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Modeling and digital simulation of cogeneration system

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Title:
Modeling and digital simulation of cogeneration system
Creator:
Karpala, Jacek Antoni
Publication Date:
Language:
English
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vii, 91 leaves : illustrations ; 29 cm

Subjects

Subjects / Keywords:
Cogeneration of electric power and heat ( lcsh )
Digital computer simulation ( lcsh )
Digital modulation ( lcsh )
Cogeneration of electric power and heat ( fast )
Digital computer simulation ( fast )
Digital modulation ( fast )
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bibliography ( marcgt )
theses ( marcgt )
non-fiction ( marcgt )

Notes

Bibliography:
Includes bibliographical references (leaves 59-62).
General Note:
Submitted in partial fulfillment of the requirements for the degree, Master of Science, Department of Electrical Engineering.
Statement of Responsibility:
Jacek Antoni Karpala.

Record Information

Source Institution:
|University of Colorado Denver
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Auraria Library
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All applicable rights reserved by the source institution and holding location.
Resource Identifier:
22788506 ( OCLC )
ocm22788506
Classification:
LD1190.E54 1989m .K37 ( lcc )

Full Text
MODELING AND DIGITAL SIMULATION
OF COGENERATION SYSTEM
by
Jacek Antoni Karpala
Master Electrical Engineer in Electroenergetics
Politechnika Slaska Gliwice, Poland, 1979
A thesis submitted to the
Faculty of the Graduate School of the
University of Colorado in partial fulfillment
of the requirements for the degree of
Master of Science
Department of Electrical Engineering
1989


This thesis for Master of Science degree by
Jacek Antoni Karpala
has been approved for the
Department of
Electrical Engineering
by
D a t e (SV Q& 16^9


Karpala, Jacek Antoni (M.S., Electrical Engineering)
Modeling and Digital Simulation of Cogeneration System
Thesis directed by Associate Professor Pankaj K. Sen
111
Cogeneration is the sequential production of
electricity and heat, steam, or useful work from the
same fuel source. It takes all or part of thermal energy
that would normally be wasted and converts into useful
work. The main objective of this Thesis is to develop a
mathematical model of a cogeneration system and perform
digital simulation to study the economic performance of
such a facility. The cost of facility's operation prior
to and after the installation of a cogeneration system
has been chosen as a means of economic evaluation of the
cogeneration system. A case study has been performed to
illustrate the different aspects of programming with some
sensitivity analysis A brief overview of cogeneration
technology, including its mechanical and electrical
aspects is also discussed.
The form and content of this abstract are approved.
I recommend its publication.
Signed


CONTENTS
CHAPTER
I. INTRODUCTION.......................................1
Thesis Objective................................1
History of Cogeneration.........................2
PURPA and Cogeneration..........................3
II. PRIME MOVERS IN COGENERATION.......................6
Steam Turbines..................................6
Combustion Turbines.............................8
Reciprocating Engines..........................10
Types of Cogeneration Cycles...................11
III. ELECTRICAL ASPECTS OF COGENERATION................15
Electrical Equipment...........................17
Electrical Protection of a Cogeneration
Facility.....................................20
Grounding......................................23
Metering Schemes...............................23
IV. ECONOMIC EVALUATION OF COGENERATION SYSTEM........26
Computer Program...............................27
Analysis of Power Level........................27
Analysis of Heat Level.........................32
Program Scope..................................38
Program Execution..............................39


V
V. CASE STUDY........................................44
VI. CONCLUSION........................................57
BIBLIOGRAPHY...........................
APPENDIX
A. PROGRAM MANUALS AND SOURCE CODE
B. SAMPLE COMPUTER PRINT-OUT.......
C. COMPUTER PRINTOUT/A CASE STUDY.
59
63
83
87


TABLES
Table
1. Monthly gas consumption for the facility..........45
2. Monthly electric energy consumption and peak....46
FIGURES
Figure
1. Types of noncondensing steam turbines..............7
2. Types of automatic-extraction condensing
steam turbines.....................................8
3. Simple cycle gas turbine-generator.................9
4. Prime Movers ranges and efficiencies............11
5. Topping Cogeneration Cycle........................12
6. Bottoming Cogeneration Cycle......................13
7. Design options for cogenerator interconnection... 16
8. The CF protection problem.........................20
9. Typical protection requirements for
units between 100 KW and 1000 KW.................22
10. No sellback interconnection.......................24
11. Net sellback interconnection......................24
12. Gross sellback interconnection....................25


Vll
13. Power Flow Diagram.................................28
14. 24-hour power curves of the
cogeneration facility..............................29
15. Heat Flow Diagram..................................33
16. 24-hour heat curves of cogeneration facility......34
17. Program's block diagram............................40
18. Typical Working Day demand.........................47
19. Typical Saturday demand............................48
20. Typical Sunday/Holiday demand......................49
21. System performance for Option 3..................52
22. System performance for Option 1..................54


CHAPTER I
INTRODUCTION
Thesis Objective
The main thesis objective is to develop a digital
model of a cogeneration facility and to provide a
computer program for its simulation and economic
evaluation. Simple analysis based on the plant's annual
consumption or generation of thermal and/or electric
energy in itself is insufficient to determine feasibility
of cogeneration. In this thesis, hourly gas and electric
energy consumption and electric and heat generation are
being utilized to simulate the performance of
cogeneration facility. The computer program that has
been developed looks into facility's hourly loads of
thermal and electric energy and determines the amount of
power and heat that is required from cogeneration system.
The cost of the facility's operation prior to and after
installation of cogeneration system is utilized as a
means of economic evaluation of cogeneration system.


