&EPA
United States Industrial Environmental Research EPA-600/7-78-152
Environmental Protection Laboratory July 1978
Agency Research Triangle Park NC 27711
Optimization
of Design
Specifications for
Large Dry Cooling
Systems
Interagency
Energy/Environment
R&D Program Report
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EPA-600/7-78-152
July 1978
Optimization of Design Specifications
for Large Dry Cooling Systems
by
Tzvi Rozenman, James M. Fake, and Joseph M. Pundyk
PFR Engineering Systems, Inc.
4676 Admiralty Way, Suite 832
Marina del Rey, California 90291
Contract No. 68-03-2215
Program Element No. EHE624A
EPA Project Officer: Theodore G. Brna
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
This report describes the methodology and the results of a study
to optimize the design specifications of dry cooling systems for fossil
power plants of the 1000 MWe size. The entire cooling system from the
turbine flange outward, i.e., condenser, dry tower modules and recircu-
lating system, is designed employing a random combination of design
variables. The optimization consists of a search for the combination
of design variables which will result in the lowest incremental cost
of generating electricity in the plant. For each combination of var-
iables, the total annual capital and operating costs are determined.
The capital cost is evaluated in detail taking into account all stages
from procurement to complete erection and installation. The operating
cost includes the equivalent capital and energy cost for auxiliaries,
penalties associated with loss of capacity at high air ambient temper-
atures, and various aspects of cooling system operating and maintenance
costs. The cost base used is January 1976.
The search for the optimum combination of variables employs a multi-
component, non-linear, constrained optimization technique. Rigorous heat
transfer equations were used to evaluate the performance of the condenser
and the dry cooling modules at different site ambient temperatures.
All the thermal and mechanical design variables of the components
of the cooling system were analyzed. These include design.ambient air
temperature, condenser TTD (terminal temperature difference), cooling
range, and ITD (initial temperature difference). An important part of
the study consists of analyzing the effect of the dry tower module de-
sign specification on the annual cost of the cooling system. The tower
module design was not fixed but varied in the optimization procedure.
The module variables were tube length, number of rows, pass arrangement
and fan motor power. The tube employed for the tower was the overlapped,
wound finned-tube of 1 in. in base diameter having 10 fins/in.
The analysis was carried out for conceptual power plants located in
5 different sites in the continental U.S. Two turbine types, combined
with either surface condenser or jet condenser, were studied. Economic
factors such as fuel costs, capacity factors, and energy and capacity
charges were used as parameters in the evaluation.
The results of the study are presented in this report in both
graphical and tabular form. The results indicate that the cost of
dry cooling systems is affected by all the design variables and that
simplified assumptions may lead to erroneous conclusions.
11
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CONTENTS
Abstract ii
Figures vi
Tables viii
Acknowledgment x
1. Introduction 1
2. Summary 4
3. Conclusions 5
4. Interaction and Rating of Plant Components 6
4.1 System Thermal Interaction 6
4.2 Turbine Selection 10
4.3 Condenser Selection 11
4.3.1 Jet Condenser 11
4.3.2 Surface Condenser 12
4.4 Mechanical Draft Dry Tower 13
4.4.1 Tube Length 13
4.4.2 Number of Rows 15
4.4.3 Number of Tube Passes 15
4.4.4 Fan Power 17
4.4.5 Dry Tower Design and Rating 17
4.4.6 Combined System Performance 19
4.5 Dry Tower Piping System 20
4.5.1 Distribution System 20
4.6 Piping Pressure Drop 21
4.6.1 Surface Condenser Pumping Head 21
m
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CONTENTS (cont'd.)
4.6.2 Direct Contact Condenser Pumping Head 21
4.7 Dry Cooling Tower Structure 26
5. Economic Model and Optimization 27
5.1 General Approach 27
5.2 Cost Analysis 29
5.2.1 Cooling System Capital Cost 30
5.2.2 Cooling System Penalties and Operating Costs 31
5.3 Optimization Methodology 33
6. Results and Discussion 48
6.1 Computer Output 48
6.2 Effect of Site on Cost of Dry Cooling 53
6.3 Effect of Turbine Type 53
6.4 Effect of Condenser Type 54
6.5 Effect of Economic Factors 56
6.6 Effect of Tube Configuration 56
6.7 Effect of Tube Length 57
6.8 Effect of Summer Hours 58
6.9 Effect of ITD 60
6.10 Effect of Range 60
References 87
Appendices
A. Curves showing the heat rate and heat rejected vs.
back pressure for the turbines used in this study A-l
B. Description of the multicomponent optimization
technique used in this study B-l
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CONTENTS (cont'd.)
C. Flow chart of the dry tower optimization program C-l
D. Ambient temperature profiles for the sites studied
in this work D-l
E. Sample computer output for an optimal system E-l
F. Table of SI conversions F-l
G. Heat transfer and pressure drop calculations G-l
H. Program input H-l
I. Program listing 1-1
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FIGURES
Number Page
4.1 Schematic diagram of a dry cooling system 7
4.2 The relations hop between temperatures in the
cooling system components 9
4.3 Surface condenser design procedure 14
4.4 Four-row, round fin staggered module arrangement 16
4.5 Four-row, two-pass heat exchanger arrangement 16
4.6 Water distribution system 22
4.7 Schematic of return piping type 1 and supply piping
type 3 23
4.8 Schematic of return piping type 2 and supply piping
type 4 23
4.9 Schematic of return piping type 3 and supply piping
type 1 24
4.10 Schematic of return piping type 4 and supply piping
type 2 24
5.1 Fan control curve 34
5.2 Total annual cost for a nominal 1000 MWe fossil -
fueled plant at Casper, WY 37
5.3 Total annual cost for a nominal 1000 MWe fossil-
fueled plant at Atlanta, GA 33
5.4 Total annual cost for a nominal 1000 MWe fossil-
fueled plant at Phoenix, AZ 39
5.5 Total annual cost for a nominal 1000 MWe fossil -
fueled plant at Phoenix, with ITD fixed at 60°F 40
5.6 Total annual cost for a nominal 1000 MWe fossil-
fueled plant at Phoenix, with ITD fixed at 30°F 41
5.7 Cost for a nominal 1000 MWe fossil-fuel plant at
Phoenix, at $100/KWe: 6-row, 2-pass tube config-
uration 43
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FIGURES (cont'd.)
Number Page
5.3 Cost for a nominal 1000 MWe fossil-fuel plant at
Phoenix, at $500/KWe: 6-row, 2~pass tube config-
uration 44
5.9 Cost for a nominal 1000 MWe fossil-fuel plant at
Phoenix, at $100/KWe: 4-row, 2-pass tube config-
uration 45
5.10 Cost for a nominal 1000 MWe fossil-fueled plant
at Phoenix, for varying tube length and ITD 46
5.11 Cost for a nominal 1000 MWe fossil-fueled plant
at Phoenix, for varying tube length and fixed ITD 47
6.1 Total annual cost for various fuel cost and tur-
bine type - Casper 55
6.2 Total annual cost for various ITDs - Phoenix 61
6.3 Total annual cost for various ITDs - Casper 62
6.4 Total annual cost for various ranges - Phoenix 63
6.4 Total annual cost for various ranges - Casper 64
A.I Gross plant heat rate with a conventional turbine
in fossil fuel units A-2
A.2 Gross plant heat rate with a modified conventional
turbine in fossil fuel units A-3
A.3 Gross plant heat rate with a high back pressure
turbine in fossil fuel units A-4
A.4 Net heat rejected for modified conventional tur-
bines in fossil fuel units A-5
A.5 Net heat rejected for high back pressure turbines
in fossil fuel units A-6
C.I Flow chart of cooling system optimization C-2
D.I Temperature duration curves for Casper and Phoenix D-2
D.2 Temperature duration curves for Atlanta, Burling-
ton, and Bismarck D-3
VI 1
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TABLES
Number Page
4-1 Representative cooling system head losses 25
6-1 Cost summary of mechanical draft dry cooling
tower system 49
6-2 Tower parameter summary 50
6-3 Cost factor breakdown in millions of dollars 52
6-4 Effect of site on total annual cost 66
6-5 Effect of turbine type - Casper and Phoenix 67
6-6 Effect of turbine type - Casper 68
6-7 Effect of condenser type - Casper 69
6-8 Effect of fixed charge rate, capacity penalty,
and energy penalty for fuel cost of $.75/MMBTU 70
6-9 Effect of fixed charge rate, capacity penalty,
and energy penalty for fuel cost of $1.50/MMBTU 71
6-10 Effect of tube configuration - Casper 72
6-11 Effect of tube configuration - Phoenix 73
6-12 Effect of tube configuration - comparison at
Casper and Phoenix 74
6-13 Effect of tube length - Casper 75
6-14 Effect of tube length - Phoenix with modified
conventional turbine 76
6-15 Effect of tube length - Phoenix with high back
pressure turbine 77
6-16 Effect of changing number of summer hours not
exceeded - Casper 73
6-17 Effect of changing number of summer hours not
exceeded - Phoenix with modified conventional
turbine 79
vm
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TABLES (cont'd.)
Number Page
6-18 Effect of changing number of summer hours not
exceeded - Phoenix with high back pressure turbine 80
6-19 Effect of ITDs of 30-45°F - Casper 81
6-20 Effect of ITDs of 50-70°F - Casper 82
6-21 Effect of ITDs of 30-40°F - Phoenix 83
6-22 Effect of ITDs of 45-60°F - Phoenix 84
6-23 Effect of range - Phoenix 85
6-24 Effect of range - Casper 86
E-l Input for 1000 MWe modified conventional steam
turbine E-2
E-2 Sample computer output of surface condenser
design E-3
E-3 Sample computer output of dry tower tube bundle
design E-4
E-4 Sample computer output of dry tower piping cost
summary E-5
E-5 Sample computer output of optimum dry tower
design E-6
E-6 Computer output of summary of final dry tower
designs for a sample case E-7
F-l SI conversions for terms in British units F-2
IX
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ACKNOWLEDGMENT
PFR Engineering Systems, Inc., wishes to acknowledge the contributions
and assistance of Mr. James P. Chasse, formerly of the USEPA Thermal
Pollution Branch, Corvallis, OR, and Dr. Theodore G, Brna of USEPA1s
Industrial Environmental Research Laboratory at Research Triangle Park,
NC, to the development and completion of this report.
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SECTION 1
INTRODUCTION
The restrictions on the use of water resources for power plant
cooling in the United States have generated wide interest in dry cooling
towers. This has served as an impetus, both in government agencies and
private industry, for the development of performance and economic data
on these systems. The unique features and the economic characteristics
of dry towers have been well documented in the literature (1-5).
The major operating characteristic of dry cooling systems is their
sensitivity to the fluctuation of the ambient temperatures. This sen-
sitivity creates special problems of loss in generating capacity at high
ambient temperatures and freezing hazards at low temperatures. The out-
standing economic feature is their high capital cost - an order of mag-
nitude higher than evaporative towers. In addition, dry towers possess
unique maintenance and logistic problems which arise from their overall
size and multiplicity of units; i.e., modules, fans, piping, structural
elements, etc.
Dry towers also introduced a new degree of complexity into the
methodology of cooling system optimization. The high price of both the
capital investment and the penalties due to loss of generating capacity
requires careful consideration of all the interactions among the design
variables. The a priori selection of some variables, such as design
air temperature or fan size, might restrict the optimal solution and
lead to a costlier design. An optimal design is defined as the right
combination of system operating and design variables which will result
in the lowest cost of producing electricity. This combination may in-
clude subsystems, such as finned tube modules or piping, that may not
be optimal according to some limited thermodynamic criteria but one
which will evolve in the design producing the final lowest unit energy
cost. This can be recognized from the fact that dry towers include
large numbers of modules requiring a large space. Considerations of
structure, piping, distribution system, maintenance, manufacturing and
erection techniques will produce cost factors which can be evaluated
only in the context of the overall capital and operating costs.
The "heart"of the dry tower system is the set of modules of finned
tubes supported by a suitable structure with large diameter axial fans
inducing air flow across the tubes. Finned tubes come in different
shapes, forms and sizes, differing also in their metallurgy and manufac-
turing methods (6). These differences produce unique heat transfer and
flow resistance characteristics. Modules are constructed by assembly
of the tubes into a supporting structure with proper manifolding and
headers for the inlet and outlet piping connection. The manufacturing
and assembly techniques and the thermal and flow characteristics of the
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module have a dominant role in the total cost of the cooling system,
and are therefore appropriately mentioned in the introductory comments.
Most existing commercial dry towers have finned tubes which are also
extensively used for air coolers in the petrochemical industry. Much
knowledge of dry tower technology is founded in the petrochemical in-
dustry's air cooler experience.
The strong interaction that exists among plant components in the
operation and performance of the power plant dry tower requires imme-
diate understanding. The work performed by the turbine is dependent
upon the efficiency of the cooling system, which in turn depends upon
the difference in temperature between the saturated steam at the tur-
bine exhaust and the ambient air. A rise in dry bulb temperature re-
sults in a corresponding rise in turbine back-pressure and lower tur-
bine output. This decrease is also accompanied by an increase in the
amount of heat that must be absorbed in the tower. Thus, a change in
ambient dry bulb air temperature changes the plant operation to a new
point where the total heat rejected from the turbine again equals that
absorbed by the ambient air flowing in the tower.
These variations in plant operating conditions are dependent on
turbine operating conditions and the thermal performance of the cooling
system. For a 1000 MWe modified conventional steam turbine operating
at 14.5 in. Hg absolute back pressure (see Appendix F for conversions
to SI units. British units are used throughout this report since most
dry cooling tower literature employs British units), a 1.5°F increase
in steam temperature at the condenser corresponds to a 3.4 MWe decrease
in turbine output. Thus the performance of the cooling system compo-
nents must be accurately evaluated in order to correctly represent the
performance of the turbine.
An objective of this project is to evaluate the system components
on the basis of heat transfer and fluid flow relationships that accu-
rately represent plant performance instead of using approximate over-
all empirical formulas. The performance of the cooling system (sur-
face condenser, piping, and dry tower modules) is a function of the
design variables. These variables include pumping and fan power, water
flow rate and tube velocity, tube diameter and length, number of tube
rows and tube pass arrangement. The major objective of this work is to
study the effect of the above design variables on the performance and
the cost of dry towers.
The cost of the dry tower is very much a function of its design.
The capital cost is a function of specific module design, number of
modules, and construction, assembly and piping cost. The operating
costs are strongly dependent on fan and pumping power and the operation
of the turbine which is in turn dependent on the design variables. The
study of the effect of design variables on total cost of employing dry
towers cannot be accomplished without accurate and detailed analysis of
all the components of the system. It was thus also within the scope of
this project to develop cost analyses of dry towers which would include
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a detailed cost breakdown of all stages of procuring and constructing
the dry tower. This approach differs from previous works in which
standard designs with standard generalized cost functions were em-
ployed.
The search for the lowest cost dry tower within the wide range
of design variables and cost factors requires an advanced "search"
scheme. An optimization procedure was developed which searches for
an optimum bounded by nonlinear constraints. This multivariable
scheme selects the combination of design variables which leads to
the lowest cost of owning and operating a dry tower in a power plant.
The effect of the design and cost variables on overall cost are
studied through a sensitivity analysis.
The objectives and scope of this work are summarized as follows:
1. Application of a general methodology for multivariable op-
timization
2. Application of accurate rating methods for cooling system
components
3. Application of accurate and detailed cost analyses for the
cooling system
4. Study of the effect of dry tower design variables on the
total evaluated cost of dry towers
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SECTION 2
SUMMARY
This report presents the results of an extensive computer analysis
of the design and cost variables of a dry cooling system for 1000 MWe
fossil fuel power plants. A computer program was developed which designs
and cost estimates the dry tower components and searches for the optimal
system (defined as: system with lowest total annual cost).
The dry tower system evaluated is of the indirect type in which cool-
ing water is circulated between the condenser and air-cooled modules. Both
surface condensers and direct jet condensers are being considered in this
study as well as the selection of either the "high back pressure" turbine
or the "modified conventional" turbine. The design methodology of the dry
cooled system components does not restrict the components to preset fixed
designs, but rather varies the mechanical configuration in a search for an
optimal design. Condenser variables such as tube length and diameter, tube
velocity and number of shells are evaluated together with circulating sys^
tern flow conditions, piping design, dry tower modules, tube length, number
of rows and passes, and fan power. Such design considerations require a
multidimensional non-linear search technique which is incorporated in the
program. For any intermediate design, the performance of the dry cooling
system is evaluated for the ambient temperature fluctuation and load vari-
ation at the site. This is carried out with the aid of rigorous methods
based on the principles of fluid flow and heat transfer that predict the
performance more accurately than any approximate or simplified methods.
Such rigorous methods are required to predict accurately the variation of
plant output with the fluctuation in ambient temperatures.
The economic cost analysis is based on a constant demand of electricity
according to the load duration specified, and on the average plant capa-
city factor. When the demand cannot be met due to deteriorated performance
at high ambient temperatures, it is assumed that the supplemental power will
come from either peaking gas turbines or built-in expended plant capacity.
In both alternatives the extra capacity and energy penalties are added
to the capital cost of the cooling system. Other penalty costs include the
cost of the incremental steam supply system and fuel cost for the turbines
as compared with a "standard" low pressure turbine that provides design
capacity at 2.5 in. Hg absolute.
The dry tower designs were evaluated for 5 sites and assumed January
1976 construction start-up. Basic economic factors were parametrically
varied and the results are illustrated in tabular and graphical forms.
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SECTION 3
CONCLUSIONS
1. The annual cost of a dry cooling system for power plants is
dependent on all the operational and design variables of the
cooling system. A search for an optimal design would be best
carried out by investigating the combination of all variables
which will lead to lowest annual cost. The methodology util-
ized in this work removes many of the uncertainties associated
with simplified approximate methods.
2. The computer analysis has shown that there exist several com-
binations of system variables which will result in lowest an-
nual cost of cooling systems. The availability of several
unique optimal systems can provide leeway for configuration
of design preferences. However, deviation of one or more
variables from the values of the optimal combinations may
result in higher cost.
3. Ambient site temperature fluctuations are of great significance
to tower design, and therefore cost. Both the maximum temperature
of the site and the annual temperature duration curve contribute
to the effect on design and cost.
4. Fuel cost has an important effect on the total annual cost and the
design variables. The difference in dry tower cost for a "high back
pressure" turbine and a "modified conventional" turbine used at the
same site is primarily a function of fuel cost. As the fuel cost
increased the dry tower combined with the "modified conventional"
turbine became cheaper than a dry tower combined with a "high back
pressure" turbine. This is because the incremental fuel cost of
the high back pressure turbine erodes the advantage of the tower's
lower capital cost and energy penalties. For relatively low fuel
cost and sites with relatively hot climates, the "high back pressure'
turbine design is cheaper.
5. The use of jet condensers results in reduced annual cost of about
$200,000 as compared with a system utilizing surface condensers for
a unit fuel cost of $0.75/MMBTU. The jet condenser requires higher
pumping power, and for higher fuel cost the difference between the
cost of systems with surface condensers becomes negligible as com-
pared with the direct jet condenser system.
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SECTION 4
INTERACTION AND RATING OF PLANT COMPONENTS
The indirect dry cooling system, which is being studied, consists
of the low pressure turbine, a surface or direct contact condenser,
cooling water piping system, and the dry tower. Figure 4.1 shows the
system in a schematic diagram. A description of each element follows
in the succeeding sections.
4.1 System Thermal Interaction
The selection and design of a heat rejection system for a power
plant is a complex process involving many variables. Economic, envi-
ronmental, and engineering considerations among others constitute both
the guidelines and constraints. Even though the final decision on a
system does not evolve from pure analytical considerations, the more
quantified the interactions among the variables, the less ambiguous
and uncertain will be the final decision. This is the basic approach
that PFR is advancing in this project.
Figure 4.1 shows a schematic diagram of a portion of a plant equipped
with a dry cooling tower. Steam from the turbine flows to a condenser,
and the condensate is pumped to feedwater heaters for reheat. The cooling
water absorbs the latent heat from the steam and then is cooled in the
cooling tower. This is the basic cooling water recirculating system that
is considered in this project.
In the closed cooling system utilizing dry towers, the heat from
the condensed steam is rejected to atmospheric air. The plant output
is affected by the interaction of all the system components in this
heat rejection process. The term "interaction" refers here to the effects
that the changes in operating conditions in one component of the system
have on the performance of the other components. This interaction will
essentially determine the power output at each ambient temperature.
The power output is a function of the condenser pressure or steam
saturation temperature. The condenser pressure is determined by the
ability of the condenser to transfer the latent heat of steam to the
cooling water. This is a typical heat transfer process depending on
water flow rate and inlet temperature and size of the condenser.
The water inlet temperature is in turn a function of the tower per-
formance which is determined by tower design and ambient dry bulb temper-
ature.
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L.P. TURBINE
GENERATOR
SURFACE CONDENSER
TO FEEDWATER HEATERS
DRY TOWER
Figure 4.1. Schematic Diagram of a Dry Cooling System.
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The relationship between ambient dry bulb temperature and the sat-
uration steam temperature (as shown in Figure 4.2) can be expressed as:
TS = TORY + TAPP + TRANG + TTD (4-1)
where,
TS = saturation steam temperature.
TORY = the ambient dry bulb temperature,
TAPP = the difference between cold water temperature leaving the
tower and ambient dry bulb temperature, and is a function
of cooling tower performance.
TRANG = the cooling water temperature rise in the condenser which
is identical to the cooling range in the tower.
TTD = the terminal temperature difference in the condenser be-
tween the steam saturation and the exit (cooling water)
temperature.
The ITD (initial temperature difference) in the dry tower is the
difference between the temperature of cooling water leaving the conden-
ser and the ambient dry bulb temperature. It is thus equal to the com-
bination of the range and approach:
ITD = TAPP + TRANG (4-2)
Equation (4-2) expresses only the characteristic of the cooling
tower and is insufficient in describing the system. The complementing
equation is derived from the turbine heat rate - back pressure perfor-
mance curve provided by the turbine manufacturer. This varies with the
type and design of the turbine and can be generally expressed as:
QREJ = function (TS, type of turbine, load) (4-3)
The matching of the heat rejected from the turbine expressed by
Equation (4-3) with the heat absorbed (and rejected to the air) in the
cooling tower will provide the operating point of the plant and thus
the net power output.
The temperature range and approach and the terminal temperature
difference in the condenser are thermal characteristics of the turbine
and cooling system components. These thermal characteristics and the
interactions among them are determined by the design of the components
and are evaluated in the following sections.
8
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CONDENSER
PIPING
DRY TOWER
TS, STEAM
X
TTD
T
i
WATER RANGE, AIR
(
TS = TURBINE EXHAUST TEMPERATURE
TTD = TERMINAL TEMPERATURE DIFFERENCE FOR CONDENSER
ITD = INITIAL TEMPERATURE DIFFERENCE FOR DRY TOWER
TORY = AMBIENT DRY BULB DESIGN TEMPERATURE
Figure 4.2. The Relationship Between Temperatures in the Cooling System Components.
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4.2 Turbine Selection
Two major characteristics of turbines will affect the selection
of a turbine for a specific plant:
1. Heat rate at the design point
2. Shape of the heat rate - back pressure curve
The heat rate at the design point expresses the heat input per
unit power output for the turbine at the design back pressure. This
is the corresponding back pressure at which the turbine will generate
the nominal design power output. This heat rate will affect the total
steam flow through the turbine and the size of the steam supply sys-
tem required for the nominal turbine output. A turbine can be selec-
ted to provide the nominal design power output at any back pressure.
However, since the heat rate at the design point increases with in-
creasing design back pressures, more steam will be required to deliver
the nominal design load. For example, a turbine designed to deliver
1000 MWe at 8 in. Hg absolute back pressure will require approximately
7 percent more steam flow than a turbine delivering its rated 1000 MWe
at 3.5 in. Hg absolute, assuming both turbines have the same inlet con-
ditions and turbine efficiencies.
The fuel cost for delivering identical power would be quite dif-
ferent for these two turbines. Considering a gross heat rate of 8941
BTU/KW-HR for the 3.5 in. Hg absolute conventional turbine, the heat
rate for an 8 in. Hg absolute turbine would be 9576 BTU/KW-HR. Assu-
ming a fuel cost of $1.00/MMBTU, the difference in fuel cost would be
.635 mills/KW-HR. For a 1000 MWe plant operating 6000 hours, the an-
nual cost differential would be $3.81 million in favor of the lower
heat rate operation. This example emphasizes the effect of heat rate
at the design point on operating cost.
The shape of the turbine heat rate versus back pressure curve is
also significant in that it affects both the fuel economy and loss in
generating capacity when the turbine operates at back pressures above
the design back pressure. The shape of this curve will be determined
by the exhaust cross-sectional area, size of last row blades, exhaust
Mach number, and various other factors.
Two turbine designs were selected for this study. The first one
was a modified conventional turbine which was capable of producing
1000 MWe at 3.5 in. Hg absolute exhaust pressure but was allowed to
exhaust as high as 15 in. Hg absolute. The second turbine was a high
back pressure turbine which was capable of producing 1000 MWe at 8 in.
Hg absolute and was also allowed to operate up to 15 in. Hg absolute.'
Both full load and partial load data for these turbines are available
from the General Electric Company (7). Appendix A shows the heat rate
performance of the conventional, modified conventional, and high back
pressure turbines. Also, this appendix shows the heat rejected as a
10
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function of the back pressure for the modified conventional and high
back pressure turbines. These performance graphs, combined with steam
properties, can be curve-fitted to analytical expressions or tabular
values as a function of condensing temperature, TS. For each load
percentage, two analytical expressions can be derived from curve fit-
ting:
QREJ = function (TS, type turbine, load) (4-3)
PGEN = function (TS, type turbine, load) (4-4)
Equation (4-3) expresses the total heat rejected, QREJ, as a
function of steam temperature, and Equation (4-4) expresses the cor-
responding net power generated, PGEN, at that exhaust steam temper-
ature, TS. As TS increases, QREJ also increases but PGEN decreases.
It should always be borne in mind that QREJ, PGEN, and TS are not
fixed but vary with ambient temperature.
4.3 Condenser Selection
The condenser component of the cooling system determines the
terminal temperature difference, TTD, between the hot water leaving
the condenser and the steam saturation temperature. Both the direct
contact, jet- type condensers and surface condensers were studied in
this work.
4.3.1 Jet Condenser
The jet condenser was developed specifically for dry tower ap-
plication, and there exist several reports that outline its design
and performance characteristics (8, 9). In the jet condenser, water
is sprayed through multiple nozzles into a core of flowing steam.
Under ideal mixing conditions no temperature difference exists be-
tween the hot water and the saturated steam. Early reports on jet
condensers quoted a 0.5°F terminal temperature difference. How-
ever, in a recent report of an installation in the Soviet Union (10),
a temperature difference of 2 F was noted. This temperature differ-
ence varied somewhat with the heat load. In the present study, the
TTD in the jet condenser at full design heat load was set to 2°F. At
other loads, the TTD was set proportional to the heat rejected accor-
ding to:
(TTD) - (2.0) £Jj (4-5)
where,
QREJD = the design rejected heat load.
QREJ = the variable heat load.
11
-------
TTD = the terminal temperature difference in the jet condenser
at the corresponding heat load, QREJ.
The jet condenser design will also affect the circulating water
pumping power through the spray nozzle pressure drop. This is explained
in more detail in Section 4.6 in the discussion on piping. The pressure
drop through the nozzles was assumed fixed at 13 ft. of water.
4.3.2 Surface Condenser
The design and the performance of surface condensers are a function
of both the flow conditions and the mechanical construction. Tube side
velocity, tube diameter and length, number of passes, etc., are all im-
portant variables. Since the reduction in back pressure is of prime im-
portance in dry cooling systems, multiple pressure condensers are employed.
The basic design equations for a single pressure condenser, or for each
individual pressure compartment in a multiple pressure condenser, can be
written as follows:
QREJ = (MCp)water (TRANG)
(4-6)
QREJ = (U) (AC) (TRANG)/ ln(l + TEM}G)
(4-7)
where,
QREJ
water
TRANG
U
TTD
AC
= the total heat rejected in a single pressure condenser
or the heat rejected per compartment in a multipressure
condenser.
= the product of water flow rate and specific heat.
= the overall condenser range or the compartment range
for a multipressure condenser.
= the overall heat transfer coefficient based on area AC.
= either the overall terminal temperature difference or
the temperature difference between the saturated steam
and the exit water temperature from each multipressure
condenser compartment.
= the condenser surface area or the compartment surface
area.
In a multipressure condenser, the overall heat rejected is equal to
the sum of the heat rejected in each compartment. The overall TTD/is
the difference between the saturation temperature (corresponding to
the average of the compartment pressures) and the last compartment
water exit temperature. Equations (4-6) and (4-7) show that for any
given combination of specified TTD, TRANG, and waterflow rate there
exist multiple designs which will provide the same product (U) (AC).
12
-------
These designs can employ different tube diameter and length and also dif-
ferent flow velocities. Normally, the flow velocity is around 7 ft/sec
and it rarely deviates from a range of 6 - 8 ft/sec. An optimal selection
of design variables for the surface condenser is the one which has the
smallest effect on the cooling system tota], evaluated cost. This cost is
affected by the capital cost of th,e condenrser and by the operating cost
of pumping the water through •the^'condenser. The operating cost consists
of both the extra capacity and energy charges for the pumping power. The
prediction of the performance of the condenser involves a procedure which
is somewhat different from the design, since for a given condenser both
its range and TTD will vary as a function of the heat load. A flow dia-
gram for the condenser design procedure is given in Figure 4.3,
4.4 Mechanical Draft Dry Tower
In a mechanical draft tower the finned tubes are assembled into bundles
with common inlet and exit headers. The bundles are in widths commensurate
with the shipping requirement, no wider than 14.5 ft. The shipped bundles
are assembled in the field into bays or modules which are served by one or
more fans through common plenum chambers. A sufficient number of modules
to satisfy the heat transfer requirement of the plant is arranged in the
dry tower. Water is circulated through the modules via a main piping sys-
tem and distribution manifolds. Illustrations of the general layout of dry
towers are given in vendors' publications (11, 12) and are not depicted
here. The finned tube used in this study is, the helically-wound, L-shaped,
footed fin. The tube base diameter is 1 in. with the fin diameter being
2% in. and fins spaced 10 fins/in. These tubes are arranged in an equi-
lateral triangular pitch with %-in. clearance between fins. The tubes are
inclined to facilitate drainage.
The cooling system of a power plant incorporating modules of various
design was optimized, and the effects of these designs on total evaluated
cost were studied. The following design specifications were used as vari-
ables:
1. Tube length
2. Number of rows
3. Number of passes
4. Fan power
4.4.1 Tube Length
The module tube length affects several aspects of the dry tower.
The longer the tubes, the fewer the number of modules required for a
specified heat load. This will result in towers with a shorter longi-
13
-------
START
Input TTD, TRANG
QREJ
Water Inlet Temp.
Select Tube Diameter
Water Velocity
ondenser
Shell
Type?
Single Pressure
Multipressure
Select Fraction Heat Load
Each Compartment
Calc. Range and ITD
in each compartment
Calculate U and surface
in each compartment (AREQ)
Has
Surface Area
Converged
Calculate
U, AREQ
Calc. No. Tubes
Tube Length
Calc. Pressure Drop
and Pumping Power
Calc. Condenser Capital
and Operating Costs
No/lowest"
Possible
Figure 4.3. Surface Condenser Design Procedure.
14
-------
tudina] length and with cheaper piping. The cost of unit surface
area per module is cheaper when longer tubes are used. The disad-
vantage of longer tubes lies in increased shipping and handling ex-
penses. Longer tubes also require increased structure height to
provide adequate flow conditions for the induced air. In some cases
modules with different tube lengths will accomodate fan sizes that
result in increased efficiency. The tube length variation in this
study ranged between 40 and 80 ft.
4.4.2 Number of Rows
The number of rows in a module is a major design variable which
affects both the capital and operating cost of the dry tower. The
number of rows pertains to the number of tubes per unit module width
in the direction of air flow. Figure 4.4 shows a schematic diagram
of a module constructed with 4 rows. Modules with more rows have
higher surface area and less piping and ground area. Also, the cost
of module unit surface area decreases with the increase in number of
rows. However, the resistance to air flow and, hence, the required
fan power increases as the number of rows increases. Also, the in-
crease in number of rows results in heavier modules requiring stronger
supporting structure. Thus, the number of rows has several offsetting
effects on both the cost of the module and the fan power. In this
work, the dry tower analysis was made with modules having either 4,
5 or 6 rows.
4.4.3 Number of Tube Passes
The number of passes pertains to the configuration of water flow
path through the module. In a single-pass module, the water is dis-
tributed in the inlet header to all the tubes in the module and exits
through another header situated at the other end of the tubes. In a
2- pass module, water is distributed from the inlet heater to half
of the tubes, flows to the other end of the tube, and turns to flow
in the other half before exiting at the same end as the inlet. Fig-
ure 4.5 illustrates schematically a module with 2 passes.
The number of passes has several effects on the mechanical de-
sign and the performance of dry towers. The pass configuration is
achieved by constructing the header with proper partition plates
which divide the header into pass compartments. These partition
plates are welded in the header and increase the cost of the module.
The piping system design and layout is affected by the pass number.
With an even number of passes, the water enters and exits the module
on the same side. The main feed and return pipes as well as the dis-
tribution manifolds are all located on one side of the module, re-
quiring greater care for proper layout and construction design. With
an odd number of passes the feed and return piping are located on
opposite ends of the module length.
15
-------
A A A
AIR FLOW
Figure 4.4. Four-Row, Round Fin Staggered Module Arrangement.
A
t t
AIR FLOW
Figure 4.5. Four-Row, Two-Pass Heat Exchanger Arrangement.
16
-------
The number of passes also affects the thermal and hydraulic per-
formance of the module. When the number of rows and tubes and the flow
rate remain unchanged, increasing the number of passes will propor-
tionally increase the tube flow velocity. This will result in an
increase in the tube-side heat transfer coefficient but also will
increase the pumping power because of the increase in the tube-side
pressure drop. Furthermore, increasing the number of passes increases
the mean temperature difference (MTD) of the module and hence in-
creases the effectiveness of the module.
4.4.4 Fan Power
The characteristics of the fans in dry cooling modules may pro-
vide added degrees of freedom in their design and operation. The
heat rejection capability of a module with a fixed configuration in-
creases with the increase in fan power. A dry tower may have few
modules with "powerful" fans inducing high velocity, high volume air
flow, or it may have many of the same size modules with less power-
ful fans. In either case, the total design heat load of the tower
remains unchanged. For a specified design heat rejection and ITD,
the total fan power requirement decreases with an increase in the
number of modules of a given surface area. Thus, there exist num-
erous alternatives for a dry tower design based on the number of
modules and the associated fan power.
The fans employed in dry towers are large diameter axial fans.
A characteristic of these fans is that they induce a large air flow
rate under a low pressure drop, less than 1.0 in. water. The fans
may have between 4 and 12 blades rotating at tip speeds of 12,000
ft/min or less. Fan performance is described by characteristic
curves which present the delivered air flow rate as a function of
flow resistance (pressure drop) and fan speed. The mechanical ef-
ficiency of the fan, defined as the conversion of motor power to
actual power delivered to the air, is also a function of the oper-
ating conditions of the fan. The fan selection for a dry tower is
a major design variable and affects both the performance and capital
and operating costs of the dry tower. The selection of the optimized
fan for the cooling tower was made according to the method described
by Monroe (13).
4.4.5 Dry Tower Design and Rating
The design and rating of dry tower modules involve the calcu-
lation of internal tube-and air-side heat transfer coefficients and
pressure drops and mean temperature difference. These variables
are dependent on either the specific module design or fan power, or
both, as explained in the previous sections. Data for the heat
transfer process in dry cooling modules are available in published
reports (6). The performance of mechanical draft towers is evalu-
ated by the procedures established in Kays and London (14) as ex-
plained in Appendix G.
17
-------
The heat rejection capability of a dry tower is expressed as:
QTOW = (N)mod(ITD) (MCp)mod(P) (4-3)
where,
Mmod = tne number °f identical modules.
(MCp)moc| = the product of air flow rate and specific heat of air
in a module.
P = the heat exchanger effectiveness, ratio of air temp-
erature rise to ITD for (MCp)al> < (MCp)water.
ITD = the initial temperature difference between the hot
water and ambient air.
The (MCp)a-jr is primarily dependent on fan power. The effective-
ness, P, is a function of the number of heat transfer units, NTU; the
capacity ratio, R; and the flow and pass arrangement. The NTU and R
are defined as follows:
NTU = (u) (A) (4-9)
R = (ICP)air (4-10)
(MCp)water
where,
U = the overall heat transfer coefficient based on area A.
A = the total finned- tube heat transfer area.
U is a function of the tube-and air-side coefficients, tube wall
conductance, and the fouling resistances. The tube-side coefficient
is primarily a function of the circulating water flow velocity. The
relation between P, NTU, and R for crossflow is given graphically by
Kays and London (14) and has been analytically formulated into PFR's
computer program. Equations describe the relation between the ITD and
the heat rejected. This relationship is quite complex and is dependent
on the effectiveness and the air and water flow rates.
In the design and performance evaluation of the dry tower, the
actual heat transfer characteristics are calculated for specified con-
ditions. Total flow resistance across the dry module is used to cal-
culate fan power. The pressure drop inside the tubes is used along
with all other losses of the water distribution system to calculate
pumping power.
18
-------
4.4-6 Combined System Performance
The performance of each component of the cooling system (i.e.,
condenser, piping, cooling tower) is coupled to other components
through the heat rate vs. back pressure characteristics of the tur-
bine. The combined system performance is determined by the inter-
action of the individual components which are linked through their
thermal performance. Equations (4-3) through (4-10) form the link
between turbine back pressure and ambient air temperature. These
can be summarized as follows:
QREJ = function (TS, load) = turbine heat rejected (4-3)
PGEN = function (TS, load) = turbine power output (4-4)
QTOW = (N)mod(ITD)(MCp)mod(P) = tower heat rejected (4-8)
TS = TORY + ITD + TTD = steam saturation temperature (4-1)
ITD = TRANG + TAPP = initial temperature difference in
the tower (4-2)
These equations describe the thermal interaction between the
various components of the cooling system. For any given ambient
temperature, TORY, the above equations will determine TS and thus
the turbine power output, PGEN. The above equations also estab-
lish the number of independent variables that are sufficient to
describe the system. For a dry tower module of specified design
(i.e., fixed tube diameter and material, number of rows and num-
ber of passes), there are 6 variables that describe the system.
They are: ITD, TTD, TRANG, TS, tube length, and fan power per module.
The optimum design will be the one in which the right combination of
the above variables will lead to the lowest incremental cost of pro-
ducing electricity.
It is conceivable that different combinations of design varia-
bles will lead to several low incremental costs within a ± 1.0 percent
differential from each other. This is a common result when optimizing
a cost which is a function of multivariables. For example, a design
with few modules with "powerful" fans may have the same cost (within
± 1.0 percent) of a design consisting of a large number of modules
and smaller fan power. However, these designs may differ by plot area
or actual length of piping. Such differences may point to a prefer-
ence of one design over the other simply on the basis of construction
logistics and maintenance problems which may not be reflected by the
cost factor. In reviewing the various design combinations which pro-
duce the lowest incremental bus-bar cost, it is thus possible to
select the best design which conforms to the particular conditions
of a specific project.
19
-------
4.5 Dry Tower Piping System
The piping system consists of carbon steel pipes arranged above
ground to provide equal water flow to each tube module. The main sup-
ply and return lines are designed with appropriate valving to bypass
the dry cooling towers and to isolate the circulating pumps and water
recovery turbines. In addition, storage tanks with fill pumps, val-
ving and fill piping are included to facilitate easy draining or fil-
ling of the dry tower. All piping includes expansion joints to relieve
any thermal expansion. In general, all pipes are standard wall and
designed for a water velocity between 8 and 12 ft/sec.
As much shop work as possible is done in order to reduce the
amount of expensive field work that is needed. The assumptions that
were used in this work are:
1. Pipes below or equal to 4 ft. in diameter are made in 40-ft.
lengths with 2 lengths butt-welded together in the shop.
2. Pipes between 4 and 8 ft. in diameter are made in 12-ft.
lengths with 4 lengths butt-welded together in the shop.
3. Pipes between 8 and 12 ft. in diameter are made in 12-ft.
lengths with 2 lengths butt-welded together in the shop.
4.5.1 Distribution System
Cooling water is pumped from the main condenser to the dry tower
which is located 500 ft. away. The supply line enters perpendicularly
at the middle of the tower and branches in both directions to supply
water along the entire length of the tower. At each bay (3 tube
bundles with a common header) a feeder line rises to a bay distribu-
tion manifold. The feeder lines are adequately valved in order to
shut off water flow to the entire bay. The bay distribution manifold
then distributes the water to the inlet headers of the 3 tube
bundles. In order to keep piping costs at a minimum, the size of the
supply and return lines reduce in size as the water flow rate decreases
along the length of the tower. The return scheme is identical to the
supply scheme.
Four possibilities exist as to the general layout depending on
the total water flow rate and the number of tube passes. With an
even number of passes, the supply line runs down the middle of the
tower, and there are 2 return lines also running down the middle
on either side of the supply line. With an odd number of passes
there are 2 supply lines which run along both sides of the tower.
A single return line runs down the middle of the tower. In addition,
a large water flow rate might necessitate supply and return lines
larger than 12 ft. in diameter. In this case, 2 supply and 2
return lines are needed. This would change the piping arrangement
slightly at the entrance to the tower for both the even and the odd
20
-------
number of tube pass situations. Figure 4.6 is a schematic drawing of
the piping for an even number of passes. Figures 4.7 through 4.10 de-
pict all 4 possibilities for the return and supply piping.
4.6 Piping Pressure Drop
The pressure drop of the piping system is calculated by determining
the loss through each section of the piping, taking into account losses
from valves and elbows. By changing the supply and return line pipe dia-
meter to keep the water velocity nearly constant, there will be no momen-
tum losses or maldistribution in the system. Figures 4.7 through 4.10
denote the various piping diameters with numbers. The total pumping head
depends on the type of condenser.
4.6.1 Surface Condenser Pumping Head
For a surface condenser the pumping head is the sum of the tube bundle,
supply and return piping, and condenser losses. Normally the pressure
drop of the supply and return lines is the smallest component of the total
pumping head. The dry tower tube-side and the condenser pressure drop are
of the same order of magnitude as shown in Table 4.1.
The major constraint is to ensure that the operating pressure for the
condenser does not exceed the limit of the waterbox design pressure.
4.6.2 Direct Contact Condenser Pumping Head
In a direct contact condenser the cooling water mixes with the steam
turbine exhaust. It is thus of prime importance to prevent ambient air
from leaking into the circulating system. The hazard of leakage exists
due to the vacuum conditions in the condenser which is now part of the
cooling water circulation loop. To prevent this hazard, the water cir-
culating pump raises the pressure so that the water in the piping system
is above atmospheric pressure. The pumping conditions are such that at
the highest point (about ground level) in the circulating system, the pres-
sure is 3 ft. above atmospheric. Hydraulic turbines are placed upstream
of the spray nozzles to recover part of the head delivered by the pump
while reducing the cooling water pressure to the conditions in the jet
condenser.
The pump must overcome the head difference between the top of the
condenser where the water is sprayed and the bottom of the condenser where
the liquid water level is. In addition, the pump must overcome the spray
nozzle drop, the tube bundle loss, and the return and supply piping losses.
For a 1000 MWe plant, the total pumping head is approximately 140 ft. of
water. The drop across the recovery turbine will be about 75 ft., 80 per-
cent of which can be recovered while producing useful power.
21
-------
ro
no
DISTRIBUTION
MANIFOLD
RETURN
LINE
Figure 4.6. Water Distribution System.
-------
©
©
TO OTHER HALF OF TOWER
©
©
Return Type 1 - Even number of passes, one line to power plant
Supply Type 3 - Odd number of passes, one line from power plant
Figure 4.7. Schematic of Return Piping Type 1
and Supply Piping Type 3.
TO OTHER
HALF OF TOWER
©
©
<$)
©
©
©
0)
Return Type 2 - Even number of passes, two lines to power plant
Supply Type 4 - Odd number of passes, two lines from power plant
Figure 4.8. Schematic of Return Piping Type 2
and Supply Piping Type 4.
Note: Circled number refer to pipe diameter numbers used for computer
output. See Table E.4.
J
G I
23
-------
TO OTHER
HALF OF TOWER
Return Type 3
Supply Type 1
Odd number of passes, one line to power plant
Even number of passes, one line from power plant
Figure 4.9. Schematic of Return Piping Type 3
and Supply Piping Type 1.
TO OTHER
HALF OF TOWER I
-------
TABLE 4-1. REPRESENTATIVE COOLING SYSTEM HEAD LOSSES*
Supply Lines and
Distribution Piping
Tube Bundle
Return Piping
Condenser Head
Condenser Spray Nozzles
Condenser Tubes
Recovery Turbine or
Throttling Valve
Total Pumping Head
Head Recovered by
Recovery Turbine
Net Pumping Head Penalty
Surface
Condenser
6.5
25.0
6.5
___
—
17.0
—
55.0
—
55.0
Jet Condenser or
Direct Contact
Condenser with
Recovery Turbine
6.5
25.0
6.5
14.0
13.0
—
75.0
140.0
60.0
80.0
direct Contact
Condenser without
Recovery Turbine
6.5
25.0
6.5
14.0
13.0
—
75.0
140.0
—
140.0
* in ft. of water
25
-------
The main advantage of the direct jet condenser is in the lower
TTD as compared to a surface condenser. However, the pumping power
is higher for the direct jet condenser. For a 1000 MWe fossil plant,
the direct jet condenser will require about 2.5 MWe more pumping
power. Table 4.1 demonstrates representative differences in pumping
heads for the different types of condensers.
4.7 Dry Cooling Tower Structure
The horizontal tube modules must be sufficiently elevated to
allow proper distribution of air flow to all modules. The height of
the structure varies as a function of module design and air flow rate.
The structure must be designed to support the module weight and
various wind and live load conditions. The supporting structure for
the dry cooling tower is a steel braced system with bracings in all
3 planes. In addition to the transverse, horizontal and longitudinal
steel bracing systems, a network of I-beams and columns forms the
main structure which supports the weight of the tower; the founda-
tions for these columns consist of 3-foot-deep reinforced concrete.
The structure is designed for Seismic Zone 3 with a roof live load
of 40 lb/ft2. Thus, the tower structure would satisfy building
codes almost anywhere in the United States.
Proper site preparation is performed; it includes 3-foot-deep
excavation, compaction, and grading. The site is cleared and pre-
pared for an additional 30 ft. on both sides of the tower, and a
paved road is constructed down one side for easy accessibility to
the entire tower.
26
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SECTION 5
ECONOMIC MODEL AND OPTIMIZATION
As discussed in the previous section, a cooling tower is a com-
plex system whose size is dependent on many interrelated variables
and whose operation affects the production of electricity in a plant.
A rational application of these towers involves optimization schemes
in which cost is the main factor to consider.
5.1 General Approach
Much work has been done in trying to optimize the design of large,
mechanical draft cooling towers. These studies ((I), (2), (3), (4))
used approximate relations for the heat transfer process in the tower
and simplified generalized cost functions. Furthermore, the optimi-
zation was performed by varying only 1, or at most, 2 variables
while fixing the other variables arbitrarily. Rozenman and Pundyk (15)
discuss these points in detail.
In this work the optimization of the dry tower is based on the
following principles and procedures:
1. All independent variables that define and affect the design
and operating conditions of the cooling tower are included
in the optimization scheme. These are:
a. Design ambient dry air temperature
b. ITD of the tower
c. TTD of the condenser
d. Cooling water temperature range
e. Overall number of modules
f. Fan power
g. Tube length, number of rows, and number of passes
2. Rigorous heat transfer and pressure drop calculations are
made for each design at the different ambient temperatures
to determine the plant performance and assess operating
cost (see Appendix G).
3. The capital cost of the cooling system is evaluated for all
the components of the system with detailed cost breakdown
of all stages of procuring and constructing the dry tower.
4. An advanced, nonlinear, constrained rnu Hi variable optimiza-
tion scheme is used to find the lowest evaluated cost of
the cooling system (see Appendix B).
27
-------
The cost of the cooling system is an incremental cost to the
entire cost of the power plant. The cost of the turbine will not
vary, however. The turbine capital cost was assumed constant during
the optimization process and was not included as part of the incre-
mental cost. The optimization objective is to design the heat re-
jection system which will result in the smallest incremental annual
cost for producing the electricity. The annual cost is composed of
the amortized capital cost (fixed rate charges) and the total oper-
ating cost.
The major capital cost components of the heat rejection system
are:
1. Condenser
2. Cooling tower
3. Piping system (pumps, piping, valves, etc,)
4. Land
The major component of the direct operating cost is the fuel
cost.
As discussed before, the response of the heat rejection system
components to changes in ambient temperature gives rise to variation
in the following factors:
1. Turbine back pressure
2. Auxiliary power requirements
An increase in turbine back pressure will cause a reduction in
plant output because of the heat rate increase. Various schemes are
suggested (22) to overcome the corresponding loss in capacity. These
schemes may require extra capital and energy expenditures. The re-
sulting incremental costs are significant and must be evaluated in
any optimization program.
Auxiliary power is required for the pumps and fans. The auxili-
ary power can be provided by an incremental plant capacity increase
or through the same source that makes up the loss in capacity, such
as a gas turbine or an enlarged plant.
It is evident, then, that in addition to their cost, cooling
towers affect the performance of the entire power cycle. Thus, the
optimization is a study of the combined effect of many variables in
a plant. A true optimization will result from a scheme in which the
design and operating variables are freely combined to provide a cool-
ing tower system with the lowest incremental bus-bar cost of produ-
cing electricity for a given size plant in an assigned geographical
28
-------
area. The interaction of variables is determined by the thermal and
flow characteristics of each component in the plant as explained in
Section 4.
The approach to optimization is to:
1. Identify the minimum number of variables that can be inde-
pendently changed
2. Evaluate their interaction by rating methods described in
Section 4
3. 'Determine the total annual incremental cost for each inter-
action
4. Employ multivariable search techniques to arrive at a com-
bination of variables producing the lowest cost. The search
technique is the Box Complex Method (16) and is explained in
detail in Appendix B.
5.2 Cost Analysis
The study is made on a 1000 MWe fossil fuel plant, 2400 psig,
1000°F/1000°F, located in assigned geographical areas. Two alternate
turbine designs are chosen for the plant - the high back pressure tur-
bine and the modified conventional turbine. The heat rate and heat
rejection of these turbines are shown in Appendix A. Five locations
within the continental U.S. were chosen. These are:
1. Phoenix, Arizona
2. Casper, Wyoming
3. Bismarck, North Dakota
4. Atlanta, Georgia
5. Burlington, Vermont
The annual dry bulb temperature duration curves for the above
sites are given in Appendix D.
The plant is a summer peaking, base load plant with an average
capacity factor of 0.75. The capacity is distributed over the year
as follows:
100 percent load - July, August, September
75 percent load - The rest of the year except April
Shut-down - April
29
-------
The objective is to design an optimum dry cooling system which
will result in the lowest incremental bus-bar cost of producing the
electricity in the plant. The accounting method used here reflects
actual plant operation and practice. The base plant under consider-
ation is viewed as the best source of power. Under all conditions
the steam turbine is modulated until the demand load is achieved.
If the demanded load cannot be achieved, then the power must be ac-
quired elsewhere. This outside power is assessed through capacity
and energy penalties according to the price scheme selected a priori.
For a comparative analysis of all the variables considered in
this study, the annual cost of each cooling system is determined by
evaluating economic costs of penalties for the various components
of the cooling system. These costs include the capital investment,
penalties associated with loss of capacity at higher ambient condi-
tions, and various cooling system operating costs.
5.2.1 Cooling System Capital Cost
The capital cost of the cooling system includes equipment and con-
struction costs for the total cooling system from the turbine flange
onward. This includes the cooling tower, the condenser, the circula-
ting water system, and the indirect charges for the cooling system.
The dry tower cost was evaluated in detail, taking into account
all the stages from procurement to the complete erection and instal-
lation. Because of the logistics involved with the various compo-
nents of the tower and expenses incurred in field installation, the
construction is based on a modular basis in which shop fabrication
is maximized. The cost breakdown includes the following:
1. Cost of fabricated finned-tube bundles with proper headers,
nozzles, and support plates prepared for shipping. The
width of the bundle is between 12 and 14 ft. and the bundle
may have 4 to 6 rows with a tube length up to 80 ft.
2. Cost of fabricated sections for the plenum and recovery
stack. These sections are shipped to the construction site
for installation.
3. Cost of the fans, fan motors, and gearboxes. The fans may be
up to 40 ft. in diameter and have between 4 and 12 blades per
fan.
4. Cost of shipping the above items
5. Cost of support structure. The cost includes the structural
steel fabrication and erection, site preparation, foundation,
walkways and ladders, field and shop labor, and miscellaneous
painting.
30
-------
6. Cost of erection of modules and fans. The shipped bundles
are set and aligned on the support structure and combined
together with the plenum chamber, The fans, motors, gear-
boxes, and recovery stacks are installed, and the fans are
balanced and tested. All labor and material costs, as well
as support crane costs are included.
7. Cost of pumping system. Costs of circulating water pumps
and drives, water recovery turbines, pump and water recovery
turbine foundation are included.
8. Cost of electrical substation and cabling. Labor and material
costs, including conduit and cable for connecting the power to
the fan motors and pump motors,, incremental transformer and
station service cost are included.
9. Cost of piping system. Costs of material and labor for main
water supply and return piping, material and labor for module
inlet and outlet manifold and feeder line, fill and bypass
lines, valving, expansion joints, controls, and storage tanks
are included.
10. Cost of condensers and installation
The annualized cost for the cooling system investment is equal
to the capital cost multiplied by the fixed charge rate. The capital
cost was obtained by summing up the 10 costs enumerated above.
5.2.2 Cooling System Penalties and Operating Costs
The plant equipped with a dry tower cooling system will incur
cost penalties due to the fact that power output is reduced at ele-
vated ambient temperature. A requirement for supplemental power will
occur whenever the turbine output is below its design load at the bus-
bar. This requirement for supplemental power will require additional
expenditures for capacity and energy.
Capacity penalty is the cost of providing the capability to ob-
tain the power that is lost due to the poor performance of dry cooling
towers during hot ambient conditions. Other than purchasing excess
capacity from other utilities, the simplest method is to erect a gas-
turbine on site to provide the power during hot peaking conditions. A
second method is to charge this capacity at the price of the next base
loaded plant to be built in the system. The rationale here is that
the next plant in question will underperform. Another method is to
expand the plant under consideration to supply the loss in power. This
study uses a cost of $100/KWefor installed gas turbine capacity and
$500/KWefor installed capacity of a new plant.
Another capital expense arises from the fact that steam turbines
for dry cooling towers are designed with slightly more steam flow than
31
-------
conventional turbines. This is due to the fact that higher back pres-
sures are experienced and the exhaust flow area is decreased. The
modified conventional 1000 MWe turbine uses approximately 73,000 Ib/hr
of additional steam. The steam supply system could be expanded to pro-
vide this at a cost of about $750,000. For the high back pressure tur-
bine, an additional 513,000 Ib/hr of steam is needed and would cost
approximately $5.4 million for the steam generator.
Energy penalty is the cost of producing that electrical energy
that is lost due to poor dry cooling tower performance. It was assumed
that gas turbine generated energy would cost 40 mills/KW-HR, but at
ambient temperatures below 82°F energy could be bought from the system
at 20 mills/KW-HR. This type of energy penalty is referred to as "40/20"
on subsequent tables and figures. If the energy penalty is assessed
on building the next plant slightly larger, a cost of 10 mil ls/KVJ-HR
is used regardless of ambient temperature. This type of energy penalty
is referred to as "10/10" on subsequent tables and figures.
Special consideration must be given to penalties due to cooling
system auxiliaries. This pertains to the power drawn by the fans and
the recirculating pumps. This auxiliary power reduces the power avail-
able at the bus-bar for the load demand, and its cost is considered as
an additional penalty cost. There exist 2 ways to supplement the
auxiliary power required to power the fans and the circulating pumps.
The first way is to consider the auxiliary power to be a penalty loss
similar to loss of capability at high temperature. Thus, the auxiliary
power can be drawn from the same source as the loss in capability at
high temperatures with the corresponding charges for capacity and pen-
alty. The second way is to recognize that the auxiliary power require-
ment would be of long duration and would be required even at low anbient
temperatures. In this case the base plant capacity is expanded to sup-
ply the required auxiliaries. In such a case the capital and energy
charges of the auxiliaries will use base plant cost factors.
There exist several considerations unique to dry tower application
which will influence the choice of power for cooling system auxiliaries.
If the yearly load demand is such that the plant will operate in the
part load mode for a fraction of the year, the auxiliary power can be
generated without plant expansion. For example, when the yearly load
profile is 100 percent load for summer months and 75 percent load for
the rest of the year, the auxiliary power can be provided at the 75
percent load requirement by simply overfiring the existing plant such
that the power generated would be the auxiliary plus required bus-bar
power. The cost penalty for this case will not include expanded plant
capacity capital cost but will include incremental fuel cost that is
charged for generating the auxiliary power. For the full load summer
period, the auxiliary power penalty can be charged using gas turbine
cost factors.
Another factor which influences the choice of the source for aux-
iliaries is the potential for fan control. In dry cooled systems ap-
32
-------
proximately 75 percent of the auxiliary power requirement is for the
fans, and the other 25 percent is the water pumping power. As the
ambient temperature decreases, the performance of the dry tower in-
creases and the back pressure is reduced. However, below a back pres-
sure of about 5 in. Hg absolute the heat rate curve for a high back
pressure turbine is almost flat, and little gain in power output is
achieved with the reduction in back pressure. Thus, it would be more
economical to maintain a constant back pressure and reduce fan power
as the ambient temperature is reduced. A constant back pressure is
reached below which the extra turbine power gained from a decrease in
back pressure is less than the power saved by reducing the auxiliary
fan power. A typical curve of fan-controlled power reduction as a
function of ambient temperature is given in Figure 5.1. This figure
shows that fan control begins at an ambient temperature of 73°F with
the fan power decreasing rapidly with a further decrease in ambient
temperature. At a temperature of 50°F the required fan power is only
10 MWe as compared to the design requirement of 25 MWe. This potential
for fan control is unique to dry towers using non-conventional turbines.
This behavior is contrary to conventional turbines with wet towers in
which the reduction in back pressure as the ambient temperature de-
creases is used as a means to increase power production.
The above behavior would indicate that considering the source for
auxiliary power requirement as identical to the source for loss in capa-
city at high ambient temperature (i.e., gas turbines) has economic merit
by saving the cost for increased incremental base plant capacity. This
method of accounting for auxiliary penalty, which uses gas turbine gen-
erated power, was used throughout this work. In some cases, however, a
comparison was made between results obtained with the above accounting
method and the method which provides for increased base plant capacity
for auxiliaries.
5.3 Optimization Methodology
The general flow diagram for the optimization procedure is given
in Appendix C. The steps in the optimization codes are as follows:
1. Input
2. Design the cooling system, i.e., dry tower, circulating water
system and condenser on the basis of a combination of design
variables
3. Calculate capital cost of the system
4. Determine plant performance with the change in annual ambient
temperature over the annual cycle
5. Calculate capital and energy costs for cooling system auxiliaries
and loss in generating capacity, employing fan control and extra
firing when advantageous
33
-------
SITE
CONDENSER TYPE
TURBINE TYPE
FIXED CHARGE RATE
FUEL COST ($/MMBTU)
CAPACITY COST ($/KWe)
ENERGY COST (MILLS/KW-HR)
CASPER
SURFACE
MOD.CONV.
.20
.75
100
40/20***
TUBE CONFIGURATION = 6R2P *
CAPACITY FACTOR = .914
SUMMER HOURS NOT EXCEEDED = 10 **
TUBE LENGTH (FT) - 80
ITD (OF) = 49.9
RANGE (°F) = 23
HOURS ABOVE 82°F AMBIENT = 440 *
25 -
20 -
O)
15 --
-------
6. Calculate total fuel cost
7. Determine total incremental bus-bar cost of the cooling
system
8. Employ the box inulticomponent optimization search scheme
to generate a new set of design variables that will lead
to total cost
9. Stop when the combination of variables that will result
in lowest total cost has been found
10. Print the optimum results
The first step involves the determination of the program input.
This is described in detail in Appendix H.
The second step involves the selection of random combinations of
design variables consisting of heat load, ITD, range, TTD, tube length,
and number of modules. The program iterates to find the right approach
velocity which will satisfy the heat transfer characteristics of the
modules. The module design is described in Section 4.4. A suitable
fan design is selected and total fan power is calculated.
The third step involves the design of the condenser, intercon-
necting piping, pumping power, pumps, storage tank controls and valves,
and all other auxiliary equipment of the cooling water system. The
capital cost of all the components is then evaluated as well as the
costs for shipping, structures and foundations, erection and construc-
tion, and electrical connections.
The fourth step involves the evaluation of the plant performance
with the changes in the ambient temperatures. The highest ambient tem-
perature for penalty calculations is determined from the annual temper-
ature duration curve. In most calculations, the temperature at the
site which was equaled or exceeded 29 hours a year ^equivalent to 1
percent of the 4 warmest months) was taken as the highest ambient tem-
perature. For each combination of ambient temperature and the time
occurrence (number of hours), the program calculates plant performance
by matching heat rejected from the tower with the heat load of the tur-
bine. Heat transfer calculations are performed to find the turbine
back pressure for each given ambient temperature. At each ambient tem-
perature a check is made to determine whether fan control is economical
and whether the demanded load is less than 100 percent. If demanded
load is 100 percent of the design load for the turbine and the turbine
output is less than this load, the energy penalty is calculated. If
the demanded load is below 100 percent, a search is made for a turbine
operating point which produces the demanded load plus auxiliary power.
In addition to the fuel consumption energy penalty, the replacement
capacity penalty is calculated.
35
-------
After evaluating the performance over the entire year, the pro-
gram calculates and sums the fuel cost, energy penalty cost, replace-
ment capacity cost, capital and operating costs, the total annual
cost and the total incremental bus-bar cost of the cooling system.
The program then utilizes the "Box" multicomponent optimization
search scheme, generates a new set of independent variables and
repeats the entire process. The calculation stops when a combin-
ation of design variables is found which leads to the lowest total
evaluated cost.
As was evident in the analysis, there exist many combinations of
the design variables which will result in a cooling system with identi-
cal total annual cost. Since the cost is a function of 6 variables,
it cannot be represented simply as a graph on a 2-dimensional plot.
The effect of design variables on the cost was investigated by tabu-
lating all the cost points for the combinations of all variables. No
graphs can be plotted since the functional variation on a 2-dimensional
plot is not easily discernible.
Figures 5.2 to 5.4 show how the annual cost may vary with the ITD.
The points on the figures are the annual costs for cooling systems
designed with a random combination of design variables. Each point
represents the annual cost of the cooling system with a different
combination of ITD, range, fan power, number of modules, TTD, and
ambient temperature. No meaningful curves can be plotted through
the points. For any given fixed ITD, the annual cost may vary as
much as $3-4 million (vertical distance between high and low points),
depending on the combination of design variables. It is evident
that the points are distributed in a domain of ITDs in which the
cost reaches a minimum but no single point is the absolute minimum;
there exist several points with different ITD and identical cost.
This indicates that other design variables, such as fan power and
range, may have compensating effects on the total annual cost. Fig-
ures 5.2 to 5.4 indicate that the ITD cannot serve as the only in-
dependent variable that will determine the optimum design of a cool-
ing system. For example, Figure 5.3 shows the cost analysis for the
Atlanta site with the lowest cost as $15.6 million. The lowest cost
corresponded to an ITD of 49.5°F. However, for that ITD there exist
other points which show the cost to be $16.6 million. The difference
stems from slight changes in design ambient air temperature, temper-
ature range, condenser TTD, number of tower modules and fan power.
Figures 5.5 and 5.6 show the variations of annual cost with range/
ITD for the Phoenix site. The ITD was kept fixed at 60°F for Figure
5.5 and 30°F for Figure 5.6. Large variations in cost are evident from
these figures. The lowest point tends to be between ratios of 0.4 and
0.6. However, for a given range/ITD ratio the price can vary by about
$1 million (vertical distance on the graphs). This indicates that no
single optimum range/ITD ratio exists but that the ratio is a function
of the other independent design variables.
36
-------
SITE = CASPER
CONDENSER TYPE = SURFACE
TURBINE TYPE = MOD.CONV,
FIXED CHARGE RATE - .20
FUEL COST ($/MMBTU) =1.50
CAPACITY COST ($/KWe) = 100
ENERGY COST (MILLS/KW-HR) - 40/20
COST BASE - JAN. 1976
TUBE CONFIGURATION = 6K2P
TUBE LENGTH (FT) - 80
CAPACITY FACTOR = .75
SUMMER HOURS NOT EXCEEDED = 29
ITD (°F)
RANGE (°F)
HOURS ABOVE 82°F AMBIENT = 440
TOTAL GENERATION (MW-HR) - 6,570,000
20000-r
19000—
18000—
3
c
c:
to
4J
o
8 17000-j
o
16000-
15000-
I
+
o
o
o o
o
<> o
00 ° ° °
r, O O
o o
O O o
o
o
O 00
00 O
o o o g °
000
0°
-.0
o
o
o
14000
30
Figure 5.2.
-M—r-
40
50
ITD - °F
60
Total Annual Cost for a Nominal 1000 MWe
Fossil-Fueled Plant at Casper, WY.
70
37
-------
SITE - ATLANTA
CONDENSER TYPE - SURFACE
TURBINE TYPE = MOD.CONV.
FIXED CHARGE RATE - .20
FUEL COST ($/MMBTU) = .75
CAPACITY COST ($/KWe) = 100
ENERGY COST (MILLS/KW-HR) = 40/20
COST BASI
21000-
20000-
19000-
o 18000"
o
o
<— 1
^»-
1
in
o
° 17000-
"fO
3
^
<
r— -
ra
-M
° 16000-
i cnnn
I = JAN. 1976
o
o
o
o
o
Q
0 0
0 0 0
0
o
"~ ° o
{•<
c
~ c
c
c
c
~-J. ..._L—4— -U-.U--J L -J .
TUBE CONFIGURATION
TUBE LENGTH (FT)
CAPACITY FACTOR
SUMMER HOURS NOT EXCEEDED
ITD (OF)
RANGE (OF)
HOURS ABOVE 82°F AMBIENT
TOTAL GENERATION (MW-HR)
6R2P
80
.75
29
733
6,570,000
o
o o
o °o
o o
o ° o
o o
o o
o o
o o
oo o o o
o ° o o
o °°oO o°°
o o
o
0
30
Figure 5.3.
t-f— t~"h"h-H- H h-l I- -I I
40 50
ITD - OF
-]- f
60
Total Annual Cost for a Nominal 1000 MWe
Fossil-Fueled Plant at Atlanta, GA.
o
o
o
•f-4- \
70
38
-------
SITE
CONDENSER TYPE
TURBINE TYPE
FIXED CHARGE RATE
FUEL COST ($/MMBTU)
CAPACITY COST ($/KWe)
ENERGY COST (MILLS/KW-HR)
COST BASE
23000'
225004-
= PHOENIX TUBE CONFIGURATION
= SURFACE TUBE LENGTH (FT)
= MOD.CONV. CAPACITY FACTOR
= .20 SUMMER HOURS NOT EXCEEDED -
= .75 ITD (°F)
= 100 RANGE (°F)
= 40/20 HOURS ABOVE 32°F AMBIENT =
= JAN. 1976 TOTAL GENERATION (MW-HR) =
6R2P
80
.75
29
2760
6,570,000
22000-
o
o
o
21500-1
5 21000^
o
o
20500-
•4 -
35
Figure 5.4.
8
o
o
8
4-4—h-f-4-4--I--4-4-f I-- -1 4-rL—M-
40 45 50
ITD - op
Total Annual Cost for a Nominal 1000 Mwe
Fossil-Fueled Plant at Phoenix, AZ.
39
-------
SITE
CONDENSER TYPE
TURBINE TYPE
FIXED CHARGE RATE
FUEL COST ($/MMBTU)
CAPACITY COST ($/KWe)
ENERGY COST (MILLS/KW-HR)
COST BASE
= PHOENIX TUBE CONFIGURATION = 6R2P
= SURFACE TUBE LENGTH (FT) = 80
- MOD.CONV. CAPACITY FACTOR = .75
= .20 SUMMER HOURS NOT EXCEEDED = 29
- .75 ITD (°F) = 60
= 500 RANGE (op) = —
= 10/10 * HOURS ABOVE 82°F AMBIENT = 2760
- JAN, 1976 TOTAL GENERATION (MW-HR) = 6,570,000
30000 +
29000--
28000-
o 27000
o
-p
i/i
o
<_>
c
c
26000—
(0
25000—
24000-^— H—|—
.3
r
* See page 32 for definition
o o
0 0
o o o
o
o o
o o o o Q o
0 o 0° o oo
O O o °
o ° ° °o o
,j 0 O O 0 ,, o O
° » C) O 8 <>
11 °
o
-t--t-t-~l
Range/ITD
• 6
Figure 5.5.
Total Annual Cost for a Nominal 1000 MWe Fossil-Fueled
Plant at Phoenix, with ITD fixed at 60°F.
40
-------
SITE
CONDENSER TYPE
TURBINE TYPE
FIXED CHARGE RATE
FUEL COST ($/MMBTU)
CAPACITY COST ($/KWe)
ENERGY COST (MILLS/KW-HR)
COST BASE
- PHOENIX
- SURFACE
= MOD.CONV
= .20
= .75
= 500
= 10/10
TUBE CONFIGURATION = 6R2P
TUBE LENGTH = 80
CAPACITY FACTOR = .75
SUMMER HOURS NOT EXCEEDED - 29
ITD (OF) = 30
RANGE (°F)
HOURS ABOVE 82°F AMBIENT
2760
= JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
30000 —
29000 -t
g 28000
I/I
o
_ 27000 -f
rO
26000 -
O
o
o o
o o
o
o
o
o o
o o
o o
o
O o
25000 J—I--I—M—tH--"M-H I—4-4~-t -f--f---l--4—I--4-+--I—1-
.3 -4 .5 .6 .7
Range/ITD
Figure 5 6. Total Annual Cost for a Nominal 1000 MWe Fossil-Fueled
Plant at Phoenix, with ITD fixed at 3QOF.
41
-------
Figures 5.7 and 5.8 show the effect of auxiliary power pumping
and fan power on the total annual cost. Wide variation of cost with
auxiliary power is evident with no specific trend. Figure 5.7 is
for the Phoenix site using a gas turbine for supplying loss in capa-
city (capacity cost $100 KWe, energy cost 40/20 mills/KW-HR). The
figure shows that the total annual cost is sensitive to the auxiliary
power; deviations of ± 3 MWe from the lowest point result in an in-
crease of about $0.5 million. Figure 5.8 is for the Phoenix site
using an expanded plant for supplemental capacity (capacity cost
$500/KWe, energy cost 10/10 mills/KW-HR). The cost is less sensitive
to auxiliary power but the annual cost is about $3 million higher
than the cost of Figure 5.7.
Figure 5.9 shows similar results for the Phoenix site using a
module design of 4 rows and 2 passes as compared to the 6-row, 2-pass
design in the previous graph. Again wide variation in cost is evident
but the spread is over a wider range of auxiliary power as compared
with the results of Figure 5.7.
Figures 5.10 and 5.11 show the possible variations of the annual
cost with the tube length of the module. Tube lengths of 40, 60, 70
and 80 ft. were used. The variation in annual cost can range up to
$6 million for a fixed tube length and a random combination of design
variables. These cost variations are based on ITD ranging between
30°F and 70°F and range/ITD between 0.35 and 0.65. In observing the
variations in cost, it was evident that the lowest cost occurred in
the ITD range of 41-43°F. For ITDs closer to 30°F or 70°F the annual
cost was higher. Figure 5.11 shows the variation in total annual
cost with the ITD fixed in a range of 41-43°F. Variations of up to
$3 million are evident in the cost. However, the lowest cost was ob-
tained with a module using 80-ft. long tubes.
Two major conclusions stem from the above results:
1. The total annual evaluated cost is dependent on all the
variables of the cooling system. No single variable domi-
nates the cost, and setting some variables as fixed values
can lead to non-optimal results.
2. Several combinations of design variables exist which will
result in the lowest total annual evaluated cost. No
unique combination gives this cost since some variables
tend to have compensatory effects on the cost.
Optimal combinations will lead to the lowest annual cost. The
next section describes the results and parametric analysis using the
optimal results.
42
-------
SITE
CONDENSER TYPE
TURBINE TYPE
FIXED CHARGE RATE
FUEL COST ($/MMBTU)
CAPACITY COST ($/KWe)
ENERGY COST (MILLS/KW-HR)
COST BASE
21700 --
21600 --
21500 --
21400 --
21300--
21200
8 21100 —
o
1 21000 —
in
O
,- 20900 —
ro
20800 4-
20700
20600 -f
20500
= PHOENIX TUBE CONFIGURATION
= SURFACE TUBE LENGTH (FT)
= MOD.CONV. CAPACITY FACTOR
= .20 SUMMER HOURS NOT EXCEEDED
= .75 ITD (°F)
= 100 RANGE (6F)
= 40/20 HOURS ABOVE 32°F AMBIENT
= JAN, 1976 TOTAL GENERATION (MU-HR)
6R2P
80
.75
10
2760
6,570,000
o
o
o o
o
O o
ou o
o
o o
0°
o
o o
o o
o
o
O 0
0 0
f-i-T-t^-l-t-^^^-±HH---1---T-±--H--H-H--t
20
25 30 35
Auxiliary Power - MWe
40
Figure 5 7 Cost for a Nominal 1000 MWe Fossil-Fueled Plant at
Phoenix, at $100/KWe: 6-Row, 2-Pass Tube Configuration
43
-------
SITE = PHOENIX TUBE CONFIGURATION = 6R2P
CONDENSER TYPE = SURFACE TUBE LENGTH (FT) = 80
TURBINE TYPE = MOD.CONV, CAPACITY FACTOR = -75
FIXED CHARGE RATE = .20 SUMMER HOURS NOT EXCEEDED = 29
FUEL COST ($/MMBTU) = .75 ITD (OF) - 40
CAPACITY COST ($/KWe) = 500 RANGE (OF)
ENERGY COST (MILLS/KW-HR) = 10/10 HOURS ABOVE 82°F AMBIENT = 2760
COST BASE = JAN, 1976 TOTAL GENERATION (MW-HR) = 6,570,000
30000 -
29000 -
28000 -
o 27000
0
•*£>
(
1/1
° 26000
„
° 25000
o/ir\nn
o
~ 0
0
~" o
o
o
"" 0 0
o ° o
o
, 0 °
o
o
0 ° 0
0
— o
o o o
0 0 o 0
0 O °
— o
o
0 0
° 8 ° °
— ° ° o o o o°°°
0 ° 0 0 ° 0 o
o
0 ° 8 o OQ o
0 0
o o
o o o o o o
00°
o o *-b ° °o
o o o
o
1 1 1 1 1 1 1 1 1 1 1 1 1 1
1 — w«_ _^«__ . i — — — — — — -~- I -4 I I — -— H — - — 4 1-— J — . 1— — 1 1 1 1
20
Figure 5.8.
Auxiliary Power - MWe
Cost for a Nominal 1000 MWe Fossil-Fueled Plant at
Phoenix at $500/KWe: 6-Row, 2-Pass Tube Configuration,
44
-------
SITE = PHOENIX TUBE CONFIGURATION = 4R2P
CONDENSER TYPE = SURFACE TUBE LENGTH (FT) = 80
TURBINE TYPE = MOD.CONV. CAPACITY FACTOR - .75
FIXED CHARGE RATE = .20 SUMMER HOURS NOT EXCEEDED = 10
FUEL COST ($/MMBTU) = .75 ITD (°F)
CAPACITY COST ($/KWe) - 100 RANGE (OF)
ENERGY COST (MILLS/HW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT = 2760
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
22100-
22000-
21900-
21800-
21700-
21600-
0 21500-
o
o
, — 1
7 21400-
to
° 21300-
ra
| 21200-
as
£21100-
21000-
?nqnn -
o o
°0
o
0 0
o
o
_ o o
o
o ° o 0
o
— o
o
o
— o
0 0 ° ° 0
~~ o
0 ° 0
— o o 0 o
- °
0 00
— o
0 ° 0 0
o o ° o °
°oo°0° o0
9. 00 0 ° °
° ° 0 0
0 0
i — O O O
0 0 ° 00
0 ° o
i I . 1 ° 1 1 1 1 1 1 J l_ L_L
20
Figure 5.9.
25 30
Auxiliary Power - MWe
35 40
Cost for a Nominal 1000 MWe Fossil-Fueled Plant at
Phoenix at $100/KWe: 4-Row, 2-Pass Tube Configuration.
45
-------
SITE = PHOENIX
CONDENSER TYPE = SURFACE
TURBINE TYPE = MOD.CONV.
FIXED CHARGE RATE = .20
FUEL COST ($/MMBTU) = .75
CAPACITY COST ($/KWe) = 500
ENERGY COST (MILLS/KW-HR) = 10/10
COST BASE = JAN, 1976
TUBE CONFIGURATION
TUBE LENGTH (FT)
CAPACITY FACTOR
SUMMER HOURS NOT EXCEEDED
ITD (°F)
RANGE (6F)
HOURS ABOVE 32°F AMBIENT
TOTAL GENERATION (MW-HR)
= 6R2P
= .75
= 29
= 30-70
= 2760
= 6,570,000
o
o
o
30000 --
29000 --
28000-
I 270004-
c
£ 26000 --
25000--
24000
t
t
t
40
60
Tube Length - Ft.
80
100
Figure 5.10.
Cost for a Nominal 1000 MWe Fossil-Fueled Plant at
Phoenix for Varying Tube Length and ITD.
46
-------
SITE = PHOENIX
CONDENSER TYPE = SURFACE
TURBINE TYPE = MOD.CONV.
FIXED CHARGE RATE = .20
FUEL COST ($/MMBTU) = .75
CAPACITY COST ($/KWe) = 500
ENERGY COST (MILLS/KW^HR) = 10/10
COST BASE = JAN. 1976
30000
29000
TUBE CONFIGURATION
TUBE LENGTH (FT)
CAPACITY FACTOR
SUMMER HOURS NOT EXCEEDED
ITD (°F)
RANGE (°F)
HOURS ABOVE 82°F AMBIENT
TOTAL GENERATION (MW-HR)
- 6R2P
= .75
= 29
= 41-43
- 2760
= 6,570,000
28000 4-
o
o
o
4-1
l/l
27000 _|_
°26000
03
£25000
o
o
o
o
o
o
o
o
o
24000 J f-4
o
o
o
o
o
o
o
o
o
o
o
40
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
60
Tube Length - Ft.
80
100
Figure 5.11.
Cost for a Nominal 1000 MWe Fossil -Fueled Plant
at Phoenix for Varying Tube Length and Fixed ITD.
47
-------
SECTION 6
RESULTS AND DISCUSSION
The final result in the computer analysis is a printout of 13
possible best designs which represent the optimal design within a
variation in cost of ± 0.5 percent. Implicit in these results is
the fact that there exist several designs which will provide the
lowest cost of the cooling system.
6.1 Computer Output
Table 6-1 shows a sample computer output of the cost components
for a dry cooling system designed for Atlanta, Georgia. A modified
conventional turbine with a multipressure surface condenser was used.
The dry tower was designed with modules consisting of 6-row, 2-pass,
80-ft. long tubes. The cost base is January, 1976, using a fixed
charge rate of 20 percent. The cost summary in Table 6-1 is for the
13 cases differing in the number of modules, fan and pumping pov/er,
design ambient air conditions, and other parameters as depicted in
Table 6-2.
The first column of Table 6-1 is the total capital cost of the
dry tower structure. This cost includes cost of modules and fans,
erection and installation, and support structure. The second column
is the incremental cost of overhead and maintenance for the cooling
system which was taken as 0.05 mills/KW-HR. The third column is
entitled "pipe cost," which consists of the cost of the recircula-
ting system including piping, distribution manifolds, controls, pumps,
storage tanks, etc. Next come the capacity and energy penalties.
Note that the auxiliary power requirement charges were included as
part of the penalty cost using gas turbine plant capital and energy
charges. The sixth column is the total yearly fuel cost for the
plant. The base fuel cost for this case was $0.75/MMBTU. The sev-
enth column is the incremental fuel cost expressing the increase in
fuel cost of the dry tower turbine as compared with the conventional
turbine. This also includes the fuel cost for overfiring the plant
at part load to provide the power for auxiliaries. This incremental
fuel cost was calculated from the cumulative difference between the
heat rate of the plant at the ambient temperatures of the site and a
base heat rate. This base heat rate is as follows:
1. 8887 BTU/KW-HR @ 100 percent load.
