
($/kg)
Chosen Low
O&M
(9/GJ)
High Chosen
Low
Participate
Electrostatic
preoipitator
SO
Flue gas
desulfurizacion
NO
33
55
11
40
9.9
23.1
.079 .054 .0045
.385 .236 .110
Combustion
modification
6.6 5.50
2.4
.079 .054 .006
SO and NO
x x
Simultaneous
treatment
Atmospheric Eluidizea
bed combustion H
Natural draft
cooling tower
6.6
4/.3
3.08 .246 .000
.141
(References: 18, 33. 37)
63
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The data in Table 16 and 17 were derived independently
(except for cooling towers) and then economy of scale equations were deter-
mined from the two sots of values to aid in calculating cost values for
plant sizes other than those given in the tables. The scaling factor for
both capital, and operation and maintenance costs for the industrial air
pollution control equipmer sed is 0.85. This is a conservative value
as opposed to other esti' •. . that tend to use scaling factors on the order
of 0.65 to 0.75. This tends to £ive the analysis a conservative bias (i.e.
less favorable to cogeneration since economies or scale due to cost savings
from air-thermal pollution centralization in cogeneration are reduced).
The calculated economy of scale factors that could be calculated from the
costs in Tables 16 and 17 are given in Table 18.
TABLE 18. ECONOMY OF SCALE FACTORS FOR
AIR POLLUTION CONTROL TECHNOLOGIES
Technology
Capital
cost
O&M
cost
Electrostatic precipitator .86
Flue gas desulfurization .85
Combustion modification .75
Atmospr.ere fluidized
bed combustion 1.29
.78
-89
.78
Average
.82(excluding
atmosphere
fluidized bed
combustion)
ECONOMIC ANALYSIS EXAMPLE CASE
The cost and energy models discussed in previous sections and discussed
in detail in Appendix C were used to evaluate the principl' of cogenaraiion
for a number of industry/power plant combinations. The specific example
that was introduced and used in Sections 5 and 6 will also be used for
the illustration of the economic analysis. The Results of additional cases
will be presented in later sections. All costs in this example have been
converted to 1977 constant dollars.
-------
Capital Coats
Initial construction costs are shown in Table 19• The costs of the
co&enerating utility i-jwe1* plant includes the cost savings in turbines
and cooling towers, and the additional costs of the supplementary utility.
It may be noted by the reader that there are several assumptions inherent
in this example case that are not consistent with the real world. For
example, flue gas desulfurization is not included in the calculation of
the cost for this example. This was omitted because this study is interested
specifically in the impact of cogeneration and not various other pollution
technologies. If pollution control technologies such as flue gas desulfur-
ization are included on both industry and utility size boilers, the cogener-
ation system is given a significant cost advantage due to economies of
scale, and it would then become necessary to address other issues that
are addressed in Section 6 relative to the environmental analysis. For
this specific example, the bottom line is that the capital cost of the
cogeneration system is 22.6 million dollars more than the equivalent conven-
tional or status quo system. However, it should be noted that this is
only a 4.2 percent increase in the total cost.
TABLE 19. CAPITAL COSTS OF EXAMPLE SYSTEMS
(Millions of 1977 dollars)
A B NET
Status quo Cogeneration B - A
Utility power plants
Base power plant 436.1
Electro-static precipitators 27.0
Natural draft cooling _?^il
Subtotal 498.0
Piping
55.0
7.8
Industrial boilers
Base boilers
Natural draft cooling
Subtotal
21.0
19.2
-4". 2
TOTAL
538.2
560.8
22.6
65
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Operation and Maintenance Coats
Table 20 is a tabulation of the operation and maintenance costs of
the example energy systems. Industrial boilers cost proportionately more
to operate than utility power plants and, thus, the coats of operation
and maintenance in the additional cogeneration facilities are balanced
by the coats of induatrial boilers. The costs shown are for the first
year and are expected to increase at a higher rate tna- "he wholesale price
index due to increasing problems of maintenance over time. However, the
difference in the first year cost is leas than 0.05 percent of the total
operation and maintenance cost. From a realistic point of view this differ-
ence is ins i^r. if leant and would have almost no impact on an investment
decision. The cost of operation and maintenance is included as part of
the life-cycle cost.
TABLE 20. OPERATION AND MAINTENANCE COSTS* OF EXAMPLE SYSTEMS
(MILLIONS OF 1977 DOLLARS)
First year operation
and maintenance costs
A B NET
Status quo Cogeneration B - A
Utility power plants
Base power plant
Electro-static precipitators
Natural draft cooling
Subtotal
Piping
15.9
1.7
1.7
19.3
0
2.3
.4
Industrial boilers
Base boilers
Natural draft cooling
Subtotal
Total first year costs
1.6
1.0
2.6
21.9
0
0
0
22.0
-2.6
0.1
*First-year costs
66
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Fuel Costs
The first year costs of fuel for the example analysis are shown in
Table 21. The cost differences reflect the significant reduction in fuel
consumption in the cogeneration system. These fuel costs in the cogeneration
system include fuel consumed in the cogenerating power plant, and in the
supplementary power plant. The plant factor (fraction of time during the
year that the system is operating) is assumed to be 0.9. This is high
for utility power plants that are operated for the prime purpose of producing
electricity. The net cogeneration fuel savings are $20.8 mil:ion annually,
a 16 percent decline in the cost of fuel. This saving is a direct result
of the reduction in the total fuel requirement that was discussed in detail
in Section 5. For purposes of analysis, it was assumed that the cost of
fuel escalated at a rate of 1 percent. This is a very conservative assump-
tion. A 30 year projection of the fuel costs of this example is included
in the print-out of the HAIES computer rodel in Appendix C.
TABLE 21. FUEL COSTS OF EXAMPLE SYSTEMS
(MILLIONS OF 1977 DOLLARS)
First year fuel cost
A B NET
Status quo Cogeneration B - A
Utility
Base power plant
Supplementary power plant
92.7
92.7
16.4
Subtotal
Industrial boilers
Total first year costs
Present worth (escalated at 1% annually)
92.7
37.1
129.8
1781.1
109.1
0
109.1
1496.3
16.4
-37.1
-20.7
284.8
Life-Cycle Cost
To this point, the discussion of costs has centered around capital
cost and the first year operating, maintenance, and fuel cost. Table 22
lists the capital cost and the first year cost for fuel, operation and
67
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maintenance. It is noted that after only the first year of operation the
net savings in fuel for the cogeneration system is approximately 90 percent
of the additional capital investment. The 20.8 million dollar saving will
occur annually and increase as the cost of fuel increases. This means
that in this example, the incremental costs of the cogeneration is recovered
within less than 2 years. However, facilities of the type included in
this example have an economic life on the order of 30 years. Therefore,
the net present value over the project life will give a batter indication
of the true value of applying the principle of cogeneration. In terms
of 1977 dollars, the life cycle net present value is 234.5 million dollars,
or approximately 10 times the additional capital cost.
TABLE 22. NET PRESENT VALUE COMPUTATION*
COST COST (Millions of 1977 dollars)
COMPONENT Status quo Cogeneration
Capital 538.2 560.8
First year O&M 21.9 22.0
First year fuel 129.8 109.1
^Assumptions: (1) Fuel cost eseallation rate is 1%; (2) Discount
rate _s 7%; and (3) Plant life is 30 years.
Sensitivity of Cost Variables
The economic analysis example showed cogeneration to be economically
viable; however, the analysis was based on general estimates. Sensitivity
analysis can provide a significant amount of information on the reliability
of the results in response to changes in the cost estimates.
As the cost models used in the analysis are only estimates which repre-
sent average values, the uncertainity of the net present value computed
may be high. Sensitivity analysis serves as a check to determine which
variables are most critical in the economics of cogeneration systems.
The equation for sensitivity of the independent variable x is:
68
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NPV, - NPV
1 o
NPV
Sensitivity (x) = =
xo
where
xQ s base value Tor independent variable
x1 = new value for independent variable
Sensitivity is a measure of the fraction by which net present value changes
in response to a change in the variable under investigation. The sensitivity
was used to rank the variables, and identify these that are most critical
to the economics of the cogeneration system. Table 23 displays the sensi-
tivity of cogeneration system economics to changes in key parameters.
Fuel costs, as expected, show the highest seisitivity. The discount rate
is also a critical parameter. Construction, operation and maintenance
costs of power plants, and industrial boilers possess moderate sensitivity,
because their magnitude is small related to the cost of power plant. Al-
though the variables listed in Table 23 are separate, it should be recognized
that they are not independent variables. For example, the capital cost
of power plants both utility and industrial are closely related, as are
th> operating and maintenance cost. As is shown in Table 23, the sign
of the sensitivity of these linked variables are opposite so that the net
rei ult would be much less than that indicated in this table. The following
sections will investigate the relationship between the net present value
and some of the most sensitive variables.
Sensitivity of Fuel Costs
The high energy efficiency of cogeneration provides significant fuel
savings. The fuel source in the example is coal, at a price of $.92/GJ.
MBtu. Although this price may vary significantly for different regions
in the country, an associated important variable is the rate by which fuel
prices will change in the future. The example case assumption for this
is a one percent escalation rate. Figure 15 is a plot of the net present
value as a function of the first year price of fuel. The example fuel
price is $-92 per GJ. As this figure illustrates, increases in the price
of fuel significantly increase the value of cogeneration. This is because
the same output product is produced with less energy. Figure 16 illustrates
how the net present value of cogeneration systems change as the coal escala-
tion rate is changed. The cogeneration system economics are attractive
at all realistic rates.
Sensitivity of Discount Rate
The discount rate is a critical variable in all economic analyses.
Many reports have been criticized due to their treatment of discount rate.
Lovins (38), in a critique of cost-risk-benefit analysis, claims that many
69
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1000
2 soo-
(B
^ 600 - -
s
H
400-
5
V
(0
2 200-
EXAMPLE
Fuel price ($/GJ)
Figure IS. Impact of first year coal price on net present value.
70
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1000
m
U)
w
0)
z
400--
200--
EXAMPLE
t
f
t
Escalation rate (percent)
Figure 16. Impact of coal price escalation on net present value.
71
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analysts adjust the discount rate to Justify their own preferences. We
attempt to avoid the pitfalls of otner studies by showing the sensitivity
of cogeneration economics to different discount rates. Figure 17 illustrates
that the net present value does not become negative a', discount rates within
the range of this figure. This occurs because the discount rate is an
indicator of '•tie time value of money. The general trend is for higher
discount rates to favor investments with a quick return on the investment.
Therefore, since the example returned the original investment in less than
two years, the net present value will be positive even for large discount
rates.
TABLE 23. RANKING OF COST PARAMETERS BY SENSITIVITY
Parameter
Fuel costs
Discount rate
Operating and maintenance cost of industrial boilers
Capital cost of utility power plants
Operating and maintenance cost of utility power plants
Capital cost of industrial boilers
Capital cost of cooling towers
Operating and maintenance cost of cooling towers
Capital cost of piping
Operating and maintenance cost of piping
Operating and maintenance cost of flue gas
desulfurizatlon equipment
Capital cost of flue gas desulfurization equipment
Operating and maintenance cost of particle control
Operating and maintenance cost of nitrogen oxide control
Sensitivity
+1.25
- .85
+ .39
- .46
- .38
+ .33
+ .07
+ .05
- .07
- .06
- .015
- .005
+ .015
J .015
n
-------
CO
14
o
•o
(0
o
01
10
0)
1000
800-
600 ~ -
400--
200--
EXAMPLE
9 12
Discount rate (percent)
Figure 17. Impact of discount rate on net present value.
15
73
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Sensitivity of the Capital Costa of Power Planta
Table 23 indicated that cogeneration economics showed moderate sensi-
tivity to the costs of power plants. The basic reason for this sensitivity
is that the cogeneration must include a supplementary power plant to replace
electrical capacity lost due to steam extraction. Thus, the cogeneration
system has some additional utility capacity. Figure 18 is the sensitivity
of net present value to changes in utility power plant costs. The sensitiv-
ity curve shows only a moderate amount of change in cogeneration system
economics. Even when power plant costs increase by 50 percent, the net
present value ia reduced by only 31 million dollars out of the original
234 million. It should be pointed out that the sensitivity of the net
present value to the capital cost of the power plant as indicated in this
figure is higher than would be anticipated in the real world. This is
because the assumption is made that capital uost of the utility power plant
is an independent variable, which is not true. In reality, all capital
costs, specifically for utility and industrial power plants, are closely
related. Therefore, the economic impact for variations in capital cost
are significantly less than would be indicated in Figure 18.
Sensitivity of Energy Transport Distance
Another important consideration that has not been previously addressed
is the relationship of the distance between the power plant and the industry
to the economics. In general, the closer the Letter, however, Figure 19
illustrates the relationship. There are two factors that cause the benefits
to reduce as distance increases. The first is the increased cost of the
piping and the second is the loss of thermal energy associated with increas-
ing distances.
The data used in this application was for systems that use saturated
steam as a transport media. However, there are several other transport
media tnat could be employed, including pressurized water and heat transfer
oil. The selection of the specific heat transfer medium will depend on
the specific factors such as application, distance, temperature, and quant-
ity. In general, all of the options will exhibit the same basic relationshio
between cost and distance. However, the general trend is that direct utili-
zation of steam is most economical for short distances while pressurized
water is most economical for greater distances. For applications such
as space heating, where the required temperature is low (38°C), it may
be economical to transport thermal energy as far as 80 km with pressurized
water. At the present time the use of hydrocarbon heat transfer oils is
prohibitively expensive in all but very specialized cases that require
high temperatures because of the high cost of these oils.
In-Plant Cogeneration
An alternative technical approach to cogeneration is in-plant cogenera-
tion. In-plant cogeneration is the application of the principal of cogenera-
tion within the industrial plant. Basically, the industry buys a boiler
74
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1000
09
M
CO
o
•o
0\
CO
o
800 --
600 --
>M*
3 400
-------
1000
800
I
i
600
> 400
c
g>
s
Q.
200
Example Case
Net Present Value of
In-Plant Cogeneration
Distance (km)
Figure 19. Impact of steam transport distance on net present value.
76
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that can provide the required quantity of steam but operates at a higher
temperature and pressure than is required by the process. By adding steam
turbines and electrical generators, the industry can produce electricity
with the high pressure steam and then use the exhaust from trie turbines
to provide the process heat. This technique is often employed in paper,
chemical, and petrolium plants. The present value of using inplant cogenera-
tion that provides the same thermal energy as the example case is 196 million
dollars. The solid line at 196 million dollars in Figure 19 illustrates
the relative value of inplant cogeneration as compared with transporting
steam over a distance. As is noted, large scale cogeneration is more cost
effective for distances of less than 2 kilometers, while in-plant generation
is more cose effective for separation distances greater Chan 2 kiloueters.
The 2 kilometer value is not to be considered as a general result. However,
the economics of in-plant cogeneration are well documented and will be
increasingly important in the future. In general, the planners of an indus-
trial complex of the size used for this example case would probably have
elected to employ in-plant cogeneration if large scale cogeneration was
not a practical option.
77
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SECTION 8
INSTITUTIONAL AND SOCIAL IMPACT
In develoDing a large Industrial complex, there are many institutional
barriers to overcome. These institutional barriers include regulatory,
licensing, political, and social. Although many of these barriers can
be overcome by satisfying simple formal requirements, some barriers are
difficult to specify, let alone satisfy. Most of the institutional barriers
are manifestations of real concerns of the society. In this section, the
institutional constraints are identified, and a simple method of evaluating
the impact of a cogeneration system on the local community is given.
INSTITUTIONAL CONSTRAINTS
Institutions are the structures within society. They include government
organizations; industries, banks, research organizations, consumer groups
and environmental lobbyists. Although cogeneration systems may be techni-
cally, economically, and environmentally favorable, institutior-1 constraints
may inhibit development. Problems of obtaining licensing, right of ways,
contracts, etc., reflect poor interfacing between institutions. Several
institutional constraints are discussed in this section.
Institutional Inertia Constraints
Society possesses an inertia to resist change. Institutions tnat have
been operating in a similar manner for several years tend to resist accep-
tance of other modes of operation. To overcome this inertia, energetic
support for the change is required, particularly in management.
Capital Formation Constraints
Many utilities face a severe problem in obtaining sufficient funds
to finance new power plants. They may find it even more difficult to find
adeqiate funding to pay the additional costs of a cogeneration system power
plant. A case in point is Union Electric's proposed construction of a
solid waste resource recovery system for the city of St. Louis. The plans
fell through in large port because funds originally allocated for the re-
source recovery system were needed to build new conventional electric power
plants. Capital financing of cogeneration systenis must involve utilities,
industries, banks, long term debt markets, and possibly government. Typi-
cally, utility projects have been firanced in the short term by bank loans
and in Mie long term by bonds. The utilities' inability to increase revenue
-------
as operating costs increase has made banks uncertain of the utilities earning
capabilities. For this reason, higher capital amounts are being required.
The same may be true for cogeneration systems. The large capital require-
ments force a multi-ownership situation between industries, and possibly
utilities. Multi-ownership arrangements present a host of contractural
problems. Cost and benefit sharing must be explicitly specified, and much
interface between tfe owners is required.