2
History of Cogeneration
Cogeneration is a new name for an old and proven
method of producing power. Cogeneration is the
sequential production of electricity and heat, steam, or
useful work from the same fuel source. Simply, it is a
system that takes all or part of thermal energy that
would normaly be wasted and converts it for in-plant
utilization. This idea was implemented in the late
1800's and early 1900's, when industry generated close to
half the energy it used. As late as 1950, cogeneration
supplied approximately fifteen percent of U. S. energy
needs. With few exceptions, early cogeneration systems
had no interconnections with utilities, which means that
generating equipment was run to meet electrical demand
without any regard for heat demand. Since exhaust heat
of the cogeneration system was not used, the total heat
demand was covered by using auxiliary equipment. In
either case, economic and thermal efficiency was
impaired. Industrial installations were more successful
than commercial because they had higher annual
utilization rates for both heat and electricity, and
greater maintenance capabilities. Commercial users
frequently based economic calculations on ideal
conditions which were not present all year round. Another
factor limiting early attempts at cogeneration
was that without utility tie-in, individual users had to


3
overcome their peaking and stand-by problems. In the
past the average utility company has unfortunately
regarded onsite generation as a competition and was
unlikely to agree to participate in any kind of share-
the-load agreements. Then the use of cogeneration
declined even more when in the 1950's and 1960's fuel
became less expensive and electric power generated by
utilities became cheaper and more reliable. By 1977,
only four percent of the nation's energy came from
cogeneration; however, in Europe higher fuel cost has
spurred industries to continue to expand the use of this
technology.
PURPA and Cogeneration
The Federal Government has come to recognize that
substantial amount of fuel can be saved by using
cogeneration techniques. In 1978 the U.S. Congress
amended the Federal Power Act, resulting in the issuance
of Public Utilities Regulatory Policies Act (PURPA) [1-
2] . The law was written to encourage cogeneration and
small power production. To distinguish new cogeneration
facilities which would achieve meaningful energy
conservation from those which would be "token" facilities
producing trivial amounts of either useful heat or power,
Federal Energy Regulatory Commission under PURPA,
established operating and efficiency standards for both


4
topping and bottoming cycle new cogeneration facilities.
In order to obtain qualifying status and benefit from
various privileges of government regulations, a
cogeneration facility has to meet all required efficiency
standards established by Federal Energy Regulatory
Commission. No efficiency standards are required for
existing cogeneration facilities regardless of the energy
source or the type of facility.
Energy conservation can be accomplished by using
less energy or by using it more efficiently. More
efficient utilization generates more product per given
unit of energy. Recognition of the advantages of
cogeneration and waste heat recovery is a major step
toward less energy dependence on traditional fuels. The
nonconventional utilization of various energy sources
serves not only as an economical advantage, but
also lessens the drain on precious resources. The
provisions of PURPA allow private industry and public
utilities to cooperatively optimize the generation of a
significant amount of electrical and heat energy. It
would be prudent in this time of heavy energy demands to
pursue this opportunity to its fullest extent. A
computer program developed in the thesis can assist an
engineering team in evaluating feasiblility of a
cogeneration system with various gas or diesel fired
prime movers. The typical cogeneration system containing


5
a prime mover, a heat recovery system, a generator,
a mechanical and electrical interconnecting system, and
a control system is the subject of the next chapter.


CHAPTER II
PRIME MOVERS IN COGENERATION
A thermal-to-electrical conversion is made with a
"heat engine," which is also known as a "prime mover."
Steam turbines, gas turbines, and diesel engines [3-12]
are three common prime movers associated with
cogeneration.
Steam Turbines
Steam turbine systems have achieved market
dominance in larger on-site applications, particularly in
the industrial sector and for systems of 1 MW to 100 MW
and more. These systems are best suited for applications
in excess of 10 MW due to increased efficiency for that
range (see Figure 4).
Noncondensing Steam Turbines Figure 1
schematically illustrates three types of noncondensing
steam turbines. These all exhaust directly into a steam
header. The straight noncondensing units supply steam
only at the single pressure of the exhaust. The single
and double automatic-extraction units supply steam at two
or three different pressure levels.


7
Straight
Noncondensing
(SNC)
Single Automatic-
Extraction -
Noncondensing
(SAENC)
Double Automatic-
Extra ction -
Noncondensing
(DAENC)
Figure 1. Types of noncondensing steam turbines.
Condensing Steam Turbines Single, double, and
triple automatic extraction steam turbines that exhaust
into a condenser are shown schematically on Figure 2. By
condensing the exhaust steam and increasing the
difference between steam turbine's inlet and outlet
temperatures, it is possible to increase steam cycle
efficiency over that of a noncondensing turbine.
Steam turbines are usually integrated with the
process to provide process steam as well as power. In
steam turbine cycles, steam may be expanded in
noncondensing, automatic extraction noncondensing, or
condensing steam turbine-generators which extract and/or
exhaust into process.