2. 9021 BTU/KW-HR @ 75 percent load.
3. 9396 BTU/KW-HR @ 50 percent load.
48
-------
TABLE 6-1. COST SUMMARY OF MECHANICAL DRAFT DRY COOLING TOWER SYSTEM
**THE FOLLOWING SHOWS ANNUAL COSTS IN THOUSANDS OF DOLLARS FOR THE OPTIMIZED DESIGNS OF THE BOX COMPLEX**
1
2
J
4
5
6
7
8
9
10
11
u
li
1
TUBE
MODULE
COST
4961 .0
50=44,9
5352.6
5504.0
-1851.5
5520.0
5251.6
5215.6
4826.6
5108.7
5252.6
5504.0
5569.5
2
HEAT
REJECT
0 + H
528. 5
528.8
529.5
529. 9
528. S
529.5
529.9
528.8
J28.4
529.5
528.8
529.8
529.5
3
PIPE
COST
1605.4
1681 .4
1729. /
1819.8
151S.O
1740.5
1755.2
1727.5
1546,2
1691.1
Io47.4
1829.0
1778.1
•4
C4PC
PEN.
1371.5
1809.2
1707.1
1592. i
H2&.0
Io95.9
1668. 5
1747.4
1927.2
1769.2
1779.1
1597.8
164J.5
2
ENERGY
PEN.
4755,2
5616.7
5550.5
5072,1
5906.8
5555.0
5299.0
5450.5
5905,9
5541.0
5544.5
5122.0
5184.4
6
ANNUAL
FUEL
cosr
45569.7
45552.9
45559.2
45528.9
45589.2
45559.5
45556.6
45552.6
45585.9
4S559.5
45555.2
45551.4
45550,*,
7
IfltH.
FUtL
COST
1144.9
1128.1
1114. a
1104.0
1 164.4
1114.4
1151.8
1107.8
1161,1
1154.7
1110,4
1106.5
1105.7
8 9
HATEH
COND, HECVRr
COST PJ3B.
782.0
790.7
826.7
862.6
766.4
815,5
844.4
814.1
768,7
797.4
770.1
855.4
854.2
0.0
0.0
0.0
0.0
0,0
o.o
0.0
0.0
0,0
0.0
0.0
0.0
0.0
10
EJTC.
SUb-
ST4T.
156.8
141.9
14J.6
145. a
159,6
146.7
151.0
158.0
158.4
148.6
142,6
145.6
H2.2
11
INTTTST
DURING
CONST-?
916.2
957.0
969.9
1017.9
888, 1
980,5
978,5
965.2
891.9
947.5
^55.1
1017.8
995.5
12
MTTL
PER
KWH
2,591
2,588
2.577
2.585
2. i86
2.588
2. i77
2.587
2,591
2.586
2. 192
2.592
2. 576
.U
TOTAL
cosr
15711,5
15687,6
15615,6
I5o58,5
15o74.2
I568b,9
15619,5
15682.8
15706,5
I5o77.5
15718,5
15715,9
15ol2.
-------
TABLE 6-2. TOWER PARAMETER SUMMARY
en
o
1
2
3
a
5
6
7
6
9
10
11
12
13
DESIGN
HEAT
DUTY
MMBTU/HR
1
a7!7.8
4735.6
4717.5
4717.5
4717. H
4727,5
4717. 4
4733.0
4717.7
4721 .4
4762.1
4753,2
4718.2
TTD
°F
2^
5.0
5.0
5.0
5.0
5.0
5.0
5.0
5,0
5.0
5.0
5.0
5.0
5.0
MAX.
BACK
PRES.
in.Hg
3_
8,4
3.1
7.7
7.2
8,6
7.5
7.3
8.0
8.6
7.7
8.0
7.2
7.5
FAN
HP
4
159.
1 7b.
166.
160.
172.
178.
191,
149,
177.
199.
170.
159.
158.
FAN
MW
5^
17
19
19
19
18
20
22
17
18
21
19
19
18
PUMP
MW -
e_
6
6
b
7
5
6
6
6
5
6
5
7
7
WRT
MW
7
0
0
0
0
0
0
0
0
0
0
0
0
3
AUX.
MW
8
23.0
24.8
25.3
26.0
24.1
26,5
28.3
23.2
23.6
27.4
25.0
25.9
2«.7
RNG/
ITD
9
.53
.5V
.52
.51
,54
.54
.52
.51
.54
.55
.56
.51
.50
ITD
OF
10
53,2
51.5
49.3
47,1
53,7
48,6
47,7
50.7
53.9
49.9
51,0
47,3
48.4
* PRES.
AIR
SIDE
in.H20
11
,b3
.66
,bb
.63
.67
.67
.70
.60
,66
.70
.66
.63
.61
DROP
TUBE
SIDE
psi
12
9.3
9.4
10,0
10.2
9.3
9.4
10.5
9.7
9.3
9.4
8.2
10.2
10. a
Note: All parameters, are for the entire dry cooling tower, except for
column 4 which is the horsepower per fan.
-------
non corresP°nd to the conventional steam turbine
at 3.0, 2.0, and 1.0 in. Kg absolute back pressure, respectively.
The eighth column is the total cost of the condenser including
material and installation. This is followed by the cost items of
the water recovery turbine when jet condensers are employed. The
tenth column is the cost of electrical work for connecting the power
to the fans and uses a portion of the transformer switch yard.
The interest during construction is the last item before the mills/
KW-HR and the total annual evaluated cost items. Mills/KW-HR is the
total annual cost divided by total power produced; this expresses
the total annual evaluated cost of the dry cooling system of the
plant per unit of power produced.
Table 6-2 shows the design conditions corresponding to the 13
designs shown in Table 6-1. Note that the TTD of the surface con-
denser was optimized at the lowest allowable TTD. Column 3 of Table
6-2 shows the possible variation in maximum back pressure for differ-
ent designs with identical cost. The back pressure range is between
7.2 and 8.6 in. Hg absolute. The column entitled ITD shows the op-
timal ITD for the various 13 designs. The results in this column
show also the variation in the design ITD for an optimum. In this
case the range of ITD is between 53.9 and 47.1°F. Additional out-
put showing the design information for the optimal case is given
in Appendix E.
A demonstration of cost breakdown of the cooling system compo-
nents is given in Table 6-3 which shows the optimum cost for Casper,
Wyoming. This table shows the piping system as a major cost compo-
nent in the dry tower due primarily to the requirement of distribu-
tion manifolds and general field labor.
A parametric study was prepared to evaluate the effect of design
and economic factors on the dry tower annual evaluated cost. As was
shown in Tables 6-1 and 6-2, the optimal analysis results in a complex
of 13 best designs, all within ± 0.5 percent tolerance. Any of the
alternate 13 best designs can serve as the optimal design. The results
of the parametric study are presented in a tabular form as shown in
Tables 6-4 through 6-24. The design and cost information is grouped
in the table for easy identification and interpretation of the results.
Few items in the parametric tables (see Tables 6-4 - 6-24) require
explanation. The tube configuration item, first line on the right side
of the table, corresponds to the number of rows and number of passes of
the tube modules. This is designated with 2 digits and 2 letters. The
letter R refers to rows and the letter P refers to passes. The symbol
6R2P refers to a tube module configuration of 6 rows and 2 passes. The
item "SUMMER HOURS NOT EXCEEDED," also placed on the right side of the
table, pertains to the number of hours on the temperature probability
curve of the site that corresponds to the maximum temperature used for
the calculation of capacity and energy penalties. The numbers of hours
51
-------
TABLE 6-3. COST FACTOR BREAKDOWN IN MILLIONS OF DOLLARS^
Cost of tube modules $ 15.500
Cost of fans and motors 4,280
Cost of shipping 0.745
Cost of structure 2-3J5
Cost of erection and installation 1.930
SUB-TOTAL (dry tower and cooling air) $ 24.800 $ 24.00
Cost of condenser $ 4.140
Cost of piping, manifolds, and pumps 4,050
Cost of controls, valving 2.760
Cost of storage tank and pit 1.330
Cost of shipping 0.170
SUB-TOTAL (cooling water) $ 12.450 $ 12.45
Cost of added steam supply $ 0,750
Cost of electrical substation & cabling 0.700
Cost of auxiliary wet tower 0.300
SUB-TOTAL (energy & capacity penalties) $ 1.750 $ 1.75
Cost of interest during construction
(11.9 percent of sum of above subtotals) $ 4.640 $ 4.54
TOTAL CAPITAL COST $ 43.54
* Cost base: January 1976
52
-------
and the corresponding maximum temperature are selected somewhat arbit-
rarily by designers of cooling towers.
The total annual cost in thousands of dollars is the first item
of the results in the body of the tables. This is followed by the
major cost items of the dry cooling systems.. Cost items such as in-
terest during construction,, cost of additional steam supply, etc. are
not shown in the tables. The design variables of the optimal tower
are shown in the third body of information on the lower part of each
table. The item "MAX LOSS IN GENERATION (MWe)" shows the loss in
capacity at the highest temperature combined with the total auxiliary
power required.
6.2 Effect of Site on Cost of Dry Cooling
Table 6-4 shows the cost summary of dry cooling systems employed
for power plants located at 5 sites within the continental U.S. De-
sign and cost information is grouped in the table for easy identifi-
cation and interpretation of the results. The tube configuration of
the modules consists of 6 rows with 2 passes (6R2P), and the tubes
are 30 ft. long. The highest ambient temperature used for penalty
assessment was selected as the temperature that is not exceeded 29
hours during the summer.
Table 6.4 shows the strong effect which the location has on the
cost of the dry cooling system. The annual cost of a dry cooling
system located in Burlington, Vermont, is $7.5 million less expensive
than a system located in Phoenix, Arizona. This is evident from the
different weather conditions at the two sites. The Phoenix site has
a maximum ambient temperature (occurring no more than 29 hours in the
summer) of 109.5°F, whereas Burlington's similar maximum temperature
is only 88.2°F. Furthermore, the Phoenix site has over 2760 hours
when the temperature is above 82°F as compared with 176 hours in
Burlington. Both the maximum temperature at the site and the area
under the annual temperature duration curve affect the cost of the
dry tower.
Table 6-4 indicates that the cost of piping is a major component
in the cost of the dry tower. The cost of piping is about double the
cost of the surface condenser. This stems from the fact that the
large number of dry tower modules requires an extensive piping and
distribution system.
6.3 Effect of Turbine Type
Table 6-5 shows the results of the analysis for plants employing
either the high back pressure or the modified conventional turbine.
Both the Casper and the Phoenix sites were studied. The results of
Table 6-5 were computed with a fuel cost of $0,75/MMBTU, Table 6-5
shows that for this fuel cost the use of a high back pressure tur-
bine results in a cheaper incremental cost for the dry tower cooling
53
-------
system. The difference in cost between the two turbines is dependent
on the site weather conditions. For the Casper site the use of the
high back pressure turbine results in a dry cooling system which is
about $600,000/year cheaper than the modified conventional turbine.
For the Phoenix site the difference in cost is about $3.3 million/
year in favor of the high back pressure turbine. Table 6-5
shows that the modified conventional turbine uses much less fuel,
i.e., the incremental fuel cost is much lower. However, this savings
is nullified by the higher capital cost and higher energy and capacity
penalties. The difference in dry tower cost for the 2 turbines for
the same site is primarily a function of the fuel cost. Thus, the
fuel cost, if different for sites compared, may significantly affect
the conclusions drawn from the computed results.
Table 6-6 shows the total cost of the dry tower systems for both
alternate turbines as a function of fuel cost for the Casper site. As
the fuel cost increases, fuel savings begin to play a more dominant
role and the modified conventional turbine becomes cheaper than the
high back pressure turbine. Notice that when the unit fuel cost is
$1.50/MMBTU, the trend is reversed, i.e., the high back pressure tur-
bine is more expensive than the modified conventional turbine by
about $1.23 million/year. At a fuel cost of $1.50/MMBTU, the capital
cost and energy penalties are still higher for a modified conventional
turbine but the incremental fuel cost is about $4 million lower in cost
than for the high back pressure turbine. The results in Tables 6-5
and 6-6 are shown graphically in Figure 6.1 which shows the effect of
unit fuel cost on dry tower systems for the 2 turbines. Figure 6.1
shows that for the Casper site the break-even fuel cost is slightly
over $1.00/MMBTU.
The high back pressure turbines seem quite attractive for hot
climates and sites with low fuel costs. The capital cost of the high
back pressure turbine here was assumed to be the same as the cost of
a conventional turbine. However, the cost of the design modification
for the operation of the turbine at high back end temperatures may
outweigh the advantages of smaller energy penalties.
6.4 Effect of Condenser Type
Both surface condensers and direct contact condensers were studied
for the Casper site with either a modified conventional turbine or a
high back pressure turbine. Table 6-7 indicates that the use of a sur-
face condenser would cost approximately $200,000/year above the cost
of a jet condenser. Basically, this is due to the fact that a surface
condenser has about a 3°F higher TTD than a direct contact condenser
and requires an equivalently lower ITD tower design. Thus, the capital
costs are higher for a system with a surface condenser, if a modified
conventional turbine is used, this difference in the TTD will also re-
sult in higher penalties for the design with the surface condenser.
This is not necessarily so for a high back pressure turbine, since'its
heat rate curve is much flatter, and a 3°F rise in saturation tempera-
54
-------
C-ITE = CASPER
CONDENSER TYPE = SURFACE
TURBINE TYPE
FIXED CHARGE RATE = ,20
FUEL COST ($/MMBTU)
CAPACITY COST ($/KWe) = 100
ENERGY COST (MILLS/KW-HR) = 40/20
TUBE CONFIGURATION = 6R2P
CAPACITY FACTOR = .75
SUMMER HOURS NOT EXCEEDED - 29
TU1£ LENGTH (FT) =80
HOURS ABOVE 82°F AMBIENT = 440
18000 H-
17500 -5-
17000 -f
16500 -4-
o
16000
?15500 -4-
ro
^
C
<15000
14500 H
14000
.75
Figure 6,1,
1.00 1.25
Fuel Cost - $/MMBTU
1.50
1.75
Total Annual Cost for Various Fuel Cost
and Turbine Type - Casper.
55
-------
ture is not quite as significant.
Another noteworthy observation about Table 6-7 is that the in-
cremental fuel cost is lower for the system with a surface condenser.
This results from the higher pumping power required for a direct con-
tact system (on the order of 2,5 MWe). Additional fuel must be_con-
sumed to power the pumps. This difference is especially significant
at part loads when fan control occurs. Therefore, an increase in the
fuel cost could make the systems with surface condensers cheaper.
6.5 Effect of Economic Factors
A parametric analysis was performed to evaluate the effect of
economic factors on the cost of dry towers. The analysis was per-
formed for the Casper site using a modified conventional turbine and
a surface condenser. Results are shown in Tables 6-8 and 6-9 for
unit fuel cost of $0.75/MMBTU and $1.50/MMBTU respectively. Two
fixed charge rates, 15 percent and 20 percent, were used, and 2
methods of accounting for penalties were employed.
Tables 6-8 and 6-9 show that the higher fixed charge rate re-
sults in a more expensive dry tower system, When the loss in capa-
city was replaced by gas turbine generation, the annual cost for a
0.20 fixed charge rate was about 20 percent higher than the annual
cost with a 0.15 fixed charge rate. However, if replacement power
came from a new plant, the increase in cost from a fixed charge
rate of 0.15 to one of 0.20 was nearly 30 percent. Therefore, the
magnitude of the effect of raising the fixed charge rate depended
on how the penalties were assessed.
The results in Tables 6-8 and 6-9 show that assessing penalties
using a new fossil plant with a capacity cost of $500/KWe and an en-
ergy cost of 10 mills/KW-HR results in much more expensive plant op-
eration than when using a gas turbine plant with $100/KWe and 40/20
mills/KW-HR energy charges. For a fixed charge rate of 0.20, the
difference in cost is about $5 million/year more when penalties re-
quire an expanded fossil plant. This difference remains essentially
unchanged whether the fuel cost is $0.75/MM3TU or $1.50/MMBTU, The
reason for this difference is that the increased capital cost of the
new plant far outweighs its savings in energy cost. The optimized
dry cooling system for the expanded plant tends to be considerably
bigger; i.e., more modules are needed than for the dry cooling sys-
tem using gas turbines, and higher auxiliary cost and energy require-
ments result. This results in one beneficial effect in that the maxi-
mum back pressure for the expanded plant is considerably lower than
the maximum back pressure of the plant using gas turbines for peaking,
6.6 Effect of Tube Configuration
The effect of the number of rows and passes of the dry cooling
tower tube modules on the total annual cost is surprisingly small.
56
-------
A careful look at the results in Tables 6-10, 6-11, and 6-12 shows the
importance of optimizing the tower design for each set of conditions.
The first situation studied was for the Casper site with replace-
ment power coming from gas turbines» The tube configurations used
were: 6-row, 2-passi 5-row, 2-pass; 4-row, 2-pass; and 4-row, 1-pass.
These results are shown in Table 6-10, The difference in total annual
cost for all the designs was under $200,000, which is slightly over
a 1 percent change. In fact, the 2 cheaper designs, 6R2P and 4R2P,
are only $5,000 apart. This occurs because the optimization procedure
searches for the combination of design variables for the lowest cost.
The 6-row, 2-pass design requires a lower number of modules with fewer
piping components and smaller ground plot area than do the other con-
figurations studied.
Table 6-11 shows the summary of the tube module configuration
analysis for the Phoenix site using an expanded plant for replacement
power ($500/KWe, 10/10 mills/KU-HR). The table shows almost identical
cost for all 2-pass configurations. However, the 6-row, 2-pass tower
requires 92 modules as compared with 124 modules for the 4-row, 2-pass
design. The 4-row, 1-pass configuration is about $350,000 more ex-
pensive than the 2-pass arrangements.
Table 6-12 shows the effect of the penalty charges on the cost
with different tube configurations. For the Casper site with an ex-
panded plant for replacing lost capacity, the 4-row, 2-pass design
is about $200,000 cheaper. However, for the Phoenix site with gas
turbines used for replacing lost power, the 4-row, 2-pass design is
about $350,000 more expensive.
Conclusions similar to those for the effect of tube configuration
on cost follow from consideration of other design variables, such as
fuel cost, fixed charge rate, etc. A different fuel cost, for example,
could produce different results.
It seems that the savings in pumping costs for 1-pass designs
is outweighed by the increased piping costs and reduced heat transfer
capabilities. For the 2-pass designs, the number of rows is not a
major consideration. Designs, with 6 rows are probably more desirable
since they require less plot area and fewer fans and modules. Above
6 rows, standard-size fans do not provide the necessary air flow, and
schemes involving large diameter fans or sharing fans between bays
would have to be employed,
6.7 Effect of Tube Length
The effect of tube length was studied by choosing three different
situations and optimizing the design using 40-, 50-, 70-, and 80-ft.
tubes. The general trend was a decrease in total annual cost with an
increase in tube length. Tube lengths above 80 ft. were not studied
because of uncertainties in shipping procedures. In all 3 cases,
57
-------
the 70-ft. design was slightly more expensive than the 60-ft. design.
This was due to the fact that shipping costs are higher for lengths
greater than 60 ft., and for tube lengths over 60 ft. a single fan
per bay can no longer provide the required air flow. Thus, 2 fans
per bay are required which increases the module cost and auxiliary
power. Eighty-ft. tubes provide the economy of size over smaller
designs and permit use of more efficient, larger fans in the design
optimization.
Tables 6-13, 6-14 and 6-15 demonstrate these effects. For the
Casper site with a modified conventional turbine and replacement ca-
pacity and energy coming from a gas turbine, there is a $1.1 million
annual advantage of the 80- over the 40-ft. tubes. As the tube length
increases, less modules are needed. This permits lower ITD designs
using fewer modules with corresponding lower costs for piping, capa-
city, and energy penalties.
Table 6-15 shows the Phoenix site with a high back pressure tur-
bine and penalties coming from a gas turbine. For this case the tur-
bine heat rate curve is flatter, and the capacity and energy costs
play a less significant role. The savings from 80-ft. to 40-ft. tubes
($1.1 million) are primarily due to the reduced module and piping
costs that arise from fewer numbers of modules.
For Phoenix with a modified conventional turbine and penalties
coming from a new plant, the cost difference is $1.3 million per
year. As tube length increases, there are less modules and lower
ITDs. This lowers the piping, capacity, and energy charges.
For the cases studied, it is evident that 80-ft. tubes are the
most economical. The fact that they have an increased pressure drop
is insignificant compared with the high costs of modules, and the
amount of power required for the fans. Longer tubes should be studied
to examine whether their increased handling and shipping costs are
offset by their savings in other piping costs and whether their total
cost is lower than that of shorter tubes.
6.8 Effect of Summer Hours
The "SUMMER HOURS NOT EXCEEDED" is a term used to de-
termine how many of the hottest hours at a particular site can be
ignored. Using the hottest temperature ever recorded to calculate
capacity replacement, for instance, unfairly penalizes the dry cool-
ing tower system. These high temperatures occur for short periods
of time, and the power plant most probably will not see their effect
due to the time constant of the plant. A commonly used rule is the
10-hour rule. In this rule, the hottest 10 hours of the year are
ignored, and the highest temperature which is exceeded during those
10 hours is used for capacity replacement calculations and for energy
penalties for the 10-hour duration. Another method is to use 1 per-
cent of the 4 hottest months which corresponds to 29 hours. A third
58
-------
method used in this study had 2,5 percent of the 4 hottest months,
which is 72 hours.
Table 6-16 shows the effect of going from the 10- to 29-hour
rule for the Casper site with a modified conventional turbine. There
was only a 1.4 F difference in the maximum ambient temperature, but
for the case when penalties are made up by a new plant this can be
significant. Since a new, expanded plant has relatively high capa-
city penalties, any reduction in turbine back pressure results in
lower cost. Thus, the 29-hour case was $350,000 cheaper per year
than the 10-hour case. The decrease in the highest ambient temper-
ature allowed a decrease in back pressure and a large reduction in
the capacity penalty. It required more modules and fans to do this,
but the increased capital costs were compensated by the ability to
use a lower capacity replacement. When the penalties come from a
gas turbine, the effect is not as drastic since capacity replacement
is relatively cheaper. The reduction in the highest ambient temper-
ature simply allows a slight reduction in water flow rate and fan
power. This increases the ITD and reduces the capital costs. The
29-hour case saved only $5,000 per year.
The same type of study was conducted for Phoenix with a modi-
fied conventional turbine; it is shown in Table 6-17. The differ-
ence in the maximum ambient temperature from 10 hours to 29 hours
was 2.4°F. As in the Casper case, when penalties come from a new
plant a savings occurs which is almost entirely due to the reduc-
tion in capacity penalty. For Phoenix this amounted to $650,000
annually. For penalties coming from a gas turbine the effect is
much less drastic. The savings was only $40,000 annually. As in
the Casper case, the fan power and water flow rate decreased allow-
ing a higher ITD and lower capital costs. It was interesting to
note that due to the large number of hours that the ambient is
above 32°F at Phoenix, the energy penalty increased for the 29-hour
case. This occurred because of the higher design ITD which offset
some of the capital savings.
Table 6-18 shows the Phoenix site with a high back pressure tur-
bine and with 10, 29, and 72 hours that are not exceeded. Penalties
come from a gas turbine. The effect is small due to the flatness of
the turbine heat rate curve and the fact that gas turbine capacity
replacement is cheap. In going from 10 hours to 72 hours, there was
a 4.1°F difference in maximum ambient temperature; yet, the savings
was only $190,000 annually. As the number of summer hours not ex-
ceeded increases at a given site, the ITD also increases, thus re-
ducing the total annual cost. For 29 hours this substantially lowered
the capital costs and accrued large energy penalties during the many
hours that the ambient was above 82°F. For 72 hours the optimum schem-2
decreased the capital costs less drastically and incurred slight in-
creases in energy penalties.
59
-------
The effect of the number of summer hours not exceeded, which a
designer selects as a basis to calculate penalties, can be a signifi-
cant factor in determining the total annual cost of a dry cooling
tower. This cost depends on the type of turbine, penalty scheme,
and climatic conditions.
6.9 Effect of ITD
The effect of ITD on an optimal design was studied by fixing the
ITD at a specific value and finding the combination of other design
variables which would produce the lowest cost for the specific ITD.
Two sites were analyzed. The results for the Casper site with gas
turbines are shown in Tables 6-19 and 6-20; the results for the Phoenix
site with expanded plant for penalty assessments are shown in Tables
6-21 and 6-22. For both sites the total annual cost has a minimum
point at a specific value of ITD. This is shown in Figures 6.2 and
6.3. Each point on these curves is an optimized point for that par-
ticular ITD. Any deviation of auxiliary power, range, etc., from
those that are given in the tables could result in higher costs for
that ITD.
The effect of ITD is obvious from looking at the tables. As
the ITD increased the capital costs decreased, but the penalties
increased. When the ITD increased, the number of modules and aux-
iliary power decreased while the maximum back pressure and loss in
generation increased.
For the Phoenix case there was a $2.8 million annual increase
from the optimum design ITD of 40°F to an ITD of 60°F. It is note-
worthy that a deviation of 5°F from the optimum design ITD gave a
penalty of over $300,000/year.
For the Casper case the optimum ITD was approximately 53°F.
The corresponding cost was nearly $4.2 million cheaper than for a
design ITD of 30°F, and a 5°F deviation from the optimum cost less
than $200,000/year. Notice that the Casper curve is flatter near
the optimum than the Phoenix curve. Casper was less sensitive be-
cause of its lower capacity replacement charge.
The choice for the design ITD can have a large effect on the
annual cost. In addition, its optimum value is dependent on the site-
related variables, penalty scheme, and economic parameters. These
will also determine the shape of the ITD curve.
6.10 Effect of Range
The study of the effect of range was similar to the study of ITD,
and range was shown to be a significant factor. The results are pre-
sented in Figures 6.4 and 6.5. Again, it must be remembered that each
point is optimized for the conditions stated.
60
-------
SITE = PHOENIX
CONDENSER TYPE = SURFACE
TURBINE TYPE = MOD,COM/.
FIXED CHARGE RATE = .20
FUEL COST ($/MMBTU) = .75
CAPACITY COST ($/KWe) = 500
ENERGY COST (MILLS/KW-HR) = 10/10
TUBE CONFIGURATION
CAPACITY FACTOR
SUMMER HOURS NOT EXCEEDED
TUBE LENGTH (FT)
HOURS ABOVE 82°F AMBIENT
COST BASE
6R2P
.75
29
80
2760
JAN. 1976
28000-1-
27000
o
o
o
1 260004-
10
o
03
25000
24000
50
60
ITD - °F
Figure 6.2. Total Annual Cost for Various ITDs - Phoenix,
61
-------
SITE = CASPER
CONDENSER TYPE = SURFACE
TURBINE TYPE = MOD,CONV.
FIXED CHARGE RATE = .20
FUEL COST ($/MMBTU) = .75
CAPACITY COST ($/KWe) = 100
ENERGY COST (MILLS/KW-HR) = 40/20
TUBE CONFIGURATION ' 6R2P
CAPACITY FACTOR = .75
SUMMER HOURS NOT EXCEEDED = 29
TUBE LENGTH (FT) = 80
HOURS ABOVE 82°F AMBIENT - 440
COST BASE = JAN. 1976
19000 --
18000--
17000--
o
o
o
1/1
o
r- 16000--
CO
3
(0
•t-J
o
15000--
30
40 50
ITD - °F
60
70
Figure 6.3. Total Annual Cost for Various ITDs - Casper.
62
-------
SITE = PHOENIX
CONDENSER TYPE = SURFACE
TURBINE TYPE = MOD,CONV
FIXED CHARGE RATE = ,20
FUEL COST ($/MMBTU) = .75
CAPACITY COST ($/KWe) = 500
ENERGY COST (MILLS/KW-HR) = 10/10
TUBE CONFIGURATION = 6R2P
CAPACITY FACTOR - .75
SUMMER HOURS NOT EXCEEDED = 29
TUBE LENGTH (FT) = 80
HOURS ABOVE 82°F AMBIENT = 2750
COST BASE = JAN. 1976
26500
26000 -r-
25500 -T-
o
o
o
3 25000-
c
•=c
CO
o 24500-
24000
15
20 25
Range - °F
30
35
Figure 6.4. Total Annual Cost for Various Ranges - Phoenix
63
-------
SITE = CASPER
CONDENSER TYPE = SURFACE
TURBINE TYPE = MOD,CONV,
FIXED CHARGE RATE = ,20
FUEL COST ($/MMBTU) = .75
CAPACITY COST ($/KWe) = 100
ENERGY COST (MILLS/KW-HR) = 40/20
TUBE CONFIGURATION = 6R2P
CAPACITY FACTOR = .75
SUMMER HOURS NOT EXCEEDED = 29
TUBE LENGTH (FT) =80
HOURS ABOVE 82°F AMBIENT = 440
COST BASE = JAN. 1976
16500- -
16000 __
o
o
o
£15500-
o
ra
3
C
4J
O
15000--
15
20 25
Range - °F
30
35
Figure 6.5. Total Annual Cost for Various Ranges - Casper.
64
-------
The Phoenix case with a modified conventional turbine and penal-
ties coming from a new plant can be found in Table 6-23, It is inter-
esting to note that changing the range did not alter the number of
modules. Changing the range did affect the water flow rate, however.
As the range increased, the water flow rate dropped and resulted in
smaller piping and condenser costs and larger ITDs. The larger ITD
caused higher capacity and energy penalties since back pressure and
loss in generation increased.
The trend of increasing penalties with decreasing capital costs
resulted in a minimum total annual cost at a range of 20°F. At this
point the total cost was $2 million less than that for an optimum
design for a range of 35°F.
The Casper site with a modified conventional turbine and penal-
ties coming from a gas turbine exhibited the same trend as the Phoenix
case. The results are presented in Table 6-24. For Casper the range
curve was much flatter and had a minimum annual cost at a range near
26°F. This represented a cost that was almost $1.2 million/year
lower than for a tower designed for a range of 15°F.
65
-------
TABLE 6-4. EFFECT OF SITE ON TOTAL ANNUAL COST
SITE = TUBE CONFIGURATION = 6R2P
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) = 80
FUEL COST ($/MMBTU) = ,75 CAPACITY FACTOR = .75
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED = 29
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT =
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUALIZED.
TOTAL COST ($1000) 20522 15612 14869 14593 12817
SITE PHOENIX ATLANTA CASPER BISMARCK BURLINGTON
HOURS ABOVE 82°F AMBIENT 2760 783 440 415 176
AMBIENT EXCEEDED BY 29 HOURS (°F) 109.5 95.3 93.1 96.1 88.2
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (Op)
ITD (OF)
RANGE (°F)
5594
1964
990
2293
6612
1316
45541
80
21
29.0
9.7
114.7
5.1
43.9
21
5370
1778
854
1644
3184
1106
45331
76
18
24.7
7.5
82.2
5.0
48.4
24
4961
1661
828
1828
3014
968
45192
72
18
24.4
8.2
91.4
5.0
53.9
26
4846
1652
844
1872
2815
959
45184
68
21
28.1
8.1
93.6
5.0
50.6
25
4268
1420
730
1798
2181
944
45169
60
17
22.4
8.2
89.9
5.2
58.8
31
66
-------
TABLE 6-5. EFFECT OF TURBINE TYPE - CASPER AND PHOENIX
SITE = TUBE CONFIGURATION
TURBINE TYPE = - — CONDENSER TYPE
FIXED CHARGE RATE, = .20 TUBE LENGTH (FT)
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED =
ENERGY COST (MILLS/KN-HR) = 40/20 HOURS ABOVE 82°F AMBIENT =
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) =
NOTE: ALL COSTS ARE ANNUALIZED.
TOTAL COST ($1000)
TURBINE TYPE
SITE
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (OF)
HOURS ABOVE 82°F AMBIENT
14255
HIGH B.P.
CASPER
4645
1465
717
833
1059
2963
47188
68
18
23.1
10.4
41.7
5.7
64.3
33
440
14869
MOD.CONV.
CASPER
4961
1661
828
1828
3014
968
45192
72
18
24.4
8.2
91.4
5.0
53.9
26
440
17193
HIGH B.P.
PHOENIX
4660
1684
875
1268
2930
3146
47371
68
19
27.1
12.4
63,4
5.1
55.9
25
2760
= 6R2P
= SURFACE
= 80
= .75
= 29
= 6,570,000
20522
MOD.CONV.
PHOENIX
5594
1964
990
2293
6612
1316
45541
80
21
29.0
9.7
114.7
5.1
43.9
21
2760
67
-------
TABLE 6-6. EFFECT OF TURBINE TYPE - CASPER
SITE = CASPER TUBE CONFIGURATION
TURBINE TYPE = CONDENSER TYPE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT)
FUEL COST ($/MMBTU) = CAPACITY FACTOR
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED <
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) ••
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
TURBINE TYPE HIGH
FUEL COST ($/MMBTU)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (OF)
ITD (°F)
RANGE (OF)
17165
B.P.
1.50
4611
1462
730
858
1013
5931
94381
68
14
19,9
10.9
42.9
5.2
66.6
33
15936
MOD.CONV.
1.50
4812
1620
815
1918
3194
1950
90400
68
17
23.6
8.6
95.9
5.2
55.5
26
15198
HIGH B.P.
1.00
4359
1454
722
977
1192
3965
62932
64
15
20.7
11.5
48.8
5.3
68.9
34
= 6R2P
= SURFACE
= 80
= .75
= 29
= 440
= 6,570,000
15236
MOD.CONV.
1.00
5026
1739
879
1759
2871
1328
60294
72
18
25.3
7.9
88.0
5.1
52.2
23
68
-------
TABLE 6-7. EFFECT OF CONDENSER TYPE - CASPER
TMDDTMr TVDC = CASPER TUBE CONFIGURATION
TURBINE TYPE = — - CONDENSER TYPE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT)
FUEL COST (5/MMBTU) = .75 CAPACITY FACTOR
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED =
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT =
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) =
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
CONDENSER TYPE
TURBINE TYPE
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (OF)
ITD (°F)
RANGE (OF)
14869
SURFACE
MOD.CONV.
4961
1661
828
1828
3014
968
45192
72
18
24.4
8.2
91.4
5.0
53.9
26
14600
JET
MOD.CONV.
4896
1675
721
1751
2856
1051
45276
72
17
26.3
7.7
87.6
2.0
57.3
27
14255
SURFACE
HIGH B.P.
4645
1465
717
833
1059
2963
47188
68
18
23.1
10.4
41.7
5.7
64.3
33
6R2P
80
.75
29
440
6,570,000
14072
JET
HIGH B.P.
4302
1450
738
834
1109
3056
47281
64
17
24.0
10.3
41.7
2.0
67.1
32
69
-------
TABLE 6-8. EFFECT OF FIXED CHARGE RATE, CAPACITY PENALTY, AND ENERGY
PENALTY FOR FUEL COST OF $.75/MMBTU
SITE = CASPER
TURBINE TYPE = MOD.CONV
TUBE CONFIGURATION
CONDENSER TYPE
FIXED CHARGE RATE = TUBE LENGTH (FT)
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F
COST BASE = JAN. 1976 TOTAL GENERATION
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
FIXED CHARGE RATE
CAPACITY COST ($/KWe)
ENERGY COST (MILLS/KW-HR)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (°F)
19661 15264
.20 .15
500 500
10/10 10/10
6294 4518
2168 1485
1028 702
6613 5458
680 727
1005 949
45230 45174
92 88
21 17
29.2 24.3
6.0 6.8
66.1 72.8
5.2 5.1
42.4 47.0
19 22
EXCEEDED
AMBIENT
(MW-HR)
14869
.20
100
40/20
4961
1661
828
1828
3014
968
45192
72
18
24.4
8.2
91.4
5.0
53.9
26
= 6R2P
= SURFACE
= 80
= .75
= 29
= 440
= 6,570,000
12253
.15
100
40/20
3962
1329
674
1262
2726
967
45192
76
17
23.9
7.7
84.2
5.1
51.7
24
70
-------
TABLE 6-9. EFFECT OF FIXED CHARGE RATE, CAPACITY PENALTY AND ENERGY
PENALTY FOR FUEL COST OF $1.50/MMBTU
SITE = CASPER TUBE CONFIGURATION = 6R2P
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = TUBE LENGTH (FT) = 80
FUEL COST (S/IWIBTU) =1,50 CAPACITY FACTOR = 75
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED = 29
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT = 440
COST BASE - JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUALIZED.
TOTAL COST ($1000)
FIXED CHARGE RATE
CAPACITY COST ($/KWe)
ENERGY COST (MILLS/KW-HR)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (OF)
20526
.20
500
10/10
6204
2006
976
6956
706
1865
90314
88
21
27.9
6.4
69.6
5.0
44.5
23
16206
.15
500
10/10
4388
1475
747
5475
769
1930
90380
84
21
28.4
6.6
73.0
5.2
45.7
21
15936
.20
100
40/20
4812
1620
815
1918
3194
1950
90400
68
17
23.6
8.6
95.9
5.2
55.5
26
13197
.15
100
40/20
3924
1246
637
1339
2912
1826
90276
76
18
23.3
3.1
89.3
5.0
53.6
27
71
-------
TABLE 6-10. EFFECT OF TUBE CONFIGURATION - CASPER
SITE = CASPER TUBE CONFIGURATION
TURBINE TYPE = MOD.CONV, CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) =80
FUEL COST (S/MMBTU) = .75 CAPACITY FACTOR = .75
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED = 10
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT = 440
COST BASE = JAN, 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUALIZED,
TOTAL COST ($1000)
TUBE CONFIGURATION
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (°F)
14945
6R2P
4979
1702
872
1842
2921
996
45221
72
21
28.1
8,0
92,1
5.0
51.5
24
15136
5R2P
4665
1422
698
2229
3674
928
45153
76
17
22,3
9.9
111.5
5.1
60.0
34
14940
4R2P
4776
1528
737
2056
3338
941
45166
88
19
25.3
9,0
102.8
5.2
56.0
31
15054
4R1P
4506
1850
968
1964
3184
976
45201
80
22
28.6
8.4
98.2
5.4
52.9
19
72
-------
TABLE 6-11. EFFECT OF TUBE CONFIGURATION - PHOENIX
SITE = PHOENIX TUBE CONFIGURATION
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) =80
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR = 75
CAPACITY COST ($/KWe) = 500 SUMMER HOURS NOT EXCEEDED = io
ENERGY COST (MILLS/KW-HR) = 10/10 HOURS ABOVE 82°F AMBIENT = 2760
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
TUBE CONFIGURATION
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (°F)
25205
6R2P
6317
2128
996
11205
1478
1219
45444
92
21
28.7
9.5
112,1
5.0
40.9
20
25167
5R2P
6372
2096
914
11252
1479
1202
45426
104
19
27.2
9.6
112.5
5.1
41.7
22
25193
4R2P
6651
2163
936
10905
1425
1207
45432
124
20
29,1
9.2
109.0
5.0
40.0
21
25543
4R1P
6295
2405
1059
11180
1482
1214
45439
116
22
29.5
9.4
111.8
5.1
40.9
17
73
-------
TABLE 6-12.
EFFECT OF TUBE CONFIGURATION - COMPARISON
AT CASPER AND PHOENIX
oiic. - — — -•
TURBINE TYPE = MOD.t
FIXED CHARGE RATE = .20
FUEL COST ($/MMBTU) = .75
rflDAPTTV rn^T ($./K\>if*'\ — .-•
CMCDPV PACT ^MTI 1 C IV\/l\W-nK )
COST BASE « JAN.
NOTE: ALL COSTS ARE ANNUAL I ZED
SITE
TOTAL COST ($1000)
TUBE CONFIGURATION
CAPACITY COST ($/KWe)
ENERGY COST (MILLS/KW-HR)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (OF)
HOURS ABOVE 82°F AMBIENT
1 UUI- V,
:ONV. CONDEN
TUBE L
CAPACI
SUMMER
HOURS
1976 TOTAL
CASPER
20016
6R2P
500
10/10
6125
2054
923
7375
736
982
45207
88
20
28.2
6.6
73.8
5.4
44.4
21
440
• unr iuur\n i a. uii
ISER TYPE
.ENGTH (FT)
TY FACTOR
: HOURS NOT EXCEEDED
ABOVE 82°F AMBIENT
GENERATION (MW-HR)
CASPER
19823
4R2P
500
10/10
5879
1890
852
7734
753
951
45176
108
20
27.6
6.9
77.3
5.0
46.3
25
440
PHOENIX
20564
6R2P
100
40/20
5926
2017
960
2334
6257
1270
45495
84
21
29.7
9,8
116.7
5.2
42.0
20
2760
= SURFACE
= 80
= .75
= 10
= 6, .570 ,000
PHOENIX
20918
4R2P
100
40/20
5728
1982
879
2471
6773
1322
45547
104
21
29.7
10.3
123.5
5.3
44.6
23
2760
74
-------
TABLE 6-13. EFFECT OF TUBE LENGTH - CASPER
SITE = CASPER TUBE CONFIGURATION = 6R2P
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE - .20 TUBE LENGTH (FT)
FUEL COST (S/MMBTU) = .75 CAPACITY FACTOR = .75
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED =29
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT = 440
COST BASE = JAN, 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUALIZED,
TOTAL COST ($1000)
TUBE LENGTH (FT)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (°F)
15991
40
4988
1823
874
2077
3591
990
45215
124
20
25.8
9.0
103.9
5.0
57.5
23
15286
60
4924
1757
886
1920
3203
971
45196
92
18
24.2
8.5
96,0
5.0
55.6
24
15452
70
5200
1668
789
1927
3277
955
45180
80
19
25.2
8.5
96.3
5.1
58.0
28
14869
80
4961
1661
828
1828
3014
968
45192
72
18
24.4
8.2
91.4
5.0
53.9
26
75
-------
TABLE 6-14.
EFFECT OF TUBE LENGTH - PHOENIX
WITH MODIFIED CONVENTIONAL TURBINE
SITE = PHOENIX TUBE CONFIGURATION = 632P
TURBINE TYPE - MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE - .20 TUBE LENGTH (FT)
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR = .75
CAPACITY COST ($/KWe) = 500 SUMMER HOURS NOT EXCEEDED = 29
ENERGY COST (MILLS/KW-HR) - 10/10 HOURS ABOVE 82°F AMBIENT = 2760
COST BASE - JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
TUBE LENGTH (FT)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (OF)
ITD (°F)
RANGE (°F)
25869
40
6433
2468
1058
11061
1591
1319
45544
164
21
29.9
9.3
110.6
5.2
42.6
17
25048
60
6518
2299
1005
10607
1488
1222
45447
120
19
27.1
9.1
106.1
5.1
41.8
19
25097
70
6200
2200
1032
10962
1558
1283
45508
96
19
28,5
9.3
109.6
5.0
42.5
18
24549
80
6224
2185
1008
10526
1480
1264
45489
88
20
29.2
8.9
105.3
5.1
40.7
19
76
-------
TABLE 6-15. EFFECT OF TUBE LENGTH - PHOENIX
WITH HIGH BACK PRESSURE TURBINE
SITE = PHOENIX TUBE CONFIGURATION = 6R2P
TURBINE TYPE = HIGH B,P. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT)
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR = .75
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED = 29
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT = 2760
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUALIZED.
TOTAL COST ($1000)
TUBE LENGTH (FT)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (°F)
18280
40
5575
2032
861
1248
2717
3066
47291
140
17
23.6
12.7
62.4
5.2
56.6
26
17601
60
5028
1938
988
1213
2614
3107
47332
92
17
23.8
12.5
60.7
5.2
55.6
22
17614
70
5180
1746
871
1274
2794
3062
47287
80
16
21.9
13.1
63.7
5.0
58.1
27
17193
80
4660
1684
875
1268
2930
3146
47371
68
19
27.1
12.4
63.4
5.1
55.9
25
77
-------
TABLE 6-16. EFFECT OF CHANGING NUMBER OF SUMMER HOURS
NOT EXCEEDED - CASPER
SITE = CASPER TUBE CONFIGURATION = 6R2P
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) = 80
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR = .75
CAPACITY COST ($/KWe) = SUMMER HOURS NOT EXCEEDED =
ENERGY COST (MILLS/KW-HR) = HOURS ABOVE 82°F AMBIENT = 440
COST BASE - JAN. 1976 TOTAL GENERATION (MW-HR) = 6,.570,000
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
SUMMER HOURS NOT EXCEEDED
CAPACITY COST ($/KWe)
ENERGY COST (MILLS/KW-HR)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (°F)
HIGHEST AMBIENT TEMPERATURE (°F)
20016
10
500
10/10
6125
2054
923
7375
736
982
45207
88
20
28.2
6.6
73.8
5.4
44.4
21
94.5
19661
29
500
10/10
6294
2168
1028
6613
680
1005
45230
92
21
29,2
6.0
66.1
5.2
42.4
19
93.1
14945
10
100
40/20
4979
1702
872
1842
2921
996
45221
72
21
28.1
8.0
92.1
5.0
51.5
24
94.5
14869
29
100
40/20
4961
1661
828
1828
3014
968
45192
72
18
24.4
8.2
91.4
5.0
53.9
26
93.1
-------
TABLE 6-17. EFFECT OF CHANGING NUMBER OF SUMMER HOURS NOT EXCEEDED -
PHOENIX WITH MODIFIED CONVENTIONAL TURBINE
SITE = PHOENIX TUBE CONFIGURATION = 6R2P
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) = 80
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR = 75
CAPACITY COST ($/KWe) = SUMMER HOURS NOT EXCEEDED =
ENERGY COST (MILLS/KW-HR) = HOURS ABOVE 82°F AMBIENT = 440
COST BASE « JAN. 1976 TOTAL GENERATION (MW-HR) = 6, .570 ,000
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
SUMMER HOURS NOT EXCEEDED
CAPACITY COST ($/KUe)
ENERGY COST (MILLS/KW-HR)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
RANGE (op)
HIGHEST AMBIENT TEMPERATURE (OF)
25205
' 10
500
10/10
6317
2128
996
11205
1478
1219
45444
92
21
28.7
9.5
112.1
5.0
40.9
20
111.9
24549
29
500
10/10
6224
2185
1008
10526
1480
1264
45489
88
20
29.2
8,9
105.3
5.1
40.7
19
109.5
20564
10
100
40/20
5926
2017
960
2334
6257
1270
45495
84
21
29,7
9.8
116.7
5.2
42.0
20
111.9
20522
29
100
40/20
5594
1964
990
2293
6612
1316
45541
80
21
29.0
9,7
114.7
5.1
43.9
21
109.5
79
-------
TABLE 6-18. EFFECT OF CHANGING NUMBER OF SUMMER HOURS NOT EXCEEDED -
PHOENIX WITH HIGH BACK PRESSURE TURBINE
SITE = PHOENIX TUBE CONFIGURATION = 6R2P
TURBINE TYPE = HIGH B.P. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) =80
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR = .75
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT =2760
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
SUMMER HOURS NOT EXCEEDED
HIGHEST AMBIENT TEMPERATURE (°F)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (OF)
ITD (°F)
RANGE (op)
17260
10
111.9
5301
1792
858
1174
2340
3075
47300
76
19
26.1
12.0
58.7
5.0
52.5
26
17193
29
109.5
4660
1684
875
1268
2930
3146
- 47371
68
19
27.1
12.4
63,4
5.1
55.9
25
17069
72
107.8
5026
1707
822
1131
2636
3084
47309
72
17
23,6
12.0
56.5
5.2
56.6
28
80
-------
TABLE 6-19. EFFECT OF ITDs OF 30-45°F - CASPER
SITE - CASPER TUBE CONFIGURATION = 6R2P
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) = 80 '
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR = 75
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED = 29
ENERGY COST ( MILLS/ KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT = 440
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUALIZED,
TOTAL COST ($1000)
ITD (°F)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
RANGE (°F)
19030
30
9008
2864
1087
1123
1581
1033
45258
128
36
45.9
4.3
56.2
5.5
16
17225
35
7426
2481
1054
1202
1953
1030
45254
108
31
41.0
4.9
60.1
5.2
17
16040
40
6423
2223
1018
1318
2109
1041
45266
92
25
34.8
5,7
65.9
5.3
18
15264
45
5775
1963
944
1472
2336
998
45223
84
22
30.2
6.5
73.6
5.1
21
81
-------
TABLE 6-20. EFFECT OF ITDs OF 50-70°F - CASPER
SITE = CASPER TUBE CONFIGURATION = 6R2P
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) = 80
FUEL COST ($/MMBTU) - .75 CAPACITY FACTOR = .75
CAPACITY COST ($/KWe) = 100 SUMMER HOURS NOT EXCEEDED = 29
ENERGY COST (MILLS/KW-HR) = 40/20 HOURS ABOVE 82°F AMBIENT = 440
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
ITD (°F)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (me)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
RANGE (OF)
14955
50
5252
1766
865
1686
2737
979
45204
76
20
27.4
7.4
84.3
5.2
24
15173
60
4491
1555
782
2127
3689
997
45221
64
18
24.5
9.3
106.4
5.1
28
15907
70
4106
1398
714
2552
4661
1027
45252
60
16
21,5
11.3
127.6
5.2
34
82
-------
TABLE 6-21. EFFECT OF ITDs OF 30-40°F - PHOENIX
SITE = PHOENIX TUBE CONFIGURATION = 6R2P
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) =80
FUEL COST (S/MMBTU) - .75 CAPACITY FACTOR = .75
CAPACITY COST ($/KWe) = 500 SUMMER HOURS NOT EXCEEDED = 29
ENERGY COST (MILLS/KW-HR) = 10/10 HOURS ABOVE 82°F AMBIENT = 2760
COST BASE = JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUALIZED,
TOTAL COST ($1000)
ITD (OF)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
. TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
RANGE (°F)
25795
30
8830
2832
1169
8363
1165
1135
45360
128
28
38.1
6.6
83.6
5.0
16
24807
35
7222
2515
1083
9387
1298
1256
45481
104
24
34.1
7.6
93.9
5.1
17
24489
40
6564
2194
957
10225
1435
1216
45441
96
21
29,3
8.6
102.3
5.0
20
83
-------
TABLE 6-22. EFFECT OF ITDs OF 45-60°F - PHOENIX
SITE = PHOENIX TUBE CONFIGURATION = 6R2P
TURBINE TYPE = MOD.CONV. CONDENSER TYPE = SURFACE
FIXED CHARGE RATE = .20 TUBE LENGTH (FT) =30
FUEL COST ($/MMBTU) = .75 CAPACITY FACTOR = -75
CAPACITY COST ($/KWe) = 500 SUMMER HOURS NOT EXCEEDED = 29
ENERGY COST (MILLS/KW-HR) = 10/10 HOURS ABOVE 82°F AMBIENT = 2760
COST BASE - JAN. 1976 TOTAL GENERATION (MW-HR) = 6,570,000
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
ITD (°F)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
RANGE (°F)
24749
45
5926
1946
923
11294
1624
1257
45482
84
20
26,8
9.7
112.9
5.0
23
25291
50
5648
1851
881
12132
1781
1276
45501
80
18
24.9
10.5
121,3
5.0
26
27338
60
5073
1548
733
14794
2238
1375
45600
72
14
19.4
13.4
147,9
5,0
32
84
-------
TABLE 6-23. EFFECT OF RANGE - PHOENIX
SITE = PHOENIX
TURBINE TYPE = MOD.CONV.
FIXED CHARGE RATE = .20
FUEL COST ($/MMBTU) = .75
CAPACITY COST ($/KWe) = 500
ENERGY COST (MILLS/KW-HR) = 10/10
COST BASE = JAN, 1976
NOTE: ALL COSTS ARE ANNUAL I ZED,
TOTAL COST ($1000)
RANGE (°F)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
24951
15
6480
2597
1201
9929
1390
1329
45554
92
21
32.6
8.2
99.3
5.0
37.7
TUBE CONFIGURATION = 6R2P
CONDENSER TYPE = SURFACE
TUBE LENGTH (FT) = 80
CAPACITY FACTOR = .75
SUMMER HOURS NOT EXCEEDED = 29
HOURS ABOVE 82°F AMBIENT = 2760
TOTAL GENERATION (MW-HR) = 6,570,000
24491
20
6317
2128
1001
10445
1487
1241
45466
92
24
32.1
8.6
104,5
5.0
39.9
24914
25
6317
1939
828
11135
1616
1257
45482
92
23
29.4
9.3
111.3
5.1
43,3
25437
30
6378
1772
745
11773
1733
1242
45467
92
23
27,8
10.0
117.7
5,1
45.9
26487
35
6273
1696
707
12905
1919
1238
45463
92
18
22.2
11.4
129.0
5.0
51.2
85
-------
TABLE 6-24. EFFECT OF RANGE - CASPER
SITE = CASPER
TURBINE TYPE = MOD.CONV.
FIXED CHARGE RATE = .20
FUEL COST ($/MMBTU) - .75
CAPACITY COST ($/KWe) = 100
ENERGY COST (MILLS/KW-HR) = 40/20
COST BASE = JAN. 1976
NOTE: ALL COSTS ARE ANNUAL I ZED.
TOTAL COST ($1000)
RANGE (°F)
MODULE COST ($1000)
PIPING COST ($1000)
CONDENSER COST ($1000)
CAPACITY PENALTY ($1000)
ENERGY PENALTY ($1000)
INCREMENTAL FUEL COST ($1000)
ANNUAL FUEL COST ($1000)
NUMBER OF MODULES
TOTAL FAN POWER (MWe)
TOTAL AUXILIARY POWER (MWe)
MAXIMUM BACK PRESSURE (in. Hg)
MAXIMUM LOSS IN GENERATION (MWe)
TTD (°F)
ITD (°F)
16089
15
4986
2279
1146
1718
2927
1281
45506
72
18
33.4
7.1
85.9
5.1
48.5
TUBE CONFIGURATION = 6R2P
CONDENSER TYPE = SURFACE
TUBE LENGTH (FT) = 80
CAPACITY FACTOR = .75
SUMMER HOURS NOT EXCEEDED = 29
HOURS ABOVE 82°F AMBIENT = 440
TOTAL GENERATION (MW-HR) = 6,570,000
15145
20
5060
1895
962
1695
2794
1058
45282
72
20
29.7
7.3
84.8
5.1
49.4
14934
25
4914
1840
834
1840
3077
981
45206
72
19
26.3
8.1
92.0
5.1
53.5
14972
30
5091
1547
746
1899
3167
924
45149
72
19
24.0
8.5
95.0
5.0
55.5
15370
35
4961
1444
673
2143
3686
915
45140
72
17
21.1
9.7
107.0
5.1
60.3
86
-------
REFERENCES
1. Rossie, J. and E. A. Cecil. Research on Dry-Type Cooling Towers
for Thermal Electric Generation, Parts I and II. EPA Report,
Water Pollution Control Research Series 16130 EES. November,
1970.
2. United Engineers and Constructors, Inc. Heat Sink Design and
Cost Study for Fossil and Nuclear Power Plants. WASH-1360. Phila-
delphia, PA. December, 1974.
3. Sebald, J.G. Report on Economics of LWR and HTGR Nuclear Power
Plants with Evaporative and Dry Cooling Systems Sited in the United
States. GAI Report No. 1869. Gilbert Associates, Inc. Reading,
PA. June, 1975.
4. Andeen, B. R. and L. R. Glicksman. Dry Cooling Towers for Power
Plants. Report #DSR73047-1. Department of Mechanical Engineering,
M.I.T., Cambridge, MA. February 1, 1972.
5. Larinoff, M. W. Dry Cooling Tower Power Plant Design Specifica-
tions and Performance Characteristics. In: Proceedings of the ASME
(Heat Transfer Division) Winter Annual Meeting (Dry and Wet/Dry
Cooling Towers for Power Plants). November 11-15, 1973. New York,
NY. PP. 57-75.
6. PFR Engineering Systems, Inc. Heat Transfer and Pressure Drop Char-
acteristics of Dry Tower Extended Surfaces, Parts I and II. Pre-
pared for The Dry Cooling Tower Program, Battelle Pacific Northwest
Laboratories. National Technical Information Service, Springfield,
VA, BNWL-PFR 7-100 and BNWL-PFR 7-102. March, 1976.
7. Private Communications (telephone and letters) between R. D. Mitchell
of R. W. Beck and James Fake of PFR Engineering Systems. May-June,
1976.
8. Heeren, H. and L. Holly. Air Cooling for Condensation and Exhaust
Heat Rejection in Large Generating Stations. In: Proceedings of
the American Power Conference. Chicago, IL. April, 1970.. PP. 579-594.
9. Heller, L. Wet/Dry Hybrid Condensing System. In: Proceedings of the
ASME (Heat Transfer Division) Winter Annual Meeting (Dry and Uet/Dry
Cooling Towers for Power Plants). November 11-15, 1973. New York,
NY. PP. 85-98.
87
-------
10. Report of the United States of America Dry and Dry/Wet Cooling Tower
Delegation Visit to the Union of Soviet Socialist Republics, May 26 -
June 7, 1975. ERDA (RRD Engineering & Technology Engineering .Compo-
nents Development Branch). ERDA-105. Washington, D.C.
11. Smith, E. C. and M. W. Larinoff. Power Plant Siting Performance and
Economics with Dry Cooling Tower Systems. In: Proceedings of the
American Power Conference. Chicago, IL. April, 1970. PP. 544-572.
12. The Marley Company. Dry Cooling Towers for Large Power Installations.
Mission, KS. 1972.
13. Monroe, R. C. Fans Key to Optimum Cooling Tower Design. Oil and
Gas Journal. May 17, 1974. PP. 52-56.
14. Kays, W. M. and A. L. London. Compact Heat Exchangers. Second Edition,
McGraw-Hill Book Company. New York, NY. 1964.
15. Rozenman, T. and J. M. Pundyk. Design Considerations in the Optimization
of Dry Cooling Towers. In: Proceedings of the Workshop on Dry Cooling
Systems. Franklin Institute Research Laboratories. Philadelphia, PA.
July, 1975. PP. 13-1 - 13-8.
16. Box, M. J. A New Method of Constrained Optimization and a Comparison
with Other Methods. Computer Journal. Vol. No. 8. 1965. PP. 42-52.
17. Stevens, R. A. et al. Mean Temperature Differences in One-, Two- and
Three-Pass Cross Flow Heat Exchangers. Transactions of the ASME. Vol.
79. 1957. PP. 287-297.
18. Lawrence, A. E. and T. K. Sherwood. Industrial and Engineering Chemistry.
Vol. 23. 1931. PP. 301-309.
19. Schmidt, T. E. Improved Methods for Calculation of Heat Transfer on
Finned Tubes (in German). Kaltetechnik. Vol. 18. No. 4. 1966.
PP. 135-138.
20. Sieder, E. N. and G. E. Tate. Industrial and Engineering Chemistry. Vol.
28. No. 12. 1936. PP. 1429-1436.
21. Moody, L. F. Transactions of the ASME. Vol. 66. 1944. P. 671.
22. Fryer, B.C. A Review and Assessment of Engineering Economic Studies of
Dry Cooled Electrical Generating Plants. Battelle Pacific Northwest
Laboratories. Richmond, WA BNWL-1976. March, 1976.
23. Briggs and Young. Chemical Engineering Progress Symposium Series. Vol.
59. No. 41. 1963. P. 1.
24. Crane Company. Flow of Fluids Through Valves, Fittings, and Pipe. Tech.
Paper 410.
-------
APPENDIX A
Curves showing the heat rate and heat rejected vs,
back pressure for the turbines used in this study.
A-l
-------
Note:
1000 MWe CONVENTIONAL TURBINE
(FOR STUDY PURPOSES ONLY)
Turbine has net heat rate of 8047 BTU/KW-HR at 3.5 in. Hg absolute.
Heat rates assume 10 percent stack losses.
13000 --
12000 - -
CO
tO
CZ.
11000 --
10000 - -
9000 - -
25% LOAD
Back Pressure - in. Hg.
Figure A.I. Gross Plant Heat Rate with a Conventional Turbine
in Fossil Fuel Units.
A-2
-------
1000 MWe MODIFIED CONVENTIONAL TURBINE
(FOR STUDY PURPOSES ONLY)
Note: Heat Rates are calculated from ratios which are based on a
conventional turbine at 3.5 in. Hg absolute with 8047 BTU/
KW-HR net. Heat rates assume 10 percent stack losses.
15000 -
14000 - -
13000
CO
1 12000
0)
to
cc
(O
O)
11000
(C
D-
10
to
O
s-
CD.
10000 - -
9000 -'
25% LOAD
0 1
Figure A.2.
2 3 4 5 6 7 8 9 10 11 12 13 14 15
Back Pressure - in. Hg
Gross Plant Heat Rate with a Modified Conventional Turbine
in Fossil Fuel Units.
A-3
-------
Note:
1000 MWe HIGH BACK PRESSURE TURBINE
(FOR STUDY PURPOSES ONLY)
Heat Rates are calculated from ratios which are based on a
conventional turbine at 3.5 in. Hg absolute with 8047 BTU/
KW-HR net. Heat rates assume 10 percent stack losses.
15000
14000 - -
13000 - -
, 12000 - -
O)
to
a:
re
+j
c
ro
11000 --
to
in
O
eg
10000 - -
9000 - -
25% LOAD
0 1
Figure A.3.
45678910
Back Pressure - in. Hg
12 13 14 15
Gross Plant Heat Rate with a High Back Pressure
Turbine in Fossil Fuel Units.
A-4
-------
Note:
1000 MWe MODIFIED CONVENTIONAL TURBINE
(FOR STUDY PURPOSES ONLY)
Based on conventional turbine at 3.5 in. Hg absolute with a
net heat rate of 8047 BTU/KW-HR.
6.14-
5.2--
01
O
X
cc
4.3--
•o
0)
3.4 —
OJ
2.5 —
1.6--
FULL LOAD
75% LOAI
50% LOAD
25% LOAD
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14
Back Pressure - in, Hg
Figure A.4. Net Heat Rejected for Modified Conventional Turbines
in Fossil Fuel Units.
A-5
-------
Note:
1000 MWe HIGH BACK PRESSURE TURBINE
(FOR STUDY PURPOSES ONLY)
Based on conventional turbine at 3.5 in. Hg absolute with a
net heat rate of 8047 BTU/KW-HR.
6.1
5.2 --
••->
034
J • "
-------
APPENDIX B
Description of the multicomponent optimization
technique used in this study.
B-l
-------
The Multicomponent Optimization
The basic method of optimization for the dry cooling tower sys-
tem is the M.J. Box Complex Method (16). This method is a sequential
search technique that was chosen due to the nature of the non-linear,
constrained variables that make up the cost function of a cooling
tower system. In addition, the Box Method requires a fewer number of
cost calculations as compared with the factorial, "shotgun", or uni-
variate methods. The basic Box procedure was employed, but some modi-
fications were implemented to better accomodate the dry cooling tower
project.
The Box Method minimizes a function,
by finding the optimum combination of the independent variables. The
independent variables along with certain implicit variables are subject
to the following constraints:
Gk < Xk < Hk k = 1, 2, 3, M
The lower and upper constraints, Gk and Hk, are either constants or
functions of the independent variables. The implicit variables,
through XM, are dependent functions of the independent variables.
The procedure is as follows:
1. Randomly pick an initial complex of points such that all
constraints are satisfied. Each point is a set of the in-
dependent variables and a complete design, rating, and
costing of the cooling tower is performed for each point.
2. Find the jtn point in the complex with the highest cost
function and replace it with a new point. The new point
is found by:
- *ij) (B-l)
where Xj is the centroid of the ith independent variable
and a is an expansion factor which is greater than 1. For
this study a value of 2 was used for a. The centroid is
the average of the ith independent variable of all the
points, excluding the point that is being replaced.
Check to see if all the independent variables of the new
point satisfy their respective constraints. If an explicit
constraint is violated, that particular variable is placed
a small distance, 6, from the boundary. If an implicit con-
straint is violated, the variable is moved half of the dis-
tance to its centroid.
B-2
-------
4. If the point repeats as the one with the highest cost function,
then all of the independent variables are moved half of the dis-
tance to their centroids.
5. This procedure continues until there is no further reduction of
the cost function. The criterion for termination depends on the
user.
The cooling tower design is characterized by N = 6 independent vari-
ables (the number of tube rows and passes is fixed for a given design).
They are:
Q = the heat rejected in the cooling tower.
ITD = the difference between the ambient temperature and the hot
water temperature entering the cooling tower.
RANGE = the difference between the temperature of the water entering
and the temperature of the water leaving the cooling tower.
TL = length of the tubes.
TN = number of tubes for the entire cooling tower.
TTD = the difference between the saturation temperature of the steam
in the condenser and the temperature of the water leaving the
condenser.
The constraints used for the cooling tower variables are as follows:
QMIN < Q < QMAX
ITDMIN < ITD < ITDMAX
RNGMIN < RANGE < MIN(RNGMAX, ITD)
TLMIN < TL < TLMAX
TNMIN < TN < TNMAX
TTDMIN < TTD < TTDMAX
The minimum and maximum values used for this study depended on what
case was being studied. In general, Q varied from 4678 MMBTU/HR up to
5401 MMBTU/HR. ITD varied from 20°F up to 8QOF. TL varied from 40 ft.
up to 80 ft. TN varied from 50,000 tubes up to 200,000 tubes. Finally,
TTD varied from 2°F up to 15°F.
In addition to the 6 independent variables, the Box procedure must
constrain the 2 dependent variables, air-side and tube-side velocity.
B-3
-------
When a dependent variable constraint is violated, the value of TN or
TL is changed such that the dependent variable rests on the limit. If
the tube-side velocity constraint is violated, the value of TN is
changed. If air-side velocity constraint is violated, the value of
TL is changed. The criterion for an optimal solution is for all the
points to have cost functions that lie within a specified tolerance
of each other and continue to do so for a specified number of iter-
ations.
B-4
-------
APPENDIX C
Flow Chart of the
Dry Tower Optimization Program.
C-l
-------
NO
INPUT
(See Appendix H)
SET NO. PASSES, NO. ROWS
SET Q DESIGN, ITD,
RANGE, TUBE LENGTH,
NO. TUBES, TTD
ITERATE ON AIR VELOCITY
UNTIL NTU ASSUMED CONVERGES
TO NTU CALCULATED
ARE ALL
VARIABLES WITHIN
CONSTRAINTS
(CALCULATE AP TUBESIDE
AP AIR
DETERMINE:
NO. FANS
NO. BLADES
FAN DIAMETER
FAN POWER
Figure C.I. Flow Chart of Cooling System Optimization,
C-2
-------
DESIGN INTERCONNECTING PIPING
CONDENSER
STORAGE TANKS
CIRCULATING PUMPS
VALVE SIZES
FILL PUMPS
PUMP & FAN MOTORS
WATER RECOVERY TURBINE
DETERMINE PUMPING POWER!
CALCULATE COST OF COOLING SYSTEM
FANS MOTORS
MODULES GEARBOXES
VALVES PIPING
CONDENSER STORAGE TANKS
PUMPS CONTROLS
PLENUMS WATER RECOVERY TURBINE
CALCULATE COST OF:
STRUCTURE
ERECTION
FOUNDATIONS
CONSTRUCTION
SHIPPING
ELECTRICAL CABLING
FIND PLANT PERFORMANCE WITH ANNUAL
CHANGES IN AMBIENT TEMPERATURES
FIND HIGHEST SITE AMBIENT
TEMPERATURE WHICH IS EXCEEDED
29 HOURS A YEAR
Figure C.I (cont'd.)
C-3
-------
CONVERGE ON PLANT
OPERATING POINT
CALCULATE POWER OUTPUT OF PLANT AT
THE SPECIFIED AMBIENT TEMPERATURE
REDUCE AUXILIARY POWER
BY USING FAN CONTROL AND
FIND NEW OPERATING POINT
IS
BACK PRESSURE
LOW ENOUGH FOR
FAN CONTROL
IS
DEMANDED LOAD
LESS THAN
100%
COMPUTE AND
ACCUMULATE
ENERGY PENALTY
FIND TURBINE FIRING RATE
AND NEW OPERATING POINT
TO PRODUCE DEMANDED LOAD
PLUS AUXILIARY POWER
COMPUTE AND
ACCUMULATE FUEL CONSUMPTION
Figure C.I (cont'd.).
C-4
-------
CALCULATE CAPITAL COST
OF REPLACEMENT CAPACITY
SELECT NEXT
AMBIENT TEMP.
IS
AMBIENT THE
HIGHEST
HAS
LOWEST AMBIENT
BEEN REACHED
DETERMINE TOTAL BUS-BAR COST
THIS IS COST FUNCTION TO
OPTIMIZE
GET NEW SET OF INDEPENDENT
VARIABLES USING BOX OPTI-
MIZATION SEARCH METHOD
Figure C.I (cont'd.)
C-5
-------
APPENDIX D
Ambient Temperature Profiles
for the Sites Studied in this Work.
D-l
-------
0 1000 2000 3000 4000 5000 6000 7000 8000 8760
Cumulative Time that Temperature is Exceeded - Hr
Figure D.I. Temperature Duration Curves for Casper and Phoenix.
D-2
-------
-40
1000 2000 3000 4000 5000 6000 7000 8000 8760
Cumulative Time that Temperature is Exceeded - Hr
Figure D.2.
Temperature Duration Curves for Atlanta, Burlington
and Bismarck.
D-3
-------
APPENDIX E
Sample Computer Output
for an Optimal System.
E-l
-------
TABLE E-l. INPUT FOR 1000 MWe MODIFIED CONVENTIONAL STEAM TURBINE
**THE FIRST
***THE LAST
4 COLUMNS A^E
4 COLUMNS ARE
HEAT RATE- BTU/KW-HR
HEAT REJECT - MMBTU/HR
-LOAD*
8P -
• •
2.0
2*5
3,0
3.5
4.0
4.5
5.0
S.5
6.0
6.5
7.0
7.5
8.0
S.5
9.0
9.5
10,0
10.5
11.0
11.5
12.0
18.5
13.0
13.5
14.0
14, S
15,0
uoo
in. Hg
8935.
8957.
8990,
9031.
9084.
9146.
9218.
9294,
9372.
9444,
9516,
956fa.
965?.
9785.
9791.
9858.
9926,
9994.
10060.
10126.
10191.
10255.
10319.
1038?.
10446,
10509.
10573.
.75
9057,
909fl,
9149,
9225,
9522.
9425,
9527,
9625.
9719,
9810.
9900.
9988.
10073.
10159.
10242.
10326,
10409,
10491,
10570,
10654.
10737.
10815.
10893,
10971.
11049.
11127.
11205.
.50
9560,
9647.
9789,
9936.
10067,
10196,
10323.
10403,
10570.
10688,
10804.
10915.
11027,
11138,
11249,
11361,
11471,
1 1583,
Il69a,
11806,
11917.
12023,
12139.
12250,
12362.
12473,
12585,
.25
10448,
10648.
10905.
11127.
11305,
11461.
11616.
11761.
11917,
120/2,
12229.
12384.
12540.
12695*
12851,
13008,
13163,
13319,
13474.
13631.
13786.
13942.
14097.
14253.
14409,
14565,
14721,
1,00
4678.
4feB7,
4699,
4714,
4735.
4758.
478<1,
4811.
4839,
4864,
4889.
4912.
49J5,
me,
4980.
5001,
5023.
5044,
S064.
5084,
5103,;
$122.
5141.
51S9.
5177,
5195,
5218.
,75
4620.
3630.,
3646.
3667.
3694.
3721.
3748.
3773.
3797,
3620.
3841.
3863,
3682.
3902.
3921.
394Q.
39S8.
3976,
3993.
4010.
4027.
4043.
4059.
4074.
4089,
4105,
4119,
,50
2698.
2714.
2739,
2765,
2787.
2808.
2829.
2841.
2867.
2885,
2902.
2918.
2934.
2949.
2964,
2979.
2994.
3007,
3021.
3035,
3048,
3062.
3075.
3087,
3100,
3112.
3124.
,25
1595,
1612,
1633.
1650.
1664.
1675.
1686.
1696,
1707.
1717.
1727.
1737.
1746.
1756.
1765.
1774.
1782,
1791.
1799.
1807,
1815.
1823.
1830,
1837.
1845.
1852.
1859,
MINIMUM SACK PRESSURE AT ABOVE LQAO$
3.60 2.90 2.00 2.00
COMPARATIVE MEAT RATE AT ABOVE UQAD8
E INCREMEMTAL FJEL COST
8887. 9021, 9396, 9827,
TO
E-2
-------
TABLE E-2. SAMPLE COMPUTER OUTPUT OF SURFACE CONDENSER DESIGN
•« STtAM CONDITIONS
TOTAL FLOW LEAVING
SATURATION Tt«P.
SATURATION PRESSURE
4.967
121.89 DEG.F
i.6J IN. HG
2.253 WMHG/HH
49.94 OtG.C
12289 H/M2
MULT(PRESSURE DESIGN
SATURATION OVER. FRAC.
Prt.«-.->.«}*i TEMP-v COEFF. DUTY
ZONE 1 2.88 111.6 498.61 .45
a 4.)8 129.3 si).98 .55
'F *F "f
INLET TEMP,
TEMP. RANGE LMTO
92.6 10.9 14,9
10).5 13.4 17.8
m
i
co
** CIRCULATING MAUR CONDITIONS
FLO* RATE 19U.486
TEMP.ENTERING 92.5b OEG.F
TE^P.LEAVING 116.8? DEG.F
*• OVERALL PERFORMANCE
HEAT DUTY
MEAN IE^P.DIFF.
CLEANINESS FACTOR
4719.003 MMBTU/HR
16.1J OEG.F
88.173 MMKti/HR
33.64 OEG.C
47.16 OEG.C
H8ST', 169 MMKCAL/HH
9.07 OEG.C
.850
*• DESIGN RESTRAINTS
TU8E SIDE VELOCITY FT/SEC 6.00
TUdE SIDE PRESSURE 03QP PSI
TUBE LENGTH FT 20,00
SATURATION PRESSURE,IN. HG Aba 2.00
MAXIMUM
7.00
15.00
80.00
15.00
»« DESIGN PARAMETERS
PLATE MATERIAL CARUON STEEL
TUBE MATERIAL CA4BQN STEEL
TUBE GAUGE 16.
DESIGN TUBE INFORMATION
NO.OF "40.OF TUBE SIDE
OVERALL
TOTAL
COST ESTIMATED
NO.
O.D LENGTH
NUlbER TUBE SHELL PRESS VELOC.
PASSES SES. DROP
-------
TABLE E-3. SAMPLE COMPUTER OUTPUT OF DRY TOWER TUBE BUNDLE DESIGN
TOT4L IN3ULLED COST f>t=>
«1" COOLER COST
1*69" 7,270.
-------
TABLE E-4. SAMPLE COMPUTER OUTPUT OF DRY TOWER PIPING COST SUMMARY
* BAY PIPING
1, INLET FEEDER LINE
2. OUTLET FEEDER LINE
3. INLET HEADER
4. OUTLET HEADER
PIPING/BAY
76. BAYS
8 SUPPLY PIPINGUYPE 1)
t.
2.
3.
4.
5.
6.
C RETURN PIP1NGCTYPE i)
1
2
J
4
5
6
0 FILL LINES
E BYPA33 LINES
F VALVINGUN3TALLED)
1. 8AY CONTROL
2. CONO. PUMP ISOLATION
5. RECVRY TURBINE ISO.
4, 8YPA33
5. FILL PUMP ISOLATION
6. FILL DRAIN
C PUMP3UN3TALLEO)
' 1. 5 82700. GPM CONO,
2. 1 10000 CPM FILL
H STORAGE TANKCINSTALLED)
4 - 120701. GAL TANKS
I CONTHOL3(IN3TALLEO)
J NITROGEN BLANKETING
« SHIPMENT OF PIPING
DIAMETER
(IN)
15,25
lb.25
10.14
10.14
114,00
78.00
23. 2S
72.00
60.00
78.00
114.00
60.00
17.25
43.00
ai.oo
76.00
I1?. 25
114.00
IS. 25
114.00
114,00
114.00
19.25
19.25
TOTAL
($)
4582.
3496.
3<»9.
SYSTEM
TOTAL
1242558,
720444.
867757,
59070,
27175,
1021892.
1328050.
20000.
14M3M.
1911245.
13350.
18S199.
8890271,
*NOTE: See Figure 4.7 for a description of the supply and return
piping and what the type and numbers refer to.
E-5
-------
TABLE E-5. SAMPLE COMPUTER OUTPUT OF OPTIMUM DRY TOWER DESIGN
•• PRINTOUT OF OPTIMUM OESION GENERATED BY THE PFR OPTIMIZATION PROGRAM
1 SIZE 15- UQ5- 6-HORIZONTAL tNOUCEO NBU»^>» I JOOO M* DOSSIL FUEL
2 SURFACE/UNIT EXT/BARE MOSISMS./ 1881158. I SITE ATLANTA GEORGIA
3 HEAT EXCHANGED / *TO a7l8.2«0l/ 1«>.95 I TURBINE MODIFIED CONV.
« HATE EXT/BAHE/CLEAN 5.84/125.70/135,94 I CONOEN3R SURFACE
•• TUBE 310E ••
*• PWQCESS 4NO PERFORMANCE DATA PER UNIT ••
5 FLUID CIRCULATED CC
6 TOTAL FLUID
7 LIQUID
8 TEMPERATURE
9 PRESSURE
10 PRESSURE DROP SPEC./CALC.
JNOEN. HATER
(H-LB/HR)
(M«LB/HR)
(DEG.F)
(PSIA)
(P3I)
ENTERING
194385. 5«5
194185.545
lit. 9
26 . 38
0.00
LEAVING
194385,545
92.6
16.00
10.38
•• AIR 3IOE »•
It AIR/UNIT (M-LS/HR) 652321.86
1£ AIR/FAN (ACFM) 10tt«J59.02
t 13 FACE VEL C3FPM) 576,7UO
1<4 MASS V (LU/HR-FT2) 3088.8/9
TEMP, IN/OUT (OEG.F) b«.5/ 98.fe
ALTITUDE (FT) 1050.
STATIC D.P..CALC.
-------
TABLE E-6. COMPUTER OUTPUT OF SUMMARY OF FINAL DRY TOWER DESIGNS FOR A SAMPLE CASE
*** THE FQuUQrtlNG ARE THE OPTIMIZED DESIGNS GENERATED 8T THE BOX METHOD
THEY MAKE UP THE COMPLEX AT THE END OF THE OPTIMIZATION PROCEDURE ***
1
2
3
4
5
6
7
8
9
10
11
12
13
2 ^
B P
A A
Y N
72 2
72 2
76 2
80 2
72 2
76 2
76 2
76 2
68 2
72 2
76 2
80 2
76 2
8UND FAN BARE
«DTH ID SURF, •
AREA
FT FT FT**2
14.
14.
14,
14.
14.
14,
14.
14,
i ->»
15.
la.
la ,
15.
52.
32.
32.
32.
32.
52.
32.
32.
32,
32.
32.
32.
32.
1729345,
1755747,
1825420.
1921494,
1676541.
1853289.
1825420,
1825420.
1683141,
1782149.
1825420.
192149U.
1881158.
TUBE ]
NO,
395
399
393
393
381
399
393
393
405
405
393
393
405
[NFORMATION
UGH TEMPS. VEU» FLOW
FT Iht>F°Ur FPS MMLB/HR
30
80
80
80
80
80
80
80
80
80
80
80
80
117
I2t
117
117
117
119
117
12$
117
118
126
124
117
89,
93.
91*
93*
88,
93.
92.
9a,
88.
90.
97.
100.
93.
4.7 168.39
4.8 172.20
4.9 185.18
5*a 196.55
4.7 162.84
4.8 181.71
5.0 189.68
4.8 181.38
4>7 163.40
4*7 ..173. 97.
a. a 166.94
5.0 198.20
5.0 19a.39
* AIRS
TEMPS,
64
69
67
70
63
70
69
69
63
68
75
77
69
96
100
97
99
95
99
98
101
95
97
105
106
99
IDE
VEU
FPM
586
604
596
587
610
607
624
572
602
624
601
586
577
INFO, *
FUQrt
MMLB/HR
609,46
637.94
653.81
678.68
615,64
676.55
684.87
627.73
609.09
668.47
660.09
677.58
652.32
*NOTE: The above designs correspond to the costs given in Table 6-1.
-------
APPENDIX F
Table of
SI Conversions.