Contractual Constraints
Difficulties may arise in negotiating a contract for the industry to
purchase utility-generated steam. Variables include price, price escalaters,
steam supply reliability and ownership questions. The local Public Service
Commission may elect to become involved in the contracting procedure or
may oppose the project totally. The reliability question is crucial because
it will determine the extent of the utility back-up system. The industry
may have to purchase part of the system, in particular the piping on irdustry-
owned land.
Environmental Regulatory Constraints
A number of environmental issues are discussed in Section 6. Decisions
will have to be made regarding the acceptability of cogeneration systems
in areas of marginal air or water quality. An important problem occurs
when local, state and federal agencies have jurisdiction over the environment
of tne same area. In such cases, the utility or industry project planners
feel frustrated by the uncertainty of what the actual regulations pertaining
to the project are.
FPC Regulatory Constraints
The Federal Power Commission and state public service authorities will
be involved in setting the rate structure for energy (electrical and thermal)
produced by cogeneration systems which is used in the power grid. This
involves the accounting of the cost, or marginal cost of producing the
power which goes to the grid. Rates for energy used by the utilities must
be specified in the contractual agreements between utilities and industry,
depending on the ownership.
Licensing. Permits, and Right-of-Way Constraints
One of the most strategic points at which a project can be forestalled
is during the approval process. Persons or institutions opposed to a project
can apply pressure for the rejection, and sometimes even, revocation of
approvals. If steam lines have to cross private property, there could
be substantial problems obtaining the right-of-way due to the space and
safety problems. Another problem may oe with civil court actions brought
by irate local citizens. Large cogeneration systems would provide a likely
target for law actions involving anything from aesthetics to zoning, because
they will have the same characteristics of large utility power plants.
79
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Public Approval Constraints
One or the oust neglected parties in utility and industry projects
is the public, particularly those citizens who live near a proposed develop-
ment. Failure to include the public can eventually backfire and produce
united public opposition. An example of the consequences of such action
is the cogeneration system planned for Midland, Michigan. A nuclear power
plant is being constructed to supply steam to the nearby Dow Chemical com-
plex. However, public opposition has plagued the project. Construction
has been delayed for several years. More active solicitation of public
involvement during the planning stages might have prevented many of the
problems.
SOCIAL IMPACT ANALYSIS
In any comprehensive analysis, the impact of a cogeneration system
on a local community must be considered. A concentrated and rather abrupt
increase in the level of industrial activity results in demographic changes
in a locale which have implications in terms of housing, the demand for
public services, and tne size of the local private commercial sector.
Changes, resulting from a cogeneration system, affecting the general public
can be both positive and negative. To some extent, these community effects
can be anticipated, thereby allowing the opportunity to plan for timely
adjustments. The value of any such analysis lies in the fact that it is
a systematic, though generally imprecise, process of trying to alert society
to what logically might be expected. A social impact analysis itself is
not a plan for action; its real function is to raise the level of awareness
about potential consequences which would warrant attention. Its function
will have been served if th»: major problems which are actually experienced
in the implementation of a cogeneration system are identified in the anal-
ysis.
The overall approach was to determine the magnitude of the absolute
impacts of constructing and operating a large cogeneration system, given
that it is technically, economically and environmentally feasible.
There are two general objectives in this social impact analysis. First
the major changes that would be caused by a cogeneration system in the
host community are to be identified. Ihe second objective is to identify
general policies and location parameters which might mitigate possibly
undesirable impacts.
The social impacts of interest depend on two factors: the particular
cogeneration concept and the pre-existing demographic make-up of the host
community. Rather than treating a number of different concepts, just the
extreme case, a large cogeneration system, was examined. The impacts of
such a case constitutes an approximate upper limit on the impact expected
from other possible cogeneration system concepts. Basically, the analysis
determines the extent of change to population distributions when a cogener-
ation system brings additional construction and industrial workers into
a community.
80
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The methodology was developed considering potential impacts from a
large cogeneration concept, in a "typical small" and in- a "typical large"
host community. Interpolation of quantitative results gives a fair represen-
tation of the impacts from this large cogeneration system in any host commun-
ity of interest. Further, in generalizing results along another dimension,
some subjective scaling is used to extend the quantitative results to smaller
or larger cogeneration system concepts. This approach is deemed to be
an acceptable compromise between a completely general analysis which pre-
cludes any quantitative treatment, and the assessment of a specific cogener-
ation system concept in some actual community which allows little, if any,
generalization of results.
To approximate how changes in a host community occur over time, the
analysis was carried out for 3 time periods. Separate computations were
made for the large cogenerations system during its construction phase,
during the start-up of operation phase, and during its long-term operation
phase.
Multiplier Models
The methodology for determining population effects from a cogeneration
system installation is developed around the multiplier notion from economics.
This multiplier notion is presented here and used to estimate a host commu-
nity's population distribution. A certain fraction of a dollar received
by an individual, individual 1, is spent on the consumption of goods and
services needed to sustain his standard of living. Also, individual 2,
the recipient of that fraction of a dollar spent by individual 1, on the
average spenus the same fractional part of his revenue for his consumption
of goods and services. The same fraction of individual 2's expenditures,
receipts to other individuals, continues to be spent on their consumption
of goods and services. Theoretically this continues indefinitely. However,
talcing a practical limit and combining the fractions yields a multiplier
which is used to estimate total expenditures.
Expressing this same serial dependency notion in terms of man-days
of work per day, instead of dollars, yields the multiplier model used in
the present analysis. A simplified example should help to explain the
multiplier logic. Suppose we define a standard unit of output as one man-
day of work, and assume individual 1 is a producer of non-consumption goods.
Other workers are producers of consumer goods. Individual 1 and his family
consume fraction p of individual 2's output in man-days/day. Individual
2 and his dependents, spending some of the receipts received from individual
1, consume p of individual 3's output, and so on. The community's total
consumption per day resulting from individual 1's presence, expressed in
man-days/day, is C.
C = p •*• p * p * . . .
or
81
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C . ,
Where p is the Traction individual output consumed by a worker and
family.
To produce -rr man-days of consumption goods requires r- workers em-
ployed in the production of consumption goods, (r~ is called the multipli-
er). For every individual like individual 1, a producer of other than
consumption goods, there must be -£- other individuals to produce the neces-
sary consumption goods. In the cogeneration context, for a group of N
industrial or construction workers there must be a group of -r^— local commer-
cial workers to provide the necessary goods to sustain the entire work
force, i.e. N ( 1 •*> T^T)I plus their dependents.
The multiplier notion can be generalized beyond the area of consumption.
Similar reasoning can be applied to model other aspects of human behavior
and yield simple multiplier relationships to describe a community. Such
models presume that there is an identifiable steady state social structure
in a community. When a fairly large number of people are considered, this
static model of a community is quite reasonable. Excepting the influence
of the possibility of large numbers of people migrating into or out of
a community, social change is in fact observed to be a vp.-y gradual phenom-
enon. The problems will be much more severe for a small host community.
Essentially what is done in the present methodology is to superimpose the
structure of a new cogeneration system population on that of the host com-
munity.
Social Impact Models
Four multiplier models were developed to evaluate effects of a large
cogeneration system on small and large host communities. Appendix D contains
block diagrams of each model along with an explanation of parameter assump-
tions. The models estimate short term population effects of construction
as well as long term population effects of industrial activity. Three
sources of information (39, 40,41) provided the composition of different
sized communities, employment statistics by type of occupation, the multi-
plier factors, and the construction and operating parameters for various
industrial activities.
Figure 20 shows the model used for determining the population effects
from constructing a large cogeneration system in a large host community.
This is one of four models used to compute population effects of constructing
and operating cogeneration systeios in a host community. To apply these
models, one must specify the total work force needed to construct and operate
a cogeneration system, and the number and type of workers currently available
in the host community. Distribution effects are easily computed using
the indicated multiplier factors *n Figure 20.
82
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1D.1
LA
1B.1
PEAK
CONSTRUCTICH
oWUHhUiT
-IB. 2
PEAK REV
CONSTItUL'l KM
WORKERS
SINGLE-
STATUS
WORKERS
.1.82
8IHGLB-
STATUS
RODS me
OMITS
CD
10
1D.1
IB. 2
1C.1
•Subooqurat local aaployBnt opportunlclaa ar*
aaoioMd to a*l*t la a largo boat coBounity.
Tha population effect* of tha con*truction
phaaa ara therefor* takan to bo paraannt fat
all now *upport vorkara and for up to 1113 oaw
construction vorkar*.
PAWLT-
STATUS
WORKERS
HOUSIBC
UNITS
1D.2
11.4
ir.i
10. i
1B.1
u.i
IP. 2
1C.2
IB. 2
HJ.2
Figure 20. Population effects* for t lu ,-onst met ion phase: larRt-
cogeneratlon system ronci-pt in a large host community.
-------
These average factors were developed using population distributions
from small and large communities in the Atlanta metropolitan area. The
assumption is made that the factors represent reasonable values for this
type of social impact analysis of a hypothetical host community.
SOCIAL IMPACT ANALYSIS EXAMPLE CASE
The basic purpose of the example case analysis is to assess the observ-
able effects on a community of constructing a cogeneration system. It
is therefore necessary to identify those factors which could substantially
influence the effect either directly or indirectly. The parameters dealing
with the development of the methodology for the social impact analysis
included size of host community, type of power source of the cogenerating
utility, and construction scenario. These are the factors which are consid-
ered to have the most potential for altering the effects upon a community.
The analysis consisted of the steps shown in Figure 21. The particular
cogeneration system to be considered oust be specified in terms of the
type of utility (nuclear or coal), its size, the term and man-hour require-
ments for the construction of the utility and the various industrial plants,
and the industrial work force to be employed in the cogeneration system.
The host community in which the cogeneration system is to operate must
be defined in terms of its pre-existing employment levels by type (industri-
al, construction, other support), its demographic parameters (family units,
school age children, etc.) and idle resources (unemployment levels, housing
vacancy rate, etc.)
The third step is to specify a construction scenario. This is expressed
in terms of the extent to which there is centralized planning for all the
elements in a cogeneration system. The importance of this will be seen
in a later discussion. The construction scenario affects peak construction
requirements and the change in total labor requirements over the tern of
the cogeneration system construction phase.
Applying the multiplier models as described previously is a straightfor-
ward procedure which yields population distributions used to measure the
changes in the host community.
Cogeneration System
To quantify the social impacts, it is necessary to define a typical
large cogen»ration concept. A large utility power plant is taken to be
1000 MW, either fossil fuel (coal) or nuclear. The construction period
for the uti-lity is taken as six years. For a coal-fired power utility,
a peak construction force of 1000 workers is expected to be needed; for
a nuclear power utility, 2000 construction workers. The operating work
force for the utility is taken to be 125 workers and 100 workers for coal
and nuclear, respectively. The specific composition of the accompanying
new industrial community is not critical for present purposes. A few large
84
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SPECIFY A COGENERATION CONCEPT
SPECIFY A HOST COMMUNITY
SPECIFY THE CONSTRUCTION SCENARIO
I
APPLY MULTIPLIER MODEL
DETERMINE CHANCES Hi THE HOST COMMUNITY
Figure Jl. Steps in t lie social Impact .inalvsis.
8=;
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plants or many small planes may be assumed. The assumption used is that
the total construction effort will oe 15,000 man-years and the total indus-
trial employment will be 5000 workers. Individual industrial plants are
expected to take, on the average, three years to build. These input figures
are representative of the list of corresponding ranges of values cited
in Reference 10.
The methodology presented in the beginning of this section produced
the community multiplier models shown in Appendix D. Beyond their use
in specifying the host communities, these constitute the basic models employ-
ed in quantifying the cogeneration system social impacts. To apply them,
all that is needed is an estimate of the appropriate work force (construction
or industrial workers) and estimates of the numbers and types of workers
currently available in an cogeneration system host community.
It would be expected that in building a cogeneration system, individual
construction projects would gradually require more and more workers, reach
a peak, and gradually require fewer and fewer workers until each is complet-
ed. For this analysis, a reasonable approximation to the cogeneration
system construction profiles are shown in Figure 22.
The difference in the length of the construction period between the
utility and the industrial plants gives rise to different construction
scheduling possibilities. Two extreme cases are considered. First, individ-
ual industries might schedule their own construction so that it will take
three years and be completed concurrently with the construction of the
utilit-. This schedule, called "not coordinated construction," eliminates
unr.cessary periods of idle (non-incomp earning) capital investment prior
to industrial operation. From the industry standpoint, this is the most
desirable. Figure 22a is a model of "not coordinated construction." The
other extreme, a "coordinated construction" effort, is a schedule wherein
the industrial construction is staggered ever time to span the entire six
years required to build the utility. A model of coordinated construction
is given in Figure 22o. During the first and last 1} years of cogeneration
system construction, there are gradual changes in the number of construction
workers. In the interim three years, the aggregate non-utility construction
work requires a fairly constant number of workers. The total man-hours
required for construction is assumed to be the same for either coordinated
or not coordinated construction.
Superimposing the construction manpower requirements given earlier
for the utility, on those shown in Figures 22a and 22b for the industrial
plants gives the profiles shown in Figures 22c and 22d for a nuclear and
fossil fuel power utility. In each of these figures, the peak work force
for both coordinated and not coordinated construction are shown along with
the long term cogeneration system employment.
Large Cogeneration System in a Large Host Community
Table 24 shows the summary results for a large cogeneration system
86
-------
IWBUU luuiuu i> m
OPIIBKTICII wo ontaw*
m ui •« MMIUM. rum
/IHMTIML
11.000 MB 1
|4-"omK.iia rtnoo ra» m iniun-
Figure. 22a.
ii.a
/ BICUIIBI or a>
1.100
b i »,«.
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aoom»»tl» omrriairTlo
uauiuD u m
o oMut
ro> «u. an uowTtui
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(11.001 HW-ILUI)
-».tL
|<— oantHiciioi niuo rot nu iniun-
Figure 22b.
- onuttK ruioo-
Figure 22c. Figure 22d.
Figure 22. Cogeneration system construction profiles.
-------
TABLE 24.
LARGE COCENERATION SYSTEM [N A LARGE HOST COMMUNITY-
THE FIRST EIGHT TO TEN YEARS
(1000 MW POWER PLANT)
OD
oo
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-------
TABLE 24. (CONTINUED)
00
-------
in a large community obtained using the multiplier mode hi in Appendix D,
and input data for the large host community shown in Table 2U. for each
of the comiounity parameters, Table 24 shows the value that existed prior
to the advent of the cogeneration system. For each phase in the cogeneration
system deve'.opment, the percentage increase in the pre-existing value of
the community parameter is shown for both a nuclear and a coal power utility.
The per antage increases shown graphically in the bar chart were computed
for be'.h a coordinated (cross hatched) and not-coordinated (solid white)
construction scenario. The figures in the far right opposite each of the
bare n the figure are the numerical values of the percentage increases.
Expressed as percentage change, the results shown in the figure all<_w compar-
isons to be made across community parameters to determine what aspects
uf the host community will be most affected by the cogeneration system.
The percentage change format further allows results to be extrapolated
to other host communities.
General observations about the quantitative results in Table 24 can
be made by considering each phase in the cogeneration system development
separately. The major features of the impact of a large cogeneration system
in a large host community are discussed below.
Peak Construction Phase—
If the Construction work is coordinated, peak employment will be reached
roughly three years after the beginning of the cogeneration system construe'
tion. If industries are left to schedule construction projects independently
(not coordinated construction), peak employment will be reached after roughly
4J years. The host community is expected U» supply some of peak labor
requirements. Only the new labor immigrating to the cogeneration system
will require increased support from the community in terms of housing,
public services, and consumer goods and services. The four to six percent
increase in housiig requirements with coordinated construction over three
years, should be easily met. The 24 to 26 percent increase in housing
requirements with not coordinated construction would, in most cases, overtax
the local housing industry since most of the increased demand is expected
to occur during only a U year period beginning in the third year. A surge
in the demand for moderate cost housing may result in overcrowding, artific-
ally high rents and a general decline in the quality of new housia'j. Though
overcrowding would be remedied as the housing supply expands, the .sudden
interim worsening of living standards tends to cause irreversible and general
declines in affected neighborhoods. Inferences may be drawn about the
long term changes in the local tax base, crime rates, and other ?jcial
problems based on similar observations of general decline seen in large
urhan areas.
The larger peak work force required if cogenerations system construction
is not coordinated is likely to far exceed the immediately available work
force, causing wage rates to become artifically high. Wage increases would
be expected to occur in both construction and non-construction jobs since
these necessarily compete for workers in the general labor market. The
institutional forces that historically have prevented wages from decreasing
90
-------
once tney have risen, (i.e., labor unions and employment contracts;, might
foster high levels of long run employment.