8
i,
ii
ii
Single Automatic-
Extract ion -
Condensing
(SAEC)
Double Automatic
Extraction-
Condensing
(DAEC)
Triple Automatic-
Extraction-
Condensing
(TAEC)
Figure 2. Types of automatic-extraction
condensing steam turbines.
Combustion Turbines
The basic combustion turbine cycle is shown in
Figure 3. It has been found that the best application in
I cogeneration systems is between 500 KW and 20 MW.
j
I
Efficiency of a gas turbine is considerably greater then
i
^ that of steam turbine, as shown in Figure 4.
I
| A gas turbine consists of a compressor, a
|1
i combustor, and a expansion turbine. Ambient air is drawn
! in through the compressor and flows steadily into the
I;
; combustor. Fuel is fired in the combustor resulting in
- development of high pressure and high temperature
I combustion gases. Gas expands in the expansion turbine,
i'


9
Hot Combustion
Figure 3. Simple cycle gas turbine-generator.
driving the generator and compressor. The temperature of
the exhaust gases is controlled by the fuel-to-air ratio.
Since most industrial gas turbines use as much as three
to four times the air as required to combust fuel, the
exhaust stream contains 15% to 20% of oxygen and can be
used to burn additional fuel to increase the amount of
thermal energy available.
Thermal energy of exhaust gases can be utilized
by these three most common methods:
1) Pass the exhaust flow through a heat exchanger
(or boiler or absorption chiller) and generate
process fluid or steam.


10
2) Use relatively clean and dry exhaust flow as a
direct-heating and/or drying medium.
3) Use the exhaust flow as highly preheated
combustion air in combustion devices of
boilers, space heaters, oil heaters, and hot
gas generators.
Reciprocating Engines
Internal combustion, reciprocating engines,
ranging in size from 100 KW to 5,000 KW, have been
successfully used for direct drive of compressors,
pumps, fans, and most commonly to drive electric
generators (see Figure 4, for efficiency rates). Large,
slow-speed units are more efficient and have a longer
operating period between maintenance and overhauls than
small, high-speed engines. Large units generally cost
more and require more space per unit of electrical
output.
Waste heat is recovered from the diesel exhaust
and the cooling system. The thermal energy recovered
from exhaust gases can be used to generate hot water or
steam with equipment similar to the one listed for gas
turbines. Typical efficiency of diesel engines is about
33%. Recovery of the exhaust gas heat can increase the
efficiency to about 45%, and additional equipment
utilizing energy of cooling water and lubricating oil


11
lOOkW lOOOkW 10,OOOkW 100MW
Prime Mover Size
Figure 4. Prime Movers ranges and
efficiencies [13].
v
heat can increase the efficiency to about 75%. Diesel
engines have a higher thermal efficiency than gas and
steam turbines and thus greater electrical conversion
efficiency. They also have a higher fuel-to-electricity
conversion ratio than the gas engines because of the
diesel's higher compression ratio. With minor
modifications, gas engines can burn fuels such as
gasoline, propane, butane, natural gas, sewage gas,
alcohol, and mixtures of gasoline and alcohol.
Types of Cogeneration Cycle
Two basic types of cogeneration systems are
available from prime mover application stand point:


12
1. Topping Cycle This is a cogeneration system
which produces electricity and exhausts
thermal energy which is then used for district
heating or comparable functions. It is the
system where the primary energy source is used
to produce useful electric or mechanical power
output. Reject heat from power production is
then used to provide useful thermal energy
(Figure 5).
Thermal
Energy
Input
O
Waste
Figure 5. Topping Cogeneration Cycle.
2. Bottoming Cycle This is a cogeneration
system which produces thermal energy for an
industrial process or district heating and
part of the thermal energy is withdrawn to
generate electricity. It is a system where


13
the primary energy source is applied to a
useful heating process, and the reject heat
emerging from the process is then used for
production of electric power (Figure 6).
Thermal
Energy
Input
O
Electric
Power
Generation
Waste
<>
Figure 6. Bottoming Cogeneration Cycle.
There are many factors that will influence the
development and selection of a cogeneration cycle. These
factors include:
1) Process heat and power demand characteristics.
2) Available energy supplies (fuel and power) and
their costs .
3) Environmental requirements.
4) Avoided cost rates for power sales.
5) Critical plant services.


14
6) Capital availability.
7) Economic criteria for discretionary
investments.
8) Energy legislation incentives.
These factors will govern the selection of the
available cogeneration alternatives. Consideration will
be given to the type of prime movers with the most merit.
Redundancy in prime mover and/or process heat supply
systems should be considered, along with the power
generating capacity that may prove the most economical
for the specific site and situation being evaluated.


CHAPTER III
ELECTRICAL ASPECTS OF COGENERATION
The fact that the major capital investment in a
cogeneration system,is in the mechanical equipment leads
to the possibility that the electrical design of the
cogeneration plant will be given insufficient attention.
However, it is important to give just as much attention
to the electrical design [14-34] These basic design
considerations for the electrical system of a
cogeneration plant are:
safety
reliability
simplicity
ease of maintenance
flexibility
The electrical power system engineer has two
basic design options when determining how to tie a
generator or generators into the power system, as
illustrated in Figure 7.


