WATER POLLUTION CONTROL RESEARCH SERIES • 16130 DHS 08/70
A SURVEY OF
ALTERNATE METHODS FOR
COOLING CONDENSER DISCHARGE
WATER
OPERATING CHARACTERISTICS
AND DESIGN CRITERIA
ENVIRONMENTAL PROTECTION AGENCY • WATER QUALITY OFFICE
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WATER POLLUTION CONTROL RESEARCH SERIES
The Water Pollution Control Research Series describes
the results and progress in the control and abatement
of pollution in our Nation's waters. They provide a
central source of information on the research , develop-
ment, and demonstration activities in the Water Quality
Office, Environmental Protection Agency, through inhouse
research and grants and contracts with Federal, State,
and local agencies, research institutions, and industrial
organizations.
Inquiries pertaining to Water Pollution Control Research
Reports should be directed to the Head, Project Reports
System, Office of Research and Development, Water Quality
Office, Environmental Protection Agency, Room 1108,
Washington, D. C. 20242.
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A SURVEY OF ALTERNATE METHODS
FOR COOLING CONDENSER DISCHARGE WATER
OPERATING CHARACTERISTICS AND DESIGN CRITERIA
DYNATECH R/D COMPANY
A Division of Dynatech Corporation
Cambridge,^ Massachusetts 02139
for the
WATER QUALITY OFFICE
ENVIRONMENTAL PROTECTION AGENCY
Project No. 16130 DHS
August, 1970
For sale by the Superintendent of Documents, U.S. Government Printing Office, Washington, D.C. 20402 - Price $1.00
Stock Number 5601-0128
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EPA Review Notice
This report has been reviewed by the Water
Quality Office, EPA, and approved for publication
Approval does not signify that the contents
necessarily reflect the views and policies of
the Environmental Protection Agency, nor does
mention of trade names or commercial products
constitute endorsement or recommendation for
use.
11
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TABLE OF CONTENTS
Section Page
1 INTRODUCTION
1.1 Overall Program Goals 1
1.2 Scope of Task II 1
1.2.1 Task I and Task II 2
1.2.2 Task II and Task m 4
1.3 Topics under Consideration 4
2 POWER PLANT SELECTION CONSIDERATIONS 6
2.1 Introduction 6
2.2 Initiation 6
2.3 Unit Capacity Selection 8
2.3.1 Growth 8
2.3.2 Limitations 9
2.4 Fuel Selection 17
2.5 Site Selection 26
2.6 Plant Capacity Factor 29
2.7 Fixed Charge Rate 32
3 DETAILED DESIGN AND OPTIMIZATION 35
3.1 Introduction 35
3.2 Basic Cycle Optimization 36
3.2.1 Capital Costs 38
3.2.1.1 Turbine Generator Costs 45
3.2.1.2 Boiler Plant Costs 45
3.2.1.3 Example 48
3.2.2 Operating Costs 49
3.2.2.1 Plant Loading Criterion 50
3.2.2.2 Computation of Base Unit
Incremental Running Rates 56
3.2.3 Present Worth Evaluation 63
3.3 Feedwater Heaters 65
3.4 Condenser System 67
3.4.1 The Single-Shell Condenser 68
3.4.2 The Multi-Pressure Condenser 70
3.4.3 Condenser Costs 76
3.5 Operational Considerations 76
3.5.1 Instrumentation and Control 77
3.5.2 Power Plant Layout 78
iii
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TABLE OF CONTENTS (CONCLUDED)
Section Pag
4 SUMMARY AND CONCLUSIONS 82
BIBLIOGRAPHY 84
Types of Equipment and System Descriptions 84
Operating Procedures 85
General Design 86
Nuclear Design 90
Condenser Design 93
IV
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Section 1
INTRODUCTION
1.1 Overall Program Goals
In December, 1968, Dynatech R/D Company undertook a program for the
Federal Water Pollution Control Administration with the ultimate aim of perform-
ing a survey and economic analysis of alternate methods for cooling condenser
discharge water from thermal power plants. The first phase of this program was
to consist of a systematic gathering of present state-of-the-art information in the
areas of:
1. Large-scale heat rejection equipment;
2. Power plant operating characteristics; and
3. Total community considerations.
This report will document the results of Task n, Phase I, of this program.
1.2 Scope of Task n
The second task of this program is concerned with gathering information
relating to selection, design, and optimization of the power plant itself. In order
to understand the scope and relevance of Task n, it is necessary to review the
thrust of the entire program.
As stated above, the first phase of the investigation is intended to survey
the state-of-the-art in the areas of large-scale heat rejection equipment, power
plant characteristics, and the integration of the power plant with the community
which it serves. Whereas these areas are dealt with separately for the sake of an
orderly investigation, a proper understanding of the problem of thermal pollution
and its solutions as related to electric power generation comes only from a consi-
deration of these three areas as they relate to one another.
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1.2.1 Task I and Task II
The initial task, as reported in July, 1969^presented, in detail, con-
siderations of alternative methods of transferring large quantities of rejected heat
to the atmosphere. However, the technological and economic aspects of this heat
rejection process were discussed in isolation from power plant considerations,
except insofar as the unit capacities (amount of heat to be rejected), process side
temperature (temperature of condenser discharge water), and ambient conditions
(atmospheric dry-bulb and wet-bulb temperatures) were chosen to be typical of
present or projected power plant operating conditions.
The results of an analysis of this kind leads to the conclusion that for a
given heat load and ambient conditions, the size of the heat transfer equipment,
and, as a result, its cost, can always be reduced by raising the process side tem-
perature. It is part of the scope of Task II to relate back to the analysis and con-
clusion of Task land to put this conclusion in a proper perspective.
A brief discussion here will serve to illustrate the importance of this
relationship. Figure 1.1 presents a plot of unit cost versus heat rejection tem-
perature. Line A represents the cost of the heat transfer equipment and shows
the cost decreasing with increasing temperature. Line B indicates a possible total
power plant cost (including heat rejection equipment) which might be typical if an
existing plant, designed to operate at the lowest condensing temperature available
with once-through cooling, is forced to operate in conjunction with a cooling unit
at higher condensing temperatures. As is well Known, if the heat rejection tem-
perature is raised, the operating point of the plant is shifted, with the net result
being an increase in the amount of heat rejected and a decrease in the net output
power.
If, however, one starts with the constraint that once-through cooling is
not permissible, and the technological and economic restrictions and operating
characteristics are included in the total optimization process, then the power plant
cycle and the resultant cost curve will be affected. A possible result is suggested
by Line C in Figure 1.1. The result of including the heat rejection system in the
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Plant
Cost
($/kw)
Cooling
Cost
( $/kw
Condenser Temperature (° F)
Figure 1.1
Plant and Cooling Cost Comparison
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overall system optimization may not result in a shift in the cost minimum to a
new operating point but the absolute level of the cost curve should be shifted down.
1.2.2 Task n and Task III
In addition to providing sufficient information to relate the results of
Tasks I and n together in a total system picture, it is necessary to anticipate the
need to relate Task n to the overall community considerations of Task III. That
is, when the means by which the power producing section of the community might
be integrated with other sections with a need (or at best a possible use) for thermal
energy input, it will be found that most applications require that the energy be
available at temperatures which are considerably in excess of normal power plant
condenser temperatures. Operation at these temperatures will clearly cause the
power plant to operate inefficiently in the classical, thermodynamic sense.
However, if a source of environmental deterioration is eliminated by such a scheme,
then the traditional definitions of efficiency may be replaced by some evaluation
of "quality of life" which will dictate this new operating condition.
Here again, if an existing power plant, designed with conventional para-
meters in mind, were forced to operate at these conditions, the operating cost
would be extremely high and the rated capacity would probably not be attainable.
However, if a plant is designed and optimized from the beginning with these con-
straints in mind, the total system will operate in a more efficient way.
1. 3 Topics Under Consideration
In this task, we will try to consider the fundamental governing criteria which
determine how power plants are designed and optimized. These criteria are both
technical and economic, and many of them are decoupled from the question of heat
rejection and the resultant effect on the environment. That is, no matter what con-
straints are placed on the plant in the way of water use regulations or what decisions
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are reached concerning the trade-offs between once-through cooling, towers, or air
rejection, some of the basic design decisions may well be unaffected. In the following
discussion, we have tried to focus on those technical and economic considerations which
affect and are affected by the process of heat rejection.
This report has been divided into two sections. In Section 2, the whole
question of power plant considerations will be considered. This will include
questions of establishment of need, capacity determination, fuel selection, siting,
capacity factor and fixed charge rates. The process of answering these questions
may be thought of as a system planning study, in which the requirement for detailed
design and optimization are established. These initial design considerations are
often overriding in determining how the power generation section of the community
will operate and therefore must be thoroughly understood by FWQA.
Section. 3 will deal with detail plant design and optimization, which may
be considered as the process of satisfying the needs established in the system planning
study.
Although this two-step method of presentation of the design process is
somewhat indicative of actual practice, there is really no clear separation of the
two processes. System planning is done with expected results of the detailed design
and there are often changes in plans due to results of detail study. The mechanism
and consequences of this feedback vary drastically with individual plants and are
therefore difficult to generalize, although an attempt has been made in Section 3.
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Section 2
POWER PLANT SELECTION CONSIDERATIONS
2.1 Introduction
The selection of the design for a new power plant is influenced by many
factors. The relative importance of these factors will vary according to geogra-
phical location, local legislation, ownership, source of finance, and other cir-
cumstances. The selection considerations discussed below are some of the more
general criteria and procedures used today. It should be emphasized that the
different criteria are not considered separately but rather that many different
combinations need be considered in order to provide a power plant design which
is not only economical but also as beneficial as possible to the community
which it serves.
2.2 Initiation
At the present time, in this country, thermal power plants are being
initiated which will require up to ten years for completion. These long-term
planning requirements necessitate accurate prediction of future power needs. Power
consumption in the United States has grown exponentially in the past. As shown
in Figure 2.1, this growth is expected to continue. Thermal power station require-
ments could, in fact, be greater than these projections with the advent of the
electric car or other major electric power consumer. They could, of course, be
less with advances in state of the art of direct energy conversion, but this is
unlikely for the next several decades. One interesting note is that power company
predictions in the past have always been conservative; i.e., more electricity has
been needed than was predicted.
In the past, initiation of a new power plant sometimes took the form of
a memorandum from the chief engineer at an existing facility to its management
stating that with the expected load increases, the existing generating capacity would
become inadequate at some future date. At present, with the extended construction
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0>
o
rt
a
a
u
on
H
Projected Non-1 luclear
1960
1970
1980
1990
Figure 2.1
Projected Electric Utility Generating Capacity (From Ref. 114)
7
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times necessary for the larger plants, power company management must be aware
well in advance of the future generating needs of the system. Also, due to the large
interconnected grid systems now in use in the United States, the different company
managements must be aware of other system needs and plans. Thus, the decision
to build a new plant nowadays is the result of careful planning of both the people
within a power system and the people representing various neighboring power systems,
2. 3 Unit Capacity Selection
2.3.1 Growth
The development of the thermal power station from its beginning in the
late 1800's to the present can be roughly divided into five successive phases. The
initial phase was characterized by manually fired, fire-tube and combined fire-tube
smoke-tube boilers. This permitted only very small capacities (5Mw) and steam
pressures (200 psi) and lasted until about 1900. Sectional and vertical water-tube
boilers with fixed and restricted movement grates of many different designs marked
the second phase of development, which lasted until about 1925. Capacities increased
to about 30 Mwe and pressure to about 500 psi during this phase. The grating and
material problems of the first two phases were overcome partly in the third phase
with the introduction of pulverized coal firing. With pulverized coal fired radiant
boilers, steam pressure and temperature continued to increase to the 2000 psi and
1000°F range with 100-200 Mwe units until the 1950's. Present day supercritical
fossil plants represent the fourth phase of development. At times during this phase
pressures up to 5000 psi and temperatures up to 1200° F have been used, but the
high cost of austenite steels necessary for these values has caused a general falling
back to the 3500 psi and 1050° F range foe modern fossil fueled plants of up to 1000
Mwe. The fifth phase is, of course, the present nuclear power plant era. Due to
imposed limitations and economic considerations, to be explained, the steam con-
ditions for present day nuclear power plants are in the range of those of the third
stage of development of the fossil fueled plant. Even with these less advanced steam
conditions, nuclear plants of over 1000 Mwe are being planned.
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The heat rate of fossil fueled plants is not expected to be improved much
in the near future. This is due to what are considered stabilized maximum steam
conditions with present day materials. Unit size, on the other hand, is expected to
continue to increase although there appear to be limits on this also. Average and
maximum sizes of new fossil fueled units are shown in Figures 2.2 and 2. 3. It is
noted that while average unit size continues to increase, the maximum unit size
appears to have leveled off. Total plant capacity has shown a similar increase as
shown by some specific examples in Figure 2.4.
The trend toward larger units, both fossil and nuclear, is explained by
the lower specific cost of a power station as unit size is increased, as shown in
Figures 2.5 and 2.6. This trend is expected to be more pronounced with nuclear
plants since capital costs of nuclear plants fall off more rapidly with increased
rating than do capital costs of fossil plants. (Ref. 86). The choice between
nuclear fuel and fossil fuel is discussed more fully in the next section.