Without a coordinated cogeneration system construction effort in which
labor requirements are distributed over an extended period, excessive demand
for labor is very likely to occur. Because this situation is remedied
by an influx of workers, over-crowding and neighborhood decline are probable
consequences of inadequacies in housing and public services. To the extent
that the excess demand for labor .LS reduced by wage increases, inflationary
pressures will mount affecting both the local community and the construction
costs and completion Jate of the cogeneration system. Some disruption
in the local economy may be expected to result if construction wages become
high enough to divert local labor from other employment. Though generally
expansionary in character, the local economic changes occur over a short
period of time. They are likely to foster uncertainty and thereby will
not stimulate needed community capital investment. The only recourse will
be to over-utilize existing . .
-------
the host community's economy being temporarily in a poorer state tn?n it
had been prior to the beginning of the cogeneration system. The detrimental
impacts of the construction phase can be greatly reduced by the coordinated
construction approach, by reducing the total number of workers required
as well as by reducing the fluctuations of the work force. To the extent
that the local populace perceives this cause and effect relationship and
fails to see the condition as temporary, resistance to its further indus-
trialization may be created. Such opposition may result in the passage
of local ordinances and other political action aimed at restricting or
discouraging future industrial expansion.
It should be noted that the impact differences between a coordinated
construction cogeneration system and one in which construction had not
been coordinated persist well beyond the construction phase. This is mainly
due to the fact that differences in the changes in housing construction
and the expansion of the local commercial section, dictated by differences
in previous peak employment levels, are not easily reversed.
Full Operation Phase-
As might be expected, the long run changes in the community caused
by the cogeneration system appear to be almost completely independent of
whether the construction had been coordinated or not. The slight differences
(typically on the order of one percent that will persist derive from the
disproporionately high outflow of single-status workers that would have
followed an uncoordinated construction phase.
Excepting the clearly undesirable impacts of temporary unemployment
and housing vacancies, the community parameters will have all increased
by roughly 33 percent. This demonstrates the multiplier effect: the crea-
tion of roughly 10 percent more jobs in the local community (the long run
new industrial employment of the cogeneration system) causes a 33 percent
increase in tne size and level of economic activit/ of the community.
The analysis shows little difference in impact between cogeneration
system with a coal-fired utility and one with a nuclear utility. This
is probably a valid conclusion in te.-ms of measures used here to characterize
a host community. A real difference betwen the two may still exist in
terms of less tangible measures, (e.g. community attitudes on safety and
pollution).
Large Cogeneration System in a Small Host Community
Beyond its size, the main feature which distinguishes a small host
community from a large host community is the fact that it will be able
to provide little, i" any, of the labor required to construct and operate
a cogeneration system. The small community's existing public services
would generally be inadequate to support a cogeneration system. In particu-
lar, water treatment plants, schools, and health and safety facilities
are likely to require immediate expansion. Even in the short term, more
92
-------
intensive use of existing facilities is not likely to be a practical way
of meeting the needs created by a large degeneration system, as had been
the case in the large host community. The major features of the Impact
of cogeneration system in a small host community are discussed below.
Peak Construction Phase—
If in a small host community, there is coodmated cogeneration system
construction, the 45 to 56 percent increase in housing requirements (occupied
dwellings) over a three year period (roughly 1500 new units) is likely
to be more than the local residential construction industry could provide.
If housing units were built in groups of four or five so that each required
as little as six total man-months of labor, less than 3100 units could
be built in the three year period. Allowing for weather conditions and
more realistic scheduling conditions, probably less than half the needed
units could actually be completed. If the construction is not coordinated,
about 10,000 new housing units would be needed with a UJ year period.
Less than a third of these could reasonably be expected to be completed
by the resident construction industry. Given the generally rural conditions
assumed to exist around the small host community and the extreme pressure
on housing, it is likely that a large number of mobile homes would appear.
In this case, much of the investment in housing would have been diverted
outside the local economy and the potential increase in the property tax
base substantially reduced.
The 100 to 200 percent increase in construction workers and corresponding
25 to 66 percent increase in the supporting commercial workers should signifi-
cantly change the character of the community. A predominance of construction
trades in the rapidly growing work force and the expectation that a majority
of these will be short term residents and not be living locally in family
units might actually reduce the amount of non-cogeneration system capital
investments and interrupt any previous growth that had been underway.
A large portion of the local population will feel no real vested interest,
long term or even short term, in the community.
Any wage and price stability that had existed in the community is likely
to be lost. The expected surge in the demand for labor and consumables
is likely to create correspondingly high pressure to increase supplies
and prices. Expanded supply levels will probably be frustrated by local
reluctance to make the necessary capital investment in economic capacity.
The local increase in demand would then result in significant and rapid
wage and price increases and, to a much lesser extent, in increases in
the quantitites of goods and services provided in the community.
Phase Just Prior to Operation—
Anticipating that there will be little opportunity for suitable long
term employment, most of the cogeneration system construction work force
will leave the host community toward the end of the construction phase.
Appreciable induced unemployment is to be expected in the commercial sector,
roughly 10 and 2t percent above normal for the coordinated and uncoordinated
cases, respectively. Despite the higher emigration from a small host com-
93
-------
munity, the cogeneration system would tend to cause higher employment in
a small community than in a large one.
The actual housing surplus and newly developed residential land just
prior to operation may be somewhat less than the figures indicated in Append-
ix D. Those figures are based on the assumption of no house trailers being
used to alleviate the earlier peak construction housing shortage. The
figures in the table should be reduced accordingly if a significant number
of house trailer.* are observed during the construction phase.
It should be noted that there are only small differences between the
impacts of cogeneration system with a nuclear power plant and one with
a coal-fired power plant. As is the case for the cogeneration in a large
host community, attention should be directed to the differences in cogener-
ation system impacts which derive coordinated versus uncoordinated construc-
tion.
Pull Operation Phase-
In the long term, all the community pressures associated with high
rates of change in demand will have to be alleviated by expanded public,
commercial, and industrial capacity. A demographic and economic equilibria!
will be reestablished and the community will have roughly doubled in size
and doubled in the level of economic activity. Such appreciable growth
in an originally small community would generally be accompanied by some
economies of increased scale and some increase in the variety of locally
available goods and services. Both of these are usually precursors to
or are directly associated with a general improvement in the recreational-
cultural facilities and a greater number of local economic opportunities.
GENERALIZATION OF RESULTS
More complete comparisons of changes in small and large host communities
for a conventional and nuclear power utility, respectively, are given in
Appendix D. The impacts as measured in percentage change are seen to be
inversely related to the size of the host community. The cogeneration
system induced rates of change of the demographic and economic parameters
of a community are also inversely related to the size of the community.
For a large cogeneration system, changes in a small nost community are
likely to be so large and so sudden that they will be detrimental. However,
a larger host community, having relatively greater capacity to accommodate
the cogeneration system using existing resources, should fare much better.
A sufficiently large community would be expected to experience a more moder-
ate rate of induced economic growth and show generally positive, desirable
changes in its community parameters.
Acceptability criteria for social impacts have not been established
in this study. Nevertheless, it seems clear from the contrasting impacts
of a large cogenerataon system in the small and large host communities
that there exists some larger host community which can adequately accommodate
large cogeneration systems. Interpolation of the quantitative results
-------
should yield the minimum community size apropnate. This analysis might
be repeated for one or more small cogeneration systems to yield the curve
shown schematically in Figure 23. If a cogeneration system and host commun-
ity gave a point below the curve, the ensuing social impacts would be unde-
sirable unless some appropriate counteractive measures were undertaken.
Generalizing from the tabulated results in this section, the cogeneration
system impacts are four to five times greater in a small community than
in a large one. Although it depends partly on the migration assumptions
made in the analysis, it is nonetheless clear that the larger the host
community, the more social-economical benefits the original residents will
receive. Conversely, the social-economic impact will constitute a burden
to the original residents in a small host community. Most cogeneration
system social-economic benefits will accrue to the transient and new perma-
nent residents in a small host community.
The coordinated construction scenario will produce far less traumatic
impacts on all community parameters than the non-coordinated construction.
This typically two to five time larger adverse impact, for non coordinated
construction, appears for both small and large host communities, in both
nuclear and coal utilities.
Based on results of the multiplier model analyses and references drawn
above, steps which could be caken to minimize the impacts of cogeneration
development were identified. These are not exhaustive or unique of cogenera-
tion systems; they are illustrative of the options which might be desirable
or practical.
a. Restrictions on the minimum size community which can be selected
as a site for cogeneration development.
b. Approval of over all development plans by the host community.
c. Having the cogeneration system firms bear the initial cost of
expanded public services. This cost might eventually be trans-
ferred to the new industrial community by imposing some focused
tax scheme, e.g. temporary excise taxes on payrolls or property
of new industry, and rebates to the construction firms.
d. Development of provisions to control the rate of wage and price
increases.
e. Development of provisions to provide adequate assistance in the
expected period of high-level, short-duration unemployment.
f. Establishment of comprehensive zoning ordinances to preclude
residential profiteering by permitting an undesirably high
proportion of low cost housing. (Care should be taken to insure
the proper distribution of growth across the host community.)
95
-------
Implementation of a cogeneration system, like any other major develop-
ment which causes change In a community, should be carefully planned Rates
and percentage changes in community parameters must be considered if appro-
priate expansion of community resources is to be possible. Uncontrolled
social impacts can alternately produce over investment and over utilization
of public and private facilities. Such excesses, even if short lived,
generally have very adverse social and economic effects on specific segments
of a community. The social costs and benefits, though less easily estimated
than are the technological costs and benefits, still require careful and
thorough consideration.
Positive social impact.
Negative social impact
Size of the cogeneration nystem concept
(Industrial workforce in thousands)
Figure 23. Relative sizes of the cogeneration system
concept and the host community.
96
-------
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APPENDIX A
COST-BENEFIT ANALYSIS
A cost-benefit analysis is an estimation and evaluation of net benefits
associated with alternatives for achieving defined goals. Techniques used
in identifying and comparing cost and benefits are almost as numerous as
existing analyses. Nevertheless, some principles and guidelines can be
stated.
Cost-benefit analysis is based on Depuit's concept of consumer's surplus
(42). The tool has been developed extensively in planning for water-related
projects, especially since the Congressional mandate in 1936. Cost benefit
analysis has been applied to many other problems as well, e.g., defense
systems, aerospace activities and agricultural projects.
As applied welfare economics, cost-benefit analysis uses a decision
criterion identified as the potential Pa.-eto superiority criterion which
labels a project as superior if those who gain from the project would comprn-
sdtj those who ose so that none would be worse off with the project. This
criterion identifies net benefits and forms the basis for a more detailed
review of decision criteria.
Many criteria have been suggested as appropriate for evaluating alterna-
tive projects. Some, such as net present value and benefit-cost ratios
have a long history of use in cost-benefit analysis and some, such as cut-
off and pay-back criteria, have been employed only occasionally in public
expenditure evaluations. The net present value criterion was used in this
analysis.
NET PRESENT VALUE
The net present value (NPV) method reduces a stream of costs and benefits
to a single number in which costs or benefits which are projected to occur
in the future are discounted. For example, if a project is expected to
yield a benefit worth $100 next year, we might value that $100 next year,
as $95 today. The formula is
Bi - ci B»- - cf B« - cn
MPU r
NPV = -C
0 (1 + d) (1 * dT (1 •» d)n
where C is the dollar value of costs incurred at time t,
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B is tne dollar value of benefits incurred at time t,
d is the discount rate, and
n is the life of the project, in years.
The principa^ problem associated with using the net present value method
is the determination of the appropriate discount rate. However, the consid-
eration of a range of reasonable values is often sufficient in a cost benefit
analysis. If the net present value is greater than zero, the project is
determined to be economical and should be undertaken. Of course, the higher
the net present value, the more favorable is the project. Another advantage
of net present value is that it can be related to units of production.
The net present value can be spread into a series of equal annual values
using the following formula:
Annual Equivalent (AE) = NPV il *<*)*<*
(1 * d)n - 1
Then the annual equivalent can be divided by annual production (e.g., kilo-
watt hours generated by a power plant to determine the cost per kilowatt
lour).
BENEFIT COST RATIO
The benefit-cost ratio (B/C) ii normally defined in terms of discounted
values. Tfce formula for computing the benefit-cost ratio is
$—^
l=2_Jl_t_dl
S-^
t^O (1 •» d)
While this has been traditionally a popular criterion, it is sensitive
to the definition of benefits and costs. While, it would seem that a posi-
tive benefit should be identical to a negative cost (of the same magnitude),
it clearly makes a differenca in the calculation of a ratio whether a sum
is added to the numerator or subtracted from the denominator. An appliciton
where this difficulty is likely to surface is in the assessment of external
effects, e.g., pollution. Is a reduction of pollution a positive benefit
to society or a reduction in cost? It is clear from its definition that
the net present value criterion suffers from no such ambiguity.
IDENTIFICATION AND QUANTIFICATION OF COSTS AND BENEFITS
The most important aspect of a cost-benefit analysis is the identifi-
cation of all relevant costs and benefits. Second only to this in importance
is the quantification of such costs and benefits. The Justification for
quantification is to facilitate the analysis of trade-offs.
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Once relevant cost and benefits have been identified, a scenario for
analysis must be developed; that is, a determination of the goals of the
project. If, for example, a cogeneration system is to be built, is the
real objective to concentrate industria. activity in a single location
for aesthetic reasons, to decrease energy coats, to increase local employment
or to minimize profits? When this quesiton is settled, a set of accounts
must be devised through which to organize the analysis. This process is
based on experience and observation and, to some extent, public law. Federal
projects, for example, require both national economic development and envir-
onmental accounts, with distributional accounts (using regional development
or income-class categories) displayed for information. After the summary
accounts are established, the analyst must identify the benefits and cost
appearing under each account and carefally check for double-counting prob-
lems.
In the economic and energy efficiency analysis, a number of costs and
benefit categories were identified. In addition to fuel costs, capital
cost, and operation and maintenance costs for a large power plant, a number
of additional costs are separated and identified. Among these are capital
and operation and maintenance costs for specific pollution control equipment
such as SO scrubbers, electrostatic precipitators and cooling towers.
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APPENDIX B
TECHNOLOGY SURVEY
The following sections will address the technical aspects associated
with supplying industrial energy needs with multipurpose power plants.
The specific topics addressed will be power systems, industry applications,
pollution control and cogeneration.
CONVENTIONAL POWER SYSTEM
Hast electric power is produced by steam which is used as the working
medium in coal, oil and nuclear power systems. Although the specific hardware
may vary depending on the source of heat energy, the basic principles of
steam electric generation are the same (43, 44).
Basic Steam Cycle
Because of its unique properties and natural availability, water has
been used for many centuries as a working fluid to convert thermal energy
to mechanical energy. As a result, the physical and thermodynamic properties
of water and steam have been studied in more detail than any other fluid.
Figure B-1 shows a simple representation of a steam-electric generation
system. Water is pumped into the boiler under high pressure, and the boiler
adds heat until the water undergoes a phase change to a high pressure steam.
This high pressure steam expands in the turbine until it reaches atmospheric
pressure.
The operation of a power plant approaches that of the Rankine cycle,
which was independently proposed by Rankine and Clausius. Figure B-2 is
the temperature-entropy (T-S) diagram of the basic Rankine cycle. All
steps are assumed to be reversible. Liquid is compressed isentropically
from points A to B. From B to C, heat is added reversibly to heat the
compressed liquid and convert it to superheated steam. Isentropic expansion
with shaft work output takes place from C to D and unavailable heat is
rejected to the atmosphere from D to A. The area enclosed by the path
is the usable thermal energy, and the shaded area is the energy that is
unavailable for useful work.
Improvements in Basic Rankine Cycle—
If the Rankine cycle is closed in the sense that the same fluid repeat-
edly executes the various processes, it is termed a condensing cycle.
Higher efficiency of the condensing steam cycle is a result of the particular
114
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BOILER
GENERATOR
WATER
Figure B-l. Steam-electric power generation.
115
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SATURATED
VAPOR
CRITICAL
TEMPERATURE
Entropy S
Figure B-2. Temperature-entropy (T-S) diagram of
the basic Rankine cycle for steam power
plant using superheated steam.
116
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pressure-temperature relationship between water and its vapcr state, steam.
Tne lowest temperature at which an open or noncondensing steam cycle may
reject heat is approximately the saturation temperature of 100 °C. This
corresponds to normal atmospheric pressure of approximately 101 kPa.
The condensing cycle takes advantage of the much lower sink temperature
for heat rejection available in natural bodies of water and the atmosphere,
and the discharge pressure is the saturation presure corresponding to a
condensing temperature which may be 38 °C or lower. The decrease in the
exhaust pressure results in an increase in the heat available to do the
work.
Figure B-3 shows the T-S diagrams for several modifications of the
Rankine cycle and the relationships between energy that is avialable to
produce electrical energy and the unavailable energy. Figure B-3a is typical
of a simple, open cycle steam turbine system such as the one previously
depicted in Figure B-1. For open cycle operation, the exhaust is at atmos-
pheric pressure, therefore the temperature is 100 °C or the temperature
of boiling water. By condensing the steam and reusing the condensate,
the exhaust temperature can be reduced to approximately 38 °C. The asso-
ciated improvement in efficiency is reflected in Figure B-3b, by an increase
in the usable energy and a corresponding decrease in the unavailable energy.