16
Facility Bus
Connected Scheme
Utility Bus
Connected Scheme
Utility Bus
Industrial Bus
Industrial
Load
Utility Bus
Industrial Bus
Industrial
Load
Figure 7. Design options for cogenerator
interconnection.
The Facility Bus Connected Scheme ties the
generator directly Into the primary distribution system
of an industrial or commercial plant while the Utility
Bus Connected Scheme connects the generator through a
step-up transformer directly onto the utility high
voltage grid. Small industrial or commercial plants may
utilize 2.4 kV or 4.16 kV primary distribution systems
while medium to large plants will generally be at 13.8
kV. Connecting the generator directly to the bus of
the facility has some advantages since there is
minimum investment in new electrical equipment and the
generation


17
is placed in close electrical proximity to the plant's
load. There is also economic flexibility with this
scheme since the generated power can be strictly for
inplant use or separately metered and sold to the
utility. Yet, for all the benefits, there are some
serious restrictions when trying to integrate generators
directly to the industrial distribution system. One of
the major limitations is that the short circuit
contribution associated with the turbine generator is
usually too high for the existing plant switchgear.
Electrical Equipment
Two basic types of generating equipment for
cogeneration application are: synchronous generators and
induction generators. Due to quite different equipment
design, characteristics, and performance, each may have
its best suitable application in cogeneration. Some of
the basic differences in design and application are as
follows:
Synchronous Generators. Synchronous generators
have several features which make them desirable from a
utility standpoint, but the excitation and
synchronization equipment required often make these
generators economically unfeasible. The synchronous
generator with associated excitation equipment is able to
supply its own reactive power and hence may operate at


18
unity or lagging power factor. Cogeneration facilities,
in some cases, are required to supply a sufficient
generator reactive power capability to withstand normal
voltage variations on the utility system. This
operation enhances generator stability and obviates the
need for supplemental power factor correction equipment.
Synchronous generators require automatic synchronization
equipment and supervisory relays to prevent closure into
the utility network when the cogeneration facility's
generator is improperly synchronized. Other protective
relaying may be required to account for overspeed,
excitation overvoltage, loss of excitation, loss of
synchronism, frequency deviation, field ground, neutral
overvoltage, and others.
Induction Generators. Induction generator
installations are in many respects simpler than
synchronous generator systems, but they pose additional
problems. The induction generator may be started as a
motor with full voltage if current inrush, voltage
regulation and lamp flicker are not serious problems. If
the quality of service to the other utility customers is
adversely affected due to full voltage starting, reduced
voltage starting or some other starting method may be
necessary. Since the induction generator cannot maintain
constant voltage and constant frequency operation,
without an outside source of reactive power, locally


19
installed capacitors may be required. The installation
of capacitors at, or near, an induction generator
increases the risk that the machine may become self-
excited if it is isolated from utility system. A self-
excited induction generator can produce power of abnormal
voltage and frequency. This unregulated power may damage
equipment electrically connected to the isolated
generator. To protect against self-excited operation,
over-and-under frequency relays and voltage regulation
relays should be required on all induction generators of
rating greater than 5 KW. Other protective equipment
such as voltage restrained overcurrent relays may also be
required to reduce the possibility of damage to utility
equipment and the equipment of other customers. Where
self-excitation problems appear likely, it may be
necessary to rearrange the distribution network to
prevent the induction generator from becoming isolated
with a small attached load. Reclosure of a distribution
line after a utility system disturbance may cause damage
to the induction generator. Protective equipment should
be installed to prevent such reclosure.


20
Electrical Protection of a Cogeneration Facility
There are two major areas of protection for the
Cogeneration Facility (CF) that need to be addressed:
1. Protection during faults.
2. Protection during abnormal conditions.
Protect
Utility
From CF
Faulted
Conditions
Detect Util.
Faults Supplied
by CF
Overcurrent
*Device
Coordination
PROTECTION
PROBLEM
FOR "CF"
Abnormal
Conditions
Protect CF
From Utility
Internal Fault
Detection
Modification
of Util. Practice
Fluctuating
Generation
Protect
Utility
From CF
_Protect CF
, From Utility
Harmonics
Overvoltage
Overheating
* Overload
Figure 8. The CF protection problem [16].


21
Each of the above can be broken down further into
two main areas: 1) Protection of the utility from the CF
and 2) Protection of the CF from the utility, as shown on
Figure 8.
These areas represent the two different,
sometimes opposing, viewpoints on this problem. The'
purpose of the chart in Figure 8 is to show that the CF
protection problem cannot be viewed entirely from either
perspective alone. It encompasses both the utility and
the CF owner, and must be solved with an integrated
approach and effort. The CF owners may have to install
more protective equipment than they feel necessary. The
utility may have to modify long-established practices.
Both sides may have to bend a little so that the
Cogeneration Facility can be safely interconnected with
the utility system.
Protection requirements vary with size,
connection point to the utility, and the utility's
attitude toward cogeneration. Figure 9 may represent a
typical arrangement for protective devices for a
generator being utilized in a cogeneration system. The
system parameters being sensed here are:
frequency (81)
over and undervoltage (27/59)
instantaneous overcurrent (50)
time overcurrent (51)
directional overcurrent (67)


22
generator differential (87G)
transformer differential (87T)
directional power (32)
synchronizing (25)
thermal (49)
phase balance current (46)
Generally, in a configuration like this, the
primary fault detection entities are current and voltage
at the generator site. The frequency relay prevents
islanding of the generator with a connected load from the
utility system, and the negative sequence relay detects
unusual conditions resulting from single-phasing and
unbalanced faults.
Figure 9. Typical protection requirements for
units between 100 KW and 1000 KW [16].