2.3.2 Limitations
The problems to be solved in increasing turbine-unit size depend on
whether the purchaser wishes to have a tandem-compound (single shaft) or a cross-
compound machine (double shaft). Maximum size of a tandem-compound turbine is
approximately 800 Mwe at present, while cross-compound machines have been
built with capacities over 1000 Mwe and are available up to 1500 Mwe. The main
problem faced by the turbine manufacturer is the length of blade in the last stage of
the low-pressure turbine. In 1968 blades having a maximum length of 33. 5 in. were
designed for use in 3600 rpm turbines, and 52 in. was the maximum designed length
for 1800 rpm use.
Another possible limit on turbo-generator unit size is transport weight
limits for generators. Direct contact hydrogen and water cooling of rotor and stator
have reduced the specific weight of generators considerably over the past ten years,
yet cartridge stator assembly has been necessary for some of the recent large units.
Stator site winding has been avoided for the large units due to the increased cost, but
could become a necessity as unit size continues to grow.
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~t Average Capacity Within Survey Period
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Maximum Size Unit completed (or planned)
in each year within a given survey period
1200 r
1000 _
Composite of Maximum Size Units
Reported in all surveys
Composite of Maximums
0)
I
•a
a
a
o
x
cti
C
P
\
1962 '64
Growth and Decline of Maximum Size of New Fossil Units (Ref. 63)
11
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1400
1200
1000
to
o>
>, 800
•^•4
a
O
-u
§ 600
400
200
X
©
1950
Average ~ Unit Size Ordered in Year (Ref. 86)
Maximum ~ Unit Size Ordered in Year (Ref. 86)
Specific Plants - (Ref. 53)
X O
GO
GO
O
O
O
0 O
' 1 L
j i L
Extrapolable from experience of early 1950's
i i i i i i i i
1955
1960
1965
1970
Figure 2.4
Growth of Average and Maximum Size of Fossil Plants
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280 -
240
200
160
120
o 80
O
a.
at
O
40
(Ref. 85)
(Ref. 121)
(Ref. 89)
_L
_L
_L
_L
200 400 600 800 1000 1200
Unit Size (Mwe)
Figure 2. 5
1400
1600
1800
Capital Cost for Fossil Plants
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Capital
Cost
($/kw)
600
560
520
480
440
400
360
320
280
240
200
160
1 O t\
120
80
40
(
—
-0
- O
o
0 Specific Plants (Ref. 92)
-
-
- o
Average CRef 110)
~ • \ Specific Plants (Ref. 110)
_ '. Vand "stretch"
_ ' G)
'. \ \ High and Low Gain Breeders i
\"\^ (Ref. 85) Steam Breeders '' |(Ref. 121)
©., ^^^ "^^ / Water Reactors ^ > i
"*'••-? x^ri^^^. i^ — - — •-. \__*
'©• •• . ,."~°^~- ~"U^ _7^— ~^~-^_zr-rr-jL_i:: ^-^
^ w\ "(Ref 89)
-
-
I 1 1 1 1 1 1 | 1 I i l 1 i i | 1 | i j
) 200 400 600 800 1000 1200 1400 1600 1800 2000
Unit Size (Mwe)
Figure 2.6
Capital Cost for Nuclear Plants
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A third limit on turbo-generator size could be turbine shaft strength.
The strength and proportion of these shafts are determined not only by their ability
to transmit full load torque and at the same time support their weights and give
acceptable critical speeds, etc., but also by their capability to withstand severe
transient loads under short circuit conditions. On large turbo-generators the initial
short circuit torque in the air gap can be of the order of ten to fifteen times the normal
full load torque of the machine. The torque transmitted to the rotor shafts is generally
smaller due to torsional elasticity, with the largest torque (four to six times full load
torque) occurring at the coupling between turbine and generator, and diminishing to
about twice full load torque at the high pressure-low pressure coupling in a tandem
compound unit.
Boiler sizes have grown continually in the past but there does appear
to be a future limit on coal burning unit size. A single steam generating furnace for
a 1070 Mwe unit has been put in service in the U. S., and manufacturers are willing
to offer single boilers with a divided furnace having an output of 1200 Mwe for coal
firing. Capacities can easily be increased further if oil or natural gas are burned,
since the limitation on size for coal units is principally one of length of soot blower.
Blowers have not yet been produced in the United States which can satisfactorily deal
with furnace widths, much in excess of 100 ft.
Steam conditions for most present day nuclear plants, as has been
noted, approximate those used in fossil-fueled plants of thirty to forty years ago.
While these conditions result in lower thermal efficiency and thus have limited the
application of nuclear power, two important points have often been disregarded:
1. The steam-temperature limitations of present day light-
water power reactors are as much a result of economic
optimization as they are of technological limits.
2. Limitations on the pressure and temperature of the
steam cycle affect only the efficiency of the steam
cycle itself, whereas the only meaningful comparison
is one based on overall plant efficiency. On this basis,
the nuclear plant fares somewhat better, since the
fossil plant incurs additional inefficiencies in the
furnace/boiler units. That is, in spite of the
15
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extensive use of stack gas recuperators, some of the
energy released in the combustion of the fossil fuel is
lost to hot stack gases. In a nuclear reactor, all of the
energy liberated in the fission reaction is transferred
to the steam cycle.
This is not to say that technological considerations do not limit nuclear plant design.
The major obstacle in improving steam conditions in nuclear plants is still the de-
velopment of suitable materials—the same major obstacle faced in fossil plant design.
Present day steam cycles in nuclear plants can be divided into two cate-
gories; superheated- and saturated-steam cycles. The most common cycle at the
present time, and for the immediate future, is the saturated steam cycle, such as
used in the Oyster Creek (Ref. 102) and Connecticut Yankee (Ref. 86) plants. Super-
heated-steam plant designs can be divided into three main groups:
1. Boiling water integral-superheat plants such as Bonus
and Pathfinder (Ref. 108);
2. Plants that use other-than-water-coolants in a primary
loop to superheat steam in a secondary loop, such as the
liquid-metal Fermi plant, the organic cooled Piqua plant,
and the gas-cooled Peach Bottom plant; (Ref. 115)
3. Nuclear plants using fossil fuel fired superheaters such
as the plants at Elk River and Indian Point (Ref. 115).
While all three types of nuclear superheat plants promise higher thermal efficiencies
in the future, the large (> 400 Mwe) nuclear plants built and on the drawing boards
today are saturated steam cycle plants. The reason that nuclear superheat is more
difficult and expensive to obtain than fossil fuel superheat is the materials that are
required. Besides the high temperature requirement for both nuclear and fossil
superheat, in a nuclear plant there is the desire to maintain a minimum neutron
absorption cross section, and also the requirement that the material can withstand
high neutron fluxes for the fuel lifetime. For these reasons, the maximum steam
temperature for present day large reactors (BWR and PWR) is about 550 ° or less.
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To achieve better efficiencies and the low steam temperatures in nuclear
plants, the incentive has been to operate at the highest possible pressure, which is the
saturation pressure. This causes a major limitation of excessive moisture in the later
stages of the turbine. For a saturated steam cycle with no means of moisture removal
or reheat, initial steam pressures as low as 50 psig may be necessary to keep the
moisture at 1. 5" Hg exhaust pressure within the acceptable range of 8-12% (Ref. 115).
For this reason, nuclear saturated steam plants usually use at least one stage of
moisture separation, whereby steam is extracted from the turbine after partial expan-
sion. Often the steam is reheated immediately following moisture separation, re-
sulting in low pressure superheated steam being returned to the turbine. Reheat is
usually accomplished with either the primary coolant, or with steam extracted from
the reactor or steam generator. The main purpose of reheat in both nuclear and
fossil plants is to reduce the moisture in the turbine exhaust --this then allows higher
initial steam pressure and higher thermal efficiency.
Many other factors affect plant capacity choice, such as location and
community considerations, and they are discussed in the following sections.
2. 4 Fuel Selection
There are two major factors that must be considered in choosing between
nuclear and fossil fuel for a new thermo-electric plant. The first is economics and
the second is public concern. Economics, it will be shown, tends to favor nuclear
power in the future. Public concern, on the other hand, often tends to disfavor nu-
clear power for a number of reasons: thermal pollution, radiation poisoning, or
"bomb" possibility.
The absolute economics of nuclear power are difficult to determine or
to project since the price of plutonium and enriched uranium is set by the Federal
government. The general comparison between nuclear and fossil fueled plants is
one of higher capital cost and lower operating costs for nuclear plants than for fossil
plants. This statement needs considerable qualification and any comparison is
dependent on numerous factors as will be shown below. Also, any really valid
17
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economic comparison between nuclear and fossil fueled plants should be based on
a comparison of the present worth of all future revenue requirements for a plant.
The present worth concept is necessary to account for the difference in timing of
both investments and expenses.
The capital cost of both nuclear and fossil plants depends on two major
variables: time, with regard to technological advances and other economic factors,
and size. The change in capital costs with time is almost impossible to separate
from the size variable. Even when separated from the size effect, it is difficult to
quantify. As part of the consideration of the effect of time are the factors of state
of technology, interest rate, labor and material costs, and site location as reflec-
ting land costs and community considerations. Figure 2.8 is indicative of the
variation in the specific capital cost of fossil fueled plants over the past two decades.
While the ordinate of this figure is specific cost, average plant capacity varied for
the different years and thus affects the changes with time.
Both nuclear and fossil plant specific capital costs decrease with increased
size as was shown in Figures 2.5 and 2.6, with nuclear cost decreasing more
rapidly than fossil. The steeper slope of the nuclear curve is due to the large
amount of fixed-cost investment in a nuclear plant; that is, that minimum invest-
ment required independent of size; e.g., fuel handling systems, chemistry facilities,
certain amounts of shielding and containment. There is proportionally more of
this base investment in a nuclear plant than in a fossil-fuel plant. A recent paper^ '
shows the capital costs of the two types of plants to become equivalent in the
1200 to 1600 Mwe range, as shown in Figure 2.9.
Fuel cost for fossil fueled plants tends to vary considerably with different
locations in the United States,while nuclear fuel cost is essentially constant every-
where as fixed by the government. A continuous national survey of new fossil
fueled plants in the United States shows, Figure 2.10, a general increase in fossil
fuel price over the last two decades, but this may be misleading. The use of
unit trains and coal pipes in the past few years has reduced fossil fuel costs in
some areas of the country.
18
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20-
18
CQ
CO
O
OQ
O
U
16-
14
12
(1967 Dollars Constant)
First Core Average
Second Core Avera
Third Core Average
101 I L
j i
i
123456789 10
Year
Figure 2. 7
Nuclear Fuel Costs 1971-1980 (Ref. 89)
19
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•D
f-,
a
0>
W
-M
CD
O
U
03
03
O
160
150-
140
130-
120
110-
100
1950
'58 '62
Figure 2.8
Capital Cost of Fossil Plants (Ref. 64)
70
20
-------
200
180
160
Capital
Cost
($/kw) 140
Range for
fossil plants
Estimated for nuclear plants
(as of 1968)
120
lOOi
200
400
600
800
1000
1200
Figure 2.9
Unit Size (Mwe)
Capital Cost for Nuclear and Fossil Plants (Ref. 89)
21
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30 _
-4-»
CQ
28
26
CD
O
I
24
22
2o
I _ I
1950 '54 '58 '62 '66
i i
'70
Figure 2.10
Fossil Fuel Costs (Ref. 64)
22
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Figure 2.7 shows predicted nuclear fuel cost for the next decade. For
a comparison of fuel costs as a per cent of the price of the power produced, the
generally lower thermal efficiency of nuclear plants, as compared to fossil plants,
must be considered. Figure 2.11 shows projected nuclear costs in the units of
mills/kwhr, which therefore reflects projected nuclear thermal efficiency.
A comparison of total energy costs, sometimes called "bus-bar" energy
cost, is shown in Figure 2.12. As was mentioned previously, many factors affect
this cost, some of the more important being location, interest rate, capacity
factor, and community consideration.
An interesting example of interest rate affecting the type of nuclear plant
built is the tendency to build gas-cooled reactors in England and Germany and heavy water
reactors in Canada. Both these countries have public power systems and resulting
lower interest rates than the United States. This, therefore, allows both countries
to build reactor types which require more capital investment (gas-cooled and heavy
water versus boiling water and pressurized water as built in the U. S.), but which
use a less expensive fuel (natural uranium versus enriched uranium in the U. S.).
Public concern over nuclear power plants has, in the past, centered on
the "bomb" possibility and radiation poisoning. Before the power companies
launched large scale public relations campaigns, many people associated nuclear
power plants with atomic bombs, and thought that if an accident occurred a nuclear
blast would result. The public now generally accepts that this will not happen,
but there is still much concern over radiation poisoning from a nuclear plant.
This concern is focused on two main types of radioactive release—the "normal"
radiation release from a nuclear power plant or fuel reprocessing plant, and the
possibility of large scale radioactive release caused by an accident. The Atomic
Energy Commission regulates the first type of release to keep it within "acceptable"
limits, and requires many redundant design safety features to be incorporated in
a nuclear plant to try to prevent a major accident from occurring. Nevertheless,
there are still many people who think nuclear power is acceptable, but that it
should be built "in another town."