F-l
-------
TABLE F-l. SI CONVERSIONS FOR TERMS IN BRITISH UNITS
TO OBTAIN
J
Kg
Kg/sec
Kg/m2-sec
m
m/sec
m3
m3/sec
m3/sec
N/m2
N/m2
N/m2
W
W/m2-°K
W
MULTIPLY
BTU
lyhr
lbm/hr-ft2
ft
ft/min
gal
gal/min
ft3/min
psi
ft H20
in. Hg
BTU/hr
BTU/hr-ft2-°F
hp
B_Y
1055.06
.45359
1.2600 x 10-"
1.3562 x 10"3
.30484
.50800 x 10"2
3.7854 x 10"3
6.3091 x 10-5
4.7196 x 10"*
6894.6
2989.0
3385.3
3.4122
5.6783
745.71
OTHER:
To obtain °K:
T(K) = 273 + 5/9 (T(F) - 32}
F-2
-------
APPENDIX G
Heat Transfer
and Pressure Drop Calculations,
G-l
-------
HEAT TRANSFER AND PRESSURE DROP CALCULATIONS
The heat transfer method used in this program utilizes the effective-
ness - NTU approach to heat exchanger design as developed by Kays and London
(14). In this method, the heat load is expressed by the following equation:
Q = (MCp)air (ITD)(P) (G-l)
where,
Q = the total heat load transferred in the heat exchanger.
(MCp)air= the product of air flow rate and specific heat of air.
ITD = the initial temperature difference between the incoming
hot water and the ambient air.
P = thermal effectiveness.
The number of transfer units and capacity ratio, R, are nondimensional
numbers which characterize the heat exchanger by its design variables. In
the equations used here, it is assumed that (MCp)water is greater than
(MCp)air.
NTU = _ (4-9)
(4-10)
(MCp)water
U is the overall heat transfer coefficient based on the outside finned
surface area.
For a heat exchanger with "countercurrent" (counterflow) or "cocurrent"
(parallel) flow configuration, the relationship between P, R, and NTU can be
formulated in closed form by integration. Analytical expressions for the
above relationship are given by Kays and London (14). For a cross flow con-
figuration with both tube-side and air-side in the "unmixed" flow condition,
the relationship cannot be expressed in analytical form. It can be solved
numerically by the method of Stevens et al (17). In this program, a numer-
ical procedure has been incorporated into a subroutine that calculates the
effectiveness, P, for a specified NTU and R.
The overall coefficient, U, is calculated as the reciprocal of the sum
of all the individual resistances to heat transfer:
U = 1.0/d.O/HAIR + RAOI/HIN + RFIN + RTOT) (Q-2)
G-2
-------
where,
HAIR = the air-side heat transfer coefficient based on total finned
surface area.
RAOI = the ratio of finned surface to inside tube surface.
HIN = the water- or tube-side heat transfer coefficient.
RFIN = the fin resistance
RTOT = the sum of the resistances due to tube wall conductance and
inside and outside tube fouling, all based on the finned tube
area.
The air-side coefficient, HAIR, was calculated on the basis of the
Briggs and Young (23) correlation:
HAIR = 0.904 (KA) (REA)0-718 (PRAV)0-333 (6-3)
where,
KA = the thermal conductivity of the air in BTU/hr-ft2-op.
DO = the outside tube diameter in in.
REA = the air- side Reynolds number.
PRAV = the air-side Prandtl number.
The Reynolds number was calculated as:
REA = (DO)(GA) (G-4)
(29. 04) (MA)
where,
GA = the air-side mass velocity in lbm/hr-ft2.
MA = the air viscosity in Op.
The air-side mass velocity was calculated as:
(G-5)
where ,
W2 = the total air-side flow rate in Ibm/hr.
AMIN = the minimum air-side free flow area transverse to air flow
in ft2.
G-3
-------
The Prandtl number was calculated as:
PRAV = (2.42)(MA)(CPA) ,, ' (G-6)
where, ;, .,.:, -...,'.
CPA = the air heat capacity in BTU/lbm-°F.
The water- or tube-side coefficient, HIN, was calculated from the
correlation of Lawrence and Sherwood (18):
HIN = 0.7 (gjL) (REW)0-7 (PR)0'5 (6-7)
where,
KW" = the thermal conductivity of water in BTU/hr-ft2-°F.
DI = the inside tube diameter in in.
REW = the tube-side Reynolds number.
PR = the tube-side Prandtl number.
The Reynolds number was calculated as:
REW = (DI)(GW) (6-8)
(29.04)(MW)
where,
GW = the tube-side mass velocity in lbm/hr-ft2.
MW = the water viscosity in Cp.
The tube-side mass velocity was calculated as:
GW = Wl (G.9)
where,
Wl = the total tube-side flow rate in lbm/hr.
AT = the inside cross-sectioned area of all tubes in a single tube
pass in ft2.
The Prandtl number was calculated as:
PR = (2.42)(MW)(CPW) •' (6-10)
KW
where, ,
CPW = the water heat capacity in BTU/lbm-°F.
G-4
-------
The fin resistance, RFIN, is a function of fin height and thickness
and thermal conductivity of the fin and was calculated by the method de-
veloped by Schmidt (19). The sum of the inside and outside tube fouling
factors in this study was assumed to be 0.005 hr-ft-°F/BTU, which is the
value used by industry for relatively clean conditions. The tube wall
resistance was calculated using a value of 26 BTU/hr-ft-°F for the tube
thermal conductivity.
The air-side friction loss was determined by using the following
correlation which was developed at PFR Engineering Systems, Inc.:
DELP = (f)(GA)2(N) (2.68 x HT10) ,G in
(GC)(DENA) ( J
where,
f = the dimensionless friction factor.
N = the number of tube rows in the direction of air flow.
GC = the dimensional gravitational constant of 32.2 lbm-ft/lbf-sec2.
DENA = the air density at average temperature in lbm/ft3.
DELP = the pressure drop in psi.
The friction factor as developed by PFR is a function of Reynolds
number, tube geometry, and tube pitch. The friction factor was defined
as:
f = (6.03)(REA)-°-21t5(^I)"0-872(^I)0-515(RAOR)°-lt30 (G-12)
where,
PT = the tube pitch transverse to air flow in in.
PL = the tube pitch in the direction of air flow in in.
RAOR = the ratio of total outside finned surface area to the out-
side surface area of the bare tube.
In addition to the tube bundle friction loss, the program calculates
three additional pressure losses. Each loss uses the actual density cor-
rected for altitude and temperature at the position in the bundle- The
momentum loss accounts for contraction and expansion into and out of the
dry cooling tower as well as the loss caused by the increase in air tem-
perature as air is heated, producing a higher leaving velocity. The cal-
culation of the total pressure loss also incorporates the dynamic velocity
head to find the loss incurred in accelerating the air from zero velocity
to the approach velocity and incurred due to the area change at the fan.
Finally, the program calculates the loss due to flow through the fan guards
6-5
-------
and inlet louvers. The equations for these additional pressure losses can
be found in Kays and London (14). The program uses a value of 1.8 for the
louver loss coefficient, 1.1 for the fan guard loss coefficient, and 4.5
for the dynamic velocity head loss coefficient. The use of these loss co-
efficients is defined in Kays and London (14).
The tube-side pressure drop is calculated by assuming commercial cir-
cular pipe with fouling and using the Fanning friction formulation. The
Fanning equation for flow loss in a tube is:
DELPN = U)(f1so)(GW)2(L) (1.286 x KT8) (G-13)
(GC)(DENW)(DI)
where,
DELPN = the pressure drop in psi.
L = the total length of tube in ft.
fiso = the dimensionless isothermal Fanning friction factor.
DENW = the water density at average temperature in lbm/ft3.
= the Sieder-Tate (20) correction factor for bulk to wall
property variation.
Both fiso and <(> are defined differently depending on whether or not
the flow is laminar, in transition, or turbulent. The expressions for
fiso were found by fitting curves to the 3 zones of the Moody (21) chart
and dividing by 4 to determine the Fanning friction factor.
To determine the total dry cooling tower pressure drop, in addition
to the tube-side friction loss, the program calculates the inlet nozzle
loss using a loss coefficient, k, of 1.0; the inlet header contraction
loss using a k of 1.5; the turn-around loss between passes using a k of
1.5; the outlet header expansion loss using a k of .25, and the outlet
nozzle loss using a k of 0.5. The pressure drop for each of these losses
is:
DEL = _ (G_14)
(DENW) (1.20 x 1011)
where,
DEL = the pressure loss in psi.
k = the loss coefficient.
For the nozzle losses, GW is calculated based on the inside cross-sectional
area of the nozzle.
G-6
-------
The pressure losses due to the rest of the circulating system have
been discussed in detail in earlier sections. The return and supply
piping losses were determined by converting all straight lengths, elbows,
valves, etc. to equivalent lengths in pipe diameters L/D. The sum of
all the L/Ds was used in equation G-13 assuming an average DENW and GW
and a constant value of 0.00275 for the product of fiso and <|>. No loss
coefficients were used in calculating these pressure losses. The values
used for the L/Ds of the elbows, valves, etc. can be found in Crane (24)
The program actually sums up each pipe, elbow, valve, etc. that is con-
tained in the circulating system. Thus, the elements that are included
in the determination of the pressure drop will depend heavily on the de-
sign of the system as described in earlier sections.
6-7
-------
APPENDIX H
Program Input and Program Listing,
H-l
-------
PROGRAM INPUT
The input data required for the Dry Cooling Tower Optimization
Program includes an alphanumeric description of the case, the temper-
ature-load profile of the site, site-related design information, para-
meters for the economic evaluation, and steam turbine performance char-
acteristics. These data are read from standard 80-column computer
cards. Integer variables must be right justified and real variables
require a decimal point. An explanation of each card is given below.
1. Card No. 1
Col. 1-2
Col. 3-22
01 (Card Number)
Case description
Col. 23-37 Geographical location or site
Col. 38-52 Turbine type
Col. 53-67 Condenser type
Variable Name
KNO
BARB(1)-BARB(4)
BARB(5)-BARB(7)
BARB(8)-BARB(10)
BARB(11)-BARB(13)
2. Card No.
Col. 1-2
Col. 3-7
Col. 8-9
Col. 10-14
Col. 15-19
Col. 20-25
Col. 26-29
Col. 30-33
02 KNO
Tube inclination in degrees
from the horizontal ANGI
Number of tube bundles in
parallel in each bay ZBUP
Number of fins/in. ZNFI
The distance in in. between
centers of adjacent tubes in
a row perpendicular to the
air flow direction PTI
Altitude of site in ft. HALT
Fixed charge rate of base plant
expressed as a decimal fraction COST(2)
Cost in mills/KW-HR of energy
penalty when energy penalty is
maximum COST(6)
H-2
-------
Variable Name
Col. 34-36 Number of tube rows per bundle ZTRD
Col. 37-40 Number of tube passes per bundle ZTPD
3. Card No. 3
Col. 1-2
Col. 3-8
Col. 9-13
Col. 14-17
Col. 18-21
Col. 22-25
Col. 26-28
Col. 29-31
Col. 32-37
Col. 38-39
03
KNO
Maximum allowable tube length in
ft. TLMAX
Minimum allowable ITD in °F TITDN
Decimal fraction used to deter-
mine when to stop the optimiza-
tion procedure (The procedure
stops when all designs in the
Box Complex have total costs
whose ratios are 1.0 ± TOL.
Computational time increases
as this tolerance is decreased) TOL
Box optimization expansion factor,
« (See discussion on Box proce-
dure. Recommended value is 2.0) ALF
Decimal fraction of distance be-
tween constraint boundary and
centroid to place independent
variable when constraint is vio-
lated (See discussion on Box pro-
cedure. Recommended value is
.01)
Maximum number of iterations
allowed in Box procedure
DELT
ITRMX
Number of consectutive iterations
which will occur that satisfy
the tolerance (card 3, col. 14)
before execution stops NITR
Nominal plant capacity in MWe BCAPC
Number of ambient air tempera-
tures to be used (Max. of 20) NATTR
H-3
-------
Variable Name
Col. 40-44 Cost in $/KWe for capacity re-
placement CAPCST
Col. 45-48 Minimum allowable TTD in °F
{Usually 2.0 degrees for direct
contact condensers and 5.0
degrees for surface condensers) TTDMN
Col. 49-52 Maximum allowable TTD in °F TTDMX
4. Card No.
Col. 1-2
Col. 3-5
Col. 6-9
Col. 10-16
Col. 17-23
Col. 24-30
Col. 31-37
Col. 38-44
Col. 45-51
Col. 52-58
4
04 KNO
Fixed charge rate for capacity
replacement expressed as a
decimal fraction (In most
cases this will be the same as
the fixed charge rate for the
base plant) AFCR2
Base plant fuel cost in $/MMBTU FLCST
Maximum allowable number of tubes TNMAX
Minimum allowable number of tubes TNMIN
Base heat rate in BTU/KW-HR for
load 1 (This is the base heat
rate with which to compare the
dry tower plant. Incremental fuel
is calculated using this base. To
use total fuel as a dry tower cost
component, input zero. This heat
rate corresponds to load 1 (card
11, Col. 6) only) BHTRT(l)
Base heat rate in BTU/KW-HR for
load 2 BHTRT(2)
Base heat rate in BTU/KW-HR for
load 3 BHTRT(3)
Base heat rate in BTU/KW-HR for
load 4 BHTRT(4)
Base heat rate in BTU/KW-HR for
load 5 BHTRT(5)
H-4
-------
Variable Name
Col. 59-65 Base heat rate in BTU/KW-HR for
6 BHTRT(6)
5. Card No. 5
Col. 1-2 05 KNO
Col. 3-7 Maximum allowable air approach
velocity in ft/min at standard
conditions (Recommended maxi-
mum is 700 ft/min) VAMAX
Col. 8-12 Minimum allowable air approach
velocity in ft/min (Recom-
mended minimum is 350 ft/min) VAMIN
Col. 13-16 Maximum allowable tube-side flow
velocity in ft/sec (Recommended
maximum is 9 ft/sec) VWMAX
Col. 17-20 Minimum allowable tube-side flow
velocity in ft/sec (Recommended
minimum is 2 ft/sec) VVIMIN
Col. 21-25 Maximum allowable cooling range
in °F RNGMX
Col. 26-30 Minimum allowable cooling range
in °F RNGMN
Col. 31-35 Maximum allowable ITD in °F TITDX
Col. 36-39 Minimum allowable tube length in
ft. TLMIN
Col. 40-43 Maximum allowable flow velocity
for the piping system in ft/sec
(Recommended maximum is 12.5
ft/sec) VX
Col. 44-47 Minimum allowable flow velocity
for the piping system in ft/sec VN
Col. 48-51 Installed cost of direct conden-
ser in. $/lb/hr of steam flow
(Zero indicates a surface conden-
ser is being used) CONCT
H-5
-------
Variable Name
Col. 52-57 Total installed capital cost
of extra steam supply system
in millions of dollars STMCT
Col. 58-62 Ambient air temperature in °F
above which maximum energy pen-
alty cost is used (Usually
82QF is used) CUTMP
Col. 63-67 Cost in mills/KW-HR (Penalty
when the energy penalty is
minimum) SHELP
6. Card No. 6
Col. 1-2 06 KNO
Col. 3-7 Maximum allowable bundle width
in ft. (This is usually set
by shipping limitations and is
a maximum of 14.5 ft.) WBMAX
Col. 8-12 Maximum allowable inside diameter
in in. for piping system (Maxi-
mum is 144 in.)
Col. 13-14 Maximum allowable number of fan
blades (Minimum is 8) MXFBL
Col. 15-18 Maximum allowable fan diameter
in ft. (Minimum is 24 ft.) FDMAX
Col. 19-23 Distance in ft. from power plant
to dry cooling towers DPPCT
Col. 24-27 Distance in ft. from direct con-
tact condenser water level to
ground level (If water level
is above ground level, input a
negative value) CWTLV
Col. 28-31 Distance in ft. from direct con-
tact condenser spray nozzle level
to ground level (If spray noz-
zles are above ground level, in-
put a negative value) SPRHT
H-6
-------
Col. 32-36
Col. 37-42
Col. 43-46
Col. 47-49
Col. 50-52
Col. 53-57
Col. 58-61
Pressure drop across direct con-
tact condenser spray nozzles in
ft. of water
Maximum shipping length in ft.
for piping
Back pressure in in. Hg absolute
at which steam turbine produces
nominal power
Efficiency of cooling tower cir-
culating pumps (Usually it is
about .89)
Overall efficiency of water re-
covery turbine (Usually it is
about .8)
Installed cost of water recovery
turbine in $/KWe (Input zero
if no water recovery turbine is
desired)
Operating and maintenance cost
in mills/KW-HR for the incremen-
tal 0 & M attributable to the
heat rejection system
Variable Name
SPRNZ
SCPMP
PBPHT
CPEFF
WTEFF
CWRTI
EBPOM
7. Card No. 7
Col. 1-2
Col. 3-7
Col. 8-13
07
KNO
First ambient air temperature in
°F used to rate cooling tower
(The first temperature must be the
highest ambient temperature and
the remaining ambients must be de-
creasing; this is a requirement
for this program) ATTR(l)
Number of hours per year that
first ambient air temperature
occurs
DATTR(l)
H-7
-------
Varible Name
Col. 14-17 Load factor as decimal fraction
of nominal turbine power for de-
termining the plant output desired
during the first ambient air tem-
perature PLDFT(l)
Col. 18-22 Second ambient air temperature ATTR(2)
Col. 23-28 Number of hours per year for
second ambient air temperature DATTR(2)
Col. 29-32 Load factor for second ambient
air temperature PLDFT(2)
Col. 33-37 Third ambient air temperature ATTR(3)
Col. 38-43 Number of hours per year for
third ambient air temperature DATTR(3)
Col. 44-47 Load factor for third ambient
air temperature PLDFT(3)
Col. 48-52 Fourth ambient air temperature ATTR(4)
Col. 53-58 Number of hours per year for
fourth ambient air temperature DATTR(4)
Col. 59-62 Load factor for fourth ambient
air temperature PLDFT(4)
Col. 63-67 Fifth ambient air temperature ATTR(5)
Col. 68-73 Number of hours per year for
fifth ambient air temperature DATTR(5)
Col. 74-77 Load factor for fifth ambient
air temperature PLDFT(5)
8. Card No. 8
Col. 1-2 08
Col. 3-77 Same as card No. 7 for ambient
air temperatures No. 6 through
No. 10 (Columns 3-7 are for
ATTR(6), etc.)
KNO
H-8
-------
9. Card No. 9
Col. 1-2 09
Col. 3-77 Same as card No. 7 for ambient
air temperatures No. 11 through
No. 15 (Columns 3-7 are for
ATTR(ll), etc.)
10. Card No. 10
Col. 1-2 10
Col. 3-77 Same as card No. 7 for ambient
air temperatures No. 16 through
No. 20 (Columns 3-7 are for
ATTR(16), etc.)
Variable Name
KNO
KNO
11. Card No.
Col. 1-2
Col. 3-4
Col. 5
Col. 6-8
Col. 9-11
Col. 12-14
Col. 15-17
Col. 18-20
Col. 21-23
11
11
KNO
Number of turbine back pressures
to be used to input turbine in-
formation (Maximum is 28) NBKPR
Number of turbine loads to be
used to input turbine informa-
tion (Maximum is 6) NLODS
Turbine load No. 1 as a decimal
fraction of nominal turbine
power XLDFT(l)
Back pressure in in. Hg absolute
where fan control starts for load
1 BPMNM(l)
Turbine load 2
XLDFT(2)
Back pressure in in. Hg absolute
for fan control for load 2 BPMNM(2)
Turbine load 3
XLDFT(3)
Back pressure in in. Hg absolute
for fan control for load 3 BPMNM(3)
H-9
-------
Col. 24-26 Turbine load 4
Col. 27-29 Back pressure in in. Hg absolute
for fan control for load 4
Col. 30-32 Turbine load 5
Col. 33-35 Back pressure in in. Hg absolute
for fan control for load 5
Col. 36-38 Turbine load 6
Col. 39-41 Back pressure in in. Hg absolute
for fan control for load 6
Col. 42-45 Back pressure No. 1 in in. Hg
absolute (The first back pres-
sure for which turbine informa-
tion will be input)
Col. 46-49 Back pressure No. 2 in in. Hg
absolute (The second back
pressure for which turbine in-
formation will be input)
Col. 50-53 Back pressure No. 3 in in. Hg
absolute (The third back pres-
sure for which turbine informa-
tion will be input)
Col. 54-57 Back pressure No. 4 in in. Hg
absolute (The fourth back
pressure for which turbine in-
formation will be input)
Col. 58-61 Back pressure No. 5 in in. Hg
absolute (The fifth back pres-
sure for which turbine informa-
tion will be input)
Col. 62-65 Back pressure No. 6 in in. Hg
absolute (The sixth back pres-
sure for which turbine informa-
tion will be input)
Col. 66-69 Back pressure No. 7 in in. Hg
absolute (The seventh back
pressure for which turbine in-
formation will be input)
Variable Name
XLDFT(4)
BPMNM(4)
XLDFT(5)
BPMNM(5)
XLDFT(6)
BPMNM(6)
BP(1)
BP(2)
BP(3)
BP(4)
BP(5)
BP(6)
BP(7)
H-10
-------
Variable Name
Col. 70-73 Back pressure No. 8 in in, Hg
absolute (The eighth back
pressure for which turbine in-
formation will be input) BP(8)
Col. 74-77 Back pressure No. 9 in in. Hg
absolute (The ninth back pres-
sure for which turbine informa-
tion will be input) BP(9)
12. Card No. 12
Col. 1-2 12 KNO
Col. 3-78 Back pressures No. 10 through
No. 28 (One back pressure is BP(10)
placed in every 4 columns) BP(28)
13. Card No. 13
Col. 1-2 13 KNO
Col. 3-7 Heat rate in BTU/KW-HR of plant
for load 1 at back pressure No. 1 HTRTD(1,1)
Col. 8-11 Heat rejected in MMBTU/hr by
steam turbine for load 1 at
back pressure No. 1 HTRJD(l.l)
Col. 12-16 Heat rate in BTU/KW-HR for load
1 at back pressure No. 2 HTRTD(2,1)
Col. 17-20 Heat rejected for load 1 at back
pressure No. 2 HTRJD(2,1)
Col. 21-25 Heat rate in BTU/KW-HR for load
1 at back pressure No. 3 HTRTD(3,1)
Col. 26-29 Heat rejected for load 1 at back
pressure No. 3 in MMBTU/hr HTRJD(3,1)
Continue until all back pressures are done for load 1. Then im-
mediately start load 2 at back pressure number 1. Do this until all
loads at all back pressures are entered. Each card should start with
H-ll
-------
the card number in columns 1 and 2 and contain data in column 3 through
column 74. Use as many cards as needed, until all back pressures and
loads are entered. Do not start a new card when starting a new load,
but repeat the same sequence begun for load 1 while using the remaining
usable columns on the partially completed card before going to a new
card.
H-12
-------
APPENDIX I
Program Listing.
1-1
-------
I
ro
PROGRAM MAINA(INPUT,OUTPUT,TAPE5=INPUT,TAPE6=OUTPUT) 00010
C *** DRY COOLING TOWER OPTIMIZATION COMPUTER PROGRAM 00020
C *** DEVELOPED BY PFR ENGINEERING SYSTEMS,INC. 00030
C »** LOS ANGELES, CALIFORNIA 00040
C *** JANUARY, 1977 OOO50
C *** AUTHORS - T2VI ROZENMAN, JAMES M. FAKE, JOSEPH M. PUNDYK 00060
C *** 00070
C *** COMMON VARIABLES USED 00080
c *** PERMANENT INTEGER 00090
COMMON NFO,KGO,KNTRO.KNTR1,NSUM,NPAGE,DAY(2),PI 00100
COMMON KCI,KER,KERR(20),KFIN,KREG,LAIC,LSUP,MM,NP,NR,NT1,NT2,NTP, 00110
1NTR,NTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 00120
2,DEN(2),DEN12(2,2) , DENFN,DENLZ(7),DBW,DEO,DFH,DFR,DFS,DFT.DKL, 00130
3DLSP,DLTE.DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT.PL.PT 00140
COMMON DPAD.DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT,DPTA,DPTF, 00150
1 DPTOT(2),POUT(2) ,PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTOT, 00160
20(2),QDUT.QTOT.RFI,RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 00170
3,TWALL,TDtTW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,V ISLZ(7), 00180
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLQ(2) 00190
COMMON ANG{3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC,F, 00200
1FALT,FINEF,FFF,FSUM1OCL(4),ODL(4)IOKL(4),OML(4),OMV(4),P,PRAN(2), 00210
2PRALZ(7),R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT.TLA, 00220
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20).ZTPPA 00230
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV,ZNFI,PTI,TKT,TKF, 00240
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2).RFD.PSD,TTMIN,OD(7), 00250
2CARD7(6),DNZI(2).PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2), 00260
3RASPC,ZTPD,ZNTD,COST(7),SSUM(16,30),ISUM(13,30),PRICE(2,21) 00270
CALL START 00280
100 CONTINUE 00290
200 CALL BOX 00300
C OPTM CONTROLS FINAL OUTPUT PRINTOUTS AND ALT.SOLUTIONS 00310
300 CALL OUTPT 00320
400 STOP 00330
END 00340
SUBROUTINE ACCOST(TSTS,NTT,NTR,NTP,DTI,DTD,NFPIN,DSL,DST.DHEDW.DL, 00350
1 DTN1I,DTN10,N001I,N0010,DTN2I,DTN20,N002I.N0020,ZBUP,ZFAN,DFAN, 00360
2 N8LD,NMOT,HPMOT,NBPU,DHSTR,KNTR1,CTTOT,CSTOR,DFH,DFT ) 00370
AIR COOLER COST CALCULATION 00380
COMMON/FAN/EFFAN,NBLAD,HPMSP 00390
DIMENSION CASEO) 00400
DIMENSION TRATY1O), T«ATY2(3), TRATY3O), TRATY(3) 00410
-------
c
c
c
C_— _
c ** *
c *•*
c ***
c *» +
_— -
c
c
c
c
c
c
c
c
c
c
c
c
c
DIMENSION FANTY(2),FANTY1(2),FANTY2(2),FANTY3(2)
DIMENSION ERT1(7), ERT2(7), ERT3(7), ERT(7)
DATA CASE /4HDRY ,4HTQWE,4HR 1/
DATA ERT1 / 4HSHOP.4H ERE.4HCT I .4HNDUC, 4HED D , 4HRAFT , 4HUNI T /
DATA ERT2 / 4HSHOP.4H ERE.4HCT F,4HORCE,4HD DR.4HAFT ,4HUNIT /
DATA ERT3 / 4HFIEL.4HD ER.4HECT ,4HUNIT,4H , 4H , 4H /
DATA FANTY1/4HPERM.4H FIX/
DATA FANTY2/4HMAN. ,4H ADJ/
DATA FANTY3/4HAUT0.4H VAR/
DATA TRATY1 / 4HDIRE.4HCT 0.4HRIVE /
DATA TRATY2 / 4HV-BE.4HLT ,4H /
DATA TRATY3 / 4HGEAR.4HBOX ,4H /
GENERAL ADMINISTRATION COST FACTOR IS ASSUMED AS 1.15
DATA GAFAC/1 . 15/
MATERIAL ESCALATION FACTOR IS ASSUMED 1.05
DATA ESCAL/1 .OS/
LABOR OVERHEAD FACTOR IS ASSUMED AS 2.0
DATA OVHDL/2.0/
COST OF ALUMINUM STRIP IS .80 $/LB
DATA CFIN/.8/
DATA CPLM1 .CPLL1/.25, .5/
DATA DENCS.DENAL/.2833, -0975/
DATA TSTOP,TSBOT,TSIDE,TBACK,TSPP/5*0.75/
DATA CUTT,CUTL,WLDT.WLDL,CHOLE,CASS/2.0,5.0,3.0,5.0,0.65,0.2/
DATA CTM.CTIB1 , DEN/0. 25 , 0.33 , 0 .2B33/
DATA KTUBE.KFIN/0,0/
DATA CTPG1 , ASPG1 / 1.0, 0.5 /
DATA CTUMT/ 3.0 /
DATA TSPLM /0.09/
DATA IDFAN/3/
DATA MORPM/3600/
NBPU = NUMBER OF BAYS IN PARALLEL PER UNIT
NBUP = NUMBER OF BUNDLES IN PARALLEL PER BAY
HPMOT = MOTOR HORSEPOWER
NFAN = NUMBER OF FANS PER BAY
DFAN = FAN DIAMETER (FT)
NBLD = NUMBER OF BLADES PER FAN
FPLM = COST INDEX FOR INSTALLING PLENUM BASED ON PLENUM MATERIAL
CPLM1 = UNIT COST FOR PLENUM MATERIAL ($/LB)
TSPLM = THICKNESS OF PLENUM (INCH)
NMOT = NUMBER OF MOTORS PER BAY
DLTTK=(DTO+DTI)/2.
IF THE NUMBER OF FINS PER INCH NFPIN IS NOT AN INTEGER
RUN WITH THE INTEGERS ABOVE AND BELOW TO CALCULATE THE
00420
00430
00440
00450
00460
00470
00480
00490
00500
00510
00520
00530
00540
00550
00560
f\ f\ c "7 n
OOb '0
00580
00590
00600
00610
00620
00630
00640
00650
00660
00670
00680
00690
00700
00710
00720
00730
00740
00750
00760
AH *7 7rt
UU f l \J
00780
00790
00800
00810
00820
00830
00840
00850
00860
00870
00880
00690
00900
00910
-------
c
c
c
COST OF THE FINNED TUBES, THEN TAKE AVERAGE VALUE
ZTT=NTT
ZTP=NTP
NFAN=ZFAN+.01
ZBPU=NBPU
ZBLD=NBLD
ZMOT=NMOT
Z001I=N001I
Z0010=N0010
Z002I=N002I
Z0020=N0020
C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
• CALCULATE THE FRONT HEADER COST, KTYPE=1
KTYPE=1
CALL HEAD(NTT,NTR,NTP,DSL,DST,DHEDW,DTI,DTO,TSTS,TSTOP,TSBOT,TSIDE
1 ,TBACK,TSPP,DEN,CTM,CUTT,CUTL,WLDT,WLDL,CHOLE,DTN1I,DTN10,CTPG1 ,AS
2PG1.KTYPE.CTHF.CTCUTF.CTWLDF.CTTPGF.CTFH.SLABF.SMATF.DIF.HIF.DWOF,
3DHOF,DDOF,NPPF,NPPB)
CALCULATE THE BACK HEADER COST, KTYPE=2
KTYPE=2
CALL HEAD(NTT,NTR,NTP,DSL,DST,DHEDW,DTI,DTO,TSTS,TSTOP,TSBOT,TSIDE
1,TBACK,TSPP,DEN,CTM,CUTT,CUTL,WLDT,WLDL,CHOLE(DTN2I,DTN20,CTPG1 ,AS
2PG1,KTYPE,CTHB,CTCUTB,CTWLD8,CTTPGB,CTBH,SLABS,SMATB,DIB,HIB,DWOB,
3DHOB,DDOB,NPPF,NPPB)
CALCULATE THE COST OF TUBE BUNDLES, INCLUDING ASSEMBLING
CALL BUNDLE(ZTT,DL,DHOF,DDOF,DDOB,DHEOW,CTIB1,WLDL,WLDT,CTUMT,KTUB
1E,KFIN,NFPIN,DDIB,WTIB,DLIB,CTUB1,CTUBE,CTUBA,CTUBW,CTBUN,CTIB,WLD
2IB,SLABT,SMATT,SUPPM,SUPPL,SUPP,DTO,DLTTK,DFH,DFTtWTUBF,CTUB,CFlN)
NOZZLE COST
CALCULATE THE COST FOR INSTALLING AN INLET NOZZLE ON FRONT HEADER
CALL NOZZLE(DTN1I.CTNZI1)
CALCULATE THE COST FOR INSTALLING AN OUTLET NOZZLE ON FRONT HEADER
CALL NOZZLE(DTN10,CTNZ01)
CALCULATE THE COST FOR INSTALLING AN OUTLET NOZZLE ON BACK HEADER
CALL NOZZLE(DTN20,CTNZ02)
TOTAL COST FOR THE NOZZLES
CTNOZ=Z001I*CTNZI1+ZOalO«CTNZ01+Za020«CTNZ02
00920
00930
00940
00950
00960
00970
00980
00990
01000
01010
01020
01030
01 040
01050
01060
01070
01080
01090
01 100
01 110
01 120
01 130
01 140
01 150
01 160
01 170
01 180
01 1 90
01200
01210
01220
01230
01240
01250
01260
01270
01280
01 290
01300
01310
01 320
01330
01340
01350
01360
01370
01380
01390
01400
01410
-------
I
Ol
C
c
C
c
c
c
c
c
c
c
c
CTNOZ=CTNOZ*ZBUP
CALCULATE THE COST OF PLENUM
CALL PLENUM(NFAN,DFAN,DL,DHEDW,TSPLM,DENCS,CPLM1.CPLL1.CTPLNI,PLMTL
1.PLLAB.ZBUP)
CALCULATE FANS COST
CALL FAN(NFAN,OFAN,NBLO,IDFAN,CFAN1.CTFAN)
CALCULATE MOTORS COST
*** SPECIFY MOTORS IN 25 HP INCREMENTS
XI=HPMOT/25.
I = XI
1=1*25+25
HPMSP=I
CALL MOTOR(NMOT,MORPM.HPMSP,CMOT1,CTMOT)
CALCULATE TRANSMISSION COST
CALL TRANS(NMQT,HPMSP,CTRAN,TRANC)
CALCULATE ERECTION COST
CALL EXSTP(ZBUP,NBLD,NFAN,ZBPU,CERCT)
CTACS=CTPLM+CTFAN+CTMOT+TRANC+CTNOZ
CTACO=CTACS*ZBPU
CALCULATE STRUCTURE COST
ASSUME STEEL INDEX IS U.S. AVERAGE AND ROOF LIVE LOAD OF 40 LB/FT2
DATA STLAD.RLL/0.,40./
TUBWT=WTUBF
CALL STRUCT(NTT,TUBWT,DL,DHEDW,RLL,DHSTR,STLAD,ZBUP.ZBPU.CTSTR)
SHIPPING COST IS 5.50 S/CWT BELOW 60 FEET AND 5.00 S/CWT ABOVE 60
ASSUME MODULES WEIGH 1.4 TIMES THE TUBE WEIGHT AS IN STRUCT
WSHIP=WTUBF*DL*ZTT*ZBUP*ZBPU*1.4
CSHIP=WSHIP*.025
IF(DL.GT.60. )CSHIP=VKSHIP*.05
TOTAL LABOR COST —
CTLAB=SLABF+SLABB+SLABT
CTLAB=CTLAB*ZBUP*ZBPU+PLLAB*ZBPU
TOTAL MATERIAL COST
CTMAT=SMATF+SMATB+SMATT
CTMAT=CTMAT*ZBUP*ZBPU+PLMTL*ZBPU
01420
01430
01440
01450
01460
01470
01480
01490
01500
01510
01520
01530
01540
01550
01560
01570
01580
01590
01600
01610
01620
01630
01640
01650
01660
01670
01680
01690
01 700
01710
01720
01 730
01 740
01750
01760
01770
01 780
01790
01800
01810
01820
01830
01840
01850
01860
01870
01880
01E90
01900
01910
-------
c
c
c ***
c
c == =
c
c
c == =
c «**
MINIMUM COST IS
CTACP=CTACO-ZBPU*CTPLM
TOTAL BASE COST FOR THE AIR COOLER ($) = = =
CTOT=GAFAC*(CTMAT*ESCAL+CTLAB*OVHDL+CTACP)
C
C
c
c
10
c
c
c
TOTAL FIRM PRICE FOR THE AIR COOLER ($) = = =
CALCULATE PROFIT FACTOR AS FUNCTION OF TOTAL COST
IF(CTOT-725.£06)4,4,2
FPROF=1.4-.044*ALOG10(CTOT)
GO TO 6
FPROF=1.01
CONTINUE
CTTOT=CTOT*FPROF
CSTOR=CTTOT
CTTOT = CTTOT-f-CERCT+CTSTR+CSHlP
IF(KNTR1.EO.O)GO TO 300
PRINT OUT FINAL RESULTS
WRITE(6,10)
FORMAT(1H1.55X.15HAIR COOLER COST)
NTRAN=NMOT
NBUP=ZBUP+.01
NBUNT=NBUP*NBPU
403 DO 430 1=1,7
430 ERT(I)=ERT3(I)
404 CONTINUE
C
C
IF (HPMOT.GT.7.5) GO TO 445
DO 441 1=1,3
441 TRATY(I)=TRATY1(I)
GO TO 452
445 CONTINUE
IF (HPMOT.GT.20.0) GO TO 449
DO 446 1 = 1 ,3
446 TRATY(I)=TRATY2(I)
GO TO 452
449 DO 450 1=1,3
01920
01930
01940
01 950
01960
01 970
01 980
01990
02000
02010
02020
02030
02040
02050
02060
02070
02080
02090
02100
021 10
02120
02130
02140
02150
02160
02170
02180
02190
02200
02210
02220
02230
02240
02250
02260
02270
02280
02290
02300
02310
02320
02330
02340
02350
02360
02370
02380
02390
02400
02410
-------
450 TRATY(I)=TRATY3(I)
452 CONTINUE
C
GO TO (432,434,436), IDFAN
432 DO 433 1=1,2
433 FANTY(I)=FANTY1(I)
GO TO 438
434 DO 435 1=1,2
435 FANTY(I)=FANTY2(I)
GO TO 438
436 DO 437 1=1,2
437 FANTY(I)=FANTY3(I)
438 CONTINUE
55 CONTINUE
CC=CSTOR+CERCT+CSHIP+CTSTR
WRITE(6,57)CC
57 FORMAT(1HO,29HTOTAL INSTALLED COST PER UNIT,23X,F12.2,2H $)
68 CONTINUE
C
C
C PRINT OUT DESIGN INFORMATION
C
63 WRITE(6,66)
66 FORMAT(/,2X,132(1H-),/)
69 CONTINUE
WRITE(6,60)
60 FORMAT(48X,31HHEAT EXCHANGER DESIGN VARIABLES,/)
WRITE(6,62) (CASE(I), 1=1.3), (ERT(I), 1=1,7)
62 FORMAT(1H .2X.7HCASE ID,18X,3A4,31X,7A4)
WRITE<6,64) NBPU.NBUNT
64 FORMAT(1H .2X.23HNO. OF BAYS IN PARALLEL,11X,13,31X,34HNO. OF BUND
1LE SECTIONS IN PARALLEL,15)
WRITE(6,70)
70 FORMAT(1H ,1X,132(1H-))
WRITE(6,75)
75 FORMAT(1H ,2X,*TU8E BUNDLE INFORMATION*,/)
WRITE(6,80) DL.DSL
80 FORMAT(1H ,7X,*BUNDLE LENGTH (FT)*,5X,F12.2,28X,*LONGITUDINAL PITC
1H*,4X,*(INCH)*,2X,F14.4)
WRITE(6,85) NTT.DST
85 FORMAT(1H ,7X,*TOTAL NUMBER OF TUBES *,I 9,31X,*TRANSVERSE PITCH
1 (INCH) *,F14.4)
WRITE(6.90) NTR.DTI
90 FORMAT(1H ,7X,*NUMBER OF TUBE ROWS
1TER (INCH) *,F12.2)
WRITE(6,91) NTP.DTO
91 FORMAT* 1H ,7X,*NUMBER OF TUBE PASSES
1TER (INCH) *,F12.2,/)
IF (KTUBE) 92,92,94
92 WRITE(6,93)DFH
*,I9.31X,*TUBE INSIDE DIAME
*,I9,31X,*TUBE OUTSIDE DIAME
02420
02430
02440
02450
02460
02470
02480
02490
02500
02510
02520
02530
02540
02550
02560
02570
02580
02590
02600
02610
02620
02630
02640
02650
02660
02670
02680
02690
02700
02710
02720
02730
02740
02750
02760
02770
02780
02790
02800
02810
02820
02830
02840
02B50
02860
02870
02880
02690
02900
02910
-------
CO
93 FORMAT(1H ,7X,9HTUBE TYPE,11X,17HROUND WELDED C.S.,26X,1OHFIN HEIG 02920
1HT.12X, 02930
16H(INCH),9X,F7.4) 02940
GO TO 96 02950
94 WRITE(6,95)DFH 02960
95 FORMAT(8X,9HTUBE TYPE.9X,19HROUND SEAMLESS C.S.,26X,1OHFIN HEIGHT, 02970
112X, 02980
16H(INCH),9X,F7.4) 02990
96 CONTINUE 03000
IF (KFIN) 97,97,99 03010
97 WRITE(6,98)DFT 03020
98 FORMAT(8X,9HFIN TYPE,9X,14HALUMINUNI L FIN.31X, 03030
113HFIN THICKNESS,9X, 03040
16H(INCH),9X,F7.4) 03050
GO TO 101 03060
99 WRITE(6,100JDFT 03070
100 FORMAT(SX,9HFIN TYPE,9X,14HALUMINUM G FIN.31X, 03080
113HFIN THICKNESS,9X, 03090
16H(INCH),9X,F7.4) 03100
101 CONTINUE 03110
ZFPIN=NFPIN 03120
WRITE(6,102)ZFPIN,WTUBF 03130
102 FORMATMH .7X.20HNO. OF FINS PER INCH,8X,F4.1,31X,30HWEIGHT OF FIN 03140
1 AND TUBE (LB/FT),7X,F6.3) 03150
WRITE(6,70) 03160
226 CONTINUE 03170
WRITE(6,230) 03180
230 FORMAT(1H ,2X,20HMECHANICAL EQUIPMENT) 03190
WRITE(6,232)(FANTY(I),I=1,2),MORPM,(TRATY(I),I=1,2) 03200
232 FORMAT(4X,9HFAN TYPE..14X,2A4,8X,11HMQTOR TYPE.,5X,3HA/C,16, 03210
14H RPM.6X,18HTRANSMISSION TYPE . ,6X , 3A4) 03220
WRITE(6,236) NFAN,NMOT,NTRAN 03230
236 FORMAT(1H ,7X,BHNO./BAY.,13X,12,18X,8HNO./BAY.,13X,12,19X,8HNO./BA 03240
1Y..13X.I2) 03250
WRITE(6,238) DFAN.HPMQT 03260
238 FORMAT(8X,13HDIAMETER (FT),7X,F6.2,12X,11HPOWER/MOTOR, 03270
112H -OPERATING ,F6.2) 03280
WRITE(6,240)NBLD,HPMSP 03290
240 FORMAT(8X,13HNO.BLADES/FAN,8X,12,26X.12H -INSTALLED ,F6.2) 03300
WRITE(6,70) 03310
WRITE(6,242) DHSTR 03320
242 FORMAT(1H ,2X.21HSTRUCTURE HEIGHT (FT),13X,F6.2) 03330
WRITE(6,70) 03340
300 RETURN 03350
END 03360
-------
I
ID
SUBROUTINE BOX
COMMON/EPA/TNMIN,TNMAX,TSAT(21),COSTT(21), X(10,21),XC(10),VAMAX ,
1VAMIN.VWMAX,VWMIN,XN,XP ,SUBCL,OMIN,OMAX,PITCH,DI A,
2RNGMX,RNGMN,TLMIN,TLMAX,TITDX,TITDN,TSATA,TSATZ,XHEAT(21)
COMMON IDUM,KGO,IDUM1(4),DUMP(3),IDUMW(34),DUMW(SB),
1 DTIM,DUME1 ( 4 ) , PT , DUMM( 1 07) , FALT , DUME2 ( 74 ) , ZTRD, ANGI , DUME3 ,
2ZBUP,DUME4(4),ZNF I ,PT1,DUME7(5),TAMB.HALT,C319,DUME9(4),RFC,
3DUME10(18),CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2),DUME11,
4ZTPD,DUNIE12,COST(7),DUIVIE14(912)
COMMON/PEN/ATTR(20),DATTR(20),AMBTPT(20).BCAPC,NATTR,CAPCST,CMAIN,
1MACC,AFCR2,XLVL,FLCST1CAPBS,PLDFT(20),STMCT,CUTMP,SHELP,BHTRT(6)
COMMON/STIN/XLDFT(6),BP(28),HTRTD(28t6),HTRJD(2B,6),NLODS,NBKPR
1 ,PLOAD.BPMNM(6) ,TPMNM(6)
COMMON/JUMP/JAKE,TINMX,N002I,DTN2I,N001I,NFPIN,N0020.N0010
COMMON/JAN7/WBMAX,PBPMN,TBPMN,CPEFF,WTEFF,PBPHT,EBPOM,PPOM,CWRTI,
1SCPMP,CCPMP,FDMAX,MXFBL,SPRNZ,SPRHT,CWTLV,DPPCT,PDMAX,CONCT
COMMON/PIPE/XDIA(20),XLGT(20),NN1,NN2.XTOWR,PLNMH,TTTBH,VX,VN
1,VAVE
COMMON/BCKPR/BCKMN,BCKMX
COMMON/FAST/STOW(3)
COMMON/SCOND/TTDMN,TTDMX,TISUM(21 )
COMMON/CASED/BARB(13)
READ(5,7)KNO,(BARB(I),I=1,13)
C *** READ CARD LEFT FROM ORIGINAL AC INPUT
READ(5,3)KNO,ANGI,ZBUP,ZNFI,PTI,HALT,COST(2),COST(6),ZTRD,ZTPD
ZNOZ(1)=2.
ZNOZ(2)=2.
NP = ZTPD-l-0.01
NTR=ZTRD+0.01
CALL INPUT
SET VARIABLES
STOW(1)=0.
STOW(2)=0.
STOW(3)=0.
N=6
JAKE=1
CALL EXINI
IF(KGO-1)2,2,300
2 CALL GEOM1
PITCH=PT
DIA=DTIM
C *** CALC FALT - CORRECTION TO AIR DENSITY
IF(HALT-4000.0)4,4,6
4 FALT=1 .-3.4E-5*HALT
GO TO 9
6 FALT=.985-3.025E-5*HALT
9 CONTINUE
C
C
C
03370
03380
03390
03400
03410
03420
03430
03440
03450
03460
03470
03480
03490
03500
03510
03520
03530
03540
03550
03560
03570
03580
03590
03600
03610
03620
03630
03640
03650
03660
03670
03680
03690
03700
03710
03720
03730
03740
03750
03760
03770
03780
03790
03800
03810
03820
03830
03840
03850
03860
-------
c
c
READ INPUT
i
H->
o
100 READ(5,150)KNO,TLMAX,TITDN,TOL,ALF,DELT,ITRMX,NITR,BCAPC,
1NATTR.CAPCST,TTOMN.TTDMX
READ(5,225)KNO,AFCR2,FLCST,TNMAX,TNMIN,(BHTRT(I) ,1 = 1,6)
READ(5,230)KNO,VAMAX,VAIYUN,VWMAX,VWMIN,RNGMX,RNGMN,TITDX,TLMIN,
1VX,VN,CONCT,STMCT,CUTMP,SHELP
C *** DETERMINE AVERAGE DESIGN VELOCITY FOR PIPING
VAVE=.5*(VX+VN)
READ(5,240)KNO,WBMAX,PDMAX,MXF8L,FDMAX,DPPCT,CWTLV,SPRHT,SPRNZ,
1SCPMP.PBPHT,CPEFF.WTEFF.CWRTI,EBPOM
DO 110 M=1,4
MM=1-t-(M-1 )*5
MMM=MM+4
110 READ(5,250)KNO,((ATTR(I),DATTR(I),PLDFT(1)),I=MM,MMM)
READ(5,325)KNO,NBKPR,NLODS,((XLDFT(I),BPMNM(I)),1=1,6),(BP(I),1=1,
19)
READ(5,350)KNO,(BP(I),I*10,28)
d=1
112 LSRT=1
114 LEFT=NBKPR-LSRT-H
IF(LEFT)116,116,118
116 d = d + 1
IF(J-NLODS)112,112,124
118 J1=J
I1ST=LSRT
IF(LEFT-8)122,120,120
120 I1END=LSRT-l-7
LSRT=LSRT+B
121 READ(5,375)KNOf((HTRTD(I,J1),HTRdD(I,d1)),I=I1ST,I1END)
GO TO 114
122 I1END=NBKPR
IF ( ( d-t-1 ) -N LODS) 1 26,126,123
123 LSRT=NBKPR+1
GO TO 121
126 d2=d+1
I2ST=1
MADD=8-LEFT
IF(MADD-NBKPR)128,130,130
128 I2END=MADD
d = J2
LSRT=MADD+1
GO TO 132
130 I2END=NBKPR
IF((d+2)-NLODS)135,135,131
131 LSRT=NBKPR+1
d = d2
132 READ(5,375)KNO,((HTRTD(I,d1),HTRdO(I,d1)),I=I1ST,I1END),
1 ((HTRTD(I.J2),HTRdD(I,d2)),I=I2ST,I2END)
GO TO 114
03870
0388C
03890
03900
03910
03920
03930
03940
03950
03960
03970
03980
03990
04000
04010
04020
04030
04040
04050
04060
04070
04080
04090
04100
041 10
04120
04130
04140
04150
04160
04170
04180
04190
04200
04210
04220
04230
04240
04250
04260
04270
04280
04290
04300
04310
04320
04330
04340
04350
04360
-------
135 J3=J+2
I3ST=1
I3END=MADD-NBKPR
J = J3
LSRT=I3END+1
REAO(5,375)KNO,((HTRTDd.vM),HTRJD(I,J1 )),1 = 11 ST,11 END),
1 ((HTRTD(I,J2),HTRJD(I.J2)),I=I2ST,I2END),
2 ((HTRTD(I,J3),HTROO(I,J3)),1=I3ST,I3END)
GO TO 114
124 CONTINUE
WRITE(6,199)ANGI,ZBUP,ZNFI,PTI.HALT.COST(2).COST(6)
125 WRITE(6,200)TLMAX,TITDN,TOL,ALF,DELT,ITRNIX,NITR,NP,NTR,BCAPC,
1NATTR.CAPCST
WRITE(6,175)AFCR2,FLCST,TNMAX,TNMIN,
WRITE(6,igOJVAMAX.VAMlN.VWMAX.VWMlN,
1.VX.VN.CONCT.STMCT.CUTMP.SHELP
WRITE(6,195)WBMAX,POMAX.MXFBL,FDMAX,DPPCT,CWTLV,SPRHT,SPRNZ,SCPMP,
.CWRTI.EBPOM
, TTDMN.TTDMX
, RNGMX.RNGMN.TITDX.TLMIN
1PBPHT,CPEFF,WTEFF,
Q1 1=0.
01=0.
CMAIN=0.
WRITE(6.270)
DO 140 1=1,NATTR
WRITE(6,275)ATTR(I).PLDFT(I),DATTR(I)
Q1=Q1+DATTR(I)
01 1=01 1+DATTR(I)*PLDFT( I )
C *** FIND APPROX. AVERAGE WEIGHTED ANNUAL POWER COST IN MILLS/KW
IF(PLDFT(I)-.999)139,136,136
136 IF(ATTR(I)-CUTMP)137,137,13B
137 CMAIN = CNIAIN+DATTR( I)*SHELP
GO TO 140
138 CMAIN=CMAIN+DATTR(I)*CDST(6)
GO TO 140
C *** ASSUME A HEAT RATE OF 9000 AT PART LOAD
139 CMA1N=CMAIN+DATTR(I)*FLCST*9.
140 CONTINUE
01 1=011/8760.
WRITE(6,276)01,011
WRITE(6,400)NLODS,NLODS,(XLDFT(I),I=1.NLODS),(XLDFT( I ) ,1 = 1 .NLODS)
WRITE(6,425)
DO 500 1=1.NBKPR
WRITE(6,450)BP(I),(HTRTD(I,J),d=1,NLODS).(HTRJD(I,J),J=1,NLODS)
500 CONTINUE
WRITE(6,475)(BPMNM(I),I=1,NLODS)
WRITE(6,480)(BHTRT(I),I=1,NLODS)
C *** CONVERT HEAT REJECT TO INTERNAL AND FIND QMIN AND QMAX
K = 0
BCKMN=50.
DO 40 1=1,NLODS
IF(BPMNM(I).LT.BCKMN)BCKMN=BPMNM(I)
04370
04380
04390
04400
04410
04420
04430
04440
04450
04460
04470
04480
04490
04500
04510
04520
04530
04540
04550
04560
04570
04580
04590
04600
04610
04620
04630
04640
04650
04660
04670
04680
04690
04700
04710
04720
04730
04740
04750
04760
04770
04780
04790
04800
04B10
04820
04830
04E40
04850
04860
-------
I
(-•
PO
TPMNM(I)=TSL(BPMNM(I))
IF(XLDFT(I)-.9999)25,20,20
20 K=I
25 DO 40 0=1,NBKPR
HTRJD(0,I)=HTRJD(J,I)*1.E+06
40 CONTINUE
IF(K.EO.O)WRITE(6,105)
IF(HTRJD(1,K)-HTRJD(NBKPR,K))50,50,60
50 CONTINUE
QMAX=HTRJD(NBKPR,K)
BCKMX=BP(NBKPR)
TINMX=TSL(BP(NBKPR))
GO TO 70
60 CONTINUE
QMAX=HTRJD(1,K)
BCKMX=BP(1)
TINMX=TSL(BP(1))
70 CONTINUE
ICOUNT=0
PMAX=1.
PMIN=.05
XN=NTR
XA1=VAMAX*PITCH*5./XN
XA2=VAMIN*PITCH*5./XN
XW1=VWMAX*19.635*01A**2/XP
XW2=VWMIN*19.635*DIA**2/XP
C *** MIN. DESIGN 0 IS WHEN FAN CONTROL NORMALLY WOULD START
CALL QTURB(QMIN,TPMNM(K),XLDFT(K),2)
85 ICOUNT=ICOUNT+1
C *** LOWEST POSSIBLE INLET AND OUTLET WATER TEMPERATURES
Q1=QMIN*1.000001
CALL QTURB(01,TLIW.1.,1)
TLIW=TLIW-TTDMX+459.67
TLOW=AMAX1(32.+459.67.TLIW-RNGMX)
C *** HIGHEST POSSIBLE INLET AND OUTLET WATER TEMPERATURES
01=QMAX*.999999
CALL QTURB(Q1,THIW,1.,1)
THIW=THIW-TTDMN+459.67
THOW=THIW-RNGMN
C *** LOWEST AND HIGHEST POSSIBLE INLET AIR TEMPERATURES
TLIA=AMAX1(409.67.TLIW-TITOX)
THIA=THIW-TITON
C *** PHYSICAL PROPERTIES AT LOWEST AVERAGE WATER TEMPERATURE
TAV=.5*(TLIW+TLOW)
TAV=TAV-459.67
CALL PPAUT1(TAV,CPLW,DENW,D1,D3,KODE)
C *** PHYSICAL PROPERTIES AT HIGHEST AVERAGE WATER TEMPERATURE
TAV=.5*(THIW+THOW)
TAV=TAV-459.67
04870
04880
04890
04900
04910
04920
04930
04940
04950
04960
04970
04980
04990
05000
05010
05020
05030
05040
05050
05060
05070
05080
05090
05100
05110
05120
05130
05140
05150
05160
05170
05180
05190
05200
05210
05220
05230
05240
05250
05260
05270
05280
05290
05300
05310
05320
05330
05340
05350
05360
-------
CALL PPAUT1(TAV,CPW.DENLW,D1,D3,KODE) 05370
C *** PHYSICAL PROPERTIES AT LOWEST INLET AIR TEMPERATURE 05380
CALL PPROP(TLIA,14.7,2,DENA,D3,CPLA,D4,05,0,2) 05390
C *** PHYSICAL PROPERTIES AT HIGHEST INLET AIR TEMPERATURE 05400
CALL PPROP(THIA,14.7,2,DENLA,D3,CPA,04,05,0,2) 05410
TT=THIW-459.67 05420
TTT=TT-32. 05430
C *** TEMPORARILY 00 NOT ALLOW AN ITD DESIGN THAT WILL CAUSE BACK 05440
C *** PRESSURE TO EXCEED MAXIMUM AT HOTTEST AMBIENT. EVENTUALLY THE 05450
C *** PROGRAM MUST RECOGNIZE THIS CONDITION AND REDUCE TURBINE LOAD. 05460
TITDX=AMIN1(TT+50..TITDX,(TINMX-TTDMX-ATTR(1)-3.)) 05470
RNGMX=AMIN1(TTT.RNGMX) 05480
C 05490
C *** TIGHTEN UP CONSTRAINTS IF POSSIBLE 05500
C 05510
TNMIN1=QMIN/RNGMX/DENW/XW1/CPW 05520
TNMIN=AMAX1(TNMIN.TNMIN1) 05530
TNMAX1=QMAX/RNGMN/DENLW/XW2/CPLW 05540
TNMAX=AMIN1(TNMAX,TNMAX1) 05550
RNGMX2=TNMAX1*RNGMN/TNMIN 05560
RNGMN2=TNMIN1*RNGMX/TNMAX 05570
RNGMX=AMIN1 (RNGMX,RNGMX2 ) 05580
RNGMN=AMAX1(RNGMN,RNGMN2) 05590
QMAX4=CPW*RNGMX*XW1*DENW*TNMAX 05600
QMIN4=CPLW*RNGMN*XW2*DENLW*TNMIN 05610
QMAX=AMIN1(QMAX.QMAX4) 05620
QMIN=AMAX1(QMIN.QMIN4) 05630
PMAX1=CMAX/CPLA/TITDN/XA2/DENLA/TLMIN/TNMIN 05640
PMIN1=QNIIN/CPA/TITDX/XA1/DENA/TLMAX/TNMAX 05650
PMAX=AMIN1(PMAX1,PMAX) 05660
PMIN=AMAX1(PMIN1,PMIN) 05670
TITOX2=PMAX1*TITDN/PMIN 05680
TITDN2=PMIN1*TITDX/PMAX 05690
TITDX=AMIN1(TITDX,TITDX2) 05700
TITDN=AMAX1(TITDN.TITDN2) 05710
PITDMN=TITDN2*PMAX 05720
PITDMX=TITDX2*PMIN 05730
PITDN2=PMIN*TITDN 05740
PITDX2=PMAX*TITDX 05750
PITDN1N = AMAX1 (PITDMN, PITDN2) 05760
PITDMX=AMIN1(PITDMX.PITDX2) 05770
TLMAX2=QMAX/CPLA/XA2/PITDMN/DENLA/TNMIN 05780
TLMIN2=QMIN/CPA/XA1/PITDMX/DENA/TNMAX 05790
TLMIN=AMAX1(TLMIN.TLMIN2) 05800
TLMAX=AMIN1(TLMAX.TLMAX2) 05810
TNMIN2=TLMIN2*TNMAX/TLMAX 05820
TNMAX2=TLMAX2*TNMIN/TLMIN 05830
TNMIN=AMAX1(TNMIN,TNMIN2) 05840
TNMAX=AMIN1(TNMAX,TNMAX2) 05850
RNGMX3=CPA*PITDMX *XA1»DENA*TLMAX/CPLW/XW2/DENLW 05860
-------
RNGMN3=CPLA*PITDMN *XA2*DENLA*TLMIN/CPW/XW1/DENW 05870
RNGMN=AMAX1(RNGMN,RNGMN3) 05880
RNGMX=AMIN1(RNGMX,RNGMX3) 05890
PMAX2=RNGMX/RNGMN3*PITDMN/TITDN 05900
PMIN2=RNGMN/RNGMX3*PITDMX/TITDX 05910
PMIN=AMAX1(PMIN,PMIN2) 05920
PMAX=AMIN1(PMAX,PMAX2) 05930
TITDX3=PMAX2*TITDN/PMIN 05940
TITDN3=PMIN2*TITDX/PMAX 05950
TITDX=AMIN1(TITDX.TITDX3) 05960
TITDN=AMAX1(TITDN,TITON3) 05970
PITDN3=PMIN*TITDN 05980
PITDX3=PMAX*TITDX 05990
PITDMN=AMAX1(PITOMN.PITDN3) 06000
PITDMX=AMINt(PITDMX.PITDX3) 06010
TLMIN3=CPLW*RNGMN*XW2*DENLW/CPA/PITDMX/XA1/DENA 06020
TLMAX3=CPW*RNGMX*XW1*DENW/CPLA/PITDMN/XA2/DENLA 06030
TLMINUAMAX1(TLMIN.TLMIN3) 06040
TLMAX=AMIN1(TLMAX.TLMAX3) 06050
QMAX5=CPA*PITDMX *XA1*DENA*TLMAX*TNMAX 06060
OMIN5=CPLA*PITDMN *XA2*DENLA*TLMIN*TNNIIN 06070
OMAX=AMIN1(QMAX.OMAX5) 06080
QMIN=AMAX1(OMIN.OMIN5) 06090
C 06100
C *** CHECK FOR INCONSISTANCIES IN CONSTRAINTS 06110
C 06120
IF(PMIN.GT.(PMAX+.01))GO TO 322 06130
IF(RNGMN.GT.(RNGMX+1.))GO TO 305 06140
IF(TITDN.GT.(TITDX-M .))GO TO 310 06150
IF(TLMIN.GT.(TLMAX-I-.3))GO TO 315 06160
C 06170
IF(TNMIN.GT.(1.005*TNMAX))GO TO 320 06180
C 06190
C *«* SEE IF QMIN AND QMAX CAN BE FURTHER CONSTRAINED 06200
ZRN=32.+TTDMN+RNGMN 06210
CALL QTURB(QMIN3,ZRN,1.,2) 06220
OMIN=AMAX1(QMIN.QMIN3) 06230
C *** RUN THROUGH CONSTRAINTS ONCE MORE 06240
IF(ICOUNT.EQ.1)GO TO 85 06250
C *** SET WIN AND MAX SATURATION TEMPERATURES 06260
Q1=QMIN*1.000001 06270
CALL QTURB(Q1,TSATA,1.,1) 06280
01=QMAX*.999999 06290
CALL OTURB(Q1,TSATZ,1.,1) 06300
IF(QMIN.GT.(1.001*OMAX))GO TO 321 06310
C 06320
C CALL SUBROUTINE TO PERFORM BOX OPTIMIZATION 06330
C 06340
CAUL NldBOX(TOL,ALF,DELT,ITRMX,NITR,N) 06350
C 06360
-------
I
I—>
CJ1
105 FORMAT(///,33H CAUTION. NO LOAD OF 1. WAS INPUT) 06370
3 FORMAT(12,F5.0,F2.0,2F5.0,F6.0,2F4.0,F3.0,F4.0) 06380
7 FORMAT(12,13A5) 06390
150 FORMAT(I2,F6.2,F5.2,F4.2,2F4.2,2I3,F6.1,12,F5.1 ,2F4.1 ) 06400
175 FORMAT(9X,42HAFCR2 FLCST TNMAX TNMIN TTDMN TTDMX,/,6X, 06410
12F7.2,1X,2F9.0,2F6.1,/) 06120
190 FORMAT(9X.48HVAMAX VAMIN VWMAX VWMIN RNGMX RNGMN TITDX TLMIN, 06430
138H VX VN CONCT STMCT CUTMP SHELP,/,8X,2F6.1 ,1X ,8F6.1, 06440
22F7.2.F6.1,F6.2,/) 06450
195 FORMAT(9X.49HWBMAX PDMAX MXFBL FOMAX DPPCT CWTLV SPRHT SPRNZ , 06460
137HSCPMP PBPHT CPEFF WTEFF CWRTI EBPOM,/,8X,F6.2,F6.1,15,F8.1, 06470'
2F6.0.2F6.1,F6.2.2F6.1,2F7.3,F6.1,F6.3,//) 06480
199 FORMAT(1H1,1X.38HINPUT: ANGI ZBUP ZNFI PTI HALT , 06490
111HCOST2 C05T6,/,7X,F6.1 . F7.0,F7.1 ,F4.1,F7.0,F6.2,F6.1,/) 06500
200 FQRMAT(9X,37HTLMAX TlTDN TOL ALF DELT ITRMX, 06510
133H NITR NP NTR BCAPC NATTR CAPCST,/,7X,2F7.2,F6.3,F5.1,F7.3, 06520
2I6,I5,I4,I3,F7.0,I5,F10.1,/) 06530
225 FQRMAT(12,F3.1,F4.2,8F7.0) 06540
230 FORMAT!12,2F5.1,2F4.1,3F5.1,3F4.1,F4.2,F6.3,F5.1 ,F5.2 ) 06550
240 FORMAT(I2,F5.2,F5.1,12,F4.1,F5.0,2F4.1,F5.2,F6.0,F4.1,2F3.1,F5.1, 06560
1F4.1) 06570
250 FORMAT(I2,5(F5.1,F6.1,F4.2)) 06580
270 FORMAT(1X,26HTEMPERATURE - LOAD PROFILE,/,1X,26(1H-),/, 06590
120H TEMP LOAD HOURS) 06600
275 FORMAT(1X,F6.1,F6.2,F7.0) 06610
276 FORMAT(15X,5H ,/,14X,F6.0,12H TOTAL HOURS,//,14X,F6.3, 06620
112H LOAD FACTOR) 06630
325 FORMAT(2I2,I 1 ,12F3.2.9F4.0) 06640
350 FQRMAT(12,19F4.0) 06650
375 FORMAT(I2,8(F5.0,F4.0)) 06660
400 FORMAT(1H1,42X,11(1H+),27H STEAM TURBINE INFORMATION ,11(1H*),//, 06670
113H **THE FIRST ,I1,22H COLUMNS ARE HEAT RATE./.13H ***THE LAST , 06680
211,24H COLUMNS ARE HEAT REJECT,/,7H -LOAD-,/,5X,18F7.2) 06690
425 FORMAT(/,4H BP./.4H —) 06700
450 FORMAT(1X.F4.1,18F7.0) 06710
475 FORMAT(/,37H MINIMUM BACK PRESSURE AT ABOVE LOADS,/,5X,9F7.2) 06720
480 FORMAT(/,40H COMPARATIVE HEAT RATE AT ABOVE LOADS TO,/, 06730
132H DETERMINE INCREMENTAL FUEL COST,/,5X,6F7.0) 06740
300 CONTINUE 06750
GO TO 600 06760
305 WRITE(6,306)RNGMN,RNGMX 06770
306 FORMAT(///,8H RNGMN= ,E12.5,8H RNGMX* ,E12.5) 06780
GO TO 322 06790
310 WRITE(6,311)TITDN,TITDX 06800
311 FORMAT(///,8H TITDN= ,E12.5,8H TITDX= ,E12.5) 06810
GO TO 322 06820
315 WRITE(6,316)TLMIN,TLMAX 06830
316 FORMAT(///,8H TLMIN= ,E12.5,8H TLMAX= .E12.5) 06840
GO TO 322 06850
319 FORMAT(///,8H TNMIN= .E12.5.8H TNMAX= .E12.5) 06860
-------
320 WRITE(6,319)TNMIN,TNMAX
GO TO 322
321 WRITE(6,323)QMIN,QMAX
322 WRITE(6,312)
323 FORMAT(///,8H QMINs .E12.5.8H QMAX = ,E12.5)
312 FORMAT(///,45H BOX CANNOT PROCEED. CASE IS OVER CONSTRAINED)
600 TAMB=0.0
RETURN
END
06870
06880
06890
06900
06910
06920
06930
06940
06950
i
h-»
cn
SUBROUTINE BUNDLE(ZTT,01,DHOF,DDOF,DDOB,DHEDW,CTIB1 ,WLDL,WLDT,CTUM
1T,KTUBE,KFIN,NFPIN,DDIB,WTIB,DUB,CTUB1,CTUBE,CTUBA,CTUBW,CTBUN,CT
2IB,WLDIB,SLABT,SMATT,SUPPM,SUPPL,SUPP,DTO,DLTTKtDFH,DFT,WTUBF,CTUB
3.CFIN)
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
*** INPUT
ZTT
DL
DHOF
DDOF
DDOB
DHEDW
CTIB1
WLDL
WLDT
CTUMT
KTUBE
KFIN
NFPIN
*** OUTPUT
DDIB
WTIB
DLIB
CTUB1
CTBUN
SUPP
SLABT
SMATT
VARIABLES ***
= NTT, TOTAL NUMBER OF TUBES
= TUBE BUNDLE LENGTH (FT)
= OUTSIDE HEIGHT OF FRONT HEADER (INCH)
= OUTSIDE DEPTH OF FRONT HEADER (INCH)
= OUTSIDE DEPTH OF BACK HEADER (INCH)
= BUNDLE WIDTH (INCH)
= UNIT COST FOR I-BEAM ($/LB)
=WELDING LABOR COST ($/HR)
= WELDING SPEED (WIN/INCH)
= TUBE ASSEMBLING LABOR COST ( $/HR )
= 0 FOR WELDED TUBE, 1 FOR SEAMLESS TUBE
= 0 FOR L FIN, 1 FOR G FIN
= NUMBER OF FINS PER INCH
VARIABLES ***
= I-BEAM DEPTH (INCH)
= UNIT WEIGHT OF I-BEAM (LB/FT)
= LENGTH OF I-BEAM (FT)
= UNIT TUBE COST ($/FT)
= TOTAL COST FOR THE TUBE BUNDLE SECTION ($)
= COST FOR SUPPORTS ($)
= TOTAL LABOR COST FOR THE BUNDLE ($)
= TOTAL MATERIAL COST FOR THE BUNDLE ($)
06960
06970
06980
06990
07000
07010
07020
07030
07040
07050
07060
07070
07080
07090
07100
071 10
07120
07130
07140
07150
07160
07170
07180
07190
07200
07210
07220
07230
07240
07250
07260
07270
-------
c
C COST OF TUBE MATERIAL
C *** CALL TUBEF TO CALCULATE COST OF ANY TYPE OF BARE OR FINNED TUBES
C *** (DATA AS OF APRIL,1976)
CALL TUBEF(KTUBE,KFIN,NFPIN.DTO.OLTTK,DFH,DFT,WTUBE,WFIN,WTUBF,
1ATUBE,BFIN,CTUB1.CTUB.CFIN)
CTUBE=ZTT*DL*CTUB1
C
C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
ASSEMBLING COST ($)
BUNDLE ASSEMBLING REQUIRES TWO MAN, 15 MINUTES TO MOUNT ONE TUBE
ONTO THE TUBE SHEETS
CTUMT=3.0 $/HR
ASSEMBLING COST IS PROPORTIONAL TO BUNDLE LENGTH
ASSUME 1.0 HR FOR 80 FT, 0.5 HR FOR 40 FT TUBE LENGTH
CTUBA=2.0*ZTT*(0.75*OL)/60.0*CTUMT
BUNDLE MELDING REQUIRES ONE MAN 15 MINUTES TO WELD ONE TUBE
END ONTO A HOLE
CTUBW=2.0*ZTT*15.0/60.0*WLDL
CTBUN=CTUBE+CTUBA+CTUBW
THERE ARE TWO I-BEAMS TO SUPPORT THE BUNDLES
DHO=DHOF
IF (DHO-AINT(DHQ)) 60,60,70
60 CONTINUE
DDIB=AINT(OHO)
GO TO 80
70 CONTINUE
DDIB = AINT(DHO)-M .0
80 CONTINUE
USE THE SPECIFICATIONS OF (( AMERICAN STANDARD CHANNELS ))
HERE CONFINE THE DEPTH OF I-BEAM IN THE RANGE OF 9 TO 18 FT
WTIB = UNIT WEIGHT OF I-BEAM (LB/FT)
IF(DDIB-8.)82,82,84
82 CONTINUE
WTIB=1.567*(DDIB-3.)+4.
GO TO 200
84 CONTINUE
07280
07290
07300
07310
07320
07330
07340
07350
07360
07370
07380
07390
07400
07410
07420
07430
07440
07450
07460
07470
07480
07490
07500
07510
07520
07530
07540
07550
07560
07570
07580
07590
07600
07610
07620
07630
07640
07650
07660
07670
07680
07690
07700
07710
07720
07730
07740
07730
07750
07770
-------
I
(—»
00
IF (DDIB-9.0) 90,90,100
90 CONTINUE
WTIB=13.4
GO TO 200
100 CONTINUE
IF (DDIB-10.0) 110,110,120
110 CONTINUE
WTIB=15.3
GO TO 200
120 CONTINUE
IF (DDIB-12.0) 130,130,140
130 CONTINUE
WTIB=20.7
GO TO 200
140 CONTINUE
IF (DDIB-15.0) 150,150,160
150 CONTINUE
WTIB=33.9
GO TO 200
160 CONTINUE
IF (DDIB-18.0) 170,170,180
170 CONTINUE
WTIB=42.7
GO TO 200
180 CONTINUE
*** HERE THE I-BEAM DEPTH EXCEEDS THE AMERICAN CHANNELS SPECS.
*** SO WTIB IS ESTIMATED BY EXTRAPOLATION
WTIB=3.31*(DDIB-10.J+15.3
C
c
C
c
c
c
c
c
c
c
c
c
c
c
c
200 CONTINUE
LENGTH OF I-BEAM (FT)
DLIB=DL+(DDOF+DDOB)/12.0
WEIGHT OF I-BEAM (LB)
WTIB1=WTIB*DLIB
WEIGHT FOR TWO I-BEAMS (LB)
WTIB2=WTIB1*2.0
I-BEAM MATERIAL COST ($)
CTIB=CTIB1*WTIB2
I-BEAM WELDING COST ($)
WLDIB=2.0*(DDOF+DDOB)*WLDL*WLDT/60.0
EVERY 6 FT ALONG THE BUNDLE LENGTH, THERE ARE TUBE SPACERS,
TUBE KEEPERS AND SUBE SUPPORTS
TO CALCULATE DETAILED MATERIAL AND LABOR COST OF THE SUPPORTS,
07780
07790
07800
07810
07820
07830
07840
07850
07860
07870
07880
07890
07900
07910
07920
07930
07940
07950
07960
07970
07980
07990
08000
08010
08020
08030
08040
08050
08060
08070
08080
08090
08100
081 10
08120
08130
08140
08150
08160
08170
08180
08190
08200
08210
08220
08230
08240
08250
08260
08270
-------
c
c
c
c
c
c
c
c
c
SUPPORTS DIMENSIONS MUST BE GIVEN
HERE, ASSUME THAT THE COST FOR EVERY 6 FT SUPPORTS IS CTSP1 ($)
CTSP1 IS PROPORTIONAL TO BUNDLE WIDTH
AK=0.5
CTSP1=AK*DHEDW
ISUPP=INT(DL)/6
IF (DL/6.0-FLOAT(ISUPP)) 202,202,204
202 CONTINUE
I5UPP=ISUPP-1
204 CONTINUE
SUPPM=CTSP1*FLOAT(ISUPP)
ASSUME THE ASSEMBLING COST FOR TUBE SUPPORTS IS THE SAME FOR
SUPPORTS MATERIALS
SUPPL=SUPPM
SUPP=CTIB+WLDIB+SUPPM+SUPPL
SLABT=CTUBA+CTUBW+WLDIB+SUPPL
SMATT=CTUBE+CTIB+SUPPM
400 CONTINUE
RETURN
END
08280
08290
08300
08310
08320
08330
08340
08350
08360
08370
08380
08390
08400
08410
08420
08430
08440
08450
08460
08470
08480
08490
08500
08510
08520
08530
C
C
C
C
SUBROUTINE CENT(J ,N , KN,JHIGH)
COMMON/EPA/TNMIN,TNMAX,TSAT(21),COSTT(21),X(10,21),XC(10),VAMAX,
1VAMIN,VWMAX,VWMIN,XN,XP,SUBCL,QMIN,QMAX,PITCH,DI A,
2RNGMX,RNGMN,T LMIN,TLMAX,TITDX,TI TON
THIS SUBROUTINE CALCULATES THE CENTROID. OF THE KN POINTS
ONLY POINT J IS NOT INCLUDED.
NN=KN-1
XNK=NN
IF(JHIGH.NE.O) GO TO 350
DO 100 1=1,N
XC(I)=0.
100 CONTINUE
DO 200 1=1,KN
08540
06550
08560
OB570
08580
08590
08600
08610
08620
08630
08640
08650
08660
08670
08680
-------
DO 200 11 = 1 ,N
c
c
c
c
c
200 CONTINUE
DO 300 1=1 ,N
XC(I)=(XC(I)-X(I,J))/XNK
300 CONTINUE
GO TO 500
IF THE CENTROID HAS BEEN CALCULATED FOR A PREVIOUS CASE,
THE NEW ONE IS SIMPLY THE OLD CENTROID LESS THE J POINT
WITH THE JHIGH POINT ADDED BACK IN.
350 DO 400 1=1 ,N
XC(I)=XC(I)+(X(I.JHIGH)-X(I,J))/XNK
400 CONTINUE
500 CONTINUE
RETURN
END
08690
08700
08710
08720
08730
08740
08750
08760
08770
08780
08790
08800
08810
08320
08830
08840
08850
08860
ro
O
SUBROUTINE CFIXM(VALUE,VAMIN,VAMAX,RESET,KERN,KERRO,NERC) 08870
C *** LIMITS VALUES OF INPUT DATA AND STORES GREY ERROR MESSAGE CODES 08880
DIMENSION KERRO(I) 08890
IF (VALUE-VAMAX) 10,20,20 08900
10 IF (VAMIN-VALUE) 100,15,15 08910
15 VALUE=RESET 08920
GO TO 100 08930
20 VALUE=RESET 08940
CALL ERORG (NERC,KERRO,KERN) 08950
100 RETURN 08960
END 08970
-------
SUBROUTINE CHANL(NFO.ZBYP,VALVE.NPUMP,PPGPM,PUMPC,IXNL,PUMPF,VFILL
1,TANKC,CONTR,BLANN,SHIPCO,CAPIP,NTANK,INML)
COMMON/BCK/XIYICST(20),PIPDM(20),XSHOP(20),FIELD(20),EXJOT(20)
DIMENSION MPRNT(44),VALVE(1)
DATA MPRNT/10HINLET FEED.10HER LINE
10HINLET
10H
10H
10H
10H
10H
10H
10HBAY
1 ,
2,
3,
4,
5,
6,
7,
B,
9.
1 ,
2/
HEAD.10HER
,10H
,10H
,10H
,10H
,10H
,10H
CONTR0.10HL
10HRECVRY TUR.10HBINE ISO.
10HFILL PUMP .10HISOLATION
.10HOUTLET FEE,
,10HOUTLET HEA,
,10H
,10H
,10H
, 10H
,10H
,10H
.10HCOND. PUMP,
.10HBYPASS ,
.10HFILL DRAIN,
10HDER LINE
10HDER
10H
10H
1 OH
1 OH
10H
10H
10H ISOLATION
10H
10H
1000 FORMAT(1H1,20X,9(1H*),38H BACK-TO-BACK DRY TOWER PIPING COST ,
112HBREAKDOWN ,9(1H*),//,31X,30HDIAMETER TOTAL SYSTEM,/,
233X,4H(IN),19X,5HTOTAL,/,13H A BAY PIPING,17X,20(1H-))
1025 FORMAT(3X,11,2H. , 2A10,6X,F7.2,F11 .0)
1075 FORMAT(39X,2X,9H ,/,6X,1OHPIPING/BAY,23X,F11 .0 ,/,7X ,
1F4 0 5H BAYS,34X,F11.0,/,16H B SUPPLY PIPING,6H(TYPE .11,1H))
5025 FORMAT139X.2X.9H ,/.39X,2F11.0,//,16H C RETURN PIPING,
16H(TYPE ,11,1H))
5075 FORMAT (39X.2X.9H ,/,39X,2F1 1 .O,/)
6000 FORMAT(13H D FILL LINES,19X,F7.2,2F11.0,/)
6010 FORMATJ15H E BYPASS LINES,17X,F7.2,2F11.0,//, 1 8H F VALVING(INSTALL
13HED) )
6030 FORMAT(3X, 11 ,2H. , 2A10,6X , F7.2,F11 .0)
6040 FORMAT(4*X,9(1H-),/,39X,2F11.O,/)
6050 FORMAT(19H G PUMPS(INSTALLED),/,6H 1
I2.F8.0.10H GPM COND..13X
1 2F11 0 / 6H 2. ,I2,1BH 10000 GPM FILL , 13X , 2F11 .0 , /)
6060 FORMAT(26H H STORAGE TANK(INSTALLED),/,1X,I 4,2H -,F9.0,
110H GAL TANKS,13X,2F11.O,/)
6070 FORMAT(26H I CONTPBLSCINSTALLED) .13X.2F11.0)
6080 FORMAT(26H J N'TRQCLN BLANKETING .13X.2F11.0)
6090 FORMAT(26H K SHIPMENT OF PIPING .13X.2F11.0)
6250 FORMAT(52X,9(1H-) ,/,50X,F11.0)
2010 WRITE!NFO,1000)
TOTOX=0.
DO 1050 1=1,4
TOTO=XMCST ( I )+XSHOP( I )+FIELD( I )
i°ITElNFO?1025')°,MPRNT(2*I-1),MPRNT(2*I),PIPDM(I),TOTO
1050 CONTINUE
TTOV=ZBYP*TOTOX
VgRITE(NF0.1075)TOTOX,ZBYP,TTOV,INML
TOTOX=0.