23
Grounding
The subject of grounding is directly related to
protective relaying of the CF and safety of personnel.
Three general parameters fault current, overvoltage and
harmonic current will have an important bearing on the
decisions for grounding.
Several categories of grounding schemes can be
considered, some of them are:
1. Ungrounded
2. Solidly Grounded
3. High Resistance Grounding
4. Low Resistance Grounding
5. Resonant Grounding
Metering Schemes
Interconnection of the Cogeneration Facility with
the utility will require special metering techniques or
equipment in order to protect the interest of the
cogeneration facility, the utility company, and its
distribution cooperatives. It is necessary to meter both
the power consumed and the power produced by a
cogenerator in order to properly monitor the cash
transactions between the utility and cogeneration
facility. In the case of the CF, the consumer has the
following interconnection options:


24
No Sellback A CF operating in parallel with the
utility may choose not to sell energy back to the
utility. This may be motivated by the expense involved
with additional metering equipment and/or the fact that
the load exceeds generation (Figure 10).
Figure 10. No sellback interconnection.
Net Sellback Consumer first meets his own power
requirements and any excess of power is then sold to the
utility. A second meter is required unless a fully bi-
directional recording meter is used (Figure 11).
Figure 11. Net sellback interconnection.


25
Gross Sellback The entire output of the
facility is sold back to the utility while the
cogenerator continues to buy his full power requirements
from the utility. This is commonly referred to as
simultaneous buy-sell or dual buy-sell scheme (Figure
12) .
Figure 12. Gross sellback interconnection.


CHAPTER IV
ECONOMIC EVALUATION OF COGENERATION SYSTEM
AND DIGITAL SIMULATION
Natural gas is one of the most common fuels used
in cogeneration. Almost every commercial or industrial
facility requires gas and electric energy in order to
achieve their objectives. On the other hand, the gas
turbines and engines that are available on the market
provide an excellent selection in size and performance
for use in cogeneration. An assortment of heat recovery
equipment, ranging from heaters, boilers and dryers to
absorption chillers make design and installation of the
cogeneration system much more efficient and universal.
At the same time, prediction of economic benefits from
such installation seems to be a difficult and complex
task [35-36]. Calculations based only on total annual
consumption of gas and electric energy are insufficient
to determine the system's economic performance after its
installation. The match between thermal and electric
energy hourly consumption has to be considered, in order
to determine the feasibility of the cogeneration system.
The computer program developed in this thesis simulates
the performance of a commercial or industrial


27
cogeneration facility with a reciprocating engine or gas
turbine performing in the topping cogeneration cycle.
Computer Program
A comparison of the plant's operating expenses
before and after installation of the cogeneration system
is the program's main principle. Based on three twenty-
four hour typical days of the plant's operation with and
without a cogeneration system, the program calculates the
economic benefits or losses after the installation of the
cogeneration system. The three typical days that were
chosen are: a working day, a Saturday and Sunday or a
holiday.
For clarity of the analysis and simplicity of the
computer program, evaluation of the cogeneration system
has been done in two separate, but correlated levels: the
power level and the heat level. The results of these
evaluations are being combined into one global formula.
Analysis of Power Level
Without cogeneration, all power required in plant
or its vast majority has to be purchased from the utility
company as shown in the Figure 13. A daily graph of that
power is shown in Figure 14(a). After the installation
of the cogeneration system the plant's power requirements
will change to the one shown in Figure 14(e). Generally,
the power required from the utility after installation of


28
the cogeneration system will be the difference between
old power required in the plant and power that is
generated on site (Figure 14(b)). In some cases, the
electrically driven chiller can be replaced with an
absorption unit, resulting in reduction of overall power
requirement (Figure 14(c))..
Electric Electric
Utility Utility
Company Company
Power
Required
New Power
Required
Plant
PG Cogeneration
Plant System
(PS)
a) b)
Figure 13. Power Flow Diagram, a) without cogenera-
tion, b) with cogeneration. PG is power
generated and PS is power saved by
replacing electric chiller with
absorption chiller.
If power generated is greater then new power
required in the plant, the excess power may be sold, to
the utility, depending on the selected system's


29
P
Figure 14. 24-hour
power curves of the
coqeneration faci-
lity .
a) Total power reqiu-
red in plant.
^fTTK
Hr-
\
r -
b) Power of cogenera-
tion.
c) Power reduced in
absorption equip-
ment.
d) Excess generation
Hr'
e) Power from utility.


30
performance (Figure 14(d)). All power graphs represent
twenty-four hours of a plant's typical working day.
The difference between cost of the Power Required
and cost of the New Power Required represents potential
savings for the plant on a power level of our economic
evaluation. From the Power Flow Diagram we can write:
New Power Required = Power Required (PG + PS)
where: PG is the power generated in KW and PS is the
power reduced by replacing electric chiller with an
absorption chiller, both in KW.
If, after installation of the cogeneration
system, the generated power (PG) is less than the new
power required minus the power reduced (PS), some
additional power must be purchased from the utility. If
the generated power is greater than the power required
minus the power reduced, then depending on the selected
option, power can be sold to the utility company.
The costs of electric energy prior to and after
the installation of the cogeneration system are presented
below. The abbreviations used correspond to ones used in
the computer program.
$/UTIL PWR = USEDPWR x UTILR
where: S/UTIL PWR the cost of electric power before
installation of cogeneration, in $.