Another successful technique to improve the efficiency of the steam
cycle is to reheat the steam after it has partially expanded so that conden-
sation will not occur at high pressures. The diagram of such a reheat
steam cycle is shown in Figure B-3c. In this cycle, the water may be heated
to approximately 550 °C at a pressure in excess of 20 MPa AS the steam
expaids, the temperature decreases quickly and the steam begins to condense
at pi-essures that are still high enough to drive turbines. The steam is
rehe-tted in the boiler to approximately 550 c without increasing the
pressure. Now the steam contains sufficient energy to drive one or more
additional stages of the turbine to produce usable mechanical energy.
Figure B-3d is for a modern steam power cycle condensing system with
single reheat and regenerative feedwater heating. Regenerative feedwater
heat .ng is done by extracting steam at various stages in the turbine to
heat tne feedwater as it is pumped to the economizer and boiler.
Figure B-4 is a diagram of a widely used supercritical steam cycle
showing schematically the arrangement of various components Including the
feedwater heaters. This cycle also employs one stage of steam reheat which
is still another method cf increasing the mean high temperature. Regener-
ative heating is used in all modern condensing steam power plants. It
not only improves cycle efficiency but has other' advantages, such as lower
volume flow in the final turbine stages and a convenient means of deaerating
the feedwater. The steam power-cycle diagram of Figure B-4 uses fossil
fuel which is burned with air. A large portion of the resulting heat is
117
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CONDENSING CYCLE
Figure B-3b'
Figura B-3c
Figure B-3d°
Figure B-3. Improvements in basic RntU i ni' cvt
118
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(13)
(16)
Description:
(1) Stack
(2) Air Heater
(3) Fuel In
(4) Flue Gas Recirculatlon
(5) Ash Pit
(6) Air In
(7) Economizer/Boiler/Superheater
(8) Reheater
(9) High Pressure Turbine
(10) Reheat Turbine
(11) Low Pressure Turbine
(12) Condenser
(13) Net Power
(14) Regenerative Feedwater Heaters
(15) Boiler Feed Pump
(16) Waste Heat
Figure B-4. Power cycle diagram of a modern fossil fuel power plant.
119
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then transferred in the boiler for generating and superheating 3'.cam.
The remaining heat is discharged to the environment. The principle of
regeneration is employed in an air heater to recycle low level (low temper-
ature) heat from the combustion gases which would otherwise be rejected
to the atmosphere through the stack. Feedwater heaters, on the other hand,
utilize heat from steam which coulo have been partially converted to work
by further expansion thorugh the turbine. Both types of regeneration will
increase cycle efficiency and reduce waste heat if used properly.
Limits to Efficiency—
In steam power plants operated solely for the generation of electric
power, thermal efficiencies are limited to a maximum of about 39 percent
in fossil-fuel plants and 34 percent in nuclear plants (44, 45). More
than half of the energy released from the fuel is wasted and must be trans-
ferred to the environment in some way. This is usually done through *.
condenser, resulting in the heating of seme body of water or the air.
Coal Power Plants
Coal-fired fossil-fuel power plants will be addressed specifically
at this point. Coal is emphasized because it is the most abundant fossil
fuel available in the United States and it will become more important as
other fuels become more scarce.
A modern coal-fired power plant is a complex set of processes that
burn coal to produce high pressure steam that can be used to drive turbines
and produce electricity (43, 46, 47). The major functional components
of a coal-fired power plant are: coal supply system, water treatment system,
boiler, turbine-gei.erator system, flue gas treatment system, and cooling
system. Figure B-5 is a simplified representation of the flow of the three
major materials (air, coal, and water) used in a coal fired power plant.
Coal Supply System--
The coal supply system involves the transportation of coal to the power
plant, storage, and pulverization. Coal is normally transported by rail
or barge and stored in large piles until it is needed by the power plant.
The transportation and storage sytems and the associated material handling
equipment must be capable of handling large quantities of coal, since a
large coal fired power plant (2500 MW thermal) uses about 7700 tonnes of
coal per day. The cost associated with transporting and handling coal
can be prohibitive for small power plants.
Coal burned in modern power plants is usually pulverized to increase
efficiency and enable the production of a high temperature flame that can
be controlled. The advantages of coal pulverization are partially offset
by high capital and operating costs of the pulverization and dust control
equipment, and increases in the production of fly ash.
Water Treatment System—
The water that is converted to steam in the boiler must be highly pur-
ified to prevent corrosion or buildup of deposits in the boiler. The primary
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Figure B-5. Material flows through coal fired boiler.
121
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purpose of the water treatment system is to provide water that is suffici-
ently free of minerals and gases for safe operation of the power plant.
The requirement for water treatment is common to all steam boiler systems
whether ~oal fired, oil fired, industrial, or nuclear. A large power plant
commonly uses between 22 to 37 thousand cu m of water per hour. However,
the principal source of water is condenaate that is recycled from the tur-
bines, and only 2 to 5 percent raw water must be treated to replace lost
condensate.
Boiler—
Boilers are essentially furnaces having walls lined with water-filled
tubes that burn fuel at high temperatures, and convert water to steam.
Boiler operation is a delicate balance between water flow and combustion
temperature. Water is pumped into the boiler until it reaches the desired
temperature. High pressure water is heated in the economizer and in effect
recovers heat that would normally be ejected into the environment in the
form of hot flue gas. From the economizer, the water flows into the boiler
where it is converted to steam. After the water is converted to steam,
additional heat is added in the superheater before it is used in the tur-
binas. In some cases, steam is returned to the reheater after going through
the first stage of the turbine to prevent condensation in later turbine
stages. Present constraints on material design limit the maximum steam
temperature and pressure to approximately 540°c and 24 kPa.
Turbine-Generator System--
The steam turbine converts thermal energy in the steam into mechanical
energy. The operating principle of the steam turbine is relatively simple
(18). The only major moving part is the rotor, which contains sets of
blades. There are two methods of using steam in a turbine. The first
method allows the steam to expand through a nozzle which produces a stream
of high velocity steam. When this high velocity steam strikes the blades
on the rotor, the energy is transferred to the rotor in the form of an
impulse. A second method allows the steam to expand as it flows through
a series of fixed and moving blades. Mechanical rotation results from
a reaction to the forces produced by pressure differences, turbines are
classified either impulse or reaction type, depending on which method of
energy conversion is used.
To extract the maximum energy from the steam, turbines may have many
stages or sets of blades. The diameter of eacn successive set of blades
must be increased, because as the steam expands, its volume increases.
For applications that employ high pressures, it is not unusual to employ
several low pressure turbines in parallel to limit the diameter of the
blades. It is desirable to limit the blade size to limit tlw centrifugal
forces that are encountered during the high speed operation.
Turbines are selected based on anticipated operating conditions. Flexi-
bility in the operating conditions allows two important applications of
the steam turbine. Back pressure turbines are specially selected turbines
that accept hi: * pressure steam and exhaust steam from the turbine at pres-
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3urea well above atmospheric pressure, "'or example, a back pressure turbine
may have an inlet steam pressure of 7 MPa and an outlet pressure of
720 kPa. In a large utility power plant there may in effect be several
back pressure turbines that are operated in series followed by a condensing
turbine. The term condensing turbine refers to the conditions of the exhaust
steam in the condenser which ia at the pressure of condensing steam (i.e.,
1.5 inches or 38 mm of mercury). The extraction turbine is specially de-
signed so that steam can be extracted at pressures sufficiently high for
uses other than driving a turbine.
From a practical standpoint, there is a wide range of possible turbine
combinations that are available during the design phase of a power plant.
However, once the turbines are installed, much of the versatility is gone.
Manufacturers market turbines in a range of sizes, and esentially every
large turbine is custom designed by selecting standard size blades that
satisfy the steam inlet and outlet conditions. By applying this modular
design approach, the manufacturer can provide turbines that operate at
near maximum efficiency for a wide range of applications.
The rotation shaft of the turbine can be used to power any number of
mechanical systems. However, the most common application of large turbines
is to power electric generators.
Flue Gas Treatment System—
The flue gas treatment system removes particles and ^ases from the
flue gas that would be harmful to the environment. The cost of pollution
control is significant in terms of capital, labor, and energy. It is impor-
tant to note that flue gas treatment is primarily a direct response to
government regulation.
Cooling System—
From a functional standpoint, the cooling system consists of a heat
exchanger or condenser that actually condenses the steam, and a heat sink
that can absorb the heat from the condenser steam. The heat sink is always
the environment. In some cases the heat is ejected from the condenser
into a river or large body of water or it may be ejected into the air by
cooling towers. Regardless of the method used, the heat ejected through
the condenser heats the environment in some way. The size and cost of
the cooling system is therefore a function of the quantity of steam that
must he condensed. All of the heat from the condenser must be absorbed
by the environment.
By condensing the turbine exhaust steam, the outlet pressure can be
reduced, resulting in an increase in the efficiency of the steam cycle.
Howevar, to condense the steam, approximately 60 percent of the thermal
energy that is used to produce the high pressure steam must be removed
by the condenser. Condensation temperature is around 38 °C which is
too low in temperature to have economic value for the large quantities
of heat available.
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Nuclear Power Plants
Although there are several promising techniques that utilize nuclear
energy to produce electric power, only two basic types of systems are in
widespread use. These are the pressurized water reactor and the boiling
water reactor (46). Since these systems rely on the basic steam cycle
for the production of electricity, there are many similarities to fossil
steam plants. The major functional components of the nuclear power plant
are: reactor, water treatment system, turbine generator system, and cooling
system. However, the water treatment, turbine generator, and cooling system
perform the identical functions that were previously discussed relative
to the coal-fired power plant. The reactor replaces the boiler.
The reactor is a vessel containing the nuclear fuel where nuclear fission
takes place. Once the fuel elements are installed in the nuclear reactor,
a controlled nuclear chain reaction can be produced. There is no requirement
for a continuous fuel handling system because the reactor can operate for
approximately 1.5 years on one set of fuel elements. Large quantities
of heat are released as a result of the nuclear reaction. The heat is
transferred from the fuel elemen*.s directly to a working fluid (usually
water).
Since heat is generated inside the fuel elements of the nuclear reactor,
all of the heat is transferred to the working fluid. However, this causes
some operational problems. Water that is circulated, not only serves as
a working fluid for the steam cycle, but also serves as a coolant for the
fuel elements. If the fuel elements cannot be cooled sufficiently, the
fuel elements will overheat, rupture, and contaminate the system. To protect
against fuel cell rupture, nuclear reactors that use water as a working
fluid must not allow departure from nucleate boiling. In effect, this
limits the temperature and pressure of steam that can be produced by nuclear
reactors.
The two types of nuclear steam systems (pressurized and boiling) are
similar, but were developed by making different tradeoffs between safety
and economics (3, 46, 49). Schematic diagrams of both systems are shown
in Figure B-6. Steam is generated directly in the reactor of the boiling
water reactor. However, to prevent departure from nucleate boiling and
protect the fuel elements from rupture, the maximum pressure is limited
to approximately 7 MPa and saturated steam is produced at a maximum
temperature of approximately 290 °C. This low pressure and temperature
limits the efficiency of the steam cycle to a maximum of approximately
33 percent. The pressurized water reactor system uses water under high
pressure, but does not produce steam in the reactor. The water is circulated
through a special heat exchanger called a steam generator which transfers
heat to water at a lower pressure and produces steam that is used to drive
the turbines. The advantage of the pressurized system is that the steam
generator provides isolation between the reactor and the turbines. There-
fore, the probability of contaminating the turbines with radioactive material
is significantly reduced, while the efficiency is essentially unaltered.
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TURBINE
C3-
Figure B-6a
Boiling water reactor nuclear steam power system.
> r
CONDENSER}
u
<
I
r^
f V*
>
f
STEAM
GENERATOR
TORSI
v^
«!—.-_-
A "
Figure B-6b
Pressurized water reactor nuclear steam power system.
Figure B-6. Pressurized and boiling nuclear power cycles.
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MULTIPURPOSE POWER PLANTS
One practical means available for improving the use of energy in steam
plants is tne use of multipurpose atearn plants, where steam is exhausted
or extracted from the turbines at a proper pressure level for use in an
industrial process. With such arrangements, it is possible to obtain an
overall thermal utiization between 65 percent and 70 percent (3, 50, 51,
52). Combination power-and-process installations have been used successfully
in industry for many years. By trading electricity production for available
thermal energy, the net efficiency of the input fuel can be increased.
Steam can be used as a controlled temperature source of heat. At a
given pressure, the transformation of steam to water is associated with
the release of large amounts of heat. For pressures below 100 psi, the
latent heat of transformation is approximately 900 Btu per pound, but the
temperature of the steam/water remains constant during the transformation.
Therefore, the steam pressure can be used to control the temperature for
applications that require heat at a specific temperature.
Thermal Energy
The heat wasted in the condenser of an electric power plant can be
used by a multipurpose power plant. By extracting steam at high pressure,
the heat associated with the phase transformation can be used. Figure B-7
illustrates how it is possible to increase efficiency of the system by
trading electricity production for thermal energy availability. Diagram
A shows the T-S diagram for a typical steam condensing power cyle. The
enclosed area represents the electrical energy produced, while the shaded
area represents tho heat that is ejected through the condenser. In the
condensing cycle, the condensing temperature is approximately 38 °C which
corresponds to an absolute pressure of 7 kPa. However, the condensation
of steam produces approximately 2.2 kJ/kg of condensed steam that must be
ejected through the condenser. For example, by extracting the steam at
345 kPa, the condensation temperature is 138 °C, and the heat that is
available from the condensation process is 21.5 kJ/kg of steam condensed.
Because of its higher temperature, this heat can be used for many more
applications, such as drying. Diagram B in Figure B-7 shows the relation-
ship between the electricity production and the unavailable thermal energy.
As compared with Diagram A, the electricity production is reduced due to
the extraction of steam, but the area that represents Che unavailable energy
is reduced significantly. The overall efficiency of the energy system
represented by Diagram B has a potential efficiency of as high as 80 percent,
while the energy system represented by Diagram A has an efficiency that is
limited to a maximum value of less than 40 percent.
Reduction of Electric Generation Capacity—
As an example of the impact of steam extraction on electricity produc-
tion, Figure B-8 shows the electricity production in megawatts electric
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10
i.
1
I.
Electricity Produced
Heal Elected
I
I
10
8
200 400 600 800
CoM Reheat Steam Extracted (kg/ sec)
1000
Figure B-8. Effect of steam extraction on electric power production.
100
80
60
£ 40
20
I
I
I
200 400 600 800
Cold Reheat Steam Extracted (kg/sec)
1000
Figure B-9. Effect of steam extraction on system efficiency.
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and the heat ejected through the condenser as a function of extracted steam.
The maximum electricity production occurs when no steam is extracted for
use as thermal energy; however, the maximum production also corresponds
to maximum heat ejected through the condenser. Heat ejeoted through the
condenser is waste energy, because it is of such low temperature that it
has no economical uses. Aa steam is extracted from the system, and used
to supply thermal energy, the electricity production decreases, but simul-
taneously the ejected heat also decreases. If sufficient steam is extracted,
no heat is ejected through the condenser; however, electricity can still
be produced. Electrical production is primarily a result of the steam
flow through the high pressure turbine.
usable
heat
Diagram B
Figure B-7. Potential increase in available energy from steam extraction.
Improved Efficiency—
The increase in efficiency is directly related to the ability to use
the heat that is normally ejected through the condenser. By making the
assumption that all of the extracted steam is used at 100 percent efficiency,
it is posible to calculate an effective system efficiency. Figure B-9
shows that the system efficiency with no steam extraction is approximately
35 percent. As the extracted steam increases, so does the efficiency.
The potential efficiency of this system with maximum extraction is slightly
over 80 percent.
Proven Technology—•
Experience in industry where both processed steam and electricity
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been produced have shown that the concept of multipurpose power plants
is tecnnicaliy feasible, and in many cases economically desirable. One
significant advantage of the multipurpose power plant is that the size
of cooling towers and heat exchangers can be reduced or eliminated. Although
the principle of multipurpose power plants *s philosophically desirable,
there are many engineering, economic, institutional, and environmental
factors that can limit actual use.
Industrial In-Plant Degeneration
Many industries that require process heat have found it practical and
economical to use steam as a transfer medium. The production of processed
steam for industries is very similar to the production of steam for utility
applications. Some type of fuel is consumed in a boiler and steam is genera-
ted. The general term that is used for industrial power plants which are
capable of producing both electrical energy and processed steam is in-plant
cogeneration. In-plant cogeneration employs the same principles as a utility
power plant, except that the industry has a need for the thernal energy
contained in the steam that the utility industry normally ejects through
the condenser.
Even though in-plant cogeneration has the potential to save significant
amounts of energy, it is not always practical for an industry to operate
an in-plant cogeneration facility (50, 51). The following are some of the
barriers to in-plant cogeneration that may be incountered by an industry
(53).
a. The variations in the operating requirements for electricity
and process steam are incompatible.
b. The industries may fear possible action by regulatory agencies,
(such as the Public Seavice Commission that regulates the
utility industry).
c. The industry may be reluctant to produce its own electrical
energy regardless of the economic feasibility, because the
unit cost of installing and operating a small in-plant cogener-
ation facility is much higher than that of a large facility.