08980
08990
09000
09010
09020
09030
09040
09050
09060
09070
09080
09090
09100
091 10
09120
09130
09140
09150
09160
09170
09180
09190
09200
09210
09220
09230
09240
09250
09260
09270
09280
09290
09300
09310
09320
09330
09340
09350
09360
09370
09380
09390
09400
09410
09420
09430
09410
09450
09460
09470
-------
TOTOX=TOTOX+TOTO 09480
WRITE(NFO,1025)I,VPRNT(2*H-7),MPRNT(2«.H.8),PIPDM(H-4),TOTO 09490
5000 CONTINUE 09500
WRITE(NFO,5025)TOTOX.TOTOX.INML 09510
TOTOX=0. 0952°
DO 5050 1 = 1,6 09"0
TOTO = XMCST(I-HO)+XSHOP(I-MO) + FIELD(I + 10)+EXJOT(I + 10) 09540
TOTOX=TOTOX+TOTO 09550
WRITE(NFO,1025)I.MPRNT(2*1+19),MPRNT(2*1+20),PIPDM(I+10),TOTO 09560
5050 CONTINUE 09570
WRITE(NFO,5075)TOTOX,TOTOX 09580
TOTO=XMCST(17)+XSHOP(17)+FIELD(17)+EXJOT(17) 09590
WRITE(NFO,6000)PIPDM(17),TOTO,TOTO 09600
TOTO=XMCST(18)+XSHOP(18)+FIELD(18)+EXJOT(18) 09610
WRITE(NFO,6010)PIPDM(l6),TOTO,TOTO 09620
TOTOX=0. 09630
DO 6020 1=1,6 09640
TOTOX=TOTOX+VALVE(I) 09650
J=5 09660
IF(I.E0.1)d=1 0967°
IF(I.GT.4)J=17 ' 0968°
WRITE(NFO,6030)I,MPRNT(2*I+31),MPRNT(2»H-32),PIPDM(U),VALVE(I) 09690
6020 CONTINUE 09700
WRITE(NFO,6040)TOTOX,TOTOX 09710
WRITEfNFO 6050}NPUMP,PPGPM,PUMPC,PUMPC,IXNL,PUMPF,PUMPF 09720
WRITE(NFO.6060)NTANK,VFILL,TANKC,TANKC 09730
WRITE(NFO,6070)CONTR,CONTR 09740
WRITE(NFO,6080)BLANN,BUANN 09750
WRITE(NFO.6090JSHIPCO,SHIPCO 09760
WRITE(NFO,6250)CAPIP 09770
RETURN 0978°
END 0979°
SUBROUTINE CONST(J.DELT) 09800
COMMON/EPA/TNMIN,TNMAX,TSAT(21),COSTT(21),X(10,21),XC(10),VAMAX, 09810
1VAMIN,VWMAX,VWMIN,XNfXP,SUBCL,OMIN,QMAX.PITCH,DIA, 09820
2RNGMX,RNGMN,TLMIN,TLMAX,TITDX,TITDN,TSATA,TSATZ,XHEAT(21) 09830
COMMON/SCOND/TTDMN.TTDMX,TISUM(21) 09840
09850
THIS SUBROUTINE DETERMINES IF POINT J IS WITHIN CONSTRAINTS 09860
IF IT IS NOT,IT IS MOVED A SMALL PERCENTAGE,DELT,OF THE DISTANCE 09870
FROM THE BOUNDARY TO THE CENTROID 09880
-------
ro
co
IF(X(1,J).LT.TSATA)X(1,d)=TSATA-DELT*(TSATA-XC(1))
IF(X(1,J).GT.TSATZ)X(1,J)=TSATZ-DELT*(TSATZ-XC(1 ))
TSAT(J)=X(1,0)
CALL QTURB(XHEAT(J),TSAT(d),1,,2)
IF(X(6td).LT.TTDMN)X(6,J) = TTDMX-DELT*(TTDMX-XC(6))
SUBCL=X(6,J)
TITD=AMIN1(TITDX,(TSAT(J)-SUBCL+50.))
IF(X(2,J).LT.TITDN) X(2,J)=TITON -DELT*(TITDN -XC(2))
IF(X(2,d).GT.TITD) X(2.J)=TITD -DELT*ABS(TITD -XC(2))
IF(X(3,d).LT.RNGMN) X(3,J)=RNGMN-DELT*(RNGMN-XC(3))
RNG=AMIN1(RNGMX,X(2,d)*.99,(TSAT(d)-SUBCL~32.))
IF(X(3,J).GT.RNG) X(3,J)=RNG -DELT*ABS(RNG -XC{3))
IF(X(4,J).LT.TLMIN) X(4,J)=TLMIN-DELT*(TLMIN-XC(4))
IF(X(4,d).GT.TLMAX) X(4,J)=TLMAX-DELT+(TLMAX-XC(4))
IF(X(5,d).LT.TNMIN) X(5,J)=TNMIN-DELT*(TNMIN-XC(5))
IF(X(5,d).GT.TNWAX) X(5,J)=TNMAX-DELT*(TNMAX-XC(5))
RETURN
END
09890
0990Q
09910
09920
09930
09940
09950
09960
09970
09980
09990
10000
10010
10020
10030
10040
10050
10060
10070
10080
SUBROUTINE COSTER(J,VAIR . VH20,KKILL) 10090
COMMON/EPA/TNMIN,TNMAX,TSAT(21),COSTT(21),X(10,21),XC(10).VAMAX, 10100
1VAMIN,VWMAX,VWMIN,XN,XP,SUBCL,OMIN,QMAX,PITCH,DIA, 10110
2RNGMX,RNGMN,TLMIN,TLMAX,TITDX,TI TON,TSATA,TSATZ,XHEAT(21) 1 0120
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2),PI 10130
COMMON KCI,KER,KERR(20),IDUM6(4),MM,IDUM8(4),NTP,IDUM9,NTT 10140
COMMON DUMW(32),DEN12(2,2),DUMW2(8),DBW,DUMWW(9).DLTS, 10150
1DNZ(2),DUME22(2), 10160
1DTF,DUME5(3),PT.DUME6(28),HPFNC,DUMW1(7).ODUT,DUMM(8),TIN(2), 10170
2TOUT(2),DUME7(14),VAPP,DUME1(3),OFAN,DUME4(2),V ISLZ(7) ,DUME3(7), 10180
3W(2),DUME8(98),ZBYP,ZBUP,DUMB 10,ZFAN,DFANI.DLOV.DUME12(4),WD(2), 10190
4VAPPI,DUME15(3),TIND(2),TOUTD(2),DUME16(3),QD(7),DUME17(6), 10200
5DNZI(2),DUME19(11),ZTPD,ZNTD,COST(7) 10210
COMMON SSUM(16,30) ,ISUM(13,30),PRICE(2,21 ) 10220
COMMON/TRACE/SSSUM(9),IISUM(3) 10230
COMMON/PEN/ATTR(20),DATTR(20),AMBTPT(20),BCAPC,NATTR,CAPCST,CMAIN, 10240
1MACC,AFCR2,XLVL,FLCST,CAPBS,PLDFT(20),STMCT,CUTMP,SHELP,BHTRT(6) 10250
COMMON/STIN/XLDFT(6),BP(28),HTRTD(2B,6),HTRJD(28,6).NLODS.NBKPR 10260
1 ,PLOAD,BPMNM(6) ,TPMNM(6) 10:'70
COMMON/JUMP/JAKE,TINMX,N002I.DTN2I,N001I,NFPIN,N0020,N0010 10280
COMMON/GOFAN/KFANG 10290
-------
I
ro
COMMON/PIPE/XDIA(20),XLGT(20),NN1,NN2,XTOWR,PLNMH,TTTBH,VX,VN 10300
1 .VAVE 10310
COMMON/HEAD/TOPHD,WRTHD,DPCON,SPDP,RTDP 10320
COMMON/JAN7/WBMAX,PBPMN,TBPMN,CPEFF.WTEFF.PBPHT,EBPOM,PPOM,CWRTI, 10330
1SCPMP,CCPMP,FDMAX,MXFBL,SPRNZ,SPRHT,CWTLV,DPPCT,PDMAX,CONCT 10340
COMMON/PR5UM/XPRIC(12,21) 10350
COMMON/PERFO/AUXMW(20,21),TURMW(20,21),ZLOAD(20,21) 10360
COMMON/PASIT/TBUCK 10370
COMMON/SCOND/TTDMN,TTDMX,TISUM(21) 10380
COMMON/BCKPR/BCKMN.BCKMX 10390
COMMON/SCRAT/CLFAC,KMETL,KGAGE,CITEM(10,15).GTITD 10400
DIMENSION EKW(10),G5LOD(10) 10410
C *** SET DATA FOR SURFACE CONDENSER DESIGN 10420
c ** KCOND - is MULTIPRESSURE CODE- I=SINGLE PRESS, 2= TWO PRESSURE 10430
C ** SET TUBE METAL CODE FOR CARBON STEEL (KMETL=9) 10440
C ** SET CODE NO. OF TUBE SHEET METAL USING CARBON STEEL MN=2 10450
C ** SET THE GAGE OF THE TUBE TO BWG=16, THICK OF .065 INCH (KGAGE=5) 10460
C ** CPLB = COST/LB OF CONDENSER TUBES-IF ZERO,ESTIMATE IS MADE 10470
C *** IN SCSBP 10480
C *** SET ACCELERATION DUE TO GRAVITY 10490
C *** DPMAX = MAX. PRESSURE DROP IN PSI 10500
C *** CLMIN - MIN. ALLOWABLE TUBE LENGTH FOR DESIGN ONLY 10510
C *** VMIN - MIN. ALLOWABLE TUBE VELOCITY 10520
C *** VMAX - MAX. ALLOWABLE TUBE VELOCITY 10530
C *** SET CLEANINESS FACTOR - CLFAC 10540
DATA KCOND,MN/2.2/ 10550
DATA CPLB,GC,DPMAX,CLMIN,VMIN,VMAX/0.,32.2,15.,20.,6.,7./ 10560
C 10570
C THIS SUBROUTINE FINDS THE OBJECT FUNCTION FOR THE J POINT. THE 10580
C OBJECT FUNCTION IS THE TOTAL COST OF THE DRY COOLING TOWER SYSTEM 10590
C 10600
NSUM=J 10610
COLWS=TBUCK 10620
C *** COOLING TOWER DESIGN IS BASED ON 100 PCT. TURBINE LOAD 10630
PLOAD=1.0 10640
KMETL=9 10650
KGAGE=5 10660
CLFAC=.85 10670
BPLKW=BCAPC*1000. 10680
C «"** DESIGN BUNDLES TO BE AS CLOSE TO MAXIMUM WIDTH AS POSSIBLE 10690
C *** ALLOW 2 INCHES ON EACH SIDE FOR STRUCTURE AND .0625 INCHES ON 10700
C *** EACH SIDE CLEARANCE FROM WALL TO TUBE 10710
WTDAV=WBMAX*12.-4.125-DTF+PT 10720
C **» FIND NUMBER OF TUBES/BUNDLE 10730
ZNTZ=AINT(WTDAV/PT)*XN 10740
C *** STAGGERED BUNDLE HAS FEWER TUBES 10750
ZNTZ = ZNTZ-AINT((XN-i-.Ol)/2.) 10760
C *** FIND TOTAL NUMBER OF BUNDLES 10770
ZBYP = AINT(X(5,J)/ZNTZ-.001)-H .0 10780
C «** MAKE NUMBER OF BUNDLES A MULTIPLE OF 4 SO THAT BACK-TO-BACK 10790
-------
I
ro
en
C *** PIPING CAN ENTER IN THE MIDDLE.
ZZBYP=AMOD(ZBYP,4.*ZBUP)
IF(ZZBYP.GT..001)ZBYP=ZBYP-ZZBYP+4.*ZBUP
C *«* MAKE ACTUAL TUBES/BUNDLE AN EVEN MULTIPLE OF XN
ZNTD = AINT(X(5,d)/ZBYP-.001)-M .0
C *** IF ZZ IS ZERO THEN YOU DO NOT HAVE TO INCREASE 2NTD
ZNNN=ZNTD+AINT((XN+.01)/2.)
ZZ=AMOD(ZNNN,XN)
IF(ZZ-.001)7,7,4
4 IF(ZZ-XN/2.)5,6,6
5 ZNTD=ZNTD-ZZ
GO TO 8
6 ZNTD=ZNTD+XN-ZZ
C *** CHECK THAT BUNDLE IS STILL WITHIN WIDTH LIMITATIONS
8 IF(PT*(1.+FLOAT(INT((ZNTD-.01)/XN)))-WTDAV)7,7,9
9 ZNTD=ZNTD-XN
C *** CALCULATE ACTUAL NUMBER OF TUBES
7 X5NEW=ZBYP*ZNTD
C *** MAKE ZBYP THE NUMBER OF BAYS
ZBYP=ZBYP/ZBUP
C *** PUT TEMPERATURES IN DEGREE RANKING
T*TSAT(J)-SUBCL
TIND(1)=TCONV(T,1,1)
TIND(2)=TIND(1)-X(2,J)
TOUTDd )=TIND(1)-X(3,J)
C *** DETERMINE CP OF WATER BASED ON AVERAGE TEMPERATURE
T=.5*(TIND(1)+TOUTD(1))
T=T-459.67
CALL PPAUT1(T,CP,DEN,D1,D3,KODE)
C
C *** FIND WATER VELOCITY IN FT/SEC,
VH20=XHEAT(J)*XP/X(3,0)/X(5,J)/19.635/DIA**2/CP/DEN
C »** SET KKILL
C »** CHECK IF WATER VELOCITY IS WITHIN LIMITS
KKILL=0
IF(VH20-(VWMAX+.01)) 20,20,10
C *** WATER VELOCITY IS TOO HIGH
10 KKILL=1
GO TO 100
20 IF(VH20-(VWMIN-.01)) 30,40,40
C *** WATER VELOCITY IS TOO LOW
30 KKILL=2
GO TO 100
40 X(5,J)=X5NEW
C •*+ SET UP VARIABLES TO MAKE COMPATABLE WIITH AC PROGRAM.
C *** ONCE VARIABLES ARE SET CALL SUBROUTINE SUPER TO FIND VAIR
KCI=2
DLOV=X(4,J)
WD(1)=XHEAT(0)/X(3,0)/CP
KFANG=0
10800
10810
10820
10830
10840
10850
10860
10870
10880
10890
10900
10910
10920
10930
10940
10950
10960
10970
10980
10990
11000
11010
1 1020
1 1030
1 1040
11050
11060
11070
1 10BO
11090
11100
11110
1 1 120
1 1 130
11 140
1 1 150
1 1 160
11 170
11 180
11 190
11200
11210
11220
1 1230
1 1 240
11250
1 1260
11270
1 1 280
1 1290
-------
CALL SUPER
C +** IF KGO=2 THEN KILL THE PROGRAM. THIS CAN BE DONE BY SETTING
C **« NPAGE=TOO, SINCE THE MAXIMUM NUMBER OF OUTPUT PAGES IS 200
IF(KGO-1) 60,60,50
50 NPAGE=200
GO TO 100
C +»* IF KER=11 THEN THE AIR-SIDE VELOCITY WAS TOO HIGH. SET VAIR
C *** AN ARBITRARY VALUE ABOVE MAX. AIR VELOCITY
60 I FI f.'M. EQ.O )GO TO 80
DO 65 I=1,MM
IFf KERR( I ) -11) 65,70,65
65 CONTINUE
GO TC 80
70 V AIR= ,-iivlAX* 1.15
KKI Li_ = 3
GO TG 100
80
C **-
C ***
c + **
92
94
C **-
96
* * *
98
95
IF AIR VELOCITY, VAIR, IS OUTSIDE MAXIMUM AND MINIMUM VELOCITY
THEN RETURN WITHOUT CALCULATING COST
IFI VAIR-( VAMAX-t-. 01 ) ) 94,94,92
AIR VELOCITY IS TOO HIGH
KKILL=3
MM = C
GO TO 100
IF(VAIR-(VAMIN-.01 ) ) 96,98,98
AIR VELOCITY IS TOO
GO TO 100
FOR INITIAL COMPLEX DO NOT
IF( I ISUM( 1 ) . GT .0 )GO TO 95
IF( VAI3.GT . 1 010. 1GO TO 92
CALL OUT?E TO PERFORM BUNDLE
CALL OUTPE
COS fT i J ) rSSSl-'.K 8 I
TISUV J IrSUBCL
LET VAIR GO ABOVE 1000 FPM
AND FAN COST CALCULATION
C
C
c ***
102
ADD IN CAPITAL COST OF INCREASING STEAM SUPPLY SYSTEM (INSTALLED)
XPRIC ! 6. J 1 =STMCT»1 .E06*COST( 2)
COSTT' J ) =COSTT( J )+XPRlC(6, J)
IP CCNCT is ZERO ASSUME A SURFACE CONDENSER is USED
IF< CQNCT-. 001) 102, 102, 103
CALL SCDES(VMIN,VMAX,CLMIN,TLMAX,SSSUM(2t ,SSUM( 1 2 , J ) , W( 1 ) , KMETL ,
1 KGA3E . vs ,GC, PI ,KCOND,CLFAC,DPMAX,CPLB,TSAT t j ) , BCKMX , BCKMN.DPCON,
2DAY(1>.C1TEM,KNTR1 , CPEF F , CMA I N , AFCR2 , CAPCST , COST ( 2 ) )
DPCON=CITEM( 1,10)
SET FIRST GUESS TO BE USED IN RATING ROUTINES
GTITD=SUBCL
1 1 300
11310
1 1 320
1 1 330
1 1 340
1 1 350
1 1 360
1 1 370
1 1 3»iO
1 1 390
1 MOO
11410
1 M20
1 430
1 440
1450
1 460
1 470
1 480
1 490
1500
1510
1 1520
1 1 530
1 1 540
11550
1 1 560
1 1 570
1 1580
1 1590
1 1600
11610
1 1 620
1 1 630
1 1 640
1 1650
11660
1 1 670
1 16RO
1 1690
1 1 700
11710
1 1 720
1 1 730
1 1 740
11750
1 1 760
1 1 770
11780
1 1 790
-------
ro
103
C ***
c ***
104
C ***
C
c ***
c * * *
c
c ***
c
c ***
c ***
c ***
c
c ***
c ** *
c ***
c »**
XPRIC(7,d)=CITEM(1, 14)*1000.*COST(2)
GO TO 104
CONTINUE
ADD IN CONDENSER COST BASED ON DESIGN STEAM FLOW (USE LATENT
HEAT FOR 18 INCHES HG) CONCT IS INSTALLED COST.
XPRIC(7,d)=CONCT*QDUT/985.*COST(2)
CONTINUE
COSTT(d)=COSTT(d)+XPRIC(7,d)
CALL GEOM2(CAPIP)
ADD IN COST OF PI PING,PUMPS,VALVES,ETC.
XPRIC(1,d)=CAPIP*COST(2)
COSTT(d)=COSTT(d)+XPRlC(1,d)
CALL DPPIP TO DETERMINE AUX. POWER AT DESIGN POINT
CALL DPPIP
HPPMP=W(1)/60.*TOPHD/CPEFF/33000.
HPWRT=W(1)*WRTHD*WTEFF/8.82/3600./DENl2(2,1)
HPP=HPPMP-HPWRT
DUMX1=HPPMP*.0007457
DUMX2=HPWRT*.0007457
DUMX3=.0007457*ZFAN*ZBYP*HPFNC
ISUM(2,d)=DUMX1+.49
ISUM(7,d)=DUMX2+.49
ISUM(11,d)=DUMX3+.49
SSUM(13,NSUM)=.0007457*(HPP+ZFAN*ZBYP*HPFNC)
ADD IN 200 KW INSTALLED CAPACITY IN CASE EVAP. TOWER IS NEEDED
SSUM( 13.NSUM)=SSUM(13,NSUM)-t-.2
ADD IN COST OF WATER RECOVERY TURBINES. USE INSTALLED COST/KW
XPRIC(8,J)=CWRTI*.7457*HPWRT*COST(2)
COSTT(J)=COST T(J)+XPRIC < 8, d )
ADD IN INSTALLED COST OF ELECTRICAL SUBSTATION AND TRANSMISSION
LINES. OVERHEAD LINES ARE 27 DOLLARS/FOOT. ASSUME SUBSTATION
IS AT POWER PLANT
CAUX=580000.*SQRT(SSUM(13,NSUM)/20.)
CAUX = CAUX-t-27.*1 . 1 5* ( DPPCT-«-ZBYP/2 . *SSUM( 3 , NSUM ) *ZBUP )
XPRIC(9,d)=CAUX+COST(2)
COSTT(d)=COSTT(J)+XPRIC(9,d)
ADD IN 12 PCT. FOR INTEREST DURING CONSTRUCTION
XPRIC(10,d)=.12*COSTT(d)
COSTT(d)=COSTT(d)+XPRlC(10,d)
IF OPTIMIZATION IS THROUGH, DO NOT RUN OFF-DESIGN PERFORMANCE
IF(KNTR1.EQ.1) GO TO 100
ADD THE FOLLOWING SECTION TO FIND OFF DESIGN PERFORMANCE.
SET VARIABLES NEEDED BY SUPER
KCI = 1
WD(1)*W(1)
VAPPI=VAPP
11800
11810
11820
11830
1 1840
11850
11860
1 1870
1 1880
11890
11900
11910
11920
11930
11940
11950
11960
11970
11980
11990
12000
12010
12020
12030
12040
12050
12060
12070
12080
12090
12100
12110
12120
12130
121 40
12150
12160
12170
1 2180
12190
12200
12210
12220
12230
12240
12250
12260
122 70
12280
12290
-------
DLOV=VISLZ(1) 12300
ZTPD=NTP 12310
ZNTD=NTT 12320
DNZI(1)=DNZ(1) 12330
DNZI(2)=DNZ(2) 12340
DFANI=DFAN 12350
JAKE=3 12360
KREEP=0 12370
C *** SET ENERGY PENALTY TO ZERO 12380
ENPEN=O.O 12390
PRICE(2,J)=0. 12400
ANNFL=0.0 12410
YFUEL=0.0 12420
C *** CALL SUPER TO FIND ITD 12430
DO 200 1=1,NATTR 12440
C *** IF COST IS ALREADY HIGHER THAN IT WAS BEFORE, THEN DO NOT BOTHER 12450
C *** TO RUN OFF-DESIGN PERFORMANCE. THIS WILL MAKE THE TOTAL COST 12460
C *** WRONG SINCE THE PENALTY COST HAS NOT BEEN FULLY DETERMINED. ALSO 12470
C *** THE CAPACITY COST MAY BE BASED ON THE PREVIOUS COSTER CALL. 12480
IF(IISUM(1))107,107,105 12490
105 IF((COSTT(d)+ENPEN+YFUEL+PRICE(2,J))-COLWS)107,107,201 12500
107 CONTINUE 12510
KREEP=I 12520
C 12530
C *** SET PLANT LOAD AND NOMINAL OUTPUT FOR THAT LOAD 12540
XLOAD=PLDFT(I) 12550
PLOAD=XLOAD 12560
TBXXX=GRS(XLDFT,1.TPMNM,1,PLOAD.NLODS,XXXX) 12570
c *** PLANT OUTPUT is COMPARED AGAINST LOAD DEMANDED - NOT THE OUTPUT 12580
C *** OF AN EQUIVALENT WET TOWER PLANT 12590
XPLKW=BPLKW*XLOAD 12600
C *** SET HOURS AT THIS CONDITION 12610
HRS=DATTR(I) 12620
IINCL=0 12630
NRLOD=1 12640
PTOL=50. 12650
BOTP=.7*XLOAD 12660
TOPP=1. 12670
TIND(2)=ATTR(I)+459.67 12680
C *** IF LAST AMBIENT HAD FAN CONTROL AND NEW AMBIENT IS LOWER WITH A 12690
C *** LOWER LOAD, THEN START FAN CONTROL IMMEDIATELY 12700
IF(I.EQ.tJGO TO 109 12710
IF(OFAN.EQ.O)GO TO 109 12720
IF(ATTR(I).LT.ATTR(I-1).AND.XLOAD.LT.(FLOAD+.0001))GO TO 115 12730
109 JFAN=0 1274Q
FLOAD=PLOAD 12750
C *** IF AMBIENT IS BELOW CUTOFF FOR FAN CONTROL, START FAN CONTROL 12760
IF(ATTR(I).LT.(TBXXX-SUBCL-SSSUM(9)))GO TO 115 12770
110 CONTINUE 12780
KFANG=1 12790
-------
CALL SUPER
C *** START CONTINUOUS FAN CONTROL WHEN TIN(1) GOES BELOW MINIMUM
C *** ALLOWABLE TEMPERATURE.
C *** SEE IF TIN(1) IS WITHIN 2 DEGREES
IF((TIN(1)+2.)-(T BXXX-SUBC1+459.67))11A,150,1 50
11 4 MM=0
115 CONTINUE
CALL QTURB(QFANC,TBXXX,PLOAD,2)
C *** IF CONCT IS ZERO THEN ASSUME A SURFACE CONDENSER IS USED
IF(CONCT-.001)120,120,130
120 CALL SCMPR(TBXXX,QFANC,W(1),CLFAC,KMETL,KGAGE,BCKMX,BCKMN,
ICITEMd .11),CITEM(1,4),CITEM(1,13),GTITD,CITEM(1,15),TIND(1),
2TOUTD(1 ))
SUBCL=TBXXX-TIND(1)
GTITD=SUBCL
TIND(1)=TIND(1)+459.67
TOUTD(1)=TOUTD(1)+459.67
GO TO 140
130 CONTINUE
C *** FOR JET COND. ASSUME TTD IS PROPORTIONAL TO 0
SUBCL=QFANC*TISUM(J)/SSUM(8,J)/1.E06
TIND(1)=TBXXX+459.67-SUBCL
C *** CONVERGE ON CP
L0=1
CPX=1.
133 TOUTD(1)=TIND(1)-QFANC/W(1)/CPX
XX=.5*(TOUTD(1)+TIND(1))
CP1 = 1.191328-7.002932E-4*XX+6.3408E-7*XX*XX
IF(ABS(1.-CP1/CPX)-.004)140,140,135
135 IF(LO-5)137,140,140
137 LQ=LQ+1
CPX=CP1
GO TO 133
140 CONTINUE
TOUTD(2)=0.
KCI = 2
KFANG=0
C «»* KFANG INDICATES FAN CONTROL FOR THIS PLOAD
C »** JFAN INDICATES ANY FAN CONTROL FOR THIS AMBIENT
C *** FLOAD IS LOAD FAN CONTROL STARTED FOR THIS AMBIENT
IF(JFAN.EQ.O)FLOAD=PLOAD
JFAN=1
IF(PLOAD.GT.FLOAD)FLOAD=PLOAD
VAPSTR=VAPP
VAPPI=0.
QD(1)=0.
CALL SUPER
KCI = 1
VAPPI=VAPSTR
150 CONTINUE
12800
12810
12820
12830
12840
12850
12860
12870
12880
12890
12900
12910
12920
12930
12940
12950
12960
12970
12980
12990
13000
13010
13020
13030
13040
13050
13060
13070
13080
13090
13100
13110
13120
13130
13140
13150
13160
13170
13180
13190
13200
13210
13220
13230
13240
13250
13260
13270
13280
13290
-------
co
o
C ***
C
c ***
C ** *
C ** *
C
C ***
C ** *
151
152
C
C ** *
C ***
154
C
c ***
159
C ***
160
C ***
c ***
162
C
C ** *
c ** *
c ***
163
164
C
C ***
DETERMINE TOTAL KW FOR FANS
TOTKW=ZFAN*ZBYP*HPFNC*.7457
FIND PUMP HEAD IN FEET OF WATER AND CALCULATE HP
CALL DPPIP
HPPMP=W(1)/60.*TOPHD/CPEFF/33000.
APPLY POWER FROM WATER RECOVERY TURBINE TO PUMPING POWER
HPWRT = W(1)*WRTHD*WTEFF/8.82/3600./DEN12 (2,1)
HPP=HPPMP-HPWRT
ADD PUMPING KW ON TO FAN KW
TOTKW=TOTKW+HPP*.7457
IF EVAP. TOWER IS NEEDED FOR AUX. COOLING, ADD 200 KW TO
OPERATE TOWER PUMP AND FAN
IF((TOUT(1)-459.67)-95.)152,152,151
TOTKW=TOTKW+200.
CONTINUE
DETERMINE KW FOR TURBINE AND FIND DIFFERENCE FROM BASE PLANT KW
TZZ=TIN(1)+SUBCL
HEAT RATE RATIO IS BASED ON NOMINAL BACK PRESSURE INPUTTED
CALL HTURB(TZZ,HRATO,PLOAD,HRTBS,PBPHT)
TURKW=BPLKW*PLOAD/HRATO
DELKW=XPLKW-TURKW
FIND TURBINE HEAT RATE
HRTRB=HRATO*HRTBS
DETERMINE IF PLANT OUTPUT IS CLOSE ENOUGH TO DEMANDED OUTPUT
EZ=TURKW-TOTKW-XPLKW
IF(ABS(EZ) .GT.PTODGO TO 180
IF(I-1)162,162,165
CALCULATE CAPACITY PENALTY AT HIGHEST AMBIENT TEMPERATURE AND
STORE MAXIMUM KW PENALTY FOR TURBINE AND AUXILLARIES
TOTMX=TOTKW
SSUM(6,J) = PSL(TZZ-459.67)
DELMX=DELKW
DKWMX=TOTMX+DELMX
CPPEN=DKWMX*AFCR2*CAPCST
COSTT(J)=COSTT(J)+CPPEN
EVAP. TOWER FOR AUX. COOLING IS ASSUMED TO COST 300000. DOLLARS
INSTALLED. THE HEAT LOAD FOR THE AUX. COOLING IS INCLUDED IN
QTURB AS PART OF 10 PCT. STACK LOSS
XPRIC(11,J)=0.
IF((TOUT(1)-459.67)-95.)164,164,163
XPRIC(ll.d)=300000.*COST(2)
COSTT(0)=COSTT(J)+XPRIC(11,J)
CONTINUE
ADD UP INCREMENTAL FUEL COST - COMPARE TO DEMANDED LOAD AT THE
13300
13310
13320
13330
13340
13350
13360
13370
13380
13390
13400
13410
13420
13430
13440
13450
13460
13470
13480
13490
13500
13510
13520
13530
13540
13550
13560
13570
13580
13590
13600
13610
13620
13630
13640
13650
13660
13670
13680
13690
13700
13710
13720
13730
13740
13750
13760
13770
13780
13790
-------
I
co
C *** HEAT RATE INPUTTED FOR THIS PURPOSE
C *** IT IS POSSIBLE TO GET CREDIT AT PART LOAD CONDITIONS
165 BHTR=GRS(XLDFT,1 , BHTRT , 1 .XLOAD.NLODS , XXXX )
ANN=HRS*FLCST*1.E-06
ANN1=ANN*HRTRB*TURKW
ANNFL=ANNFL+ANN1
YFUEL=YFUEL+ANN1-ANN*BHTR»XPLKW
C *** ADD UP 0+M CHARGES FOR HEAT REJECTION SYSTEM
PRICE(2.J)=PRIC£(2,J)+EBPOM*HRS*TURKW*1.E-03
168 CONTINUE
ZLOAD(I,d)=PLOAD
AUXMW
-------
C *** POWER CAN COME FROM SYSTEM
194 ENPEN=ENPEN+HRS*SHELP*PPPWR/1000.
GO TO 160
200 CONTINUE
201 CONTINUE
C *** RESET VARIABLES SO THAT OPTIMIZATION CAN CONTINUE
KCI = 2
DFANI=0.
TOUTD(2)=0.
ONZI(1)=0.
DNZI(2)=0.
VAPPI=0.
OD(1)=0.0
C *** ADD ENERGY PENALTY TO TOTAL COST
COSTT(J)=COSTT(J)+ENPEN+YFUEL+PRICE(2,J)
l
CO
ro
101
100
SSSUM(8)=COSTT(J)*1,
XPRIC(2,J)=CPPEN
XPRIC(3,J)=ENPEN
XPRIC(4,J)=COSTT(J)
XPRIC(5,J)=YFUEL
XPRIC(12,J)=ANNFL
CONTINUE
RETURN
END
E-03
14300
14310
14320
14330
14340
14350
14360
14370
14380
14390
14400
14410
14420
14430
14440
14450
14460
14470
14480
14490
14500
14510
14520
14530
14540
SUBROUTINE DPAIR 14550
C *** CALC. OF AIR SIDE PRESSURE DROP-EXCEPT FOR FRICTION CALC. BY DPFRA 14560
COMMON NFO,KGO,KNTRO,KNTR1,NSUM.NPAGE,DAY(2),PI 14570
COMMON KCI,KER,KERR(20),KFIN,KREG,LAIC,LSUP,MM,NP,NR,NT1.NT2.NTP, 14580
1NTR.NTT.ABARE,AFAN.AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 14590
2,DEN(2),DEN12(2.2),DENFN,DENLZ(7),DBW,DEO,DFH,DFR,DFS,DFT,DKL, 14600
3DLSP,DLTE.DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,OTT,PL,PT 14610
COMMON DPAD,DPAF,DPAM,OPAW,DPF(10),DPI,DPNZ(2),DPT,DPTA,DPTF, 14620
1DPTOT(2),POUT(2),PTUB,RV2,GAMAX,GT.HPFNC,HA IR,NTS,U8ARE,UCLN,UTOT, 14630
20(2),QDUT,QTOT,RFI.RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 14640
3,TWALL,TD,TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,V ISLZ(7), 14650
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLQ(2) 14660
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC.CKFNG.CKHSC,CKLOV,CKSTC,F, 14670
1FALT,FINEF,FFF,FSUM,OCL(4),ODL(4),OKL(4),OML(4),OMV(4),P,PRAN(2), 14680
2PRALZ(7),R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA, 14690
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20).ZTPPA 14700
-------
CO
CO
COMMON ZTRD,ANGI,2BYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV,ZNFI,PTI,TKT.TKF, 14710
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD.PSD,TTWIN,QD(7), 14720
2CARD7(6),DNZI(2),PDI.CFNG.CHSC,CLOV,CBSC,PRSTC.RFAIR,RFCT,ZNOZ(2), 14730
3RASPC,ZTPD,ZNTD,C05T(7),SSUM(16,30),ISUM(13,30),PRICE(2,21) 14740
COMMON/FAN/EFFAN.NBLAD.HPMSP 14750
COMMON/JUMP/dAKE,TINMX,N002I,OTN2I.N001I,NFPIN,N0020,N0010 14760
COMMON/GOFAN/KFANG 14770
COMMON/JAN7/WBMAX,PBPMN,TBPMN,CPEFF,WTEFF,PBPHT,EBPOM,PPOM,CWRTI, 14780
1SCPMP.CCPMP,FDMAX,MXFBL,SPRNZ,SPRHT,CWTLV.DPPCT,PDMAX.CONCT 14790
TAV(2)=0.5*(TIN(2)+TOUT(2)) 14800
C *** HORSE POWER AND EFFICIENCY WILL NOT CHANGE AT OFF-DESIGN AMBIENTS 14810
C *** LOUVERS WILL CONTROL THE PRESSURE DROP TO REMAIN THE SAME AS 14820
C *** AMBIENTS INCREASE. 14830
IF(KFANG.EQ.1)GO TO 400 14840
C *** FOR DESIGN, FAN SHOULD BE SIZED FOR COLD AMBIENT - NOT DESIGN 14850
C *** AMBIENT. THIS FAN DESIGN TEMP IS INPUTTED AS TAMB 14860
IF(JAKE.EQ.3)GO TO 19 14870
C *** STORE VARIABLES THAT WILL MOMENTARILY BE CHANGED TO DESIGN FAN 14880
STJ1=VIS(2) 14890
STJ2=DEN(2) 14900
STJ3=REA(2) 14910
STJ4=TIN(2) 14920
STJ5=TOUT(2) 14930
STvJ6 = TAV(2) 14940
LLIT=0 14950
TIN(2)=519.67 14960
C *** ASSUME AT FAN DESIGN TEMPERATURE, AIR TEMP RISE IS ABOUT 40 DEGREE 14970
TOUT(2)=TIN(2)+40. 14980
TAV(2)=.5*(TIN(2)+TOUT(2)) 14990
T=TAV(2)-459.67 15000
DEN(2)=FALT/TAV(2)*39.68863 15010
VIS( 2) = .00905-1-1 . 191E-04*(T+200. )**.775 15020
REA(2)=GAMAX*DFR/VIS(2)/29.06 15030
19 CONTINUE 15040
CALL DPFRA(VIS(2),0,TAV(2),DFR,DEN(2),CFP,DKL,1,ZNTR, 15050
1 GAMAX,DPAF,REA(2) ) 15060
TR=TOUT(2)/TIN(2) 15070
DENAP=0.075*530./TIN(2)*FALT 15080
RV2=DENAP*(VAPP /60.0)**2/(64.34*144.0) 15090
C 15100
C *** IF ZFAN AND DFAN HAVE NOT BEEN SET, DO SO NOW 15110
C 15120
GO TO (31,31,49).JAKE 15130
C *** START WITH 2 FANS/BAY OR 4 FANS/BAY 15140
31 ZFAN=2. 15150
HORSE=1.E10 15160
IF(ZBUP.LT.1.1)ZFAN=4. 15170
C »** SET LARGEST DIAMETER FAN THAT MAY BE USED. ALLOW .5 FEET CLEARANCE 15180
C *** BETWEEN THE FAN BELLS. BELL DIA. IS 1.2 OF THE FAN DIAMETER 15190
35 DFAN=AMIN1(FDMAX,DBW/12.*ZBUP/1.2,(DLTE/12./ZFAN/1.2-.5/1.2))+ 15200
-------
I
CO
1.9999 15210
C *** FIND NEXT SMALLER FAN 15220
39 IT=DFAN-.999 15230
IF(IT-14)46,46,44 15240
44 IF((-1)**IT)45,46,46 15250
45 IT=IT-1 15260
46 DFAN=IT 15270
C *** CALCULATE FAN AREA BY SUBTRACTING HUB BLOCKAGE(HUB DIA=.3*DFAN) 15280
AFAN=ZFAN*.7B54«.91*DFAN**2 15290
RFNPL=AFAN/(APPR*ZBUP) 15300
C *** SET MAXIMUM NUMBER OF BLADES 15310
NBLAD=MXFBL 15320
C *** SET 24 FOOT FAN AS MINIMUM SIZE 15330
IF(DFAN.LT.23.5)GO TO 242 15340
49 R2=AMAX1(1.0,1.0/RFNPL**2) 15350
S2=RAPMX**2 15360
64 CKINP=0.5-0.4*RFNPL 15370
66 CKD=1.0+TR*(R2-1.O+CKINP) 15380
70 DPAD=CKD*RV2 15390
HRECV=RV2*TR*R2+.3 15400
DPAD=AMAX1(0.0,DPAD-HRECV) 15410
78 CONTINUE 15420
CKM=(TR-1.0)*(1.0+S2) 15430
DPAM=CKM*RV2 15440
100 CKFNG=0.25*R2*TR 15450
144 CKLOV=1.8 15460
DPAW=RV2*(CKFNG+CKLOV) 15470
C *** FLOW PER FAN IS EVALUATED 15480
WAPF=W(2)/(ZBYP*ZFAN) 15490
190 DENFN=DENAP/TR 15500
200 QA=WAPF/DENFN 15510
C *** TOTAL STATIC DROP IS SUM OF ACCESSORY,FRICTION AND MOMENTUM CHANGE 15520
C *** THE FRICT. DPAF IS CORRECTED BY BUNDLE IN SERIES BY CERRECTING NTR 15530
DPTOT(2)=DPAF+DPAW+DPAM 15540
D1=(DPTOT(2)+DPAD)*100.0 15550
C *** FIND FAN EFFICIENCY AND HORSE POWER REQUIRED 15560
C *»* IF KFANG=0 AND JAKE=3 THEN WE HAVE FAN CONTROL. USE THE FAN 15570
C *** EQUATION WITH DESIGN EFFICIENCY 15580
IF(JAKE.EQ.2)GO TO 201 15590
HPFNC=D1*QA/EFFAN/1.378168E06 15600
GO TO 270 15610
201 XBLAD=NBLAD . 15620
FLCFM=QA/60.E03 15630
PD11=D1*.27673 15640
C *** ASSUME 12000 TIP SPEED 15650
DATA VTIPA/12000./ 15660
CALL FANCON(Z1,Z2,Z3,K4,Z5,KSTEP,Z4,EFFAN.HPFNC.OFAN,DENFN, 15670
1 FLCFM.PD11,NBLAD,VTIPA,Z6) 15680
C *** USE GEAR BOX EFFICIENCY OF .97 AND MOTOR EFFICIENCY OF .93 15690
EFFAN=EFFAN«.97*.93 15700
-------
co
en
HPFNC=HPFNC/.97/.93 15710
c 15720
C *** IF LLIT=1 THEN IT IS GOING THROUGH ONCE MORE AT THE OPTIMUM DESIGN 15730
IF(LLIT)215,215,255 15740
215 IF(KSTEP)240,220,242 15750
C *** CHECK IF HORSE POWER IS SMALLER THAN PREVIOUS HORSE POWERS 15760
C *** AND TRY NEXT FAN DIAMETER OR NEXT NUMBER OF BLADES 15770
220 IF(HPFNC*ZFAN-HORSE)230,244,244 15780
230 HORSE=HPFNC*2FAN 15790
DFANL=DFAN 15800
NBLDD=NBLAD 15310
ZFANL=ZFAN 15820
EFFNL=EFFAN 15830
AFANL=AFAN 15840
RFNLL=RFNPL 15850
GO TO 244 .15860
C *** IF STALL CONDITIONS(KSTEP=-2) OCCUR, THEN DECREASE THE FAN 15870
C *** DIAMETER. IF SMALLER FAN IS INDICATED(KSTEP=-1) THEN DECREASE 15880
C *** THE NUMBER OF BLADES(TO A MINIMUM OF 8) OR DECREASE THE FAN DIA. 15890
240 IF(KSTEP.EQ.(-2))GO TO 39 15900
244 IF(NBLAD-8)39,39,241 15910
241 NBLAD=NBLAD-1 15920
GO TO 201 15930
C *** IF BIGGER FAN IS INDICATED(KSTEP=-H )DECREASE NUMBER OF FANS 15940
C *** PROVIDED THAT NUMBER OF BLADES IS AT MAXIMUM 15950
242 IF(NBLAD.LT.MXFBL)GO TO 39 15960
IF(ZFAN-1.5)250,250,245 15970
245 ZFAN=ZFAN-1.0 15960
GO TO 35 15990
C *** RESET OPTIMUM VARIABLES 16000
250 HPFNC=HORSE/ZFANL 16010
DFAN=DFANL 16020
NBLAD=NBLDD 16030
ZFAN=ZFANL 16040
EFFAN=EFFNL 16050
AFAN=AFANL 16060
RFNPL=RFNLL 16070
C *** GO THROUGH ONCE MORE AT THE OPTIMUM DESIGN(LLIT=1) 16080
LLIT=1 16090
C *** USE BIGGEST AND MOST FANS IF NO FAN IS SUITABLE 16100
IF(HORSE-.9E10)49.49,31 16110
255 CONTINUE 16120
C *** CHECK THAT A SUITABLE COMBINATION OF FAN SIZE AND NUMBER 16130
C *** OF FANS HAS BEEN FOUND 16140
IF(HORSE -.9E10)270,270,260 16150
260 CONTINUE 16160
C *** USE FAN EQUATION WITH EFFICIENCY OF .5 16170
EFFAN=.5 16130
HPFNC=D1*QA/EFFAN/1.378168E06 16190
270 WAPF=QA/60.0 16200
-------
C *** STORE THE INLET SPECIFIED AIR SIDE STATIC DP - SHOULD BE IN PSI 16210
400 CONTINUE 16220
C *** RESTORE VARIABLES THAT WERE DISTURBED TO DESIGN FAN 16230
IF(JAKE.NE.2)GO TO 450 16240
VIS(2)=STJ1 16250
DEN(2)=STJ2 16260
REA(2)=STJ3 16270
TIN(2)=STJ4 16280
TOUT(2)=STJ5 16290
TAV(2)=STJ6 • 16300
450 CONTINUE 16310
RETURN 16320
END 16330
i
<*> SUBROUTINE DPFRA (VISAV,KFINP,TAV,DFR.DENAV,CFP.DKL,KFIN,ZNTR. 16340
1 GAMAX.DPFA.REAF) 16350
C *** CALCULATE AIR SIDE PRESSURE DROP,BUNDLE. IN PSI 16360
DIMENSION CFP(3) 16370
C *** GENERALIZED EQUATIONS START HERE 16380
50 DPFA=1.0 16390
CN=CFP(2) 16400
C *** FOR FIN TUBES CHECK FOR TRANSITIONAL FLOW,KAYS AND LONDON 16410
60 IF (REAF*DKL/DFR-1000.0) 70,80,80 16420
70 CN=-0.4 16430
DPFA=(1000.0*DFR/DKL)**.155 16440
80 DPFA =CFP(1)*REAF**CN *DPFA 16450
DPFA=DPFA *GAMAX**2 *8.33E-12 *ZNTR /DENAV 16460
200 RETURN 16470
END 16480
-------
I
CO
SUBROUTINE DPPIP 16490
C *** THIS ROUTINE DETERMINES THE HEAD ON A PUMP AND THE HEAD ON A 16500
C *** WATER RECOVERY TURBINE TO MAINTAIN A 3 FEET ABOVE ATMOSPHERIC HEAD 16510
C *** IN THE COIL. IT DOES THIS BY DETERMINING THE PRESSURE DROP OF THE 16520
C *** PIPING BY ADDING UP L/D AS DESIGNED IN GEOM2. ASSUME A CONSTANT 16530
C *** FRICTION FACTOR OF .011 AND A CONSTANT AVERAGE VELOCITY. PUMP 16540
C *** SUCTION LOSSES ARE IGNORED. 16550
C *** DUE TO TAPERED SUPPLY AND RETURN LINES AND VALVING, THERE IS NO 16560
C *** MOMENTUM LOSS OR MALDISTRIBUTION 16570
COMMON NFO,KGO,KNTRO.KNTR1,NSUM,NPAGE,DAY<2),PI 16580
COMMON KCI,KER,KERR(20) ,KFIN.KREG,LA 1C,LSUP,MM.NP,NR,NT 1 .NT2.NTP, 16590
1NTR.NTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT.AXAV,AXPP(20),CP(2) 16600
2,DEN(2),DEN12(2,2).DENFN.DENLZ(7),DBW.DEQ,DFH,DFR,DFS,DFT,DKL, 16610
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT 16620
COMMON DPAD,DPAF,DPAM.DPAW,DPF(10),DPI,DPNZ(2),DPT,DPTA,DPTF, 16630
1DPTOT(2),POUT(2),PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS,UBARE,UCLN ,UTOT, 16640
20(2),QDUT.QTOT.RFI,RFIN,RFTQT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 16650
3,TWALL,TD,TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,VISLZ(7), 16660
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WL(J(2) 16670
COMMON ANG(3),CFH(3),CFP(3),CFR.CKBSC.CKFNG.CKHSC,CKLOV,CKSTC,F, 16680
1FALT.FINEF,FFF,FSUM,OCL(4),ODL(4),OKL(4),OML(4),OMV(4),P,PRAN(2), 16690
2PRALZ(7),R.RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA, 16700
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20),ZTPPA 16710
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV,ZNFI,PTI,TKT,TKF, 16720
1WD(2).VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD.PSD,TTMIN.QD(7), 16730
2CARD7(6),DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2), 16740
3RASPC,ZTPD,ZNTD,COST(7),SSUM(16,30),ISUM(13,30),PRICE(2,21) 16750
COMMON/EPA/DUM1(270),SUBCL,DUM2(10) 16760
COMMON/PIPE/XDIA(20),XLGT(20),NN1,NN2,XTOWR,PLNMH,TTTBH,VX,VN 16770
1,VAVE 16780
COMMON/HEAD/TOPHD,WRTHD,DPCON,SPDP,RTDP 16790
COMMON/JAN7/WBMAX,PBPMN.TBPMN,CPEFF,WTEFF,PBPHT,EBPOM,PPOM,CWRTI, 16800
1SCPMP,CCPMP,FDMAX,MXFBL,SPRNZ,SPRHT,CWTLV,DPPCT,PDMAX,CONCT 16810
COMMON/JUMP/JAKE,DUV7(7) 16820
IF(JAKE.EQ.3)GO TO 36 16830
SPSUM=0. 16840
RTSUM=0. 16850
C *** SUM UP SUPPLY L/D 16860
DO 10 1=1,10 16870
IF(XDIA(I)-.001)20,20,5 16880
5 SPSUM= SPSUM+XLGT(I)/XDIA(I) 16890
10 CONTINUE 16900
20 SPDP=SPSUM*VAVE**2*1.70775E-04 16910
C *** SUM UP RETURN L/D 16920
DO 30 1=11,20 16930
IF(XDIA(I)-.001)35,35,25 16940
25 RTSUM=RTSUM+XLGT(I)/XDIA(I) 16950
30 CONTINUE 16960
35 RTDP=RTSUM*VAVE**2*1.70775E-04 16970
C *** PRESSURE DROP IN CONDENSER SPRAY NOZZLES IS SPRNZ 16980
-------
C *** FIND DISTANCE BETWEEN TOP OF COIL AND SPRAY NOZZLES
CILHT=XTOWR+SPRHT
36 CONTINUE
IF(CONCT-.001)70,70,37
37 CONTINUE
C *** FIND JET CONDENSER PRESSURE IN FEET OF WATER
CONPR=PSL(TIN(1)+SUBCL~459.67)*1.133
C *** FIND WATER RECOVERY TURBINE HEAD IN FEET
C *** NECESSARY TO KEEP COIL PRESSURIZED
X=SPRNZ+CONPR-CILHT+RTDP
IF(CWRTI-.0001)40, 40,50
C *** EXRT IS THE EXTRA HEAD NEEDED TO KEEP COIL PRESSURIZED
C *** THAT MUST BE THROTTLED IN THE RETURN LINE
C *** WHEN THERE IS NO WATER RECOVERY TURBINE
40 EXRT=36.9-X
EXRT=AMAX1(0.0,EXRT)
WRTHD=0.0
GO TO 60
50 WRTHD=3.+33.9-X
WRTHD=AMAX1(O.O.WRTHD)
EXRT=0.0
60 CONTINUE
C *** TOTAL PUMP HEAD IN FEET
TOPHD=SPRNZ+DPTOT(1)*2-3066+WRTHD+CWTLV+SPDP+EXRT-SPRHT+RTDP
GO TO 75
C *»* FIND PUMP HEAD IN FEET WITH SURFACE CONDENSER
70 WRTHD=0.
TOPHD=2.3066*(DPTOT(1)+DPCON)+SPDP+RTDP
75 CONTINUE
RETURN
END
16990
17000
17010
17020
17030
17040
17050
17060
17070
17080
17090
17100
17110
17120
17130
17140
17150
17160
17170
17180
17190
17200
17210
17220
17230
17240
17250
17260
17270
17280
17290
C ** *
C ***
C ***
10
15
SUBROUTINE DPSEN(DTI,DL,ICLG,GT,RE,GOSW,DEN,RVIS,DP,FF)
CALCULATES TUBESIDE SINGLE-PHASE PRESSURE DROP - COMMERCIAL PIPE
OR DRAWN TUBING WITH FOULING
PROPERTY VARIATION CORRECTION FACTOR - SIEDER +• TATE
PHI = 1.0
30, 8,30
IF ( ICLG ~ 1 )
VR = 1./RVIS
IF (RE - 2000.)
IF (RE - 4000.)
PHI » VR«*.25
15,10,10
25,20,20
17300
17310
17320
17330
17340
17350
17360
17370
17380
17390
-------
I
CO
IO
GO TO 30
20 PHI s VR**.14
GO TO 30
25 PRO = 2.0 - 0.0005*RE
PHI = VR**.25*PRO + VR**.14*(1.-PRO)
C *** ISOTHERMAL FRICTION FACTOR
30 CONTINUE
35 IF (RE - 1380.) 55,55,40
40 IF (RE - 4000.) 60,60,70
C *** HAGEN-POISEUILLE
55 FIS = 16./RE
GO TO 75
60 FIS = 0.0116
GO TO 75
C *** WILSON-MC.ADAMS-SELTZER
70 FIS = .0035 + .264/RE**.42
C *** FANNING FRICTION FACTOR AND PRESSURE DROP
75 FF s FIS+PHI
DP = 0.333E-10 * DL*GT**2*FF/(DTI*DEN)
RETURN
END
17400
17410
17420
17430
17440
17450
17460
17470
17480
17490
17500
17510
17520
17530
17540
17550
17560
17570
17580
17590
17600
SUBROUTINE DPTUB i76io
C *** CALCULATES PROCESS SIDE PRESSURE DROPS IN THE EXCHANGER 17620
C *** OVERALL CASE 17630
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2),PI 17640
COMMON KCI,KER,KERR(20).KFIN.KREG,LAIC,LSUP,MM,NP,NR,NT1,NT2,NTP, 17650
1NTR,NTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 17660
2,DEN(2),DEN 12(2,2),DENFN,DENLZ(7),DBW,DEO,DFH,DFR,DFS,DFT,DKL, 17670
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT 17680
COMMON DPAD.DPAF,DPAM,DPAW,DPF(10),DP I,DPNZ(2) ,DPT,DPTA,DPTF, 17690
1DPTOT(2).POUT(2),PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTOT, 17700
20(2),ODUT,OTOT,RFI,RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 17710
3,TWALL,TD,TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,VISLZ(7), 17720
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB<2),WL(J(2) 17730
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC,F, 17740
1FALT,FINEF,FFF,FSUM,OCL(4),ODL(4),DKL(4),OML(4),OMV(4),P,PRAN(2), 17750
2PRALZ(7).R.RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA, 17760
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20).ZTPPA 17770
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV.ZNFI.PTI.TKT.TKF, 17780
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,OD(7), 17790
2CARD7(6),DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2), 17800
-------
3RASPC,ZTPD,ZD,COST(7),SSUM(16,30),ISUM(13,30),PRICE(2,21) 17810
NQZ=1 17820
XP=NTP 17830
KCLG=1 17840
ZLL=DLTO 17850
C *** CALCULATE TUBE PRESSURE DROP 17860
90 TB=(TT(NQZ)+TT(NQZ+1))*.5 17870
TC=.5*(TIN(2)+TOUT(2)) 17880
TW=TB-(TB-TC)*UTOT*RAOI/HTS 17890
DENT=DENLZ(NQZ) 17900
CALL PPVIS(TW,KCLG,VISW,VI5B,OMV,OML) 17910
VISB=VISLZ(NQZ) 17920
RVIS=VISB/VISW 17930
130 RE=DTI*GT/(29.*VISB) 17940
CALL DPSEN(DTI,ZLL,KCLG.GT,RE,0.,DENT,RVIS,DPF(NQZ),FFF) 17950
C *** CALCULATE INLET HEADER CONTRACTION 17960
DPTA1=1.5*GT**2/(1-2E11*DEN12(1,1)) 17970
C *** CALCULATE OUTLET HEADER EXPANSION 17980
DPTA3=.25*GT**2/(1.2E11*DEN12(2,1)) 17990
C *** CALCULATE RETURN HEADER LOSS 18000
_ DPTA2=1.5*GT**2/(1.2E11*DENT) 18010
i C *** TOTAL LOSSES OF HEADERS 18020
O DPTAS=DPTA1+(XP-1.)*DPTA2+DPTA3 18030
C *** TOTAL TUBE LOSSES 18040
DPTF = XP*DPF(1 ) 18050
C *** TOTAL PRESSURE DROP 18060
DPT=DPTF+DPTAS 18070
DPTA=DPTAS 18080
C *** SIZE AND CALC. PRESS. DROP IN OUTLET NOZZLE 18090
CALL NOZCT(DNZI,DNZ,WB(1)/ZNOZ(2),VNZ,DEN12,0.0 ,DPNZ,DBW,0.0,2) 18100
C *** RESET TUBE SIDE PHYS.PROP. TO AVG. TEMP. 18110
TAV(1)=0.5*(TIN(1)+TOUT(1)) 18120
CALL PPV1S(TAV(1).1,VIS(1),DUM1,OMV,OML) 18130
REA(1)=GT*DTI/(29.0*VIS(1)) 18140
DPTOT(1)=ZBUS«(DPT+DPNZ(1)+DPNZ(2)) 18150
430 AX=AXPP(NTP) 18160
440 VT=WB(1)/(AX*DEN12(1,1)*3600.) 18170
500 RETURN 16180
END 18190
-------
SUBROUTINE ERORF(KER,KERR,KGO,MM)
C *** SETS PERMANENT ERRORS
DIMENSION KERR(1)
KX=MM+1
KXX=MM+2
IF (KER) 200,200,20
20 IF (MM-1) 40,40,30
C *** IF LAST TWO ERRORS ARE SAME WITH NEW KER DO NOT STORE
30 IF (KER-KERR(MM)) 40,32,40
32 IF (KER-KERR(MM-1)) 40,90 ,40
40 MM=MM+1
IF (MM-20) 50,50,150
50 KERR(MM)=KER
C *** MINOR ERRORS FROM 1 TO 49 - MAJOR ERRORS .GE.50 SET KGO=2
90 IF (KER-49) 100,100,150
100 KER=0
GO TO 200
150 KGO=2
200 RETURN
END
18200
18210
18220
18230
18240
18250
18260
18270
18280
18290
18300
18310
18320
18330
18340
18350
18360
18370
18380
18390
SUBROUTINE ERORG (N.KERRO,KER)
DIMENSION KERRO(1)
IF (N-20) 10,20,20
10 NxN+1
KERRO(N)=KER
20 RETURN
END
18400
18410
18420
18430
18440
18450
18460
-------
SUBROUTINE EXCON 16470
C *** CALCULATES TOTAL CONDENSING AREA AND DESUPERHEATING/SUBCOOLING 18480
C *** AREA AS REQUIRED USING OVERALL METHOD 18490
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2),PI 18500
COMMON KCI,KER,KERR(20).KFIN.KREG,LA 1C,LSUP,MM,NP,NR,NT1,NT2,NTP, 18510
1NTR,NTT,ABARE,AFAN,AMIN,APLOT.APPR.ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 18520
2,DEN(2),DEN 12(2,2),DENFN,DENLZ(7),DBW,DEO,DFH,DFR,DPS,DFT,DKL, 18530
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTP,DTO,DTT,PL,PT 18540
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT,DPTA.DPTF, 18550
1DPTOT(2),POUT(2),PTUB,RV2.GAMAX,GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTOT, 18560
20(2),ODUT,QTOT,RFI,RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 18570
3,TWALL.TD,TW,TMTD,TK(2),VAPP,VNZ(2),VT,OFAN,TLTE,AOF,VISLZ(7), 18580
4VIS(2),VIS 12(2,2).VISW,W(2),WAPF,WB(2),WLQ(2) 18590
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC,F, 18600
1FALT,FINEF,FFFfFSUM,OCL(4),ODL(4),OKL(4),OML(4),OMV ( 4),P,PRAN(2), 18610
2PRALZ(7),R,RAOI,RAOR,RARAF,RAPMX.REA(2),RE12(2,2),RFNPL,RPT,TLA, 18620
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20).ZTPPA 18630
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV.ZNFI,PTI,TKT,TKF, 18640
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD.PSD,TTMIN,QD(7), 18650
2CARD7(6),DNZI(2),PDI.CFNG.CHSC.CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2), 18660
3SPC,ZTPD,ZD,COST(7)ISSUM(16,30),ISUM(13,30),PRICE(2,21) 18670
FSUMrO.O 18680
GT=WB(1)/AXAV 18690
C *** SENSIBLE CASE CALC. START HERE 18700
PRAN(1)=PRALZ(1) 18710
CALL UOSEN(1) 18720
IF (KER) 550,550,590 18730
550 CALL MTDOV(TD,NP,NTR,1,1.0,KER,P,R,TNU1,LPMT,TMTD,F,0.0) 18740
IF (KER) 560,560,590 18750
560 OTOT =UTOT *ASTOT*TMTD 18760
FSUM=ODUT/OTOT 18770
590 RETURN 18780
END 18790
SUBROUTINE EXINI 18800
*** INITIALIZES VARIABLES USED IN COMMON WHICH MAY BE PRESET BY INPUT 18810
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2),PI 18820
COMMON KCI,KER,KERR(20),KFIN.KREG,LAIC,LSUP,MM,NP,NR,NT 1.NT2.NTP, 18830
1NTR,NTT.ABARE,AFAN,AMIN,APLOT,APPR.ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 18840
2.DEN(2).DEN12(2,2),DENFN,DENLZ(7).DBW,DEO,DFH,DFR.DFS,DFT,DKL, 18850
3OLSP,DLTE,OLTO,DLTS,DNZ(2),DTI,DTIM,DTP,DTO,DTT,PL,PT 18860
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT.DPTA,DPTF, 18870
-------
1DPTOT(2),POUT(2),PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HT5,UBARE,UCLN,UTOT. 18880
2Q(2),QDUT,QTOT,RFI,RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 18890
3,TWALL,TD,TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,V ISLZ(7 ) , 18900
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLQ(2) 18910
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV.CKSTC,F, 18920
1FALT,FINEF,FFF,FSUM,OCL(4),ODL(4),OKL(4),OML(4),OMV(4) ,P,PRAN(2), 18930
2PRALZ(7),R,RAOI.RAOR,RARAFtRAPMX,REA(2),RE12(2,2),RFNPL,RPT . TLA, 18940
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20).ZTPPA 18950
COMMON ZTRD,ANGI.ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV,ZNFI,PTI,TKT,TKF, 18960
1WD(2).VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,00(7), 18970
2CARD7(6),DNZI(2),PDI.CFNG.CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2), 18980
3RASPC,ZTPD,ZNTD.COST(7),SSUM(16,30),ISUM(13,30),PRICE(2,21) 18990
COMMON/JUMP/JAKE,TINMX.N002I,DTN2I,N001I,NFPIN,N0020,N0010 19000
803 FORMAT(9H KER = ,20(13,1H,)) 19010
DFAN=DFANI 19020
ZNTT=ZNTD 19030
C *** PRINT OUT ANY ERRORS 19040
IF(MM)802,802,801 19050
801 WRITE(NF0.803)(KERR(I),1=1,MM) 19060
IF(MOD(KNTRO,5).NE.O)KNTRO=KNTRO+1 19070
802 CONTINUE 19080
C *** RESET ERROR VARIABLES FOR NEXT POINT. AS SUPER IS CALLED 19090
C *** AGAIN AND AGAIN THESE VARIABLES MUST BE RESET 19100
DO 810 1=1,20 19110
810 KERR(I)=0 19120
KER=0 19130
KGO=1 19140
MM=0 19150
1001 CONTINUE 19160
DO 12 J=1,2 19170
TIN(J) = T1ND (J) 19180
TOUT(J)rTOUTD(J) 19190
DNZ(J)=DNZ1(J) 19200
12 W( J)=WD(J) 19210
TD=TIN(1)-TIN(2) 19220
VAPPsVAPPI 19230
DPTOT(1)=0-0 19240
IF(JAKE.NE.1)GO TO 91 19250
ZNTR=ZTRD 19260
ZNTP=ZTPD 19270
NTP=ZNTP+0.01 19280
NTR = ZNTR-t-0.01 19290
ANG(1)=ANGI*PI/1BO. 19300
ANG(2)=SIN(ANG(1)) 19310
ANG(3)=COS(ANG(1 )) 19320
PT=PTI 19330
91 CONTINUE 19340
ZVP=ZBUP*ZBYP 19350
TT(1)=TIN(D 19360
400 CONTINUE 19370
-------
RETURN
END
19380
19390
C
c ***
c ***
c
c ***
c
c
c
c
c
c ***
c
c
c ***
c ***
c ** +
c ***
c ** *
c ***
c ***
c
c ***
SUBROUTINE EXSTP(ZBUP,NBLD,NFAN,ZBPU,CERCT)
THIS SUBROUTINE ESTIMATES THE COST OF ERECTING THE COOLING
TOWER ON THE STRUCTURE
INPUT VARIABLES ***
ZBUP = NUMBER OF BUNDLES PER BAY
NBLD = NUMBER OF BLADES PER FAN
NFAN = NUMBER OF FANS PER BAY
2BPU = NUMBER OF BAYS PER UNIT
OUTPUT VARIABLE ***
CERCT = ERECTION COST ($)
ZBLD=NBLD
ZFAN=NFAN
ASSUME 1600 DOLLARS TO SET AND ALIGN EACH BUNDLE
C1=1600.*ZBUP
ASSUME 1120 DOLLARS TO INSTALL PLENUM
C2=1120.
ASSUME 640 DOLLARS TO INSTALL FAN AND 40 DOLLARS TO BALANCE
EACH BLADE
C3=(40.*ZBLD+640.)*ZFAN
ASSUME 880 DOLLARS FOR INSTALLING RECOVERY STACK
C4=880.*ZFAN
ASSUME 320 DOLLARS FOR ELECTRICAL HOOK-UP OF FAN
C5=320.*ZFAN
ASSUME 240 DOLLARS TO TEST FAN
C6=240.*ZFAN
ASSUME 2.5 FACTOR FOR CONTINGENCIES
CERCT=2.5*ZBPU*(C1+C2+C3+C4+C5+C6)
1000 RETURN
END
19400
19410
19420
19430
19440
19450
19460
19470
19480
19490
19500
19510
19520
19530
19540
19550
19560
19570
19580
19590
19600
19610
19620
19630
19640
19650
19660
19670
19680
19690
19700
19710
19720
19730
-------
en
SUBROUTINE FAN(NFAN,DFAN,NBLD,IDFAN.CFAN1.CTFAN)
*** THIS SUBROUTINE CALCULATES THE COST FOR PURCHASING A FAN
*** INPUT VARIABLES ***
DFAN = FAN DIAMETER (FT)
NBLD = NUMBER OF BLADES PER FAN
IDFAN = FAN TYPE IDENTIFICATION
1 FOR PERMANENTLY FIXED
2 FOR MANUAL ADJUSTABLE
3 FOR AUTOMATIC VARIABLE
*** OUTPUT VARIABLE ***
CFAN1 = COST FOR ONE FAN ($)
ZFAN=NFAN
ZBLD=NBLD
IF (IDFAN-2) 100,200,200
100 CONTINUE
GO TO 400
INFORMATION FOR THE COST OF FIXED-BLADES TYPE FANS NOT AVAILABLE
AT PRESENT TIME.
COST CALCULATION FOR MANUAL ADJUSTABLE OR AUTOMATIC ADJUSTABLE FAN
200 CONTINUE
FOR FAN DIAMETER GREATER THAN 20 FT, THE COST IS CALCULATED BASING
ON THE COST OF 28 FT FAN
IF (DFAN-20.0) 210,240,240
210 CONTINUE
THI INFORMATION FOR COST OF FAN UNDER 20 FT IS NOT AVAILABLE NOW
HERE CALCULATION IS BASED ON THE EXTRAPLOTAION OF THE >20FT FANS
240 CONTINUE
WHEN DFAN=28 FT, THE COST IS
CF28=409.2*ZBLD+300.3
IF (DFAN-28.0) 270,270,280
270 CONTINUE
CFAN1=CF28*(1-0/(1 .0+0.071*(2B.O-DFAN)/2.0))
GO TO 285
280 CONTINUE
CFAN1=CF28*(1.0+0.088*(DFAN-28.0)/2.0)
285 CONTINUE
IF (IDFAN-2) 400,400,300
19740
19750
19760
19770
19780
19790
19800
19810
19820
19830
19840
19850
19860
19870
19880
19890
19900
19910
19920
19930
19940
19950
19960
19970
19980
19990
20000
20010
20020
20030
20040
20050
20060
20070
20080
20090
20100
201 10
20120
20130
20140
20150
20160
20170
20180
20190
20200
20210
20220
20230
-------
300 CFAN1=CFAN1+250.0*ZBLD 20240
C FOR FANS WITH AUTOMATIC ADJUSTABLE BLADES, ADD EXTRA COST AT 250$ 20250
C PER BLADE 20260
C 20270
400 CONTINUE 20280
CTFAN=ZFAN*CFAN1 20290
C 20300
RETURN 20310
END 20320
SUBROUTINE FANCON(CFMB,rTPB,BETA,KODE.HPB,KSTEP,TPS,EFF,HPA,SIZEA. 20330
1DENA,CFMA,FTPA,NB,VTIPA,RPMA) 20340
DIMENSION BLANG(9),TP(9),HP(9) 20350
KODE = 0 20360
TPS = 0.0 20370
HPA = 0.0 20380
KSTEP = 0 20390
BETA = 0.0 20400
EFF = 0.0 20410
J = 0 20420
DENB = 0.075 20430
VTIPB = 12000. 20440
SIZES = 28.0 20450
INC = 4 20460
ISTART = 2 20470
4 IF(NB-8)15,5,6 20480
5 INC = 2 20490
ISTART = 6 20500
IB = 3 20510
GO TO 100 20520
6 IF(NB-9)15,7,8 20530
7 CONTINUE 20540
ISTART = 6 20550
IB = 4 20560
GO TO 100 20570
8 IF(NB-10}15,9,10 20580
9 IB = 5 20590
GO TO 100 20600
10 IF(NB-11)15,12,13 20610
12 SIZEB = 30.0 20620
IB = 6 20630
GO TO 100 20640
-------
13
14
15
16
100
C ***
103
104
105
106
107
110
120
130
C ** *
140
** *
150
160
200
C ***
C
250
*»*
260
IF(NB-12)15,14,15
IB = 7
GO TO 100
WRITE(6.16)
FORMAT(31H THERE IS NO DATA FOR THIS CASE)
CONTINUE
FAN LAWS BELOW ALLOW US TO EXTRAPOLATE TO ANY FLOW, SIZE OR RPM
VRATIO = VTIPA/VTIPB
RPMB = VTIPB/(SIZEB*3.14159)
RPMA = VTIPA/(SIZEA*3.14159)
CFMB = ((SIZEB/SIZEA)**2)*CFMA *VRATIO
FTPS = FTPA *(DENB/DENA)*(VRATIO**2)
IB=IB-2
00 200 IX = ISTART.22.1NC
J = d + 1
I = J
BLANG(I) = IX
GO T0(103,104,105,106,107),IB
CALL FDPNB8(CFMB,TP(I),BLANG(I),NB,KEXDP)
GO TO 110
CALL FDPNB9(CFMB,TP(I),BLANG(I)
GO TO 110
CALL FDPNB10(CFMB,TP( I ) ,
GO TO 110
CALL FDPNB11(CFMB.TP(I)
GO TO 110
CALL FDPNB12(CFMB,TP(I),BLANG(I),NB,KEXDP)
CONTINUE
IF(TP(I)-1.£-9)200,200,120
IF(FTPB-TP(I))130,130,160
IF(KODE)150,150,140
CALC BETA-THE INTERPOLATED VALUE OF BLADE ANGLE ONLY IF KODE=1
BETA = ((FTPB-TP(I-1))/(TP(I)-TP(I-1)))*(BLANG(I)-BLANG(I-1)) +
1BLANG(1-1)
GO TO 250
SET THE LOWEST VALUE OF BLADE ANGLE -INDICATES SMALLER FAN NEEDED
BETA = BLANG(I)
KSTEP = -1
GO TO 1000
KODE = 1
CONTINUE
AT THIS POINT AN ERROR MUST BE SET BECAUSE THE FAN CHARACTERISTICS
DO NOT SUIT THE SIZE UNDER DISCUSSION . STEP UP TO NEXT FAN SIZE.