23
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2.5 r
2.0
1
CO
tn
o
O
i—i
0)
3
1.5
1.0
0.5
Highest expected
Lowest expectec
*Assume 80% capacity factor
0 I I I I t i I I l l i
1970 1975 1980
Figure 2.11
Projected Range of Nuclear Fuel Costs (Ref. 110)
(Including Capital Charges On Fuel Inventory)
24
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6.0
5.0
4.0
Coal
Nuclear 1st Core
.Nuclear 2nd Core
3.0
I
_L
200 400
600
I
J
800 1000 1200
Unit Rating ( Mwe )
Figure 2.12
Total Power Generating Cost ( Ref. 89 )
25
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More recently, public and official concern has been directed toward the
increased heat rejection (and hence, increased thermal pollution) required for a
nuclear plant as compared to a fossil plant. This is due directly to lower overall
plant efficiencies (or higher heat rates) as was discussed briefly in an earlier
section (Sections 2.3.1 and 2. 3. 2).
Efficiencies for modern plants are still subject to considerable variation
depending upon the individual design constraints, but typical values are in the
following ranges:
Fossil - 38-40%
Nuclear, light water - 30-33%
Nuclear, gas-cooled- 37-39%
Although this suggests that gas-cooled, nuclear plants may be built with efficiencies
comparable to the best fossil plants, economic factors described in the previous
paragraph (high initial cost vs. lower operating costs) tend to dictate against their
use in the United States. Therefore, the usual comparison of efficiencies between
fossil and nuclear is based on the light-water nuclear units which must reject up to
50% more heat than well-designed fossil plants of equal capacity. The efficiency of
nuclear plants can be, and is being increased, but the high capital cost and low fuel
cost of nuclear power does not result in as much of an economic incentive for this
increase as it does in fossil fueled plants. Power companies must consider all of
the above given factors and more when deciding on the type of power plant to build.
In 1967 nuclear power accounted for less than 0. 5% of the national electrical output.
It is projected that it will account for about 35% by 1980 and 85% by 2030.
2.5 Site Selection
The trend toward larger power generating plants in the United States is well
established, and associated with this trend is the increasing problem of finding satis-
factory locations for these plants. A number of technical and economic factors must
be considered in selecting a power plant site whether it is nuclear or fossil-fueled.
The principal factors involved are an adequate means of dissipating waste heat,
means for transportation of heavy equipment and/or fuel to the site, proximity to
load or load transmission availability, adequacy of soil conditions for the type of
construction contemplated, the availability of construction and operating labpr, and
26
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community consideration. Nuclear power plants have the added special aspect of
safety requirements as mentioned in the previous section.
The cooling requirements for a nuclear plant are normally significantly
greater than for a fossil-fueled plant as discussed in the previous section. In the
case of once-through cooling, this means that for a comparable water temperature rise
across the condenser (or maximum condenser discharge temperature because of
water use regulations), the nuclear plant requires a significantly higher flow rate
(see Figure 2.13). While the use of a cooling tower can significantly reduce the
flow rate requirements (both because of the evaporative mode of cooling and higher
permissible condenser water temperature rises), the total water usage (as measured
by required make-up water) is still higher for the case of the nuclear plant.
Transportation requirements for fuel for a fossil fuel plant usually re-
present a significant portion of the capital and operating costs. A 1000 Mwe coal
burning plant may use up to 5000 tons of coal per day depending on the type of coal.
This is equivalent to approximately 70 train car loads per day which do not require
such large transportation facilities for operation, but usually require larger capa-
city transportation facilities for construction than do fossil fueled plants. A 5000
Mwe boiling water reactor has a pressure vessel that is 19 feet in diameter and
weighs approximately 500 tons. Thus, water access is desirable in many cases
and essential in some cases to bring the reactor pressure vessel to the site.
Transportation of spent nuclear fuel can be accomplished by truck, but it
is usually more desirable to have rail access to a nuclear plant for this purpose.
The space requirements for power plants can be quite large. The minimum
total area required for a large (1000 Mwe or larger) coal fired station is on the
order of 150 - 200 acres. * ' This includes space for 40 to 50 days coal storage,
ash-disposal basin and switching as well as all other station features. A nuclear
plant of similar capacity with an above-ground reactor containment structure re-
quires a minimum space of about half that for the fossil plant. It should be empha-
sized that these figures are minimum sizes and that most nuclear and fossil plants
are located on considerably larger sites, some over 1, 000 acres.
27
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00
o
0)
-------
The locating of a nuclear power plant at or near a load center (city) is highly
dependent on community consideration. The advantages of siting a nuclear plant in a
city include: freedom from atmospheric pollution and coal dust nuisance, elimination
of large fuel storage space, availability of waste heat for space heating, and the
elimination of great lengths of objectionable overhead transmission or costly under-
ground cable. The potential drawbacks, as mentioned in the previous section, are:
routine radioactive effluents, accident danger, and increased thermal pollution. The
much considered abatement of thermal pollution to rivers and estuaries by use of
cooling towers is not as easily accomplished with a power plant located in a city.
Aside from the excessive cost of the land required for a cooling tower at a city site,
secondary pollution, as described in the Task I report, must be considered as well
as the appearance of the typical cooling tower.
Increased cooperation with local and state agencies and with conservationist
groups has become a necessary policy for power companies recently. This coopera-
tion is necessary in order to solve power-reactor siting problems at an early stage
of planning. There have been instances, such as the proposed 325 Mwe nuclear plant
at Bodega Bay, California, for which the construction application to the AEG was
withdrawn after $4 million had been spent at the site (Ref. 101).
2.6 Plant Capacity Factor
Plant capacity factor is an important consideration in power plant design in
that it enters strongly into the optimization process, as will be seen in Section 3.
Capacity factor is usually defined as the ratio of the average load on a machine,
plant, or system for a givtsn period of time (commonly one year) to the capacity of
the machine or equipment. For evaluation purposes it is usually desirable to base
the capacity factor on the maximum guaranteed capability of the unit or units
considered.
When new units are installed, they are usually the largest and most efficient
in their connected system and are therefore run continuously at maximum capability
to provide the base load of the system. As the years go by, and newer and more
efficient units are installed in the system, the aging units gradually shift from base-
load to peak-load service, and in their final years may run only during the seasonal
29
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peaks or during emergency outages of other units. In design, a high expected capa-
city factor not only allows more capital expenditure for a more efficient plant, but
fuel costs can be reduced due to larger yearly consumption.
Lifetime capacity factor is determined by estimates of load duration of the
plant each year for the life of the plant. These estimates are made in the form such
as shown in Table 2.1 or in the form of curves such as Figure 2.14. Table 2.1 and
Figure 2.14 both result in approximately the same average lifetime capacity factor.
Another means of presenting the equivalent information is a plot of expected annual
generation vs. time. This is shown in Figure 2.15 for a nominal 300 Mwe plant with
the load duration curves of Figure 2.14.
Table 2.1
LOAD DURATION
Hours Per Year at Various Outputs
Output
% of Maximum
Capacity
100
80
60
35
0
0-10
5150
1750
800
700
360
Plant Life - Years
10 - 20
2200
1850
1700
1500
1510
20 - 30
1100
1250
1850
1700
2860
30
-------
co
£
o
ffi
§
7000
6000
5000
4000
3000
2000
1000
Average Lifetime Capacity Factor of
60 Percent
a 00%
% of Maximum >
Net Station Sendout
Annual
Generation
(Mw-hr/yr)
Figure 2.14
Projected Division of Hours for Each Year at Various Loads
3 x 10C
„ 1~
1 x 10 •
MAXIMUM CAPACITY
10 15 20
Years from Construction
25
Figure 2.15
Projected Annual Generation for 300 Mwe Plant with
Average Lifetime Capacity Factor of 60% (from Figure 2.14)
30
31
-------
Load duration tables or curves for a new plant are prepared by a utility
from data on present operating units and expected load increases. The expected
loading of a new plant is usually estimated for a specific type of plant with the idea
of providing a base for economic optimization, as will be seen in Section 3. Also
for optimization purposes, the load duration estimates are usually broken down
further into percents of time at various condenser pressures, as is shown in Table
2.2.
Table 2.2
DIVISION OF HOURS AT VARIOUS CONDENSER PRESSURES
Percent of Time at Condenser
Pressure
(iaHg abs.)
1.0
30
40
55
70
1.5
30
30
30
30
2.0
40
30
15
0
Percent of Maximum
Net Station Sendout
100
80
60
35
2.7 Fixed Charge Rate
An annual fixed charge rate can be defined as the fraction of original cost
which must be paid each year for the use of capital, for amortization of the investment,
and for the payment of other charges incidental to the acquisition or use of the invested
capital. Carrying charges are used to determine the yearly capital costs on items of
equipment. The major items which make up carrying charges used for economic evalua-
tion by privately owned electric utilities are:
1. Depreciation
2. Return on capital
3. Federal Income Tax
4. State and local taxes
5. Insurance.
32
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There are numerous means by which depreciation may be calculated such
as the straight line, the sum-of-the-year-digits, and the sinking-fund methods. Simple
straight-line depreciation is most often used by power utilities with occasional use of
two methods at the same time; the straight line method used for rate of return calculations
and a more rapid depreciation, such as the sum-of-the-year-digits method used for in-
come tax purposes. Normal straight-line depreciation is usually taken as 3.0% or 3.33%
corresponding to expected lives of 33 and 30 years respectively.
Return on capital and Federal Income tax are usually fixed percentages of
the value of the depreciated utility plant and as such decline as the original investment
is amortized. State and local taxes and insurance can either be considered as fixed
percentages of the original investment or treated as percentages of the depreciated
value of the utility. Figure 2.16 shows typical annual fixed charges made up of the
following:
1. Straight-line depreciation at the rate of 3. 33 percent
of the initial investment per year, with zero salvage
value at the end of the 30-year life.
2. Rate of return of 6.25 percent of the annual average
unrecovered investment.
3. Federal Income Tax rate of 4.15 percent of the annual
average unrecovered investment. This is based on a
debt-equity ratio of 50 percent.
4. Property Tax rate and insurance of 3. 31 percent
of the unrecovered investment at the beginning of
each year.
The large variation in fixed charge rate as the investment is amortized makes
it difficult to select a year or group of years which may be considered for evaluation
purposes, especially if present worth evaluation is used. The means by which this
variation is accounted for is discussed in Section 3.
33
-------
20
§
o
j-i
o>
CQ
0)
bfl
O
13
I
PM
5 [Property Tax and
Insurance
25
30
Figure 2.16
Typical Fixed Charges
34
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Section 3
DETAILED DESIGN AND OPTIMIZATION
3.1 Introduction
The design and construction of power plants using other than once-through
cooling will become increasingly important in the near future. To evaluate the economics
of these future plants it is first necessary to have an understanding of the techniques used
in the design and optimization of present day power plants. The cost of various types of
heat rejection equipment was discussed in the Task I Report and will not be covered again
in this report; rather the report will focus on the other main components of a power plant.
The economic incentive for power plant optimization is considerable. For
a utility with a steam unit capacity of approximately 2500 Mw, such as the Department
of Water and Power of Los Angeles, the annual fuel bill is about $35 million, which
represents only about 20 percent of the total power system budget (Ref. 26). Because
of this, it is apparent that a 1/2 or 1 percent reduction in either heat rate or capital
cost represents substantial savings. A non-economic consideration for improving the
efficiency of a power plant is that the higher the efficiency of a plant, the less waste
heat must be rejected to the environment per unit of electricity produced.
In Section 2, overall plant selection was considered and some discussion
of the selection of an optimum plant size was included. That type of preliminary design
study may be considered system planning, which is most often done by the power utilities
themselves. They define their power requirements and other general parameters, such
as expected load duration, in the system planning phase of power plant design.
This section describes the detailed design and optimization that follows a
system planning study. The two phases are, of course, never completely distinct, since
the considerations and results of each phase have some influence on the other phases.
The order of consideration of the parameters for optimization is as follows:
first, to select the initial pressure and temperature and reheat temperature; second,
35
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to consider the number and temperature of feedwater heaters; and third, to consider
the effect of various condensers. Less important parameters such as maintenance
and controls are then studied and the whole plant re-evaluated in terms of the suc-
cessive design changes. These progressive steps in the detailed design and optimization
procedure have been followed in the sections of this chapter.
The differences between nuclear and fossil plants have been de-emphasized
in this chapter. The economics of nuclear plants are more complex than fossil plant
economics and have been clouded by influences such as AEC support of nuclear fuel
prices, the tendency of manufacturers to bid low to get into the market, and the fact
that each new nuclear plant has usually incorporated some advancement in the state
of the art and is thus somewhat of a "first". However, the design and optimization
procedure is the same for both nuclear plants and fossil plants, and therefore the
procedure as explained in this chapter should be equally valid for both types of plants.
We also have included nuclear turbine costs in the appendix, which may be used in the
same fashion as fossil turbine costs.
Detailed economic optimization of present day power plants is often done
with the use of a computer. The computer programs that are used range from ones
that are very much simple trial and error, to ones that are very sophisticated. The
details of these programs will not be covered in this report, but rather a more general
approach will be taken.
3.2 Basic Cycle Optimization
The most important cost optimization procedure used in power plant design
after a system planning study, is the determination of the initial pressure and temperature
and the reheat temperature(s) of the unit. Also of initial importance is the type of turbine
to be used, e.g., cross compound or tandem compound and the length of the last stage
of blades.