In spite of the barriers which may discourage in-plant cogeneration,
there are many examples of industrial facilities which have demonstrated
the economic and technical feasibility of the principles.
Coal-Fired Multi-Purpose Power Plant
The use of large coal-fired power plants to supply both thermal and
electrical energy is essentially an extension of in-plant generation technol-
ogy on a larger scale. However, applying this principle on such a large
scale presents a number of other problems.
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Boiler pressure of a utility size power plant is often in excess of
20 MHa. Theoretically, steam can be extracted at any pressure below
boiler pressure; however, as a practical matter the maximum extraction
steam pressure is limited. In general, 20 MPa steam cannot be shipped
economically because very expensive piping systems would have to be used
to prevent small losses ot thermal energy which would siginificantly reduce
the pressure. For most applications, steam would be extracted between
the turbine stages. Typical steam conditions that might exist at potential
extraction points in a coal fired power plant are:
Primary boiler steam - 24 MPa, 540 °C
Cold reheat steam - 5.0 MPa, 310 °C
Crossover steam - 1.1 MPa, 350 °c
The specific location of these points in the steam cycle is identified
in Figure 5 as points A, B, and C respectively. The steam extraction
temperature and pressure can be selected by utilizing specific turbines.
Nuclear Multi-Purpose Power Plant
Using process heat from a nuclear reactor requires the additional consi-
deration of radiation contamination (3). Steps must be taken to insure
that radioactive steam does not contaminate consumer products. In a boiling
water reactor system, protection can be provided by a level of isolation
in the form of steam regenerators. In the case of a pressurized water
reactor system, this level of isolation is provided by the steam generator.
The principal impacts of this isolation requirement are an increase in
capital cost and a reduction in the available temperature and efficiency.
The maximum pressure of the steam that can be extracted from the nuclear
power cycle is approximately 7 MPa for a pressurized water reactor
system and 4.8 MPa for a boiler water reactor system. In both cases,
the steam will be saturated.
POLLUTION CONTROL
There are two types of pollution that must be given specifn consider-
ation, air pollution and thermal pollution. Air pollution is only a consid-
eration for fossil fuel boilers, but thermal pollution is a problem with
both fossil and nuclear power plants.
The pollution control systems considered in this report are for control
of steam-power boilers emissions, not industrial process emissions. The
cogeneration system replaces the need for steam production in an industry
by supplying steam and electricity directly to the industry. This eliminates
the need for pollution control devices in the industry that would have
been used to control power boiler emissions. However, this has no impact
on the need for pollution control of emissions that occur as a result of
the specific manufacturing process.
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Air Pollution Control
There are three major categories of au.r pollutants that must be control-
led: particules, sulfur oxides (SO). &nd nigrogen oxides (NO ). Each
of these pollutants can cause ei./ironrcental damage if emitted in large
quantities. Coal fired power plants emit large quantities of all three
types of pollutants and are subject to pollution control regulations.
Although the required level of control is specified, the actual control
is a technical problem. There are several technologies that may be used
to control each type of emission.
Particulate Emissions—
When pulverized coal is burned, one of the by-products is fly-ash.
Some of tne small particles of fly-ash are suspended in the flue gas and
carried cut the stack to the environment. Since these particles are visible
in the atmosphere, particulate control is desirable not only from an envir-
onmental standpoint, but also from a social and institutional standpoint.
There are several technical approaches to the control of particulates
from coal combustion. These technologies fall into three categories:
wet scrubbing, mechanical, and electrostatic. Wet scrubbing collection
systems primarily nix the fuel gas with water. The water traps the particles
and forms a slurry from which the solids can be removed. Collection effi-
ciencies as high as 99.9 percent are possible with this type of system.
Mechanical collectors such as cyclones spin the gas stream, and the centrif-
ugal action forces the particles out of suspension. Other mechanical col-
lectors such as the bag house are just like large fabric filter systems.
The electrostatic precipitator uses sets of electrically charged electrodes
to first charge the particles and then attract them to an electrode. After
a predetermined amount has been collected on an electrode, the electrodes
are rapped with a mechanical hammer, and the particles fall to the floor
of the precipitator for collection. Mechanical and electrostatic collector
systems are only effective for particulate control.
SO Emissions-
Oxides of sulfur and particularly SO are considered to be a serious
health hazard as well as having a very unpleasant odor. Sulfur oxides
result when fuels that contain sulfur are burned. The most common sulfur
bearing fuels are eastern coal and residual oil.
The easiest way to reduce the output of SO is fuel substitution.
Fuel substitution with low sulfur fuels such as natural gas, distilled
oil, or low sulfur coal is not always an acceptable solution. These fuels
are limited in availability and the cost may be unacceptable.
Another option is stack gas clean up. There are several processes
that are capable of reducing SO emissions by at least 85 percent. All
of these technologies involves similar principles. The stack gases are
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mixed with a material that absorbs the sulfur compounds. Some of these
processes produce large quantities of quick-sand-like sludge that must
be thrown away. This throwaway sludge creates a major disposal problem.
Other processes are regenerative, and can produce elemental sulfur or sul-
furic acid and the absorbing medium can be reused.
A third option for the reduction of SO emissions is the physical clean-
ing of the coal. This technique requires the precoabustion treatment of
the fuel which may be costly and energy consuming.
NO Emissiona--
Oxides of nitrogen are formed primarily as a result of hign temperature
combustion of fuel in air. The resulting NO is important in the formation
of smog and has other detrimental effects on the environment.
Control options for NO are primarily in the categor .es of combustion
modification and flue gas treatment. Combustion modification includes
several methods that are designed to reduce NO production. Specific exam-
ples of combustion modification are low excess air on firing, staged combus-
tion, flue gas recirculation, and water injection. Some of the combustion
modification techniques are very cost effective because little or no capital
cost is associated with the modifications. Flue gas treatment is accom-
plished with techniques that are very similar to those discussed previously
relative to SO control.
Fludized Bed Combustion—
There is one technology currently under development that has the poten-
tial of simultaneous control of all three major pollutants. This technology
is fluidized bed combustion. In this process, fuel is injected into a
bed of limestone powder where combustion takes place. Since the combustion
takes place in intimate contact with the limestone, the particules and
SO are absorbed directly. Also, the combustion temperature is relatively
low, so lesa NO is formed relative to a conventional power plant. As
a result, fluidized bed combustion requires little or no stack gas clean
up.
Thermal Pollution Control
Approximately 50 percent of the thermal energy from the fuel is ejected
through the condenser of a steam electric pov, ?r plant. This heat must
be disposed of in some way, specifically transferred to the environment.
For many years it was standard practice to use natural bodies of water
or rivers to cool the condensers. However, as the demand for electric
power has increased, and the size of power plants has increased, the heating
of streams and other natural bodies of water has reached unacceptable levels.
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Alternative methods of disposing of the huge quantities jf nea:. have
been developed. These methods are cooling ponds and cooling uwers.
ponds are large man-made lakes that can transfer the heat to tne air by
convection or evaporation. Cooling towers perform the same function, but
they are tall structures that don't need large areas of land. Although
both methods transfer heat to the environment, they don't directly heat
natural water resources.
Technologies Selected
Various options for air and thermal pollution control were selected
for use in the analysis. These options included technologies that control
emissions before, during, and after combustion. All of these technologies
have been proven by actual use or are considered sufficiently promising
that enough research experience and literature are available to estimate
costs and operating characteristics.
Several technologies are considered.
Solvent refined coal, which controls SO emissions.
Electrostatic precipitator which controls particulate emissions.
Flue gas desulfurization which controls SO emissions.
Combustion modification in the boiler which controls NO emissions.
Dry flue gas treatment which controls NO emissions.
Dry flue gas treatment with simultaneous treatment control of
SO and NO emissions.
Wet flue gas treatment with simultaneous treatment control of
SO., and N0_ emissions.
-* x
Atmosphere fluidized bed combustion boiler which controls SO
emissions.
Pressurized fluidized bed combustion which takes place under pres-
sure and controls SO and NO emissions.
Forced draft cooling tower which controls thermal emissions.
Natural draft cooling tower which controls thermal emissions.
In general, these technologies appear to be the most economical methods
of satisfying present and future standards for industrial and utlity power
boilers. Electrostatic precipitation and flue gas desulfurization are
proven technologies and are in widespread use. Wet and dry flue gas treat-
ment are presently being examined as alternatives to satisfy the more string
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ent NO standards that may be imposed in the future.
Wet and dry methods of simultaneous flue gas treatment control of SO
and NO emissions are presently considered within economically feasible
ranges though high in cost. However, only dry blue gas treatment methods
can be considered economically feasible for selective control of NOX emis-
sions. Combustion modification is considered a cheaper method of controlling
NO than flue gas treatment, but combustion modification may not decrease
NO emissions enough to meet more stringent NOX standards if they are pro-
mulgated.
Although fludized bed combustion is not a fully developed technology,
it has a good probability of acceptance by industries and utilities. It
also seems to be the only other method aside from flue gas desulfurization
that can economically and in an energy efficient manner meet EPA SO stand-
ards. Atmospheric fluidized bed combustion with SO emission control boiler
technology will not be commercially available on a significant scale until
the early 1980's, while pressurized fluidized bed boiler technology will
not be commercially available until the mid 1980's. Pressurized fluidized
bed combustion boilers are more applicable to utility applications because
they can make use of the high pressure flue gases to turn a gas turbine
to generate electricity. As much as one-fifth of the electric power derived
from the boiler could coce from this use of the pressurized fluidized bed
combustion boiler's flue gases. This gives the boiler a higher thermal
efficiency than conventional boiler. However, much of this efficiency
advantage would be lost if the pressurized fluidized bed combustion boiler
is used in an industrial setting where the purpose of the boiler would
be to generate steam and not electricity.
Transportation of Thermal Energy
The transportation of steam from the power plant to the industries
impact a cogeneration system both economically and operationally. A utility
size power plant could supply thermal energy to several large industries.
In such a case, the facilities required by the power plant and the industries
would require a physical separation between them that could easily be several
miles. Regardless of the separation distance, steam must be available
at the industries. Therefore, the power plant and the industries must
be connected by a piping system through which some heat-transfer medium
will flow. There are three generic heat transfer media that are suitable
for transporting thermal energy at temperatures below 340 °C. These are
high-temperature water, organic fluids, and steam (32). The selection
of the heat transfer medium depends on the spcific application, but steam
and high-temperature water are most often used.
Organic fluids that are used for thermal energy transfer and storage
-------
are usually by-products of the petrollurn process. Several manufacturers
offer these organic fluids under various tradenames. The basic character-
istic of these fluids is a very high boiling point, which allows these
fluids to be heated to several hundred degrees without having to pressurize
the working fluid. By operating near atmospheric pressure, the piping
system is simpler than for steam and pressurized 'water systems even though
a system of heat exchangers must be used (32). However, precautions must
be taken to contain the organic fluids because they can be very detrimental
to the environment if a leak does occur. The major reason organic fluids
are not extensively used is the cost of the fluid and the cost of the precau-
tions that must be taken to protect the fluids from atmospheric contamin-
ation.
Steam has been used as a heat transfer medium for many years. Opera-
tionally, steam has several advantages, e.g., water is readily available
to make steam, st
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APPENDIX C*
DESCRIPTION OP MAIB3 COMPUTER PROGRAM
PURPOSE
A FORTRAN computer program has been written to help in the comparison
of costs and benefits associated with a cogeneration system and a status
quo system. Th-s program called Model for Assessment of Integrated Energy
System (MAIES) is used to compute costs and benefits as well as energy
balance, energy efficiency, electrical energy output and fuel requirements
for both the cogeneration system and the status quo aystera for the energy
and economic analysis. In addition, tiie program computes the volume of
air pollutants (particles, sulfur oxides, carbon monoxide, hydrocarbons
and nitrogen oxides) produced and emitted as well as thermal heat ejected
into the environment by conventional, cogeneration, and industrial power
plants.
APPROACH
The cost elements included in the program logic make it possible to
compare the costs of providing both thermal and electrical energy to a
group of co-located industries from a large central source, to providing
these energy requirements from a status quo system consisting of a large
utility which provides electricity only and industrial boilers which provide
steam and by-product electricity to individual industries.
The program is arranged to automatically evaluate an equivalent status
quo system following the evaluation of a cogeneration system. Any number
of industries may be co-located at varying distances from the centralized
power plant. The program contains all data related to industry thermal
and electrical energy requirements, pollution control equipment efficiencies
and costs, and all costs associated with particular utility power plant
types (nuclear or coal) and industrial boiler types (coal, fuel oil or
natural gas). To facilitate the evaluation of a variety of cost and techni-
cal parameters as well as industries types and locations, the program reads
all concepts from files, or inputs are typed in at a teletype in response
to programmed questions. In addition, practically any parameter may be
varied and the run repeated without re-entiring original data.
As an example, a cogeneration concept may be read in that consists
of a number of industries located at some distance from the centralized
cogeneration power plant. A file may be set up to run this concept and
repeat the evaluation of the concept for succeeding sets of relative industry
locations. Many other parameters may also be changed and runs repeated.
Examples of these parameters are discount rate, all capital and operation
*The MAIES Computer Program is written in English units and therefore
this appendix has been written in those units, too.
136
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and maintenance costs, fuel type, fuel costs, industry size, industry elec-
trical --*nd thermal demands, pollution control system type, pollution control
system costs, pollution control equipment pollutant collection efficiency,
power plant size (Mw tnermai>i and industrial boiler cype.
PROGRAM OUTPUTS
Program outputs include efficiency and fuel use analysis of the status
quo system, industrial utilizer, and the cogeneration system. Cost compar-
isons between the status quo system and the cogeneration system are made
on the level of capital and operation and maintenance costs as well as
fuel costs. The net present value of the overall system is an integral
part of program output. An environmental inpact analysis is also part
of available program output.
DEFINITION OP PARAMETERS
This section
so that the level
AF1EF
AFJND (8)
AFSs)
AFUEL (8)
ANCOST (50)
ANPUEL ("»)
BASE
BFUEL (8)
BLCIEFC
BLCIEFN
BLESQC
BLCSQN
CAPCIEF
CAPCIND (8)
CAPCSQ
CCCTIEF
CCCTINO (8)
CCCTSQ
CCEPIEF
CCE.-SQ
CCNOIEF
CCNOSQ
lists the parameters used in the MAIES computer program
of detail con3idered by the program is understood.
Annual fuel use in cogeneration system
Annual fuel use in industries
Annual fuel use in status quo systems
Additional induetrial fuel requirements
Annual cogeneration system fuel costs
Industrial by-product fuel
Area of power plant in square feet
Industrial by-product fuel
Baso linear coefficient for capital cost of coal total
cogeneration system
Base linear coefficient for capital cost of nuclear
total generation system
Base linear coefficient for capital cost of coal status
quo system
Base linear coefficient for capital cost of nuclear
status quo system
Capital cost of total cogeneration system utility
Capital cost of each industrial utility
Capital cost of status quo utility
Capital cost of cooling towers for total cogeneration
systems
Capital cost of cooling towers for industries
Capital cost of cooling towers for status quo systems
Capital cost of electrostatic precipitators for total
cogeneration system?
Capital cost of electrostatic precipitators for status
quo systems
Capital cost of NO. control equipment for total cogenera-
tion systems
Capital cost of NO control equipment for status quo
137
-------
CCSOIEF
CCSOSQ
CLCItFC
CLCIEF
CLCSQC
CLCSQN
COOLSAV
COSTINO(50, 8).