KSTEP = 1
BETA = 22.0
GO TO 1000
CONTINUE
IF(J-1 )260,260,270
d MUST BE GREATER THAN 1
WRITE(6,400)
.NB.KEXDP)
BLANG(I),NB,KEXDP)
BLANG(I),NB.KEXDP)
20650
20660
20670
20680
20690
20700
20710
20720
20730
20740
20750
20760
20770
20780
20790
20800
20810
20820
20830
20840
20850
20860
20870
20880
20890
20900
20910
20920
20930
20940
20950
20960
20970
20980
20990
21 000
21010
21020
21 030
21040
21050
21060
21070
21 080
21090
21 100
21 110
21 120
21 130
21 140
-------
I
-p>
00
GO TO 1000
270 CONTINUE
C »** FIND THE FAN HORSEPOWER WHICH SUITS THE CFMB AND BETA FOUND ABOVE
C *** CONVERT BACK TO FAN UNDER CONSIDERATION
GO T0(303,304,305,306,307),IB
303 CALL FHPNB8(CFMB,HP(J-1),BLANG(J-1),NB.KEXHP)
CALL FHPNB8(CFMB,HP(d),BLANG(J).NB.KEXHP)
GO TO 310
304 CALL FHPNB9(CFMB,HP(J-1),BLANG(J-1).NB.KEXHP)
CALL FHPNB9(CFMB,HP(J),BLANG(J),NB.KEXHP)
GO TO 310
305 CALL FHPNB10(CFMB,HP(J-1),BLANG(J-1).NB.KEXHP)
CALL FHPNB10(CFMB,HP(d),BLANG(J).NB.KEXHP)
GO TO 310
306 CALL FHPNB11(CFMB,HP(d-1),BLANG(J-1).NB.KEXHP)
CALL FHPNB11(CFMB,HP(J).BLANG(J).NB.KEXHP)
GO TO 310
307 CALL FHPNB12(CFMB,HP(J-1),BLANG(J-1).NB.KEXHP)
CALL FHPNB12(CFMB,HP(d),BLANG(J).NB.KEXHP)
310 CONTINUE
HPB =((BETA-BLANG(d-1))/(BLANG(J)-BLANG(J-1)))*(HP(J)-HP(J-1)) +
1HP(J-1 )
C ** *
CONVERT BACK TO FAN UNDER CONSIDERATION
HPA = HPB *((SIZEA/SIZEB)**2)*(DENA/DENB)*(VRATIO**3)
EFF = (CFMB*1000.0*FTPB)/(6356.0*HPB)
C *** MAKE SOME CHECKS TO DETERMINE IF FAN IS NEAR STALL POINT
C *** FOR THE BETA BLADE ANGLE FIND IF THE DP IS LOWERED AS THE CAPACITY
C IS LOWERED BY 10 PERCENT
CFM = .90*CFMB
C *** IF LOWER HP THEN WE ARE ENTERING STALL REGION
GO 10(313,314,315.316,317),IB
313 CALL FDPNB8(CFM,TP(J),BLANG(J),NB,K)
CALL FDPNB8(CFM,TP(J-1),BLANG(J-1),NB.K)
GO TO 320
314 CALL FDPNB9(CFM,TP(J),BLANG(J),NB,K)
CALL FDPNB9(CFM,TP(J-1).BLANG(d-1),NB,K)
GO TO 320
315 CALL FDPNB10(CFM.TP(J),BLANG(J),NB,K)
CALL FDPNB10(CFM,TP(J-1).BLANG(J-1),NB,K)
GO TO 320
316 CALL FDPNB11(CFM.TP(J).BLANG(J),NB,K)
CALL FDPNB11(CFM.TP(J-1),BLANG(J-1),NB,K)
GO TO 320
317 CALL FDPNB12(CFM,TP(d),BLANG(J),NB,K)
CALL FDPNB12(CFM,TP(J-1),BLANG(d-1),NB,K)
320 CONTINUE
400 FORMAT(38H SOMETHING IS WRONG,J=1 AT THIS POINT)
TPS=((BETA-BLANG(d-1))/(BLANG(J)-BLANG(d-1)))*(TP(J)-TP(J-1)) +
1TP(J-1)
IF(TPS-FTPB)550,550,1000
21 150
21 160
21 170
21 180
21 190
21200
21210
21220
21230
21240
21250
21260
21270
21280
21290
21 300
21310
21 320
21330
21340
21350
21360
21370
21380
21390
21400
21410
21420
21 430
21 440
21450
21460
21470
21480
21490
21 500
21510
21520
21530
21540
21550
21560
21570
21580
21590
21600
21610
21620
21630
21640
-------
550 KSTEP = -2
1000 CONTINUE
RETURN
END
21650
21660
21670
21680
SUBROUTINE FDPNB8(CFM,DP.ANGLE,NB,KEXDP) 21690
C *** THIS SUBROUTINE CALCULATES FAN TOTAL PRESSURE DROP-GIVEN THE BLADE 21700
C *** ANGLE AND FLOW -FOR 8 BLADES -28FT. FAN 21710
KEXDP = 0 21720
IF(NB-6)7,7,8 21730
7 CONTINUE 21740
8 IF(NB-8)9,9,11 21750
11 GO TO 3000 21760
9 CONTINUE 21770
2001 IF(ANGLE-6.01)2002,2002,2007 21780
2002 IF(CFM-840.)2003,2003,2004 21790
2003 DP =-8.0294E-4 *CFM +1.0744 21800
GO TO 3000 21810
2004 IF(CFM-1045.)2005,2005,2006 21820
2005 DP =-9.512E-4 *CFM +1.199 21830
2006 KEXDP = 6 21840
C *** EQUATION GOOD FROM 840 TO 1045 21850
GO TO 3000 21860
2007 IF(ANGLE-8.01)2008,2008,2013 21870
2008 IF(CFM -830.)2009,2009,2010 21880
2009 DP =-7.838E-4 *CFM +1.1905 21890
GO TO 3000 21900
2010 IF(CFM -1172.)201 1 .2011 .2012 21910
2011 DP = -8.246E-4 *CFM +1.2244 21920
C *** EQUATION GOOD FROM 830 TO 1172 21930
2012 KEXDP = 8 21940
GO TO 3000 21950
2013 IF(ANGLE-10.01)2014,2014,2019 21960
2014 IF(CFM -1090.)2015,2015,2016 21970
2015 DP =-7.672E-4 *CFM +1.3163 21980
GO TO 3000 21990
2016 IF(CFM -1280.)2017,2017,2018 22000
2017 DP =-9.474E-4 *CFM +1.513 22010
2018 KEXDP =10 22020
C *»* EQUATION GOOD FROM 1090 TO 1280 22030
GO TO 3000 22040
2019 IF(ANGLE-12.01)2020,2020,2027 22050
-------
en
o
2020 IF(CFM -900.0)2021 ,2021,2022
2021 DP =-5.1E-4 *CFM + 1.237
GO TO 3000
2022 IF(CFM -1130. )2023,2023,2024
2023 DP = -7.74E-4 *CFM +1.4745
GO TO 3000
2024 IF(CFM -1400.)2025,2025,2026
2025 DP =-B.89E-4 *CFM + 1.6044
2026 KEXDP = 12
C *** EQUATION GOOD FROM 1130 TO 1400
GO TO 3000
2027 IF(ANGLE- 14.01)2028,2028,2039
2028 IF(CFM -800.)2029,2029,2030
2029 DP =-2.033E-4*CFM +1.1017
GO TO 3000
2030 IF(CFM-900.)2031,2031,2032
2031 DP =-6.4E-4*CFM +1.451
GO TO 3000
2032 IF(CFM-1Q30.)2033,2033,2034
2033 DP =-4.23E-4*CFM +1.2558
GO TO 3000
2034 IF(CFM-1200.)2035,2035,2036
2035 DP =-7.06E-4 *CFM +1.5471
GO TO 3000
2036 IF(CFM -1540.)2037,2037,2038
2037 DP =-7.647E-4 *CFM +1.61765
2033 KEXDP = 14
C *** EQUATION GOOD FROM 1200 TO 1500
GO TO 3000
2039 IF(ANGLE -16.01)2040,2040,2049
2040 IF(CFM-1110.)2041,2041,2042
2041 DP =-3.9E-4 *CFM + 1.2917
GO TO 3000
2042 IF(CFM - 1250.)2043,2043,2044
2043 DP =-5.714E-4 *CFM +1.4943
GO TO 3000
2044 IF(CFM -1430.)2045,2045,2046
2045 DP =-7.22E-4*CFM +1.6828
GO TO 3000
2046 IF(CFM-1625.)2047,2047,2048
2047 DP =-8.21E-4 *CFM + 1.8233
2048 KEXDP = 16
C *** EQUATION GOOD FROM 1430 TO 1625
GO TO 3000
2049 IF(ANGLE-18.01)2050,2050,2069
2050 IF(CFM -600.)2051,2051,2052
2051 DP =-0.001*CFM +1.02
GO TO 3000
2052 IF ( CFNI-750. ) 2053, 2053 ,2054
2053 DP = 0.96
22060
22070
22080
22090
22100
221 10
22120
22130
22140
22150
22160
22170
22180
22190
22200
22210
22220
22230
22240
22250
22260
22270
22280
22290
22300
22310
22320
22330
22340
22350
22360
22370
22380
22390
22400
22410
22420
22430
22440
22450
22460
22470
22480
22490
22500
22510
22520
22530
22540
22550
-------
I
en
GO TO 3000
2054 IF(CFM-900.)2055,2055,2056
2055 DP=0.00012*CFM +0.87
GO TO 3000
2056 IF(CFM -1000.)2057,2057,2058
2057 DP = 0.978
GO TO 3000
2058 IF(CFM-1090.)2059,2059,2060
2059 DP =-3.11E-4 *CFM +1.2891
GO TO 3000
2060 IF(CFM -1200.)2061,2061,2062
2061 DP =-3.64E-4 *CFM + 1.3468
GO TO 3000
2062 IF(CFM-1330.)2063,2063,2064
2063 DP =-5.39E-4 *CFM +1.55621
GO TO 3000
2064 IF(CFM - 1500.)2065,2065,2066
2065 DP=-7.06E-4 * CFM +1.779
GO TO 3000
2066 IF(CFM-1710.)2067,2067,2068
2067 DP=-8.10E-4 *CFM +1.9353
2068 KEXDP =18
C *** EQUATION GOOD FROM 1500 TO 1710
GO TO 3000
2069 IF(ANGLE-20.01)2070,2070,2079
2070 IF(CFM-1370.)2071,2071,2072
2071 DP=-3.33E-4 *CFM +1.3667
GO TO 3000
2072 IF(CFM-1470.)2073,2073,2074
2073 DP=-5E-4 *CFM +1.595
GO TO 3000
2074 IF(CFM-1610.)2075,2075,2076
2075 DP =-7.143E-4 »CFM + 1.91
GO TO 3000
2076 IF(CFM-1770.)2077,2077,2078
2077 DP =-1.25E-3 *CFM + 2.7725
2078 KEXDP = 20
C *** EQUATION GOOD FROM 1610 TO 1770
GO TO 3000
2079 IF(ANGLE-22.01)2080,2080,3000
2080 IF(CFM-600.)2081,2081,2082
2081 DP = -0.00015*CFM +1.05
GO TO 3000
2082 IF(CFM-850.)2083,2083,2084
2083 DP = 0.96
GO TO 3000
2084 IF(CFM -1100.)2085,2085,2086
2085 DP =0.00016*CFM +0.824
GO TO 3000
2086 IF(CFM -1250.)2087,2087,2088
22560
22570
22580
22590
22600
22610
22620
22630
22640
22650
22660
22670
22680
22690
22700
22710
22720
22730
22740
22750
22760
22770
22780
22790
22800
22810
22820
22830
22840
22850
22860
22870
22830
22890
22900
22910
22920
22930
22940
22950
22960
22970
22980
22990
23000
23010
23020
23030
23040
23050
-------
I
CJ1
2087 DP =0.000067* CFM + 0.9267
GO TO 3000
2088 IF(CFM -1350.)2089,2089,2090
2089 DP=-0.0001*CFM + 1.135
GO TO 3000
2090 IF(CFM -1450.)2091 ,2091 ,2092
2091 DP=-0.0002*CFM + 1.27
GO TO 3000
2092 IF(CFM -1530.)2093,2093,2094
2093 DP =-0.0005 *CFM + 1.705
GO TO 3000
2094 IF(CFM -1650.)2095,2095,2096
2095 DP = -0.00065 *CFM + 1.9345
GO TO 3000
2096 IF(CFM -1770.)2097,2097,2098
2097 DP = -0.00085*CFM +2.2645
GO TO 3000
C *** EQUATION GOOD FROM 1650 TO 1770
2098 KEXDP =22
3000 DP =AMAX1(0.0,DP)
RETURN
END
23060
23070
23080
23090
23100
23 110
23120
23130
23140
23150
23160
23170
23180
23190
23200
23210
23220
23230
23240
23250
23260
23270
SUBROUTINE FDPNB9(CFM,DP,ANGLE,NB,KEXDP) 23280
C *** THIS SUBROUTINE CALCULATES FAN TOTAL PRESSURE DROP-GIVEN THE BLADE 23290
C *** ANGLE AND FLOW-CFM -FOR 9 BLADES -12000 FPM-136 RPM.28FT. FAN 23300
C *** DP - IS THE CORRECTED TOTAL PRESSURE DROP,INCH OF H20 23310
C *** CFM - IS THE ACTUAL FLOW RATE IN 10E3 CUBIC FOOT PER MINUTE 23320
C *** HP - CURVE HP WHICH MUST BE CORRECTED FOR DENSITY RATIO.THE EFFECT 23330
C *** OF ALTITUDE,AND SPEED FACTOR. CURVE IS BASED ON 12000 FT/MIN TIP 23340
C »** SPEED 23350
KEXDP=0 23360
IF(ANGLE-6.01)35,35,80 23370
35 IF(CFM-750.)40,40,45 23380
40 DP=-8.E-4*CFM+1.125 23390
GO TO 600 23400
45 IF(CFM-900.)50,50,55 23410
50 DP=-9.66666E-4*CFM+1.25 23420
GO TO 600 23430
55 IF(CFM-1050.)60,60,58 23440
58 KEXDP=6 23450
60 DP=-1.16666E-3*CFM+1.43 23460
-------
en
CO
C »** EQUATION GOOD FROM 900 TO 1050
GO TO 600
80 IF(ANGLE-10.01)85,85,170
85 IF(CFM-1040)90,90,95
90 DP=-B.38888E-4*CFM+1.44944
GO TO 600
95 IF(CFM-1180.)100,100,105
100 DP=-1.01428E-3*CFM+1.63185
GO TO 600
105 IF(CFM-1285.)110,110,108
108 KEXDP=10
110 DP = -1 .20952E-3*CFM-t-1 .86224
C *** EQUATION GOOD FROM 1180 TO 1285
GO TO 600
170 1F(ANGLE-14.01)175,175,260
175 IF(CFM-730.)180,180,185
180 DP=-8.69565E-5*CFM+1.09347
GO TO 600
185 IF(CFM-900.)190,190,195
190 DP=-4.11765E-4+CFM+1.33059
GO TO 600
195 IF(CFM-1150.)200,200,205
200 DP=-6.8E-4*CFM+1.5720
GO TO 600
205 IF(CF!VI-155B. )210,210,208
208 KEXDP=14
210 DP = -8.45588E-4*CFM-M .76242
C *** EQUATION GOOD FROM 1150 TO 1558
GO TO 600
260 IF(ANGLE-18.01)325,325,390
325 IF(CFM-740.)330,330,335
330 DP=1.05
GO TO 600
335 IF(CFM-930.)340,340,345
340 DP=1.31579E-4*CFM+0.95263
GO TO 600
345 IF(CFM-1010.)350.350,355
350 DP = -6.25E-5*CFM-t-1 . 13312
GO TO 600
355 IF(CFM-1 190.)360,360,365
360 DP=-3.38888E-4*CFM+1.41228
GO TO 600
365 IF
-------
en
390 IF(ANGLE-22.01)410,410i600
410 IF(CFM-840.)420,420,425
420 DP = -4.41176E-5*CFM-M .07206
GO TO 600
425 IF(CFM-1170.)430,430,435
430 DP=2.12121E-4*CFM+0.85682
GO TO 600
435 IF(CFM-1360.)440,440,445
440 DP=-2.63158E-5+CFM+1.13579
GO TO 600
445 IF(CFM-1490. )450,450,455
450 DP=-3.84615E-4*CFM+1.62307
GO TO 600
4S5 IF(CFM-1630.)460,460,465
460 DP=-6.78571E-4*CFM+2.06107
GO TO 600
465 IF(CFM-1770.)470,470,468
468 KEXDP=22
470 DP=-9.28571E-4*CFM+2.46857
C *** EQUATION GOOD FROM 1630 TO 1770
C *** NEVER ALLOW THE PRESSURE DROP TO BE LESS THAN ZERO
600 DP=AMAX1(0.0,DP)
RETURN
END
23970
23980
23990
24000
24010
24020
24030
24040
24050
24060
24070
24080
24090
24100
241 10
24120
24130
24140
24150
24160
24170
24180
24190
24200
SUBROUTINE FDPNB10(CFM,DP,ANGLE,NB,KEXDP)
C *** THIS SUBROUTINE CALCULATES FAN TOTAL PRESSURE DROP-GIVEN THE BLADE
C *** ANGLE AND FLOW -CFM-FOR 10 BLADES -12000FPM -136RPM -28FT. FAN
KEXDP = 0
IF(ANGLE-2.01)15,15,100
15 IF(CFM-700.)20,20,25
20 DP = -1.125E-3*CFM+1. 1025
GO TO 600
25 IF(CFM-840.)30,30,28
28 KEXDP=2
30 DP=-1-39285E-3*CFM+1.2899
C *** EQUATION GOOD FROM 700 TO 840
GO TO 600
100 IF(ANGLE-6.01)105,105,200
105 IF(CFM-BOO.)110,110,115
110 DP=-9.44444E-4*CFM+1.28055
GO TO 600
24210
24220
24230
24240
24250
24260
24270
24280
24290
24300
24310
24320
24330
24340
24350
24360
24370
-------
I
en
tn
115 IF(CFM-960.)120.120,125
120 DP=-1.09375E-3*CFM+1.4
GO TO 600
125 IF(CFM-1070.)130,130,128
128 KEXDP=6
130 DP=-1.36363E-3*CFM+1.65909
C *** EQUATION GOOD FROM 960 TO 1070
GO TO 600
200 IF(ANGLE-10.01)205,205,300
205 IF(CFM-730.)210,210,215
210 DP=-6.25E-4*CFM+1.37625
GO TO 600
215 IF(CFM-920.)220,220,225
220 DP=-8.94736E-4*CFM+1.57315
GO TO 600
225 IF(CFM-1310.)230,230,228
228 KEXDP=10
230 DP = -1 .12820E-3*CFM-H .78795
C *** EQUATION GOOD FROM 920 TO 1310
GO TO 600
300 IF(ANGIE-14.01)305,305,400
305 IF(CFM-770.)310,310,315
310 DP=-2.22222E-4*CFM+1.26111
GO TO 600
315 IF(CFM-970.)320.320,325
320 DP = -4.5E-4*CFM+1 .4365
GO TO 600
325 IF(CFM-1200.)330.330,335
330 DP=-7.82608E-4*CFM+1 .75913
GO TO 600
335 IF(CFM-1580.)340,340,338
338 KEXDP=14
340 DP=-9.73684E-4*CFM+1.98842
C *** EQUATION GOOD FROM 1200 TO 1580
GO TO 600
400 IF(ANGLE-18.01)405,405,500
405 IF(CFM-700.)410,410,415
410 DP=-6.0E-5*CFM-H .2
GO TO 600
415 IF(CFM-950.)420,420,425
420 DP=1.2E-5*CFM+1.1496
GO TO 600
425 IF(CFM-1100.)430,430,435
430 DP=-1.53333E-4*CFM+1.30666
GO TO 600
435 IF(CFM-1250.)440,440,445
440 DP=-4.53333E-4*CFM+1.63666
GO TO 600
445 IF(CFM-1440.)450,450,455
450 DP=-7.36842E-4*CFM+1.99105
24380
24390
24400
24410
24420
24430
24440
24450
24460
24470
24480
24490
24500
24510
24520
24530
24540
24550
24560
24570
24580
24590
24600
24610
24620
24630
24640
24650
24660
24670
24680
24690
24700
24710
24720
24730
24740
24750
24760
24770
24780
24790
24800
24810
24820
24830
24840
24850
24860
24870
-------
I
en
01
GO TO 600
455 IF(CFM-1600.)460,460,465
460 DP=-1.OE-3*CFM+2.37
GO TO 600
465 IF(CFM-1770.)470,470,468
468 KEXDP=18
470 DP=-1.11764E-3*CFM+2.55823
C *** EQUATION GOOD FROM 1600 TO 1770
GO TO 600
500 IF(ANGLE-22.01)505,505,600
505 IF(CFM-800.)510.510,515
510 DP=-8.33333E-5*CFM+1.19666
GO TO 600
515 IF(CFM-1100.)520,520,525
520 DP=2.33333E-4*CFM+0.94333
GO TO 600
525 IF(CFM-1300.)530,530,535
530 DP=2.5E-5*CFM+1.1725
GO TO 600
535 IF(CFM-1420.)540,540,545
540 DP=-2.25E-4*CFM+1.4975
GO TO 600
545 IF(CFM-1570.)550,550,555
550 DP=-6.2E-4*CFM+2.0584
GO TO 600
555 IF(CFM-1770.)560,560,558
558 KEXDP=22
560 DP=-9.25E-4*CFM+2.53725
C *** EQUATION GOOD FROM 1570 TO 1770
600 DP=AMAX1(0.0,DP)
RETURN
END
24880
24890
24900
24910
24920
24930
24940
24950
24960
24970
24980
24990
25000
25010
25020
25030
25040
25050
25060
25070
25080
25090
25100
251 10
25120
25130
25140
25150
25160
25170
25180
25190
SUBROUTINE FDPNB11(CFM,DP,ANGLE,NB.KEXDP) 25200
C «** THIS SUBROUTINE CALCULATES FAN TOTAL PRESSURE DROP-GIVEN THE BLADE 25210
C *** ANGLE AND FLOW-CFM-FOR 11BLADES -12000FPM -127RPM -30FT. FAN 25220
KEXDP=0 n!o^«
IF(ANGLE-2.01)15,15.100 25240
15 IF(CFM-800.)20,20,25 25250
20 DP=-8.5E-4*CFM+.95 25260
GO TO 600 25270
25 1F(CFM-955.)30,30.28 25280
-------
I
CJ1
28 KEXDP=2
30 DP=-9.6774E-4*CFM+1.04419
C *** EQUATION GOOD FROM 800 TO 955
GO TO 600
100 IF(ANGLE-6.01)105,105,200
105 IF(CFM-1280.)110,110,108
108 KEXDP=6
110 DP=-7.72058E-4*CFM+1.22823
C *** EQUATION GOOD FROM 600 TO 1280
GO TO 600
200 IF(ANGLE-10.01)205.205,300
205 IF(CFM-800.)210,210,215
210 DP=-4.5E-4*CFM+1.25
GO TO 600
215 IF(CFM-1300.)220,220,225
220 DP=-6.6E-4*CFM+1.418
GO TO 600
225 IF(CFM-1560.)230,230,228
228 KEXDP=10
230 DP=-8.07692E-4*CFM+1.61
C **+ EQUATION GOOD FROM 1300 TO 1560
GO TO 600
300 IF(ANGLE-14.01)305.305,400
305 IF(CFM-900.)310,310,315
310 DP=-5.E-5*CFM+1.1
GO TO 600
315 IF(CFM-1100.)320,320,325
320 DP=-3.25E-4*CFM+1.3475
GO TO 600
325 IF(CFM-1300.)330,330,335
330 DP = -5.5E-4*CFM-H .595
GO TO 600
335 IF(CFM-1870.)340,340,338
338 KEXDP=14 14
340 DP=-6.0526E-4*CFM+1.66684
C *** EQUATION GOOD FROM 1300 TO 1870
GO TO 600
400 IF(ANGLE-18.01)405,405,500
405 IF(CFM-1300.)410,410,415
410 DP=1.42857E-5*CFM+1 .09
GO TO 600
415 IF(CFM-1450.)420,420,425
420 DP=-2.33333E-4*CFM+1.41333
GO TO 600
425 IF(CFM-1600.)430,430,435
430 DP=-4.E-4*CFM+1.655
GO TO 600
435 IF(CFM-1870.)440,440,438
438 KEXDP=18
440 DP*-5.E-4*CFM*1.815
25290
25300
25310
25320
25330
25340
25350
25360
25370
25380
25390
25400
25410
25420
25430
25440
25450
25460
25470
25480
25490
25500
25510
25520
25530
25540
25550
25560
25570
25580
25590
25600
25610
25620
25630
25640
25650
25660
25670
25680
25690
25700
25710
25720
25730
25740
25750
25730
25770
25780
-------
I
en
C *** EQUATION GOOD FROM 1600 TO 1870
GO TO 600
500 IF(ANGLE-22.01)505,505,600
505 IF(CFM-1000.)510,510,515
510 DP=1.75E-4*CFM+.935
GO TO 600
515 IF(CFM-1400.)520,520,525
520 DP=1.25E-4*CFM+.985
GO TO 600
525 IF(CFM-1600.)530,530,535
530 DP=-5.E-5*CFM+1 .23
GO TO 600
535 IF(CFM-1870.)540,540,538
538 KEXDP=22
540 DP=-2.96296E-4*CFM+1.62407
C *** EQUATION GOOD FROM 1600 TO 1870
600 DP=AMAX1(.0,DP)
RETURN
END
25790
25800
25810
25820
25830
25840
25850
25860
25870
25880
25890
25900
25910
25920
25930
25940
25950
25960
25970
SUBROUTINE FDPNB12(CFM,DP,ANGLE,NB,KEXDP) 25980
C *** THIS SUBROUTINE CALCULATES FAN TOTAL PRESSURE DROP-GIVEN THE BLADE 25990
C *** ANGLE AND FLOW -CFM-FOR 12 BLADES -12000FPM -136RPM -28FT. FAN 26000
KEXDP=0 26010
IF(ANGLE-2-01)35,35,100 26020
35 IF(CFM-720.)40,40,45 26030
40 DP=-1.31818E-3*CFM+1.29909 26040
GO TO 600 26050
45 IF(CFM-860.)50,50,48 26060
48 KEXDP=2 26070
50 DP=-1.60714E-3+CFM+1.50714 26080
C *** EQUATION GOOD FROM 720 TO 860 26090
GO TO 600 26100
100 IF(ANGLE-6.01)105,105,200 26110
105 IF(CFM-900.)110,110,115 26120
110 DP=-1.14285E-3*CFM+1.54357 26130
GO TO 600 26140
115 IF(CFM-1000.)120,120,125 26150
120 DP=-1.45E-3*CFM+1.82 26160
GO TO 600 26170
125 IF(CFNI-1095.)130,130,128 26180
128 KEXDP=6 26190
-------
en
130 DP=-1.57894E-3*CFM+1.94894
C *** EQUATION GOOD FROM 1000 TO 1095
GO TO 600
200 IF(ANGLE-10.01)205,205,300
205 IF(CFM-750.)210,210,215
210 DP=-7.5E-4*CFM+1 .6175
GO TO 600
215 IF(CFM-850.(220,220,225
220 DP = -9.5E-4*CFM-H .7675
GO TO 600
225 IF(CFM-1000.)230,230,235
230 DP=-1.2E-3*CFM+1.98
GO TO 600
235 IF(CFM-1340.)240,240,238
238 KEXDP=10
240 DP=-1.32353E-3+CFM+2.10353
C *** EQUATION GOOD FROM 1000 TO 1340
GO TO 600
300 IF(ANGLE-14.01)305,305,400
305 IF(CFM-750.)310,310,315
310 DP=-2.4E-4*CFM+1.45
GO TO 600
315 IF(CFM-940.)320,320,325
320 DP=-5.26315E-4*CFM+1.66473
GO TO 600
325 IF(CFM-1100.)330,330,335
330 DP=-8.125E-4*CFM+1.93375
GO TO 600
335 1F(CFM-1300.)340,340,345
340 DP = -1 .E-3*CFM-»-2. 14
GO TO 600
345 IF(CFM-1630.)350,350,348
348 KEXDP=14
350 DP=-1.0909E-3*CFM+2.25818
C **+ EQUATION GOOD FROM 1300 TO 1630
GO TO 600
400 IF(ANGLE-18.01)405,405,500
405 1FICFM-650.)410,410,415
410 DP = -1.33333E-4+CFM-H .42666
GO TO 600
415 IF(CFM-800.)420,420.425
420 DP=1,03333E-4*CFM+1.27283
GO TO 600
425 IF(CFM-1000.)430,430,435
430 DP = -7.75E-5*CFM+1 .4175
GO TO 600
435 IF(CFM-1150.)440,440,445
440 DP = -3.33333E-4*CFM-H .67333
GO TO 600
445 IF(CFM-1300.)450,450,455
26200
26210
26220
26230
26240
26250
26260
26270
26280
26290
26300
26310
26320
26330
26340
26350
26360
26370
26380
26390
26400
26410
26420
26430
26440
26450
26460
26470
26480
26490
26500
26510
26520
26530
26540
26550
26560
26570
26580
26590
26600
26610
26620
26630
26640
26650
26660
26670
26680
26690
-------
I
O
450 DP=-6.66666E-4*CFM+2.05666
GO TO 600
455 IF(CFM-1500.)460,460,465
460 DP=-9.5E-4*CFM+2.425
GO TO 600
465 IF(CFM-1760.)470,470,468
468 KEXDP=18
470 DP=-1.15384E-3+CFM+2.73076
C *** EQUATION GOOD FROM 1500 TO 1760
GO TO 600
500 IF(ANGLE-22.01)505,505,600
505 IFICFM-950.)510.510,515
510 DP=1.33
GO TO 600
515 IF(CFM-1240.)520,520,525
520 DP=2.41379E-4*CFM+1.10068
GO TO 600
525 IF(CFM-1350.)530,530,535
530 DP=-9.0909E-5*CFM+1.51272
GO TO 600
535 IF(CFM-1460.)540,540,545
540 DP=-4.54545E-4*CFM+2.00363
GO TO 600
545 IF(CFM-1600.)550,550,555
550 DP=-7.8571E-4*CFM+2.48714
GO TO 600
555 IF(CFM-1770.)560,560,558
558 KEXDP=22
560 DP=-1.11764E-3*CFM+3.01823
C *** EQUATION GOOD FROM 1600 TO 1770
600 DP=AMAX1(0.0,DP)
RETURN
END
26700
26710
26720
26730
26740
26750
26760
26770
26780
26790
26800
26810
26820
26830
26840
26850
26860
26870
26880
26890
26900
26910
26920
26930
26940
26950
26960
26970
26980
26990
27000
27010
27020
SUBROUTINE FHPNB8(CFM,HP,ANGLE,NB.KEXHP) 27030
C *** THIS SUBROUTINE CALCULATES FAN HORSPOWER-GIVEN THE BLADE ANGLE 27040
C *** AND FLOW-CFM -FOR 8 BLADES ,2BFT. FAN 27050
KEXHP = 0 27060
IF(ANGLE-6.01)1001,1001,1010 27070
1001 IF(CFM -650.)1002,1002,1003 . 27080
1002 HP = -0.00667«CFM +82.335 27090
GO TO 3OOO 27100
-------
1003 IF(CFM -790.J1004,1004,1005
1004 HP =-0.05714* CFM +115.14
GO TO 3000
1005 IF(CFM - 940.)1006,1006,1007
1006 HP =-0.08* CFM + 133.2
GO TO 3000
1007 IF(CFM -1150.)1008,1008,1009
1008 HP = -0.0619* CFM +116.19
1009 KEXHP =6
C *** EQUATION GOOD FROM 940 TO 1150
GO TO 3000
1010 IF(ANGLE -8.01)1011,1011,1020
1011 IF(CFM -800.)1012,1012,1013
1012 HP = 90.0
GO TO 3000
1013 IF(CFM - 940.)1014,1014, 1015
1014 HP = -0.0357 *CFM + 118.57
GO TO 3000
1015 IF(CFM -1070.)1016,1016,1017
1016 HP =-0.0769* CFM +157.31
GO TO 3000
1017 IF(CFM -1170.)1018.1018,1019
1018 HP =-0.125 *CFM +208.75
1019 KEXHP = 8
C *** EQUATION GOOD FROM 1070 TO 1170
GO TO 3000
1020 IF(ANGLE -10.01)1021,1021,1034
1021 IF(CFM -740.)1022,1022,1023
1022 HP =0.02632 *CFM + 90.53
GO TO 3000
1023 IF(CFM -850. )1024,1024,1025
1024 HP = 110.0
GO TO 3000
1025 IF(CFM -950. )1026M026,1027
1026 HP =-0.02 *CFM + 127.0
GO TO 3000
1027 IF(CFM -1100.)1028,1028,1029
1028 HP =-0.05333 *CFM + 158.67
GO TO 3000
1029 IF(CFM -1200.)1030,1030,1031
1030 HP = -0.1 *CFM +210.0
GO TO 3000
1031 IF(CFM -1280.)1032,1032,1033
1032 HP =-0.1625 *CFM + 285-
C **' EQUATION GOOD FROM 1200 TO 1280
1033 KEXHP = 10
GO TO 3000
1034 IF(ANGLE-1 2.01)1035,1035 ,1046
1035 IF(CFM -910.)1036,1036,1037
1036 HP =0.04167*CFM +97.083
271 10
27120
27130
27140
27150
27160
27170
27180
27190
27200
27210
27220
27230
27240
27250
27260
27270
27280
27290
27300
27310
27320
27330
27340
27350
27360
27370
27380
27390
27400
27410
27420
27430
27440
27450
27460
27470
27480
27490
27500
27510
27520
27530
27540
27550
27560
275'70
275.30
27590
27600
-------
en
no
GO TO 3000
1037 IF(CFM -1000.)1038,1038,1039
1038 HP =135.0
GO TO 3000
1039 IFfCFM -1130.)1040,1040,1041
1040 HP =-0.03846*CFM +173.46
GO TO 3000
1041 IF(CFM -1260.)1042,1042,1043
1042 HP =-0.07692*CFM + 216.9
GO TO 3000
1043 IF(CFM-1400.)1044,1044,1045
1044 HP =-0.125 *CFM + 277.5
C *** EQUATION GOOD FROM 1260 TO 1400
1045 KEXHP = 12
GO TO 3000
1046 IF(ANGLE-14.01)1047,1047,1060
1047 IF(CFM-900.)1048.1048,1049
1048 HP =0.07069*CFM + 93.88
GO TO 3000
1049 IF(CFM-980.)1050,1050,1051
1050 HP =0.03125 *CFM +129.38
GO TO 3000
1051 IF(CFM -11 10.)1052,1052,1053
1052 HP =160.0
GO TO 3000
1053 IF(CFM -1250.)1054,1054,1055
1054 HP = -0.05*CFM + 215.5
GO TO 3000
1055 IFfCFM -1350.)1056,1056,1057
1056 HP =-0.08*CFM + 253.
GO TO 3000
1057 IF(CFM -1530.)1058,1058,1059
1058 HP =-0.09722 *CFM + 276.25
C *** EQUATION GOOD FROM 1350 TO 1530
1059 KEXHP = 14
GO TO 3000
1060 IF(ANGLE -16.01)1061,1061,1072
1061 IFfCFM -1100.)1062,1062,1063
1062 HP =0.059375*CFM + 119.69
GO TO 3000
1063 IF(CFM-1180.)1064,1064,1065
1064 HP = 185.0
GO TO 3000
1065 IFfCFM -1290.)1066,1066,1067
1066 HP =-0.04545*CFM -t-238.64
GO TO 3000
1067 IF(CFM -1400.)1068,1068,1069
1068 HP =-0.06818*CFM -t- 267.96
GO TO 3000
1069 1F(CFM -1600.)1070,1070,1071
27610
27620
27630
27640
27650
27660
27670
27680
27690
27700
27710
27720
27730
27740
27750
27760
27770
27780
27790
27800
27810
27820
27830
27840
27850
27860
27870
27880
27890
27900
27910
27920
27930
27940
27950
27960
27970
27980
27990
28000
28010
28020
28030
28040
28050
28060
28070
28080
28090
28100
-------
00
1070 HP =-0.0975 *CFM +309.
C *** EQUATION GOOD FROM 1400 TO 1600
1071 KEXHP = 16
GO TO 3000
1072 IF(ANGLE-18.01)1073,1073,1086
1073 IF(CFM -900.)1074,1074,1075
1074 HP =0.065*CFM +136.5
GO TO 3000
1075 IF(CFM -1 190.)1076,1076,1077
1076 HP =0.0517 *CFM + 148.45
GO TO 3000
1077 IF(CFM -1270.)1078,1078,1079
1078 HP = 210.0
GO TO 3000
1079 IF(CFM -1370.)1080,1080,1081
1080 HP =-0.025 *CFM + 241.75
GO TO 3000
1081 IF(CFM - 1500.)1082,1082,1083
1082 HP =-0.05769*CFM +286.54
GO TO 3000
1083 IF(CFM -1700.)1084,1084,1085
1084 HP =-0.085*CFM + 327.5
C *** EQUATION GOOD FROM 1500 TO 1700
1085 KEXHP =18
GO TO 3000
1086 IF(ANGLE - 20.01)1087,1087,1098
1087 IF(CFM -1450.)1088,1088,1089
1088 HP = 0.04444 *CFM + 173.06
GO TO 3000
1089 IF(CFM -1500.)1090,1090,1091
1090 HP = 237.5
GO TO 3000
1091 IF(CFM -1600.)1092,1092,1093
1092 HP = -0.025 *CFM +275.
GO TO 3000
1093 IF(CFM -1680.)1094,1094,1095
1094 HP = -0.0625 *CFM + 335.
GO TO 3000
1095 IF(CFM - 1740.)1096,1096,1097
1096 HP = -0.1 * CFM + 398
C *** EQUATION GOOD FROM 1680 TO 1740
GO TO 3000
1097 KEXHP =20
1098 IF(ANGLE-22.01)1099,1099,3000
1099 IF(CFM -1000.)2000,2000,2001
2000 HP =0.024 *CFM +208.
GO TO 3000
2001 IF(CFM -1510.)2002,2002,2003
2002 HP = 0.0745 *CFM + 157.50
GO TO 3000
281 10
28120
28130
28140
28 1 50
28 1 60
28170
28180
28190
28200
28210
28220
28230
28240
28250
28260
28270
28280
28290
28300
28310
28320
28330
28340
28350
28360
28370
28380
28390
28400
28410
28420
28430
28440
28450
28460
28470
28480
28490
28500
28510
28520
28530
28540
28550
28560
28570
285 JO
28590
28600
-------
2003 IF(CFM -1650.)2004,2004,2005
2004 HP = 270.0
GO TO 3000
2005 IF(CFM -1770.)2006,2006,2007
2006 HP =-0.054l67*CFM + 359.4
C *** EQUATION GOOD FROM 1650 TO 1770
GO TO 3000
2007 KEXHP =22
C *** NEVER ALLOW THE HP TO BE LESS THAN ZERO
3000 HP = AMAXI(O.O.HP)
RETURN
END
28610
28620
28630
28*40
28650
28660
28670
28680
28690
28700
28710
28720
SUBROUTINE FHPNB9(CFM,HP,ANGLE,NB,KEXHP) 28730
C *** THIS SUBROUTINE CALCULATES FAN HORSEPOWER-GIVEN THE BLADE ANGLE 28740
C *** AND FLOW-CFM -FOR 9 BLADES,12000 FPM- 136 RPM.28FT. FAN 28750
C *** DP - IS THE CORRECTED TOTAL PRESSURE DROP,INCH OF H20 28760
C *** CFM - IS THE ACTUAL FLOW RATE IN 10E3 CUBIC FOOT PER MINUTE 28770
C *** HP-CURVE HP WHICH MUST BE CORRECTED FOR DENSITY RATIO,THE EFFECT 28780
C *** OF ALTITUDE,AND SPEED FACTOR. CURVE IS BASED ON 12000 FT/MIN TIP 28790
C *** SPEED 28800
KEXHP=0 28810
IF(ANGLE-6.01)35,35,100 28820
35 IF(CFM-680.)40,40,45 28830
40 HP=1 .66666E-2*CFM-t-78. 66666 28840
GO TO 600 28850
45 IF(CFM-800.)50,50,55 28860
50 HP=-4.16666E-2*CFM+118.33328 28870
GO TO 600 28880
55 IF(CFM-940.)60,60,65 28890
60 HP=-7.85714E-2*CFM+147.85711 28900
GO TO 600 28910
65 IF(CFM-1050.)70,70,68 28920
68 KEXHP=6 28930
70 HP=-1.72727E-1*CFM+236.36335 28940
C *** EQUATION GOOD FROM 940 TO 1050 28950
GO TO 600 28960
100 IF(ANGLE-10.01)105,105,200 28970
105 IF(CFM-710.)110,110,115 28980
110 HP=4.28571E-2*CFM+94.57143 28990
GO TO 600 29000
115 IF(CFM-8BO.)120,120,125 29010
-------
on
120 HP=5.88235E-3*CFM+120.82352
GO TO 600
125 IF(CFM-1020.(130,130,135
130 HP=-3.57142E-2*CFM+157.42848
GO TO 600
135 IF(CFM-1170.)140,140,145
140 HP = -1.26666E-1*CFM+250.2
GO TO 600
145 IF(CFM-1285.)150,150,148
148 KEXHP=10
150 HP=-1.913Q4E-1*CFM+325-82608
*** EQUATION GOOD FROM 1170 TO 1285
GO TO 600
200 IF(ANGLE-14.01)205,205,300
205 IF(CFM-770.)210,210,215
210 HP=8.88B8BE-2*CFM+105.55555
GO TO 600
215 IF(CFM-940.)220,220,225
220 HP=5.2941E-2*CFM+133.23529
GO TO 600
225 IF(CFM-1080.)230,230,235
230 HP=7.14285E-3+CFM+176.28571
GO TO 600
235 IF(CFM-1230. )240 ,240,245
240 HP=-4.66666E-2*CFM+234.4
GO TO 600
245 IF(CFM-1380.)250,250,255
250 HP=-8.66666E-2*CFM+283.6
GO TO 600
255 IF(CFM-1565.)260.260,258
258 KEXHP=14
260 HP=-1.56756E-1*CFM+380-32432
; *** EQUATION GOOD FROM 1380 TO 1565
GO TO 600
300 IF(ANGLE-18.01)305,305,400
305 IF(CFM-850.)310,310,315
310 HP=8.28571E-2+CFM+172.57143
GO TO 600
315 IF(CFM-1050.)320,320,325
320 HP = 5.5E-2*CFM-H96.25
GO TO 600
325 IF(CFM-1200.)330,330,335
330 HP=6.66666E-3*CFNH-247.
GO TO 600
335 IF(CFM-1370.)340,340,345
340 Hpr-5.2941 1E-2*CFIVH-318.52941
GO TO 600
345 IF(CFM-1530.)350,350,355
350 HP=-1.125E-1*CFM+400.125
GO TO 600
29020
29030
29040
29050
29060
29070
29080
29090
29100
291 10
29120
29130
29140
29150
29160
29170
29180
29190
29200
29210
29220
29230
29240
29250
29260
29270
29280
29290
29300
29310
29320
29330
29340
29350
29360
29370
29380
29390
29400
29410
29420
29430
29440
29450
29460
29470
29480
29490
29500
29510
-------
355 IF(CFM-1770.)360,360,358
358 KEXHP=18
360 HP=-1.45833E-1*CFM+451.12499
C *** EQUATION GOOD FROM 1530 TO 1770
GO TO 600
400 IF
-------
CTl
GO TO 600
125 IF(CFIY!-1065. )130,130,12B
128 KEXHP=6
130 HP=-1.75757E-1*CFM+245.18181
C *** EQUATION GOOD FROM 900 TO 1065
GO TO 600
200 IF(ANGLE-10.01)205,205,300
205 IF(CFM-850.)210,210,215
210 HP=2.10526E-2*CFM+122.10526
GO TO 600
215 IF(CFM-1050.)220.220,225
220 HP=-5.0E-2*CFM+182.5
GO TO 600
225 IF(CFM-1190.)230,230,235
230 HP = -1 .78571 E-1*CFM+317.5
GO TO 600
235 IF(CFM-1310.)240,240,238
238 KEXHP=10
240 HP = -2.91 666E-1+CFM+452.08333
C *** EQUATION GOOD FROM 1190 TO 1310
GO TO 600
300 IF(ANGIE-14.01)305,305,400
305 IF(CFM-1050.)310,310,315
310 HP=3.63636E-2*CFM+161.81818
GO TO 600
315 IF(CFM-1260.)320,320,325
320 HP=-4.76190E-2*CFM-t-250.
GO TO 600
325 IF(CFM-1580.)330,330,328
328 KEXHP=14
330 HP=-1.5625E-1*CFM+386.875
C *** EQUATION GOOD FROY 1260 TO 1580
GO TO 600
400 IF(ANGLE-18.01)405,405,500
405 IF(CFM-1200.)410,410,415
410 HP=5.42857E-2*CFM+212.85714
GO TO 600
415 IF(CFM-1400.)420,420,425
420 HP=-4.0E-2*CFM+326.
GO TO 600
425 IF(CFM-1770. )430,430,42B
428 KEXHP=18
430 HP = -1 .67567E-1+CFM+504.59459
C *** EQUATION GOOD FROM 1400 TO 1770
GO TO 600
500 IF(ANGLE-22.01)505,505,600
505 IF(CFM-1300.)510,510,515
510 HP=6.0E-2*CFM+270.
GO TO 600
515 IF(CFM-1600.)520,520.525
29930
29940
29950
29960
29970
29980
29990
30000
30010
30020
30030
30040
30050
30060
30070
30080
30090
30100
301 10
30120
30130
30140
30150
30160
30170
30180
30190
30200
30210
30220
30230
30240
30250
30260
30270
30280
30290
30300
30310
30320
30330
30340
30350
30360
30370
30380
30390
30400
30410
30420
-------
520 HP=-4.0E-2*CFM+400.
GO TO 600
525 IF(CFM-1770.)530,530,528
528 KEXHP=22
530 HP=-1.23529E-1*CFM+533.64705
C *** EQUATION GOOD FROM 1600 TO 1770
600 HP=AMAX1(0.0,HP)
RETURN
END
30430
30440
30450
30460
30470
30480
30490
30500
30510
i
o>
CO
SUBROUTINE FHPNB11(CFM,HP,ANGLE,NB,KEXHP) 30520
C **« THIS SUBROUTINE CALCULATES FAN TOTAL HORSPOWER -GIVEN THE BLADE 30530
C *** ANGLE AND FLOW-CFM-FOR 11 BLADES -12000FPM -127RPM -30FT. FAN 30540
K£XHP=0 30550
IF(ANGLE-2.01)5,5,100 30560
5 IF(CFM-800.)10,10,15 30570
10 HP=-5.E-2*CFM+100. 30580
GO TO 600 30590
15 IF(CFM-955.)20,20,18 30600
18 KEXHP=2 30610
20 HP=-1.29032E-1*CFM+163.2258 30620
C *** EQUATION GOOD FROM 800 TO 955 30630
GO TO 600 30640
100 IF(ANGLE-6.01)105,105,200 30650
105 IF(CFM-900.)110,110,115 30660
110 HP=2.E-2*CFM+92. 30670
GO TO 600 30680
115 IF(CFM-1100.)120.120,125 30690
120 HP=-2.5E-2*CFM+132.5 30700
GO TO 600 30710
125 IF(CFM-1280.)130,130,128 30720
128 KEXHP=6 30730
130 HP=-1 .38888E-1*CFM-t-257. 77777 30740
C *** EQUATION GOOD FROM 1100 TO 1280 30750
GO TO 600 30760
200 IF(ANGLE-10.01)205,205,300 30770
205 IF(CFM-900.)210,210,215 30780
210 HP=6.66666E-2*CFM+100. 30790
GO TO 600 30800
215 IF(CFM-1400.)220,220,225 30810
220 HP=-4.4E-2*CFM+199.6 30820
GO TO 600 30830
-------
I
en
10
225 IF(CFM-1565.)230,230,228
228 KEXHP=10
230 HP=-1.69696E-1*CFM+375.57575
C *** EQUATION GOOD FROM 1400 TO 1565
GO TO 600
300 IF(ANGLE-14.01)305,305,400
305 IF(CFM-1100.)310,310,315
310 HP=6.6E-2*CFM+147.4
GO TO 600
315 IF(CFM-1400.)320,320,325
320 HP=-3.33333E-3*CFM+223.66666
GO TO 600
325 IF(CFM-1700.)330,330,335
330 HP=-6.33333E-2*CFM+307.66666
GO TO 600
335 IF(CFM-1870.)340,340,338
338 KEXHP=14
340 HP=-1.47058E-1+CFM+450.
C *** EQUATION GOOD FROM 1700 TO 1870
GO TO 600
400 IF(ANGLE-18.01)405,405t500
405 IF(CFM-1200.)410,410,415
410 HP=9.83333E-2*CFM+185
GO TO 600
415 IF(CFM-1500.)420,420,425
420 HP=5.66666E-2*CFM+235.
GO TO 600
425 IF(CFM-1700.)430,430,435
430 HP=-4.E-2*CFM+380.
GO TO 600
435 IF(CFM-1870.)440,440.438
438 KEXHP=18
440 HP=-1.E-1*CFM+482.
C *** EQUATION GOOD FROM 1700 TO 1870
GO TO 600
500 IF(ANGLE-22.01)505,505,600
505 IF(CFM-1400.)510,510,515
510 HP=7.E-2*CFM+268.
GO TO 600
515 IF(CFM-1870.)520,520,518
518 KEXHP=22
520 HP=2.97B7E-2*CFM+324.29787
C *** EQUATION GOOD FROM 1400 TO 1870
600 HP=AMAX1(0.0,HP)
RETURN
END
30840
30850
30860
30870
30880
30890
30900
30910
30920
30930
30940
30950
30960
30970
30980
30990
31000
31010
31020
31030
31040
31050
31060
31070
31080
31090
31 100
31 1 10
31 120
31 130
31 140
31 150
31 160
31 170
31 180
31 190
31200
31210
31220
31230
31240
31250
31260
31270
31280
31290
-------
--J
o
c ***
c ***
15
20
25
28
30
C ** *
100
105
110
115
120
125
128
130
C ** +
200
205
210
215
220
225
230
235
238
240
C ***
300
305
31P
315
320
325
330
SUBROUTINE FHPNB12(CFM,HP,ANGLE,NB,KEXHP) 31300
THIS SUBROUTINE CALCULATES FAN TOTAL HORSPOWER -GIVEN THE BLADE 31310
ANGLE AND FLOW -CFM-FOR 12 BLADES -12000FPM -136RPM -28FT. FAN 31320
KEXHP=0 31330
IF(ANGLE-2.01)15,15,100 31340
IF(CFM-700.)20,20,25 31350
HP=-2.5E-2*CFM+77.5 31360
GO TO 600 31370
IF(CFM-860.)30,30,28 31380
KEXHP=2 31390
HP=-9.375E-2*CFM+125.625 31400
EQUATION GOOD FROM 700 TO 860 31410
GO TO 600 31420
IF(ANGLE-6.01)105,105,200 31430
IF(CFM-800.)110,110,115 31440
HP = -2 . 17391E-2*CFM-M32.39130 31450
GO TO 600 31460
IF(CFNI-950. ) 120, 120,125 31470
HP=-1.33333E-1*CFM+221.66666 31480
GO TO 600 31490
IF(CFM-1090.)130,130,12B 31500
KEXHP=6 31510
HP=-2.5E-1*CFM+332.5 ' 31520
EQUATION GOOD FROM 950 TO 1090 31530
GO TO 600 31540
IF(ANGLE-10.01)205,205,300 31550
IF(CFM-900.)210,210,215 31560
HP=-9.375E-3*CFM+173.4375 31570
GO TO 600 31580
IF(CFM-1050.)220,220,225 31590
HP=-1.E-1*CFM+255. 31600
GO TO 600 31610
IF(CFM-1200.)230,230,235 31620
HP=-1.8E-1*CFM+339. 31630
GO TO 600 31640
IF(CFM-1340.)240,240,238 31650
KEXHP=10 31660
HP=-3.07142E-1*CFM+491.57142 31670
EQUATION GOOD FROM 1200 TO 1340 31680
GO TO 600 31690
IF(ANGLE-14.01)305,305,400 31700
IF(CFM-1000.)310,310,315 31710
HP=3.4E-2*CFM+206. 31720
GO TO 600 31730
IF(CFM-1200.)320,320,325 31740
HP=-5.E-2*CFM+290. 31750
GO TO 600 31760
IF(CFM-1300.)330,330,335 31770
HP=-1.1E-1*CFM+362. 31780
GO TO 600 31790
-------
335 IF(CFM-1630.)340,340,338 31800
338 KEXHP=14 31810
340 HP=-2.0909E-1*CFM+490.81818 31820
C *** EQUATION GOOD FROM 1300 TO 1630 31830
GO TO 600 31840
400 IF(ANGLE-18.01)405,405,500 31850
405 IF(CFM-1000.)410,410,415 31860
410 HP=4.E-2*CFM+300. 31870
GO TO 600 31880
415 IF(CFM-1270.)420,420,425 31890
420 HP=340. 31900
GO TO 600 31910
425 IF(CFM-1400.)430,430,435 31920
430 HP=-1.E-1*CFM+467. 31930
GO TO 600 31940
435 IF(CFM-1550.)440,440,445 31950
440 HPr-i .93333E-1*CFM-»-597. 66666 31960
GO TO 600 31970
445 IF(CFM-1760.)450,450,44B 31980
448 KEXHP=18 31990
450 HP*-2.66666E-1*CFM+711.33333 32000
C *** EQUATION GOOD FROM 1550 TO 1760 32010
GO TO 600 32020
500 IF(ANGLE-22.01)505,505,600 32030
505 IF(CFM-800.)510.510,515 32040
510 HP=-1.66666E-2*CFM+398.33333 32050
GO TO 600 32060
515 IF(CFM-1100.)520,520,525 32070
520 HP=8.33333E-2*CFM+318.33333 32080
GO TO 600 32090
525 IF(CFM-1460.)530,530.535 32100
530 HP=410 32110
GO TO 600 32120
535 IF(CFM-1770.)540,540,538 32130
538 KEXHP=22 32140
540 HPs-1.12903E-1*CFM+574.83870 32150
C »** EQUATION GOOD FROM 1460 TO 1770 32160
600 HP=AMAX1(0.0,HP) 32170
RETURN 32180
END 32190
-------
I
~vl
no
SUBROUTINE GEOM1
DIMENSION XT(3),B2IL(4,4),B2ST(4,4),XNIL(4,4),XNST(4,4),
1 CROWI(10),CROWS(10)
COMMON NFO,KGO,KRO,KNTR1,NSUM,NPAGE,DAY(2),PI
COMMON KCI,KER.KERR(20),KFIN,KREG,LAIC,LSUP.MM,NP,NR,NT1,NT2,NTP,
1NTR.NTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV, AXPP(20),CP( 2)
2,DEN(2),DEN12(2,2).DENFN,DENLZ(7),DBW,DEO,DFH,DFR,DFS,DFT,DKL,
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT
COMMON DPAD,DPAF,DPAM.DPAW,DPF(10).DPI,DPNZ(2),DPT,DPTA,DPTF,
1DPTOT(2),POUT(2),PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS,DBA RE,UCLN,UTOT,
20(2),QDUT,QTOT,RFI.RFIN.RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8)
3,TWALL,TD,TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,VISLZ(7),
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLO(2)
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC,F,
1FALT,FINEF,FFF,FSUM,OCt(4),ODL(4),OKL(4),OML(4),OMV(4),P.PRAN(2),
2PRALZ(7),R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA,
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20),ZTPPA
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV,ZNFI,PTI,TKT,TKF,
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD.PSD,TTMIN,OD(7),
2CARD7(6),DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2),
3RASPC.ZTPD,ZNTD,COST(7),SSUM(16,30),ISUM(13,30),PRICE(2,21)
COMMON/JUMP/JAKE,TINMX,N002I,DTN2I,N001I,NFPIN,N0020,N0010
COMMON/PIPE/XDIA(20),XLGT(20),NN1,NN2,XTOWR,PLNMH,TTTBH,VX,VN
1,VAVE
DATA CROWI/ 0.68,.75,.83,.89,.92,.95,.97,.98,.99,1.O/,
1 CROWS/ 0.64,.80,.87,.90,.92,.94,.96,.98,.99,1.O/
DATA XT/1.35,1.75,2.SO/,B2ST/.518,.505,.519,.522,.451,.460,.452,
1 .488,.404,.416..482,.449,.310,.356,.440,.421/.B2IL/ .348,.275.
2 .100,.0633,.367,.250,.101,.0678,.418,.299,.229,.198,.290,.357,
3 .374, .286/, XNST/.556,.554,.556,.562,.568,.562,.568,.568,.572,
4 .568,.556,.570,.592,.580,.562,.574/,XNIL/.592,.608,.704,.752,
5 .586,.620,.702,.744,.570,.602,.632,.648,.601,.584,.581,.608/
BUNDLE AND TUBE DESIGN CHANGE
BUNDLE DESIGN CHANGE ONLY
NO CHANGE
C *** OAKE=1
C *** JAKE=2
C *** JAKE=3
C
40 DLTO=DLOV*12.0
GO T0(45,236,2000),JAKE
45 CONTINUE
NP=AMIN1(20.0,ZNTP)+0.01
NR=AMIN1(20.,ZNTR)+0.01
50 DTO=1.0
70 DTT=0.083
80 DTIM=DTO-2.0*DTT
DTI=DTIM
DFR=DTO
C +** FINNED TUBE DIMENSIONS
110 ZNF=ZNFI
IF (ZNFI-.0001) 112,112,114
32200
32210
32220
32230
32240
32250
32260
32270
32280
32290
32300
32310
32320
32330
32340
32350
32360
32370
32380
32390
32400
32410
32420
32430
32440
32450
32460
32470
32480
32490
32500
32510
32520
32530
32540
32550
32560
32570
32580
32590
32600
32610
32620
32630
32640
32650
32660
32670
32680
32690
-------
I
-«J
CO
112 ZNF=10.0 32700
114 CONTINUE 32710
116 DFH=0.625 32720
120 DFT=0.018 32730
122 DEQ=DFR+ZNF*DFT*DFH*2.0 32740
DTF=DFR+2.0*DFH 327^0
C *** CHECK IF FIN THICK. AND FINS/INCH ARE REASONABLE 32760
IF (DFT*ZNF-1.0) 140,130,130 32770
130 ZNFI=0.0 32780
GO TO 112 32790
140 RAOR=1.0+2.0*ZNF*DFH*(1.0+(DFH+DFT)/DFR) 32800
150 AOF=RAOR*PI*DFR/12.0 32810
160 DFS=1.0/ZNF-DFT 32820
AR=PI*DFR/12.0*(1.0-ZNF*DFT) 32830
RARAF=AR/(AOF-AR) 32840
CFR=DFH/12.0*SQRT(24.0/(TKF*DFT)) 32850
CFR=CFR*(1.0+0.5*DFT/DFH)*(1.0+0.35*ALOG(1.0+2.0*DFH/DFR)) 32860
C *** TUBE PITCH, TRANSVERSE AND LATERAL TO FLOW 32870
224 PL=.5*PT/.5774 32B80
SMAX=15000. 32890
OHGT=ZNTR*PL+DTO 32900
DLTS=DHGT*SQRT(2.5*.75*PDI/SMAX) 32910
DTSMN=.75 32920
DLTS=AMAX1(DLTS,DTSMN)*2.0 32930
RPT=PT/DFR 32940
c »** CALC. TUBE RESISTANCE 32950
RAOI=AOF/(PI*DTIM/12.0) 32960
RFI=AOF/(2.0*PI*TKF)*ALOG(DFR/DTO) 32970
RTW=AOF/(2.0*PI*TKT)+ALOG(DTO/DTIM)+RFI 32980
RFTOT=.0005*RAOI 32990
RTOT=RFTOT+RTW 33000
C *** FIND TIP-TO-TIP BUNDLE HEIGHT 33010
TTTBH=(PL*{ZNTR-1.)+DTF)/12. 33020
C *** SET UP SOME BUNDLE COST INFORMATION NEEDED BY ACCOST 33030
N002I=0 33040
DTN2I=0. 33050
N001I=ZNOZ(1) 33060
NFPIN=ZNF 33070
IF((-1 ) + *NTP)710,710,720 33080
710 N0010=0 33090
N0020=ZNOZ(2) 33100
GO TO 730 33110
720 NOOtO=ZNOZ(2) 33120
N0020=0 33130
730 CONTINUE 33140
234 TLA=ATAN(.5*PT/PL)*57.3 33150
C *** CALC. EFFECTIVE BUNDLE WIDTH. ALLOW 2IN. FOR STRUCT. EACH SIDE. 33160
236 CONTINUE 331?o
240 Z=ZNTT/ZNTR 33180
NT1=Z 33,90
-------
IF (ABS(Z-FLOAT(NT1))-0.0001) 244,244,242 33200
242 NT1=NT1-M
244 Z=NT1
DBW=PT*Z
C *** STAGGERED ARRANGEMENT
250 CLER=DBW-((0.5+FLOAT(NT1-1))* PT+DTF)-.03125
C *** TUBE COUNT EQUATIONS - PER BUNDLE
309 IF (CLER+.0001) 314,320,320
314 NT2=NT1-1
GO TO 326
C *** IN-LINE ARRANGEMENT
320 NT2=NT1
326 NTT=0 33320
DO 350 1=1,NR 33330
IF ((-1)**I) 330,340,340
330 NTT=NTT+NT1
GO TO 350
340 NTT=NTT+NT2 33370
350 CONTINUE
354 NT2=NTT
_ 356 NTT=ZNTT+0.01
i 410 ZTPPA=ZNTT/ZNTP
^ 436 NTTP=NTT/NTP
DO 450 1=1,NP
450 ZTPP(I)=NTTP
460 NTOV=NTT-NTP*NTTP
464 IF (NTOV) 500,500,470
470 DO 480 1 = 1 ,NP
ZTPP(I)=ZTPP(I)+1.0
NTOV=NTOV-1
IF (NTOV) 500,500,480
480 CONTINUE 33510
GO TO 464 33520
500 CONTINUE 33530
C *** TUBE SPACER WIDTH ASSUMMED 2 IN.-USED EVERY 6 FT. 33540
650 DLSP=2*IFIX(DLTO/71.9-1.0) 33550
DLTE=DLTO-DLSP-DLTS 33560
C *** CALC. APPROAC AREA/BUND. (APPR), PLOT AREA/BAY (APLOT), AND MIN. 33570
C *** CROSSFLOW AREA (AMIN) 33580
APPR=DLTE*DBW/144.0 33590
AMIN=APPR*(PT-DEQ)/PT 33600
RAPMX=AMIN/APPR 33610
C *** SURFACE AREA CALCULATION 33620
ASBUN=ZNTT*DLTE*AOF/12.0 33630
ASTOT = ASBUN * ZBUS * ZBUP * ZBYP 33640
C *** CALC. TUBE SIDE CROSSFLOW AREAS 33650
AX=PI*(DTI/12.0)**2*0.25 33660
DO 800 1*1,NP 33670
AXPP(I)=AX*ZTPP(I) 33680
800 CONTINUE 33690
-------
CJ1
AXAV=AX*ZTPPA
C *** SET UP CONSTANTS FOR AIR SIDE HT AND DP RELATIONS
1040 IF(JAKE.EQ.2)GO TO 1500
1072 PLP=PL/COS(TLA*.01745)
C = 1 .0
1080 CFP(1)=6.03/RPT**.8715*RAOR**0.43 *(PT/PLP)**.515 *C
CFP(2)=-0.245
DKL=4.0*PT*PL*(
CONTINUE
BRIGGS AND YOUNG
1086
1206
C ** *
1260
.0-DEQ /PT)/(RAOR*PI*DFR)
.0-0.3/ZNTR)*1..05
CFH(1)=0.1378*12
CFH(2)=0.718
1302 CFH(3)= (1
1500 CONTINUE
CALL ERORF (KER,KERR.KGO.MM)
2000 RETURN
END
GEOMETRY PARAMETERS
0/DFR*(DFS/DFH)**0.296
33700
33710
33720
33730
33740
33750
33760
33770
33780
33790
33800
33810
33820
33830
33840
33850
33860
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
*» *
** *
** *
*+ *
* + *
** *
** *
** *
** •*
** *
** *
«t» *
** *
** *
** *
** *
** *
** *
** *
** *
** *
** *
***
n
w
A
PC
SI
A!
PC
TC
A!
p;
If
Tl
Tl
1
2
3
4
5
6
7
8
SUBROUTINE GEOM2(CAPIP)
THIS ROUTINE DESIGNS THE COOLING TOWER PIPING AND CONVERTS ALL
VALVES AND FITTINGS INTO EQUIVALENT LENGTHS. THE DESIGN FOLLOWS
A LINE FROM A SINGLE PUMP TO THE LAST TOWER BAY AND BACK TO THE
POWER PLANT. THE LOSSES FROM CONTRACTIONS AND EXPANSIONS IN THE
SUPPLY AND RETURN LINES ARE IGNORED. THE COOLING TOWERS ARE
ASSUMED TO LAY PERPENDICULAR TO THE PIPING RUNNING TO AND FROM THE
POWER PLANT WITH THE PIPING ENTERING AT THE MIDDLE OF THE COOLING
TOWERS. THE BAYS ARE ARRANGED IN A BACK-TO-BACK SCHEME.
ASSUME ALL PIPES ARE STANDARD WALL AND THAT INLET AND OUTLET
PIPE SIZES ARE THE SAME. BREAK UP SUPPLY AND RETURN LINES
INTO 4 DIFFERENT SIZES.
THE OUTPUT ARRAYS ARE XDIA AND XLGT, BOTH IN INCHES
THESE ARRAYS ACCOUNT FOR THE FOLLOWING LOSSES:
POWER PLANT TO COOLING TOWERS
COOLING TOWER TO SUPPLY LINE
TURN INTO SUPPLY LINE AND FIRST LENGTH OF SUPPLY
SECOND LENGTH OF SUPPLY LINE
THIRD LENGTH OF SUPPLY LINE
FOURTH LENGTH OF SUPPLY LINE
INLET FEEDER LINE LOSS
TURN INTO INLET HEADER AND HEADER LOSS
LINE
33870
33880
33890
33900
33910
33920
33930
33940
33950
33960
33970
33980
33990
34000
34010
34020
34030
34040
34050
34060
34070
34030
34030
34100
-------
C *** 9 = TURN OUT OF INLET HEADER TO BUNDLE INLET NOZZLE 34110
C *** 10= 0. 34120
C *** 11= TURN FROM BUNDLE OUTLET NOZZLE INTO OUTLET HEADER 34130
C *** 12= LOSS IN OUTLET HEADER AND TURN OUT OF HEADER 34140
C *** 13= OUTLET FEEDER LINE LOSS 34150
C *** 14= FOURTH LENGTH OF RETURN LINE 34160
C *** 15= THIRD LENGTH OF RETURN LINE 34170
C *** 16= SECOND LENGTH OF RETURN LINE 34180
C *** 17= FIRST LENGTH OF RETURN LINE AND TURN OUT OF RETURN LINE 34190
C *** 18= RETURN LINE TO BOUNDARY OF COOLING TOWER 34200
C *** 19= COOLING TOWER TO POWER PLANT 34210
C »** 20= 0. 34220
COMMON/BCK/XMCST(20),PIPDM(20),XSHOP(20),FIELD(20),EXJOT(20) 34230
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2),PI 34240
COMMON KCI,KER,KERR(20),KFIN.KREG,LA 1C,LSUP,MM,NP,NR,NT1,NT2,NTP, 34250
1NTR.NTT,ABARE,AFAN,AMIN,APLOT,APPR,AS8UN,ASTOT,AXAV,AXPP(20),CP(2) 34260
2,DEN(2),DEN12(2,2),DENFN,DENLZ(7),DBW.DEO,DFH,DFR,DFS,DFT,DKL, 34270
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI , DTIM,DTF,DTO,DTT,PL,PT 34280
COMMON DPAD,DPAF,DPAM,DPAW,OPF(10),DPI,DPNZ(2),DPT.DPTA,DPTF, 34290
1DPTOT(2),POUT(2) ,PTUB,RV2,GAMAX,GT,HPFNC,HA IR,HTS,UBARE,UCLN,UTOT, 34300
20(2),QDUT,QTOT,RFI,RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 34310
3,TWALL.TD,TW,TMTD,TK(2) , VAPP,VNZ(2) , VT , DF AN , T LT E , AOF , V I SLZ ( 7 ) , 34320
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLQ(2) 34330
COMMON ANG(3),CFH(3).CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV.CKSTC,F, 34340
1FALT,FINEF, FFF , FSUM ,OCL ( 4 ) ,ODL(4),OKL(4).OM|_(4) , OMV ( 4 ) , P,PRAN(2) , 34350
2PRALZ(7).R.RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2.2),RFNPL,RPT,TLA, 34360
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20),ZTPPA 34370
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV.ZNFI,PTI,TKT,TKF, 34380
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,QD(7), 34390
2CARD7(6),DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT.ZNOZ(2), 34400
3RASPC,ZTPD,ZNTD,COST(7),SSUM(16,30),ISUM(13,30).PR ICE(2,21) 34410
COMMON/PIPE/XDIA(20),XLGT(20),NN1,NN2,XTOWR,PLNMH,TTTBH,VX,VN 34420
1.VAVE 34430
COMMON/JAN7/WBMAX,PBPMN,TBPMN,CPEFF,WTEFF,PBPHT,EBPOM,PPOM,CWRTI, 34440
1SCPMP,CCPMP,FDMAX,MXFBL,SPRNZ,SPRHT,CWTLV,DPPCT,PDMAX,CONCT 34450
COMMON/CONTL/CSTOR,INML,D(13) 34460
DIMENSION GPMD(3),PUMPD(3),VALVE(6),DIARR(20),VLARR(20) 34470
C *** ARRAY OF COSTS OF BUTTERFLY VALVES (1976 PRICES) 34480
DATA VLARR/ 700.00, 1500.0, 3000.0, 4500.0, 6700.0, 34490
1 8000.0, 10200., 12200., 15800., 19300., 34500
2 25800., 27300., 30000., 32800., 38000., 34510
3 41500., 47900., 54100., 58000., 85000./ 34520
C *** ARRAY OF PIPE SIZES (INCHES) 34530
DATA DIARR/4.026,8.071,12.09,17.25,23.25,29.25,35.25,42.,48.,54., 34540
1 60.. 66., 72., 78., 84., 90., 96., 108., 114., 144./ 34550
C *** COST OF THE 3 CIRC. PUMPS WITH PUMP DRIVES WITHOUT WATER RECOVERY 34560
C *** TURBINES (1976 PRICES) 34570
DATA PUMPD/265610.,355220.,520810./ 34580
C •** CAPACITIES OF THE 3 CIRCULATING PUMPS USED IN GPM 34590
DATA GPMO/82700.,110300.,165400./ 34600
-------
C
c ***
c ***
c »**
c »**
c ***
c
c ***
c ***
c ***
100
** *
** *
c
c ***
c
PIPES BELOW 48 INCH DIAMETER HAVE PROPORTIONATELY MORE MACHINING
AND PIPES ABOVE 48 HAVE THICKER WALLS. AS A RESULT ALL PIPES WORK
OUT TO A COST OF 2. DOLLARS/FOOT/DIAMETER INCH
USE SHOP JOINT COST OF 4 DOLLARS/DIAMETER INCH
USE FIELD JOINT LABOR AS 24 DOLLARS/HOUR
DATA BIGPI ,SMPIP.SJ,FJ/2.,2. ,4. ,24./
XDIA(10)=0.
XDIA(20)=0.
CALCULATE THE VARIOUS PIPE SIZES USED IN THE PIPING DESIGN
D(6)=D(5)/1 .414
D(7)=SQRT(W(1)/ZBYP*2./DEN12(1 , 1 )/VN/19.635)
D(8)=D(5)* .6124
D( 10)=D(7)/1 .414
ASSUME 10000 GPM FILL LINES
D(1 1 )=SQRT( 1 0000. /VX/2. 448)
D(12)=D(5)*.433
D( 13)=D(5)/2.828
D( 1 )=D(10)*SQRT( VN/VAVE)
D(2)=D(1 )/1 .414
D(3)=DNZ(1 )
D(4)=DNZ(2)
FIND PIPE SIZES
DO 100 1=1,13
IF(I.EQ.3.0R.I.EQ.4)GO TO 100
CALL NOZID(0. ,1 . £08, D( I ) , IDUM, DUM, 0 )
CONTINUE
SET CODE FOR NECESSARY ARRANGEMENT
FIND STANDARD LENGTH FOR SUPPLY AND RETURN LINES
STLGT=ZBUP*(DBW+4. )*(ZBYP-4.
FIND LENGTHS AND DIAMETERS TO USE FOR PRESSURE DROP CALCULATIONS
XDIA( 1 )=D(5)
XDIA(2)=D(6)
XLGT(2)=0.
XLGT(3)=STLGT
XDIA(4)=D(7)
XLGT(4)=STLGT
XDIA(5)=D(B)
XLGT(5)=STLGT
XDIA(6)=D(9)
XLGT(6)=STLGT
XDIA(7)=D( 1 )
XLGT(7) = 195.*XDIA(7)-M2.*XTOWR
XDIA(8)=D(2)
XLGT(8)=90.*XDIA(8)+(DBW+4.)*(ZBUP/2.-.5/ZNOZ(1 ) )
XDIA(9)=D(3)
XLGT(9)=135.*XDIA(9)
34610
34620
34630
34640
34650
34660
34670
34680
34690
34700
34710
34720
34730
34740
34750
34760
34770
34780
34790
34800
34810
34820
34830
34840
34850
34860
34870
34880
34890
34900
34910
34920
34930
34940
34950
34960
34970
34980
34990
35000
35010
35020
35030
35040
35050
35060
35070
35030
35090
35100
-------
00
XDIA(11)=D(4)
XLGT(11) = 120.*XDIA(11 )
XDIA(12)=D(2)
X LGT(12)=60.* XDIA(12) + (DBW+4.)*(ZBUP/2.-.5/ZNOZ( 2) )
XDIA(13)=D(1)
XLGT(13) = 180.*XDIA(13)-M2.*XTOWR
XLGT(14)=STLGT
XDIA(14)=D(13)
XLGT(15)=STLGT
XDIA(15)=D(12)
XLGT(16)=STLGT
XDIA(16)=D(10)
XLGT(17)=STLGT
XDIA(17)=D(9)
XLGT(18)=0.
XDIA(18)=D(6)
GO TO (130,140,150,160),INML
130 XLGT(1)=DLTO+120.*XDIA(1)+12.*DPPCT
XDIA(3)=XDIA(2)
XLGT(3)=XLGT(3)+90.*XDIA(3)
XLGT(17)=XLGT(17)+60.*XDIA{17)
GO TO 300
140 XDIA(1)=D(6)
XLGT(1) = DI_TO+120.*XDIA(1)+12.*DPPCT
XDIA(3)=XDIA(2)
XLGT(3)=XLGT(3)+20.*XDIA(3)
XOIA(1B)=D(9)
GO TO 300
150 XLGT<1)=120.*XDIA(1)-M2 . *DPPCT
XDIA(2)=D(9)
XLGT(2)=170.*XDIA(2)
XDIA(3)=XDIA(2)
XDIA(17)=D(6)
XLGT(18)=140.*XDIA(18)
GO TO 300
160 XDIA(1)=D(6)
XLGT( 1) = 120.*XDIA(1 )-H2.*OPPCT
XDIA(2)=D(9)
XLGT(2)=80.*XDIA(2)+2.*OLTO
XDIA(3)=XDIA(2)
XLGT(3)=XLGT(3)+20.*XDIA(3)
XDIA(17)=D(6)
XLGT(17)=XLGT(17)+20.*XDIA(17)
300 CONTINUE
XDIA(19)=XOIA(1)
XLGT(19)=XLGT(1)
IF(INML.LT.3)GO TO 305
XDIA(4)=D(10)
XDIA(5)=D(12)
XDIA(6)=D(13)
351 10
35120
35130
35140
35150
35160
35170
35180
35190
35200
35210
35220
35230
35240
35250
35260
35270
35280
35290
35300
35310
35320
35330
35340
35350
35360
35370
35380
35390
35400
35410
35420
35430
35440
35450
35460
35470
35480
35490
35500
35510
35520
35530
35540
35550
35560
35570
35580
35590
35600
-------
XLGT(13)=XLGT(13)+20.*XDIA(13)
XDIA(14)=D(9)
XDIA(15)=D(8)
XDIA(16)=D(7)
XLGT(19)=XLGT(19)+DLTO
GO TO 306
305 CONTINUE
XLGT(7) = X LOT(7) + 72.+20.*XDIA(7)
XLGT(18)=100.*XDIA(18)
CONTINUE
FIND MATERIAL COSTS FOR ALL PIPELINES
INLET FEEDER LINE
OUTLET FEEDER LINE
INLET HEADER
OUTLET HEADER
SUPPLY LINE NUMBER 1
SUPPLY LINE NUMBER 2
SUPPLY LINE NUMBER 3
SUPPLY LINE NUMBER 4
SUPPLY LINE NUMBER 5
10= SUPPLY LINE NUMBER 6
11= RETURN LINE NUMBER 1
12= RETURN LINE NUMBER 2
13= RETURN LINE NUMBER 3
14= RETURN LINE NUMBER 4
15= RETURN LINE NUMBER 5
16= RETURN LINE NUMBER 6
17= FILL LINES
18= BYPASS LINES
PIPRA=BIGPI/SMPIP
XMCST( 1 )=XTOWR-t-.4*D( 1 )
PIPDM(1)=D(1)
PIPDM(2)=D(1)
XMCST(3)=D(2)*SMPIP*(DBW+4.)/12.*(ZBUP-1 ./ZNOZ(1))
PIPDM(3)=D(2)
PIPDM(4)=D(2)
XMCST(4)=XMCST(3)*(ZBUP-1./ZNOZ(2))/(ZBUP-1./ZN02(1))
XMCST(5)=DPPCT
PIPDM(5)=XDIA(1)
STNRD=STLGT*2./12.
XMCST(6)=STNRD
PIPDM(6)=XDIA(3)
XLZ=STNRD
IF( INML.GT.2)XLZ=2.*STNRD
DO 600 1=7,9
XMCST(I)=XDIA(I-3)*XLZ*SMPIP
PIPDM(I)=XDIA(I-3)
600 CONTINUE
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
306
** *
** *
** *
** *
** *
* * *
*+ *
** *
** *
** *
+ **
** *
** *
***
** *
«* *
** *
** *
***
Cl
F
1
2
3
4
5
6
7
8
9
1
1
1
1
1
1
1
1
1
35610
35620
35630
35640
35650
35660
35670
35680
35690
35700
35710
35720
35730
35740
35750
35760
35770
35780
35790
35800
35810
35820
35830
35840
35850
35860
35870
35880
35890
35900
35910
35920
35930
35940
35950
35960
35970
35980
35990
36000
36010
36020
36030
36040
36050
36060
36070
360'iO
36090
36100
-------
XMCST(10)=0. 36110
PIPDM(10)=D(6) 36120
XMCST(11)=DPPCT+DLTO/12. 36130
PIPDM(11)=XDIA(1) 36140
XLZ=STNRD 36150
1F(INML.LT.3)XLZ=2.*STNRD 36160
XMCSTf12)=XLZ 36170
PIPOM(12)=XDIA(17) 36180
DO 700 1=13,15 36190
XMCST(I)=SMPIP*XLZ*XDIA(29-I) 36200
PIPDM(I)=XDIA(29-I) 36210
700 CONTINUE 36220
XMCST(16)=0. 36230
PIPDMf16)=D(6) 36240
XMCST(17)=2.*DPPCT*SMPIP*D(11) 36250
PIPDM(17)=0(11) 36260
PIPD.V!( 18) = PIPDM(5) 36270
XMCST( 18)=4.*PIPDIV1(18)/12.*SIVIPIP*PIPDM(18) 36280
XMCST(2)=XMCST(1) 36290
GO 10(550.575,625,650),INML 36300
_, 550 XMCST( 1 )=XMCST( 1 )+6.+.4*0(1 ) 36310
i XMCST(5)=XMCST(5)+DLTO/12. 36320
g XMCST(12)=XMCST(12)+4.*.4*0(9) 36330
XMCSK16)=4.*.4*D(6)*SMPIP*D(6) 36340
GO TO 675 36350
575 XMCST(1)=XMCST(1)+6.+.4*0(1) 36360
XMCST(5)=2.*(XMCST(5)+DLTO/12.)+2.*.4*0(6) 36370
XMCST(11)=2.*XMCST(11 ) 36380
XMCST(12)=XMCST(12)+.4*10.*D(9) 36390
XWCST(17)=2.*XMCST(17) 36400
XMCST(18)=2.*XMCST(1B) 36410
GO TO 675 36420
625 XMCST(2)=XMCST(2)+.4*D(1) 36430
XMCST(6)=2.*XMCST(6)+8.*.4*D(9) 36440
XMCST(10)=D(6)+SMPIP*(2.*DLTO/12.+.4*D(6)) 36450
XMCST(12)=XMCST(12)+4.*.4*0(6) • 36460
GO TO 675 36470
650 XMCST(2)=XMCST(2)+.4*D(1) 36480
XMCST(5)=2.*XMCST(5) 36490
XMCST(6)=2.*XMCST(6)+10.*.4*D(9)+4.*DLTO/12. 36500
XMCST(11)=2.*XMCST(11)+2.*.4*D(6) 36510
XMCST(17)=2.*XMCST(17) 36520
XMCST(18)=2.*XMCST(18) 36530
675 CONTINUE 36540
XMCST(1)=XMCST(1 )*D(1 )*SMPIP 36550
XMCST(2)=XMCST(2)*D(1)*SMPIP 36560
XMCST(5)=XMCST(5)*SMPIP*XDIA(1) 36570
XMCST(6)=XMCST(6)*SMPIP*XDIA(3) 36580
XMCST(11)«XMCST(11 )*XOlA(1)*SMPIP 36590
XMCST(12)=XMCST(12)*SMPIP*XDIA(17) 36600
-------
I
c»
WPING=0.0 36610
00 710 1=1,18 36620
C *** 10 PCT. ADDED TO MATERIAL FOR WELD NECKS,ETC. 36630
XMCSTII)=1.1*XMCST(I) 36640
IF(PIPDM(I).GT.48.01)GO TO 708 36650
C *** ASSUME PIPE THICKNESS OF .375 INCHES AND FIND VOLUME OF PIPE METAL 36660
VPING=XMCST(I)+37.699/PIPDM(I)/SMPIP*(.375**2+.375*PIPDM(I)) 36670
GO TO 709 36680
C *** ASSUME PIPE THICKNESS OF .5 INCH AND FIND VOLUME OF PIPE METAL 36690
708 VPING=XMCST(I)*37.699/PIPDM(I)/SMPIP*(.5**2+.5*PIPDM(I)) 36700
XMCST(I)=XMCST(I)+PIPRA 36710
709 IF(I.LE.4)VPING=ZBYP*VPING 36720
WPING=WPING+VPING 36730
710 CONTINUE 36740
C *** TO CALCULATE TOTAL PIPING WEIGHT USE .2833 LB/IN3 36750
WPING=WPING*.2833 36760
C *** FIND PIPING SHIPPING COST BY ASSUMING 5.00 $/CWT 36770
SHIPCO=WPING*.05 36780
C 36790
C *** FIND SHOP LABOR FOR ALL PIPING 36800
C 36810
XSHOP(1)=SJ*D(1) 36820
XSHOP(2)=XSHOP(1) 36830
TEMY=D(1)+6.*D(2) 36840
XSHOP(3)=SJ*(TEMY + 2.*D(3)*ZNOZ(1 )*ZBUP) 36850
XSHOP(4)=SJ*(TEMY+2.*D(4)*ZNOZ(2)*ZBUP) 36860
TEMY=ZBYP/2.*D(1) 36870
XSHOP(5)=D(5)*SJ 36880
XSHOP(6)=SJ*(TEMY+14.*D(9)) 36890
XSHOP(7)=2.*D(7) 36900
XSHOP(8)»=SJ*TEVY 36910
XSHQP(9)=XSHOP(8) 36920
XSHOP(10>=0. 36930
XSHOP(11)=XSHOP(5) 36940
XSHOP(13)=4.*D(10) 36950
XSHOP(14)=XSHOP(8) 36960
XSHOP(15)=XSHOP(14) 36970
XSHOP(16)=0. 36980
XSHOP(17)=0. 36990
XSHOP(18)=0. 37000
GO T0(725,750,775,800),INML 37010
725 XSHOP(1)=2.*XSHOP(1) 37020
XSHOP(6)=SJ*(TEMY+4.*D(6)) 37030
X5HOP(12)=11.*D(9) 37040
XSHOP<16)=SJ*9.*D(6) 37050
GO TO 840 37060
750 XSHOP(1)=2.*XSHOP(1) 37070
XSHOP(5)=0. 37080
XSHOP(6)=SJ*(TEMY+2.*D(6)) 37090
XSHOP(11)=D(6)*SJ«2. 37100
-------
775
eoo
840
XSHOP(12)
GO TO 840
XSHOP<2)=
XSHOP(7)=
XSHOP(10)
XSHOP(12)
XSHOP(13)
GO TO 840
XSHOP(2)=
XSHOP(5)=
XSHOP(7)=
XSHOP(11 )
XSHOP(12)
XSHOP(13)
CONTINUE
XSHOP(7)=
XSHOP(12)
XSHOP(13)
c
c ***
c
:16.*D(9)
2.*XSHOP(2)
4.*D(10)
=SJ*7.*D(6)
=7.*D(6)
=2,*D(7)
2.*XSHOP(2)
D(6)*SJ
4.*D(10)
= 0.
=2.*D(6)
=2.*D(7)
SJ*(XSHOP(7)+TEMY)
=Sd*(XSHOP(12)+TEMY)
=SO*(XSHOP(13)+TEMY)
l
00
ro
FIND FIELD LABOR FOR ALL PIPING
FIELD(1)=FJ*(1.4+1.6*D(1))
FIELD(2) = FIELD(1 )
IF( lrm-3)860,870,870
860 FIELDd )=2.*FIELDd)
870 CONTINUE
IF(XTOWR-SCPMP)890,890,880
880 XTRA=AINT(XTOWR/SCPMP-.01)*FJ*(1.4+1.6*0(1))
F1ELD(1)=FIELD(1)+XTRA
FIELD(2)=FIELD(2)+XTRA
890 FIELD(3)=ZBUP*ZNOZ(1)*Fd*(1.4+1.6*0(3))
FIELD(4)=ZBUP*ZNOZ(2)*FJ*(1.4+1.6*0(4))
DO 900 1=5,18
EXdOT(I)=0.
FIELD(I)=0.
900 CONTINUE
FIELD(18)=FJ*4.*(1.4+1.6*PIPDM(18))
GO T01910,920,930,940),INML
910 FIELD(6)=2.*FJ*(1.4+1.6*0(6))
FIELD)11)=FJ*(1.4+1.6*0(5))
FIELD(12)=FJ*(1.4+1.6*0(9))*5.
FIELD(16)=FIELD(6)
GO TO 950
920 FIELD(5)=FJ*(1.4+1.6*0(6))*2.
FIELD(11)=FIELD(5)
FIELDd2)=FJ*(1.4+1,6*D(9))*6.
FIELD(18)=2.*FIELD(18)
GO TO 950
930 FIELD(6)=FJ*(1.4+1.6*0(9))*6.
FIELD(10)=FJ*(1.4+1.6*0(6))
37 110
37120
37130
37140
37150
37160
37170
37180
37190
37200
37210
37220
37230
37240
37250
37260
37270
37280
37290
37300
37310
37320
37330
37340
37350
37360
37370
37380
37390
37400
37410
37420
37430
37440
37450
37460
37470
37480
37490
37500
37510
37520
37530
37540
37550
37560
37570
37580
37590
37600
-------
CO
CO
940
950
C
c ***
c ***
C
960
970
975
976
978
980
985
990
1000
C ***
C
c ***
FIELD(12)=3.*FIELD(10)
GO TO 950
FIELD(6)=FJ*(1.4+1.6*0(9))*6.
FIELD(11)=FJ*(1.4+1.6*D(6))*2.
FIELD(18)=2.*FIELD(18)
CONTINUE
ALL LONG PIPES MUST HAVE ADDITIONAL FIELD JOINTS, SHOP JOINTS,
AND EXPANSION JOINTS DUE TO THEIR LENGTH
DO 1000 1=5,15
IF(I-5)960,960,970
LENG=DPPCT
IF(INML.LT.3)LENG= LENG+D LTD/1 2.
PIECE=1.
IF((-1)**INML.GT.O)PIECE=2.
GO TO 990
IF(I-11)975,980,985
IF(I.NE.10)GO TO 976
IF(INML.NE.3)GO TO 1000
LENG=2.*DLTO/12.
PIECE=1.
GO TO 990
IF(I.NE.6)GO TO 978
IF(INML.NE.4)GO TO 978
LENG=DLTO/12.
PIECE=4.
CALL PIPDIV(PIPDM(I),LENG,PIECE,SCPMP,FJ,SJ,I)
LENG=STLGT/12.
PIECE=2.
IF(INML.GT.2)PIECE=4.
GO TO 990
LENG=DPPCT+DLTO/12.
PIECE=1.
IF( (-1 )**INML.GT.0)PIECE=2.
GO TO 990
LENG=STLGT/12.
PIECE=2.
IF(INML.LT.3)PIECE*4.