It has been found in the past that somewhat specific ranges for the above
parameters represent probable ranges within which the most economical values will
be found. In order to shorten the description of these parameter ranges we will limit
our consideration to units of greater than 200 Mwe.
36
-------
For large steam units of greater than 200 Mwe the values of initial
pressure and temperature and reheat temperature that are usually considered are
given in Table 3.1.
Table 3.1
Initial Pressure, psi 1800, 2400, 3500
Initial Temperature, °F 1000, 1025, 1050, 1100
Reheat Temperature, °F 1000, 1025, 1050
The possible combinations of the variables in Table 3.1 are over 100 if
a second reheat is considered. If this is multiplied by the possible kinds of turbines
for each pressure and temperature (approximately 20), then the total number of possible
alternatives exceeds 2000. Obviously, detailed cost calculations cannot be performed
for 2000 alternatives, except possibly by computer. Therefore, some sort of limiting
approximations are necessary. These approximations are the result of past experience
in power plant design and a general knowledge of the costs as functions of the various
parameters. For example, for a plant with an expected high lifetime capacity factor
only higher pressures will be considered.
The final selection of the optimum power plant is done by calculating
the present worth of all future revenue requirements* for various alternatives and
selecting the lowest. The present worth concept discounts the value of money needed
in the future (fuel cost, etc.) relative to initial revenue requirements (capital expenditures),
as will be explained in Section 3.2.3. To calculate the present worth of the various al-
ternatives requires the calculation of the capital charges per year and the operating costs
per year for the various alternatives. The details of these procedures are described
in the following two sections, and the means of converting to present worth described
in the third section.
*Approximately 80% of power companies in the United States use this method.
37
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3.2.1 Capital Costs
The calculation of yearly capital charges requires first a calculation of
the initial investment costs. The fixed charge rates, as described in Section 2.7, are then
applied to the initial investment cost to give the capital charges per year.
The investment required for a steam power plant varies greatly with
location, fuel, particular requirements, desired heat rate, and numerous other factors.
Figure 3.1 shows the type of variation in cost encountered for steam power plants in
this country.
100
o
50 100 150 200 250
Station Cost, Dollars Per Kw
Figure 3.1
Cumulative Frequency Distribution of Station Cost (From Ref. 51a)
38
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To understand the reasons for this large variation, it is necessary to ex-
amine the costs of the various components that make up a steam power plant. The
largest source of data on steam power plant costs are the reports of the utilities to
the Federal Power Commission. The FPC has established a Uniform System of
Accounts (Ref. 4a) that the utilities use for reporting costs. Some of the important
accounts of the system are specified as follows:
For Fossil-Fueled Plants:
Account 310. Land and Land Rights
This account includes the cost of land and land rights employed in connection
with steam-power generation.
Account 311. Structures and Improvements
This account includes the cost in place of structures and improvements used
and useful in connection with steam-power generation. (Note: Also includes steam-
production roads and railroads.)
Account 312. Boiler-Plant Equipment
This account includes the cost installed of furnaces, boilers, coal and ash
handling, coal-preparing equipment, steam and feedwater piping, boiler apparatus
and accessories used in the production of steam, mercury, or other vapors, to be
used primarily for generating electricity. (Note: Includes the feedwater heaters,
boiler feed pumps, and all other equipment associated with the feedwater system.
Also, when the system for supplying boiler or condenser water is elaborate, as when
it includes a dam, reservoir, canal, pipe line, or cooling pond, the cost of such spe-
cial facilities shall be charged to a subdivision of Account 311.)
Account 314. Turbine-Generator Units
This account includes the cost installed of main turbine-driven units and
accessory equipment used in generating electricity by steam. (Note: Also includes
the condensers and circulating-water system. Also cooling system including towers,
pumps, tanks, and piping.)
Account 315. Accessory Electrical Equipment
This account includes the cost of auxiliary generating apparatus, conversion
equipment, and equipment used primarily in connection with the control and switching
of electric energy produced by steam power, and the protection of electric circuits
39
-------
and equipment, except electric motors used to drive equipment included in other
accounts. Such motors shall be included in the account in which the equipment with
which it is associated is included. (Note: Does not include transformers and other
equipment used for changing the voltage or frequency of electric energy for the pur-
pose of transmission or distribution.)
Account 316. Miscellaneous Power-Plant Equipment
This account includes the cost installed of miscellaneous equipment in and
about the steam-generating plant devoted to general station use, which is not properly
includable in any of the foregoing steam-power-production accounts.
Account 353. Station Equipment
This account includes the cost installed of transforming, conversion, and
switching equipment used for the purpose of changing the characteristics of electricity
in connection with its transmission or for controlling transmission circuits.
For Nuclear Plants:
For nuclear plants, similar accounts are defined. These are:
Account 320: Land and Land Rights
Account 321: Structures and Improvements
Account 322: Reactor Plant Equipment
Account 323: Turbogenerator Units
Account 324: Accessory Electric Equipment
Account 325: Miscellaneous Power Plant Equipment
Similar to the case of fossil plants, condensers and cooling systems including
towers are part of Account 322. However, ponds, reservoirs, dams, etc. are in-
cluded as a subsection of Account 321, Structures and Improvements.
Figure 3. 2 shows typical relative magnitudes of the various costs according
to the FPC accounts. Specific FPC data, however, must be used with discretion
because there are some items that have not been clearly defined. The most important
of these is "installed generating capacity" which some utilities consider to mean the
nameplate rating while others report maximum unit capability. The difference can
be as much as 25 percent.
40
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Because some of the accounts specified by the FPC are so broad, it is nearly
impossible to use their statistics to establish detailed patterns of station component
costs. However, since these accounts are so widely used and there is a large body of
data classified according to the system, it is beneficial to examine them further.
For optimization purposes it is generally sufficient to examine the changes in
boiler-plant equipment costs and turbine-generator equipment costs with size and steam
conditions. Overall capital costs as functions of size were discussed in Section 2, and
therefore in this section the emphasis will be on variation of costs with steam conditions.
Unit size, however, is still an important parameter is the discussion. Table 3.2 shows
some 1963 costs broken down into component costs. It is seen that the major cost
changes with steam conditions occur for the boiler plant equipment costs and the tur-
bine plant equipment costs, and that other costs, such as transmission costs, although
large, do not vary significantly with steam conditions.
To understand the reasons for these cost variations with steam conditions it
is first necessary to break down the boiler plant equipment costs and turbine genera-
tor equipment costs further. Table 3.3 shows approximate cost percentages for the
various components of these two cost accounts. In the next two sections turbine genera-
tor costs and boiler costs are discussed in more detail.
41
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250-
to
200-
o
*!—f
UJ
150-
8.
n 100-
CO
o
O
c
o
50-
Boiler Plant
Equipment
(Acct. No. 312)
Turbogenerator
Unit
(Acct. No. 314)
Structures and
Improvements
(Acct. No. 311)
Accessory Elec
Acct. No. 312
Acct. No. 314
Acct. No. Sir
Acct. No. 315
1%
1.5%
\
15%
Reactor Plant
Equipment
(Acct. No. 322)
Turbogenerator Unit
(Acct. No. 323)
Structures and
Improvements
(Acct. No. 321)
__ -Accessory Elec.
). 5% Equip. (Ac. #324
Misc. Plant Equipment
(FPC Acct. No. 316)
-Misc. Plant Equipment (Acct. No. 325)
Figure 3.2
Typical Distribution of Station Costs According to FPC Accounts for Coal-Fired, Gas or Oil-Fired,
and Nuclear Plants (from Ref. 16a)
-------
POWER STATION CAPITAL COST (THOUSANDS)
Nameplate
Pressure, psig
Temperature, F
First Reheat, F
Second Reheat , F
310 Land and Land Rights
311 Structures and Improvements
312 Boiler Plant Equipment
314 Turbine Generator Equipment
315 Accessory Electrical
Equipment
316 Miscellaneous Power
353 Transmission
Transformers
General Items
Contingency
TOTAL COST
$/kw net output
2400
1000
1000
$ 200
2,860
15,590
8,408
1,204
414
320
4,345
1.609
$34,950
$114.97
300 Mw
TC4F
3600 RPM
3500
1000
1000
$ 200
2,860
16,228
8,541
1,204
414
320
4,414
1.669
$35,850
$119.18
400 Mw
TC4F
3600 RPM
3500
1000
1000
1000
$ 200
2,860
16,612
8,917
1,204
414
320
4,478
1.695
$36,700
$121.74
2400 3500
1000 1000
1000 1000
$ 200 $ 200
3,015 3,015
19,907 20,638
10,520 10,431
1,277 1,277
417 417
415 415
4,735 4,800
1,964 2,007
$42,450 $43,200
$103.79 $106.60
500 Mw
CC2F
3600/1800 RPM
3500
1000
1000
1000
$ 200
3,015
21,149
10,809
1,277
417
415
4,868
2. 050
$44,200
$108.67
2400
1000
1000
$ 200
3,510
23,959
13,238
1,565
443
490
5,388
3.407
$51,200
$ 98.79
3500
1000
1000
$ 200
3,535
25,179
13,154
1,565
443
490
5,478
2.456
$52,500
$102.81
3500
1000
1000
1000
$ 200
3,510
25,504
13,566
1,565
443
490
5,540
2,482
$53,300
$103.69
2400
1000
1000
$ 200
3,790
27,730
14,983
1,655
475
590
5,922
2,705
$58,050
$ 95.35
600 Mw
CC2F
3600/3600 RPM
3500
1000
1000
$ 200
3,790
28,943
14,886
1,655
475
590
5,981
2.780
$59,300
$ 98.42
3500
1000
1000
1000
$ 200
3,790
29,578
15,340
1,655
475
590
6,077
2,895
$60,500
$100.05
Table 3.2
1963 POWER PLANT COSTS (FROM REFERENCE 65)
-------
Table 3.3
TYPICAL BREAKDOWN OF BOILER PLANT EQUIPMENT COSTS
AND TURBINE GENERATOR EQUIPMENT COSTS
(after Ref. 16a)
Account 312. Boiler Plant Equipment
Boiler 55
Piping 15
Fuel Handling System 13
Feedwater System 9
Draft System 5
Ash Handling System 3
Toof
Account 314. Turbine Generator Equipment*
Turbine Generator 75
Condenser 10
Condenser Supply System 15
*Cost breakdown typical for a once-through cooling system.
44
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3-2.1.1 Turbine Generator Costs
Turbine generator costs are one of the more well defined components of
steam station costs. The manufacturers of this equipment publish prices for a large
number of "standard" units including price modifications for various steam conditions.
Table 3.4 is a recent Westinghouse price list for various large steam turbines, and are
base, uninstalled prices. The actual selling price is obtained by the use of a common
multiplier (quoted as 0.54 in March, 1970), i.e., the price of a 175,000 kw, TC2F-25*
is $9,800,000 x 0.54 - $5,292,000 or $5, 292, 000/175, 000kw = 30. 24 dollars/kw.
The full Westinghouse price list and portions of the General Electric price
list have been included in the Appendix. Prices for the two company's turbines are
identical (as is the multiplier) on an equal power basis with slightly different designs
(last stage blade lengths) used. The price multiplier applies not only to the base turbine
prices but also to all the accessory prices given in the Appendix.
It should be noted that in Table 3.4 there is a cost reduction between similar
units in going from 2400 psi to 3500 psi, which is contrary to general power station costs
as functions of pressure. This decrease in cost for the turbine is more than compensated
for by increased boiler cost, and also by the increased cost of a second reheat, a usual
addition to supercritical units.
The condenser system, which comprises about 25 percent of the turbine
generator system cost will be discussed in Section 3.4
3.2.1.2 Boiler Plant Costs
Boiler costs are one of the most difficult component costs to obtain. The
difficulty is that there are many variables, such as fuel type, that have a significant
effect on the overall cost and that are not in standard use throughout the industry. Boiler
manufacturers do not publish prices, and it is necessary for utility companies to submit
detailed design requirements to the manufacturers to obtain cost estimates.
*Numbers after turbine type are length of last stage blades (in inches).
45
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Table 3.4
(From Westinghouse - See Appendix)
Steam Turbine Generator
Units
Condensing Non-Reheat and Reheat
Double Flow 25-Inch Last Row Blades
and Larger
Condensing Reheat Units
Basic List Prices
Prices—in Thousands of Dollars—In-
clude Freight and Installation Services
Basic Unit Generator Turbine Basic List
Turbine Rating, Exhaust Price
Rating, Kw Kva Ends
Tandem Compound—3600 Rpm
175,000
225,000
250,000
250,000
350,000
450,000
500,000
500,000
650,000
750,000
210,000
270,000
300,000
300,000
420,000
540,000
600,000
600,000
780,000
900,000
2-25"
2-28.5"
2-31"
4-23"
4-25"
4-28.5"
4-31"
6-25"
6-28.5"
6-31"
$ 9,800
12,200
13.300
13.400
16,200
20.600
23.000
23.000
28.600
32,800
Cross Compound—3600/3600 Rpm
250,000
350,000
4CO.OOO
450,000
500,000
500,000
650,000
700,000
750,000
900,000
1,000,000
300,000
420,000
480,000
4-23"
4-25"
6-23"
540,000 4-28.5"
600,000 4-31"
600.000 6-25"
780.000 6-28.5"
840.000 8-25"
900,000 6-31"
1,080,000 8-28.5"
1,200,000 8-31"
15,800
18.E50
20.500
22.800
25,000
25.000
30.400
31.200
34.700
40.000
43.800
Cross Compound—3600/1800 Rpm
400,000
500,000
700,000
800,000
1,000,000
1,200,000
1,400,000
1,500,000
480,000
600,000
840,000
960,000
1,200,000
1,440,000
1,680,000
1,800,000
2-40"
2-44"
2-52"
4-40"
4-44"
6-40"
4-52"
6-44"
21,200
24,800
33,100
37,000
43,200
51.200
67.000
61.800
Pricing for Units with Capability
other than Listed
1. Add or deduct turbine capability at
$9.00/kw for each kw more or less than
listed in table for base machine of the
type desired.