D
DIST (8)
EETIND (8)
EESUP
EFFIES
EFFLDSS
EFFO
EFFPOL(5,3)
EFFS
EFIND (8)
EINLOSS
ELECT (8)
FLECTP (8)
ENIEF(S)
EMJND (5,8)
EHINDX (4,5) •
EMSQ (5)
EMSSQ (5)
EHSIEF (5)
EMSIND (5,8) •
ENPEN
EI1TLPC (9)
ENTLPI (9)
ENTLPN (9)
ENTLS (9)
ETA (t)
ETAI (1)
ETAS (4)
ETIEF
ETSQ
EXCESS
EXCIEFC
systems
Capital cost of SO- scrubbers for total cogeneration
systems
Capital cost of SO. scrubbers for status quo systems
Linear coefficient for capital cost of coal total cogenera-
tion system
Linear coefficient for capital cost of nuclear total
cogeneration system
Linear coefficient for capital cost of coal status quo
ays-terns
Linear coefficient for capital cost of nuclear status
quo systems
Cost savings of total cogeneration system Cooling towers
aver status quo sy.items towers
Annual industry costs
Discount rate
Distance from power plant to each industry
Electrical energy requirements for industries
Electrical energy provided by supplemental utility
Efficiency of cogeneration system
Fuel use efficiency of power plant
Efficiency of status quo systems
Efficiency of pollution control devices
Efficiency of total cogeneration system power plant
Efficiency of industrial power plants
Fuel use efficiency of industrial boilers
Industrial electrical requirements
Electrical energy purchased by industrial power plants
Emissions from cogeneration system
Emissions Irom industries
Emissions index file
Emissions from status quo systems
Solid waste produced from status quo systems
Solid waste produced from cogeneration system
Solid waste produced from industries
Total energy penalty
Enthalpy for coal plants
Enthalpy for industrial boilers
Enthalpy for nuclear plants
Enthalpy for small industrial boilers
Turbine efficiencies
Industrial boiler efficiencies
Small industrial boiler efficiencies
Electrical energy required for cogeneration system
Electrical energy required for status quo systems
Total cogeneration system electrical energy produced
but not used
Exponential coefficient capital cost of coal
total cogeneration system
138
-------
EXCIEFN
EXCSQC
EXCSQN
FACTOR (8)
FM (8, 8)
FHI (8,8)
FOMPIP
FRATB
FRATIEF
FRATIND (8)
FRATBSQ
FUELING (SO)
FUELCSQ (SO)
FWORD 1
FWORD 2
GRF (u)
GTLIEF
GTFLSQ
GTFUEL
GTOMIEF
GTOMSQ
H (8,8)
HJIEF
HJIND (8)
HJSQ
HTOT1 (8)
HTOTIEF
HTOTSQ
ICNTCC
IEFUPT
IEFF
INOCAP (P)
INDCNTL
INDELEC (8)
INOFUEL (8)
INBLOP
INDOPT
1PLANT (8,2)
ISMALL
ITITL (3)
IWORD (5)
ISQF
IOP1
IOP2
IOPU
IOP5
IOP6
Exponential coefficient capital cost of nuclear
total cogeneration system
Exponential coefficient capital cost of coal status
quo systems
Exponential coefficient capital cost of nuclear status
quo systems
Factor for electrical requirements
Steam mass flow rate
Effective steam mass flow rate
O&M factor for piping
Adjusted fuel rate for total cogeneration system
Fuel rate for total cogeneration system
Fuel rate for industries
Fuel rate for status quo systems
Annual industry fuel costs
Annual status quo systems fuel costs
Alphanumeric for total cogeneration system fuel type
Alphanumeric for industrial fuel type
Fuel price growth rate
Total cogeneration system fuel costs over life of facility
Total status quo systems fuel costs over life of facility
Total fuel costs
Total O&M costs for total cogeneration system
Total O&H costs for status quo system
Industry enthalpiers
Heat ejected from cogeneration system
Heat ejected from industrial boilers
Heat ejected from status quo systems
Heat produced by industries
Heat produced by cogeneration system
Heat produced by status quo systems
Pollution control system used
Mass calculation option for power plant
Total cogeneration system fuel type
Industry power capacity
Industry pollution control system used
Industry electrical requirements
Industry fuel requirements
Industrial boiler option
Industrial power plant option
Alphanumeric of industrial plant type
Small Industrial boiler option
Title for output
Input read and write work options
Status quo systems fuel type
Status quo systems energy print option
Total cogeneration system energy print option
Scenario print option
Economic analysis print option
Fuel use and cost analysis print option
139
-------
10 P7
LIFE
N
NAME (4)
NCOH
NIEFF
NGRADES (8)
NO
NP
NPLANTS
OMCIGP
OMCINO (8)
OMCOE (5)
OHCSQ
OHCTIEF
OHCTINO (8)
OHCTSQ
OHBPIBP
QHBPSQ
OMEXP (5)
OMNOIEF
ment
OMNQSQ
OHPIP
OMSOIEP
OMSOSQ
PEXTCOB (2,2)
PEXTBXP (2,2)
PEN (8)
PF
PFIND (8)
PPSQ
P1PCOB (2,2)
P1PCON
PIPBXP (2,2>
PIPBXT (2)
PIPXOL
PIPCOST (8,8)
PE1CBFC (4)
PRF (4,50)
RATIO
R1
R2
R3
R4
R5
R6
Environmental impact print option
Facility life
Number of years of operation
Status quo systems fuel titler
Number of pollution control systems
Alphanumeric of total cogeneration system fuel type
Industrial steam grade
Years beyond 1975 of initial operation
Plant number
Number of industries
O&N costs of cogeneration system
O&M costs of industries
0AM coat coefficients
O&M costs of status quo systems
O&M costs of total cogeneration system cooling towers
O&M costs of industrial cooling towers
O&M costs of status quo system cooling towers
O&M costs of total cogeneration system electrostatic
precipitators
O&M costs of status quo systems electrostatic precipitates
O&M costs exponents
O&M Costs of total cogeneration system NO- control equip-
O&M costs of status quo systems NO- control equipment
O&M costs of piping
O&M costs of total cogeneration system SO- scrubbers
O&M costs of status quo systems SO- scrubbers
Steam extraction cost coefficients
Steam extraction cost exponents
Industrial energy penalty
Plant Factor for total cogeneration system
Plant factor for industries
Plant factor for status quo systems
Piping cost coefficient
Piping distance effectiveness constant
Piping cost coefficients
Steam extraction costs
Additional extraction costs for nuclear plants
Piping costs for each industry
Initial price of fuel
Annual price of fuel
Ratio of supplementary electrical energy to status quo
systems electrical energy
Inflation rate for capital costs of piping
Inflation rate for capital cost of total cogeneration
system
Inflation rats for capital cost of cooling towers
Inflation rate for capital cost of turbines
Inflation rate for capital cost of industrial boilers
Inflation rate for capital cost of status quo system
140
-------
R7
R8
R9
R10
SCCCT
SCCEP
SCCIND
SCC NO X
SCCSOX
SFUELPR
SOMCT
SOMIND
SOMEP
SOMNOX
SOHSOX
SQXCESS
SWORD (8,8)
SM1
SM2
SHU
TCCIEP
TCCIND
TCCSQ
TCOST(SO)
TEETINO
TEFFSQ
TFUEL
THERMS (8,8)
TNRIND (8)
TOMCIEF
TOTALM
TOMCIND
TOMC5Q
TPIPCST
TTHIND
TURBCOE (5)
TURBEXP (5)
TURBTAV
WORDH12)
WORD2(12)
XPV (50)
Inflation rate for O&M cost of piping
Inflation rate for O&M cost of total cogeneration system
Inflation rate for O&M cost of status quo systems
Inflation rate for O&M cost of industrial boilers
Sensitivity for capital cost' of cooling towers
Sensitivity for capital cost of electrostatic precipita-
tora
Sensibility for capital cos*1 of industrial boilers
Sensitivity for capital cost of NO. control equipment
Sensitivity for capital cost of SO. scrubbers
Sensitivity for fuel price
Sensitivity for O&M cost of cooling towers
Sensitivity for O&M cost of industrial boilers
Sensitivity for O&M cost of electrostatic preoiptators
Sensitivity for O&M cost of NO,, control equipment
Sensitivity for O&M cost of SO* scrubber
Excess electrical power in status quo systems
Alphanumeric steam pressure grade for industries
High mass flow rate for steam
Intermediate mass flow rate for steam
Low mass flow rate for steam
Total capital costs of total cogeneration system
Total capital costs of industries
Total capital costs of status quo system
Annual total status quo systems fuel costs
Total industry electrical energy
Overall status quo systems efficiency
Total industrial fuel requirement
Thermal energy for industries
Turbine energy for industries
Total O&M costs for total cogeneration system
Total mass of system
Total O&M costs for industrial utilities
Total O&M costs as status quo systems
Total piping costs
Total thermal energy for industries
Turbine energy coefficients
Turbine energy exponents
Savings in turbine costs of cogencration system over
status
quo systems
First command for input
Second command for input
Net present value
MAIES COMPUTER PROGRAM SUBROUTINE DESCRIPTION
Figure C-1 presents a flow chart of the sequence of subroutine calls
for the Model for Assessment of Integrated Energy Systems (MAIES). The
following paragraphs describe the computations performed in each sub-rou-
tine.
Ill
-------
Call Inpt
call nwun
>=-Q
WOUHD-STOP'
<
IW»D(1)-RUNT
Call IEF
]=[
Call niRPLHT
Call
"_M
Call PURPLNT
Ctll PIPING
Call DOOM
Call CAFCOST
ti-^J
Calculate
Pual Coat*
Call NPV
Calculate Industrial
PtMl U>*
Call PUNT
Call CONTROL
Figure C-l. Flowchart of the MAIES computer program.
1*2
-------
Subroutine INPT
Subroutine INPT contains data statements which initialize the coeffic-
ients used in many subroutines of MAIES. INPT also contains initial or
base values for all variable parameters in MAIES. INPT initializes all
print options to zero, which suppresses all optional printouts.
Subroutine NTRPRET
Subroutine KTRPRBT reads an alphanumeric command, then calls the apro-
priate subroutine—PTABLE, RTABLE, or RESET—based on the command. NTEPRET
also allows the user to enter an alphanumeric heading to label the program's
output.
Subroutine PTABLE. RESET
Subroutines PTABLE and RESET set and reset flags which determine the
outputs listed by subroutine PRINT. For example, the user may enter:
"PRINT SCENARIO".
NTRPRET reads this command, then calls PTABLE which sets a flag. PRINT
set the "SCENARIO" flag and lists the industries and their associated param-
eters.
Subroutine RTABLE
Subroutine RTABLE allows the user to change many of the values initial-
ized by subroutine INPT. Based on the command received from NTRPRET, RTABLE
solicits the required input from the user. In this way, the following
parameters can be updated or varied: open or closed cycle cogeneration
system utility, industrial boiler size and type, plant factors for the
cogeneration system, status quo, and industrial utilities, the capital
costs and O&H costs of status QUO, cogeneration system, and industrial
utilities and pollution controls, the type of pollution control system
used, fuel prices and escalation or deflation rates, discount rate, base
size of status quo utility, distances for steam shipping, emission indices,
type of fuel used, initial year of operation, and the life of the facility.
RTABLE also reads in factors for sensitivity analysis of costs.
Subroutine CONCEPT
RTABLE calls subroutine CONCEPT when a "READ CONCEPT" command is receiv-
ed. CONCEPT reads the industry names, their distances from the cogeneration
system utility (over which the steam is piped), whether the iMustrial
utilities are open or closed cycle, the type of fuel used, the amount of
electrical energy provided by the industrial utilities, and a sizing factor
used to increase/decrease the industries' electrical demand, mass flow
rates, capital costs of the utililties, amount of by-product fuel, and
the industries capacities (tons/day, etc.) Parameters scaled by the sizing
factor are unique to a given industry.
-------
Subroutine PWRPLNT
Subroutine PWRPLNT calculates the amount of fuel required by the degenera-
tion system utility, status quo utility, and the industrial utilities.
PWRPLNT also calculates the total electrical energy provided by the status
quo and cogeneration system utilities. These calculations are based on
the mass flow rates and grades of steam required (high, intermediate, or
low pressure), the steam piping distances, and the type of fuel used.
Subroutine SQ
Subroutine SQ calls PWRPLNT to calculate the fuel requirements and
the electrical energy provided by the status quo utility. SQ also calls
PWRLNT for each of the industrial utilities. Based on the fuel requirements
calculated by PWRPLNT, SQ computes the total emissions of particles, sulfur
oxides, nitrous oxides, carbon monoxide, and nydrocarbons produced annually
by the utilities. SQ also suos the total thermal and electrical demand
of the industries and calculates an overall efficiency for the industrial
utilities.
Subroutine IEF
Subroutine Iff calls PWRPLNT to calculate the fuel requirements and
the electrical energy provided by the cogenerating utility. IEF then calc-
ulates overall efficiencies for the cogeneration system and status quo
utilities. The efficiency for the cogeneration system utility is based
on its own fuel requirements and energy (thermal and electric) output.
The efficiency for the status quo system is based on fuel requirements
of the status quo utility and that of the industrial utilities as well
as energy output. The fuel requirements of the cogeneration system are
also used to calculate annual emissions.
Subroutine PIPING
Subroutine PIPING calculates the capital cost of piping steam to each
of the industries. Parameters in this calculation include distance from
the cogenerating utility, mass flow rates and grades of steam required,
and whether the industries operate open or closed cycle.
Subroutine CONTROL
Subrouting CONTROL calculates capital costs and operation and maintenance
costs for pollution control equipment used by the cogeneration system,
status quo utility, and industrial utilities. For the status quo utility,
costs are based on the total electrical energy provided. Costs for the
industrial utilities are based on a percentage of the total electrical
energy supplied by the status quo utility. Costs for the cogeneration
system utility ars based on electrical energy sold to the power grid as
well as the total electrical energy supplied t-y the status quo utility.
All operation and maintenance costs are also a function of plant factor
(percentage of time plant remains in operation each year).
111
-------
Subroutine CAPCOST
Subroutine CAPCOST calculates capital costs of the cogenerating and
status quo utilities. Capital cost of the status quo utility is a function
of total electrical energy supplied; capital cost of the cogenerating utility
is based on a percentage of the electrical energy provided by the status
quo and the electrical energy sold to the power grid by the cogeneration
system. CAPCOST also sums the capital costs of the industrial utilities.
Subroutine 0AM
Subroutine O&M calculates operation and maintenance costs of the cogenera-
ting and status quo utilities. Costs for the status quo utility are based
on total heat energy; costs for the cogenerating utility are functions
of total heat energy and electrical energy sold to the power grid. O&M
also calculates an operation and maintenance cost for the industrial util-
ities which is a percentage of their total capital cost.
Subroutine NPV
Subroutine NPV calculates net resent value of the ccgeneration system
for each year of operation based on capital costs, annual fuel costs, oper-
ation and maintenance costs, and discount rate.
Subroutine PRINT
Subroutine PRINT is the last subroutine called. PRINT inspects output
flags set by INPT and PTABLE and prints the outputs desired by the user.
Outputs include:
Heading
Fuel used by cogeneration and status quo utilities
Cogeneration and status quo utility sizes
Industry name and capacity
Open or closed system
Electrical energy & fuel requirements for cogeneration systems,
status quo system, and industries
Heat ejected through condensers
Efficiency of status quo, cogeneration, and industries
Summary of capital and operation and maintenance costs
Annual fuel costs
Fuel use analysis
System efficiency analysis
Summary of pollutants produced and emitted
Before the PRINT suoroutine is called, MAIES calculates annual fuel
costs based on fuel requirements and plant factors for the status quo and
industrial utilities and the cogeneration system utility.
Input Options
The read options provide a method of changing various values of the
115
-------
input variables.
Command
READ IEFOPT
READ SMALL
READ SCCCT
RSAD SUMCT
READ SCCIN
READ SUMIN
uSAD SCCEP
READ SCCSO
READ SCCNO
HEAD SOMEP
RSAD SOMSO
READ SOHNO
READ PP
DEAD PFSQ
READ PPIND
READ CNTRL
READ INDCN
READ FUIEF
READ FUIND
READ FUSQ
READ NYES
READ CNCPT
READ PRICE
READ NEWSQ
RED DIST
READ SDR
READ EMISS
READ DEFLA
READ ESCAL
READ CAPCO
READ SFLPR
READ COOLS
READ COOL 1
READ COOLN
READ LCIN
READ LCLC
READ LCSM
READ LCSC
READ EXCIN
READ EXCIC
READ EXCSN
READ EXCSC
READ NYIO
Output Options
Command
Input Request
Yes
None
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
•••Enter Type of Fuel*"
Enter Fuel Used by each Industry
•••Enter Type of Fuel
Yes
Yes
Write Fuel I.D., Base Fuel Price
and Annual of Increase
Yes
Yes
Yes
Yes
Yes
Yes U, Rate)
Yes
Yes
None
None
None
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Output
Net present value
146
-------
Efficiency analysis
Status quo parameters
Industrial parameters
Total cogeneration system parameters
Industrial power plant parameters
Capital costs
Operation and maintenance costs
Annual fuel costs
Fuel use analysis
Environmental impact analysis
Suppeerset output
PRINT SQ
—
PRINT IEF
PRINT SCEN
PRINT COST
—
PRINT FUEL
—-
PRINT POLL
RESET
•RESET may be used for any PRINT option
User's Guide for MAIES
This section presents the approacn to executing the MAIES computer
program on the Georgia Tech CDC 7400 general purpose computer. The execut-
able version of the program is XMAIBS. The program may be executed demand
or batch and provides a number of input and output options that may be
chosen by the user during program execution. These options are described
in detail in the following sections.
To execute, enter:
"XMAIES".
The program then responds with a question mark. Any of the input and
output options listed may be entered using "READ" or "PRINT". After appro-
priate options have been set, and the "concept" has been read-in, the user
may enter "RUN" to begin program computations or "END" to terminate program
execution. All output options may be reset using the "RESET" command.
The following is the range of values that may be uaed for the input and
output variables.
Input Variables
All commands are followed by a carriage return and each command initiates
an input request.