CALL PIPDIV(PIPDM(I),LENG,PIECE,SCPMP,FJ,SJ , I )
CONTINUE
LENG=DPPCT
PIECE=2.
IF<(-1)**INML.GT.0)PIECE=4.
CALL PIPDIV(PIPDM(17),LENG,PIECE,SCPMP,FJ,SJ,17)
XNL=PIECE/2.
ASSUME 1 FILL PUMP PER LINE AT 20000 DOLLARS FOR PUMP AND DRIVE
PUMPF=20000.*XNL
CALCULATE COST OF CONDENSATE PUMPS
37610
37620
37630
37640
37650
37660
37670
37680
37690
37700
37710
37720
37730
37740
37750
37760
37770
37780
37790
37800
37810
37820
37830
37840
37850
37860
37870
37880
37890
37900
37910
37920
37930
37940
37950
37960
37970
37980
37990
38000
38010
38020
38030
38040
38050
38060
38070
38030
38090
38100
-------
I
CO
C 38110
GPMSL=W(1)/XNL/DEN12(1,1)/8.021 38120
PUMPC=1.E11 38130
DO 1500 1=1,3 38140
IPUMP=IFIX(GPMSL/GPMD(I))+1 38150
PUMP I=FLOAT(IPUMP)*PUMPD(I) 38160
IF(PUMPI-PUMPC)1300,1500,1500 38170
1300 PUMPC=PUMPI seiso
NPUMP=IRUMP 38190
PPGPM=GPMD(I) 38200
1500 CONTINUE 38210
PUMPOPUMPC*XNL 38220
IXNL=XNL 38230
NPUMP=NPUMP*IXNL 38240
C *** FIND COST OF BUTTERFLY VALVES 38250
C *** VALVE(OI) = EACH BAY HAS 2 CONTROL VALVES 38260
C *** VALVE(02) = EACH SUPPLY LINE HAS 2 CONDENSATE PUMP ISOLATION VALVE 38270
C *** VALVE(03) = EACH RETURN LINE HAS 2 RECOVERY TURB. ISOLATION VALVES 38280
C *** VALVE104) = EACH PAIR OF LINES HAS 3 BYPASS VALVES 38290
C *** VALVEI05) = EACH SUPPLY FILL LINE HAS 2 FILL PUMP ISOLATION VALVES 38300
C *** VALVE(06) = EACH RETURN FILL LINE HAS 2 FILL DRAIN VALVES 38310
VALVE(1)=2.*Z8YP*GRS(DIARR,1,VLARR,1,D(1),20.JDUM) 38320
VLVCT=GRS(DIARR,1,VLARR,1,PIPDM(5),20,JDUM)*XNL 38330
VALVE!2)=2.*VLVCT 38340
VALVE(3)=0. 38350
IF(CWRTI.LE..05)GO TO 1600 38360
VALVE(3)=VALVE(2) 38370
1600 VALVE(4)=3.*VLVCT 38380
VLVCT=GRS(DIARR,1.VLARR,1,PIPDM(17),20,JDUM)*XNL 38390
VALVE(5)=2.*VLVCT 38400
VALVE(6)=VALVE(5) 38410
C *** CALCULATE STORAGE TANK VOLUME BASED ON 1.5 CAPACITY FACTOR 38420
C *** TANKS MUST HOLD THE TUBE AND FEEDER LINE VOLUME PLUS EXTRA 1.5 TO 38430
C *** ACCOUNT FOR HEADERS AND OTHER ABOVE GROUND PIPING. ASSUME 38440
C *** RETURN AND SUPPLY LINES NEED NOT BE COMPLETELY DRAINED. 38450
VFILL=DLTO*ZBYP*ZBUP*FLOAT(NTT)*.7854*DTIM**2 38460
VFILL=VFILL+.7854*0(1)**2*XTOWR*ZBYP*12.*2. 38470
VFILL=1.5*VFILL/231. 38480
C *** ASSUME TANKS ARE 40 FEET LONG AND 3/8 INCHES THICK. COST IS 38490
C *** 1.10 $/LB INSTALLED WITH AN EXTRA 2.25 S/GAL FOR THE PIT. 38500
C *** ASSUME MAXIMUM TANK SIZE OF 150000 GALLONS. 38510
NTANK=VFILL/150000.-H 38520
XTANK=NTANK 38530
VFILL=VFILL/XTANK 38540
C *** SEE NOTEBOOK FOR DERIVATION OF FORMULAS 38550
DTANKA=ACOS(1.-VFILL/250673.96) 38560
DTANK=80."COS(DTANKA/3.+4.18879)+40. 38570
WTANK=16.02*(240.2*DTANK+7.4-DTANK**2) 38580
TANKC=XTANK*(1.1*WTANK+2.25*VFILL) 38590
C *** ADD IN SHIPMENT COST OF TANKS AT 5.00 S/CWT 38600
-------
00
en
SHIPCO=SHIPCO+.05*WTANK*XTANK 38610
C *** ASSUME CONTROLS ARE 9 PCT. OF BUNDLE COST 38620
CONTR=.09*CSTOR 38630
C *** ASSUME 13350 DOLLARS FOR NITROGEN BLANKETING 38640
BLANN=13350. 38650
C *** FIND TOTAL COST OF PIPING SYSTEM 38660
CAPIP=PUMPF+PUMPC+TANKC+CONTR+BLANN 38670
DO 1800 1=1,4 38680
CAPIP=CAPIP+ZBYP*(XMCST(I)+XSHOP(I)+FIELD(I))+VALVE(I) 38690
1800 CONTINUE 38700
CAPIP=CAPIP+VALVE(5)+VALVE(6) 38710
DO 1900 1=5,18 38720
CAPIP=CAPIP+XMCST(I) + XSHOP(I)+FIELD(I)+EXiJOT(I) 38730
1900 CONTINUE - 38740
CAPIP = CAPIP-i-SHIPCO 38750
NN1=IXNL 38760
NN2=NN1 38770
IF(KNTR1.EQ.O)GO TO 5000 38780
CALL CHANL(NFO,2BYP,VALVE,NPUMP.PPGPM,PUMPC,IXNL, PUMPF.VFILL, 38790
1TANKC,CONTR,BLANN,SHIPCO,CAPIP,NTANK,INML) 38800
5000 CONTINUE 38810
RETURN 38820
END 38830
FUNCTION GRS (X,NDX,Y,NDY,XV,N.NRANGE)
THIS FUNCTION INTERPOLATES BETWEEN THE POINTS OF AN ARRAY
ARRAY OF POINTS ON ABSCISSA
ARRAY OF POINTS ON ORDINATE
INCREMENT BETWEEN POINTS IN THE X ARRAY
INCREMENT BETWEEN POINTS IN THE Y ARRAY
VALUE OF X TO FIND FUNCTION FOR
NUMBER OF POINTS IN ARRAYS
INDICATES EXTRAPOLATION
DIMENSION X(1),Y(1),DX(3),DY(3),YP(2)
NRANGE=0
C *** CHECK IF XV LIES OUTSIDE RANGE
IF((XV+.001).LT.X(1).AND.(XV+.001).LT.X(1+NDX*(N-1 )))NRANGE = -1
IF(XV.GT. (X( 1+NDX*(N-1 ) ) + .001 ) .AND.XV.GT. ( X( 1 )+. 001 ) )NRANGE=1
C ••« IF X IS DECREASING CHANGE SIGN OF NRANGE
C
c
c
c
c
c
c
c
c
c
c
THIS Fl
X
Y
NDX
NDY
XV
N
NRANGE
38840
38850
38860
38870
38880
38890
38900
38910
38920
38930
38940
38950
38960
38970
38980
38990
39000
39010
-------
I
00
C ***
1
2
4
10
C ***
C *+*
11
20
C ***
30
C ***
C ***
40
50
C
C ***
C ***
C
55
IF(X(1 ).GT.X(1+NDX*(N-1 ) ) )NRANGE= (-1 )*NRANGE
IF(NRANGE.NE.O)GO TO 11
DO 10 I=2,N
11=1
FIND XV BETWEEN I AND 1-1 POINTS
IF( ABS(XV-X( 1+NDX*( 1-2) ) ) . LT . .001 )GO TO 4
IF(XV-X(1+NDX*(1-2)))1 ,4,2
IF(XV-X(1+NDX*( 1-1 ) ) )10,70,20
IF(XV-X( 1+NDX*( 1-1 ) ) )20,70,10
11=1-1
GO TO 70
CONTINUE
IF XV IS OUTSIDE RANGE USE LAST 3 OR FIRST 3 POINTS DEPENDING
ON WHETHER OR NOT X IS DECREASING OR INCREASING
I=N
IF(NRANGE.EQ. (-1 ) ) 1 = 1
IF(I.GT.2)GO TO 30
IF XV IS ON LOW END USE FIRST 3 POINTS
N1=3
N2=2
N3=1
NP=3
GO TO 55
IF(I.LT.N)GO TO 40
IF XV IS ON HIGH END USE LAST 3 POINTS
NP=3
GO TO 50
USE 4 POINTS - 2 ON EITHER SIDE OF XV
NP=4
N4=I+1
N1=I-2
N2=I-1
N3=I
THE FOLLOWING FORMULAS WERE EXTRACTED FROM PAGE 75 OF *CALCULATION
OF PROPERTIES OF STEAM* BY MCCLINTOCK AND SILVESTRI
60
DX<1 )=
DY(1 )=
DX(2)
DY(2)=
R=(XV-
YP(1 )=
IF(NP.
GRS=Y(
GO TO
DX(3)=
DY(3)=
YP(2)
X(1+NDX*(N2-1))-X(1+NDX*(N1-1 ))
Y(1+NDY*(N2-1 ) )-Y( 1+NDY* (N1-1 ))
X(1+NDX*(N3-1))-X(1+NDX*(N2-1 ))
Y(1+NDY*(N3-1 ) )-Y ( 1+NDY* (N2-1 ) )
X(1+NDX*(N2-1)))/DX(2)
(DY( 1 )*DX(2)**2+DY(2)*DX(1 ) **2 )/(DX( 1 ) * ( DX( 1 )+DX(2)) )
EQ.4)GO TO 60
H-NOY*(N2-1 ) )+R* ( YP( 1 )+R*(DY(2 )-YP( 1 )))
100
X(1+NDX*(N4-1))-X(H-NDX*(N3-1 ))
Y(1-»-NDY*(N4-1 ) )-Y ( 1 +NDY* ( N3-1 ) )
DY(2)*DX(3)**2+OY(3)*DX(2)**2)/(DX(3)*(OX(2)-t.DX(3) ))
1+NDY* (N2-1 ) )+R* ( YP( 1 ) + R* { 3 . *DY(2 ) -2 . *YP( 1 )-YP ( 2 )+R* ( YP( 1 )•*•
39020
39030
39040
39050
39060
39070
39080
39090
39100
39110
39120
39130
39140
39150
39160
39170
39180
39190
39200
39210
39220
39230
39240
39250
39260
39270
39280
39290
39300
39310
39320
39330
39340
39350
39360
39370
39380
39390
39400
39410
39420
39430
39440
39450
39460
39470
39480
39490
39500
39510
-------
1YP(2)-2.*DY(2))))
GO TO 100
70 GRS=Y(1+NDY*(II-1
100 RETURN
END
39520
39530
39540
39550
39560
i
00
SUBROUTINE HEAD(NTT.NTR,NTP,DSL,DST,DHEDW,DTI,DTO,TSTS,TSTOP,TSBOT
1,TSIDE,TBACK,TSPP,DEN.CTM,CUTT,CUTL,WLDT,WLDL,CHOLE,DTNZI,OTNZO,CT
2PG1.ASPG1,KTYPE.CTH.CTCUT.CTWLD.CTTPG.CTOTH.SLAB.SMAT.DHEDD.DHEDH.
3DWO,DHO,DDO,NPPF,NPPB)
TOTAL NUMBER OF TUBES
NUMBER OF TUBE ROWS
NUMBER OF TUBE PASSES
LONGITUDINAL PITCH (INCH)
TRANSVERSE PITCH (INCH)
BUNDLE WIDTH (INCH)
TUBE INSIDE DIAMETER (INCH)
TUBE OUTSIDE DIAMETER (INCH)
THICKNESS OF TUBE SHEET (INCH)
THICKNESS OF TOP PLATE (INCH)
THICKNESS OF BOTTOM PLATE (INCH)
THICKNESS OF SIDE PLATE (INCH)
THICKNESS OF BACK PLATE (INCH)
THICKNESS OF PASS PARTITION (INCH)
METAL DENSITY (LB/IN3)
COST OF METAL SHEET ($/LB)
CUTTING SPEED (WIN/INCH)
CUTTING LABOR COST ($/HR)
WELDING SPEED (MIN/INCH)
WELDING LABOR COST ($/HR)
HOLE CUTTING COST (S/4INCH THICKNESS)
INLET NOZZLE DIAMETER (INCH)
OUTLET NOZZLE DIAMETER (INCH)
NUMBER OF INLET NOZZLES
NUMBER OF OUTLET NOZZLES
1 FOR FRONT HEADER. 2 FOR BACK HEADER
PLUG COST (S/PLUG)
PLUG ASSEMBLING COST ($/PLUG)
c
c ***
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
INPUT
NTT
NTR
NTP
DSL
DST
DHEDW
DTI
DTO
TSTS
TSTOP
TSBOT
TSIDE
TBACK
TSPP
DEN
CTM
CUTT
CUTL
WLDT
WLDL
CHOLE
DTNZI
DTNZO
NNZI
NNZO
KTYPE
CTPG1
ASPG1
39570
39580
39590
39600
39610
39620
39630
39640
39650
39660
39670
39680
39690
39700
39710
39720
39730
39740
39750
39760
39770
39780
39790
39800
39810
39820
39830
39840
39850
39860
39870
39880
39890
399DO
39910
39920
-------
I
CO
CO
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
*** OUTPUT
CTOTH =
SLAB =
SMAT =
DHEDD =
DHEDH =
DWO =
DHO
DDQ
NPPF =
NPPB =
ZTT=NTT
ZTR=NTR
ZTP=NTP
* BUNDLE
VARIABLES ***
TOTAL COST FOR THE HEADER ($)
TOTAL LABOR COST FOR THE HEADER ($)
TOTAL MATERIAL COST FOR THE HEADER ($)
INSIDE LENGTH OF HEADER (INCH)
INSIDE HEIGHT OF HEADER (INCH)
OUTSIDE WIDTH OF THE HEADER (INCH)
OUTSIDE HEIGHT OF THE HEADER (INCH)
OUTSIDE DEPTH OF THE HEADER (INCH)
NUMBER OF PASS PARTITIONS IN FRONT HEADER
NUMBER OF PASS PARTITIONS IN BACK HEADER
HEIGHT = NUMBER OF ROWS * LONGITUDINAL PITCH
DHEDH=ZTR*DSL
c
c
c
c
CALCULATE "HE CROSSFLOW AREA OF TUBES IN A PASS
APASS=3
SET THE
. 14 iG/4.0*ZTT/ZTP*DTI**2
AREA OF THE HEADER DHEDW*DHEDD=APASS/2 . 0 ,
DHED1=APASS/2.0/DHEDW
C
C
C
c
THEREFORE
IF(OTNZI-DTNZO) 1,1,2
1 DTNOZ=DTNZO
GO TO 3
2 DTNOZ=DTNZI
3 CONTINUE
DHED2=DTNOZ*1 .2
IF (DHED1-DHED2) 4,4,6
4 DHEDD=DHED2
GO TO 8
6 DHEDD=DHED1
8 CONTINUE
c
c *
c
c
= OHEDW-t-2.0*TSIDE
DHO=DHEDH+TSTOP+TSBOT
DDO=OHEDD+TSTS+TBACK
FROM THE NUMBER OF TUBE PASSES NTP, FIGURE OUT THE NUMBER OF
PASS PARTITIONS IN FRONT HEADER AND BACK HEADER
39930
39940
39950
39960
39970
39980
39990
40000
40010
40020
40030
40040
40050
40060
40070
40080
40090
40100
401 10
40120
401
401
401
40'
30
40
50
60
401 70
40180
40190
40200
40210
40220
40230
40240
40250
40260
40270
40280
40290
40300
40310
40320
40330
40340
40350
40360
40370
40380
40390
40400
40410
40420
-------
c
c
oo
C
C
C
C
C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
NPPF = NUMBER OF PASS PARTITIONS IN FRONT HEADER
NPPB = NUMBER OF PASS PARTITIONS IN BACK HEADER
NPPF=NTP/2
ZPPF=NPPF
IF (ZTP/2.0-2PPF) 10,10,20
10 CONTINUE
NPPB=NPPF-1
GO TO 30
20 CONTINUE
NPPB=NPPF
30 CONTINUE
IF (KTYPE-1) 50,50,40
40 CONTINUE
NPP=NPPB
GO TO 60
50 CONTINUE
NPP=NPPF
60 CONTINUE
ZPP=NPP
--- WEIGHT CALCULATIONS ---
TUBE SHEET (LB)
WTTS=DHEDW*DHEDH*TSTS*DEN
TOP PLATE (LB)
WTOP=(DHEDW+2.0*TSIDE)*(DHEDD+TSTS+TBACK)*TSTOP*DEN
BOTTOM PLATE (LB)
(DHEDW-»-2.0*TSIDE)*(DHEDD+TSTS+TBACK)*TSBOT*D£N
TWO SIDE PLATES ( LB)
WSIDE=2.0*DHEDH*(DHEDD+TSTS+T8ACK)*TSIDE*DEN
BACK PLATE
WBACK=DHEDW*DHEDH*TBACK*DEN
PASS PARTITION (LB) — HORIZONTAL
WTPP=DHEDW*DHEDO*TSPP*DEN*ZPP
TOTAL WEIGHT OF THE HEADER (LB)
WTOT=WTTS+WTOP+WTBOT+WSIDE+WBACK+WTPP
ADD 5( TO TOTAL WEIGHT
WTOT=WTOT*1 .05
40430
40440
40450
40460
40470
40480
40490
40500
40510
40520
40530
40540
40550
40560
40570
40580
40590
40600
40610
40620
40630
40640
40650
40660
40670
40680
40690
40700
40710
40720
40730
40740
40750
40760
40770
40780
40790
40800
40810
40820
40830
40840
40850
40860
40870
40880
40890
40900
40910
40920
-------
I
10
O
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
** COST OF THE HEADER PLATES ($)
CTH=CTM*WTOT
LABOR COST
(((CUTTING)))
EACH PLATE HAS FOUR SIDES —• CUTTING + FINISHING
PLTS=2.0*(DHEDW+DHEDH)
PLTOP=2.0*(DHEDW+2.0*TSIDE+DHEDD+TSTS+TBACK)
PLBOT=PLTOP
PSIDE=2.0*2.0*(DHEDH+DHEDD+TSTS+TBACK)
PBACK=PLTS
PLPP=2.0*ZPP*(DHEDW+DHEDD)
PLTOT=PLTS+PLTOP+PLBOT+PSIDE+PBACK+PLPP
SIDE CUTTING COST ($)
CTSD=PLTOT*CUTT/60.0*CUTL
HOLE CUTTING COST ($)
FOR BUNDLE TUBES + REMOVABLE PLUGS
CTHL=ZTT*CHOLE
* CHECK IF THERE IS ANY ADDITIONAL COST FOR CUTTING HOLES ON THE
* BACK HEADER
IF (KTYPE-1) 80,80,70
70 CONTINUE
PLUGS ON BOTH THE FRONT AND BACK HEADER
IF (2.0*TSTS+2.0*TBACK-4.0) 72,72,80
72 CONTINUE
CTHL=0.0
80 CONTINUE
«» TOTAL CUTTING COST ($)
CTCUT=CTSD+CTHL
(((WELDING)))
EACH PASS PARTITION HAS EIGHT WELDS (4 LONG, 4 SHORT)
= 8.0*DHEDH+2.0*2.0*((DHEDD+DHEDW)*2.
1 PP*2 . 0*2 . 0* ( DHEDW+DHEDD )
TOTAL WELDING COST
CTWLD=PLWLD*WLDT*WLDL/60.0
40930
40940
4095O
40960'
40970
40980
40990
41000
41010
41020
41030
41040
41050
41060
41070
41080
41090
41 100
41110
41 120
41130
41 140
41 150
41 160
41 170
41 180
41 190
41200
41 210
41 220
41230
41 240
41250
41260
41270
41280
41290
41300
41310
41320
41330
41340
41350
41360
41370
41330
41 390
41400
41410
41420
-------
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
PLUGS COST
PLUG MATERIAL COST
CMTPG=ZTT*CTPG1
PLUG ASSEMBLING COST
CASPG=ZTT*ASPG1
TOTAL COST FOR PLUGS
CTTPG=CASPG+CMTPG
TOTAL LABOR COST FOR THE HEADER
SLAB=CTCUT+CTWLD+CASPG
TOTAL MATERIAL COST FOR THE HEADER
SMAT=CTH+CMTPG
TOTAL BASE COST FOR THE HEADER
CTOTH=CTH+CTCUT+CTWLD+CTTPG
RETURN
END
41430
41440
41450
41460
41470
41480
41490
41500
41510
41520
41530
41540
41550
41560
41570
41530
41590
41600
41610
41620
41630
41640
41650
41660
41670
SUBROUTINE HTAIR(GAMAX,DFR,VISAV,REAV,CONAV,PRAV,HAIR,CFH.CFR, 41680
1RARAF,FINEF,RFIN) 41690
DIMENSION CFH(3) 41700
C *** INDUCED DRAFT,SMOOTH FIN CORRELATION 41710
REAV=GAMAX*DFR/(29.0*VISAV) 41720
C *** BRIGGS AND YOUNG CORRATION, HIGH FIN TUBES 41730
80 HAIR=CFH(1)*CONAV*REAV**CFH(2) *PRAV*».333 41740
155 CH=CFH(3) 41750
190 HAIR=CH*HAIR 41760
HA1=HAIR 41770
FINEF=CFR*SQRT(HA1 ) 41780
FINEF=TANH(FINEF)/FINEF 41790
RFIN=1.0/HA1*(1.0-FINEF)/(RARAF+FINEF) 41800
300 RETURN 41810
END 41820
-------
I
10
ro
SUBROUTINE HTURB(T,H,XLOAD.HTRT,BBP) 41830
C *** GIVEN T IN DEGREES RANKINE THIS SUBROUTINE CALCULATES A HEAT RATE 41840
C *** RATIO,H. THE BASE HEAT RATE.HTRT.IS THE HEAT RATE WHEN THE 41850
C *•* TURBINE IS AT A NOMINAL LOAD OF XLOAD WITH A BACK PRESSURE 41860
C *** OF BBP INCHES OF MERCURY 41870
C 41880
COMMON ID1,KGO,105(4),D1(3),102,KER,KERR(20),ID3(4),MM,104(7), 41890
102(1218) 41900
COMMON/STIN/XLDFT(6),BP(28),HTRTO(28,6),HTRJO(28,6),NLODS,NBKPR 41910
1,PLOAD,BPMNM(6),TPMNM(6) 41920
COMMON/BCKPR/BCKMN.BCKWX 41930
COMMON/FAST/STOW(3) 41940
DIMENSION X(4),N(7),Y(4) 41950
N1=0 . 41960
C- 41970
C *** CHANGE T TO DEGREES F 41980
TT=TCONV(T,1,2) 41990
C *** FROM T FIND EXHAUST PRESSURE IN INCHES-HG ABS. 42000
BBPP=PSL(TT) 42010
C *** MAKE SURE BBPP IS WITHIN BACK PRESSURE RANGE 42020
I F( BBPP. LT.BCKMN)BBPP=:BCKMN+. 00001 42030
IF(BBPP.GT.BCKMX)BBPP=BCKMX-.00001 42040
LOOP=1 42050
C *** SET ALL EXTRAPOLATION INDICATORS TO ZERO 42060
3 DO 5 1=1,7 42070
5 N(I)=0 42080
NP=3 42090
C *** SEE IF XLOAD LIES WITHIN THE RANGE OF XLDFT 42100
IF( (XLOAD+.001 ) . LT.XLDFT(NLODS) .AND. ( XLOAD-t-. 001 ) . LT . XLDFT ( 1 )) 42110
1N(1)=-1 42120
IF(XLOAD.GT.(XLDFT(1)+.001) .AND.XLOAD.GT.(XLDFT(NLODS)+.001) ) 42130
1N(1)=1 42140
IF(XLDFT(1).GT.XLDFT(NLODS))N(1)=(-1)*N(1) 42150
IF(N(1).NE.O)GO TO 11 42160
C *** FIND XLOAO BETWEEN I AND 1-1 POINTS 42170
DO 10 I=2,NLODS 42180
IZ=I 42190
IF(ABS(XLOAD-XLDFT(I-1)).LT..002)GO TO 4 42200
IF(XLOAD-XLDFT(I-1))1,4.2 42210
1 IF(XLOAD-XLDFT(I))10,70,20 42220
2 IF(XLOAD-XLDFT(I))20,70,10 42230
4 IZ=I-1 42240
GO TO 70 42250
10 CONTINUE 42260
C *** IF XLOAD IS OUTSIDE RANGE OF XLDFT USE LAST 3 OR FIRST 3 POINTS 42270
C *** DEPENDING ON WHETHER OR NOT XLDFT IS DECREASING OR INCREASING 42280
11 I=NLODS 42290
IF(N(1).EQ.(-1))I=1 42300
20 IF(1.GT.2)GO TO 30 42310
C *»« IF XLOAD IS ON LOW END USE FIRST 3 POINTS. IF IT IS ON HIGH END 42320
-------
BBPP
BBPP
NBKPR
NBKPR
,NBKPR
,N(2))
,N( 3 ))
,N(4))
I
VO
GO
C *** USE LAST 3 POINTS. OTHERWISE USE 4 POINTS - 2 ON EITHER SIDE
C *** OF XLOAD
N1=3
N2=2
N3=1
GO TO 50
30 IF(I.EQ.NLODS)GO TO 40
NP = 4
N4-I+1
40 N1 = I~2
N2=I-1
N3-I
GO TO 50
45 IF(N1 .EQ.O)GO TO 70
C **« FIND THE HEAT RATES(CORRESPONDING TO THE BACK PRESSURE) OF THE
C *** 3 OR 4 LOADS THAT ARE NEAR XLOAD
50 X(1)=GRS(BP,1,HTRTD(1,N1),1,BBPP,
X(2)=GRS(BP,1 ,HTRTD(1 ,N2),
X(3)=GRS(BP,1 ,HTRTD(1,N3),
Y(1 ) = XLDFT(N1)
Y(2)=XLDFT(N2)
Y(3) = XLDFT(N3)
IF(NP.EQ.3)GO TO 55
Y(4)=XLDFT(N4)
X(4)=GRS(BP,1,HTRTD(1,N4),1 , BBPP .NBKPR ,N( 7 ) )
55 CONTINUE
C *** FIND THE HEAT RATE FOR XLOAD
HTRT=GRS(Y,1 ,X,1 , XLOAD , NP ,N( 5 ) )
GO TO 100
70 HTRT=GRS(BP,1,HTRTD(1,IZ),1, BBPP,
C *** SET MINOR ERROR IF EXTRAPOLATION
100 DO 200 11 = 1 ,7
IF(N(II))250,200,250
200 CONTINUE
GO TO 300
250 KER=22
CALL ERORF(KER,KERR,KGO,MM)
C *** SEE IF BOTH HEAT RATES HAVE BEEN CALCULATED
300 IF(LOOP.EQ.2) GO TO 400
C *** FIND BASE HEAT RATE
H = HTRT
320
340
350
42330
, NBKPR, N(6))
OCCURRED
BBPP=BBP
NO NEED TO RECALCULATE HTRT IF BASE CONDITIONS HAVE NOT CHANGED
I F(ABS(XLOAD-STOW(1))-. 002)320, 320, 350
IF(ABS(BBP-STOW(2))-. 01)340, 340, 350
HTRT = STOW(3)
GO TO 400
STOW(1)=XLOAD
STOW(2)=BBP
,~
4235°
4236°
4237°
4238°
424°
4245°
42460
42470
42480
42490
42500
42510
42560
42570
42590
42600
42610
42620
42630
4264°
42690
42700
42710
42760
42770
42780
-------
GO TO 45
400 H=H/HTRT
STOW(3)=HTRT
RETURN
END
42830
42840
42850
42860
42870
vo
-pa
SUBROUTINE ICHEK
C *** CHECKS INPUT DATA FOR CONSISTENCY
C *** LIMITATION OF INPUT DATA
DIMENSION KERRO(20)
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAV(2),PI
COMMON KCI,KER,KERR(20),KFIN,KREG,LAIC,LSUP,MM,NP,NR,NT11NT2,NTP,
1NTR,NTT,ABARE.AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2)
2,DEN(2).DEN 12(2,2),DENFN,DENLZ(7),DBW.OEQ,DFH,DFR,DFS,DFT,DKL,
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT,DPT A,DPTF,
1DPTOTI2),POUT(2) .PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS.UBARE,UCLN .UTOT,
20(2).QDUT,QTOT.RFI,RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8)
3,TWALL,TD.TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE.AOF,VISLZ<7).
4VIS(2),VIS12(2,2),VISW,W(2),\rtAPF,WB(2),WLQ(2)
COMPTON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKC,CKLOV,CKSTC,F.
1 FALT,FINEF,FFF,FSUM,OCL(4),ODL(4),OKL(4),OML(4),OMV(4),P,PRAN(2),
2PRALZ(7),R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA,
3XREX.ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20).ZTPPA
COMMON ZTRD.ANGI ,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV,ZNFI ,PTI,TKT , TKF,
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,OD(7),
2CARD7I6),DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2),
3RASPC,ZTPD,ZNTD,COST(7),SSUM(16,30),ISUM(13,30),PRICE(2,21)
9010 FORMAT (1H1)
9020 FORMAT(47HO MINOR ERRORS FOUND IN INPUT DATA (CALCULATION,
1 13H CONTINUES)--/7X,10(14,1H,)/7X,10(14,1H,»
9030 FORMAT(48HO MAJOR ERRORS FOUND IN INPUT DATA (CALCULATION,
1 9H STOPS)--/7X,10(14,1H,)/7X,10(14,1H,))
NERC=0
MM=0
CALL CFIXM(ZTRD
CALL CFIXM(ANGI
CALL CFIXM(ZBYP
CALL CFIXM(ZBUP
CALL CFIXM(ZBUS
ZTPMX=IFIX(DLOV/19.99)+1
CALL CF1XM(ZFAN , 0.001 ,10.1
0.001 ,99.0 ,4.0
-0.001 ,90.01 ,0.0
.001 ,1000. ,1 .0,110,K-ERRO,NERC)
0.001 ,10.01 ,1.0
0.001 ,4.01 ,1.0
.ZTPMX
, 104.KERRO.NERC)
.107.KERRO.NERC)
.111.KERRO.NERC)
, 112,KERRO.NERC)
.113,KERRO.NERC)
42880
42890
42900
42910
42920
42930
42940
42950
42960
42970
42980
42990
43000
43010
43020
43030
43040
43050
43060
43070
43080
43090
43100
43110
43120
43130
43140
43150
43160
43170
43180
43190
43200
43210
43220
43230
-------
CALL CFIXM(PTI ,-0.001 ,20.0 ,0.0
CALL CFIXM (TKT , 0.001 ,500.0 ,26.0
0.001 ,500.0
CALL CFIXM (TKF
CALL CFIXM(COST(2),.001 ,1 . E5
DO 10 1=1,2
CALL CFIXM(ZNOZ(1), 0.01,10.0
10 CONTINUE
KCI=2
356 NTP=ZTPD+0.01
740 IF (ZIMTD*ZNTR-0.01 ) 746,746,742
742 IF (ZNTD-ZNTR) 743,746,746
743 ZNTD=ZNTR
CALL ERORG(NERC,KERRO,902)
746 CONTINUE
748 IF (ZNTD-0.01) 750,750,760
750 CALL ERORF (105,KERR,KGO,MM)
760 IF (DLOV-0.01) 770,770,780
770 CALL ERORF (201,KERR,KGO,MM)
780 CONTINUE
1006 GO TO 1080
1020 CALL ERORF(102,KERR,KGO,MM)
GO TO 1100
1080 IF (TIND(1)*TOUTD(1)*WD(1)
1 1020,1020,1100
1100 CONTINUE
IF (NERC+MM) 9000,9000,8000
8000 CONTINUE
8400 IF (NERC) 8600,8600,8500
8500 WRITE(NFO,9020) (KERRO(I),1=1,NERC)
8600 IF (MM) 9000,9000,8800
8800 WRITE(NFO,9030) (KERR(I),1*1,MM)
9000 RETURN
END
,110.0
,100.0
,1.0
,212,KERRO,NERC)
,215,KERRO,NERC)
,216,KERRO,NERC)
,915,KERRO,NERC)
,1+816,KERRO,NERC)
*TIND(2)-0.1 )
43240
43250
43260
43270
43280
43290
43300
43310
43320
43330
43340
43350
43360
43370
43380
43390
43400
43410
43420
43430
43440
43450
43460
43470
43480
43490
43500
43510
43520
43530
43540
43550
43560
SUBROUTINE ICONV
C »** INPUT UNIT CONVERSION
DIMENSION IFN(6)
COMMON IDUM(6),RDUM(3),IDUMW(34),DUMW(246),DUMYD(60),DUM1(912)
DATA IFN/16,19.20,21,22,25/
KIN=1
C *** CONVERSION OF TEMPERATURES TO ABSOLUTE
DO 10 1=1,6
43570
43580
43590
43600
43610
43620
43630
43640
-------
II = IFN( I )
10 DUMYD(II)=TCONV(DUMYD(II),KIN,1)
C *** CONVERSION OF U.S. UNITS TO INTERNAL COMPATIBLE
DUMYD(13)=DUMYD(13)*1.OE3
DUMYD(14)=DUMYD(14)*4.5E3
DO 220 1=1,7
220 DUMYD(1+25)=DUMYD(1+25)* 1.OE6
900 RETURN
END
43650
43660
43670
43680
43690
43700
43710
43720
43730
i
<£>
CTv
SUBROUTINE INPUT 43740
C *** S/R INITA CONTROLS DATA HANDLING 43750
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2),PI 43760
COMMON KCI,KER,KERR(20),KFIN.KREG,LAIC,LSUP.MM,NP,NR,NT1,NT2.NTP, 43770
1NTR.NTT.ABARE,AFAN.AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 43780
2,DEN(2).DEN12(2,2).DENFN,DENLZ(7),DBW,DEO,DFH,DFR,DFS,DFT,DKL, 43790
3DLSP.DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT 43800
COMMONPAD,DPAF,DPAM,DPAW,DPF(10).DPI,DPNZ(2).DPT.DPTA.DPTF, 43810
1DPTOTI2),POUT(2),PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTOT, 43820
20(2),QDUT,QTOT,RFI, RFIN.RFTOT,RTOT,RTW,TAV(2),T1N(2),TOUT(2),TT(8) 43830
3,TWALL,TO,TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,VISLZ(7), 43840
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLO(2) 43850
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC,F, 43860
1FALT,FINEF,FFF,FSUM,OCL(4),ODL(4),OKL(4),OML(4) ,OMV(4 ) ,P.PRAN(2), 43870
2PRALZI7),R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA, 43880
3XREX,Ziyp,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20),ZTPPA 43890
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV,ZNFI,PTI.TKT.TKF, 43900
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN.QD(7), 43910
2CARD7(6).DNZI{2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2), 43920
3RASPC,ZTPD,2NTD,COST(7),SSUM(16,30),ISUM(13,30),PRICE(2,21) 43930
10 CALL IREAD 43940
200 CONTINUE 43950
CALL ICONV 43960
CALL ICHEK 43970
IF (KGO-1) 300,300,10 43980
300 CALL PPCON 43990
1000 RETURN 44000
END 44010
-------
SUBROUTINE I READ 44020
COMMON IDUM1,KGO,IDUM2(4),DUM(3),IDUM4(34),DUM1(246),RON2(60), 44030
1DUM3(912) 44040
20 KGO=1 44050
RON2(25)=32. 44060
RON2(41)=50. 44070
RON2(8)=60. 44080
RON2(20)=93. 44090
RON2(19)=156. 44100
RON2(21)=131. 44110
RON2(13)=179130. 44120
RON2(53)=270. 44130
900 RETURN 44140
END 44150
C
c
C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
SUBROUTINE MJBOX(TOL,ALF,DELT,ITRMX,NITR,N)
-------
c
c
c
c
c
c
c
c
vo
CO
c
C
C
VAMAX= MAXIMUM AIR VELOCITY - FT/MIN 44430
VAMIN= MINIMUM AIR VELOCITY - FT/MIN 44440
VWMAX= MAXIMUM WATER VELOCITY - FT/SEC 44450
VWMIN= MINIMUM WATER VELOCITY - FT/SEC 44460
CPW= SPECIFIC HEAT OF WATER 44470
CPA= SPECIFIC HEAT OF AIR 44480
DENW= DENSITY Of WATER 44490
DENA= DENSITY OF AIR 44500
COMMON/EPA/TNMIN,TNMAX,TSAT(21),COSTT(21),X(10,21),XC(10),VAMAX, 44510
1VAMIN,VWMAX,VWMIN,XN,XP,SUBCL,QMIN,QMAX,PITCH,DIA, 44520
2RNGMX,RNGMN.TLMIN,TLMAX,TITDX,TITDN 44530
3,TSATA,T5ATZ,XHEAT(21) 44540
COMMON/SCOND/TTDMN,TTDMX,TISUM(21) 44550
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2),PI 44560
COMMON KCI,KER,KEfirR(20),KFINIKREGtLAIC,LSUP,MM,NP,NR,NTl,NT2,NTP, 44570
1NTR,NTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20).CP(2) 44580
2.DEN(2),DEN12(2,2),DENFN,DENLZ(7),DBW,DEO,DFH,DFR,DPS,DFT,DKL, 44590
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT 44600
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT,DPTA,DPTF, 44610
1DPTOT(2),POUT(2),PTUB,RV2.GAMAX.GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTOT, 44620
20(2).QDUT.QTOT.RFI,RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 44630
3,TWALL,TD,TW,TMTD,TK(2),VAPP,VNZ(2)tVT,DFAN,TLTE,AOF,VlSLZ(7), 44640
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLQ(2) 44650
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC,F, 44660
1 FALT, FINEF, FFF , F SUM, OCL ( 4 ) , DDL ( 4 ) , OK L( 4 ) , OM[_( 4 ) , OMV ( 4 ) ,P,PRAN(2) , 44670
2PRALZ(7),R.RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA, 44680
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20),ZTPPA 44690
COMMON ZTRD,ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI.DLOV.ZNFI,PTI,TKT,TKF, 44700
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,00(7), 44710
2CARD7(6),DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2), 44720
3RASPC,ZTPD,ZNTD.COST(7), SSUM( 1 6,30) , ISUM( 1 3, 30),PRICE(2,21) 44730
COMMON/PAS IT/TBUCK 44740
COMMON/TRACE/SSSUM(9),HSUM(3) 44750
DIMENSION XLOW(10),XHIGH(10) 44760
44770
SET NUMBER OF POINTS IN COMPLEX,KN 44780
44790
KN = 2*N-M 44800
ICHCK=0 44810
NSUM=1 44820
LJCNT=0 44830
IISUM(1)=0 44840
IISUV(2)=1 44850
IISUM(3)=1 44860
TBUCK=0. 44870
ITR=0 44880
JHIGH=0 44890
ITRCT=0 44900
LJ=1 44910
0*1 44920
-------
C
C
C
C
C ** *
100
C
C
C
C
C
C
C
C
C
C
150
160
175
SET UP ORIGINAL COMPLEX,DETERMINE OBJECT FUNCTIONS
AND FIND d.THE POINT WITH THE HIGHEST VALUE
CALL SETUP(d.KN,Ld)
ITRCT=1
LdSTR=Ld
LIMIT THE NUMBER OF OUTPUT PAGES TO 200
IF(NPAGE.GE.200) GO TO 312
MULT=1
IF HIGHEST POINT,J, HAS REPEATED THEN MOVE d 1/2 THE
DISTANCE TO THE CENTROlD
IF(d.NE.dHIGH) GO TO 200
MULT=0
IF THE SAME POINT HAS BEEN MOVED TOWARDS THE CENTROlD 5 TIMES, IT
IS ALMOST EQUAL TO THE CENTROlD. THUS THE CENTROlD IS EITHER THE
WORST CASE OR VIOLATES THE IMPLICIT CONSTRAINTS. SET WORST POINT
EQUAL TO BEST POINT.
IF(ICC.LT.5) GO TO 175
DO 160 M=1,N
X(M,d)=X(M,LJ)
CONTINUE
ICC = 0
GO TO 305
CALL MOVIT(N,J)
ICC=ICC+1
GO TO 305
C
C
C
200
C
C
C
C
300
305
C
C
C
CALCULATE CENTROIDS OF ALL POINTS EXCEPT J IF J HAS
NOT REPEATED AS THE HIGHEST POINT
CALL CENT(d,N,KN,JHIGH)
IF HIGHEST POINT,d, HAS NOT REPEATED THEN MOVE
d IN THE NORMAL FASHION
ICC = 0
dHIGH=d
TBUCK=COSTT(d)
DO 300 IX=1,N
X(IX,d)=XC(IX)+ALF*(XC(IX)-X(IX,d))
CONTINUE
CONTINUE
CHECK TO SEE IF NEW POINT SATISFIES CONSTRATINTS
CALL CONST(d.DELT)
44930
44940
44950
44960
44970
44980
44990
45000
45010
45020
45030
45040
45050
45060
45070
45080
45090
45100
451 10
45120
45130
45140
45150
45160
45170
45180
45190
45200
45210
45220
45230
45240
45250
45260
45270
45280
45290
45300
45310
45320
45330
45340
45350
45360
45370
45380
45390
45400
45410
45420
-------
o
o
c
c
c
c
c
C CALCULATE OBJECT FUNCTION FOR NEW POINT
C
310 CONTINUE
IISUM(1)=ITRCT
IISUM(2)=LJ
IISUM(3)=J
CALL COSTER(J,VAIR,VH20,KKILL)
C *** LIMIT THE NUMBER OF OUTPUT PAGES TO 200
IF(NPAGE.LT.200) GO TO 315
312 WRITE(6,7)
GO TO 1000
IF WATER VELOCITY IS NOT BETWEEN WIN AND MAX FT/SEC, SET
NUMBER OF TUBES SUCH THAT WATER VELOCITY IS ON BOUNDARY.
315 IF(KKILL) 380,380,317
317 GO T0(319.320,340,345) KKILL
319 V=VWMAX
GO TO 330
320 V=VWMIN
330 X(5,J)=VH20/V*X(5,J)
GO TO 310
IF AIR VELOCITY IS NOT BETWEEN MIN AND MAX FT/MIN, SET TUBE
LENGTH SUCH THAT AIR VELOCITY IS ON BOUNDARY. IF DOING THAT
VIOLATES TUBE LENGTH CONSTRAINT, MOVE THE POINT 1/2 THE
DISTANCE TO THE CENTROID
340 V=VAMAX
GO TO 350
345 V=VAMIN
350 TL=VAIR/V*X(4,J)
IF(TL.GT.TLMAX.OR.TL.LT.TLMIN) GO TO 150
X(4,J)=TL
GO TO 310
380 LJ=LJSTR
J=JHIGH
FIND LOWEST OBJECT POINT,LJ, AND HIGHEST
OBJECT POINT,J
DO 600 1=1,KN
IF(COSTT(I).GT.COSTT(J)) GO TO 400
IF(COSTT(I).LT.COSTT(LJ)) GO TO 500
GO TO 600
400 J=I
GO TO 600
500 LJ=I
600 CONTINUE
C
C
c
c
c
c
c
c
c
c
45430
45440
45450
45460
45470
45480
45490
45500
45510
45520
45530
45540
45550
45560
45570
45580
45590
45600
45610
45620
45630
45640
45650
45660
45670
45680
45690
45700
45710
45720
45730
45740
45750
45760
45770
45780
45790
45800
45810
45820
45830
45840
45850
45860
45870
45880
45890
45900
45910
45920
-------
ITRCT=ITRCT+1
C *** IF LOW POINT REPEATS FOR 15 ITERATIONS NO PROGRESS IS BEING
C *** MADE. THE OBJECT FUNCTION GRADIENT IS FLAT. TRY TO INCREASE
C *** ALF SO AS TO THROW SOLUTIONS OUT OF THE FLAT REGION.
IF(LJSTR.NE.LJ) GO TO 660
IF(LJCNT.GT.IS) GO TO 640
LJCNT=LJCNT+1
GO TO 690
ALF=ALF*1.05
GO TO 670
LJSTR=LJ
LJCNT=0
CONTINUE
SEE IF LOW AND HIGH OBJECT POINTS ARE
WITHIN CONVERGENCE TOLERANCE
IF((COSTT(J)/COSTT(LJ)-1.).LE.TOL) GO TO 700
640
660
670
690
C
C
C
C
C
C
692
694
696
698
C
C
C
C
IF(ICHCK)692,692,698
IF(COSTT(J)/COSTT(LJ)-TOL-1.005)694,694,698
ICHCK=1
DO 696 IVAR=1,N
XLOWIIVAR)= X(IVAR,1)
XHIGH( IVAR)=X(IVAR,1 )
DO 696 IPT=2,KN
IF(X(1VAR,IPT).LT.XLOW(IVAR))XLOW(IVAR)=X(IVAR,IPT)
IF(X(IVAR,IPT).GT.XHIGH(IVAR))XHIGH(IVAR)=X(IVAR,IPT)
CONTINUE
TSATA = AMAX1(TSATA,XLOW( 1 ))
TSATZ=AMIN1(TSATZ.XHIGH ( 1 ))
TITDN=AMAX1(TITDN,XLOW(2))
TITDX = AMIN1(TITDX,XHIGH(2) )
RNGMN=ftMAXl (RNGMN,X LOW(3))
RNGMX=AM1N1(RNGMX,XHIGH(3))
TLMIN=AMAX1(TLMIN,XLOW(4))
T|_MAX = AMIN1(TLMAX.XHIGH( 4))
TNMIN=AMAX1(TNMIN.XLOW(5))
TNMAX=AMIN1(TNMAX,XHIGH(5))
TTDMN=AMAX1(TTDMN,XLOW ( 6))
TTDMX=AMIN1(TTDMX,XHIGH(6))
CONTINUE
SET CONSECUTIVE ITERATION COUNTER BACK TO ZERO
IF A NEW POINT CAME OUT LOW ENOUGH TO CAUSE TOL VIOLATION
IF(JHIGH.EQ.LJ) ITR=0
GO TO 800
45930
45940
45950
45960
45970
45980
45990
46000
46010
46020
46030
46040
46050
46060
46070
46080
46090
46100
461 10
46120
46130
46140
46150
46160
461 70
46180
46190
46200
46210
46220
46230
46240
46250
46260
46270
46280
46290
46300
46310
46320
46330
46340
46350
46360
46370
46380
46390
464 JO
46410
46420
-------
C SEE IF NUMBER OF SUCCESSFUL CONSECUTIVE ITERATIONS
C EQUALS THE NUMBER REQUIRED
C
700 IF(NITR.GT.ITR) GO TO 725
IF(COSTT(d).GT.TBUCK)GO TO 100
C *** CALL COSTER AGAIN TO MAKE Ad PRINT OUT THE DESIGN WITH
C *** THE LOWEST COST FUNCTION. SET KNTR1 TO KILL OFF-DESIGN PERFORMANCE
KNTR1=1
SUBCL=X(6,LJ)
CALL COSTER(LJ,VAIR,VH20,KKILL)
GO TO 750
C *** INCREMENT THE CONSECUTIVE ITERATION COUNTER IF A NEW POINT
C *** IS TO BE WORKED ON NEXT
725 IF(J.NE.JHIGH) ITR=ITR+1
GO TO 800
SET MULT=2 TO PRINT LAST ITERATION
750 MULT=2
NSUM=KN
GO TO 1000
SEE IF MAXIMUM NUMBER OF ITERATIONS HAS BEEN EXCEEDED
800 IFflTRCT.GE.ITRMX) GO TO 900
IF(MULT.EQ.2) GO TO 1000
GO TO 100
900 WRITE(6,6)
PRINT LAST ITERATION
GO TO 750
1000 CONTINUE
6 FORMAT(/,62H BOX METHOD DID NOT CONVERGE IN SPECIFIED NUMBER OF IT
1ERATIONS)
7 FORMAT(///,38H PROGRAM EXCEEDED 200 PAGES OF OUTPUT)
RETURN
END
C
C
C
C
C
C
C
C
C
46430
46440
46450
46460
46470
46480
46490
46500
46510
46520
46530
46540
46550
46560
46570
46580
46590
46600
46610
46620
46630
46640
46650
46660
46670
46680
46690
46700
46710
46720
46730
46740
46750
46760
46770
46780
46790
46800
-------
o
GO
C
c ***
C
c ***
c
c
c
c ***
c
c
1200
1800
2700
3600
C
1
c ***
c
c
SUBROUTINE MOTOR(NMOT.MORPM.HPMOT,CMOT1,CTMOT)
THIS SUBROUTINE CALCULATES THE COST FOR PURCHASING A MOTOR
INPUT VARIABLES ***
MORPM = MOTOR RPM
HPMQT = MOTOR HORSEPOWER
OUTPUT VARIABLE ***
CMOT1 = MOTOR COST ($)
ZMOT=NMOT
INDEX=MORPM/900
GO TO (1200,1800,2700,3600),INDEX
CMOT1=10.827*HPMOT+197.325
GO TO 1
CMOT1=9.777*HPMOT+1B8.57
GO TO 1
CONTINUE
CMOT1=6.627*HPMOT+162.3
CONTINUE
CTMOT=ZMOT*CMOT1
ADD 10 PCT. FOR SHIPPING TO MANUFACTURER
CTMOT=1.1*CTMOT
RETURN
END
45810
46820
46830
46840
46850
46860
46870
46880
46890
46900
46910
46920
46930
46940
46950
46960
46970
46980
46990
47000
47010
47020
47030
47040
47050
47060
47070
47080
47090
47100
471 10
C
C
C
C
WAMIN,VWMAX,VWMIN,XN,XP,SUBCL,QMIN,QMAX,PITCH,DIA,
2RNGMX,RNGMN,T LMIN,T LMAX.TITDX,TI TON
THIS SUBROUTINE MOVES POINT J 1/2 THE DISTANCE
TO THE CENTROID
DO 100 1 = 1 ,N
47120
47130
47140
47150
47160
47170
47180
471'iO
47200
47210
-------
100 CONTINUE
RETURN
END
47220
47230
47240
O
-p.
SUBROUTINE MTDOV (TOT,NP,NR.MSW.CMIX,KER,PA,R1.XNTU1,LPMT,TMTD,FT,
1 COCUR)
C *** CALCULATION OF LMTD, NTU, f, R, AND P.
C *** CMIX=1 ASSUME UNMIXED-UNMIXED. IF CMIX=0 THEN MIXED-UNMIXED.
DIMENSION XNR(IO),PNR(10),TB(20)
C *** SET TO MATRIX OF N X N
SN=.1
2NTP=NP
12 P=PA*R1
R=1.0/R1
63 IF (P-1.0) 70,64,64
64 KER=70
GO TO 482
C *** IF R CLOSE TO ONE CORRECT EQ.
70 IF (ABS(R-1.0)-.001) 72,80,80
72 DELT=P/(1.0-P)
GO TO 90
C *** DELT IS THE NTU FOR TRUE COUNTERCURRENT FLOW
80 DELT=ALOG((1.0-P)/(1.0~P*R))/(R-1.0)
90 CONTINUE
92 CONTINUE
C *** NEWTON RAPHSON CONVERGENCE TECHNIQUE STARTS HERE
100 XNR( 1 ) = . 1
XNR(2)=DELT
120 LPMT=1
130 XNTU=XNR(LPMT)
C *** MULTIPLE PASS CORRECTION
140 XNTA=XNTU/ZNTP
C *** UNMIXED-UNMIXED RELATIONS,1 PASS - AFTER STEVENS - 20X20 MATRIX
180 XNTA=XNTA*SN
XR=XNTA/(1,0+.5»(1.0+R)*XNTA)
TH2=0.0
DO 182 1=1,10
182 TB(I)=0.0
DO 200 d=1,10
184
DO 190 1=1,10
IF (1-1) 184,184,186
TA»1.0
47250
47260
47270
47280
47290
47300
47310
47320
47330
47340
47350
47360
47370
47380
47390
47400
47410
47420
47430
47440
47450
47460
47470
47480
47490
47500
47510
47520
47530
47540
47550
47560
47570
47580
47590
47600
47610
47620
-------
I
I—'
o
186 DT=(TA-TB(I))*XR
TA=TA-DT
190 TB(I)=TB(I)+DT*R
200 TH2=TH2+TA*SN
PN=1.0-TH2
206 IF (NP-2) 210,260,260
210 PNR(LPMT)=P-PN
C *** CALL N/R CONV. S/R
220 CALL NRCON (LPMT,XNR,PNR,KER,71,1.E-4,K,10)
IF (K-1) 130,400,500
C *** CORRECT ONE PASS P FOR ANY NUMBER OF PASSES
260 CONTINUE
262 IF (ABS(R-1.0)-0.001) 270,270,280
270 PN=(ZNTP*PN)/(1 .0+(ZNTP-1 .0)*PN)
GO TO 210
280 PN=((1-0-PN*R)/(1,0-PN))**NP
PN=(PN-1.0)/(PN-R)
GO TO 210
400 CONTINUE
450 TMTD=TDT*P/XNTU
482 PA=P*R
490 R1=1.0/R
500 RETURN
END
47630
47640
47650
47660
47670
47680
47690
47700
47710
47720
47730
47740
47750
47760
47770
47780
47790
47800
47810
47820
47830
47840
47850
47860
SUBROUTINE NOZCT (DNZI,DNZ,WNZ,VNZ,DEN,PNZMX,DPNZ,DBW,CTPA,I)
C *** CONTROLS SIZING OF TUBE SIDE NOZZLES
COMMON/PIPE/XDIA(20),XLGT(20),NN1,NN2,XTOWR,PLNMH,TTTBH,VX,VN,VAVE
DIMENSION DNZI(1 ),DNZ(1 ) ,VNZ(1 ) ,DPNZ(1),DEN(4),VKTN(2)
DATA VKTN/1.0.0.5/
DPMAX=.1
IF (DNZI(I)-.01) 20,20,30
20 IF (1-1 ) 22,22,120
C *** ESTIMATE NOZZLE SIZE FROM AVERAGE
22 ONZ(I )=.4*SQRT(WNZ/(VAVE*DEN(I)*3.
CALL NOZID (CTPA,DBW ,DNZ(D,N,
30 VNZ(I)=WNZ *.04/(.7854*DNZ(I)**2*DEN(I))
RV2N=DEN(I)*VNZ(I)**2
DPNZ(I)=VKTN(I)*RV2N/(144.0*64.34)
60 IF (DNZI(I)-.01) 70,200,200
70 IF (DPNZ(I) -DPMAX) 200,200,100
100 IF (DNZ(I)-DNZMX+.01) 105,200,200
ALLOWABLE WATER VELOCITY
, 14159))
DNZMX,0)
47870
47880
47890
47900
47910
47920
47930
47940
47950
47960
47970
47980
47990
48000
48010
48020
48030
-------
105 N=N+1
CALL NOZID (CTPA,DBW,DNZ(I),N,DNZMX,1)
GO TO 30
C *** IF DENSITIES ARE WITHIN 15 PCT. LET OUTLET =INLET
120 IF(ABS(DEN(2)/DEN(1)-1.)-.15)140,140,22
140 DNZ(I)=DNZ(I-1)
GO TO 30
200 RETURN
END
48040
48050
48060
48070
48080
48090
48100
481 10
48)20
I
H-'
O
SUBROUTINE NOZID (CTPA,DBW.DNZ,N,DNZMX,KSTEP) 48130
DIMENSION DNZA(20) 48140
DATA DNZA/1.049.2.069,3.068,4.026,5.047,6.065,8.071,10.136,12.09, 48150
1 13.25,15.25,17.25,19.25,21.25,23.25,25.25,29.25,33.25, 48160
2 35.25,41.O/ 48170
NMAX=20 48180
C *** LOOK UP ON NOZZLE SIZE 48190
IF (KSTEP-1) 5.45,45 48200
5 X=0.8*DBW/(1.0+CTPA) 48210
30 DNZMX=X*DBW 48220
C *** CHECK IF PIPE DIAMETER IS ALREADY TOO LARGE FOR TABLE 48230
IF(DNZ-DNZA(NMAX)/.97)31,31,41 48240
31 DO 40 J=1,NMAX 48250
N=J 48260
IF (DNZA(N)/DNZ-.97) 40,50,50 48270
40 CONTINUE 48280
C *** LET PIPE GO UP BY INCREMENTS OF 6 INCHES TO A MAXIMUM OF 15 FEET 48290
41 DNZY=42. 48300
DO 43 J=1,21 48310
IF(DNZY/DNZ-.97)42,44,44 48320
42 DNZY=DNZY+6. 48330
43 CONTINUE 48340
44 DNZ=DNZY 48350
GO TO 90 48360
45 IF (N-NMAX) 50,60,60 48370
50 DNZ=DNZA(N) 48380
GO TO 70 48390
60 DNZ=DNZ+4.0 48400
70 IF (DNZ-DNZMX) 90,90,80 48410
80 DNZ=DNZMX 48420
90 RETURN 48430
END 48440
-------
c
c +* *
c ***
c ***
c ***
c
c
c ***
c
c
c ***
c
c
c
c $
c
c *
10
c
c *
20
30
34
40
45
50
SUBROUTINE NOZZLE(DTNOZ,CTNOZI)
THIS SUBROUTINE GIVES THE INFORMATION OF INSTALLING COST
FOR A CARBON STEEL NOZZLE WITH WELD NECK FLANGE
PRESSURE 150 PSI
NOMINAL DIAMETER 2.4 24.2 INCH
INPUT VARIABLE ***
DTNOZ = NOMINAL NOZZLE DIAMETER (INCH)
OUTPUT VARIABLE ***
CTNOZ1 = COST FOR INSTALLING ONE NOZZLE ($)
CTNOZ1=0.
IF(DTNOZ.LT..001)GO TO 50
IF (DTNOZ.GT.24.2) GO TO 40
NOMINAL DIAMETER IN RANGE 13.8— 24.2 INCH
IF (DTNOZ.LE.13.8) GO TO 10
CTNOZ1=168.0+21.73*(DTNOZ-13.8)
GO TO 50
NOMINAL DIAMETER IN RANGE 8.2 — 13.8 INCH
IF (DTNOZ.LE.8.2) GO TO 20
CTNOZ1=78.0-M6.07*(DTNOZ-8.2)
GO TO 50
NOMINAL DIAMETER IN RANGE 2.4 — 8.2 INCH
IF (DTNOZ.LT.2.4) GO TO 30
CTNOZ1=16.0+10.69*(DTNOZ-2.4)
GO TO 50
WRITE(6,34)
FORMAT(1H ,*NOZZLE DIAMETER TOO SMALL FOR COST ESTIMATION*)
GO TO 50
WRITE(6,45)
FORMAT(1H ,*NOZZLE DIAMETER TOO LARGE FOR COST ESTIMATION*)
CONTINUE
RETURN
END
48450
48460
48470
48480
48490
48500
48510
48520
48530
48540
48550
48560
48570
48580
48590
48600
48610
48620
48630
48640
48650
48660
48670
48680
48690
48700
48710
48720
48730
48740
48750
48760
48770
48780
48790
48800
48810
48820
48830
48840
48850
48860
48870
-------
: ***
: ***
: ***
1 0
20
30
40
46
50
53
54
1000
55
SUBROUTINE NRCON (NR.X,Y,KER,KERNO,TOL,KODE,NX)
NEWTON-RAPHSON PROCEDURE
DIMENSION X(1 ) ,Y( 1 )
IF KODE=0,1,2 THEN CONTINUE, CONVERGED, ERROR EXIT RESP.
IF KODE IS SET TO 100 FROM OUTSIDE THEN
NEGATIVE VALUES OF X ARE ALLOWED
IF (ABS(Y(NR))-TOL) 10,10,20
KODE=1
GO TO 100
IF (NR- 1) 90,90,30
IF (NR-NX) 50,40,40
KODE=2
KER=KERNO
GO TO 100
IF (ABS(Y(NR)/Y(NR-1)-1
)-1.E-8) 53,53,54
o
00
X(NR+1 )=(X(NR)+X(NR-1 ) )*.5
GO TO 1000
X(NR+1)=X(NR)-Y(NR)*(X(NR)-X(NR-1))/(Y(NR)-Y(NR-1))
IF(NR-3)66, 55.55
J1=0
Y1=-1 ,
E6
Y2 = + 1.E6
DO 60 JJ=1,NR
IF (Y(JJ) ) 56,56,57
56 IF (Y(JJJ-Y1) 60,58,58
57 IF (Y(JJ)-Y2) 59,59,60
58 Y1= Y(JJ)
J1= JJ
GO TO 60
59 Y2= Y(JJ)
J2= JJ
60 CONTINUE
C *** SET LOK=1
LOK = 0
IF(Y(NR)-Y1+1.E-8)1250,1200,1200
1200 IF(Y(NR)-Y2-1.E-8)1275,1275,1250
1250 LOK=1
1275 CONTINUE
IF (J1 ) 66,66,61
61 IF (J2) 66,66,62
62 IF (X(NR+1 )-X(J1 | ) 64,65,63
C *** CHECKS MADE HERE TO DETERMINE IF NEW GUESS
C *** TWO PRIOR GUESSES WHICH WERE NEC. AND POS.
63 IF(X(NR+1)-X(J2) ) 1100,65,65
64 IF(X(NR-H )-X(J2) 165,65,1100
C **+ IF NEW GUESS IS TOO CLOSE TO PRIOR
C *** OF NEWTON-RAPHESON EQ. AT 66 BELOW
1100 IF(ABS(X(NR+1)/X(NR)-1 .0)-TOL*0. 1 ) 1 1 1 0 , 1 1 1 0 , 66
1110 IF(ABS(X(NR)/X(NR-1)-1.0)-TOL*0.1)1120,1120,66
WHEN THE Y RETURNED IS NO LONGER BETWEEN Yt AND Y2
IS BETWEEN THE BEST
GUESS THEN USE AVG. INSTEAD
48880
48890
48900
48910
48920
48930
48940
48950
489GO
48970
48980
48990
49000
49010
49020
49030
49040
40050
49060
49070
49080
49090
491 00
491 10
49120
491 30
49140
491 50
491 60
491 70
491 80
491 90
49200
49210
49220
49230
49240
49250
49260
49270
49280
49290
49300
49310
49320
49330
49340
49350
49360
49370
-------
I
I—I
o
c ** -
1 120
C * * *
c * * *
65
66
67
70
C ** *
80
82
84
90
100
TWO GUESSES
, ERRORS
.5
WHICH PRODUCED THE
IF GUESSES ARE TOO CLOSE AND LOK=1 THEN ASSUME CONVERGENCE
IF(LOK-1 )65,10,10
EQ. BELOW USES AVG. OF
CLOSEST NEG. AND POSIT.
X(NR-M )=(X(J1 )+X(J2))*.
IF (KODE-100) 67,80,67
IF (X(NR+1) ) 70,70,80
X(NR+1)=X(NR)*.5
SKIP CHECK IF X(NR-1) IS ZERO
IF(ABS(X(NR-1))-1.£-20)90,90,82
IF(ABS(X(NR)/X(NR-1)-1.0)-TOL*1
KODE=3
GO TO 46
KODE=0
NR=NR+1
RETURN
END
.E-6)84,84,90
493RO
19390
49400
494 10
49420
49430
49440
49450
49460
49470
49480
49490
49500
49510
49520
49530
49540
SUBROUTINE OCONV{KODE,KODE1)
c *** OUTPUT UNIT CONVERSION
C **' KODE=1 CONVERT FROM INTERNAL
C *** KODE=2 CONVERT FROM
C *** KODE=3 CONVERT FROM
C *** KODE=4 CONVERT FROM
COMMON IDUM(6|,RDUM(3
IF(K3DE-2(100,100,300
C *** INTERNAL TO U.S.
100 DUr,1W( 86) =DUMW(86 ) *27. 73
DUMWI79)=DUMd(79)*27.73
DO 110 LL=149,155
110 DUMW(LL)=DUMW(LL)*1.E-3
DUMW(151)=DUMW(151)+1.E3
DO 120 LL=101,102
120 DUMW( LL)=DUMW( LL)*1.E~6
DO 130 LL=108,124
130 DUMWI LL)=TCONV(DUMW(LL),1,2)
GO TO 900
C *** U.S. TO INTERNAL
300 DUMW(86)=DUMW(861/27.73
DUMW(79)=DUMW(79)/27.73
DO 310 LL=149,155
310 DUMW(LL)=DUMW(LL)* 1.E3
TO U.S. UNITS
INTERNAL TO S.I. UNITS
U.S. TO INTERNAL UNITS
S.I. TO INTERNAL UNITS
,IDUMW(34),DUMW(246),DUMYD(60),DUM(912)
49550
49560
49570
49580
495'JO
49600
49610
49620
49630
49640
49650
49660
49670
4M6HQ
4 9 () J 0
4^700
4971 0
49720
49730
49740
49750
49760
49770
49780
-------
DUMW(151)=DUMW(151)*1.E-3
DO 320 LL=101,102
320 DUMW( LL)=DUMW( LL)/1.E-6
DO 330 LL=108,124
330 DUMW( LL)=TCONV(DUMW(LL),1,1)
GO TO 900
900 RETURN
END
49790
49800
4981 0
49820
49830
49840
49850
49860
I
i—•
i—'
O
SUBROUTINE OUTFA (KOT,KOT1) 49870
C *** FINAL PRINTOUT (PART-1) 49880
DIMENSION UUTEM(2,2),UUMF(3,2),UUPRA(2,2),UUPR(2,2),UUDRT(2,3), 49890
1UUDIR(3,3),ISIZE(3),BARR(3) 49900
COMMON NFO,KGO,KNTRO,KNTR1,NM,NPAGE,DAY(2),PI 49910
COMMON KCI,KER,KERR(20),KFIN,KREG,LAIC,LSUP.MM,NP,NR,NT1,NT2,NTP, 49920
1NTR,NTT,ABARE,AFAN.AMIN,APLOT,APPR, ASBUN.ASTOT,AXAV,AXPP(20) ,CP(2) 49930
2,DEN(2),DEN12(2,2),DENFN,DENLZ(7),DBW,DEO,DFH,OFR,DFS,DFT,DKL, 49940
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT 49950
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT,Df'TA.DPTF, 49960
1DPTOT(2),POUT(2),PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTOT, 49970
20(2),QDUT.QTOT,RFI,RFIN,RFTOT,RTOT,RTW.TAV(2),TIN(2),TOUT(2),TT(8) 49980
3,TWALL,TD.TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,VlSLZ(7)r 49990
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLQ(2) 50000
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC,F, 50010
1FALT,FINEF,FFF,FSUM,OCL(4),ODL(4),OKL(4),OML(4),OMV(4),P,PRAN(2), 50020
2PRAL2(7),R,RAOI,RAOR,RARAF,RAPMX.REA(2),RE12(2,2),RFNPL,RPT,TLA, 50030
3XREX.ZMP.ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20),ZTPPA 50040
COMMON ZTRD,ANGI,ZBYP,ZBUP,ZBUS.ZFAN,DFANl, DLOV,ZNFI.PTI.TKT.TKF, 50050
1WD(2),VAPPI,TAIVIB,HALT,C3191TIND(2),TOUTD(2),RFD,PSD,TTMIN,OD(7), 50060
2CARD7(6),DNZI(2) ,PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFA IR,RFCT,ZNOZ(2) , 50070
3RASPC,ZTPD,2NrD,COST(7) ,SSUM(16,30) , ISUM(13,30) , PR ICE(2,21 ) 50080
COMMON/CASED/BARB(13) 50090
C *** DATA FOR OUTPUT ALPHANUMERIC INFO. 50100
DATA UUTEM/4H(DEG,4H.F) ,4H(DEG,4H.C) /, 50110
3 UUMF/3H(M-,3HLB/,3HHR),3H ,3H(KG,3H/S)/, UUPRA/3H(PS,3HI A), 50120
43H(K-,3HPA)/,UUPR/3H (P,3HSI),3H(K-,3HPA)/ 50130
DATA UUDRT/4H FOR,3HCED,4HINDU,3HCED,4HNATU,3HRAL/, 50140
1 UUDIR /2HHa,4HRIZa,4HNTAL,2H ,4HINCL,4HINED,2H ,4HVERT,4HICAL/, 50150
1BARR/4HCOND.4HEN.W.4HATER/ 501 60
1100 FORMAT(72H1** PRINTOUT OF OPTIMUM DESIGN GENERATED BY THE PFR OPTI 50170
1MIZATION PROGRAM,/) 50180
1105 FORMAT(4H ,17(4H )) 50190
-------
1110 FORMAT( 8H 1 SIZE , I 3, 1H-,I 4, 1H-, I 2, 1H-,A 2 , 2A4, 1X,A4,A3 , 50200
15H N3U=,I3,6H I ,4A5,/,25H 2 SURFACE/UNIT EXT/BARE , F1 1 . 0 , 1H/, 50210
2F9.0.11H I SITE , 3A5,/,25H 3 HEAT EXCHANGED / 'vl T D ,F11.4, 50220
31H/,F6.2.3X,11H I TURBINE ,3A5,/,25H 4 RATE EXT/BARE/CLEAN , 50230
4r:7.2, 1H/, F6.2, 1H/, F6.2, 1 1H I CONDENSR , 3A5 ) 50240
1120 FORMAT(47H ** TUBE SIDE +* ** PROCESS AND PERFORMANCE, 50250
117H DATA PER UNIT *t,/,20H 5 FLUID CIRCULATED,8X,3A4 , 1 OX, 50260
222HENTERING LEAVING,/, 15H 6 TOTAL FLUID, 15X,3 A3 , F19.3 , /, 50270
312H 7 LIQUID,18X,3A3,5X,2F14.3) 50280
1130 FORMAT(15H 8 TEMPERATURE,17X,2A4,4X,2(5X,F9.1),/, 50?90
133H 9 PRESSURE , 2A3,11X , F8 . 1 , F14. 1 ,/, 50300
233H 10 PRESSURE DROP SPEC./CALC. ,2A3,12X,F7.2,1H .F13.2,/, 50310
32H -,35(2H—)) 50320
KFI=2 50330
NBUT=ZBUS*ZBUP*ZBYP+O.01 50340
IF (ANG(1)-0.27) 4,5,5 50350
4 KANG=1 503'.0
GO TO 8 50370
5 IF (AMG(1)-1.47) 6,6,7 • 503UO
6 KANG=2 50390
GO TO 8 50400
7 KANG=3 50410
8 CONTINUE 50420
ISIZEl 1 ) = (DBW+4.0 1/12.0 + 0.5 50430
ISIZE(2)=NTT 50440
ISIZE(3)=NTR 50450
220 CONTINUE 504GO
400 WPITE(NFO,1100) 50470
WRITE(NFO,1105) 50480
WRITE!NFO, 1 1 10) ( I SIZE( I) ,I = 1 ,3) ,(UUDIR( I ,KANG) , I = 1 ,3) , 50490
1 (UUDRT(I ,KFI ) ,1 = 1 ,2),NBUT,(BARB(I) , 1 = 1 ,4) , ASTOT , ABARE , 50500
2(BARB(I),I=5,7),QDUT,TMTD,(BARB(I),I=8,10),UTOT,UBARE,UCLN, 50510
3(BARB!I),1=11,13) 50520
WRITE!NFO,1105) 50530
WRITE (NFO, 1 120)(BARR( I ) ,1 = 1 ,3) , ( ULJMF ( I , KOT ) ,I = 1.3),W(1), 50540
1 (UUMF( I ,KOT) ,1 = 1 ,3),WLO(1),WLO(2) 50550
WRITE(NFO, 1130){UUTEM(I,KOT) ,I = 1,2),TIN(1) , TOUT(1 ), 50560
1(UUPRA(I,KOT),I=1,2),PTUB,POUT(1),(UUPR(I,KOT),I=1,2),PSD,DPTOT(1) 50570
500 RETURN 50580
END 50590
-------
I
I—•
I—•
CO
SUBROUTINE OUTFB IKOT.KQT1)
C **+ FINAL PRINTOUT (PART-2)
DIMENSION AOUT1(5,2),AOUT2(5,2)
DIMENSION UUAR(2,2),UUTEM(2,2) ,UUPR(2,2) ,UUAFR(2 , 2 ) .
1 UUDP(2 2) ,UUSV(2,2) ,UUL1(2) ,UUL2(2) ,UUFLX(3,2) ,UUMF(3,2),
2UUPWR(2,2),UUHDR(2,5),UULAY(2,2),UUTUB(2,21,UUL3(2),UUFIN(2,3),
3UOTYP(3,3)
COMMON NFO,KGO,KNTRO.KNTR1,NSUM,NPAGE,DAr'(2),PI
COMMON KCI ,KER,KERR(20) ,KFIN,KREG, LAIC,LSUP,MM,NP,NR,NT1 .NT2.NTP,
1NTR,NTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV, AXPP(20) ,CP(2)
2,DEN(2),DEN12(2,2) , DENFN,DENLZ(7) .DBW.DEQ.DFH.DFR.DFS.DFT.DKL,
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT,DPTA,DPTF,
1DPTOT(2) POUT(2),PTUB,RV2,GA',lAX,GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTaT,
2Q(2) .QDUT.QTOT.RFI,RFIN,RFTOT,RTOT,RTW,TA V(2} ,TIN(2) ,TOUT(2) .TT(8)
3,TWAIL,TD,TW,TMTD,TM2) ,VAPP,VN2(2) , VT , DF AN , TLT E , AOF , V I SLZ ( 7 ) ,
4VISf2),VIS12(2,2),VISW,W(2),WAPF,W3(2),WLQ(2)
COMMON ANG(3),CFH(3),CFP(3),CFR.CKBSC,CKFNG,CKHSC,CKLOV,CKSTC.F.
1FALT,FINEF,FFF,FSUM,OCL(4) ,ODL(4) ,OKL(4) ,OML(4) ,OMV(4) ,P,PRAN(2) ,
2FRALZI7),R,RAOI.RAOR,RARAF,RAPMX,REA(2),RE 12(2,2) ,RFNPL,RPT,TLA,
3XREX,ZMP,ZNF,ZNTP.ZNTR.ZNTT,ZTPP(20),ZTPPA
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV,ZNFI,PTI.TKT,TKF,
1WD(2),VAPPl,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,QD(7),
2CARD7(6) DNZI(2),PDI,CFNG,CHSC,CLOV,CB5C,PR5TC,RFAIR,RFCT,ZNOZ(2),
3RASPC.ZTPD,ZNTD,COST(7),SSUM(16,30) , I SUM(13,30) ,PR 1CE(2,21 )
COMMON/FAN/EFFAN.NBLAD.HPMSP
*** DATA
DATA
1
2
3
DATA
FOR OUTPUT
AOUT1/4H
4H
AOUT2/4H
4H
UUAR/3H(FT
ALPHANUMERIC
S.4HTATI,4HC
D , 4HRAFT,4H
S.4HTATI,
D.4HRAFT,
,2H2),3H
,4HALC.
,4HQD.
,4HPEC.
.4HAIL.
3H
INFO.