2. Add generator capability at $10.00/kva
for each kva more than listed in table for
base generator rating.
3. Deduct generator capability at $10.00/
kva for each kva less than listed in table
for base generator ratings down to
150,000 kva.
4. For further kva reductions lower than
150,000 kva, deduct $12.00/kva.
Price Additions for Pressure (Psig)
Prices—in Thousands of Dollars
Turbine
Rating, Kw
1 60,000
200,000
300,000
400,000
600,000
600,000
700,000
800 000
900 000
1 ,000,000
1 100000
1 ,200,000
1,300,000
1 ,400,000
1 ,500,000
Initial Pressure
1250-1450
$ 120
300
540
840
1.200
1,620
Range, Psig®
1 600-1 800
$ 0
0
120
300
540
840
1,200
1 620
2 100
2200-2400
$ 120
0
0
0
120
300
540
840
1 200
1,620
2 100
2 640
3 240
3 900
4.620
3200-3500
$540
300
120
0
0
0
0
0
0
0
o
o
o
o
0
41 00-4500
$1,200
1.000
800
600
700
800
900
1 000
1 100
1,200
300
400
500
600
.700
®For pressures between those listed above, use the adjoining pressure range which results in the higher price.
Table F: Price Additions for Temperature (°F)
Prices—in Thousands of Dollars
Turbine
Rating, Kw
1 50,000
200,000
300,000
400,000
500,000
600,000
700,000
800000
900,000
1 000 000
1 100,000
1 200,000
1 300 000
1 400,000
1,600,000
Initial Temperature Range
826-
900
-$ 60
- 90
- 120
- 160
- 180
- 210
901- 951-
950 1 000
-» 40 $0
- 60 0
- 80 0
- 100 0
- 120 0
- 140 0
0
0
0
0
0
0
0
0
0
1001-
1050
$180
180
240
300
360
420
480
640
600
660
720
780
840
900
960
1051-
1100
t 480
480
480
600
720
840
960
1,080
1,200
1,320
1,440
1,660
1,680
1,800
1.920
First Reheat Temperature Range
826-
900
-$ 60
- 90
- 120
- 160
- 180
- 210
901-
950
-$ 40
- 60
- 80
- 100
~ 120
- 140
951- 1001-
1000 1025
$0 $300
0 300
0 300
0 300
0 300
0 320
0 340
0 360
0 380
0 420
0 440
0 480
0 600
1026-
1050
$500
500
600
500
600
620
640
680
700
Second
1000
$1,600
1.600
1,600
1.600
1.700
1,800
1 900
2 600
2.700
Reheat Temperature Range
1001-
1025
$1.800
1,800
1.800
1.800
1,900
2.000
2 arm
1026-
1050
$2.000
2,000
2,000
2,000
2,100
2.220
2 340
9 con
i inn
Price* effective August 9,1969; subject to change
without notice.
46
-------
Babcock and Wilcox have, however, made some estimates of general cost
differentials for variations of pressure, temperature, fuel type, and unit size. These
differentials, for three pressures (1800, 2400, and 3500 psig) three reheat schedules
(1000/1000° F, 1050/1025° F, and 1000/1000/1000° F) and two capacities (300 Mw;
2100 x 10 lb/hr and 500 Mw; 3400 x 103 Ib/hr) are shown in Table 3. 5 for coal-fired
units. Simple, additive corrections forgoing to gas-fired or oil-fired are given below.
Table 3.5
BOILER COST DIFFERENTIALS* FOR COAL-FIRED UNITS
(figures in $/kw)
1000/1000°F 1050/1025°F
300 Mw 500 Mw 300 Mw 500 Mw
1000/1000/1000°F
300 Mw 500 Mw
1800 psig
2400 psig
3500 psig
-2.69
0.
(base)
+0.90
not
available
-1.68
-0.78
-1.75
+0.94
+1.84
not
available
-0.82
+0.08
not
available
+1.35
+2.25
not
available
-0.36
+0.54
*Cost differentials (delivered and erected) including burning equipment, forced
draft fans, structural steel, air heaters, insulation, lagging and casing, flues
and ducts, and soot blowing equipment; excluding high pressure leads and feed-
water system (Courtesy of Babcock and Wilcox).
The corresponding cost differentials for oil-fired or gas-fired units are ob-
tained for any specific pressure, reheat schedule, and unit size simply by adding the
additional savings noted below. These savings differ slightly with unit size.
Table 3.5a
ADDITIONAL SAVINGS FOR DIFFERENT FUELS
300 Mw 500 Mw
Oil-fired
Gas -fired
-11.26
-12.43
-11.22
-12.46
47
-------
Therefore, the total differential cost for a gas-fired, 3500 psig, 1000/1000/1000°F,
300 Mw unit is
A$/kw = +2.25 -12.43
(Table 3. 5) (Table 3. 5a)
= -10.18 $/kw
while for a 500 Mw unit of the same type
A$/kw = +0.54 -12.46
(Table 3. 5) (Table 3. 5a)
= - 11.92 $/kw
47a
-------
3.2.1.3 Example
For use in explaining the optimization procedure in the following sections
we have chosen an example from the literature (Ref. 40a). The example includes
estimates of costs for various steam conditions for a 300 Mw new unit in 1963. These
cost estimates were based on book prices for turbine generator units and preliminary
cost data from manufacturers of other equipment. The total plant costs for the various
units are shown in Table 3.6. It is noted that the costs in Table 3. 6 are considerably
higher than the costs for the 300 Mw units shown in Table 3.2. This is due to the use
of book prices and preliminary estimates for the costs shown in Table 3. 6 whereas the
costs in Table 3. 2 were based on competitive prices.
The nine sets of steam conditions and turbine types shown in Table 3. 6
will also be used as examples in the next sections on operating costs.
Table 3.6
COST DATA FOR VARIOUS ALTERNATIVE STEAM CONDITIONS
Alternate
Number
1
2
3
4
5
6
7
8
9
2400
2400
3500
3500
3500
3500
3500
3500
3500
AND TURBINE TYPES (from Ref.
Turbine
Steam Conditions
psig,
psig,
psig,
Psig,
Psig,
psig,
Psig,
Psig,
psig,
1000/1000
1050/1000
1000/1000
F
F
F
1000/1000/1000 F
1000/1025/1050 F
1000/1000
1000/1000
1000/1000
1000/1000
F
F
F
F
Type
TC4F-26
TC4F-26
TC4F-26
TC4F-26
TC4F-26
TC4F-29
CC4F-29
CC2F-38
CC2F-43
40 a)
Initial
Station
Cost*
128.
131.
133.
138.
140.
134.
136.
135.
138.
$/kw
96
19
98
68
94
71
32
65
47
Maximum
Net Station
Sendout
(at 1.5 in. Hg.)
kw
303,
302,
299,
299,
299,
302,
302,
301,
305,
700
700
330
980
980
330
330
330
330
*$/kw based on maximum net station sendout at 1. 5 in. Hg. abs.
48
-------
3.2.2 Operating Costs
The analysis of how comparative operating costs for a variation of alterna-
tive power plants will consider only the fuel costs. Other operating costs such as
labor and maintenance will be deferred to Section 3. 5. This restriction is usually
imposed on the basic cycle optimization procedures in practice, since the fuel costs
represent the dominant portion of the operating costs. Furthermore, changes in
the basic cycle affect the fuel costs to a much greater extent than that to which they
affect the other operating costs.
In order to compute the fuel costs for the various alternative cycles, the
following information is required:
1. the heat rate (efficiency) for cost cycle (Appendix)
2. the projected load duration curves (Figure 2.14)
3. the associated projected condenser pressure curves (Table 2.2)
4. the criterion by which the loads are distributed among the
plants within the particular utility system.
With this information, the comparison and selection procedure consists
of the following steps:
1. Quantify the criterion for load distribution in the utility
system (this sets the basis for comparison).
2. Compute the expected loadings of the alternatives.
3. Calculate the expected fuel consumption over the life
of the plant.
4. Calculate the present worth of the future fuel costs.
In order to perform these steps, it is necessary to make projections of
future fuel costs. Nuclear and fossil fuel costs were discussed in Section 2 and past
fuel costs are shown in Figures 2. 7 and 2.10. The common assumptions are either
49
-------
that the cost will remain constant or that it will increase linearly at some assumed
rate given the life of the plant. The entire procedure will be illustrated by means of
a sample computation based on the selection of a 300 Mwe (nominal) unit from among
the alternatives tabulated in Table 3. 6 to meet the projected load duration tabulated
in Table 2.1 and Table 2.2.
3.2.2.1 Plant Loading Criterion
There are two commonly used criteria for determining how the total
system load is assigned to the individual units within the system. These are:
1. All units operating at equal Incremental Heat Rates
or 2. All units operating at equal Incremental Running Rates
These terms are defined as follows:
(a) Incremental Heat Rate (IHR)
The incremental heat rate is the additional amount of energy input
required to obtain a unit change in power output, expressed in (Btu/hr-kw). The heat
rate (HR) relates the energy input (Q™) to the plant output (KW) as
„„.*«
KW
Therefore, the incremental heat rate (IHR) can be expressed mathemati-
cally as:
AO
TTTT? = IN - A (HR x KW)
K AKW ~ AKW
= KW A(HR) + HR
KW A(KW) + HR
Therefore, curves of incremental heat rate vs. load are readily con-
structed from the normal unit rating curves of heat rate vs. load. These are shown
in Figures 3.3 and 3.4.
50
-------
(b) Incremental Running Rate (IRR)
The incremental running rate is the additional cost to obtain a unit
increase in plant output. This is computed simply as the fuel cost (in $/Btu) times the
incremental heat rate. These curves correspond to the absolute and incremental heat
rate curves of Figures 3. 3 and 3. 4 and are shown in Figures 3. 5 and 3.6.
The absolute heat rate curves, from which the others are obtained, are
computed from the turbine heat rate tables included in the Appendix. In order to give
meaningful comparisons between plants, however, the turbine heat rate must be
connected to a net plant heat rate (NHR). This is given by:
Plant NHR = turbine heat rate
/ % Auxiliary Power\
77 boiler \ 100 J
where TJ = boiler efficiency
Boiler efficiencies range from 88% to 91% and are normally considered constant for
optimization computations.
Figures 3. 3 and 3. 4 show absolute and incremental plant net heat rates
at 1. 5 in Hg abs condenser pressure for the nine cases of the example of the preceding
section. Figures 3. 5 and 3. 6 show the incremental running rate curves for the same
cycles for a fuel cost of 35. 0 cents per million Btu. These curves have the same
shape and general characteristics as the incremental heat rate curves of Figures 3. 3
and 3.4, except that the "hooks" at the lower ends have been eliminated.
51
-------
f-i
si
i
HI
a
10000
9500
9000
8500
8000
7500
7000
Absolute Heat Raw
Incremental .
Heat Rate \
1.
2.
3.
4.
5.
Turbine Type, TC4F-26
2400 psi - 1000/1000
2400 psi - 1050/1000
3500 psi - 1000/1000
3500 psi - 1000/1000/1000
3500 psi - 1000/1025/1050
I i i
100 150 200 250 300
Net Station Sendout - Mw
350
Figure 3.3
Absolute and Incremental Heat Rates at 1. 5" Hg Condenser
Pressure. Variation with Pressure and Temperature
52
-------
10000
9500
9000
8500
-
PQ
s
.3 8000
0>
ffi
Absolute Heat Rate
7500
7000
3500 psi - 1000/1000
3. TC4F-26
6. TC4F-29
7. CC4F-29
8. CC2F-38
9. CC2F-43
100 150 200 250 300 350
Net Station Sendout - Mw
Figure 3.4
Absolute and Incremental Heat Rates at 1. 5" Hg Condenser
Pressure. Variation with Turbine Type
53
-------
3.4
3.2
3.0
0>
I 2.8
2.6
01
2.4
2.2
Fuel Cost - 35. 0 cents/MBtu
Turbine Type, TC4F-26
1. 2400 psi - 1000/1000
2. 2400 psi - 1050/1000
-3. 3500 psi - 1000/1000
4. 3500 psi - 1000/1000/1000
5. 3500 psi - 1000/1025/1050
50 100 150 200 250
Net Station Sendout - Mw
300
350
Figure 3.5
Incremental Running Rates Corresponding to Incremental
Heat Rates Shown in Figure 3.3
54
-------
0>
•8
rt
-------
The criterion which will be adopted here is that a utility system will run
all of its individual plants at equal running rates. It is clear that this represents a
minimum cost solution. Consider, for example, two plants one operating at a higher
IRR than the other. If the load on the first plant is reduced AKWi.this will result in
a cost savings of AKW x IRR... This load can then be picked up by the other plant at
a cost of AKW x IRRg. This results in a net savings of AKW1
This suggests that the appropriate way to compare the alternative cycles
listed in Table 3. 6 is at equal incremental running rates. This is done in the following
way.