"READ" Options:
IEFOPT -
INBLOP
SMALL
SCCCT
SOMCT
Cogeneration system open or closed system
"0" is entered for closed v/cle (default)
"1" is entered for open cycle
Industrial boiler type
"1" Low Btu Boiler (default)
"2" AFBC Boiler
Size of Industrial Utility
Sets size to small
Sensitivity factor for capital cost of cooling towers,
Default = 1.0
Sensitivity factor for O&M cost of cooling towers,
HIT
-------
SCCIND
SOMIND
SCCEP
SOMEP
SCCSOX
SOMSOX
SCCNOX
SOHNOX
PF
PFSQ
PFIND
CNTCC
Default = 1.0
Sensitivity factor for capital cost of industries
Default = 1.0
Sensitivity factor for O&M cost of industries,
Default = 1.0
Sensitivity factor for capital cost of electrostatic
precipitator
Default =1.0
Sensitivity factor for O&M costs of electrostatic
precipitator
Default = 1.0
Sensitivity factor for capital cost of SO, scrubbers
Default =1.0
Sensitivity factor for O&M cost of SO., scrubbers
Default =1.0
Sensitivity factor for capital cost
equipment
Default = 1.0
NO2 control
n-jn
INDCNTL
FUIEF
FUSQ
FUIND
Sensitivity factor for O&M cost of NO- control equipment
Default =1.0
Plant factor for cogeneration system
Default = .9
Plant factor for status quo system
Default = .9
Plant factor for industries
Default = .9 for one industry
Sets system pollution control efficiencies, depends
on system used
»0" ESP
ESP, FGD, combustion modification
ESP, FGD, dry flue gas treatment
ESP simultaneous dry flue gas treatment
ESP, simultaneous wet flue gas treatment
ESP, AFBC
ESP, PFBC
Sets industrial pollution control system
"0" ESP
"1" ESP, FGD, combustion modification
"2" ESP, FBL
Initiates input request for fuel type used by total
cogeneration system:
"NU" is entered for nuclear
"CO" is entered for coal
Initiates input request for fuel type used by status
quo systems:
"NU is entered for nuclear
"CO" is entered for coal
Initiates input request for fuel type used by industries
"1" = coal
"5"
"6"
148
-------
NYRS
CNCPT
TITLE
101, 1D2
PRICE
NEWSQ
DIST
SPR
EMISS
DEFLA
5SCAL
CAPCO
"2" = nuclear
"3" = natural gas
"4" = fuel oils
Initiates a request for life at facility
Input is an interger greater than or equal to 50
Default = 30
Initiates c 1 to subroutine CONCEPT inputs are of the form
TITLE
1D1, 1D2
Alphanumeric lable displayed on output (3Alo FORMAT)
Alphanumeric lable displayed on output (2A10 FORMAT) the
user must enter at least the first 10 characters of
the following:
Chlorine
Sulphur (or Sulfur)
Phosphoric
Steel
Pulp and Paper
Ammonia
Textures
if input i3 one of these type of plants.
The program solicits further information DIST - distance
(in miles) from industry to cogeneration system
INDOPT - open or closed cycle
"0" closed cycle
"1" open cycle
INDELC - industrial electrical requirements
INDFUEL - industrial fuel requirements
Other possible responses are
READ FACTOR
END
READ FACTOR - initiates a request for a scaling factor
that adjusts the "size" of the industry; input is a
real number. The electrical demand, mass flow rates
and by-product fuel are all multiplied by this factor
END - suoroutJne returns to RTABLE
Initiates a request for fuel ID, base fuel price, and
annual rate of increase of fuel prices.
Changes base status quo power plant size
Default = 3,000 sq ft
Changes distance from industrial plants to cogeneracion
system
Default =0.5
Changes discount rate
Default =0.07
Changes emission control induicer
Solicits new deflation rates
Solicits number of rate, and new escalation rate.
Reads in sensitivity analysis factor for capital costs
Default = 1.0
119
-------
SFLPR
COOLS
COOLI
COOLN
LCZN
LCLC
LCSN
LCSC
EXCLS
EXCIC
EXCIN
EXCSC
NY10
Output Options
Reads in sensitivity analysis factor for fuel costs
Default = 1.0
Changes status quo system cooling to forced draft
Default = Natural draft
Changes total cogeneration system cooling to forced
draft
Default = Natural draft
Changes industrial cooling to forced draft
Default = Natural draft
Changes linear coefficient for capital costs of nuclear
total cogeneration system
Default = 4.,34861
Changes linear coefficient for capital costs of coal
total cogener..tion system
Default = 1.9154
Changes linear coefficient for capital costs of nuclear
status quo system
Default = 4.434861
Changes linear coefficient for capital cost of coal
status quo system
Default = 1.154
Changes exponent for capital cost of nuclear status
quo system
Default = 0.6573
Changes exponent for capital costs of coal total
cogeneration system
Default = 0.7632
Changes exponent for capital cost of nuclear status
quo system
Default = 0.6573
Changes exponent for capital cost of coal status
quo system
Default = 0.7632
Changes year of initial operation
(difference from 1975)
Default = 2 1977
All commands are followed by a carriage return. Net present value,
system efficiency, and open or closed cycle are always part of initial
printout.
"PRINT" Option:
SQ - Lists for status quo utility and each industry, total electrical
energy, fuel requirements, heat ejected through the condenser,
and power plant efficlenty
IEF - Lists for cogeneration system, open or closed cycle, total
electrical energy, fuel requirements, heat ejected through
the condenser, power plant efficiency, and overall cogeneration
system efficiency.
150
-------
SCEN - Lists for industries; name, distance, electrical demand,
electricity applied, mass flow rate, enthalpy, thermal energy,
and open or closed cycle.
COST - Lists the capital and operation and maintenance costs of
the cogeneration system and status quo system for the follow-
ing: utility power plants, additional feedwater systems,
extraction and piping, industrial utilities, and pollution
control devices. Also lists fuel costs for status quo systems
and cogeneration system.
FUEL - Lists annual fuel costs for the status quo systems and cogenera-
tion system for N years as well as fuel use analyses of status
quo systems and cogeneration system
ROLL - Lists pollution control system and summarizes pollutants
produced and emitted as well as solid waste produced.
"RESET" Option:
"RESET" may be used to suppress output initially set by the
"PRINT" command.
Enter:
RESET OPNAME
where OPNAME is any of the above
PRINT options.
Example Program Output
The following pages present an example output from the MAIES computer
program. The particular concept consists of a large chlorine plant co-
located in a complex and supplied thermal and electrical energy by a coal-
fired cogenerating power plant. Electrostatic precipitators and natural
draft cooling towers are used.
151
-------
CONCEPT t MSI CDS: MOO TON/MI CL2
COAL-FIRED UTILITY SQ - 1100. WE
IEF - 904. NC
arr- IM. WE
CHORINE MM TONS/MI
INITIAL TEM V OPERATION- Wl
aosED craE
NIT RESENT VALUE (Ml • 2M.SSI
OVERALL ENER6T EFFICIENCT
STATUS OUO INTEGRATED ENERG1
UTILin INDUSTRIES OUEMU FACILITY STSTU
.11VO .8000 .«45 .5*70 .5298
EKRST EFFICIENCY FACTOR FOR POUUTION COnRUS! .9881
CMXPT ! IASE CASE! 6000 VWWt O2
StOMRIO DEFIMTIOM
OIST.(HILES) am. terns ELECT. SUPFLT
-------
st SMIUS ouo Focuiir u
suns QUO uriiiiT
ELECTRIC* vast <«>« ion.no
RKL (SUUIKICHTS (MTU/WM 117W.
HUT f JICTO TMNU6H OHKHSEJt HUTU/MI) • 40J7.
POO PUW EFFICIENCT* .3190
INUSTtlM. POKE PUNTS
—OiVIK
ELEXTRICM. DO6I (MC» 0.000
nil KUIttKNTS (OTUM)> 4712.4
«»I £JKID TWOUEH COBtUSa (MIUMt) • 0.
POO PUNT ETFICIENCT' .8000
a INTEGRATED ENER6I FKILITY tt
ttOSEOCTCU
EUCTIICM. END!6T (WEI* N5.SU
Fib KOUIKKIITS (»TU/HR)« 13844.
KMT EJECTED TNROUGN COnCNSER (NITUMII • W>7.
POO PUWT EFFICIERn> -S470
ErriCIEKT OF IES • .S298
153
-------
coon : MS OKI: MM TOB/OAY 02
oanuc AMLTSIS
tram root run ICON.)
AMITIOMI FEEHMTEI STSTENS
OIMCIIOM AN* ntm
INWSTRIAL UTIUIIES (CML)
TOTALS
ttriTAL COST (Ml
STATUS on its
414.117 492.021
0.000 0.000
O.ON 7.714
21.011 0.000
457.1*5 499.007
OPERATION «•
MINIEMNK COST (Ml
STATUS QUO US
11.892 10.101
0.000 0.000
O.OM .Ji»
«.412 0.000
17.505 10.490
FUU COSTS (Ml
vrum POO run
lausniAL uraims
CMLORIIK
TOTAL (FUST TEAM
TOTAL OVD LIFE
STATUS U>
92.710
17.110
129.0M
17B.111
UrTESRATD
amsr SYSTEM
109.094
0.000
109.094
1494.294
fOiUTIU COHTnL
OtlMt. COSTS (Ml
STATUS OUO
UTIUTT lUtiSTRIES TOTAL SB
NRIIOES 27.000
S9LF OMK 0.000
MTR OXIK 0.000
COOLttt M.f4» 1MB
0.000
0.000
TOTALS
il.Ml 1MB
27.000
0.000
0.000
U.IZi
OKUTIOi I MUTlMNCt COSTS (M)
STATUS QUO
HTIUTT MUSTMES TOTAL SO
minus i.m 0.000
Stlf OXIK 0.000 0.000
an oxuc 0.000 0.000
COOLUC i.w .fir
TOTALS
1.442
.fit
i.m
0.000
0.000
2.7M
>»•»••••
4.401
EKR61 SYSTEM ' NET WLUE
11.745
0.000
0.000
2MOT
<0.fS4
INTEBnTO
BURST STSTCN
1.9*4
0.000
0.000
1.499
1.4M
-4.745
0.000
0.000
24.917
20.172
NH VALUE
-.2ft
0.000
0.000
1.247
.t4i
-------
(MOT : MSI US: 6000 TOOTH (12
tut
na COSTS (MIUIOBI n
M. UTILITIES TOT* SUIUS QUO IET
f
10
II
12
13
14
»
U
17
18
19
20
a
a
21
24
29
26
2?
28
V
M
92.710
91.637
94.594
95.340
94.495
f7.4M
98.4B
99.419
100.4IJ
101 .416
102.412
101.434
144.4*1
109.316
106.391
107.657
146.713
109.821
110.919
112.021
lll.l«
114.280
113.421
116.577
117.741
118.920
120.109
121.310
122.523
121.749
17.130
17.501
17.876
38.253
9.638
39.024
39.414
19.808
40.206
40.60?
41.013
41.425
41.839
42.257
42.660
41.107
41.SK
41.973
44.413
44.837
45.306
49.759
46.216
46.678
47.145
47.617
48.091
48.574
49.059
49.550
I29.BM
111. 159
112.470
ID.tJ
IB. Ill
116.484
1P.84?
119.228
140.620
142.026
141.446
144.881
146.330
147.791
149.271
150.764
157.271
151.794
155.112
156.883
IS8.454
160.039
161.639
161.2SS
164.888
166.517
168.202
169.884
171.583
173.299
109.094
110.183
111.287
112.400
111.524
114.659
115.806
116.964
118.134
119.315
120.308
121.713
122.930
124.160
125.401
126.655
127.922
129.201
110.491
111.798
111.116
134.447
133.791
117.149
138.321
139.906
141.305
142.718
144.145
(43.387
na IH MN.TSIS
no. USE
can
•mm
CUMK
T8TH RKL COJBUK8
•MTMSUMI
ST«TUS OUO
91.787
I/.1S3
129.939
11769.0
4H2.4
16481.4
6827.2
IHE6MTD
EKIBT STSTHI
(HtrnyMi usru/ni
11843.9 109.161
IH45.9
3007.2
189.1*1
155
-------
OMZPT i USE CAS! 4000 IW/KW CU
EWHMCNTAL WICl AMLTSIS
STATUS QUD uriim t OF : STSTEH o, MT. HUFT COOLINE
NRTICUS - EUCTMBIATIC HXCIPITATB
IMUSTUAL uiiinia: sm» t, mi. mm OOLIIC
ir PouuTABTS POMCD AMMLT MILLIOH LK>
on oussiv smwn
TOTAL WOO!
MCIUTI MRTIOES SB GO K MB
CNLBIK
suns QUO oiiLin
nm
in
2B.V
SM.84
111.42
UO.X
IMM
3U.82
471 .a
IN.S
1.20
7.IS
11.17
f.»
l.«0
1.9*
J.5»
4.4»
24.13
M.11
84.44
70.W
urruoa 110.07 73.41 1.7? .1* ».»
TOTAL DUTTD
FACIL1TT PARTICUS SOU CO K MB
OLORiC
STATUS auo uriun
TBTAt
ur
1.02
7.33
10.37
t.0t
13.49
S6.II
BO.N
1M.23
1.20
7.98
11.17
9.19
l.M
1.9*
3.59
4.49
24.13
M.11
84.41
70.93
IIFFIKMX 1.49 -45.93 1.7* .8* 11.31
S9UI MtSTE fHMOD
FACinn rMiiacs sn a « MB
M.ORIK
STATUS an arnm
TBT«t
nr
22V.33
371.2*
892.84
474.44
121.9
8.M
121 .a
0.80
8.00
8.00
0.00
0.00
0.00
0.00
0.00
O.N
0.00
0.00
0.00
0.00
SOTDUX U8.a m.a 0.00 0.00 0.00
156
-------
APPENDIX D
SOCIAL IMPACT ANALYSIS MULTIPLIER MODELS
Figures D-1, D-2, D-3, and D-1 are the multiplier models used to deter-
mine population distribution effects from cogeneration system construction.
Each figure is accompanied by a table of explanatory comments supporting
the particular values of the parameters shown in the figures. Figures
D-1 and D-2 describe the effects of a large cogeneration system in a large
host community. The basic differences reflected in Figure D-1 for the
construction phase and Figure D-2 for the long term effects are the family
status composition of the construction work force and its lesser consumption
of general goods and services available in the community. The lower than
average proportion of family status workers during cogeneration system
construction (60$ vs 85%) is based on experience with other large construc-
tion projects. This and the more modest support requirement of construction
workers, are undoubtedly related and both are probably influenced by the
short term nature of construction projects.
Figures D-3 and D-1 describe the population effects of a large cogener-
ation system in a small host community. The differences are similar to
those noted between Figures D-1 and D-2. The main differences between
the pairs of Figures D-1 and D-2 Tor the large host community and D-3 and
D-1 for the small, lie in the lesser diversity of goods and services gener-
ally available in a small community and its typically larger amount of
available land.
The long run community statistics shown in Figures D-2 and D-1 were
used to develop the specific data describing the hypothetical large and
small host communities. A large host community was assumed to be a contig-
uous area containing 50,000 employed persons (datum for block 2D-1 in Figure
D-2). A small host community was assumed to be a small contiguous area
separated by sparsely populated areas from neighboring population centers.
This small host community was assumed to be large enough to provide its
own essential public services and contain 10,000 employed persons (datum
for block 1A in Figure D-1).
Tables D-1 through D-8 provide a graphical representation of the results
of the application of the multiplier models. Table D-1 addresses the situ-
ation of a large cogeneration system in a large host community. In general,
the large host community has little difficulty accomodating the demands
of the increased industrial activity. Table D-2 addresses the construction
and operation of a large cogeneration system in a small host community.
The small host community would have to provide a significant increase in
facilities and services. This increase would be approximately 100 percent
over a period of four to five years. Table D-3 is a comparison of the
changes that would occur in a large host community and a small host commun-
ity. While the changes are minimal for the large community, they are large
for the small community. Table D-1 compares the changes that occur in
157
-------
host communities just prior to operation as the cogeneration related popula-
tion is changing from transient to permanent. The impacts of full scale
operation are compared in Table 0-5.
Tables 0-6 through D-8 compare the effects of a large nuclear powered
cogeneration facility on the host communities for the various phases of
construction and operation. The basic impacts are the same, since the
impacts are predominantly related to the increased need for housing and
services.
158
-------
1D.1
VANZLT-
KATtB
UORJZBS t
OUTS
«3.»
11.3
rAKXLT
STATUS
rusen
Ul
\o
CONSTBUCTIDH
HOWCEBS
ALREAUr If
WBSIDOKE
11.2
1C.1
t local avlejBKit opport-vttl** «n
•MUM! to asiat IB • large beat coHfalty.
Via population affacta af tha conatnieileo
phaaa ax* tbarafoca takaa to ba pananaat far
all oev aupport workara and far op to 0313 nov
eoaatruction vorkani.
FAMILT-
STATU8
WDRKEIS t
aioinnc
WITS
0.7
FAIOLT 1
STATUS
pBisan
18.2
11.4
ir.i
1C.1
U.1
ir.s
16.7
IB. 2
Figure D-l. Population effects* for the construction phase: large cogeneration system concept in
a large host community.