31
USEDPWR power consumed in plant in KWH.
UTILR = (SCH + PKR*PKD + PR*USEDPWR)/
/USEDPWR -
an average monthly utility rate based
on peak demand and energy charges before
cogeneration installation, in $. This is
calculated in the program, where SCH is
the monthly utility service charge, PKR is
the demand charge, PKD is the peak demand
for a given month, PR is the energy
charge, and USEDPWR is the monthly energy
consumption.
After installation of the cogeneration system, a
new amount of power will be required, with a new monthly
rate:
S/POWER AFTER = UTILPWR x COGR
where: S/POWER AFTER cost of power purchased from the
utility after the installation of the
cogeneration system, in $.
UTILPWR amount of power purchased from
utility, in KWH.
COGR average utility rate after the
installation of the cogeneration system,
in $, calculated in the same way as UTILR,
but with a different peak demand and
energy consumption.


32
For power sold to utility:
$/S0LD PWR = PSELL x SELLR
where: $/S0LD PWR savings due to excess power sell to
utility company.
PSELL amount of power sold, in KWH.
SELLR user defined rate at which
the utility is willing to buy one KWH of .
power from the cogeneration facility.
The cost of power generated and power reduced is
not important, since the calculation of the economic
results is based on the difference between the cost of
the plant's operation prior to and after the installation
of the cogeneration system. PG power generated and PS
- power reduced (saved) were essential in determining the
plant's power requirements after installation of the
cogeneration system.
Analysis of Heat Level
A very similar study can be performed on the
thermal energy level of our evaluation. A simple flow
diagram of the thermal energy or (gas) required for the
plant, both without and with the cogeneration system is
presented in the Figure 15. Daily graphs of thermal
energy involved are shown on Figure 16(a) through 16(f).
They also represent twenty-four of the plant's operation.


33
Gas Utility
Company
Gas Utility
Company
Fuel For
Cogeneration
Gas (Heat)
Required
New Gas (Heat)
Required

Plant
URPP ^ -
Plant Cogeneration System
Heat Wasted
I
a) b)
Figure 15. Heat Flow Diagram, a) without cogenera-
tion, b) with cogeneration. HREC'is
the amount of recovered heat.
Again, from the heat flow diagram we can write:
New Heat Required = Heat Required HREC
where: New Heat Required is new heat required from the
utility after installation of the cogeneration system, in
MMBTU, Figure 16(d). Heat Required is the heat required
from the utility before installation of the. cogeneration
system,in MMBTU, Figure 16(a). HREC is the heat
recovered in the cogeneration process in MMBTU, Figure 16
(b). The recoverable heat in the cogeneration process,


34


35
usually heat of the exhaust, (Figure 16(e)) may greatly
exceed or be insufficient to cover the plant's
requirements. If the cogeneration process is not able to
supply the plant's total heat requirements, then the
missing amount of thermal energy has to come from the gas
utility company. If recoverable energy of the
cogeneration process exceeds the plant's needs, then the
excess heat is wasted to the exhaust (Figure 16(c)).
The formula for the cost of remaining thermal
energy to be purchased from the gas utility company after
installation of the cogeneration system is:
$/HT AFTER = HTA x GR
where: HTA heat required in plant after installation
of the cogeneration system, in MMBTU.
GR gas rate in $/MMBTU calculated in the
program and based on the cost of 1 CF of
gas and its Lower Heating Value.
The cost of the plant's thermal energy prior to
the cogeneration system installation:
$/HT REQUIRED = HTREQ x GR
where: $/HT REQUIRED cost of thermal energy required
in the plant prior to the cogeneration
system installation in $.
HTREQ amount of thermal energy required


36
in plant prior to the installation of the
cogeneration system, in MMBTU.
Again, the cost associated with thermal energy
recovered in the cogeneration process can be disregarded,
since the difference between the cost of thermal energy
prior to and after installation of the cogeneration
system is being considered. The amount of thermal energy
recovered in the cogeneration process is essential in
order to determine the plant's new heat requirements.
The main operating expense of the cogeneration
system is that of the fuel consumed by the prime movers
of the system. It may be a natural gas, a gasoline, or a
diesel fuel:
$/FUE L COST = GENHT x FR
where: GENHT total heat required in the cogeneration
process (heat input for prime-movers),
in MMBTU, Figure 16(f).
FR fuel heat rate in $/MMBTU which is
calculated in the program from input data
in the manner similar to the one used for
GR.
All the costs associated with the cogeneration
system have been discussed, except the cost of
maintenance, which is usually expressed in its simplest


37
form as a fraction of the dollar per one kilowatt-hour of
generated power by the unit:
S/MAINTAIN = PG x MC
where: PG amount of power generated in KWH.
MC rate of cost of maintenance in $/KWH.
If we are to summarize the costs of the plant's
operation prior to and after installation of the
cogeneration system, we have:
1. Prior to the cogeneration system's
installation:
- $/UTIL PWR cost of power required in
the plant
- $/HT REQUIRED cost of thermal energy
in the plant
2. After the cogeneration system's installation:
- $/P0WER AFTER cost of power from the
utility after cogeneration installation
- $/HT AFTER cost of outside fuel after
cogeneration installation
- $/FUEL COST cost of fuel of cogeneration
system (fuel of prime movers)
- S/MAINTENANCE cost of maintenance of
cogeneration system