D. ,4HP. ,C
HEA.4HD.RE
4HC D.,4HP.,S
4H HEA.4HD.AV
M.2H2)/,
1 UUTEM/4H(DEG.4H.F) ,4H(DEG,4H.C) /,
2UUAFR/3H(AC,3HFM),3H(M3,3H/S)/,
4 UUPR/3H (P.3HSI),3H(K-,3HPA)/,UUMF/3H(M-,3HLB/,3HHR)
5 3H/S)/
DATA UUDP/4H(IN-,4HH20),4H(K-P,4HA) /, UUSV/3H(SF,3HPM)
1 3H (M.3H/S)/, UUL1/4H(FT),4H (M)/, UUL2/4H(IN) , 4H(MM ) /,
2 UUFLX/4H (LB,4H/HR-,4HFT2),4H (,4HKG/S,4H-M2)/,
3UUPWR/3H (H.3HP) ,
4 3H (K.3HW) /, UUL3/3HIN.,3H M./
DATA UUHDR/4H ,4HPLUG,4H C,4HOVER,4H B0.4HNNET
1.4HMANI.4HFOLD/, UULAY/4HSTAG,4HGERD,4H IN-,4HLINE/,
24HLAIN.4H FI.4HNNED/,
4H SLO,4HTTED,4HSERR,4HATED/,
4HIGHT.4H ,4H U-,4HTUBE,4H
,3H(KG,
3 UUFIN/ 4H SM.4HOOTH,
4 UOTYP /4H .4HSTRA,
5 4HRPEN.4HTINE/
1170 FORMAT(23HO** PROGRAM
4HWELD.4H-BOX
UUTUB/4H P,
SE,
MESSAGES - ,10(13,1H,))
1175 FORMATM5H ** AIR SIDE **,/,13H 11 AIR/UNIT , 3A3 , F1 1 . 2 , 8H TEMP.
110H IN/OUT .2A4.F6.1 .1H/.F6.1 ,/,11H 12 A IR/FAN,5X,2A3,F11 .2,
50600
50610
50620
50630
50640
50G50
50660
50670
50600
50690
50700
50710
50720
50730
50740
50750
50760
50770
50780
50790
50800
50810
50820
50830
50840
50B50
50860
50870
50880
50890
50900
50910
50920
50930
50940
50950
50960
50970
50980
50990
51000
51 010
51 020
51 030
51040
51050
51 060
51070
51 080
51090
-------
212H ALTITUDE ,9X , A4,7X,F7.0./,16H 13 FACF. VEL ,2 A3,F11 .3,5A4, 51100
32X,2A4,F9.4,/,10H 14 MASS V,3A4,F1 1 .3,5A4,2X,2A4,F9.4 ) 51110
1176 FORMAT (2H -,35(2H—)) 51120
1180 FORMAT(54H ** CONSTRUCTION INFO. PER BUNDLE DESIGN PRESSURE , 51130
1 2A3, F1 2. 1 , / , 18H 15 BUNDLE WIDTH , A4 ,-SX , F 7 . 2 , 1 OH NO. TUF3E ROWS 51140
2,I3,15H TUBE PASSES ,I3,/,22H 16 NO. BUNDLES PARA ,12,7H SERIES 51150
3,I2t27H TUBE INCLINATION (DEC.),3X,F9.1,/,16H 17 NO. BAYS , 51160
45HPARA ,13,7H SER I ES,12,14H HEADER TYPE , 17X,2A4 ) 51170
1190 FDRMAT(/,31H ** TUBE AND FIN INFORMATION **,/,14H 18 MO. TUBES/, 51180
16HBUNDLE.7X,16,12H TUBE TYPE , 3X,3A4.4X,2A4,/, 14H 19 TUBE OD/ID, 51190
23X,A4,F6.3,1H/,F5.3,14H TUBE LAYOUT,F5- 0,8H DEGREES,4X,2A4 ,/, 51200
317H 20 FIN OD/THICK ,A4 , F6.3,1H/,F5.3,23H PITCH- TRANSVERSE , 51210
4A4,F12.4,/,18H 21 NO. FINS PER ,A3,5X,F7.2,8X,15H- LONG1TUD. , 51220
5A4,F12.4) 51230
2000 FORMAT(21H 22 TUBE LENGTH-OVRL ,A4,F8.3,17H FINNING FACTOR,F22.3 51240
1./.3H 23,12X,6H-EFF. ,A4,F8.3,14H FIN SURFACE,17X,2A4,/,4H 24 , 51250
217HTUBE SHEET THICK.,A4,F8.1,23H TOTAL SPACER LENGTH ,A4,F12.1) 51260
2010 FORMAT!/,20H +* FAN EQUIPMENT **,/,16H 25 NO. FANS/BAY,14X,I 3, 51270
118H POWER/FAN, (EFF=,F3.2,1H) ,2A3,F11 .2,/, 16H 26 FAN DIAMETER,5X, 51280
2A4,F8.3,22H POWER/FAN,SPEC. ,2A3,F11.2,/,16H 27 AREA RATIO- , 51290
311H FAN/FACE,F6.3,12H PLOT AREA,1 OX,A3,A2,F12.2,/,9H 28 AREA , 51300
418HRATIO- X-SECT/FACE,F6.3.15H ASPECT RATIO,F24.3) 51310
KHED=1 51320
KFIN=2 51330
KCTL=1 51340
KCBU=1 51350
DPI=0.0 51360
XAOF=(DBW+4.0)/12.0 51370
NFAN=ZFAN+0.01 51300
NBUP=ZBUP+0.01 51390
NBUS = ZBUS4-0 . 01 51400
NBYP = ZBYP-l-0 . 01 51410
C *** FOR NOW SET NUMBER OF BAYS IN SERIES EQUAL TO 1 51420
N3YS=1 51430
KFINS=1 51440
KNAT=1 51450
200 WRITE!NFO,1175)(UUMF(I , KOT ) ,I = 1,3),W(2),lUUTEIVI(l,KOT),I = 1,2), 51460
1 TIN(2),TOUT(2),(UUAFR(I ,KOT) , I = 1 ,2) ,WAPF,UUL1 (KOT) , V ISLZ(2 ) , 51470
2 (UUSV(I,KOT),I = 1,2),VAPP,(AOUT1(K,KNAT),K = 1,5), (UUDPl I ,KQT ) ,1 = 1 ,2 514HO
3),DPTOT(2),(UUFLX(I ,KOT ) ,1 = 1 ,3) ,GAMAX, (AOUT2(K,KNAT) ,K = 1 ,5) , 51490
4 (UUDP(I,KOT),1=1,2),DPI 51500
WRITE!NFO,1176) 51510
WRITE!NFO,1180)(UUPR(I,KOT),I=1,2),DPTA,UUL1(KOT),XAOF,NTR,NTP, 51520
1NBUP,NBUS,ANGI,NBYP,NBYS,(UUHDR(I,KHED),I=1,2) 51530
WRITE(NFO, 1 190)NTT, (UOTYP(I,KCBU),I=1,3),(UUTUB(I,KFIN),I=1,2), 51540
1UUL2(KOT),DTO,DTIM,TLA, 51550
1 (UULAY(I.KCTL) ,1 = 1 ,2) ,UUL2(KOT) ,DTF,DFT,UUL2(KOT) ,PT,UUL3(KOT) , 51560
2ZNF,UUL2(KOT),PL 51570
WRITE(NFO,2000) UUL1(KOT) , V ISLZ(1 ) ,RAQR, UUL1 (KOT),TLTE, 51580
1(UUFIN(I.KFINS),1=1,2),UUL2(KOT),DLTS,UUL2(KOT),DLSP 51590
-------
WRITE(NFO,2010)NFAN,EFFAN,(UUPWR(I,KOT),I=1,2),HPFNC,UUL1(KOT), 51600
1DFAN,(UUPWR(I,KOT) , 1 = 1 ,2),HPMSP ,RFNPL,(UUAR(I,HOT),1 = 1.2),APLOT 51610
2.RAPMX.RASPC 51620
430 IF(MM)490,490,440 51630
440 WRITE (NF0.1170) (KERR(I),I=1,MM) 51640
C *** STORE VALUES FOR SUMMARY OUTPUT 51650
490 CONTINUE 51660
IF (KGO-1) 550,550,510 51670
510 ISUM(01,NSUM)=99 51680
X=MM 51690
M=AMIN1(10.0.X) 51700
ISUM(02,NSUM)=M 51710
DO 520 1 = 1 ,M 51720
520 ISUM(I+2,NSUM)=KERR(I) 51730
550 CONTINUE 51740
NPAGE=NPAGE+1 51750
RETURN 51760
END 51770
SUBROUTINE OUTPE 51780
C *** ROUTINE CALCULATES THE COMMON VARIABLES NECESSARY FOP OUTPUT 51790
COMMON NFO,KGO.KNTRO.KNTR1,NSUM,NPAGE,DAV(2),PI 51800
COMMON KCI,KER,KERR(20),KFIN,KREG,LAIC,LSUP,MM,NP,NR,NT1,NT2,NTP, 51810
1NTR,NTT,ABARE,AFAN,AMIN,APLQT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 5I820
2,DEN(2),DEN12(2,2),DENFN,DENLZ(7),DBW,DEQ,DFH,DFR,DFS,DFT,DKL, 51830
3SP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT 51840
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT,DPTA,DPTF, 51850
1DPTOT(2),POUT(2),PTUB,RV2.GAMAX.GT,HPFNC.HAIR,HTS,UBAPE,UCLN,UTOT, 51860
2Q(2),QDUT,OTOT,RFI,RFIN.RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 51870
3.TWALL.TD,TW,TMTD,TK(2) ,VAPP,VNZ(2).VT,DFAN,TLTE,AOF,VISLZ(7), 51880
4VIS(2),V1S12(2,2),VISW,W(2),WAPF,WB(2),WI-Q(2) 51890
COMMON ANG(3),CFH(3).CFP(3),CFR,CKBSC,CKrNG.CKHSC,CKLOV,CKSTC,F, 51 900
1FALT,FINEFfFFF,FSUM,OCL(4),ODL(4),OKL(4),OML(4),OMV(4),P,PRAN(2), 51910
2PRALZ(7),R,RAOI,RAOR,RARAF,RAPMX1REA(2).RE12(2,2),RFNPL,RPT,TLA, 51920
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20),ZTPPA 51930
COMMON ZTRD,ANGI ,ZBYP,ZBUP,ZBUS,ZFAN,DFANI ,DLOV,'ZNF I . PT 1 , TKT , TKF , 51940
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,OD(7), 51950
2CARD7(6),DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC.RFAIR,RFCT,ZNOZ(2), 51960
3RASPC,ZTPD,ZNTD,CQST(7) ,SSUM(16,30) ,ISUM(13,30) ,PR ICE(2,21) 51970
COMMON/TRACE/SSSUM(9),IISUM(3) 51980
COMMON/PEN/ATTRf 20),DATTR(20) ,AMBTPT(20),BCAPC.NATTR,CAPCST,CMAIN, 51990
1MACC,AFCR2,XLVL,FLCST.CAPBS,PLDFT(20),STMCT,CUTMP,SHELP,BHTRT(6) 52000
-------
COMMON/FAN/EFFAN,NBLAD,HPMSP
COMMON/PIPE/XDIA(20),XLGT(20),NN1,NN2,XTOWR,PLNMH,TTTBH,VX,VN
1 , VAVE
COMMON/JUMP/JAKE,TINMX,NOD2I,DTN2I,NOQ1I,NFPIN,N0020,N0010
COMMON/CONTL/CSTOR,INML,D(13)
COVMON/JAN7/DUM(12),IDUM,DUM2(4),PDMAX.DUM3
ABARE=ASTOT/RAOR
IFIKNTR1.EO.O)GO TO 600
100 TLTE=DLTE/12.0
IF (KGO-2) 120,1 10,110
110 TMTD=0.0
UBARE=0.0
GO TO 500
120 CONTINUE
160 HT5=RAOI/(1.0/UTOT-(RTOT+RFIN+1.0/HAIR))
220 CONTINUE
280 UCLN=RAOR/(1.0/UTOT-RFTOT)
UBARE=UTOT*RAOR
XREX=(1 .O/FSUM-1 . 0)*100.0
J=1
DO 290 1=1,2
290 RE12(1..J)=REA(J)*VIS(J)/VIS12(I,J)
TT2=TOUT(1)
306 TWALL=TT2-UTOT*RAOI*(TT2-TIN(2))/HTS
308 TD=1.0/(1.0/HTS+0.5*(RTW-RFI))
DT1=TIN(1)-TOUT(2)
TO=TIN(1)-UTOT/TD*DT1
500 WLQI 1 )=W(1 )
WLO(2)=W(1)
600 CONTINUE
C *** SET UP VARIABLES AND CALL ACCOST FOR BUNDLE COST
NBPU=ZBYP+.01
NMOT=ZFAN+.01
DHEDW=DBW+4.
IF( (-1 )**NTP)710,710,720
DTN10=0.
GO TO 730
DTN10=DNZ(2)
CONTINUE
710
720
730
C
C * * *
c ***
C ***
c * * *
ASSUME VELOCITY ENTERING THE SIDES OF THE BUNDLE EQUALS VAPP
AND CALCULATE THE HEIGHT OF THE TOWER
XTOWR=W(2)/ZBYP/ZBUP*12./VAPP/DBW/60./.075
FIND 2 OF THE PIPE SIZES TO BE USED IN GEOM2
D(5) = SCJRT(W(1 )/OEN12(1 ,1 )/VX/19.635)
D(9)=D(5)/2.
SET PIPING ARRANGEMENT CODE FOR GEOM2
INML=1
IF(D(5) .GT.PDMAX)INML = 2
IF(((-1)**NTP).LT.O)INML=INML+2
52010
52020
52030
52010
52050
52060
52070
52080
52090
521 00
52 MO
521 20
52130
52140
52150
52160
521 70
52 180
52 190
52200
52210
52220
52230
52240
52250
52260
52270
52280
52290
52300
52310
52320
52330
52340
52350
52360
52370
52380
52390
52400
52410
52420
52430
52440
52450
52460
52470
52480
52490
52500
-------
C **+ ADD 1/2 OF SUPPLY LINE DIAMETER TO TOWER HEIGHT TO INSURE THAT
C *** PIPE DOES NOT SIGNIFICANTLY INTERFERE WITH AIR FLOW
IF(INML.GT.2)XTOWR=XTOWR+D(9)/24.
CALL ACCOST(DLTS,NTT,NTR,NTP,DTIM,DTO,NFPIN.PL,PTtDHEDW,DLOV,
1 DNZ(1),DTN10,N001I,NQOlO,DTN2I,DNZ(2),N002I,N0020,2BUP,2FAN,DFAN,
2 NBLAD.NMOT,HPFNC,NBPU,XTOWR,KNTR1 ,CTTOT,CSTOR,DFH,DFT )
PRICEI1,NSUM)=CTTOT*COST(2)
STOTS=PRICE(1,NSUM)
800 CONTINUE
IF(KNTR1.EQ.O)GO TO 850
C *** TRANSFORM INPUT DATA FOR UNIT CONVERSION
VISLZI2)=HALT
DPTA=PDI
APLOT=ZBYP*ZBUP*(DLOV+DNZ( 1 )* . 2 ) * ( DBW+4 . 0 ) / 1 2 . 0
C *** CORRECT THE PLOT AREA FOR THE INCLINATION OF THE TUBES
C ANG(3) IS THE COSINE(ANGI)
APLOT=APLOT*ANG(3)
850 CONTINUE
VISLZ(1)=DLOV
ISUM(09,NSUM)
ISUM( 1 0,
I SUM(12,
ISUM( I 3,
SSUM(03,
SSUM(04,
.01
.01
.01
,0)/12.0
ZFAN+0.
ZBYP+0.
NTT
DLOV+0.
(DBW+4.
DFAN
ABARE
ODUT*1
VAPP
HPFNC
TCONV(TOUT(1),1,2)
DPTOT(2)*27.73
DPTOT(1)
. E-6
,NSUM)
,NSUM)
,NSUM)
,NSUM)
,NSUM)
SSUM(05,NSUP/I)
SSUM(08,NSUM)
SSUM(1O.NSUM)
SSUM(11,NSUM)
SSUM(12,NSUM)
SSUM(15,NSUM)
SSUM(16,NSUM)
SSSUM(1)=ASTOT*1.E~03
S3SUM I2) = TCONV(TIN(1 ) , 1 ,2)
SSSUMf3)=VT
SSSUM(4)=W(1)*1.E-06
SS3UM(5)=TCONV(TIN(2),1,2)
SSSUM(6)=TCONV(TOUT(2),1,2)
SSSUP/K 7)=W(2) *1 . E-06
SSSUM(8)=STOTS
SSSUM(9)=TIN(1)-TIN(2)
SSUM(14,NSUM)=(SSSUM(2)-SSUM(12,NSUM))/SSSUM(9)
ISUM(5,NSUM)=SSSUM(5)-t-.49
ISUM(6,NSUM)=SSSUM(6)+.49
I SUM(3,NSUM)=VAPP+.49
ISUM(4,NSUM)=SSSUM(2)+.49
SSUM(1 ,NSUM)=VT
SSUM(2,NSUM)=SSSUM(4)
SSUM(9,NSUM)=SSSUM(7)
SSUM(7,NSUM)=SSSUM(9)
52510
52520
52530
52:>40
52550
52560
52570
52580
52590
52GOO
52610
52620
52630
52040
52650
52060
52670
52680
52690
52700
52710
52720
52730
52740
52750
52760
52770
52780
52790
52800
52810
52820
52830
52840
52850
52860
52870
52880
52890
52900
52910
52920
52930
52940
52950
52960
52970
52980
52990
53000
-------
RETURN
END
53010
53020
SUBROUTINE OUTPT
C *** CONTROLS THE FINAL AND SUMMARY OUTPUTS A'JD CALL OPTIM(IZER)
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DA«'(2).PI
COMMON KCI ,KER,KERR(20) , KFIN.KREG, LA 1C , LSL'P , MM , NP ,NR , NT 1 .NT2.NTP,
1NTR,MTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXFP|20),CP(2)
2,DEN(2).DEN12(2.2),DENFN,DENLZ(7),DBW,DE':.DFH.DrRlDFS,DFT,DKL,
3DLSP.DLTE,DLTO,DLTS,DriZ(2),DTI , DT I M , DT F , D TO , DT T , PL , P T
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,D-NZ(2),DPT,DPTA,DPTF,
1DPTOT(2),POUT(2),PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS.UBARE.UCLN.UTOT,
2QI2) ,ODUT,OTOT,RFI ,RFIN,RFTOT ,RTOT,RTW,TA V(2) , TIN(2) ,TOUT(2) ,TT(8)
3,TWALL,TD,TW,TMTD,TK(2) ,VAPP,VNZ(2) ,VT,DFAN,TLTE,AOF,V ISLZ(7),
4VIS(2t.VIS12(2,2),VISW,W(2),WAPF,WB(2),WLQ(2>
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC,F,
1FALT,FINEF,FFF,FSUM,OCL(4) ,ODL(4),OKL(4) ,OML(4) ,OMV ( 4)tP,PRAN(2),
2PRALZI7),R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(212),RFNPL,RPT,TLA,
3XREX.ZWP.ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20) ,ZTPPA
COMMON ZTRD.ANGI ,ZBYP,ZBUP,ZBUS,ZFAN,DFAN I,DLOV,ZNFI ,PTI ,TKT,TKF,
1WDI2) .VAPPI ,TAMB,HALT,C319,TIND(2) ,TOUTD(2),RFD,PSD,TTMIN,QD(7),
2CARD7I6) DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC.RFAIR,RFCT,ZNOZ(2),
3RA5Pc!zTPD,ZNTD.COST(7),SSUM(16,30) ,ISUM(13.30),PR 1CE(2,21 )
KOT=1
100
250
500
61 0
700
1000
6000
KOT1=KOT
CALL OCONV
CALL
CALL
CALL
CALL
(KOT, 1 )
(KOT,KOT1)
(KOT.KOT1)
(KOT+2, 1 )
OUTFA
OUTFB
OCONV
OWARN
CALL SECOND(TYM1)
TYMEL=TYM1-DAY(2)
DAY(2)=TYM1
WRITE!NFO,6000)TYMEL
CALL OUTSM
CONTINUE
RETURN
FORMAT(21HO*** CASE EXECUTED
END
IN,F8.2,5H SEC. )
53030
53040
53050
530GO
53070
53080
53090
53100
531 10
53120
53130
53140
531 50
531 60
53170
53100
53190
53200
53210
53220
53230
53240
53250
53200
53270
53280
53290
53300
53310
53320
53330
53340
53350
53360
53370
53380
-------
00
SUBROUTINE OUTPUT ( WTDUM , TTIN , TOUT , C LFAC , VMI N , VMAX , TLMI N , TLMAX , TSAT
1 , QDUM.CITEM.CNEW.NPAGE, DAY , DPMAX , T LM , DPTOT ,PSAT.PS1,PS2,KCOND1
1 KMETL ,MN, BWG,
2TS1 , TS2.TLM1 ,TLM2,U01 ,U02,TR1 ,TR2,FRAC,FRAC2,TIN2,PSMIN,PSMAX)
DIMENSION CNEW( 1 5) ,CITEM( 10, 15)
DIMENSION TUBEM( 13,2),SHETM(6,2)
DATA TUBEM/7H ADMI.7H ARSENI.7H ALUM.7H ALUM. ,7H ALUM. ,
,7H CARBON, 7H 410 ST.7H 304 ST,
,7HCAL CU .7HINUM .7HBRASS
.7HCU - NI.7H STEEL .7HAINLESS,
1 7H MUNTZ.
2 7H 316 ST.
3 7HBRONZE ,
4 7HAINLESS,
7H 90/10
7H TITA
7H METAL
7HAINLESS
DATA SHETM/7H MUNTZ
1 7H 90/10 ,7H METAL
2 7HCU - NI/
,7H 70/30
.7HRALTY
,7HCU - NI
,7HNIUM /
,7H CARBON,7H
304 ST.7H 316 ST.7H ALUM.
7H STEEL ,7HAINLESS,7HAINLESS,7HBRONZE
WCONV(W) = W/2.505
OCONV(Q1) = Q1/3-968
TCON(T)=(T-32.17)/1 .8
PCONV(P) = P * 0.03452
Q=QDUM/1.E6
WT=WTDUM/1.E6
WTS = 0/950.0
WT1 = WCONV(WT)
WTS1 = WCONV(WTS)
OC1 = QCONV(Q)
TC1=TCON(TTIN)
TC2=TCON(TOUT)
TC3=TCON(TSAT)
DP1 = PCONV(DPTOT)
PSAT1 = PCONV(PSAT)
PS11 = PCONV(PS1 )
PS21 = PCONV(PS2)
TLMC = TLM/1.8
WRITE(6,900)
WRITE(6,910)WTS,WTS1,TSAT,TC3,PSAT,PSAT1
IF(KCOND-2)150,100.150
100 WRITE(6,925)PS 1 ,TS1 ,U01 ,FRAC,TTIN,TR1 , TLM1 TPS2,TS2,U02,FRAC2,TIN2,
1TR2,TLM2
150 CONTINUE
WRITE(6.920)WT,WT1 ,TTIN,TC1 ,TOUT,TC2,0,QC1 ,TLM,TLMC,CLFAC
WRITE(6,930)VMIN,VMAX,DPMAX,TLMIN,TLMAX,PSMIN,PSMAX
WRITE(6,940)(SHETM(MN,I) ,1 = 1,2),(TUBEM(KMETL,I) ,1 = 1,2) ,BWG
DO 600 1 = 1 ,10
IF(CITEM(I,1).GT..99E30)GO TO 700
600 WRITE(6,950)CITEM(1,6),CITEM(I,4),CITEM(I,5),CITEM(I,3),CITEM(I,2)
1 ,CITEM(I,12),CITEM(I,10),CITEM(I,7),CITEM( I,9),CITEM(I , 11),
2CITEM(I,1) ,CITEM(I,8)
700 CONTINUE
900 FORMAT(36H1** SURFACE CONDENSER DESIGN ,/)
910 FORMAT(22HO»* STEAM CONDITIONS ,/,
1 22H TOTAL FLOW LEAVING,3X,F7.3,8H MMLB/HR,8X,F7.3,8H MMK
53390
53400
53410
53420
53430
53440
53450
53460
53470
53480
53490
53500
53510
53520
53530
53540
53550
535GO
53570
53580
53590
53600
53610
53620
53630
53640
53650
53660
53670
53680
53690
53700
53710
53720
53730
53740
53750
53760
53770
53780
53790
53800
5381 0
53820
53830
53840
53850
53860
53870
53880
-------
2G/HR./.26H SATURATION TEMP.
3.C,/, 26H SATURATION PRESSURE
4CM2,/ )
920 FORMAT(32HO** CIRCULATING WATER CONDITIONS,/,
1 15H FLOW RATE ,10X, F7.3, 8H MMLB/HR,8X,F7.3,8H MMKG/
2HR,/, 26H TEMP.ENTERING
3.C,/, 26H TEMP.LEAVING
4.C,///,26H ** OVERALL PERFORMANCE
,F6.2,6H DEC.F,11X.F6.2,GH DEG
,F6.2,6H IN HG,1 1X , F6.2,7H KG/
.F6.2.6H DEG.F,11X,F6.2,6H DEG
,F6.2,6H DEG.F,11X,F6.2,6H DEG
HEAT DUTY ,8X,
F9.3.10H MMBTU/HR ,5X,F8.3,10H MM
5 15H
6KCAL/HR,/,
7 26H MEAN TEMP.DIFF. .F6.2.6H DEG.F,11X,F6.2,6H DEG
8.C./, 22H CLEANINESS FACTOR , 21X , F5.3,//)
925 FORMAT(26HO** MULTI PRESSURE DESIGN ,/,
SATURATION OVER.
PRESS. TEMP.
1
56H
, 62H
LMTD,/,
10H
10H
COEFF.
FRAC.
DUTY
INLET
TEMP.
TEMP.
RANGE
ZONE 1,F8.2,F8.1,F8.2.F6.2,2F8.1.F7.1,/,
930 FORMAT(67HO** DESIGN RESTRAINTS
1AXIMUM
2 29H
3 31H
4 1 9H
5 30H
ZONE 2,F8.2,F8.1,F8.2,F6.2,2F8.1,F7.1
MINIMUM
//)
TUBE SIDE VELOCITY FT/SEC,4X,F6.2,17X,F6.2,/,
TUBE SIDE PRESSURE DROP PS I ,25X,F6.2,/ ,
TUBE LENGTH FT.,14X,F6.2,17X,F6.2,/,
SATURATION PRESSURE, IN HG , -IX , F5 . 2 , 1 8X , F5 . 2 , // )
940 FQRMAT(25HO** DESIGN PARAMETERS , / , 19H PLATE MATERIAL ,2A7,
1/.19H TUBE MATERIAL ,2A7,/,19H TUBE GAUGE .F14.0,//,
1 56H DESIGN TUBE INFORMATION NO.OF NO.OF TUBE SIDE
TOTAL COST.11H
2,
3
4,
5
6,
26H
56H
26H.
56H
26H
OVERALL
NO.
COEFF.
SERVICE
ESTIMATED,/,
O.D LENGTH NUMBER TUBE SHELL
SURFACE M-$ ,11H TOTAL ,/,
PRESS VELOC
AREA
PASSES SER. DROP
,14H WEIGHT(TONS))
950 FORMAT(F7.0,F7.3,F7.1,F9.0,F7.0,F6.0,F7.3,F6.1,F10.3,F11.1,F7.0,
1F9.0)
RETURN
END
53890
53900
53910
53920
53930
53940
53950
53960
53970
53930
53990
54000
5401 0
54020
54030
540-10
54050
540GO
54070
54080
54090
541 00
541 10
54 1 20
54130
54 1 40
54150
54160
54170
54180
54190
54200
54210
54220
54230
54240
-------
SUBROUTINE OUTSM 54250
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2).PI 54260
COMMON KCI,KER.KERP(20),KFIN,KREG,LAIC,LSUP . f.'M , MP , NR , NT 1 , NT2 , NTP , 54270
1NTR,NTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 54280
2,DEN(2),DEN12(2,2) . DENFN,DENLZ(7) .DBW.DEQ.DFH.DFR.DFS.DFT.DKL. 54290
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF.OTQ,DTT,PL,PT 54300
COMMON DP AD , DPAF , DP AM . DRAW , DP F (10),DPI,DPNZ(2),DPT,DPTA,DPTF, 54310
1DPTOT(2),POUT(2),PTUB,RV2.GAMAX.GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTOT, 54320
20(21 ,QDUT.QTOT.RFI ,RFIN,RFTOT,RTOT,RTW,TAV(2),T1N(2) ,TOUT(2!,TT(8) 54330
3,TWALL,TD.TW,TMTD,TK(2).VAPP,VNZ(2),VT,DFAN,TLTE,AOF,V1SLZ(7), 54340
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WBl2),WLO(2) 54350
COMMON ANGCSJ.CFHOJ.CFPOJ.CFR.CKBSC.CKFNG.CKHSC.CKLOV.CKSTC.F, 54360
1FALT,FINEF,FFF,FSUM.OCL(4),ODL(4),OKL(4),Or(-L(4) . CMV ( 4 ),P,PRAN(2), 54370
2PRALZ<7),R,RAai,RAOR,RARAF,RAPMX,REA(2),F
-------
411H FUEL
547HFUEL COND. RECVRY SUB- DURING PER TOTAL,/,5X,
511HCOST 0+M,
655H COST PEN. PEN.
726HSTAT. CONSTR KWH
COST COST
COST,/,1X,97(1H-)
COST
TURB.
2030 FORrvlAT(ix.I2.5F7.1,F10.1,5F7.1,F7.3,F8.1)
IF (NSUM) 1000,1000,350
350 KOT=1
WRITEINFO, 25)
600 WRITE(NFO, 200)
DUM = 0
DO 30
J=1
30
i
i—>
ro
, SSUM(14.K),SSUM(7,K) ,SSUM(15,K) ,SSUM(16.K)
NATTR
J)*DATTR( J)
000 . *BCAPC
WRITE! NFO, 220)
DO 640 K=1 ,NSUM
WRITEINFQ,240)K, ISUM( 10,K),ISUM(9,K), (SSUM( I,K).I=3,5),
1 ( I SUM! I, K), 1 = 12, 13) ,ISUM(4,K) , SSUM( 12,K) , (SSUM( I. K), 1 = 1, 2).
2( ISUMI I ,K) , 1=5.6) . ISUM(3,K) ,SSUM(9,K)
640 CONTINUE
WRITE(NFO, 260)
DO 680 K=1 .NSUM
WRITE(NFO,280)K.SSUM(8,K),TISUM(K) ,SSUM(6,K) , SSUM( 1 1 , K ) , I SUM( 1 1 , K )
1 ,ISUM( 2,K ) ,
2 ISUMI7.K) ,SSUM( 13,K) ,
680 CONTINUE
NPAGE=NPAGE+1
OUTPUT COST OF AIR COOLER - AREA«COST ( 1 ) +HP*COST ( 2 ) =TOT A L
WRITE(NFO,2000)
WRITE(NFO,2010)
DO 930 K = 1 , NSUM
CHP=PRICE( 2,K)*1
CSA=PRICE( 1 ,K)*1
DUM1 =\PRIC(4,K)*1000. /DUM
DO 925 1=1 ,12
CA( I )=XPRIC( I ,K) + 1 .E-3
WRITE(NFO,2030)K,CSA,CHP,(CA(I),I=1 ,3) ,CA( 12) ,CA(5)
1 (CA( I ) , 1=7 , 10) ,OUM1 ,CA(4)
930 CONTINUE
WR I TE( NFO. 1 100)
DO 1 900 K=1 , NATTR
IF(K.EQ.7)WRITE(NFO,2000)
WRITE(NFO,1200)ATTR(K),PLDFT(K)
WRITE (NFO, 1300) (ZLOAD(K, I ) , 1=1 ,NSUM)
DO 1800 1=1 ,NSUM
AUXMW( K, I ) =AUXMW( K , I )*1 . E-03
TURMW( K, I )=TURMW( K , I )*1 . E-03
1800 CONTINUE
WRITE( NFO, 1400) ( AUXMW(K, I ) , 1=1 ,NSUM)
WRITE (NFO, 1 500) (TURMWfK, I) , 1=1 ,NSUM)
800
**+
910
920
925
. E-3
.E-3
54750
54760
54770
547BO
54790
54800
54810
54820
54830
54840
54850
54660
54870
54880
54890
54900
54910
54920
54930
54940
54950
54960
54970
54980
54990
55000
55010
55020
55030
55040
55050
55060
55070
55080
55090
55 1 00
551 10
551 20
55130
55140
55150
55160
55 170
551 80
551 90
55200
55210
55220
55230
55240
-------
1900 CONTINUE 55250
1100 FORMAT(///,52H **• OFF DESIGN PERFORMANCE OF THE OPTIMIZED DESIGNS 55260
1.19H IN THE BOX COMPLEX,/,37H TURBINE FIRING RATE.MW,AND AUXILIARY 55270
2.34H MW ARE GIVEN FOR EACH AMBIENT ***,/) 55280
1200 FORMAT(/,7H TAMB=,F6.1.16H DEMANDED LOAD=,F6.3) 55290
1300 FORMAT(6H LOAD .21F6.3) 55300
1400 FORMAT(6H A. MW.21F6.1) 55310
MW.21F6.0) 55320
55330
55340
55350
1500 FORMAT(6H T
1000 NSUM=0
RETURN
END
ro
ro
SUBROUTINE OWARN 55360
C *«* PRINT OUT WARNING AND ERROR MESSAGES 55370
DIMENSION IWARN(20) 55380
COMMON NFO.KGO,KNTRO,KNTR1,NSUM,NPAGE,DAV(2),PI 55390
COMMON KCI,KER.KERR(20) ,KFIN.KREG, LA 1C , LSUP , t,VJ\, NIP , NR , NT 1 .NT2.NTP, 55400
1NTR.NTT.ABARE,AFAN,AMIN,APLOT.APPR,ASBUN,ASTOT,AXAV.AXPP(20),CP(2) 55410
2,DEN(2).DEN 12(2.2 I,DENFN.DENLZ(7),DBW,DEQ,DFH,DFR,DFS,OFT,DKL, 55420
3DLSD,DLTE.DLTO.DLTS,DNZ(2).DTI,DTIM,DTP,DTO.DTT.PL,PT 55430
COMMON DPAD.DPAF , DPAM , DP AW , DPF ( 10),DPI,D(1'JZ(2),DPT,DPTA.DPTF, 55440
1DPTOT(2),POUT(2),PTUB,RV2,GAMAX.GT,HPFNC,HA IR,NTS,U6ARE,UCLN,UTOT, 55450
20(2),QDUT.QTOT.RFI,RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 55460
3,TWALL,TD,TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,V1SLZ(7|, 55470
4VIS(2),ViSl2(2.2),VISWfW(2),WAPF,WB(2),WLC/<2) 55480
COMMON ANG(3),CFHI3),CFP(3),CFR.CKBSC,CKFNG,CKHSC,CKLOV.CKSTC,F, 55490
1FALT,F1NEF,FFF,FSUM,OCL(4),ODL(4),OKL(4),OML(4),OMV(4).P,PRAN(2), 55500
2PRALZ(7).R.RAOI.RAOR,RARAF.RAPMX,RE A(2),RE12(2,2),RFNPL,RPT,TLA, 55510
3XREX,Zr,'P,ZNF.ZNTP,ZNTR,ZNTT,ZTPP(20 ),ZTPPA 55520
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI.DLOV.ZNFI,PTI,TKT,TKF, 55530
1WD(2),VAPPI.TAMB,HALT,C319,TIND(2J,TOUTD(2),RFD,PSD,TTMIN,QD(7), 55540
2CARD7(6),DNZI<2) ,PDI,CFNG.CHSC,CLOV.CBSC,PRSTC,RFAIR, RFCT.ZNOZ(2) , 55550
3RASPC,ZTPD.ZNTD.COST(7),SSUM(16.30),I SUM(13,30),PR ICE(2,21 ) 55560
1000 FORMAT(1H1) 55570
1001 FORMAT(4H ***.17(4H****)) 55580
1002 FORMAT<20H I WARNING MESSAGES,/4H I ,4(4H ),/2H I) 55590
1003 FORMAT(55H I MINOR CALCULATION ERRORS / PROGRAM EXECUTION CONTIN, 55600
1 3HUES/2H I/47H I NO. S/R ERROR DESCRIPTION / ACTION TAKEN ./ 55610
2 13H I ,2X.B(4H ),/2H I) 55620
1004 FORMAT(54H I MAJOR CALCULATION ERRORS / PROGRAM EXECUTION STOPS. 55630
1 /2H I/51H I NO. S/R ERROR DESCRIPTION / SUGGESTED ACTION ,/ 55640
2 13H I ,2X.9(4H ),/2H I) 55650
-------
ro
CO
2001 FQF?MAT(55H I TUBE FLUID PASSED THROUGH TRANSITION ZOME / IF OVER,
1 9HALL CASE ,/
2 60H I RERUN WITH STEPWISE OPTION TO INSURE REASONABLE RESULTS.,
3 /2H I)
2009 FORMATI23H I SPEC. TUBE COUNT OFtI5,24H / BUNDLE DOES NOT AGREE,
1 5H W1TH./23H I CALCULATED VALUE OF,15,
2 30H / BUNDLE. PROGRAM USED SPEC../2H I)
2010 FORMAT(44H I FAN TO FACE AREA RATIO LESS THAN .35 / /
1 44H I CHECK FAN RING I.D. AND NO. BUNDLES/BAY. / 2H I)
2011 FORMAT(70H I FAN DIAMETER EXCEEDS BUNDLE WIDTH!S) OR FAN/FACE ARE
1A EXCEEDS 0.7./44H I BAY MAY BE SHARED B/ MORE THAN ONE UNIT. /
2 52H I AIR DYNAMIC PRESSURE DROP MAY BE OVER PREDICT ED./2H I)
2012 FORMATO7H I PCT. UNDERDESIGN IS CONSERVATIVE. / ,
1 60H I RECOMMEND RERUN TO FIND OUTLET TEMP (CARD 1 ITEM 1=4) /
2 2H I )
DANGER OF FREEZING OR SOL IDIFICATI ON./2H 2)
2 UOCON CONV. METHOD FAILED IN COLBURN-HOUGEN/ U,
2013 FORMAT(41H I
3002 FORMAT(55H I
1 8HSED WARD ,/2H I)
3005 FORMAT(55H i 5 QQUAL
1 15H/ CALCULATES DX ,
2 /2H I , 13X.20HPROPORTIONAL TO DQ.
CP AND HFG NOT CONSISTENT WITH T-Q CURVE,
,/2H I )
3006 FQRMAT(57H I
1 D /56H I
2 /56H I
3 / 2H I)
3007 FORMAT(55H I
I 6HE USED
EXINI
7 OBALN
,/2H I)
THE VAPOR PRESSURE CURVE HAS BEEN ADJUSTS
TO AGREE WITH ENTERING FLOW CONDITIONS
(DEW POINT, PCT. NON-COND., INLET PRESS.)
CONV. TO CALC, AVG. CP FAILED/ LAST VALU,
3008 FORMAT(55H I 8 QPROF CONV. METHOD FAILED/ LAST VALUE USED
1 /2H I,13X.31HCHECK INPUT VAPOR PRESSURE DATA ,/2H I)
3011 FORMAT(55H I 11 SUPER REQUIRED AIR VELOCITY EXCEEDS 3000 FPM/ ,
1 17HCASE TERMINATED ,/2H I)
3013 FORMAT(55H I 13 HTSEN CONV. FAILED IN CALC. COEF. FOR VERTICAL,
1 17H TUBES IN LAMINAR /2H I , 1 3X , 5HF LOW . , ,/2H I)
3016 FORMAT(55H I 16 EXINI SPECIFIED INLET PRESSURE DIFFERS BY MORE,
1 17H THAN 5 PCT. FROM/
2 55H I CALCULATED VALUE OBTAINED FROM CONSIDERI,
3 17HNG VAPOR PRESSURE/
4 55H I
5 2H I)
3017 FORMAT(56H I
1 /4BH I
3018 FORMAT(55H I
1 /32H I
3019 FORMAT(74H I
AND ENTERING QUALITY / LARGER VALUE USED/
17 EXINI
18 GEOM1
19 DPAIR
CALC. DEW POINT TEMP. EXCEEDS INLET TEMP.
/ INLET TEMP. RESET TO DEW POINT../2H I)
SPEC. AND CALC. BUNDLE WIDTH DIFFER /
CALC. VALUE USED. ,/2H I )
AIRSIDE STATIC DP IS HIGH. IF AXIAL FAN U
1SED.THE FAN EFFIC./ 2H I,13X,56HUSED MAY BE HIGH. / CHECK FAN PERF
20R. AND EFFIC. CURVES.)
3020 FORMAT(60H I 20 QBALN GIVEN DUTY AND CALC. TUBE SIDE DUTY DIFFE
1R BY,/73H I MORE THAN 50 PCT. / GIVEN DUTY SET TO ZER
20 AND CASE CONT. , /2H I)
3021 FORMAT (54H I 21 CHANL OP. CONVERGENCE FAILED/RESULTS SHOULD S,
55660
55670
55680
55090
55700
55710
55720
55730
557-10
55750
55760
55770
55780
55790
55800
55810
55820
55830
55840
55850
55060
55870
55880
55890
55900
55910
55920
55930
55940
55950
55960
55970
55980
55^90
56000
56010
56020
56030
56040
56050
56060
56070
56080
56090
56100
561 10
561 20
56130
561 40
56150
-------
3022
3023
3050
3062
3064
3065
3069
3070
3071
3072
118HTILL BE REASONABLE, /
FORMAT(37H I 22 HTURB
FORMAT(37H I 23 QTURB
FORMAT(55H i 50 SUPER
1 14H EXTREME TEMP. ,/2H
FORMAT(38H I 62
FORMAT(55H I 64
1 11HHAN 50 PCT.
FORMAT(55H I 65
1 16HITY SPEC
FORMAT(46H
FORMAT(48H
FORMAT(49H
FORMAT(QGH
1 FROM CALC.
OBALN
QSALN
/2H I)
UOSEN
SHOULD /2H
69 PZONE
70 MTDOV
MTDOV
EXINI
2H I)
EXTRAPOLATION OCCURRED,/2H !)
EXTRAPOLATION OCCURRED,/2H I)
CONV. FOR PERFORMANCE FAILED.
I ,13X.8HPROFILE. ,/2H I)
TEMPERATURE CROSS FOUND ,/2H
HOT AND COLD CALC. DUTY DIFFER
71
72
3073 FORMAT(93H I
1 CALC. VALUE
3075 FORMAT(46H
3097 FORMAT(63H
1PECIFED/2H
3098 FORMAT(51H
1 /2H I , 13X.33HTEMP.
XAOF =(DBW+4.0J/12.0
MMC = 1
NWARN=0
IF (KGO-2) 500,100,500
C *** HEADING
100 IF (NWARN) 110,110,120
110 IF (MM ) 900,900,120
120 WRITE (NFO,1000)
C *** WARNING MESSAGES
IF (NWARN) 300,300,200
200 WRITE (NFO,1001)
WRITE (NFO,1002)
DO 299 1=1,NWARN
IF (IWARN(I)- 1) 299,210,212
210 WRITE (NFO,2001}
212 CONTINUE
22G IF (IWARN(I)- 9) 299,227,228
227 WRITE (NFO,2009) NTT.NT2
228 IF ( IWARNf I )-10) 299,229,230
229 WRITE (NFO,2010)
230 IF (IWARN(I)-11) 299,231,232
231 WRITE (NFO,2011)
232 IF (IWARN(I)-12) 299,233,234
233 WRITE (NFO,2012)
234 IF (IWARN(I)-13) 299,235,236
235 WRITE (NFO,2013)
236 CONTINUE
299 CONTINUE
WALL TEMP. CONV. FAILED REFERI
I,13X,23HBE CLOSER TO WALL TEt
NTU CONIV. FAILED/ REPORT TO P
PROBABLE TEMPERATURE CROSS FOI
CONV. METHOD FAILED/ REPORT Tl
DESUPERHEAT ZONE DUTY DIFFERS I
VALUE/ CHECK CPV AND PROCESS./2H I)
73 EXINI SUBCOOL ZONE DUTY DIFFERS BY !
/ CHECK CPL AND PROCESS./2H I)
75 EXCON NTU CONV. FAILED/ REPORT TO P
97 PPAUT AUTOMATIC PROPERTY CODE (CARD
13X,25HNOT INCLUDED IN DATA BANK/2H I)
98 PPROP TEMP. INPUT LESS THAN .1 RANI
AIR LESS THAN 200 RANKINE ,/2H
MAY BE TOO,
I)
} BY MORE T,
UNCE VISCOS,
/IP. , /2H I )
FR./2H I)
JND. ,/2H I )
D PFR ,/2H I )
BY 50 PCT.
50 PCT. FORM
FR./2H I)
6 ITEM 1 ) S
-------
ro
On
: **+
300
306
308
309
31 0
311
312
313
316
317
322
323
324
325
32G
327
323
331
33-1
335
338
343
344
345
346
347
343
349
6000
6010
6020
6021
6022
6023
6024
6025
6026
6027
: ***
350
352
354
MINOR ERROR MESSAGES
IF ( MM ) 400,400,306
IF ( KERR(1)-50) 308,309,309
WRITE (NFO, 1001 )
, 1003)
, MM
WRITE (NFO,
DO 399 1 = 1 ,
NWARN= 1-1
IF (NWARN)
DO 312 J = 1 ,NWARN
IF (KERR(I )-KERR( J)) 312,399,312
CONTINUE
IF ( KERR( 1 )-50)
IF(KERR( I )-2)399,
WRITE (NFO, 3002)
IF(KERR(I)-5)399,322,323
WRITE (NF0.3005J
IF ( KERR( I )- 6)
WRITE (NFO, 3006)
IF ( KERRI I )- 7)
WRITE (NFO, 3007)
IF ( KERRI I )- 8)
WRITE (NFO, 3008)
IF(KERR( I )-11 )399,
WRITE (NFO, 301 1 )
IF(KERR( I 1-13)399,338,343
WRITE (NFO, 3013)
IF ( KF.RR( I )-1 6)
WRITE (NF0.3016)
IF ( KERR( I )-17)
WRITE (NFO, 3017)
IF ( KERR( I )~1 8)
WRITE (NFO, 3018)
IF ( KERR( I )-19)
WRITE (NFO, 3019)
IF (KERR(I)-20)
WRITE! NFO, 3020)
IF (KERR(I)-21) 399,6022,6023
WRITE (NFO, 3021 )
IF(KERR( I (-22)399,6024,6025
WRITE! NFO, 3022)
IF( KERRI I (-23)399,6026,6027
WRITE! NFO, 3023)
CONTINUE
IF ( KERRI I)-50) 399,350,350
MAJOR ERROR MESSAGES
IF (MMC ) 354,354,352
WRITE (NFO, 1001 )
WRITE (NFO, 1004)
MMC=-1
IF ( KERR(I)-50) 399,355,356
313,313,311
313,350,350
,316,317
399,324,325
399.326,327
399,328,331
, 334,335
399,344,345
399,346,347
399,348,349
399,6000,6010
399,6020,6021
56660
56b70
SGGfiO
5()o90
5G700
56710
56720
56730
56740
56750
56760
56770
56780
56790
S6800
56H10
56820
56030
56940
56850
56860
56870
568RO
56890
56900
56910
56920
56930
56940
56950
56060
56970
56'.iBO
56990
57000
57010
57020
57030
57040
57050
57060
57070
57000
57090
57100
57 110
57120
57130
571 40
57150
-------
362,361,362
364,363,364
366,365,366
368,367,368
370,369,370
372,371,372
no
01
355 WRITE (NF0.3050)
356 IF(KERR(I)-62)360,359,360
359 WRITE (NF0.3062)
360 IF ( KERR( I )-64)
361 WRITE (NF0.3064)
362 IF ( KERR(I )-65)
363 WRITE (NFO,3065)
364 IF ( KERR(I)-69)
365 WRITE (NF0.3069)
366 IF ( KERR(I)-70)
367 WRITE (NF0.3070)
368 IF ( KERR(I)-71)
369 WRITE (NF0.3071)
370 IF ( KERR(I)-75)
371 WRITE (NF0.3075)
372 IF(KERR(I)-97)380,379,380
379 WRITE (NFO,3097)
380 IF (KERR(I)-93) 382,381,382
381 WRITE (NF0.3098)
382 IF (KERR(I)-72) 384,383,384
383 WRITE!NFO,3072)
384 IF (KERR(I)-73) 386,385,386
385 WRITEfNFO,3073)
386 CONTINUE
399 CONTINUE
400 WRITE (NFO,1001)
GO TO 900
C *** WARNING MESSAGES ARE SET HERE
500 CONTINUE
C *** TRANSITION ZONE CHECK FOR SENSIBLE
502 IF (RE12(1 ,1 )-2000. ) 520,520,503
503 IF (RE12(2,1 )-1.OE4) 504,520,520
504 NWARN=NWARN+1
IWARNf NWARN) = 1
520 CONTINUE
C *** TUBE COUNT DISCREPANCY
570 IF (NTT-NT2-NTR) 572,572,574
572 IF (NT2-NTT-NTR) 580,580,574
574 NWARN-NWARN+1
IWARN(NWARN)=9
C *** SMALL FAN/FACE
580 IF (RFNPL-.35)
582 NWARN=NWARN-H
IWARN(NWARN)=10
C *** FAN DIA. EXCEED BUND. WIDTH.
590 IF (ZBUP*ZBYP-1.1) 592,600,600
592 IF (DFAN-XAOF*ZBUP) 594,596,596
594 IF (RFNPL-.7) 600,596,596
596 NWARN=NWARN+1
IWARN(NWARN)=11
CASES
AREA RATIO
582,582,590
571 60
57 170
57 1 80
57 190
57200
57210
57220
57230
57240
57250
57260
57270
572HO
57290
57300
57310
57320
57330
57340
57350
57360
57370
57380
57390
57400
57410
57420
57430
57440
57450
57460
57470
57480
57490
57500
57510
57520
57530
57540
57550
57560
57570
57580
57590
57600
57610
57620
57630
57640
57650
-------
600 CONTINUE
602 IF (KCI - 1 ) 610,604,610
604 IF (XREX+10.0) 606,610,610
606 NWARN=NWARN+1
IWARN(NWARN)=12
C *** FREEZING/SOLIDIFICATION
610 IF (TWALL-TTMIN-5.) 615,620,620
615 NWARN=NWARN+1
IWARN(NWARN)=13
620 CONTINUE
GO TO 100
900 RETURN
END
57660
57670
57680
57G90
57700
57710
57720
57730
57740
57750
57760
57770
57780
C ** *
c ***
c ** *
1 0
20
30
SUBROUTINE PIPDIVID,L.XMT,TLMAX,FJ,Sd,I)
PIPE DIAMETER IN INCHES
LENGTH OF PIPE IN FEET
NUMBER OF PIECES
MAXIMUM SHIPPABLE LENGTH IN FEET
FIELD LABOR RATE IN DOLLARS/HR
COST OF SHOP JOINT IN DOLLARS/DIAMETER INCH
SUBSCRIPT OF ARRAY
ADDS A FIELD JOINT EVERY TLMAX FEET TO FIELD!I)
ADDS A SHOP JOINT EVERY 48 OR 12 FT. TO XSHOP(I)
ADDS AN EXPANSION JOINT EVERY 110 FEET TO EXJOT( I )
COMMON/BCK/XMCST(20),PIPDM(20),XSHOP(20),FIELD(20),EXJOT(20)
DIMENSION EJARR(20),DIARR(20)
ARRAY OF PIPE SIZES (INCHES)
DATA DIARR/4.026,8.071,12.09,17.25,23.25,29.25,35.25,42.,48.,54.,
1 60., 66., 72., 78., 84., 90., 96., 108., 114., 144./
ARRAY OF COSTS FOR EXPANSION JOINTS
DATA EJARR/ 134.00, 234.00, 321.00, 508.00,
1 922.00, 1150.0, 2200.0, 3250.0,
4500.0, 5300.0, 6100.0, 7500.0,
16800.
C
c
c
c
c
c
c
c
c
c
** *
+ * *
** +
** *
** *
* * +
** *
** *
+ * *
** *
GIVEN
D
L
XMT
TLMAX
FJ
SJ
I
THIS ROUTI
2
3 11100., 13000.,
IF(D-48.01 )10,20 ,20
F=TLMAX
S=AMIN1(TLMAX,48.)
GO TO 40
IF(D-96.01)30,35,35
F = AMIN1(TLMAX,48. )
1976 PRICES)
850.00,
3850.0,
9300.0,
28000./
18000.
57790
57BOO
57810
57820
57830
57810
57850
57860
57870
57880
57890
57900
57910
57920
57930
579-10
57950
57960
57970
57980
57990
56000
58010
58020
58030
58040
58050
58060
-------
S=AMIN1(TLMAX,12.)
GO TO 40
35 F=AMIN1(TLMAX,24. )
S=AMIN1(TLMAX,12.)
40 XNO=AINT(L/F-.01)
FIELD(I)=FIELD(I)+FJ*(XN°+1.)*XMT*(1.4+1.6*0)
XNO=XNO*AINT(F/S-.01)+AINT((L-XNO*F)/S-.01)
XSHOP( I )=XSHOP( I )+SJ*XNO*XMT*D
XNO=AINT(L/110.-.01)
EXJOT(I)=XNO*XMT*GRS(DIARR,1,EJARR.1, D,20,JDUM)+EXJOT(I)
RETURN
END
58070
58C80
58090
501 00
58110
581 20
58130
58140
58 150
58160
58170
58180
00
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
SUBROUTINE PLENUM(NFAN,DFAN.DL,DHEDW,TSPLM.DENCS.CPLM1,CPLL1.CTPLM
1 , PLMTL,PLLAB.ZBUP)
CDMMON/PIPE/XDIA(20),XLGT(20),NN1,NN2,XTOWR.PLNMH,TTTBH,VX,VN,VAVE
*** THIS SUBROUTINE COMPUTES THE INSTALLED COST FON PLENUM
*** INPUT VARIABLES ***
DFAN = FAN DIAMETER (FT)
DL = BUNDLE LENGTH (FT)
DHEDW = BUNDLE WIDTH (INCH)
TSPLM = THICKNESS OF PLENUM (INCH)
DEN = DENSITY OF PLENUM METAL (LB/INCH3)
CPLM1 = UNIT COST FOR PLENUM METAL (S/LB)
FPLM = INSTALLED COST INDEX (BASED ON MATERIAL COST)
NFAN = NUMBER OF FANS PER BAY
ZBUP = NUMBER OF BUNDLES IN PARALLEL PER BAY
*** OUTPUT VARIABLE ***
CTPLM = INSTALLED COST FOR PLENUM ($)
ZFAN=NFAN
*** BASE PLENUM HEIGHT ON 45 DEGREE DISPERSION ANGLE
PLNMH=AMAX1((DHEDW/12.*ZBUP-DFAN)/2.,(DL/ZFAN-DFAN)/2.)
DHPLM=PLNMH
SIDE PLENUM AREA (FT2)
SIDEA=2.0*(DL+OHEDW*ZBUP/12.)*DHPLM
50 1 90
58200
58210
58220
58230
58P40
58250
58260
58270
58280
58290
58300
58310
58320
58330
58340
58350
58360
58370
58380
58390
58400
58410
58420
58430
58440
58450
58460
58470
-------
ro
C
C
C
C
C
C
C
C
C
C
TOP PLENUM AREA (FT2)
TOPA=DL*DHEDW*Z8UP/12.-ZFAN*3.1416+(DFAN/2.)*
PLENUM WEIGHT (LB)
WTPLM=DENCS*TSPLM*(SIDEA+TOPA)* 144.
PLENUM MATERIAL COST ($)
PLMTL=CPLM1*WTPLM
PLENUM INSTALLED LABOR COST
PLLAB=CPLL1*WTPLM
PLENUM INSTALLED COST
CTPLM=PLMTL+PLLAB
RETURN
END
584RO
58490
58500
5851 0
58520
50530
58540
58550
58560
58570
58580
58590
58600
58610
58620
58630
58640
58650
FUNCTION PNLIM(AMIN,AMAX,AFUNC)
C *** FUNCTION LIMITS AFUNC BETWEEN AMIN AND AMAX
PNLIM=AFUNC
IF (AFUNC-AMIN) 10,10,20
10 PNLIM=AMIN
GO TO 50
C *** IF AMAX IS LESS THAN AMIN JUST SET PNLIM TO AFUNC
20 IF (AMAX-AMIN) 50,50,30
30 IF (AFUNC-AMAX) 50,50,40
40 PNLIM=AMAX
50 RETURN
END
58660
58670
58680
58690
58700
58710
58720
58730
58740
58750
58760
58770
-------
co
o
SUBROUTINE PPAUT
C *** FILL IN AUTOMATIC PHYSICAL PROPERTY CONSTANTS
DIMENSION AP(16),AP001(16)
COMMON NFO,KGO,KNTRO,KNTR1 ,NSUM,NPAGE,DAY(2) ,PI
COMMON KCI,KER,KERR(20),KFIN,KREG.LAIC,LSUPtMM,NP,NR,NT1,NT2.NTP,
1NTR.NTT.ABARE,AFAN,AMIN,APLOT,APPR.ASBUN,ASTOT,AXAV.AXPP(20).CP(2)
2,DEN(2) DEN 12(2,2 ) , DENFN,DENLZ(7),DBW,DE9.DFH,DFR.DFS,DFT,DKL,
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,OTO,DTT,PL,PT
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,D"NZ(2l,DPT,OPTA,OPTF,
1DPTOT(2),POUT(2),PTUB.RV2.GAMAX.GT,HPFNC,HAIR,HTS,UBAME.UCLN.UTOT,
20(2) QDUT.QTOT.RFI,RFIN.RFTOT,RTOT,RTW,T,VIS12(2,2).VISW,W(2),WAPF,WB(2),WLQ(2)
COMMON ANG(3) ,CFH(3),CFP(3) , CF R , CKBSC , CKTNG , CKHSC , CK LClV, CKSTC , F ,
1FALT,FINEF.FFF,FSUM,OCL(4),ODL<4) ,OKL{4),OMLI4) .OMV<4 I .P,PRAN(2),
2PRALZ(7),R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA,
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20).ZTPPA
COMMON ZTRD,ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI ,DLOV , ZNFI ,PTI,TKT.TKF,
1WD<2).VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,OD(7),
2CARD7I6),ONZI(2),PDI, CFNG,CHSC,CLOV,CBSC,PRSTC.RFAIR.RFCT,ZNDZ(2),
3RASPC,ZTPD,ZNTD,COST(7) ,SSUM(16,30) ,ISUM( 13 , 30 ) ,PR 1CE(2 , 21 )
C *** AATER (STEAM) CONSTANTS FOLLOW*ODL,ML,KL,CL,MV,KV,CV,HF,SI,VP,PC,T
DATA 4P001/ 53.34,4.40127E-02.-5.1085E-05,0.0, -2.953 ,-470.81 ,
1 1 .074932E6.0.0,
2 6.341E-7.0.0/
DO 100 K=1,16
100 AP(K)=AP001(K)
DO 400 K=1,4
ODL(K) =AP(K)
OML(K) =AP(K+4)
OKLfK) =AP(K*8)
OCL(K) =AP(K+12)
400 CONTINUE
500 RETURN
END
-.17134,1.527E-3.-1.021E-6.0.0. 1.191.-7.0E-4.
58780
58790
5BHOO
5BBIO
58U20
58830
SOB-10
58850
58BGO
58870
5H830
5B690
58900
5891 0
58920
58930
58940
58950
58960
58970
58980
58990
59000
59010
59020
59030
59040
59050
59060
59070
59080
59090
59100
59110
59120
SUBROUTINE PPAUT1(TF,CPL,DENL.TKL,VISL.KODE)
C *** THIS SUBROUTINE CALCULATES WATER -STEAM PHYSICAL PROPERTIES
C T = TEMPERATURE DEG.R
C CPL = HEAT CAPACITY OF WATER IN BTU/LB/F
C DENL = DENSITY OF WATER IN LB/FT3
C VISL = VISCOSITY OF WATER IN CENTIPOISES
59130
591 40
59150
59160
591 70
59180
-------
c
c
n 59190
-F ° 460.0 59200
T2 = T*T 5921°
CPL = 1.191328 - 7.002932E-4*T + 6.3408E-7+T2 59220
DENL = 53.34 + 4.40127E-2*T -5.1085E-5*T2 59230
VI5L = EXP(-2.953 -470.81/T + 1074932./(T2)) 59240
ALL THE ABOVE PROPERTIES ARE VALID FOR TEMPERATURES FROM 460 TO 59250
1030 DEG.R 59260
RETURN 5927°
END 5928°
i
i—>
OJ
SUBROUTINE PPCON 59290
C *** ESTABLISH PHYSICAL PROPERTY CONSTANT DETERM. FROM INPUT DATA 59300
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE.DAY(2),PI 59310
COMMON KCI,KER,KERR(20) ,KFIN,KREG,LAIC,LSUP.MM,NP,NR,NT1 ,NT2,NTP, 59320
1NTR.NTT.ABARE,AFAN,AMIN,APLOT,APPR.ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 59330
2,DEN(2),DEN12(2,2) ,DENFN,DENLZ(7) , DBW , DEC) , DFH , DFR , DF S . DFT , OK L , 59340
3DLSP.DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,010,DTT,PL,PT 59350
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10) ,DPI,DFNZ(2) ,DPT,DPT A,DPTF. 593GO
1DPTOT(2) POUT(2),PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTOT, 59370
20(2) QDUT QTOT.RFI ,RFIN,RFTOT,RTOT,RTw,TAV(2) ,TIN(2) ,TOUT(2) ,TT(8) 59300
3 TWALL TD'TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,VISLZ(7), 59390
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2).WLO(2) 59-^00
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC.F, 59410
1FALT FINEF FFF,FSUM,OCL(4),DDL(4) ,OKL(4),OML(4) ,OMVI 4) ,P,PR AN(2), 59420
2PRALZ17) R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE 12(2.2),RFNPL,RPT.TLA, 59430
3XREX.ZMP.ZNF,ZNTP,ZNTR,ZNTT.ZTPP(2.0) ,ZTPPA 59440
COMMON ZTRD.ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI,DLOV,ZNFI,PTI,TKT,TKF, 59450
1WD(2) PPI TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,OD(7), 59460
2CARD7(6) DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2), 59470
3RASPC,ZTPD,ZNTD,COST(7),SSUM(16,30) , ISUM( 13,30 ) ,PRICE(2 , 21 ) 59480
C *** SET AUTOMATIC DATA HERE 59490
10 CALL PPAUT c95°S
300 CONTINUE 59510
1000 RETURN 59520
END 5953°
-------
SUBROUTINE PPDEN (T,PZ,ZV,AVMW,DENL,DENV,KCLG,DDL)
C *** CALC. VAPOR AND LIQUID DENSITY ,LB/FT3
DIMENSION ODL(4)
10 DENL=ODL(1)+OOL(2)*T+ODL(3)*T*T
200 RETURN
END
59540
59550
59560
59570
59580
59590
CO
ro
SUBROUTINE PPROP (TZ,PZ,KCLG,DENA,V ISA,CPA,TKA,PV.KODE,J) 59600
C *** CALC. PHYSICAL PROPERTIES 59610
COMMON NFO,KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2),PI 59620
COMMON KCI,KER,KERR(20),KFIN,KREG,LA1C,LSUP,MM,NP,NR,NT1,NT2,NTP, 59630
1NTR,NTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 59640
2,DEN(2).DEN12(2,2) , DENFN,DENLZ(7),DBW,DEQ,DFH,DFR,DFS,DFT,DKL, 59650
3DLSP,DLTE,DLT01DLTS,DNZ(2),DTI,DTIM,DTF,DTO.DTT,PL,PT 59660
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DDI,DPNZ(2),DPT,OPTA,DPTF, 59670
1DPTQT(2),POUT(2),PTUB,RV2,GAMAX,GT, HPFNC.HA1R,HTS , UBARE,UCLN,UTOT, 59600
20(2) ,QDUT,OTOT,RFI,RFIN,RFTOT,RTOT,RTW,TAV(2) , TIN(2) ,TOUT(2) ,TT(8 ) 59690
3,TWALL,TD,TW,TIVITD,TK(2) ,VAPP,VNZ(2),VT,DFAN,TLTE,AOF,V1SLZ(7), 59700
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLQ(2) 59710
COMMON ANG(3) ,CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC,CKLOV,CKSTC,F, 59720
1FALT,FINEF,FFF,FSl!M,OCL(4),ODL(4),OKL(4),OML(4), OMV (4).P.PRAN(2), 59730
2PRALZ(7),R,RAOI,RAOR,RARAF,RAPMX,RE A(2) ,RE12(2,2),RFNPL,RPTtTLA, 59740
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20),ZTPPA 59750
COMMON ZTRD,ANGI,ZBYP,ZBUP,ZBUS,ZFAN,DFANI, DLOV,ZNF1,PTI,TKT,TKF, 59760
1WD(2),VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,OD(7), 59770
2CARD7(6),DNZI (2) ,PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ(2) , 59780
3RASPC,ZTPD,ZNTD,COST(7),SSUM(16,30) ,ISUM(13,30) , PR ICE(2 , 21 ) 59790
IF (TZ-.1) 10,10,20 59800
10 KER=98 59810
GO TO 500 59820
C *** CHECK PREVENTS EXTRAPOLATION OF PROPERTIES PAST THE REF. VALUES 59830
20 CONTINUE 59840
1020 T=TZ 59850
21 IF(J-1 )70,70 ,24 59860
C *** AIR PROPERTIES CHECKED FROM -100F TO 400F (APPLY TO DRY AIR,LOW P) 59870
24 T = PNLIM(200. ,900. ,TZ) 59880
40 X=T-459.7 59890
DENA=PZ*28.97/(T*10.73)*FALT 59900
VISA = 0.00905+1.191E-4*(X+200.)* + 0.775 59910
CPA = 0.2401 457+2. 48709E-7*X-t-2. 990712E-8*X*X 59920
TKA=6.915297E-3+7.384478E-5*(X+200.)**.8376137 59930
GO TO 240 59940
-------
70 CONTINUE
CALL PPDEN(T ,P2, .1 ,.1 ,DENA,DD,KCLG,QDL)
CALL PPVIS(T,KCLG,VISA,VV,OMV,OML)
T2=T*T
CPA=OCL(1)+OCL(2)*T+OCL(3)+T2
TKA=OKL(1 )+OKL(2)*T+OKL(3)*T2
PRAN(J)=2.42*CPA*VISA/TKA
GO TO 400
240 PRAN(J)=2.42*CPA*VISA/TKA
400 CONTINUE
500 RETURN
END
59950
59960
59970
59980
59990
60000
60010
60020
60030
60040
60050
60060
oo
co
SUBROUTINE PPVIS (T,KCLG,V ISL,VISV,OMV,OML)
C *** CALC. VAPOR AND LIQUID VISCOSITY, CENTI-POISE
DIMENSION OMV(4),OML(4)
10 VISL=EXP(OML(1 )+OML(2)/T+OIVIL(3)/T**2)
200 RETURN
END
60070
60080
60090
60100
601 10
60120
FUNCTION PSL(T)
C *** GIVEN T IN DEGREES F TO FIND PRESSURE IN INCHES-HG
DATA A,B,C,D/3.2437814,5.86826E-03,1.1702379E-08,2.1878462E-03/
TC=(T-32.)/1.8+273.16
X=647.27-TC
RATIO=X/TC*(A+B*X+C*X**3)/(1.+D*X)*2.3026
P=3206.2/EXP(RATIO)
PSL=2.036*P
RETURN
END
60
60
60
GO
60
60
30
40
50
60
70
80
60190
60200
60210
60220
-------
I
I—>
co
SUBROUTINE QBALN
C *** CALC. OF HEAT DUTY FROM GIVEN INFORMATION
COMMON NFO,KGO,KNTRO,KNTR1 ,N5UM , NPAGE , DAY ( 2) , PI
COMMON KCI.KER KERR ( 20 ) , KFIN , KREG , LA 1C , LSL'P ,MM , NP , NR , NT 1 , NT2 , NTP ,
1NTR.NTT,ABARE,AFAN,AIVI[N,APLOT,APPR, ASBUN, ASTOT, AXAV, AX°P(20) ,CP(2)
2,DEN(2) ,DEN12(2,2l , DENFN , DENLZ ( 7 ) , DBW , DEO . DFH , DFR , DF S , RFT , DKL .
3DLSP,DLTE,DLTO,OLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10) ,DPI ,D^4Z(2I ,DPT,DPTA,DPTF,
1DPTOTI2) POUT(2), PTUB , RV2 . GAMAX , GT , HPFNC , HA I R , HTS , UBAKE . UCLN , UTOT ,
20(2) QDUT QTOT.RFI.RFIN,RFTOT,RTOT,RTjJ,TAV(2) ,TIN(2) , TO'JT ( 2 ) ,TT(8)
3,TWALL,TD,TW.TMTD,TK(2) ,VAPP,VNZ(2) , VT , DF AN , T LT E . AOF , V I SLZ ( 7 ) ,
4VIS(2) VIS1 2(2,2 ) , VISW, W(2) , WAPF ,WB( 2) ,WLO( 2)
COMMON ANG(3) ,CFH( 3 ) . CFP ( 3) , CFR , CKBSC , CKFNG . HSC , CKLOV . CKSTC , F ,
1FALT,FINEF,FFF,FSUM,OCL(4) , OD L ( 4 ) , OK L ( 4 ) , OML ( 4 ) , OMV ( 4 ) , P,PRAN(2) ,
2PRALZ17) ,R,RAOI.RAOR,RARAF,RAPMX,REA(2) ,RE12(2,2) , RFN P L , RPT , T LA ,
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20) ,ZTPPA
COMMON ZTRD.ANGI , ZBYP , ZBUP , ZBUS , ZF AN , DFAN I , DLOV.ZNFI ,PT1,TKT,TKF,
1WD(2) VAPPI,TAMB,HALT,C319,TIND(2) ,TOUTD(2) , RFD , PSD , T TMIN , OD ( 7 ) ,
2CARD7(6) DNZI(2) , PDI , CFNG , CHSC , CLOV , CBSC , PRSTC , RFAI R , R FCT , ZNOZ ( 2 ) ,
3RASPC,ZTPD,ZNTD,COST(7),SSUM(16,30) , ISUM( 1 3 , 30 ) . PRICE ( 2 , 21 )
LAIC=0
6 TT(2)=TOUT(1 )
IF (KCI-2) 30,36.30
C *** CALC. THE AIR SIDE FLOW RATE
30 IF (WD(2)-0.001 ) 36,36,40
36 W(2)=VAPP*4.500*APPR*ZMP
40 DO 80 J=1 ,2
IF (TOUT(J)-O.D 42,42,46
42 TOUT) J)=TIN( J)
46 TAV( d)=0.5*(TIN( J )+TOUT ( d ) )
70 CALL PPROP(TAVfJ) ,14.70, J.DEN(d) ,VIS(J),CP(J),TK(J),PV, 0,0)
80 CONTINUE
IF (KER) 200,200,1000
C *** FIND DUTY FROM TOUT, KODE=0
C *** CALC. THE PROPERIES FOR EACH ZONE GIVEN IN INPUT ONLY ONCE
200 CONTINUE
L=1
210 T=.5*(TT(1 )+TT(2))
CALL PPROP(T,1 . ,1 ,DENLZ(1),VISLZ(1 ) , CPD , TKD, PV , 0 , 1 )
IF (KER) 1212,1212,1000
1212 CONTINUE
230 DO 260 J=L,2
250 Q( J)=W( J)*CP( J)*ABS(TIN(J)-TOUT(J) )
260 CONTINUE
270 IF (QD(1 )-1 .OE-6) 280,280,272
272 CONTINUE
274 QDUT=QD(1 )
C *** CHECK IF GIVEN DUTY AGREES WITH T/S DUTY TO WITHIN 50 PCT .
278 IF (ABS(Q(1)/QDUT-1.0>-.5) 290,290,279
C *** RESET GIVEN DUTY TO ZERO AND SET MINOR ERROR 20
™
60240
60250
602GO
60270
60280
60290
60300
60310
60320
60330
60340
60350
60360
60370
60380
60390
60400
60410
60420
60440
60450
60460
60470
60480
60490
60500
60510
60520
60530
60540
60550
60560
60570
60580
60590
60600
60610
60620
60630
60640
60650
60660
60670
60680
60690
60700
60710
60720
-------
co
en
279 QD(1 )=0.0 60730
KER=20 60740
CALL ERORF(KER,KERR,KGO,MM) 60750
280 CONTINUE 60760
290 CONTINUE 60770
320 K=1 60780
J=2 60790
400 IF (QD(1)-1.E-6) 410,410,440 60800
410 CONTINUE 60810
430 QDUT=W(K)*CP(K)*ABS(TIN(K)-TOUT(K)) 60820
440 0(1)=ODUT 60830
Q(2)=QDUT 60840
446 CONTINUE 60850
472 T=TAV(J) 608f>0
LAIC=LAIC+1 60870
480 TOUT(J)=TIN(J)+QDUT/(W(J)*CP(d)) 60800
492 TftV(J(=0.5*(TIN(J)+TOUT(J)) 60890
IF (ABS(T/TAV(J)-1 .0)-0.001 ) 500,500,494 60900
494 CALL PPROP(TAV(d),14.70,J,DEN(J),VIS(J),CP(J),TK(J),PV.O.d) 60910
IF (KER) 495,495,1000 60920
495 PRALZ(1}=PRAN(1) 60930
IF (LAIC-20) 472,472,497 60940
497 KER = 7 60950
498 CALL ERORF (KER.KERR,KGO,MM) 60960
500 CONTINUE 60970
C *** CHECK FOR IMPOSSIBLE TEMPERATURE OVERLAPS 609HO
510 IF (TOUT(1)-TIN(1)) 520,520,570 60990
520 IF (TIN(2)-TOUT(2)) 530,530,570 61000
530 CONTINUE 61010
C *** COCURRENT TEMP. CONSISTENCY CHECKS 61020
538 IF (TIN(2)~TOUT(1 ) ) 540,570,570 61030
540 IF(TOUT(2)-TIN(1)(580,570,570 61040
C *** COMPARE DUTY VALUES CALC. 61050
570 KER=62 61060
GO TO 1000 61070
C *** SET UP THE INLET.OUTLET,AVG,PROPERTIES 61080
580 DO 700 0=1 ,2 61C90
DO 700 1=1,2 61100
T=TINIJ) 61110
IF (1-2) 594,590,594 61120
590 T=TOUT(J) 61130
594 CALL PPROP(T,14.70,J,DEN12(I,J),VIS12(I ,J) ,CPD,TKD.PV,1 ,J) 61140
IF (KER) 600,600,1000 61150
600 CONTINUE 61160
700 CONTINUE 61170
C *»* CALC. INLET NOZZLE PRESSURE DROP 61180
WB(1)=W(1)/ZMP 61190
CALL NOZCT(DNZI,DNZ,WB(1 )/ZNOZ(1 ),VNZ,DEN12,0.0 ,DPNZ,DBW,0.0,1) 61200
C *** NTU BASED ON AIR SIDE 61210
P=(TOUT(2)-TIN(2))/TD 61220
-------
R=(TIN(1)-TOUT(1))/(TOUT(2)-TIN(2)) 61230
TT(2)=TOUT(1) 61240
: *** COMPARE APPR. VELOCITY WITH SPEC. VALUE 61250
870 IF (KCI-2) 880,930,880 61260
880 VT=W(2)/(4.5*APPR*ZMP) 61270
IF (VAPPI-0.01) 920,920,890 61200
890 \IR=( VT/VAPP-1 .0 ) *100.0 61290
IF (ABS(VR)- 5.0) 930,900,900 61300
900 WRITE (NF0.2010) VR 61310
IF (ABS(VR)-150.0) 920,904,904 61320
904 KER=64 61330
GO TO 930 61340
920 VAPP=VT 61350
930 CONTINUE 61360
1000 RETURN 61370
2010 FORMAT (/51H WARNING *** AIR APPROACH VELOCITY CALC. DIFFERS BY, 61380
1 F8.0.16H PCT. FROM SPEC.) 61390
END 61400
GO
Oi
SUBROUTINE QTURB(0,SAT,XLOAD,NCODE) 61410
C 61420
C IF NCODE=1 FIND SAT GIVEN (J AND XLOAD 61430
C IF NCODE=2 FIND 0 GIVEN SAT AND XLOAD 61440
C XLOAD - TURBINE LOAD FACTOR 61450
C SAT - SATURATION TEMPERATURE IN DEGREES F OF TURBINE EXHAUST 61460
CO- HEAT REJECT OF THE STEAM TURBINE 61470
COMMON IDUM.KGO, IDUM1(4) ,D1(3) , IDUM2.KER,KERR(20),ID1(4),MM,ID2(7) 61480
1,D2(1218) 61490
COMMON/STIN/XLDFT(6),BP(28),HTRTD(28,6),HTRJD(28,6).NLODS.NBKPR 61500
1,PLOAD,BPMNM(6),TPMNM(6) 61510
COMMON/BCKPR/BCKMN.BCKMX 61520
DIMENSION X(4) ,N(7) ,Y(4) ,Z(28) 61530
IF(NCODE-1)90,90,80 61540
80 BBPP=PSL(SAT) 61550
C *** MAKE SURE BBPP IS WITHIN BACK PRESSURE RANGE 61560
IF(BBPP.LT.BCKMN)BBPP=BCKMN+.00001 61570
IF(BBPP.GT.BCKMX)BBPP=BCKMX-.00001 61580
90 CONTINUE 61590
3 DO 5 1=1,7 61600
5 N(I)=0 61610
NP=3 61620
C *** SEE IF XLOAD LIES WITHIN THE RANGE OF XLDFT 61630
-------
I
I—>
CO
IF( (XLOAD-f .001 ) . LT.XLDFT(NLODS) . AND. (XLOAD+.001 ) . LT . XLDFT ( 1 ))
1N(1)=-1
IF(XLOAD.GT.(XLDFT(1 ) + .001 ) .AND.X LOAD.GT.(XLDFT(NLODS) + .001 ) )
1N(1)=1
IF(XLDPT(1 ) .GT.XLDFT(NLODS))N(1 ) = (-1 )*N(1 )
IF(N(1).NE.O)GO TO 11
C *** FIND XLOAD BETWEEN I AND 1-1 POINTS
DO 10 1=2,NLODS
IZ=I
IF(ABS(XLOAD-XLDFT(1-1)).LT..002)GO TO 4
IF(XLOAD-XLDFT(1-1))1,4,2
1 IF(XLOAD-XLDFT(I))10,70,20
2 IF(XLOAD-XLDFT(I))20,70,10
4 IZ=I-1
GO TO 70
10 CONTINUE
C *** IF XLOAD IS OUTSIDE RANGE OF XLDFT USE LAST 3 OR FIRST 3 POINTS
C *** DEPENDING ON WHETHER OR NOT XLDFT IS DECREASING OR INCREASING
11 I=NLODS
IF(N(1 ) .EQ. (-1 ))1 = 1
20 IF(I.GT.2)GO TO 30
C *** IF XLOAD IS ON LOW END USE FIRST 3 POINTS. IF IT IS ON HIGH END
C *** USE LAST 3 POINTS. OTHERWISE USE 4 POINTS - 2 ON EITHER SIDE
C *** OF XLOAD
N1 =1
N2 = 2
N3 = 3
GO TO 50
30 IF(I.EQ.NLODSJGO TO 40
NP = 4
N4=I+1
40 N1=I-2
N2=I-1
N3=I
C *** STORE LOADS IN Y ARRAY
50 Y(1 ) = XLDFT(N1 )
Y(2 ) = XLDFT(N2)
Y(3)=XLDFT(N3)
IF(NP.EQ.4)Y(4)=XLDFT(N4)
GO TO ( 100,200),NCODE
C + ** FOR NCODE=1 FIND THE HEAT REJECT CORRESPONDING TO XLOAD
C *** FDR EACH BACK PRESSURE AND STORE IN Z ARRAY
100 DO 125 K=1.NBKPR
Z(K)=GRS(Y,1,HTRJD(K,N1), 28,X LOAD,NP,N(2) )
125 CONTINUE
BBPP = GRS(Z,1 ,BP,1 ,0,NBKPR,N(3))
150 SAT=TSL(BBPP)
GO TO 300
C *** FDR NCODE=2 FIND THE HEAT REJECT CORRESPONDING TO SAT FOR EACH
C *** LOAD AND STORE IN X ARRAY
61640
61650
61600
61070
61 680
61690
61700
61710
61 720
61 730
61 740
61 760
61 760
61 770
61 780
61 790
61 800
61810
61820
61830
61 840
61 850
61 Si.'O
61 H70
61 8BO
61890
61 900
61 910
61 920
61930
61 940
61950
61 960
61 970
61 9BO
61 990
62000
620 10
62020
62030
62040
62050
620GO
62070
62080
62090
621 00
621 10
621 20
62130
-------
CO
CO
200 CONTINUE
X(1)=GRS(BP,1,HTRJD(1.N1),1,BBPP,NBKPR,
X(2)=GRS(BP,1,HTRJD(1,N2),1,BBPP,NBKPR.
X(3)=GRS(BP,1,HTRJD(1,N3),1,BBPP,NBKPR.
IF(NP.EQ.4)X(4) = GRS(BP,1,HTR.JD(1,N4),1,
C *** FIND 0 CORRESPONDING TO XLOAD
0=GR5(Y,1,X,1,XLOAD,NP,N(6))
GO TO 300
70 I=IZ
GO TO (225,250),NCODE
225 BBPP=GRS(HTRJD(1,I),1,BP,1,Q,NBKPR,N(7))
GO TO 150
250 CONTINUE
0 = GRS(BP,1 ,HTRJD(1 ,1) ,1 ,BBPP,NBKPR,N(7 ) )
C *** SET MINOR ERROR IF EXTRAPOLATION OCCURRED
300 DO 400 1=1,7
IF(N(I))450,400,450
400 CONTINUE
GO TO 500
450 KER=23
CALL ERORF(KER,KERRtKGO,MM)
500 RETURN
END
N(2) )
N(3) )
N(4) )
BBPP,NBKPR,N(5) )
62140
62150
62 I GO
621 70
62180
62 1 ^0
62200
6221 0
62220
62230
62240
62250
62260
62270
62280
62290
62300
62310
62320
62330
62340
62350
62360
FUNCTION RNUM(DUMMY) 62370
C *** THIS FUNCTION USES THE LEHMER MULTIPLICATION CONGINENTIAL METHOD 62380
C *** OF GENERATING PSUEDO RANDOM NUMBERS. IT IS BASED ON A MODULUS 62390
C *** OF 60 BITS/WORD FOR THE CDC6000 SERIES COMPUTER. 62400
COMMON/RAND/SEED,XMODU,XNUM 62410
10 WIX=XNUM*SEED 62420
XNUM=AMOD(WIX,XMODU) 62430
RNUM=XNUM/XMODU 62440
RETURN 62450
END 62460
-------
SUBROUTINE SCDES(VMIN,VMAX,TLMIN,TLMA,TOUT,TTIN,WT,KMETL,KGAGE,
1MN,GC,PI,KCOND,CLFAC,DPMAX,CPLI,TSAT.PSMAX,PSMIN.DPTOT,DAY,CITEM,
2KNTR1,CPEFF,CMAIN,AFCR2,CAPCST,AFCR1)
COMMON IDUM.KGO, IDUM1(4) ,01(3) , IDUM2 , KER,KERR(20) ,ID1 (4) ,MM,ID2(7)
1 ,D2(1218)
DIMENSION CNEW(15),CITEM(10,15)
DIMENSION DTOA(5) ,DTTHA(7) ,BWGA(7)
S/R FOR STEAM SURFACE CONDENSER
1 .0,1.125,1 .25/
.035,.049,.065,.083,.109/
,18.,16.,14.,12./
THIS
DATA
DATA
DATA
S/R IS A DESIGN
DTOA/0.75,0.875,
DTTHA/ .022, .028,
BWGA/24.,22. ,20.
i
i—"
OJ
TLMAX=80.
C DEFINE INITIAL TEMP. DIFF.
TITD = TSAT - TTIN
C DEFINE TERMINAL TEMP. DIFF.
TTD = TSAT - TOUT
C DEFINE TEMP. RISE
TR = TOUT - TTIN
TLM = TR/ALOG(TITD/TTD)
C CALCULATE HEAT DUTY
C *** CALCULATE WATER PROPERTIES AT AVG. TEMP.
TTAV = 0.5*(TTIN + TOUT)
X=TTAV+460.
CP=1 .191328-7.002932E-4*X+6.3408E-7*X*X
0 = WT * CP * TR
CALL PPAtfTI (TTIN,CP,DEN,TKL,VIS,KODE)
DO 10 1=1,10
1 0 CITEM(1,1) = 1 .E30
M= 0
C *+* IF DPMAX,VMAX,VMIN,TLMAX,AND TLMIN NOT GIVEN,SET TO HIGH DEFAULT
C *** VALUE
IF(DPMAX.LT.01) DPMAX = 20.0
IF(VM1N.LT.01 ) VMIN = 3.0
IF(VMAX.LT.01 ) VMAX = 12.0
IF(TLMIN.LT.01) TLMIN = 20.0
IF(TLMAX.LT.01) TLMAX = 80.0
KOUNT=0
C WR1TE(6,BOO)
C *** ONLY ALLOW 1 SHELL IN SERIES TO SAVE TIME
C *** DO 700 NSER=1 ,2
NSER=1
ZNS = NSER
C LOOP FOR NO. OF PASSES
C *** ONLY ALLOW 1 TUBE PASS TO SAVE TIME
C **« DO 600 NP=1,2
NP=1
IF(KCOND - 2)90,70,90
70 IF(NP-2)90,80,90
80 IF(NSER-1(90,600,90
90 CONTINUE
62470
62-100
62490
62500
62510
62520
62530
625('.,0
62B70
625HO
62590
62600
62610
62620
62630
62640
62650
62660
62670
62680
62690
62700
62710
62720
62730
62740
62750
62760
62770
627HO
62790
62t!00
62810
62820
62830
62840
62850
62860
62870
62880
62890
62900
62910
62920
62930
62940
62950
62960
-------
Z N P - N P
C *** ONLY DO 3 MIDDLE TUBE DIAMETERS TO SAVE TIME
C *** DO 500 1=1,5
DO 500 1=2,4
C *** SET STARTING VELOCITY TO MAXIMUM-VSTART = VMAX
C *** VT - TUBE SIDE VELOCITY BASED ON INLET CONDITIONS
VT = VMAX
DTO = DTOA(I)
DTTH = DTTHA(KGAGE)
BWG = BWGA(KGAGE)
DTI = DTO - 2. * DTTH
KCOUN = 0
DELV = 0.5
KER = 0
DPTOT = 0.0
COST = 0.0
SCCT = 0.0
CST = 0.0
C *** AX = AREA BASED ON THE INSIDE DIA. OF TUBE
AX =.7854 *(DTI/12.0)**2
C *** CA LCULATE NO. OF TUBES
100 CONTINUE
C *** IDN = DESIGN NUMBER
KOUNT = KOUNT + 1
IDN = KOUNT
C +** NT - NO.OF TUBES PER SHELL BASED ON INLET VELOCITY.VT
NT = WT/((VT*3600./ZNP)*AX*DEN)
ZNT = NT
C *** CALCULATE CROSS-SECTIONAL AREA
AXT = AX * ZNT/ZNP
GT = WT/AXT
C *** CALCULATE TUBE SIDE REYNOLDS NO.