-------
Explanation of the Parameters in Figure D-I
Diagram
Comment from
No. Node
Arc
from
Node
Comment
1A
1B.1
4
5
6
7
8
9
1A
1B.1
1B.1
1B.1
1B.1
1C.2
1C.2
1D.1
IB.2
1C.1
1C.2
1D.1
1E.1
10.2
IE.2
IE.3
and
ID.2 IE.4
It is assumed that a large construction capa-
bility will exist in the host community. As
many as 2000 of the required labor force viill
already in in residence. The minimum 20 per-
cent influx of new workers is felt to be indi-
cative of what might be expected in a typical
large host community. This is assumed to be
an indication of a general unemployment rate
of 6 percent to 8 percent. (See Comment 3.)
See Comment 1
The .9 multiplier from (18) reflects the high
consumption rates being associated with urban
living. The 100 percent figure up to a maxi-
mum of 3000 implies that the commercial sector
in the host community is expected to ade-
quately support most if not all of the new
construction (see Comment 1).
See Comment 3
The family status of the new work force is
that cited in (18) for construction workers.
See Comment 5
The family status for new commercial sector
workers is assumed tc be the same as that
cited in (18) for permanent workers in the
industrial sector.
See Comment 7
The 3.7 factor from (18) is the estimated num-
ber of persona per family.
160
-------
Explanation of the Parameters in Figure D-l (Cont'd.)
Conment
No.
Diagram
from
Node
Arc
from
Node
Comment
10
11
12
13
14
15
16
17
1E.1 ID.3
and
IE.2 ID.4
IE.3 1F.1
and
IE.4 IF.2
IE.3 1G.1
and
IE.4 1C.2
IE.3 1H.1
and
1E.4 1H.2
IE.3 1J.1
and
IE.4 1J.2
Nev dwelling
units
New residential
land developed
Density of new
population
The 1.82 d-'i •'.sor, computed for the urban liv-
ing pattei s in (19) is the average number of
single-status persons per non-family dwelling
unit.
The percentage is the average number of chil-
dren in this age group as a percentage of the
total family-status population. The figure is
computed from data in (1?) after first adjust-
ing the basic family size to 3.7 persons.
Underlying this average is an assumption thfc:
the age distribution of in-residence children
per family is unaffected by family relocation.
See Comment 11
See Comment 11
See Coninent 11
The new dwelling units in the host community
are given by the sum:
NDU1 - 1D.1 + ID.2 ' ID.3 + ID.4
In an urban setting, (19) gives a typical fig-
ure of 5.32 dwelling units per acre. New
acreage required for housing:
NAH1 =• NDU1/5.32
The average density of the new local popula-
tion is:
ADI - (1E.1 + IE.2 + IE.3 + 1E.4)/NAH1
161
-------
10.1
2B.1
FAKILT-
0TAIOS
UORKERS t
BOUSIHC
ri.7
a. a
FAHXLT-
SIATfaS
PERSONS
20. S
LONG 1W
INDUSTRIAL
KWUJTMin
fa*
1
LONG 1UB
MW nrcos-
fUAL
wonczu
U3X
•DICLB-
8T1TUS
HORKEBS
+1.8Z
SWCL^
8t*TU8
SOUS QIC
WITS
IV)
U.2
U.4
AVAILABU
DIDUStUAL
RRADT II
RKSUENCE
HUM THE
CONSTRUCT
P9ASB
raxscaooL
M.I
ac.i
a.i
zia
ar.2
SIHGU-
STATUS
HORKEIS
il. 81
W
SINCU-
STATUS
RODS DIG
OUTS
ELBKEHYAD
SCHOOL
1C.*
I MIDDLE
] SCHOOL |2H.2
OHLDREH
a. 2
20.4
[HUB SCHOOL
IOHUAEM
U.2
Figure D-2. Long run population effects of the Industrial activity: large regeneration system concept
in a large host community.
-------
Explanation of Che Parameters in Figure D--2
Comment
No.
Diagram
from
Node
Arc
from
Node
Comment
2
3
4
5
2A 2B.1 Of the construction workers still in residence
2A 2B.2 beyond the construction phase, only a portion
2B.1 2C.1 will find future work in local construction.
2B.1 2C.2 The remaining are assumed to take industrial
jobs, since the alternate employment opportu-
nities are likely to arise only gradually over
tine. Therefore, the long run increase in
construction jobs in subtracted from the
locally available work force. Similarly,
other employed workers from the commercial
sector are assumed first to fill any long run
opportunities in this sector while the remain-
ing will seek industrial employment.
Cogeneration system related Long Run Con-
struction Employment:
LRCE • (Long Run Industrial Employment)(1+2.3)
x 5.14 percent
Cogeneration system related Long Run Other
Commercial Employment:
LROCE » (Long Run Industrial Employment)(2.3)
- LRCE
The total locally available work force is com-
puted from Figure B.I.
2A 2B.1 See Comment 1
2B.1 2C.1 The 2.3 multiplier from (18) is the estimated
ratio of support workers to industrial work-
ers. This reflects the high consumption rates
being associated with urban living.
2B.1 2C.2 See Comment 3
2B.1 2D.1 The 85 percent figure from (18) is the percen-
tage of new industrial workers estimated to
family status residents.
2B.1 2E.1 The complement of new workers are single-
status residents. See Comment 5.
163
-------
Explanation of the Parameters in Figure D-2 (Cont'd.)
Conment
No.
Diagram
from
Node
Arc
from
Node
Comment
10
11
12
13
14
15
2D.1 2E.3
and
2D.2 2E.4
2E.1 2D.3
and
2D.2 2E.4
2C.2 2D.2
and
2C.2 2E.2
2E.3 2F.1
and
2E.4 2F.2
2E.3 2G.1
and
2E.4 2G.2
2E.3 2H.1
and
2E.4 2H.2
2E.3 2J.1
and
2E.4 2J.2
New dwelling
units
New residential
land developed
The 3.7 factor from (18) is the estimated num-
ber of persons per family.
The 1.82 divisor, computed for the urban liv-
ing pattern in (19) is the average number of
single-status persons per non-family dwelling
unit.
The family status for new commercial sector
workers is assumed to be the same as that
cited in (18) for permanent workers in the
industrial sector.
The percentage is the average number of chil-
dren in this age group as a percentage of the
total family-status population. The figure is
computed from data in (19) after first adjust-
ing the basic family size to 3.7 persons.
Underlying this average is an assumption that
the age distribution of in-residence children
per family is unaffected by family relocation.
See Comment 10
See Comment 10
See Comment 10
The new dwelling units in the host community
is given by the sum:
NDU2 = 2D.1 + 2D.2 + 2D.3 +• 20.4
In an urban setting, (19) gives a typical fig-
ure of 5.32 dwelling units per acre. New
acreage required for housing:
164
-------
Explanation of Che Parameters in Figure D-2 (Cont'd.)
Diagram Arc
Comment from from
No. Node Node Comment
NAH2 - NDU2/5.32
16 Density of new The average density of the new local popula-
population tion is:
AD2 ° (2E.1 + 2E.2 + 2E.3 + 2E.4)/NAH2
165
-------
3D.1
PAMILT-
8TATUS
WORKERS 1
BOUSDIG
OHITS
«3.» ^
3E.3
rAMXLY-
8TATUS
PERSONS
o\
0%
PEAK
OOH3TRVCIUM
EMPURMBR
PEAK 1
CONST
WORKS
|[i.
IRV
RUCTIOI
IS
* \
Y >
8
1^
SUPPORT
WORKERS
ALREADT II
RBSimCB
«sor.
\
8IHCLE-
BTATUS
WORKERS
3B.1
«2.S ^
SHI6LB-
8TATU8
BOUSZB6
DHITS
39.3
3D.2
NEW
SUPPORT
WORKERS
9C.2
B PAMELT- , PM
|» STATUS )J St/
-3" WORKERS * "^ PEI
\
3J.1
3B.4
PUSC800L
CBOOBBI
3C.1
•Eighty pweat of th« cooatructloo work
fore* U usuMd to nprunt taporcxy
reildeot*. ComcpoBdlnt poitioM of the
dcBDgraphie chance* vUl bo nvtraed aftor
tho conatructloa phmao.
8DICLE
STATUS
WORKERS
.2.3
SIHCLB-
STATD8
HOUSIHG
UNITS
KUMEMTAET
SCHOOL
CHILDKBI
MDDIS
SCHOOL
CHILDREN
1.2
3D.4
HIGH
SCHOOL
CHILDREN
3P.t
36.2
1.2
3J.2
Figure D-3. Population effects* for the construction phase:
small community.
large cogeneration system concept in a
-------
Explanation of the Parameters in Figure D-3
Diagram Arc
Comment from from
No. Node Node
Comment
3
4
5
6
3A 3B Host community will supply few if any of the
construction work force.
3B 3C.1 The .3 is the estimated ratio of support work-
ers to construction workers. This reflects
low consumption rates be.:ng associated with
rural living. The 10 percent constitutes an
adjustment to the 20 percent figure cited in
(18) to reflect the assumed low level of com-
mercial activity previously existing in the
host community. Up to 200 support workers are
assumed available in the host community.
33 3C.2 See Comment 2.
3B 3D.1 The 50 percent figure differes from the 60
percent in (18) to reflect a lower number of
workers who are expected to remain beyond the
construction period.
38 3E.1 Sec- Comment 4.
3D.1 3E.3 The 3.7 factor from (18) is the estimated num-
and ber of persons per family.
3D.2 3E.4
3E.1 3D.3
and
3E.2 3D.4
The aivisor 2.5, computed for rural living
patterns in (19), is the average number of
single-status persons per non-family dwelling
unit.
3C.2 3D.2 The family status for new commercial sector
workers is assumed to be the same as that
cited in (18) for permanent workers in the
industrial sector.
3C.2 3E.2 See Counent 8.
167
-------
Explanation of Che Parameters in Figure D-3 (Cont'd.)
Cooment
No.
Diagram
from
Node
Arc
from
Node
Coonent
10
3E.3 3F.1
and
3E.4 3F.2
11
12
13
15
16
3E.3 3G.1
and
3E.4 3G.2
3E.3 3H.1
and
3E.4 3H.2
3E.3 3J.1
and
3E.4 3J.2
New dwelling
units
New residential
land developed
Density of new
population
The percentage is the average number of chil-
dren in this age group as a percentage of the
total family-status population. The figure is
computed from data in (19) after first adjust-
ing the basic family size to 3.7 persons.
Underlying this average is an assumption that
the age distribution of in-residence children
per family is unaffected by family relocation.
See Comment 10.
See Comment 10.
See Comment 10.
The new dwelling units in the host community
are given by the sum:
KLU3 = 3D.1 + 3D.2 + 3D.3 + 3D.4
In a rural setting, (19) gives a typijel fig-
ure of 2.08 dwelling units per ac^e. New
acreage required for housing:
NAH3 * NDU3/2.03
The average density of the new local popula-
tion is:
AD3 - (3E.1 + 3E.2 + 3E.3 + 3E.4)/NAH3
168
-------
*>
4D.1
FANII.T-
STATUS
WORKERS t
HOUSING
ONXXB
4F.1
4E.1
•3.7
PAKXLY-
8T/TUS
PERSONS
vO
LWC BBH
nnnsniAL
H
tX
M
9
SUPPOBT
ALREADI Di
RESIDBHCB
FBOM THE
COMSTRUCTIOI
.X5X
&,
^V
8WOLE-
STATCS
*2.S
4B.X
HEW
SUPPORT
l^^j^jpa
8IHGLI-
8-ATDS
hOUS DC
OH ITS
4D.J
4D.2 4
• VAMILT-
[22 STATUS
^ WORKERS t
BOUSING wr
X
4
8
FAI
sn
rn
4C,^
4J.1
4C.1
SINGLE-
STATUS
WOBKEBS
t2.S
sracic-
STATUS
BOUSZH6
mat
4B.2
40.4
4E.4
4F.2
46.2
4B.2
4J.2
Figure D-4. Long run population effects of the industrial activity: large ccgeneration system concept
in a small community.
-------
Explanation of the Parameters in Figure D-4
Diagram Arc
Conment from from
No. Node Node Comment
4A 4B Host community will supply few if any of the
new industrial work force. The construction
work force is assumed to subsequently emi-
grate.
4B 4C1 The 1.1 is the estimated ratio of support
workers to industrial workers from (18). This
reflects low consumption rates being associa-
ted with rural living. The idle commercial
work force from the construction phase is the
most the local community can provide to sup-
port the immigraiton industrial work force.
4B 4C.2 The 1.1 and 80 percent come fr.,
-------
Explanation of Che Parameters in Figure D-4 (Cont'd.)
Conment
No.
Diagram
from
Node
Arc
from
Node
Comment
10
4E.3 4F.1
and
4E.4 4F.2
11
12
13
14
15
16
4E.3 4G.1
and
4E.4 4G.2
4E.3 4H.1
and
4E.4 4H.2
4E.3 4J.1
and
4E.4 4J.2
New dwelling
units
New residential
land developed
Densi ty of new
population
The percentage is the average number of chil-
dren in this age group as a percentage of the
total family-status group. The figure is com-
puted from data in (19) after first adjusting
the basic family size to 3.7 persons. Under-
lying this average is an assumption that the
age distribution of in-residence children per
family is unaffected by family relocation.
See Comment 10.
See Comment 10.
See Comment 10.
The new dwelling units in the host community
is given by the sum:
4D.1 + 4P.2 + 4D.3 + 4D.4
minus those vacated by the construction work
force:
0.8 (3D.1 + 3D.3).
NDU4 <• 4D.1 + 4D.2 + 4D.3 + 4D.4
- 0.8 (3D.1 + 3D.3)
In a rural setting (19), gives a typical
figure of 2.08 dwelling units per acre. New
acreage required for housing:
NAH4 - NDU4/2.08
The average density of the new local popula-
tion is:
AD4 = (4E.1 + 4E.2 + 4E.3 + 4E.4)/NAH4
171
-------
TABLE D-l-
LARGE COGENERATION SYSTEM IN A LARGE HOST COMMUNITY-
THE FIRST EIGHT TO TEN YEARS
(1000 MW POWER PLANT)
IV)
— ,„
[••1 -1
..*. . •' •tu-
*X>
L97.1M
2O. 4*2
14.174
II. HI
12. M4
44.428
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-------
TABLE D-'.(continued)
UJ
-------
TABLE D-2-
LARGE COGENERATION SYSTEM IN A SMALL HOST COMMUNITY-
THE FIRST EIGHT TO TEN YEARS
(1000 MW POWER PLANT)
r'""" bo"""i>
- Ml |.I
p r.
i i " *
? k
-------
TABLE !)-2-(conrinuc'd)
-------
TABLE D-3.
PEAK CONSTRUCTION PHASK-
COMPARISON OF CHANCES IN A SHALL AND A LARCE HOST COMMUNITY
(COAL-»-'IRED POWER PLANT - 1000 MW )
?m • M» I «T
Toi »'
POful*' liM
fmmt • .•*-«•
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-------
TABLE D-A.
PHASE JUST PRIOR TO OPERATION-
COMPARISON OF CHANGES IN A SMALL AND A LAKGE HOST COMMUNITY
(COAL-FIRED HOWER PLANT - 1000 MW )
1! to.t
• "•••w •' !••
i . I . i
I.I.I
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-------
TABLE l)-4 (continued)
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-------
TABLE !)-5-
KULl. OPERATION PHASE-
COMPAKISON OF CHANCES !N A SMALL AND A LAKt.Z HOST COMMUNITY
(COAL-K1KE1) POWER PLANT - 1000 MW )
• -. *••<•••
U.tM
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-------
TABLE 0-5. (c"ntinutd)
••••-
»i 100 I JO 140 IW
iVo' iooV*!** ' W 'iii
it', i
n. •
107 •
11. <
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0.0
-------
IABI.K l)-6 .
PEAK CONSTKLCTION PHASE-
COMPAR1SON OF CHANGES !N A SMALL AND LARGE HOST COMMUNITY
(NUCLEAR POWKK PLANT - 1000 MW )
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TABU !>-6- (cunt innt-d)
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-------
TABLE I)- 7.
PHASE JUST PRIOR TO QPERATION-
COMPAR1SON OF CHANGES IN A SMALL AND A LARGK HOST COMMUNITY
(NUCLEAR POWKR PLANT - 1000 MW )
»*fM»t*l
i
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-------
TABLE li-7. (continued)
\ ••!•»»(•>
Pr**•!•'in| valu«
su*
ho* i
i .1 . ^ i .. i_. A. 1 A J . J
0 20 40 60 W 100 120 140
^
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11.00
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• »«* '.evt »
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21. /O
u.to
-------
TABLE D-8-
FULL OPERATION PHASE-
COMPARISON OF CHANGES IN A SMALL AND A L\RGE HOST COMMUNITY
(NUCLEAR POWER PLANT - 1000 MW )
e
03
-------
TABLE D-8- (continued)
":;
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trark«r»
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act coord ln«c*d
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not coordinated
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not coord. tru ted
i
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