1 . A base unit is arbitrarily chosen (in this example we chose #1 from
Table 3. 6 — a 2400 psi, 1000/1000° F, TC4F-26) and is run so as
to meet the projected load duration curves of Tables 2. 1 and 2. 2.
The incremental running rates for that unit under those loads are
tabulated.
2. One-by-one, each of the alternatives is run for the same time
periods at the same incremental running rates. This will result
in different total outputs.
3. The final fuel cost is then evaluated two ways:
(i) at the reference capacity factor (Tables 2. 1 and 2. 2)
(ii) at the "evaluated capacity factor" which results from
running the other units at the base IRR.
3.2.2.2 Computation of Base Unit Incremental Running Rates
The load duration curves of Figure 2. 14 and their tabular approximations
(Table 2.1) are given in terms of percent of maximum station send-out. This maxi-
mum send-out will be evaluated at a condenser pressure of 1. 5 in. Hg (the difference
at 1. 0 or 2. 0 in. Hg are slight) and these are tabulated in Figure 3. 6.
56
-------
For the base costs
Max. Send-out = 302, 700 kw
Therefore, 80% = 242,160 kw
60% - 181,620 kw
35% = 105,945 kw
and these send-outs correspond to incremental running rates (Figure 3.5) of
Max. Send-out ~ IRR = 3.310
80%
60%
35%
IRR - 3. 077
IRR = 2.917
IRR - 2.812
These conversions make possible the construction of Incremental Running Rate Dura-
tion curves corresponding to the load duration curves of Figure 2.14 and Table 2.1.
These are shown in Figure 3. 7 and Table 3. 7.
§
+3
oJ
t-i
2
Q
0»
-u
a
P5
bUD
6000
5000
4000
I I 3000
K o
s
2
I
2000
1000
Incremental Running Rate
mills/kwhr
3.31 (or max. sendout)
Figure 3.7
Division of Hours at Various Incremental Running Rates.
Produces 60% Capacity Factor for Case 1, 2400 psi.1000/
1000 F, TC4F-26.
57
-------
Table 3. 7
INCREMENTAL RUNNING RATE DURATION - HOURS
PER YEAR AT VARIOUS INCREMENTAL RUNNING RATES
Incremental
Running
Rates
3.31
3.08
2.92
2.81
0-10
5150
1750
800
700
Years
10 - 20
2200
1850
1700
1500
20 - 30
1100
1250
1850
1700
The evaluation of the alternative units then proceeds by evaluating the
loading and lifetime capacity factors for the other units when run at same incremental
running rates for the same duration.
This computation is performed as follows: Consider unit #4 (3500 psig,
1000/1000/1000° F, TC4F-26). The send-out at each of the incremental running rates
is obtained from Curve #4 on Figure 3. 5. An extrapolation of the curve to an IRR =
3. 31 clearly exceeds the maximum unit capacity, so those hours are credited with
the maximum available send-out although this results in a lower IRR.
Send-out at max. capacity: 299,980 kw
0-10 10-20 20 - 30
2 KW - 299,980kwJ5150^ xlOyrs + 2200 ^ x 10 yrs + 1100 ^Jx 10 yrs |
nid-x. j yr yr yr ]
= 299,980 x 84,500 kw-hr
= 25,350,000 mw-hr
Send-out (at IRR = 3. 077) = 271, 000 kw
0-10 10-20 20 - 30
y""™^'^™'"*^ x^™"^^^™^ .^^^vNwM.
SKW3. 077 = 272>000 J1V50 |^xlO yrs + 1850 ^ x 10 yrs + 1250-^ x 10 yrsl
•/ j f
= 13,400,000 mw-hr
58
-------
Send-out (at IRR = 2. 917) - 223, 000 kw
0-10 10-20 20 - 30
(f - -^ f ~* x v
80o|pxl0yrs + 1700 ^x 10 yrs + 1850^x10 yrs
= 9,120,000 mw-hr
Send-out (at IRR = 2. 812) = 180, 500 kw
0-10 10-20 20 - 30
2KW = 180,500 (?00 — xlOyrs + 1500^x10 yrs + 1700— x 10 yrs
&. OLA ( yr yr yr
= 7,050,000 mw-hr
The total lifetime send-out is obtained by summing each of these
S KW, = S KW + S KWQ „_ + S KW0 nir? + S KW0 010
tot max 3.077 2.917 2.812
= 54,026,460 mw-hr
The average lifetime capacity factor is given by
Cap. Factor =
max
2 KW = 299, 980 x 8760 -- x 30 yrs
iricLX y^
= 78,500,000 mw-hr
Cao Factor - 54>026^460
Cap. factor 78>5oo,000
= 68.53
These results, as well as those for all of the other alternatives are tabulated in
Table 3.8.
59
-------
os
o
Table 3.8
EVALUATED CAPACITY FACTORS FOR ALTERNATE UNIT DESIGNS
Alternate
Number
Steam
U\Jn.Ul^ J-.
Conditions
(Incremental Running Rate,
mills /kwhr)
1
2
3
4
5
6
7
8
9
2400
2400
3500
3500
3500
3500
3500
3500
3500
PSig,
psig,
PSig,
psig,
psig,
psig,
psig,
psig,
psig,
1000/1000 F
1050/1000 F
1000/1000 F
1000/1000/1000 F
1000/1025/1050 F
1000/1000 F
1000/1000 F
1000/1000 F
1000/1000 F
' rxj. Ji/v^u^jj
Turbine
Type
(See Note
Below)
TC4F-26
TC4F-26
TC4F-26
TC4F-26
TC4F-26
TC4F-29
CC4F-29
CC2F-38
CC2F-43
ll>»^XVliilVa.Jlrl\J./ilj rVUlNlNllNVJT XV/iiJliO
Net Station Sendout, kilowatts
At Equal Incremental Running Rates
(3,310)
302,700
302,700
299,330
299,980
299,980
302,330
302,330
301,330
305,330
(3.077)
242,160
248,000
256,000
272,000
279,000
274, 000
274,000
278,500
298,500
(2.917)
181,620
189,000
200,500
223,000
231,000
216,500
216,500
220,500
248, 000
(2.812)
105,945
121,000
144, 000
180,500
192,000
176,000
176,000
176,000
199,000
No. 3 Unit
Lifetime
Calculated
Generation,
Mwhr
48,228,
49,394,
50,862,
54,026,
55,138,
53,866,
53,866,
54,170,
57,501,
750
100
960
460
740
710
710
130
300
Evaluated
Lifetime
Average
Capacity
Factor,
percent
60.63
62.09
64.66
68.53
69.94
67.80
67.80
68.41
71.66
Note: Incremental running rates correspond to loading of Alternate 1 at 100, 80, 60 and 35 percent of maximum net
station sendout at 1.5 in. Hg abs.
-------
It is now possible to compute the total fuel requirements for each alternative.
For Unit 4 (3500 psig, 1000/1000/1000° F, TC4F-26):
1. From Table 3. 7 we see that the incremental running
rate durations for the fifth year are
5150 hours @ Maximum Send-out
1750 hours @ 3. 08 IRR
800 hours @ 2. 92 IRR
700 hours @ 2.81 IRR
2. From Table 3.8, this corresponds to output of
299. 98 Mwe for 5150 hours
272. 0 Mwe for 1750 hours
223. 0 Mwe for 800 hours
180.5 Mwe for 700 hours
3. If the load duration breakdown of Table 2.2, into
various condenser pressures is assumed to apply,
then the loading can be broken down further as shown
in Table 3.9
Table 3.9
HOURS OF OPERATION PER YEAR AT THE GIVEN OUTPUT
AND CONDENSER PRESSURE FOR THE 3500 PSI, 1000/1000/1000 F;
TC4F-26 UNIT DURING THE FIFTH YEAR
_ ^ ^ ,. Condenser Pressure (in. Hg abs)
Power Output i B '
Mwe 1.0 1.5 2.0
299.98 1545 1545 2060
272.0 700 525 525
223.0 440 240 120
180.5 490 210 0
61
-------
4. From the heat rate tables, the turbine heat rates
are obtained for the various loads and condenser
pressures and the corresponding net plant heat rates
are calculated from Equation 3. 2). The total fuel
cost for the year is then given by
TFC = SFC S (HR x KW x T). (3.3)
where
TFC = total fuel cost for the year ($/yr)
SFC = specific fuel cost ($/Btu)
HR = heat rate at specific kw and condenser
pressure (Btu/kwhr)
KW = power output (kw)
T = time per year at kw output (hours/yr)
The summation is taken for all the values of Table 3. 9.
Numerically for Unit #4, this becomes:
l.OinHg 1.5inHg 2.0inHg
/ _ ^ ^ ^^^^^^^ ^^^^^^***> ^^^^^^^ ^^^^^^
TFC = 0.35x 106^— 4-J299.98X 103 kw 1545 — x 8728— ^j— + 1545x8753+ 2060x88041
-tstu | yr kw-hr
t
+ 272.0 x!03kw 700— x -
+ 223.0 x 103 kw |440
+ 180.5 x 103 kw
- 11
C
= 7.1 x 10 $/yr for the fifth year.
In the next section it will be seen how the present worth of fuel cost for
all the years is calculated.
62
-------
3.2.3 Present Worth Evaluation
Since differing yearly costs are encountered for various power plant design
alternatives, the problem of evaluating the relative importance of each year's costs
arises. It is generally considered by economists that a sum of money to be realized
or spent at some future time has less value than the same sum at present. This is
because of the earning power of money in terms of interest.
The relationship between the value of an amount of money in the future to
an amount at present is expressed by "present worth" equations. In this section,
interest compounded on an annual basis will be considered. With this interest, the
present worth of a sum of money at some future time is expressed as
PW =
(1 + r)
n
(3.4)
where PW = present worth, dollars
S = sum of money in the future, dollars
r = interest rate per year
n = number of years
Since overall power generating costs are a sum of fixed charges and
operating costs, and these costs are considered on a per power output basis (mill/
kwhr), the required revenue rate for a year may be expressed as
where
Ri
TFC =
O,
KWHR. =
i
R. -
i
C. x I + TFC. + O.
i 11
KWHR
(3.5)
i
required electrical rate for the year i (dollars/kwhr)
fixed charge rate for the year i (%) (Figure 2.16)
total initial investment (dollars) (Table 3. 6)
total fuel cost for the year i (dollars) (Equation 3. 3)
total operating costs (exclusive of fuel) for the year i
(dollars) (if available)
total plant net generation for the year i (kwhr) (as in Equation 3. 3)
63
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Therefore, based on present worth, the combined required electrical rate is written as
. E [Yc. x I + TFC + O. ) /(I + r)1 1
R - 1= HV * i i// ± (3.6)
PW n
2 (KWHR).
i=l l
The present worth of revenue requirements for the nine cases of our ex-
ample have been calculated and are shown in Table 3.10. The load duration data and
fixed charge rates of Sections 2. 6 and 2. 7 were used and a constant fuel cost of 35£/
million Btu was assumed. Operating and maintenance costs (exclusive of fuel) of
300, 000 $/yr were assumed for each unit. The revenue requirements are given in
Table 3.10 for the evaluated capacity factors of Table 3. 8. It is seen that the unit
with the lowest revenue requirement is the 3500 psig, 1000/1000° F CC2F-43 (#9).
Since not all possible combinations of pressure, flow arrangement, reheat tempera-
tures, and blade length were evaluated, this may not represent an absolute minimum.
In fact, examination of Units 3, 4, and 5 suggests that a different reheat temperature,
namely a 3500 psig, 1000/1025/1050° F CC2F-43 would have even lower revenue
requirements.
An alternative method of comparison is to evaluate all of the alternate
units at the base capacity factor (60.63% for the 2400 psig, 1000/1000° F TC4F-26).
This results in essentially the same lifetime send-out for all units and is more
appropriate if system planners feel that any additional capacity would not be usable.
On this basis the most economical unit evaluated was the base unit (2400 psig, 1000/
1000° F TC4F-26). An examination of Units 3 and 6 suggests that a unit with 29 inch
plates would be superior (2400 psig, 1000/1000° F TC4F-29).
64
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Table 3.10
PRESENT WORTH OF REVENUE REQUIREMENTS OF THE
VARIOUS ALTERNATIVES
Unit Revenue Requirements
Mills/kwhr
Alternate
Number
1
2
3
4
5
6
7
8
9
2400
2400
3500
3500
3500
3500
3500
3500
3500
Steam Conditions
psig,
Psig,
Psig,
psig,
psig,
psig,
psig,
psig,
Psig,
1000/1000
1050/1000
1000/1000
F
F
F
1000/1000/1000 F
1000/1025/1050 F
1000/1000
1000/1000
1000/1000
1000/1000
F
F
F
F
Turbine
Type
TC4F-26
TC4F-26
TC4F-26
TC4F-26
TC4F-26
TC4F-29
CC4F-29
CC2F-38
CC2F-43
At
Evaluated
Capacity
Factor
3.
3.
2.
2.
2.
2.
2.
2.
2.