RE = GT * DTI/(29.0*VIS)
C CALCULATE SURFACE AREA PER UNIT LENGTH
ASL = ZNT * PI * DTO/12.0 * ZNS
C *** CALL UCOND TO CALCULATE OVERALL COEFFICIENT
CALL UCOND(VT.UCLN,DTO,TTIN,KMETL,KGAGE,UBASE,FTEMP,FMETL)
UO = CLFAC + UCLN
IF(KCOND-1)120,120,130
C CALCULATE AREA REQUIRED
C *+* SINGLE PRESSURE CONDENSER
120 AREO = 0/(UO * TLM)
GO TO 150
C *** MULTIPRESSURE CONDENSER
130 CALL SCDSMP(TSAT,TUN,TOUT,VT,Q, WT , DTO , KMET L , KGAGE ,
1CLFAC.TS1,TS2,PS1.PS2.AZ1,AZ2,Q1,Q2,AREQ,FRAC,PSMAX,PSMIN,
2TLM.TLM1,TLM2,TR1,TR2,U01,U02,TIN2,FRAC2)
C WRITE(6,900)
150 KCOUN = KCOUN + 1
IF(KCOUN-20)200,300,300
62970
62980
62990
63000
630 10
63020
63030
63040
63050
63060
63070
63080
63090
63 1 00
631 10
631 20
63130
63140
63150
63160
631 70
63180
631 90
63200
63210
63220
63230
63240
632bO
63260
63270
63200
63290
63300
63310
63320
63330
63340
63*350
63360
63370
63380
63390
63400
63410
63420
63430
63440
63450
63460
-------
200 CONTINUE 63470
C CALCULATE TUBE LENGTH REQUIRED 63400
TLREQ =r AREQ/ASL 63490
C MAKE TLREQ A ROUND FIGURE - UPWARD 63500
K = TLREQ + 0.5 63510
TL = K 635PO
C *** CHECK TO SEE IF TUBE LENGTH IS LESS THAN WIN. LENGTH REQUIRED 63530
IF(TL-TLM1N)210,225,225 63540
C *+* IF LESS,SET ERROR CODE AND EXIT 63550
C SET ERROR CODE 63560
210 KER=2 635/0
GO TO 400 63580
C CHECK TO SEE IF TUBE LENGTH GREATER THAN TLMAX 63590
225 IF(TL-TLMAX)250,250,230 63600
C IF GREATER, REDUCE TUBE SIDE VELOCITY BY 0.5 63610
230 VT = VT - DELV C3620
C CHECK TO SEE IF TUBE SIDE VELOCITY IS LESS THAN VMIN 63630
IF(VT-VMIN)235,100,100 63640
C IF LESS .EXIT OTHERWISE CONTINUE 63G50
C SET ERROR CODE 63G60
235 KER=3 63670
GO TO 400 636HO
250 CONTINUE 63690
C CALCULATE TOTAL SURFACE AREA 63700
ASTOT = TL * ASL 63710
DL = 12.0 * TL 63720
C CALCULATE TOTAL PRESSURE DROP 63730
CALL DPSEN(DTI,DL,0,GT,RE,0.,DEN,DUM1,DP,DUM2) 63740
DPTOT = (2.0*DEN *VT**2/(2.0*GC)/144.0 +DP)*ZNP 63750
DPTOT = DPTOT * ZNS 63760
C *** CALCULATE CONDENSER COST BY CALLING SCSBP 63770
CALL SCSBP(DTQ,DTI ,KMETL.MN.T L.SCCT,CST,COST,NT,PR,KCOND,WTOTL, 63780
IKER.ZNS.CSTPB.CPLI) 63790
C *+* TOTAL COST OF CONDENSER AND TUBES 63800
GO TO 400 63810
300 CONTINUE 63820
C SET ERROR CODE 63830
KER=1 63840
400 CONTINUE 63850
C WRITE(6,1000)NP,NT,DTO,TL,TLREQ,VT,UCLN,UD,DPTOT.COST,ASTOT,KCOUN. 63860
C 1KERR.NSER,SCCT,CST,IDN 63870
C M = M + 1 63890
IF(M-50)410,405,405 63890
405 WRITE(6,800) 63900
M = 0 63910
410 CONTINUE 63920
IF(VT.LT.VMIN) GO TO 419 63930
IF(VT.GT.VMAX) GO TO 419 63940
IF(DPTOT.GT.DPMAX) GO TO 419 63950
IF(KER)415,415,500 63960
-------
415 CONTINUE
CNEW(14)=COST
C *** DETERMINE KW FOR PUMP POWER FOR CONDENSER
XKW=WT*DPTOT/CPEFF/1151142.
C *** FIND CAPITAL,CAPACITY, AND OPERATING COST. CMAIN IS THE
C *** AVERAGE WEIGHTED COST OF POWER PER KW PER YEAR
COST =1000. *COST*AFCR1+XKW*CAPCST*AFCR2+XK'*'*CMAIN/1000.
COST=COST/1000.
CNEW(1)
CNEW(2)
CNEWI3)
CNEWI4)
CNEW(5)
CNEW(7)
CNEWI8)
CNEW(9) =
CNEW(10) =
COST
NP
NT
DTO
TL
ION
VT
WTOTL/2000.0
UO
DPTOT
41 9
C ***
C ** *
C +* *
420
C ** *
430
500
600
700
CNEW(!1) = ASTOT
CNEW(12) = NSER
CNEW(13)=GT
CNEW(15)=FRAC
CALL STORE(3,15,CITEM,CNEW)
CONTINUE
CHECK IF TOTAL PRESSURE DROP GREATER THAN MAX. PRESSURE DROP
1F(DPTOT-DPMAX)420,420,430
IF PRESSURE DROP GREATER,REDUCE THE VELOCITY
OTHERWISE CHECK TO SEE IF VELOCITY LESS THAN VMIN
IF IVT-VMIN)500,500,430
IF LESS THAN OR EQUAL,CONTINUE OTHERWISE REDUCE THE VELOCITY
VT = VT - DELV
GO BACK AND RECALCULATE NT
GO TO 100
CONTINUE
CONTINUE
CONTINUE
IF(CITEM(1
1).GT,
,99E30)CALL ERORF ( KER,KERR,KGO,MM)
IF(KNTR1-1)750,710,750
710 CONTINUE
PSAT=PSL(TSAT)
CALL OUTPUT(WT.TTIN,TOUT,CLFAC,VMIN,VMAX,TLMIN,TLMAX,TSAT,0,
1CITEM,CNEW,NPAGE,DAY,DPMAX.TLM,DPTOT,PSAT,PS 1 ,PS2,KCOND,
1KMETL,MN,BWG,
2TS1.TS2.TLM1,TLM2,U01.U02.TR1,TR2,FRAC,FRAC2,TIN2,PSMIN,PSMAX)
750 CONTINUE
800 FORMAT(128H1 NP NT DTO TL TLREQ VT UCLN UO
1DP COST ASTOT KCOUN KERR NSER SCCT CST
2IDN )
RETURN
END
63970
63980
63990
64000
6401 0
64020
64030
64040
64050
64060
64070
64080
64090
64 1 00
64 1 1 0
64120
64'
64
64
64
64'
64'
64
30
40
50
60
70
180
1 90
64200
64210
64220
64230
64240
64250
64260
64270
64280
64290
64300
64310
64320
64330
64340
64350
64360
64370
64380
64390
64400
64410
64420
64430
64440
,64450
64460
-------
-pa
GO
SUBROUTINE SCDSMPITSAT,TTIN,TOUT,VT,QDUT,WT,DTO,KMETL,KGAGE, 64470
1CLFAC.TS1.TS2.PS1,PS2,AZ1,AZ2,Q1,Q2IAREQ,FRAC,PSIVIAX,PSMIN, 64480
2TLM,T LM1 ,TLM2.TR1 ,TR2.U01 ,U02,TIN2,FRAC2) 64490
C *** TH15 S/R IS A DESIGN ROUTINE FOR MULTI PRESSURE CONDENSER 64500
COMMON IDUM.KGO, IDUM1(4),D1(3) , IDUM2 , KER,KERR(20 ) ,ID1 (4),MM, ID2(7 ) 64510
1 .D2(1218) 64520
DIMENSION Y(10),TS(10) 64530
PSAT = PSL(TSAT) 64540
KODEFR = 0 64550
C *** SET FRAC CONVERGENCE COUNTER 645GO
LFRAC = 0 64570
C *+* INITIAL VALUE OF FRAC 64580
FRAC = 0.5 64590
C *** SET AREQ TO HIGH VALUE SO IT PASSES CHECK AT STATEMENT 590 LATER 64600
AREQ = 1 . E30 64'? 1 0
C *** SET INCREMENT FOR FRAC 64620
DELFR = 0.01 64630
C *** FRAC CONVERGENCE LOOP STARTS HERE 64640
50 LFRAC = LFRAC + 1 64650
AREQ1 = AREQ 64660
C *** CALC. ZONE ONE HEAT DUTY 64670
01 = FRAC * OOUT ^ 64-580
CALL PPAUT1(TTIN,CP,DEN,TKL,VISL.KODE) 64690
C **•* CALC. OUTLET TEMP. FROM ZONE ONE -EQUALS INLET TEMP. TO ZONE TWO 64700
TOUT1 = Q1/(WT * CP) +• TTIN 64710
C *** CALC. OVERALL COEFFICIENT FOR ZONE ONE 64720
CALL UCOND(VT.UCLN.DTO,TTIN,KMETL,KGAGE,UBASE,FTEMP.FMETL) 64730
U01 = CLFAC * UCLN 64740
C +** SET ZONE ONE OUTLET TEMP. EQUAL TO ZONE INLET TEMP. 64750
TIN2 = TOUT1 64760
X=TIN2+460. 64770
DEN2=53.34+4.40127E-2+X-5.1085E-5+X*X 64780
VT2 = VT * DEN/DEN2 64790
C **+ CALC. ZONE TWO OVERALL COEFFICIENT 64BOO
CALL UCOND(VT2,UCLN,DTO.TIN2,KMETL,KGAGE,UBASE,FTEMP,FMETL) 64810
U02 = CLFAC * UCLN 64820
C *** FIRST GUESS FOR STEAM TEMP. TO ZONE ONE-SET COUNTER FOR 64830
C NEWTON-RAPHSON CONVERGENCE ROUTINE 64840
NR = 1 64850
TS( 1 )=(TOUT1+TSAT )/2. 648i,0
C *** MAIN LOOP ON TS1 STARTS HERE 64870
100 IF(NR-2)130,110,130 64800
110 IF(Y(1))115,120,120 64890
115 TS(2)=(TSAT+TS(1))/2. 64900
GO TO 130 64910
120 TS(2) = (TOUT1+TS(1 ))/2. 64920
130 TS1=TS(NR) 64930
TITD1 = TS1 - TTIN 64940
TTD1 = TS1 - TOUT1 64950
TLM1 =(TOUT1-TTIN)/ALOG(TITD1/TTD1) 64960
-------
c ***
CALC .
AZ1 =
PS1 =
P52 =
TS2 =
TITD2
TTD2 =
ZONE ONE
Q1/(TLMt
P5L(TS1 )
(2. * PSAT
TSL(PS2)
= TS2 - TIN2
TS2 - TOUT
SURFACE
+ U01 )
AREA
-PS1
TLM2 = (TOUT- TIN2)/ALOG(TITD2/TTD2)
C *+* CALC. ZONE TWO SURFACE AREA
AZ2 = QD'JT *(1.0 - FRAC)/(U02 * TLM2)
V(NR ) = 1.0 - AZ1/AZ2
C WRITE(6,1000)TS1 ,TS2,AZ1,AZ2,Y(NR),NR
CALL NRCON(NR,TS,Y,KER,28,.01,KODE,10)
IF(KODE-1)100,160,150
150 CALL ERORF(KER,KERR,KGO,MM)
160 CONTINUE
C *** CALC. AREA REQUIRED FOR CONDENSER
AREQ = AZ1 + AZ2
C **+ DONT ALLOW FRAC .LT. .45
IF(FRAC-.45)700,700,340
C *** FIRST ITERATION IN FRAC LOOP-SKIP THE PRESSURE CHECKS
340 IF(LFRAC-11590,590,350
350 IF(KODEFR-1)400,700,400
400 IF(PS1 - PSMIN)500,550,550
500 FRAC = FRAC + DELFR
KODEFR = 1
GO TO 50
550 IF(PS2 - PSMAX)590,590,500
590 IF(AREQ - AREQ1)600,700,500
600 FRAC = FRAC - DELFR
GO TO 50
700 CONTINUE
TLM = 0.5*(TLM1 +TLM2)
TR1 = TIN2 - TTIN
TR2 = TOUT - TIN2
FRAC2 =1.0- FRAC
C WRITE(6,900)TS1,T52,PS1,PS2,AREQ,AZ1,AZ2,FRAC.NR
RETURN
END
64970
64980
64rJ'»0
65000
65010
65020
65030
65040
65050
650GO
65070
65080
65090
65
65
65
65
65
00
10
20
30
40
65 50
65
65
60
70
65100
651 90
65200
65210
65320
65230
65240
65250
65260
65270
65280
65290
65300
65310
65320
65330
65340
65350
-------
I
I—>
en
SUBROUTINE SCMPR( TSAT,QTOT,WT,CLFAC,KMETL,KGAGE,PSMAX , PSMIN , ASTOT 65360
1,DTO,GT,GTITD,FRAC,TQUT,TTIN) 65370
COMMON IDUM.KGD, IDUM1 (4) , D1(3 ) , IDUM2 , KER,KERR(20 ) . ID1 (4 ) ,MM,ID2(7) 65380
1.02(1218) 65390
C *** RATING OF MULT I-PRESSURE CONDENSERS 65400
DIMENSION T(10),Y(10) 65410
C *** INPUT ITEMS ARE- 65420
C PSAT - AVG. SATUTATION PRESSURE AT STEAM INLET 65430
C QTOT - TOTAL HEAT TO BE REJECTED BY SURFACE CONDENSER 654-10
C WT - TOTAL WATER FLOW RATE LB/HR 65450
C GT - WATER MASS VELOCITY IN TUBES ,LB/HR-FT2 654GO
C ASTOT - TOTAL OUTSIDE SURFACE AREA ,FT2 65470
TAV = 0.0 65480
C *** ASURF - SURFACE AREA PER ZONE 65490
ASURF = ASTOT * 0.5 65500
PSAT = PSL(TSAT) 65510
NR = 1 65520
C *** FIRST GUESS 65530
T(1)=GTITD 65540
c *** MAIN LOOP TO CONV. ON STEAM TEMP.,TSI.STARTS HERE es5bo
90 TTD = TI,NR) 65560
TOUT=TSAT-TTD 65570
CPAV = 1.0 65580
C **+ INITIALIZE COUNTER FOR CONVERGENCE 65590
LQ = 0 65600
C *** TR - WATER TEMP. RANGE 65610
100 TR = QTOT/(CPAV * WT) 65G20
LQ = LQ + 1 65630
TTIN=TOUT-TR 65640
TAV1 = TAV R5650
C *** CALC. CIRCULATING WATER AVG. TEMP. 65660
TAV = 0.5 * (TTIN + TOUT) 65670
X=TAV+460. 65680
CPAV=1.191328-7.002932E-4+X+6.3408E-7+X*X 65690
C *** CONVERGE ON AVG. HEAT CAPACITY ,CPAV 65700
IF(ABS(1.-TAV1/TAV)-.001)150,150,120 65710
120 IFUQ - 5)100,150,150 65720
150 TOUT1 =(QTOT * FRAC)/(WT * CPAV) + TTIN 65730
C *** CONVERGE ON CORRECT CP 65740
X=.5*(TOUT1+TTIN)+460. 65750
CP1=1.191328-7.002932E~4*X+6.3408E~7*X*X 65700
IF(ABS(1.-CPAV/CP1)-.004)158,158,155 65770
155 LQ=LO+1 657RO
IF(LO-10)156,158,158 65700
156 CPAV=CP1 65800
GO TO 150 65810
158 CONTINUE 65820
C +** FIRST ZONE RATING 65B30
C *** CALC. PERF. OF ZONE ONE - FIND STEAN TEMP..TS1 65840
CALL SCRATG(TTIN,WT,U01 ,ASURF, TS1,TOUT 1,01 ,GT,PS 1 ,VT, 65850
-------
1KMETL,KGAGE,CLFAC,DTO,TR1)
C *** SET ZONE ONE OUTLET WATER TEMP. EQUAL TO ZONE TWO INLET
TIN2 = TOUT1
C *** SECOf.D ZONE RATING
C **+ CALC. PERF. OF ZONE TWO - FIND STEAM TEMP. ,TS2
CALL SCRATG(TIN2,WT,U02,ASURF, TS2,TOUT,Q2,GT,PS2 , VT,
1KMETL,KGAGE,CLFAC,DTO.TR2)
PSAV = (PS1 + PS2) * 0.5
Y(NR) =(1.0 - PSAT/PSAV)
C WRITE(6,1200)TTIN,TOUT,TS1,TS2.NR,Y
KODE=100
CALL NRCON(NR,T,Y,KER,29,.007,KODE,10)
IF(KODE-1)160,200,190
160 IF(NR-2)180,180,90
180 T(2)= TTD/(1.-Y(1))
GO TO 90
190 CALL ERORF(KER,KERR,KGO,MM)
200 CONTINUE
RETURN
END
65060
65870
65080
65890
65900
65 '.11 0
65920
65930
65'T'10
65950
65960
65970
65930
65990
66000
6601 0
66020
66030
66040
66050
I
I—»
cr>
SUBROUTINE SCRATG(TTIN,WT,UO,ASURF, TSTM,TOUT,QZ,QT , PSTM,VT,
1KMETL.KGAGE,CLFAC,DTO,TR)
C *** THIS S/R RATES THE PERFORM. OF A ZONE IN MULT I-PRESSURE SURF.
C **+ CONDENSER
C *** INPUT ITEMS ARE -
C TTIN - CIRCULATING WATER INLET TEMP.
C WATER MASS VELOCITY IN TUBES, LB/HR-FT2
CALL PPAUT1(TTIN,CPL,DEN,TKL.VISL,KODE)
C *** VELOCITY ENTERING THIS ZONE OF CONDENSER ,FT/SEC
VT = GT/(3600. * DEN)
C *"* CALC. OVERALL CLEAN COEFF. FOR THIS ZONE
CALL UCOND(VT,UCLN,DTO,TTIN,KMETL,KGAGE,UBASE,FTEMP,FMETL)
UO = CLFAC * UCLN
C *** CALC. NTU OF THIS ZONE
XNTU = UO * ASURF/(WT * CPL)
XK = EXP(XNTU)
R = 1.0 -(1.0/XK)
C *** CALC. RANGE- TR IN THIS ZONE
TR = TOUT - TTIN
C *** CALC. ITD IN THIS ZONE
TITO = TR/R
66060
66070
66080
66090
66 1 00
66
66
66
66
66
66
66
66
66
10
20
30
40
50
60
70
80
90
66200
66210
66220
66230
66240
66250
66260
-------
C *** CALC. STEAM SAT. TEMP. IN THIS ZONE.TSTM
TSTM = TTIN + TITO
C *** CALC. STEAM SAT. PRESSURE IN THIS ZONE.PSTM
PSTM = PSL(TSTM)
RETURN
END
66270
66280
66290
66300
66310
66320
I
I—>
-pa
C
C
C
C
C
C
C
C
C
SUBROUTINE SCSBP ( DTD , DT I , KMET L ,MN , T L , SCCT ,CST,COST,NT,PR,KCOND,
1\»ITOTL,KERR,ZNS,CSTPB,CPLI)
*** THIS SUBROUTINE CALCULATES THE SURFACE CONDENSER SHELL BASE PRISE
*** KMETL - TUBE MATERIAL CODE
*** NT = NO. OF TUBES
DTO = TUBE DIAMETER IN FT.
PR = SHELL BASE PR ICE , DOLLARS
DIMENSION FMM(24,6)
DIMENSION DENN( 1 3 ) ,CPL( 13)
DIMENSION KDENA(6)
DATA DENN/ .308, . 323, .099, .301 , .295, .303,. 323,. 323,. 2833,. 280,. 290,
1 .290, . 163/
DATA CPL/1. 44. 1.5. 1.0,1. 50, 3. 2,2. 21, 1.71,2. 11,1. 47, 2. 94, 2. 94, 2. 94,
16. 62/
DATA KDENA/6 ,9, 1 1 , 1 2,5,7/
*** KMETL = CODE NO. OF TUBE MATERIAL
1 ^ADMIRALTY; 2 ^ARSENICAL CU ; 3 = AL.; 4 =AL. BRASS; 5 -AL. BRONZE
6 =MUNTZ: 7 =90/10 CU-NI; 8 =70/30 CU-NI; 9 =CARBQN STEEL;
10 =410 S/S; 11 =304 S/S; 12 =316 S/S; 13 =TITANUM
DATA FVM/0 .0,0.0,0.0,0.0,0.0,0.0,0.0,0.0,0.0,0.0,0.0,0.0,0.0,0.0,
10. 0, 0. 0, 0. 0, 0. 0, 0. 0, 0. 0, 0. 0, 0. 0,0. 0.0.0,-. 056,-. 072, - . 08B , - . 061,
2-. 078, -.09 5, -.06 6, -.084, -.102, -.070, -.090, -.110, -.075, -.08 6, -.117,
3- 082 - 1 04 , - . 1 26 . - . 087 ,-. 1 1 0 , - . 1 33 , - . 089 , - . 1 1 2 , -. 1 36 , . OOH , . 009
4. 009, .010,. 010, .010,. 011, .011, .011. .012, .012, .012, .01 3, .013, .013,
5.014, .014, .014, .015, .015, .015, .016, .016, .016, .054, .059, .064, .061 ,
6.066, .071 , .067, .072, .077, .072, .077, .082 , .079, .083, .087, .058, .092,
7. 096, . 094, . 097, . 100, . 101, . 104, .107, .117,. 147, .177,. 130, .167, .204,
8. 143, .183, .223, .153, .196, .239, .170, .213, .256, .190, .233. .276, .206,
9. 250, . 294, . 216, . 267, . 311, . 069, . 08 1,. 093, .077,. 091, .105,. 086, .099,
A. 1 12, .092, .106, .120, .101 ,.114, .127, .113, .127, .141..122..136, .150,
A. 130, . 144, . 158/
KERR = 0
FM = 0.0
PR = 0.0
PI = 3.141592654
66330
66340
66350
66360
66370
66380
66390
66 ''.00
6641 0
66420
66430
66440
66450
66400
66470
664HO
66490
66500
66510
66520
60530
66540
66550
66560
66570
66580
66590
66600
66610
66620
66630
66640
66650
66660
66670
-------
-p.
CO
C *** TUBE SHEET DENSITY, LB/CU.INCH 66680
KDENTS = KDENA(MN) 66690
DENTS = DENN(KDENTS) 66700
C *** CALCULATE LENGTH CORRECTION FACTOR TO BE APPLIED TO BASE PRICE 66710
C *** FCL = LENGTH CORRECTION FACTOR 66720
C *** TL = TUBE LENGTH IN FT. 66730
C *** SET WIN. AND MAX. LENGTH FOR COSTING S/R ONLY 66740
TLMIN = 20.0 66750
TLMAX = 110.0 66760
IF(TL - TLMIN)400,32 ,32 66770
32 IF(TL - TLMAX)40,40,400 66780
40 FCL = 0.01544*TL +0.57111 66790
C **+ OBTAIN TUBE SHEET MATERIAL FACTOR PER WESTINGHOUSE 66800
C +** NT = NO. OF TUBES 66810
ZNT = NT 66820
C **+ iVIN - MATERIAL CODE - 1 =MUNTZ ; 2=CARBON STEEL: 3=STAINLESS 304; 6G830
C *** 4 = STAINLESS 316; 5 = ALUMINUM BRONZE; 6 =90-10 COPPER NICKEL 66840
C *** BASE PRICES INCLUDE MUNTZ METAL TUBE SHEET WITH A THICKNESS EQUAL 668bO
C TO THE TUBE DIAMETER PLUS 1/8IN. THE MATERIAL FACTOR IS TO 66860
C CHANGE THE STANDARD THICKNESS MUNTZ METAL TUBE SHEET TO A STANDARD 66870
C THICKNESS TUBE SHEET OF A DIFFERENT MATERIAL. 66880
C *** FM = MATERIAL FACTOR 66890
C *** ADD MULTIPLIER FOR OVER 50000 TUBES-USE 50000 AS BASE AND 66900
C *** INCREASE BY 5( FOR EACH 10000 66910
FMULT = 1.0 66920
IF(NT-50000)17,17,16 66930
17 IF(NT-40000)2,1,1 66940
1 K = 25 66950
GO TO 20 66960
2 IF(NT-30000)4,3,3 66970
3 K = 22 66980
GO TO 20 66990
4 IF(NT-20001)6,5,5 67000
5 K = 19 67010
GO TO 20 67020
6 IF(NT-15001)8,7,7 67030
7 K = 16 67040
GO TO 20 67050
8 IF(NT-12501)10,9,9 67060
9 K = 13 67070
GO TO 20 67080
10 IF(NT-10001)12,1 1 , 11 67090
1 1 K = 1 0 67100
GO TO 20 671 10
12 IF(NT-8001)14,13,13 67120
1 3 K = 7 67130
GO TO 20 67140
14 K = 4 67150
GO TO 20 67160
16 K = 25 67170
-------
FM'JLT = (ZNT-5E4) * 1.05E-4
20 IF(DTO-0.880)21,21,22
21 K = K-3
GO TO 30
22 IF(DTO-1.125)23,23,24
23 K = K-2
GO TO 30
24 CONTINUE
25 K = K-1
30 FM = FKMIK.MN) * FMULT
C *** CALCULATE SHELL BASE PRICE IN DOLLARS -PR
IF(DTO-0.750)45,45,50
45 PR = 7.6958333 + ZNT + 97125.0
C EQUATION GOOD FROM 6000 TO 30000
GO TO 100
50 IFIDTO-O.380)55,55,60
55 PR = 8.794123 *2NT + 102235.29
C EQUATION GOOD FROM 6000 TO 40000
GO TO 100
60 IF(DTO-1.05)65,65,70
65 PR = 10.836364 *ZNT + 102181.82
C EQUATION GOOD FROM 6000 TO 50000
GO TO 100
70 IF(DTO-1.13)75,75,80
75 PR = 12.954545 *ZNT + 103272.73
C EQUATION GOOD FROM 6000 TO 50000
GO TO 100
BO PR = 15.223256 *ZNT + 102237.21
C EQUATION GOOD FROM 7000 TO 50000
100 CONTINUE
C CALCULATE WT./FT. -WPF LB/FT.
WPF = (DTO**2-DTI**2)*PI/4.0 *1 2 . 0 *DENN(KMETL)
C DEFINE COST PER LB -CPLB
C *** CHECK TO SEE IF COST/LB IS GIVEN AS INPUT
C IF GIVEN CONTINUE OTHERWISE USE CPL ARRAY
C DEFINE TOTAL COST OF TUBES -CST
CSTPB = CPLI
IF(CPLI-.0001 )110, 110,120
CSTPB = CPL(KMETL)
CONTINUE
ADD G AND A FACTOR OF
CST = 1.15 *(WPF * TL
1 1 0
120
C ** *
c ***
125
C *+*
c * + *
126
C * * *
15 PERCENT TO TUBE COST(GENERAL ACCOUNTING)
i . ,D -vwrr - iL * CSTPB * ZNT)
KCOND - KODE FOR TYPE OF CONDENSER-1=SINGLE PRESSURE,2=MULTI-PRESS
IF(KCOND - 1)130,130,125
IF(ZNS-1.1)126,126,128
FMF = MULTIPRESSURE CONDENSER FACTOR
ONE CONDENSER
FMF = 0.08
GO TO 200
TWO CONDENSERS IN SERIES
67 1 BO
671 QO
67200
67210
67220
67230
67240
67250
67260
67270
67280
67290
67300
67310
67320
67330
67340
67350
67360
67370
67380
67390
67400
67410
67420
67430
67440
67450
674GO
67470
67480
67490
67500
67510
67520
67530
67540
67550
67560
67570
67580
67590
67600
67610
67620
67630
67640
67650
67660
67670
-------
CJ1
o
128 FMF = 0.073 67680
GO TO 200 67690
130 FMF = 0.0 67700
200 CONTINUE 67710
C *** HERE WE ADD 0.8 TO THE CORRECTION FACTORS TO ACCOUNT FOR THE 67720
c **+ FOLLOWING - WATER BOX TYPE FACTOR 67730
c +** METHOD OF ATTACHMENT FACTOR 57740
C **+ WATER BOX DESIGN PRESSURE FACTOR 67750
C *** SHELL AND TUBE SUPPORT ALTERNATE MATERIAL FACTOR 67760
C *** CONDENSATE DEPTH FACTOR 67770
c *** SHELL AND WATER BOX PREPARATION FACTORS 67780
C *** ACCF - ACCESSORIES FACTOR TO ACCOUNT FOR ALL OF THE ABOVE 67790
ACCF = 0.8 " 67800
C *** ADD 1.22*PR TO BASE PRICE FOR EXTRAS AND INCLUDE DISCOUNT 67810
C MULTIPLIER =0.88 OF FEB 1976 67820
C *** SCCT IS COST OF CONDENSER AFTER APPLYING ALL THE FACTORS 67830
SCCT = 1.22 *(PR MFM +FCL + FMF +ACCF)) 67840
C *** DETERMINE COST OF CONDENSER INSTALLATION 67850
C *** CINSTL = COST OF INSTALLATION 67860
C *** CINSTL IS ASSUMED EQUAL TO 2 * CONDENSER BASE PRICE 67870
CINSTL = 2-0 + PR 67880
C **+ COST = TOTAL COST IN THOUSANDS OF DOLLARS-COMPRISES OF THE 67890
C **+ CONDENSER SHELL BASE PR ICE(SCCT) ,COST OF TUBES(CST),AND COST OF 67900
C *** INSTALLATION-CINSTL " 67910
COST = (SCCT + CST + CINSTL)* ZNS/1000.0 67920
C *** CALCULATE TOTAL WEIGHT OF TUBES 67930
WTUBE = WPF * TL ' ZNT 67940
C *** ASSUME TUBE SHEET THICKNESS =DTO+1/8INCH. = DTS 67050
DTS = DTD + 0.125 67960
C *** ASSUME TUBE SHEET AREA = 5+AREA OF TUBES = ATS 67970
ATS = 5.0 +ZNT + PI/4.0 * DTO**2 67980
C **+ CALCULATE WEIGHT OF TUBE SHEETS 67990
WTSHT = ATS * DTS * 2.0 + DENTS 68000
C *+* WTS =WEIGHT OF TUBE SUPPORTS,ASSUME FACE AREA SAME AS TUBE SHEET 68010
C *** ZNTS= NO.OF TUBE SUPPORTS-ASSUME EVERY 3FT. 6B020
ZNTS = IFIX(TL/3.0-0.5) 68030
C *** THICKNESS OF TUBE SUPPORTS =.625 INCH AND MATERIAL OF CARBON STEEL 68040
WTS = ZNTS * .625 *ATS * .2833 68050
C *** ESTIMATE TOTAL WEIGHT OF CONDENSER PER SHELL 68060
WTOTL = 1.50 *(WTUBE+WTSHT+WTS) 68070
GO TO 800 68080
C *** TUBE LENGTH IS OUTSIDE SPECIFIED LIMITS -SET ERROR CODE -4 68090
400 KERR = 4 68100
800 RETURN 68110
END 68120
-------
SUBROUTINE SETUP(J,KN,LJ)
COMMON/EPA/TNMIN,TNMAX,TSAT(21 ) ,C05TT(21 ) ,X(10,21 ),XC(10),VAMAX
1VAMIN,VWMAX,VWMIN,XN,XP,SUBCL,QMIN,QMAX,PITCH,DIA,
2RNGMX,RNGMN,TLMIN,TLMAX,TITDX,TITDN,TSATA,TSATZ,XHEAT(21)
COMMON IDUMW(2),KNTRO,IDUM(2),NPAGE,DAY(2).DUMP,IDUM1(34)
COMMON DUME(171),FALT,DUME2(1040)
COMMON/ RAND/SEED , X.MODU , XNUM
COMMON/SCOND/TTDMN,TTDMX,TISUM(21)
C ++* SET UP RANDOM NUMBER CONSTANTS
SEED=567.*19.
XMODU = 2.*+60+1 .
XNUM=5.*+13
A = 0.
DO 100 1 = 1 ,KN
C
C
i
i—>
on
SET UP ORIGINAL COMPLEX OF KN POINTS
30 X(1,I)=TSATA+RNUM(A)*(TSATZ-TSATA)
TSAT( I )=X(1,1)
CALL QTUR6(XHEAT(I),TSAT(I),1.,2)
X(6,I }=TTDMN+RNUM(A)*(TTDMX-TTDMN)
SUBCL=X(6,I)
T1NTO=TSAT(I)-SUBCL
TITD=AMIN1(TINTO+50..TlTDX)
IQGO=0
IRAE=0
KKILL=0
NOUE = 0
IUEE=0
C *** CHECK FOR ITD INCONSISTANCIES
IF(TITDN-TITD)11 , 1 1 ,30
11 CONTINUE
XI 2, I )=TITDN + RNUVl( A ) * ( T ITD-T I TON )
12 RNG=AMIN1(RNGMX,X(2,I)+.99,TINTO-32. )
C *** CHECK FOR RANGE INCONSISTANCIES
IF(RNGMN-RNG)36,36,33
33 IQGO=IQGO+1
IF(IOGO-15)34,34,30
C *** INCREASE ITD BY 10 DEGREES
34 X(2,I)=X(2,I)+10.
C **+ CHECK THAT ITD WAS NOT INCREASED TOO MUCH
IF(X(2,I)-TITD)l2,12,30
C *** IF RANGE ALREADY HAS A VALUE TRY YO USE IT
36 IF(IRAE)38,38,37
37 IF(X(3,I).GE.RNGMN.AND.X(3,I)-LE.RNG)GO TO 39
38 IRAE=1
X(3,I)=RNGMN+RNUM(A)*(RNG-RNGMN)
39 CONTINUE
C CALCULATE WIN AND MAX TN BY ALLOWING WATER VELOCITY OF 2-10 FPS
C
681 30
681 40
68150
68 160
68 1 70
68 1 80
68 190
68200
68210
68220
68230
68240
68250
682GO
68270
68280
68290
68.^00
68310
68320
68330
68340
6H350
68360
68370
68380
68390
68400
684 10
68'120
68430
68440
68450
68460
68470
6B')80
68490
68500
68510
685?0
68530
68 540
68550
68560
68570
68580
68590
68600
68610
68620
-------
en
ro
C *** CALCULATE AVERAGE WATER TEMPERATURE AND FIND PHYSICAL PROPERTIES 68630
TAV = T INTO-X(3, I )/2. FHfj-lO
CALL PPAUT1(TAV,CPW,DENW.D1,D3,KODE) 68650
TN1=XHEAT(I)*XP/X(3,I )/DIA**2/CPW/DENW/1 96.35 68 '..hO
TN2=XHEAT(I)*XP/X(3,I)/DIA**2/CPW/DENW/39.27 68670
TNN=AMAX1(TNMIN,TN1) 68680
TNX = A"/1IN1 ( TNMAX , TN2) 68690
C **+ CHECK THAT MIN AND MAX FOR NUMBER OF TUBES IS CONSISTANT 68700
IF(TNN-TNX)27,27,20 68710
20 IQGO=IQGO+1 68720
IFIIQGQ.GT.i5)co TO 30 68730
C *** SEE IF MIN NUMBER OF TUBES CAN BE LOWERED BY INCREASING RANGE 68740
IF(TN1-TNMIN)21 .21 ,25 68750
C *** SEE IF MAX NUMBER OF TUBES CAN BE INCREASED BY DECREASING RANGE 68760
21 IF(TN2-TNMAX)22,30.30 68770
22 X(3, I )=X(3, I )-5. 68780
C *** SEE IF RANGE WAS DECREASED TOO MUCH 68790
IF(X(3,I)-RNGMN)30,39,39 68800
25 X(3, I )=X(3. D+5. 68810
C *** SEE IF RANGE WAS INCREASED TOO MUCH 68820
IF(X(3,I)-RNG)39.39,26 68830
C *** IF MAX RANGE DEPENDED ON ITD THEN INCREASE ITD 68840
26 IF( R'JG-X(2 , I ) )34,34,30 68850
C ** + IF NUMBER OF TUBES HAS A VALUE TRY TO USE IT 68860
27 IF(NOUE)29,29,28 68870
28 IF(X(5.I).GE.TNN.AND.X(5,I).LE.TNXJGO TO 90 68880
29 NOUE=1 68890
X(5, I )=TNN + RNUM{A ) *(TNX-TNN) 68900
90 CONTINUE 68910
C 68920
C CALCULATE MIN AND MAX TL BY ALLOWING AIR VELOCITY OF 100-1000 FPM 68930
C AND BY ASSUMING P=.01-1. 68940
C 68950
C +** DETERMINE AIR PHYSICAL PROPERTIES BASED ON AIR INLET TEMPERATURE 66960
TAV=TINTO-X(2,IJ+459.67 68970
T=TAV-459.67 68980
DENA=FALT/TAV*39.68B63 68990
CPA=.2401457+2.48709E-7*T+2.990712E-8*T*T 69000
TL1=XHEAT(I)*XN/X(2,I)/X(5,I)/PITCH/CPA/DENA/5000. 69010
TL2=XHEAT(I)*XN/X(2,I)/X(5,I)/PITCH/CPA/DtNA/5. 69020
TLN=AMAX1(TLMIN,TL1) 69030
TLX=AMIN1(TLMAX,TL2) 69040
C *** SEE IF TUBE LENGTH MIN AND MAX IS CONSISTANT 69050
IF(TLN-TLX)31,31,32 69060
32 IQGO=IQGO+1 69070
IF(IQGO.GT.15)GO TO 30 69080
C *** SEE IF MAX TUBE LENGTH CAN BE INCREASED BY DECREASEING NUMBER OF 69090
C **+ TUBES 69100
IF(TL2-TLMAX)91,92,92 69110
91 X(5.I)=X(5,I)/1.15 69120
-------
U1
GO
C *** SEE IF NUMBER OF TUBES WAS DECREASED TOO MUCH
IF(X(5.I)-TNN)93,90,90
93 IF(KKI LL.NE.0)GO TO 30
C *** SEE IF WIN NUMBER OF TUBES CAN BE LOWERED BY INCREASING RANGE
IF(TN1-TNMIN130,30,25
C *** SEE IF WIN TUBE LENGTH CAN BE DECREASED BY INCREASING NUMBER OF
C *** TUBES
92 IF(TL1-TLMIN)30,30,94
94 X(5,I)=X(5.I)+1.15
C *++ SEE IF NUMBER OF TUBES WAS INCREASED TOO MUCH
IF(X(5 , I ). LE.TNX)GO TO 90
IF(KKILL.NE.0)GO TO 30
SEE IF MAX NUMBER OF TUBES CAN BE INCREASED BY DECREASING RANGE
IF(TN2-TNMAX)22.30,30
IF TUBE LENGTH ALREADY HAS A VALUE TRY TO USE IT
IF( IUEE)98,98,95
IF(X(4 , I).LE.TLX.AND.X(4,I).GE.TLN)GO TO 40
IUEE=1
X(4,I )=TLN+RNUM(A)*(TLX-TLN)
C ** *
c ***
31
95
98
C
C
C
40
c ** *
c
c
c
c
42
C
C
C
C
C
C
FIND OBJECT FUNCTION
CALL COSTER( I , VA I R , VH20 , KKI L L )
LIMIT THE NUMBER OF OUTPUT PAGES TO 200
IF(NPAGE.GE.200) GO TO 200
SEE IF WATER VELOCITY IS BETWEEN WIN AND MAX FT/SEC. IF IT IS NOT
SET NUMBER OF TUBES Sufcn THAT WATER VELOCITY IS ON BOUNDARY.
IF(KKILL) 75,75,42
IQGO= IQGO-t-1
IF( IQGO.GT. 15)GO TO 30
GO TO (94,91 ,55, 60) ,KKILL
SEE IF AIR VELOCITY IS BETWEEN MIN AND MAX FT/MIN
IF IT IS NOT, SET TUBE LENGTH SUCH THAT AIR VELOCITY IS ON
BOUNDARY. IF DOING THAT VIOLATES TUBE LENGTH CONSTRAINT,
TRY TO CHANGE ITD.
55 X(4,I)=X(4,11*1.15
IF(X(4,I)-TLX)40,40,56
56 IF(TL2-TLMAX)30,30,57
C *** SET TUBE LENGTH TO MAX
57 X(4, I )=TLMAX
GO TO 34
60 X(4,I)=X(4,I)/1.15
IF(X(4,I)-TLN)61,40,40
61 IF(TL1-TLMIN)62,30,30
62 X(4,I)=TLMIN
C *** SET TUBE LENGTH TO MIN
AND INCREASE ITD
AND DECREASE ITD
691 30
691 40
691 50
69160
691 70
69180
691 00
69200
69210
69220
69230
69240
69250
69260
69270
69280
69290
69300
69310
69320
69330
69340
69350
69360
69370
69380
69390
69400
69410
69420
69430
69440
69450
69460
69470
69480
69490
69500
69510
69520
69530
69540
69550
69560
69570
69580
69590
69600
69610
69620
-------
I
h-«
Ul
X(2,I)=X(2,I)-10.
IF(X(2,I(-TITDN)30, 12,12
75 CONTINUE
SEE IF COST IS HIGHER OR LOWER THAN PREVIOUS COSTS
IF(COSTT(I).LE.COSTT(d)) GO TO 85
J=I
GO TO 100
85 IF(COSTT(I).GE.COSTT(L>J)) GO TO 100
LJ=I
100 CONTINUE
200 CONTINUE
RETURN
END
69030
69640
69650
69660
69G70
69680
69690
69700
69710
69720
69730
69740
69750
69760
69770
SUBROUTINE START 69780
COMMON NFO,KGO,KNTRO,KNTR1 , NSUM , NP AGE , DA r'( 21 , PI 697"0
COMMON KCI,KER,KERR(20),KFIN,KREG,LAIC,LSUP,MM,NP,NR,NT1.NT2.NTP, 69800
1NTR,rjTT,ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 69810
2,DEN(2),DEN12(2,2),DENFN,DENLZ(7),DBW,DEO,DFH,DFR,DFS,OFT,DKL, 69820
3DLSP,DLTE,DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,PT 69830
COMMON DPAD.DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT,DPTA,DPTF, 69840
1DPTOT(2),POUT(2),PTUB,RV2,GAMAX,GT,HPFNC,HAIR,HTS,UBARE,UCLN,UTOT, 69850
2Q(2),QDUT.QTOT,RKI,RFIN,RFTOT,RTOT,RTW,TAV(2),TIN(2),TOUT(2),TT(8) 69860
3.TWALL.TD,TW,TMTD,TK(2),VAPP,VNZ(2),VT,DFAN,TLTE,AOF,VISLZ(7), 69870
4VISI2),VIS12(2,2>,VISW,W(2),WAPF,WB(2),WLQ(2) 69HHO
COMMON ANG(3),CFH(3),CFP(3),CFR,CKBSC,CKFNG,CKHSC.CKLOV.CKSTC.F, 69890
1FALT,FINEF,FFF,FSUM,OCL(4),ODL(4),OKH4),OML(4),OMV(4),P,PRAN(2), 69900
2PRALZ(7),R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA, 69910
3XREX,ZMP,ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20).ZTPPA 69920
COMMON ZTRD,ANGI ,ZBYP,ZBUP,ZBUS,ZFAN,DFANI ,DIOV,ZNFI ,PTI,TKT,TKF, 69930
1WD(2),VAPPl,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTMIN,OD(7), 69940
2CARD7(6),DNZI(2),PDI,CFNG,CHSC,CLOV,CBSC,PRSTC.RFAIR,RFCT,ZNOZ(2), 69950
3RASPC,ZTPD,ZNTD,COST(7),SSUM(16,30) , ISUM(13,30),PRICE(2,21) 69960
CALL SECOND(DAY(2)) 69970
CALL ZEROA 69980
PI=3.14159 69990
KGO=1 - 70000
KNTR1=0 70010
KNTRO=0 70020
NPAGE=1 70030
-------
NFO = 6
NSUM=0
RETURN
END
70040
70050
70060
70070
on
en
C ** +
c
C
c ***
c
c
c
c ** *
1 0
100
c ***
c * * *
200
c ***
240
c ***
c
c ** *
c
300
c ***
350
SUBROUTINE STORE(NMAX,ITEM,CITEM,CNEW)
DIMENSION CNEW(15) , CITEM(10,15)
THIS S/R LOOKS AT A NEW ARRAY OF ITEMS AND CHECKS IF THE NEW ARRA
SHOULD BE ADDED INTO THE CITEMS MATRIX. THE CITEM MATRIX IS
ARRANGED IN ASCENDING ORDER DETERMINED BY CITEM(I.I) SLOT
INPUT VARIABLES ******
ITEM - NO. OF ITEMS TO BE STORED FROM CNEW INTO CITEM
NMAX - NO.OF STORAGE ITEMS FOR FIRST DIMENSION IN CITEM(NMAX,ITEM)
CNEW(NITEM) NEW ARRAY TO BE INTEGRATED INTO CITEM
DO 100 1=1,NMAX
CHECK IF CNEW(1) IS LOWER THAN CITEM(I,1)
IF(CNEW(1 )-CITEM(I,1 ))10, 100,100
HAVE FOUND THAT CNEW SHOULD BE INTEGRATED INTO THE N SLOT OF CITEM
N = 1
GO TO 200
CONTINUE
AT THIS POINT-THE CNEW(1) IS HIGHER THAN ANY VALUE IN CITEM(I,1)
GO TO 500
INTEGRATE CNEW INTO CITEM INTO N SLOT
CONTINUE
IF N=NMAX DONT HAVE TO PUSH ANYBODY BACK-JUST GO TO FILL-UP AT 350
IFIN-NMAX)240,350,500
CON FINUE
FIRST PUSH
SET UP THE
K=NMAX-N
DO 300 d =
DO 300 1=1,
LAST SLOT WHEN PUSHING BACK
EVERYONE
VALUE OF
BACK ONE SLOT
K THE FIRST SLOT
TO START AT FROM THE BACK
1
,K
THE
ITEM
INFORMATION WILL BE DESTROYED
= CITEM(L,d)
START FROM
SO THAT NO
L=NMAX-I
CITEMt L-t-1 , d)
CONTINUE
NOW INTEGRATE CNEW INTO N SLOT OF C I TEM( N , I TEM )
CONTINUE
DO 400 d = 1 , ITEM
CITEM(N.d) = CNEW(d)
70080
70090
701 00
701 10
701 20
70130
70 1 40
701 50
701 60
701 70
70 180
70190
70200
70210
70220
70230
70240
70250
70? GO
70270
70280
70290
70300
70310
70.320
70330
70340
70350
70360
70370
70380
70390
70400
7041 0
70420
70430
70440
-------
400 CONTINUE
500 RETURN
END
70450
70460
70470
I
(—«
tn
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
SUBROUTINE STRUCT(NTT.TUBKT.ZL,DHEDW,RLL,HTSTR,STLAD,ZBUP,ZBPU,
1CTSTR)
**« THIS SUBROUTINE ESTIMATES THE COST FOR THE STRUCTURE. INCLUDING
»«* GRADING,PAVING,FOUNDATION -f STEEL COST.
*** INPUT VARIABLES •**
DL = BUNDLE LENGTH (FT)
DHEDW = BUNDLE WIDTH (INCH)
NTT = TOTAL NUMBER OF TUBES
TUBWT =r UNIT WEIGHT OF TUBE (LB/FT)
RLL = ROOF LIVE LOAD (LB/FT2)
HTSTR = STRUCTURE HEIGHT (FT)
STLAD = INDEX FOR STEEL COST ADJUSTMENT
ZBUP = NUMBER OF BUNDLES PER BAY
ZBPU = NUMBER OF BAYS PER UNIT
*** OUTPUT VARIABLE ***
CTSTR = STRUCTURE COST ($)
ZTTrNTT
DL=ZL«2.
THE ONLY DATA AVAILABLE is FOR WIND LOAD = 35 PSF, so ASSUME THE
WIND LOAD IS NEAR 35 PSF
CHECK THE WIND MAP FOR ROOF LIVE LOAD. IF LL>20PSF, USE LL=40PSF
DATA. IF LL)20PSF, USE LL=12PSF DATA.
CHECK THE TABLE FOR STEEL PRICE MODIFICATION, INPUT THE ADJUSTMENT
INDEX STLAD
TOTAL WEIGHT OF TUBES
TTUWT=ZTT*TUBWT«DL
WEIGHT OF ONE BUNDLE SECTION
70480
70490
70500
70510
70520
70530
70540
70550
70560
70570
70580
70590
70600
70610
70620
70530
70640
70650
70650
70670
70680
70690
70700
70710
70720
70730
70740
70750
70760
70770
70780
70790
70800
70810
70820
70830
70840
70850
-------
C
c
C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
ACWT1=1.4+TTUWT
WEIGHT PER UNIT AIR COOLER, NOT INCLUDING STRUCTURE
ACWT=ACWT1+ZBUP+ZBPU
PRETEND AS A 45 FT WIDE UNIT, SO THAT THE WEIGHT IN 1000 LB IS
WT452 = ACWT*(45.0 * 120.0*12.0/DHEDW/DL/ZBUP/ZBPU)/1000.0
WT456=ACWT*(45.0*160.0*12.0/DHEDW/DL/ZBUP/ZBPU)/1000.0
DIFFERENT CALCULATIONS FOR DIFFERENT ROOF LIVE LOADS
IF (RLL-20.0) 10,10,20
10 CONTINUE
W*L*H = 45*120*30
CTWT1=23.047*(WT452-268.0)+33510.0
W+L*H = 45*120*50
CTWT2=23.125*(WT452-268.0)+37650.0
W+L'H = 45*160*50
CTWT3=36.8235*(WT456-358.0)+42240.0
W*L»H = 45*160+70
CTWT4=36.8235+(WT456-358.0)+49190.0
GO TO 30
20 CONTINUE
CTWT1=25.625*(WT452-268.0)+37360.0
CTWT2=26.40625*(WT452-268.0)+41410.0
CTWT3=37.4705*(WT456-358.0)+49200.0
CTWT4=36.8235*(WT456-358.0)+56460.0
30 CONTINUE
INTERPOLATE STRUCTURE HEIGHT
W*L - 45*120
CTHT1 =(CTWT2-CTWT1 ) /20- 0*(HTSTR-30.0)+CTWT1
W*L = 45*160
CTHT2=(CTWT4-CTWT3)/20.0*(HTSTR-50.0)+CTWT3
INTERPOLATE STRUCTURE LENGTH
IF (DL-120.0) 32,32,34
32 CONTINUE
CTSTB=(CTHT1-6000.0)/!20.0*DL+6000.0
GO TO 36
34 CONTINUE
CTSTB=(CTHT2-CTHT1)/40-0*(DL-120.0)+CTHT1
36 CONTINUE
CTSTB=CTSTB*DHEDW/540.0*ZBUP
70860
70870
70880
70890
70'.'00
7091 0
70920
70930
70940
70950
709<">0
70970
70980
70990
71 000
71010
71 020
71 030
71 040
71 050
71 OGO
71 070
71 080
71 090
71 100
71110
71 120
71 130
71140
71 150
71 160
71170
71 180
71 190
71 200
71210
71 220
71 ?30
71 240
71 250
71 2GO
71 270
71 2 HO
71 290
71 300
71310
71 320
71 330
71 340
71 350
-------
c
c
c ***
STEEL COST ADJUSTMENT
ADJUST=0.87*CTSTB*STLAD/100.0
CTSTR=CTSTB+ADJUST
CTSTR=CTSTR*ZBPU/2.
ADD 11 PCT. TO INCLUDE GALVANIZING(ADDITIONAL 120 S/TON)
CTSTR=1.11*CT5TR
RETURN
END
71 360
71370
71 380
71 390
71400
71410
71420
71 430
71440
71450
I
I—I
-------
I
I—'
en
C *** ENTER ERROR NO. IN DATA STATEMENT WHICH ARE NOT PERMANENT 71770
DATA KERNO/64,62,70,71,98,79/ 71780
TOL=.005 71790
LSUP1=0 71800
CALL EX INI 71810
IF (KGO-1) 10,10,500 71«?0
1 0 CALL GEOM1 71830
30 LSUP=1 71840
IF(KCI-2)36,80,120 71850
C *** SET UP PARAMETERS TO GUESS TIN(1) 71860
C *** MAKE THE FIRST GUESS FOR ITD SLIGHTLY HIGHER THAN THE DESIGN ITD 71870
36 S(1)=57./SSSUM(9) 71800
ZTIN2 = TCONV(TIN(2) , 1 ,2) 71890
C *+* GIVEN THE SATURATION TEMPERATURE, QTURB FINDS THE 71900
C **+ HEAT REJECT OF THE TURBINE. 71910
38 TTT--ZTIN2 + 60./S( LSUP) 71920
IF(TTT-250.)40,39,39 71930
39 TTT=250. 71940
S(LSUP)=60./(250.-ZTIN2) 71950
40 CONTINUE "1950
C *** IF TTT CONVERGES ABOVE TINMX THEN SUBROUTINE COSTER SHOULD 71970
C **+ CHECK AND ADJUST PLOAD 71980
CALL QTURB(OREJ,TTT,PLOAD.2) 71990
OD(1)=QREJ 72000
C *** SET MM=0 IN CASE PREVIOUS ITERATION HAD KER=23 FROM QTURB. THIS 72010
C *** WILL ALSO DELETE RECORD OF SOME ERRORS IN QBALN FROM LAST TIME 72020
IVM-0 72030
C *** IF CONCT IS ZERO THEN ASSUME A SURFACE CONDENSER IS USED 72040
IFfCONCT-.001)44,44,46 72050
44 CALL SCMPR(TTT,QREJ,W(1 ), CLFAC,KMETL,KGAGE,BCKMX,BCKMN, 72060
1CITEMM,11),CITEM(1,4),CITEM{1,13),GTITD,CITEM(1,15),TIN(1), 72070
2TOUT(1)) 72080
SUBCL=TTT-TIN(1) 72090
GTITD=SUBCL 72100
TD = TIN(1 (-ZTIN2 721 10
TIN! 1 I =TIN(1 (+459.67 72 I 20
TOUT( 1 )=TOUT(1 ) + 459.67 72130
TT( 1 ) = TIN( 1 ) 72140
GO TO 120 72150
C +** FDR JET COND. ASSUME TTD IS PROPORTIONAL TO 0 72160
46 SUBCL=QREJ*X(6,NSUM)/SSUM(B,NSUM)/1.E06 72170
TIN(1 )=TTT-SUBCL 72180
TIN( 1 ) =TCONV(TIN(1 ) , 1 ,1 ) 72190
C *** THE ITD IS CONSTANTLY CHANGING. TD MUST BE SET FOR USE 72200
TD=TIN(1)-TIN(2) 72210
TT(1 ) = TIN( 1 ) 72220
C *** CONVERGE ON CORRECT CP 72230
LQ=1 72240
CPX=1. 72250
45 TOUT(1)=TIN(1)-QREd/W(1)/CPX 72260
-------
XX=.5"(TIN(1)+TOUT(1))
CP1=OCL( 1 )+OCL(2)*XX+OCL(3)*XX*XX
IF(ABS(1.-CP1/CPX)-.004)48,48,47
47 IF(LQ-5)49,48,48
49 LQ = LQ-M
I
i—»
O
48
80
90
C **-
100
110
1 1 2
115
120
123
124
C ***
185
187
c ***
C *
193
194
195
196
197
198
199
200
21 0
90,90,100
112, 112,115
LOWER THAN DESIGN VAPP
, HA I R , CFH , C FR ,
GO TO 45
CONTINUE
GO TO 120
IF (VAPPI-. 1 )
5(1 ) = 1 .
IN FAN CONTROL MAKE GUESS FOR VAPP SLIGHTLY
IF(JAKE.PQ.3)5(1)=721./SSUM(10,NSUM)
GO TO 110
S(11=650./VAPP
IF(S(LSUP)-.350;
KER=11
CALL ERORF(KER,KERR,KGO,MM)
GO TO 500
VAPP=650./S(LSUP)
CALL 05ALN
I Fi. KE<5 ) 124 , 124, 193
GAMAX=VAPP /RAPMX*4.5
CALCULATE AIRSIDE HEAT TRANSFER COEFFICIENT
CALL HTAIR(GAMAX,DFR,VIS(2),REA(2),TK(2),PRAN(2i
1RARAF,FINEF, RFIN)
HAIRD=HAIR
RFIND=RFIN
CALL EXCON
IF IKGO-2) 187,500,187
IF(KER) 210,210,193
CHECK HERE FOR ERRORS FOUND IN QBALN.PPROP, AND MTDOV CAUSED BY
POOR GUESS FROM SUPER
DO 194 1=1,6
IF (KER-KERNO(I)) 194,195,194
CONTINUE
GO TO 200
IF (LSUP-1) 196,196,197
S(1 )=SI1 )* .5
GO TO 198
S( LSUP ) = (S( LSUP)-t-S( LSUP-1 ) )*.5
LSUP1=LSUP1+1
IF (LSUP1-20)199,200,200
KER = 0
GO TO 240
CALL ERORF (KER,KERR,KGO,MM)
GO TO 500
E(LSUP)=FSUM-1.
LSUP1=0
IF(LSUP-2)228,230,230
72270
72280
72290
72300
72310
72320
72330
72340
72350
72360
72370
72380
72390
72400
72410
72420
72430
72440
72450
72460
72470
72480
72490
72500
72510
72520
72530
72540
72550
72560
72570
72580
72590
72600
72610
72620
72630
72640
72650
72660
72670
72680
72690
72700
72710
72720
72730
72740
72750
72760
-------
THEN DO NOT CALL DPAIR OR DPTUB
C **' SIMPLE ITERATION USED FOR SECOND QUESS
220 5(2)=5(11/FSUM
230 CONTINUE
CALL IMRCON(LSUP,S,E,KER,50,TOL,K,20)
IF(K-1 ) 240 , 250,234
234 CALL ERORF(KER.KERR,KGO,MM)
GO TO 500
240 IF(KCI-2)38,110 , 120
C *** END OF SUPER HEAT TRANSFER LOOP
C *** CALCULATE PRESSURE DROPS
C *** IF KKILL IS TO BE SET IN COSTER
250 IF(JAKE.EQ-3)GO TO 260
C *** FOR INITIAL COMPLEX DO NOT LET VAPP GO ABOVE 1000 FPM
IF(IISUM(1).GT.O)GO TO 251
IF(VAPP-1010.)251,251,500
251 CONTINUE
IF(VAPP-(VAMAX+.01 ) ) 255,255,500
255 IF(VAPP-(VAMIN-.01))500,250,260
260 CALL DPAIR
HAIR =HAIRD
RFIN =RFIND
270 CALL DPTUB
500 CONTINUE
2000 RETURN
END
72770
72780
72790
72800
72810
72820
72830
728'40
72850
728^0
72870
72080
72890
72900
72910
72920
72930
72940
72950
72960
72970
72980
72990
73000
73010
FUNCTION TCONV(T,KUNIT,KDIR)
*** TCONV CONVERTS TEMPERATURES TO ABSOLUTE AND VICEVERSA
*** KUNIT=1 - U.S. UNITS , KUNIT=2 - S.I. UNITS
**+ KDIl?=1 - TO ABSOLUTE , KDIR = 2 - FROM ABSOLUTE
«** IF THE TEMPERATURE IS ZERO (=0.0), IT REMAINS ZERO
TCONV=0.0
IF (ABS(T)-1.OE-6) 100,10,10
10 KGO=2*KUNIT-2+KDIR
GO TO (20,30,40,50) , KGO
20 TCONV=T+459.67
GO TO 100
30 TCONV=T-459.67
GO TO 100
40 TCONV=(T+273.15)*1.8
GO TO 100
50 TCONV=T/1.8-273.15
73020
73030
73040
73050
73060
73070
730HO
73090
73100
731 10
731 20
731 30
73140
73150
73160
73170
-------
100 RETURN
END
73180
73190
CTi
ro
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
SUBROUTINE TRANS(NMOT,HPMOT,CTRAN,TRANC)
*** THIS PROGRAM CALCULATE THE COST FOR POWER TRANSMISSION
*** INPUT VARIABLE ***
HPMOT = MOTOR HORSEPOWER
*** OUTPUT VARIABLE ***
CTRAN = COST FOR ONE TRANSMISSION ($)
ZMOT=NMOT
MOTOR HORSEPOWER ON7.5 ,USE DIRECT MOTOR DRIVE
7.5N20.0 USE V-BELT
20.ON USE GEARBOX
IF (HPMOT-7.5) 10,10,20
10 CONTINUE
DIRECT MOTOR DRIVE
THE COST IS SMALL. NEGLECT.
CTRAN=0.0
GO TO 300
20 CONTINUE
IF (HPMOT-20.0) 30,30,40
30 CONTINUE
V-BELT DRIVE
DATA NOT AVAILABLE NOW. USE THE EXTRAPOLATION OF GEAR BOX
40 CONTINUE
GEARBOX DRIVE
INDEX=INT(HPMOT)/25+1
IF(INDEX.GT.8)GO TO 250
GO TO (25,50,75,100,125,150,175,200) INDEX
25 CTRAN=41.6*HPMOT
GO TO 300
50 CTRAN = 47.6*(HPMOT-25.0)-M040.0
GO TO 300
75 CTRAN=66:8*(HPMOT-50.0)+2230.0
73200
73210
73220
73230
73240
73250
73270
732BO
73290
73300
73310
73320
73330
73340
73350
73360
73370
73380
73390
73400
73410
73420
73430
73440
73450
73460
73470
73480
73490
73500
73MO
73520
73530
73540
73550
73560
73570
73580
-------
GO TO 300
100 CTRAN=64.0+IHPMOT-75.0)+3900.0
GO TO 300
125 CTRAN=33.6*(HPMOT-100.0)+5500.0
GO TO 300
150 CTRAN=22.4+(HPMOT-125.0)+6340.0
GO TO 300
175 CTRAN^12.*(HPMOT-150.J+6900.
GO TO 300
200 CTRAN=12.*(HPMOT-175.)+7200.
GO TO 300
250 CTRAN=12.*(HPMOT-200.)+7500.
C
300 CONTINUE
TRANC=ZMOT*CTRAN
C *** ADO 10 PCT. FOR SHIPPING TO MANUFACTURER
TRANC=1.1*TRANC
C
C
RETURN
END
73590
73600
736 10
73620
73630
73640
73650
73660
73670
73680
73690
73700
73710
73720
73730
73740
73750
73760
73770
73780
73790
oo
C
C
C
C
C
FUNCTION TSL(PP)
FROM PP IN INCHES OF MERCURY, FIND THE SATURATION TEMPERATURE IN
DEGREES F. TAKEN FROM PAGE 44 OF *CALCULATIONS OF PROPERTIES OF
STEAM* BY MCCLINTOCK AND SILVESTRI
DIMENSION B(6),T(6)
DATA B/1.52264683,-.682309518,.164114952,-2.02321649E-03,
1-1 . 92391111E-03.-5.74549419E-04/
C *** DO NOT ALLOW PP TO GO ABOVE THE CRITICAL POINT OR
C *** BELOW THE FREEZING POINT
IF(PP.LT..2)PP=.2
IF(PP.GT.6530.)PP=6530.
T(1 ) = 1 .
P=PP/2.036
T(2)=(ALOG(3529.05823/P)**0.4-1.46047125)/(-1 .089944)
Y = 2. *T(2)
W=B(1 )+T(2)*B(2)
DO 2 N=3,6
T(N)=Y*T(N-1 )-T(N-2)
73800
73810
73320
73830
73840
73850
73060
73870
73880
73B'»0
73900
73910
73920
73930
73940
73950
73960
73970
73980
73990
-------
2 W=W+T(N)*B(N)
TSL=1 .8*(647.3/W-273.l5)+32.
RETURN
END
74000
74010
74020
74030
SUBROUTINE TUBEF(KTUBE,KFIN,NFPIN,DTO,DLTTK,DFH,DFT,WTUBE,WFIN,WTU
1BF,ATUBE,BFIN,CTUB1,CTUB,CFIN)
Ol
-P.
c
c ** *
c
c ** *
c ** *
c
c ** *
c
c
c
c
c
c
c
c
c
c
c
c ** +
c
c
c
c
c
c
c
c ** *
c
c
c
c
c
c
c
THIS SUBROUTINE CALCULATES THE COST OF TUBE AND FIN IN $/FT
DATA DENCS.DENAL/.2833, -0975/
DENSITY OF CARBON STEEL IS 0.2833 LB/IN3
DENSITY OF ALUMIMUN STRIP IS 0.0975 LB/IN3
INPUT VARIABLES ***
KTUBE =
KFIN =
NFPIN =
DTO
DLTTK =
DFH
DFT
TUBE CODE. 0 FOR WELDED TUBE
1 FOR SEAMLESS TUBE
FIN CODE. 0 FOR L-FINNED TUBE
1 FOR G-FINNED TUBE
2 FOR EXTRUDED -FIN TUBE
NUMBER OF FINS PER INCH
TUBE OUTSIDE DIAMETER (INCH)
TUBE WALL THICKNESS (INCH)
FIN HEIGHT (INCH)
FIN THICKNESS (INCH)
OUTPUT VARIABLES ***
WTUBE =
WFIN =
WTUBF =
CTUB1 =
INTERNAL
DENCS =
DENAL =
CFIN =
CTUB =
FOVHD =
DSLEV =
CARBON STEEL TUBE WEIGHT (LB/FT)
ALUMIMUN FIN STRIP WEIGHT (LB/FT)
TUBE AND FIN WEIGHT (LB/FT)
COST FOR TUBE AND FIN PER UNIT LENGTH ($/FT)
VARIABLES ***
CARBON STEEL DENSITY (LB/IN3)
ALUMINUM DENSITY (LB/IN3)
COST FOR ALUMIMUN FIN STRIP ($/LB)
COST FOR CARBON STEEL TUBE ($/LB)
OVERHEAD FACTOR FOR TUBE AND FIN
FIN SLEEVE THICKNESS (INCH)
74040
74050
74060
74070
74080
74090
74100
741 10
74120
74130
74140
74150
74160
74170
74180
74190
74200
74210
74220
74230
74240
74250
74260
74270
74280
74290
74300
74310
74320
74330
74340
74350
74360
74370
74380
74390
74400
-------
I
1—>
CT^
Ul
C
C
C
C
C
C
C
C
C
C
ZFPIN=NFPIN
IF (KFIN-1) 5,6,7
L-FINNED TUBE
5 DSLEV=DFT
FOVHD=1.0
GO TO 8
G-FINNED TUBE
6 DSLEV^O.O
FOVHD=1.2
GO TO 8
EXTRUDED FIN TUBE
7 DSLEV=0.0
FOVHD=1.4
8 CONTINUE
DTI=DTO-2.0*DLTTK
DFR = DTO-i-2. 0+DSLEV
DOF=DFR+2. 0*DFH
CARBON STEEL TUBE WEIGHT PER FOOT (LB)
WTUBE=3.1416/4.0*(DTO**2-DTI**2)*12.0*DENCS
ALUM1MUN FIN STRIP WEIGHT PER FOOT (LB)
WFIN=(3.1416/4.0*(DOF**2~DFR**2)*DFT*ZFPIN*12.0+3.1416/4.0*(DFR** 2
1 -DTO»*2)*12.0) *DENAL
WTUBF=WTUBE+WFIN
C
C
IF (KTUBE-1) 10,20,20
*** SA-214 WELDED TUBE.
10 CTUB=0.7008
GO TO 30
*** SA-179 SEAMLESS TUBE.
20 CTUB=1 .376
30 CONTINUE
TUBE COST
ATUBE=WTUBE*CTUB
FIN COST
BFIN=WFIN*CFIN
.PRICE AS OF APRIL, 1976
, PRICE AS OF APRIL, 1976
74410
74420
74430
74440
74450
74460
74470
74480
74490
74500
74510
74520
74530
74540
74550
745GO
74570
74580
74590
74600
7461 0
74620
74630
74G40
74650
74660
74670
74680
74690
74700
7471 0
74720
74730
74740
74750
74760
74770
74780
74790
74800
748 I 0
748?0
74830
74840
74850
74860
74070
74880
74890
74900
-------
c
C COST/FT = ( WFIN*CFIN + WTUBE*CTUBE ) * FOVHD
CTUB1=(WFIN*CFIN+WTUBE*CTUB) * FOVHD
C +** MARK-UP FACTOR IS NOT USED HERE, BUT WILL BE USED LATER
C
RETURN
END
74910
74920
74930
74940
74950
74960
74970
CT>
cr>
C
C
C
C
C
C
C
C
C
c
c
c
c
c
c
c
c
c
c
SUBROUTINE UCONDt VT,UCLN,DTO,TTIN,KMETL,KGAGE,UBASE,FTEMP,FMETL) 74980
DIMENSION AMETL(7,13) 74990
*** FOLLOWING VARIABLES ARE INPUT 75000
*** VT = TUBE SIDE VELOCITY FT/SEC. 75010
*** DTO = TUBE OD INCH. 75020
*** TTIN = TUBE SIDE WATER INLET TEMP. DEG.F 75030
*** KMETL = CODE NO. OF METAL -N0.1 TO 13 75040
*** KGAGE = GAGE NO. OF METAL -N0.1 TO 7 75050
*** FOLLOWING VARIABLES APE OUTPUT 75060
*** UCLN = OVERALL HT. COEF. FOR NEW CLEAN TUBES CORRECTED FOR VARIOUS 75070
*** MATERIALS, GAUGES AND INLET WATER TEMPERATURES. 75080
*** UBASE = HT. COEF. BASED ON C*SQRT(VT) AND ON NEW CLEAN TUBES 75090
*** FTEMP r CORECTION FACTOR FOR INLET WATER TEMP.
*** FMETL = CORRECTION FACTOR FOR METAL AND GAUGE
*** CALC. OVERALL CONDENSING COEF. FOR SURFACE CONDENSERS USING HEI
*** METHODS -6TH EDITION -1970
*** FOLLOWING IS TABLE ST-1 PAGE 4 OF HEI, REF. IBID,TUBE METAL
*** CORRECTION TO CLEAN COEF. 75 50
DATA AMETL/1 .06, 1 .04,1 .02,1.0, .96, .92, .87 ,
1 .06,1 . 04,1.02,1.0,.96, .92,
1 .06,1 .04,1.02,1.0,.96, .92,
1 .03,1 .02,1.00,.97,.94,
1.03,1.02,
90 ,
90,
.87,
.87,
.84,
.84.
1.00,.97,.94,
1 .03,1 .02,1 .00,.97,
0.99,0.97,0.94,.90,
0.93,0.90,0.87,.82,
1.00,0.98,0.
0.88,0.85,0.
0.83,0.79,0.75,.69,.63,.56,.49,
0.78,0.76,0.74,.69,.65,.60,.54,
0.85,0.81,0.77,.71,.65,.56,.50/
KGAGE BWG DTTH
1 24 .022
2 22 .028
.94,.90,.84,
.85,.80,.74,
.77,.71,.64,
,95,.91,.86,.80,.74,
.82,.76,.70,.65,.59,
75
75
75
75
75
75
75
00
10
20
30
40
60
70
75180
75190
75200
75210
75220
75230
75240
75250
75260
75270
752BO
75290
75300
75310
-------
I
I—'
CTl
C
c
C
C
c
c
c
***
+**
3
4
5
6
7
20
18
16
14
12
.035
. 049
.065
.083
. 109
C ***
1 1 0
120
C ***
130
C ***
140
150
C +**
C ***
21 0
220
230
240
250
260
270
***
***
OD TUBES
1/4 IN. OD TUBES
FIRST CALCULATE UBASE HT. COEF. FOR SURFACE COND. USING ABOVE
METHODS FIG. SF-2 PAGE 5
IF(DTO-.BO) 1 10,1 1 0 , 120
CONSTANT FOR 5/8 AND 3/4 IN. OD TUBES
C = 267.
GO TO 150
IF(DTO-1 . 1 ) 130, 1 30, 140
CONSTANT FOR 7/8 AND 1.0 IN.
C = 263.
GO TO 150
CONSTANT FOR 1 1/8 AND 1
C = 259.
GO TO 150
UBASE = C * SQRT(VT)
CALC. TEMP. CORRECTION FACTOR USING ABOVE METHODS
BELOW IS A CURVE FIT OF FIG. SF-2 PAGE 5 OF ABOVE
IF(TTIN-50 . )210, 210,220
FTEMP = TTIN * . 013 + .16
FTEMP=AMAX1 ( .576 , FTEMP)
GO TO 270
IF( TTIN-70. )230,230,240
FTEMP = TTIN * .0095 + .335
GO TO 270
IF( TTIN-100. )250 ,250,260
FTEMP = TTIN * .00333 + .7669
GO TO 270
FTEMP = 0.002*TTIN + 0-9
CONTINUE
LOOK-UP OF TUBE METAL CORRECTION FACTOR FROM TABLE ST-1 PAGE 4
OF ABOVE
FMETL = AMETL(KGAGE.KMETL)
UCLN = UBASE » FTEMP * FMETL
RETURN
END
75320
75330
75340
75350
75360
75370
75380
75390
75400
75410
75420
75430
75440
75450
75460
75470
75480
75490
75500
75510
75520
755.10
75540
75550
75560
75570
75580
75590
75GOO
75610
75620
75630
75640
75650
75660
75670
75680
75690
75700
-------
O1
00
SUBROUTINE UOSENIKCLGI 75710
C *** CALC. OVERALL SENSIBLE HEAT TRANSFER AND PRESSURE DROP 75720
COMMON NFO.KGO,KNTRO,KNTR1,NSUM,NPAGE,DAY(2),PI 75730
COMMON KCI ,KER.KERR(20) ,KFIN.,KREG, LAIC.LSUP,MM,NP.NR,NT1 ,NT2,NTP, 75740
1NTR,NTT.ABARE,AFAN,AMIN,APLOT,APPR,ASBUN,ASTOT,AXAV,AXPP(20),CP(2) 75750
2,DEN(2)iDEN12(2,2) , DENFN,DENLZ(7),D5W,DEQ,DFH,DFR,DFS,DFT,DKl, 75760
3DLSP,DLTE.DLTO,DLTS,DNZ(2),DTI,DTIM,DTF,DTO,DTT,PL,Pr 75770
COMMON DPAD,DPAF,DPAM,DPAW,DPF(10),DPI,DPNZ(2),DPT,DPTA,DPTF, 75780
1DPTOT(2) POUT(2), PTUB,RV2,GArvlAX,GT ,HPFNC,HAIR,HTS ,UBARE,UCLN,UTOT , 75790
20(2) ,QDUT,QTOT,RFI,RFIN,RFTOT,RTOT,RTW,TAV(2 ) ,T I N(2> ,TOUT(2 ) ,TT(8 ) 75BOO
3,TWALL,TD.TW,TMTD,TK(2).VAPP,VNZ(2).VT,DFAN,TLTE,AOF,VISLZ<7), 75610
4VIS(2),VIS12(2,2),VISW,W(2),WAPF,WB(2),WLQ(2) 75820
COMMON ANG(3),CFH(3),CFP(3).CFR,CKBSC,CKFNG,CKHSC.CKLOV.CKSTC,F, 75830
1FALT,FINEF,FFF,FSUM,OCL(4),QDL(4),OKL(4),CML(4),OMV(4),P.PRAN(2>, 75840
2PRALZI7),R,RAOI,RAOR,RARAF,RAPMX,REA(2),RE12(2,2),RFNPL,RPT,TLA, 75850
3XREX,ZMP.ZNF,ZNTP,ZNTR,ZNTT,ZTPP(20),ZTPPA 75860
COMMON ZTRD.ANGI,ZBYP.ZBUP,Z8US,ZFAN,DFANI,DLOV,ZNFI,PTI,TKT,TKF, 75870
1WD(2) VAPPI,TAMB,HALT,C319,TIND(2),TOUTD(2),RFD,PSD,TTM1N,QD(7), 75880
2CARD7(6),DNZI(2) ,PDI,CFNG,CHSC,CLOV,CBSC,PRSTC,RFAIR,RFCT,ZNOZ( 2) , 75890
3RASPC,ZTPD,ZNTD,COST(7),5SUM(16,30),ISUM(13,30),PRICE(2,21) 75900
REA(1)=GT *DTI/(29.0*VIS(1 )) 75910
HTS=.058*REA(1)**.7*PRAN(1)**.5*TK(1)*12.0/DTI 75920
80 UTOT =1.0/(1.0/HA1R+RAOI/HTS +RTOT+RFIN) 75930
200 CONTINUE 75940
500 RETURN 75950
END 75960
SUBROUTINE ZEROA
COMMON IDUMP(6),DUMP(3),IDUMW(34),DUMW(246),DUM(972)
DO 10 1 = 1 ,34
10 IDUMW(I)=0
DO 20 1=1,246
20 DUMW(I)=0.0
DO 30 1=1,60
30 DUM(I)=0.0
RETURN
END
75970
75980
75990
76000
76010
76020
76030
76040
76050
76060
-------
TECHNICAL REPORT DATA
(Please read Initnictions on the reverse before completing)
. REPORT NO.
EPA-600/7-78-152
3. RECIPIENT'S ACCESS I Of* NO.
ri_E AND SUBTITLE
Optimization of Design Specifications for Large Dry
Cooling Systems
5. REPORT DATE
July 1978
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
Tzvi Rozenman, James M. Fake, and Joseph M.
Pundyk
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PFR Engineering Systems, Inc.
4676 Admiralty Way, Suite 832
Marina del Key. California 90291
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-03-2215
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 6/75-6/78
14. SPONSORING AGENCY CODE
EPA/600/13
is.SUPPLEMENTARY NOTES IERL-RTP project officer is Theodore G. Brna. Mail Drop 61,
919/541-2683.
. ABSTRACT The rep0r|- presents a methodology for optimizing design specifications of
large, mechanical-draft, dry cooling systems. A multivariate, nonlinear, constrai-
ned optimization technique searches for the combination of design variables to deter-
mine the cooling system with the lowest annual cost. Rigorous formulations are used
in calculating heat transfer and fluid flow. All thermal and mechanical design var-
iables of the cooling system components are analyzed. Thermal variables include
ambient air temperature, condenser terminal temperature difference, cooling range,
and initial temperature difference. Module variables are tube length, number of rows
and passes, and fan power. The methodology employs a computer program with ma-
jor computational blocks written as subroutines. The program optimizes dry towers
with either surface condensers or direct-contact jet condensers. Results of detailed
parametric and sensitivity analyses are presented. The relationships of design var-
iables , major components, site variables, and utility economic factors to incremen-
tal annual costs are examined for 1000 MWe fossil fuel plants at five U.S. sites.
Results , presented in both graphs and tables , show that all design variables affect
cooling system cost.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Pollution
Cooling Systems
Cooling Towers
Design Criteria
Engineering Costs
Condensers
Turbines
Heat Transfer
Fluid Flow
b.IDENTIFIERS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
c. COSATI 1-icld/Group
13 B
13A 20M
07A, 131 20D
14A
3. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASi
Unclassified
313
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
1-169
------- |