38
The plant's total savings (or expenses) can be
then expressed by the following equation:
$/S = ($/HT REQUIRED + $/UTIL PWR) -
($/HT AFTER + S/FUEL COST + S/POWER AFTER +
$/MAINTENANCE) + $/PWR SOLD
which is nothing more than the difference between the
plant's expenses prior to and after the cogeneration
system's installation.
In order to use this formula, a series of time
consuming calculations have to be performed by the
computer. All of the calculations of power and thermal
energy are done on an hourly basis for three typical days
in the month, for twelve months in the year. For every
month, new peak demand and, as a result, a new monthly
rate for the utility's electrical energy is calculated.
. Program Scope
The cogeneration system in the program consists
of the two identical units driven by either a gas turbine
or a gas or diesel fuel engine. The characteristic of
the engine-generator set is determined by the user and
contains a fuel intake, a power output, and an amount of
recoverable heat in the cogeneration process. The heat
recovery equipment is introduced by specifying the
equipment's efficiency factor, which determines the
amount of the recoverable heat that can be utilized.


39
Program Execution
In the first stage of the execution, after the
name of the facility, one of the four different options
of the system performances is selected, depending on the
objective of the cogeneration system (Figure 17):
1) Cover heat demand; no power sell.
2) Cover heat demand; sell excess power.
3) Cover power demand; disregard heat demand.
4) Run at full power; sell excess.
In option 1, the program follows the curve of
plant's hourly heat consumption and generates the
corresponding amount of power, using power vs. heat of
the exhaust characteristic of the selected cogeneration
unit. If the power generated this way exceeds the
plant's needs for a given hour, the generator's output is
reduced to match the power demand, and recoverable heat
of the prime mover's exhaust is adjusted accordingly. No
power is sold to the utility. If heat demand exceeds the
amount of recoverable thermal energy of the exhaust at
full power of the generator, then the shortage has to be
supplied from outside.
Option 2 is very similar to 1 except the excess
power, if present, is sold to the utility company.
In option 3, the program follows the hourly power
demand curve and the cogeneration unit produces power to


Figure 17. Program's block diagram.


41
meet the plant's demand. The amount of generated thermal
energy of the prime mover's exhaust is determined by
power vs. heat of the exhaust characteristic of the
cogeneration unit. If the capacity of the units
selected is less than the power required in the
plant for a given hour, the power shortage is bought
from the utility company. If recoverable heat of
the cogeneration system exceeds plant's demand, then
the excess heat is wasted to the exhaust. If heat
demand for the given hour is greater than the amount
of heat recovered, then the shortage has to be
supplied from outside. In some relaying and
metering schemes, a positive power flow from the
utility to the facility is required, in order to
assure proper performance of protective devices and
to facilitate cash transactions. If a certain amount
of power has to flow from the utility to the system,
the program will follow the power curve less the
specified margin.
Option 4 keeps both generators running at full
capacity 24 hours a day, throughout the year. Excess
power is sold to the utility and excess heat is wasted to
the exhaust.
For options 1 through 3, the user will select one
of the two modes of the generators parallel operation:
1) First generator loads to a 100% capacity,


42
and then the second unit comes on and
the load is shared equally.
2) First generator loads to 100%, and then
the second unit comes on and picks up the
remaining load.
After selection of the cogeneration system's
performance and mode of the parallel generators'
operation, the system's data that is stored in the first
hundred lines of the program is read to the memory.
Next, the program requires additional data from the
console when creating a new cogeneration facility, or the
program will read the file with already existing data.
The existing data are the result of the initial run of
the program, during which, parameters of the examined
facility have been retained in the form of a file. This
allows the user to adjust and manipulate existing data to
achieve the desired tolerance in the system's simulation
and performance. Also, the user can observe the system's
sensitivity to the changes in selected parameters during
multiple reruns of the program. The program can be run
as many times as practical in order to determine optimum
conditions and system parameters providing the best
economic results.
The execution of the program takes between five
and ten minutes, depending on the program's option
selected by the user. Monthly reports of changing power,


43
peak demand, electric and thermal energy utilization,
consumption, and generation are made. Related costs of
thermal and electric energy and maintenance expenses are
listed on a monthly basis. Each month is then summarized
to give the annual financial result of the cogeneration
system performance. Finally, the program prints annual
plant electric energy consumption, generation,
purchasing, and sales, along with the total thermal
energy consumed, recovered, and wasted to the exhaust, in
the cogeneration process. As an option, the user may
request a hard copy of all the supporting data used in
the program calculations. Appendix B contains a sample
of the complete printout of the program.


CHAPTER V
CASE STUDY
To illustrate the program's performance and
ability, a hypothetical facility has been created and
analyzed. The facility operates five days a week with
one shift only, excluding all Saturdays, Sundays, and
holidays. There are four separate gas services
identified as location "A", "C", "D", and "E". Each
location has its own metering. Monthly gas consumption
for each location is presented in Table 1. Gas consumed
in the facility covers all of the heating requirements,
as well as demand for domestic hot water, and the thermal
energy required for the process. The heating and hot
water that is required is supplied by direct fired
boilers and water heaters, scattered throughout the whole
facility. Services supplying gas for domestic hot water
and the thermal energy of the process can be identified
in Table 1, as the ones with monthly consumption which is
evenly distributed throughout the whole year (location
"A" and "C"). The ones with consumption which is heavily
dependent on the time of the year, represent heating
loads (location "D" and "E") .