041
006
937
838
810
841
855
824
754
At 60. 63%
Capacity
Factor
3.
3.
3.
3.
3.
3.
3.
3.
3.
041
054
067
085
096
062
074
064
084
3.3
Feedwater Heaters
The optimum number of feedwater heaters and the final feedwater temperature
are considered to be the most important cycle parameters after the initial pressure and
temperature and reheat temperature have been established.
In a regenerative feedwater heating cycle the transfer of heat from extraction
steam to feedwater takes place in feedwater heaters. Feedwater heaters are divided into
two basic categories: 1) open, or contact, heater in which the steam and water mix in
direct contact and 2) closed heaters in which no mixing occurs. Open feedwater heaters
are more effective since there is no available heat loss, but they are also more ex-
pensive since a feedwater pump is required between each heater.
65
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A complete discussion of the basic thermodynamics of the feedwater cycle
is beyond the scope of this report, but Bartlett (Ref. 16a ) contains a good introduction
to the feedwater heating cycle which we have included here for convenience.
"The maximum number of feedwater heaters which can be economically
justified is limited by diminishing performance gains, cost of extra
heaters, turbine design limitations, and turbine-room space limitations.
Usually economic appraisals lead to the following pattern of heater ap-
plication.
20, 000 - 50, 000 kw 4 or 5 heaters
50, 000 - 100, 000 kw 5 or 6 heaters
100, 000 - 200, 000 kw 5, 6, or 7 heaters
Over 200, 000 kw 6, 7, or 8 heaters
In locating heaters in the feedwater heating cycle of a nonreheat unit,
it is desirable to have the feedwater enthalpy rise for each heater as
nearly equal as the design of the turbine will permit. This arrange-
ment not only provides for optimum heater performance but also
facilitates duplication. A complete exposition, justifying the assumption
of equal rises as the basis of optimum heater arrangement, may be found
in Salisbury (Ref. 67a).
For single-reheat cycles the use of essentially equal feedwater enthalpy
rises is desirable for heaters which extract below the reheat point. The
special conditions existing at and above the reheat point require that
heaters extracting in this region receive individual attention.
The heater extracting at the reheat point provides optimum cycle per-
formance when designed with a feedwater enthalpy rise approximately
1. 8 times the average of the lower-pressure heaters.
Double reheat cycles should provide for extraction from both reheat
points and from one intermediate point in between the two reheats. The
heater extracting from the second reheat point and the low-pressure
heaters may be treated in the same manner as the heater extracting at
the reheat point and low-pressure heaters of a single-reheat cycle. The
heater extracting from the high-pressure reheat point should take about
two-thirds and the intermediate heater about one-third of the total feed-
water enthalpy rise above the heater extracting from the second reheat
point.
The ideal of equal feedwater enthalpy rises for the heaters of a non-
reheat cycle and those of reheat cycles extracting below the reheat point
is impossible to attain in actual practice because of the limited number of
stages in the turbine. Deviations from the equal-rise ideal of as much as
10 to 20 percent do not affect the heat rate appreciably.
66
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Besides the reheat points, turbines often have other natural extraction
points at the crossovers. Since extraction steam can often be removed
at these points with little drop in pressure, gains in performance can
sometimes be realized by deliberately adjusting the cycle to take ad-
vantage of them, even though from an equal-rise point of view it may
not be the most desirable arrangement.
The lowest-pressure heater often merits special consideration. The
equal-rise concept often results in extraction steam for this heater of
such great specific volume that it becomes difficult to provide for its
removal from the turbine stage and exhaust hood. An equally important
consideration is the reduction in the feedwater enthalpy rise of the bottom
heater at partial loads, resulting in the heater "cutting out of service".
These factors usually result in the provision for a somewhat larger
feedwater enthalpy rise for this heater than for those above it.
An improvement in heat rate may nearly always be obtained by increasing
the number of feedwater heaters. To obtain maximum benefit from ad-
ditional heaters, however, all the heaters should be rearranged so as to
optimize the heater enthalpy rises as nearly as possible.
Improving the effectiveness of the feedwater heating-cycle components is
usually an economical way of improving over-all performance. Losses
due to high terminal differences, large extraction-line pressure drops,
and multiple cascading of heaters without drain coolers can reach con-
siderable proportions."
There are numerous methods available for estimating the effects of changes
in feedwater heating-cycles components on performance (cf Ref. 16a). In general,
however, the present practice is to prepare, with the use of a computer, numerous
heat balances (such as shown on page 5 of GET-2050B, included in the appendix) with
various numbers and sizes of feedwater heaters. The optimum size and number is then
easily chosen with economic considerations similar to those in the preceding section.
3.4 Condenser System
One of the major components of the power plant is the condenser with its
associated piping, pumps, controls, and instrumentation. As indicated in Table 3. 3,
the cost of the condensing system can account for up to 25% of the turbine-generator
costs. More important, however, is the influence of the condenser on the overall
cycle performance, system efficiency, and, hence, total operating costs. Furthermore,
67
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it is in the condenser where the required heat rejection from the cycle is carried out,
that the interface between the power generating system and the environment occurs.
It is here that the restrictions on peak water temperature and permissible amount of
water consumption are felt on the power generation system.
In order to describe the available options and trade-offs for system optimiza-
tion, it is useful to describe the conventional, single-pressure condenser. More recent
advances will then be discussed with reference to this base system.
3.4.1 The Single-Shell Condenser
The simplest type of condenser concepts of a single shell in which turbine
exhaust steam condensers on the outside of tubes. Cooling water is pumped through
the tubes and discharged at an elevated temperature to accomplish the necessary heat
rejection. Figure 3. 8 gives a simplified sketch of the temperature distributions through
the condenser.
The steam-side operates essentially at constant temperature and pressure
at its saturation condition. The water temperature rise and the condensing temperature
level are set by the load imposed on the condenser and the condenser size. In the nomen-
clature of Figure 3.8, the governing equations are
Water Temperature Rise:
p
Condensing Temperature:
T - T
w2 wl _ Q
( T - T . \ UA
Tw2 " Twl WC (3>7)
T - T .
c wl
where U is the overall heat transfer coefficient. (The following tradeoffs will be
discussed from the point of view of U = constant.)
68
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Inlet Water
wl
Condensing Temperature, T,
Water Flow, W
Total Heat Rejected, Q
Condenser Area, A
Discharge Water
w2
0 A
Figure 3.8
Temperature Distribution in a Single-Pressure Condenser
The condensers are normally sized such that the terminal temperature difference
(T - T 9) is about 5°F. It is possible to build a larger condenser (increase A) to
C Yt £
reduce this temperature difference but a large area increase is required for a slight
additional reduction in T and the choice of 5°F as a design point represents a sensible
c
economic choice.
The obvious alternative is to increase the water flow. For a given heat load
and inlet water temperature, this will reduce the water temperature rise (Equation 3. 7)
and, if the criterion of a 5° F terminal temperature difference is maintained, will reduce
the attainable condensing temperature by a like amount. The benefit of increased water
flow must be weighed against the following factors:
-------
1. Water velocities in the tubes must be kept below 7 ft/sec,
because of tube life considerations. Hence, very high water
flows require a condenser design with a large number of
short tubes which sometimes produces an awkward geometry
with which to interface the turbine.
2. The pumping costs increase with increased water flow.
3. The increased use of water may be inconsistent with
environmental protection.
4. If the condenser utilizes once-through cooling, the above
considerations are probably sufficient. If, however,
the condenser cooling water is supplied by a cooling
tower, the increased flow is reflected in increasingly
severe tower requirements and tower costs.
Since 1965, the use of dual pressure condensers has permitted a lowering of the
effective condensing pressure and temperature with the resulting improvement in heat
rate while using essentially the same cooling water. An examination of Figure 3.8
suggests the solution. It is clear that the low temperature water which is available in
the inlet portion of the condenser is not being utilized efficiently. The condensing
temperature is set with respect to the highest (or exit) cooling water temperature.
Clearly, at least some of the turbine exhaust could be expanded to to a lower tem-
perature and pressure rise closely approaching the coolest (or inlet) water temperature.
This splitting of the steam flow is further facilitated in the larger size turbines which
have multiple exhaust flows anyway.
3.4.2 The Multi-Pressure Condenser
A diagram similar to Figure 3.8 can be drawn for a dual pressure condenser
and is shown as Figure 3.9. The extension to multi-pressure (three or more stages) is
obvious. Structurally, the unit can be thought of as two separate condenser shells, al-
though the actual design is often a single shell with a pressure tight partition separating
the high pressure condensing region (B) from the lower pressure region (A).
70
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T , single stage
wl
Condenser A
cA
Water Flow, w
Condenser B
cB
w2
Temperatures from —
Figure 3.8
Figure 3.9
Temperature Distribution in a Dual Pressure Condenser
71
-------
While part of the steam is expanded to a lower pressure and temperature
(T . < T ), the remainder is discharged at a somewhat higher temperature (TcB > TC>.
The net effort can be to improve the heat rate as illustrated in the following comparison
excerpted from Reference 45.
SINGLE VERSUS MULTIPRESSURE CONDENSING
A representative comparison of single versus multipressure condensing
performance is afforded by the diagram shown in Figures 3.10 and 3.11.
These describe the full capability overpressure performance of the low
pressure end of the heat cycle serving a 500 Mw supercritical unit.
Figure 3,10 presents the details of conventional single pressure con-
densing operation. A turbine back pressure of 2 in. of mercury absolute,
corresponding to a year round average circulating water inlet of 74 F, has
been assigned at each of the two condenser sections. Although not indicated,
condenser water sides are arranged for two pass flow of circulating water,
which is routed in parallel to both condensing sections.
Figure 3.11 assumes the single pass flow of cooling water through each
condenser section. Coolant is routed in series to one, and then the other
section. Full coolant flow through the first tube section, at an inlet tem-
perature equal to the 74 F assumed for the parallel flow case, is seen to
reduce turbine back pressure from 2. 0 to 1. 55 in Hga. Circulating coolant
supply to the second tube bank, although at twice the rate established for
the parallel flow scheme, arrives at the tube sheet at 84 F after per-
forming the condensing duty required at the first condenser shell. Calculated
performance at the second series oriented section, therefore, produces an
exhaust of 2.2, in. Hga, or 0.2 in. above the parallel flow case.
The plant utilizes condensing type auxiliary turbines for main feed pump
drive. For the multipressure condensing arrangement, drive turbine
condensate along with the colder condensate collected at the lower
exhaust pressure shell, are fed into the hotwell of the higher
operating pressure section. By heating these cascaded flows to saturation
72
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FROM I. ft MCTION
1 cooling water in @ 74° F
cooling water out
Figure 3.10
Low Pressure Cycle Performance for 500 Mw Unit Employing Single Pressure Condenser
(Parallel Flow Arrangement) (Ref. 45)
-------
MOM i.p SECTION
Codling Water
= 74° F
Cooling Water Exit
2
Figure 3.11
Low Pressure Cycle Performance for 500 Mw Unit Employing Dual-Pressure Condenser
(Series Flow Arrangement)(Ref. 45)
-------
at 2.2 in. Hga, heat that would normally be rejected to the circulating
water is recovered. This cycle advantage makes its appearance in the
increased enthalpy of condensate delivered to the first feedwater heater,
where a decreased demand for final extraction stage bleed steam(112,642
Ib/hr in Fig. 3.11 vs. 121,669 Ib/hr in Fig. 3.10) makes an incremental
addition to turbine-generator output.
Overall thermal advantage favoring the multipressure series flow con-
densing arrangement is shown to be a 222 kw increase in turbine gross
capability at cycle heat input identical to the single condensing pressure
case (565, 245 kw vs. 565, 023 kw). For this particular illustration, the
multipressure condensing design must be assigned both cycle efficiency
and unit capability credits over the competing design.
It is of significant importance to reveal that the unit chosen to illustrate
series versus parallel flow condensing performance was one that had been
previously optimized for single exhaust pressure, parallel flow operation.
No attempt was made, in the case of the dual pressure condenser arrange-
ment, to individually proportion tube dimensions and heat transfer surface
at each condensing section to best meet expected dual pressure operating
conditions. Despite differences in volumetric flow loadings produced by
unequal condensing pressures, exhaust blade length studies were not
undertaken to determine if a change in last stage blading in either turbine
exhaust might improve the economics of multipressure condensing.
Finally, variations in circulating water flow, which in some applications
might significantly affect coolant system investment costs and water
pumping power requirements were not considered. Coolant flow, as
optimized for the parallel flow arrangement, was assumed equal in each
case.
Because the coolant temperature approaches the higher of the two con-
densing temperatures in the dual pressure system rather than an average
condensing steam temperature, multipressure condensing offers the
possibility of reducing coolant flow, while maintaining the thermal per-
formance of the single-pressure condenser plants. Where site or plant
75
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characteristics place a premium cost on coolant flow quantity, this ad-
vantage can be of decisive importance. Cooling tower installations are
a case in point. Increased coolant temperature rise, at reduced coolant
flow rate through the main condensers increases tower range and reduces
tower flow loading. Both factors will contribute to a reduction in cooling
tower first cost.
3.4.3 Condenser Costs
While a detailed review of condenser cost trade-offs is beyond the scope
of this section, the approximations used to compute these costs in the optimization
program developed under another task in this study (Ref. 14a) are presented here for
convenience of reference. Nearly all power plant condensers are of the shell-and-
tube type and their cost is nearly proportional to the amount of heat transfer surface.
A curve-fit approximation to the information continued in References 137, 138, and
139 is given by:
CONCST = 20 (1. 05 x ACOND)0' 9 (3. 9)
where CONCST ~ condenser cost (dollars)
2
ACOND "•' heat transfer surface area (ft )
For dual pressure condensers, the capital cost of the condenser itself may still be
approximated by this relationship. However, the real savings in using a dual pressure
unit come from the improved heat rates attainable with these units. The computation
of the available increases in cycle efficiency are quite complex (see, for example, the
discussion of the third paragraph under "SINGLE VERSUS MULTI-PRESSURE CON-
DENSING") and cannot be included here. If the appropriate heat rate curves are
available, they are used in place of Figures 3. 3 through 3.6, for the computation of
fuel costs (Sections 3.2.2 and 3.2.3).
3.5 Operational Considerations
"Operational considerations" in power plant design could be interpreted to
mean almost all portions of the design. La this section operational considerations are
meant to mean those portions of the design of a power plant that directly affect the
facility of operation and control of the plant after it has gone "on line. " Instrumentation
76
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and control, plant maintenance, and plant layout are the main areas of operational
design that are discussed.
3-5.1 Instrumentation and Control
Because of the many different types and complexity of the controls used
in today's power plants, a complete description would fill numerous volumes. There-
fore a rather simple approach is necessary here with the details left to the references.
(References 18, 19, 21, 22, and 26 are recommended as an entrance to the field.)
During the 1950's change from pneumatic control to electric control in
power plants began on a large scale. In the early stages of this transition, many of
the systems built were combination pneumatic and electric and are still in use today.
Most power companies today use electronic computing and data logging
systems, but many companies have developed the policy of "wait and see" with regard
to the present use of computers for full control of operation of large units. This is
thought to be due to two factors:
1. Computer equipment is very costly.
2. Early computer controlled units have not
functioned satisfactorily.
The large number of interpret and control functions necessary in a power
plant is the main reason that automatic control is desired, while the type and amount
of sensing required has been a drawback. There has been considerable difficulty in
purchasing sensing devices sufficiently reliable to give proper signals to the electronic
equipment. Proponents of computer control claim that this disadvantage will be over-
come as manufacturers gain operating experience with plants in operation. Further
automation of control in power plants will most probably occur in the future, but the
rate of change does not seem to be large at present.
77
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3.5.2 Power Plant Layout
The design of the layout of a power plant occurs in parallel with the
theoretical analysis of performance, and is the most practical side of the overall
design. Layout design is essentially a trial and error process incorporating both
logic and past experience and, as such, it constitutes a substantial part of the en-
gineering cost of the whole project. The peak of layout design does not coincide with
the peaks of analytical design and detailed plant design, as will be seen, yet the analy-
sis, layout, and details must be in final agreement. This represents the major diffi-
culty in layout design.
To understand where layout design fits into the overall design picture, the
overall design may be considered to occur in six phases (Ref. 117), with the major
decisions on the plant layout being made in only one of the phases. This general
description is equally applicable to both fossil and nuclear plants. The phases con-
sidered are:
1. Initial Description — Economic and political decisions as
to type of reactor, site, etc.
2. Engineering Performance Study — Approximate power and
safety calculations to determine reactor size necessary.
3. Economic Project Evaluation — Decision whether to design
and build is made.
4. Project Design — Engineering study for specific site and
reactor size. Main stage of decision on layout and dimen-
sions of major components. Civil construction begins at
end of phase.
5. Plant Design -- Plant design proceeds by manufacturing
specialists. Main stage of engineering analysis.
6. Detail Design — Detail plant component design drawings
by manufacturers. Detailed layout drawings completed.
Differences between final detailed layout and the layout
form of phase 4 are adjusted.
78
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Although it is possible for layout design to continue through phases 5 and
6, the pressure to start construction early usually requires that the bulk of the lay-
out work be completed in phase 4.
The objectives in plant layout design are to evaluate the proper trade-offs
between the use of minimum space and the provision of easy access to critical com-
ponents. In both fossil and nuclear plants, the major problems are concerned with
the logistics of fuel. In a fossil plant, particularly a coal-fired plant, the sheer bulk
of the fuel which must be transported to and stored at the plants present serious
problems in access route and switchyard layout. Similarly, an enormous amount of
ash must be removed from the furnaces, cooled, and ultimately disposed of. Finally,
the flue gas stacks themselves must be considered and located in such a way that they
do not interfere with plant operation (particularly in the case of cooling towers and
transmission lines).
In the case of nuclear plants, fuel handling is a problem, not because of
the bulk but because of the potential hazards. Once inside the reactor containment
vessel, the hazard is virtually eliminated but during transport of the fuel elements
to the plant and during removal of spent cores the access routes and handling equip-
ment and techniques must be laid out with extreme caution. Since shielding must be
provided throughout these routes, their cost per unit length is extremely high and
plant layout must shorten them whenever possible.
Other than the above considerations, the layout of plant buildings depends
as much on local geography as it does on the internal layout of each building. Layout
of the reactor itself can be said to be determined by (Ref. 117):
shape and size of core and containment;
coolant circulation and steam generation system;
shielding;
fuel-handling and core-control systems;
site layout and foundation conditions;
method of erection of heavy parts;
79
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One of the most important maintenance projects in power generation
/
is the major overhauls of the equipment during outage periods. Usually the most
costly item is the downtime of the equipment itself. This cost is evaluated on the
basis of the incremental cost of power generation with the equipment being used
for replacement during the outage. The replacement of a 500 Mwe plant (equivalent
heat rate of 9000 ) with an older out of date plant having twice the heat rate would
cost $18,000 per day (fuel at 20£/m Btu). This is over and above the actual cost
of the maintenance work.
The large replacement cost of generating capacity justifies using many
men during a unit outage, yet, comparatively few men are needed for normal main-
tenance. Thus, it can be very advantageous for large power company groups to use
revolving work crews. Otherwise men unfamiliar with an operation must be used
during a period in which time is very expensive.
The cost of operation and maintenance, while small compared to
capital cost and fuel cost, is not negligible in the economics of a power plant. How-
ever, because of wide variations in labor costs, utility policies, plant designs, and
other variables, they are nearly impossible to generalize quantitatively. A reason-
able rule-of-thumb is that O&M costs are of the order of 5 to 15% of total generating
costs, with 5-10% perhaps more appropriate for fossil-fired plants while 10-15%
is required for nuclear plants. It appears that the increased costs for nuclear
plants are related to the more serious safety requirements and the generally higher
wage-scales for nuclear plant personnel who tend to be more technically specialized.
Table 3.11 presents some comparative cost breakdowns from the
Oyster Creek plant which might be considered typical, although in no sense defini-
tive for a given installation.
80
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Table 3.11
COMPARISON OF POWER-GENERATING COSTS FOR NUCLEAR
AND FOSSIL-FUEL PLANTS (from Ref. 115*)
Fossil-fuel Plant Nuclear Plant
(mills/kwhr) (mills/kwhr)
Capital Cost 1.57 2.04
Fuel Cost 2.35 1.66
Operating and Maintenace 0.42 p. 55
Total 4.34 4.25
*From report on Oyster Creek Nuclear Electric Generating Station 515 Mwe Plant;
Annual Costs for years 1 to 5.
Projected revenue requirements for the Oyster Creek Nuclear Station over
the plant lifetime shows some minor changes in this cost distribution with the O&M
percentage increasing as the plant ages.
Table 3.12
PROJECTED REVENUE REQUIREMENTS FOR
OYSTER CREEK NUCLEAR STATION
(from Ref. 119)
(figures in mills/kwhr)
Years of Operation
Plant Fixed Charges
Working Capital
Fuel Cycle
O&M
Total
0-5
1.67
0.20
1.64
0.51
4.02
6-10
1.57
0.35
1.28
0.51
3.71
11-15
1.46
0.39
1.23
0.51
3.59
16-20
1.45
0.42
1.23
0.54
3.64
21-25
1.66
0.48
1.23
0.67
4.04
26-30
1.84
0.54
1.23
0.80
4.41
81
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Section 4
SUMMARY AND CONCLUSIONS
Summary of Results
The central question which this total study hopes to deal with is how the ad-
ditional design requirement of cooling water use restrictions will affect the technical
and economic aspects of power generation. In order to find a real "optimum" solution
to this question it is necessary to consider both the technology and cost of the heat
rejection equipment, and to consider the design and optimization of the power plant
itself. The basic premise, as illustrated in Figure 1.1, is that a plant which is op-
timized from the outset on the basis of some water use restrictions will be more
efficient (or less costly) than a plant, originally designed in the absence of water use
considerations, and then retro-fitted with cooling equipment to meet the requirements.
The actual performance of this total optimization requires cost and performance
information not only for the cooling equipment which was made available in the Task I
Report (Ref. 136), but also for the power plant. This report has attempted to present
not only the necessary cost/performance information required for power plant op-
timization, but also the computational techniques which are presently used by power
plant designers to arrive at what they consider to be the most economic solution.
Within this framework two considerations are paramount. First, there are
a number of considerations which can dominate the total design process in terms of
plant selection and which are very difficult to quantify. These considerations are
reviewed in Section 2 in a qualitative discussion. They include plant size, type of
thermodynamic cycle, fuel, site location, and future system demands. In the optimiz-
ation program, which will be developed and presented in a later report, the determination
of each of these considerations will be left as an input specification. That is, the plant
size, cycle choice (heat rate vs. operating point), fuel choice, site data, and anticipated
load factors will be taken as given and will not be part of the optimizable parameters.
Second, there are aspects of the cost-performance information which, although
legitimately part of the optimization process, are not includable for the following reasons:
82
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1. A detailed optimization of an operating power plant is an
enormous task. As discussed in Section 3, it is done through
the computation of extremely detailed heat balances where
differences of a fraction of a percent are considered definitive.
Clearly, computations of this size and precision cannot be
generalized within the scope of this study and perhpas cannot
be generalized at all.
2. A counter-consideration, however, is that while it is true that
a detailed optimization is not possible, it is also probably not
necessary in order to obtain the result which we seek. That is,
we are interested only in the parametric variation which would
be affected by water use restrictions and choice of heat rejection
equipment. As a first approximation, although this is not
necessarily true in any specific installation, it may be assumed
that the major power plant design decision which will be affected
is the choice of the turbine-generator and condenser components.
Therefore, Section 3 has focussed on the cost performance information
for turbine-generators and on the economic computations which must be used to
select the optimum turbine-generator unit for a given set of design conditions. The
other aspects of the plant design and plant economics have been reviewed in as much
detail as was available but have not been quantified for use in the optimization program.
83
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BIBLIOGRAPHY
Types of Equipment and System Descriptions
1. Britian's First Power from Supercritical Steam Engineering
v201 n 5209 February 18, 1966 p.343-50
2. Directory Containing Information About All Electrical Stations in the
U.S.A., Electrical World, 77th Edition
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Nuclear Design
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94
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1
Accession Number
w
5
ty Subject Field & Group
05G
SELECTED WATER RESOURCES ABSTRACTS
INPUT TRANSACTION FORM
17 Tudor Street, Cambridge, Massachusetts 02139
Title,
'itlo -
A Survey of Alternate Methods for Cooling Condenser Discharge Water-
Operating Characteristics and Design Criteria
in \Aathoi(s)
IU| Ware D.
John S .
Fuller
Maulbetsch
16
21
Project Designation
16130 DHS
08/70
Note
22
Citation
Environmental Protection Agency, Water Pollution Control Research Series
16130 DHS 08/70, pp. 94, August 1970, 30 fig., 15 tab., 139 ref.
23
Descriptors (Starred First)
Electric Power Production*, thermal power plants*, nuclear power plants*,
heated water, fuels, operating costs, maintenance cost, heat exchangers,
temperature
25
Identifiers (Starred First)
Boiler plant, steam turbines, steam condensers, fixed charge rate
27
Abstract
This report is part of a larger study to perform a technical and economic survey
of alternate methods for cooling condenser discharge water from thermal power
plants. The task reported on in this document investigates the criteria by
which the power plants themselves are designed and optimized. These criteria
are both technological and economic.
The initial section reviews the general aspects of power plant selection.
These include questions such as how the procedure of procuring a new plant is
initiated, how the plant size is determined, what factors influence the choice
of fuel and site location, and how the plant capacity factor and fixed charge
rate are calculated.
There follows a detailed review of design and cost optimization procedures. This
includes a review of capital costs for the turbine-generator units and for the
boilers. Operating costs are computed based on constant incremental running
rates. A worked example is presented and carried to the point of a "present
worth" evaluation. A brief discussion of the use of feed-water heaters, single-
and multi-pressure condensers is provided. Some operational considerations
including instrumentation and control and plant layout are discussed briefly.
A separately bound Appendix includes a Heat Rate Table for General Electric
turbines, and Westinghouse and General Electric price lists for both conven-
tional and nuclear turbine-generator units.
Abstractor
M IK .SCh
Institution
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_f.nTnpany ,
17
Tnrinr
St.
namhridpe ,
Mass.
_Q2ias
WR:I02 (REV. J U 1_ Y 19691
WRSI C
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WASHINGTON. D. C. Z0240
GPO: 1970 - 407 -891
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