45
Table 1. Monthly gas consumption for
the facility
Service Location
"A" "C" "D" 11 £ II
M0. CCF CCF CCF CCF
1 5170.00 3116.00 66069.00 76811.00
2 5488.00 4233.00 60000.00 69135.00
3 5255.00 3404.00 80334.00 93402.00
4 5178.00 3391.00 20561.00 23919.00
5 4156.00 3613.00 31887.00 37073.00
6 3829.00 3139.00 17252.00 20065.00
7 3427.00 4675.00 394.00 457.00
8 3040.00 5327.00 71.00 353.00
9 3127.00 3336.00 587.00 690.00
10 3259.00 2147.00 25089.00 29177.00
11 4474.00 2731.00 31374.00 36487.00
12 4868.00 2809.00 55639.00 64692.00
There are also two primary services at 13.2 kV,
supplied by the local utility company and identified as
location "A" and "B". Table 2 shows monthly electric
energy consumption and peak for both services.
The amount of gas consumption at location "A" and
"C" results in an annual billing of $18,000.00 and
$15,000.00, respectively. These costs are insufficient
to merit installation of the cogeneration system. The
highest gas consumption is present at location "E", and
that service was selected for our further analysis.
The assumption has been made, based on highest
monthly electrical consumption and peak demand, that best
suitable electric service to consider for installation of


46
the cogeneration equipment, is that at location "B".
Table 2. Monthly electric energy consumption
and peak.
Service Location
"A fl II B"
Peak Consumption Pea k Consumption
MO . KW KWH KW KWH
1 77.00 30720.00 1830.00 654800.00
2 81.00 28080.00 1818.00 669600.00
3 72.00 27120.00 1835.00 686000.00
4 69.00 27600.00 1915.00 719200.00
5 77.00 25680.00 2070.00 743200.00
6 79.00 24240.00 2185.00 728000.00
7 77.00 25920.00 2175.00 746400.00
8 79.00 23280.00 2142.00 731200.00
9 67.00 21840.00 2117.00 650800.00
10 79.00 24480.00 2110.00 690800.00
11 77.00 28080.00 2088.00 720800.00
12 77.00 29040.00 2066.00 731200.00
Let us further assume that a fifteen minute
demand (or load profiles) for three typical days of the
plant's operation are known, and are supplied by the
utility company. Those three typical days, Tuesday for
the Working Day, and Saturday and Sunday, are shown in
Figure 18 through Figure 20. The heat (or gas) load
profiles for three typical days were assumed constant
(see Appendix C for a print-out). To illustrate
reduction in the power required in the facility by
utilization of absorption equipment, an electric chiller
providing cold water for the process is introduced. The
chiller is producing 542 Tons of refrigeration per


DAILY GRAPH TUESDAY
3,500+-- 1 1
1 1 3,000+-- 1 1
1 2,500+-- 1 1
1 1 2,000+-- X XXX X xxxx
I XXXXXX XXXXXXXXXXXXXXX XXXXXXXX I
. XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX I
. XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX I
1,500 + --- + +-+-+---+--+XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX----+----+---+---+---+---+---+--+----+ I
I XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX X I
. XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX I
> XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX I
I XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX I
1 000 + ---+ -++++XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX++I
i xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxXxxxxxxxxxx I
I XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XI
.XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXt
.xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxXxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxi
500+XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXi
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxXxxxxxxxxxxxxxi
.xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.
,XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX.
0 + + + + + + + + + +++++++++++++++ +
1 Z 3 A 56 7 8 9 10 11 12 1 2 3 A 5 6 7 8 9 10 11 12
AM -- PM
Figure 18.
Typical Working Day fifteen-minute demand


DAILY GRAPH SATURDAY
3,50 0 +--+---+----+---+----+---+----+----+---+----+---+----+---+----+----+---+----+---+----+----+---+----+---+----+
3,0 0 0 +-+----+---+----+----+---+----+----+---+-----+---+----+---+----+----+----+---+----+----+----+---+----+----+---+
2,50 0 + +----+----+---+----+---+----+---+---+----+----+---+----+----+---+ +------+---+----+----+---+----+---+ +
2,000+-
!
1,500 +----+----+----+----+-----+----+----+----+----+----+----+-----+----+----+----+----+----+-----+----+----+----+----+----+----+
i
1 000 + ++++++++++++++++++++ + + +--------------------------------------------+ I
i X XXXXX .
. X xxxxxxxxxxxxxxxxxxxxxxxxxxxx .
iXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX I
5 0 O + XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX-+-+-+i
iXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXi
iXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXi
.XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXi
.XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXi
0 +++++++++++++++++++++++++
1 23456789 10 11 12 1 2345678 9 10 11 12
AM PM
Figure 19.
Typical Saturday fifteen-minute demand.
t*
CO


DAILY GRAPHi SUNDAY
3,500+---+---+----+---+---+---+----+---+---+----+---+---+----+---+---+---+----+---+---+----+---+---+---+----+
3, 000
---+----+----+----+----+----+----+----+----+----+----+----+----+----+----+----+----+----+---+-----+----+---+----+----+
2,500+---+---+----+---+---+----+---+---+----+---+---+----+---+---+----+---+---+----+---+---+----+---+---+---+
2, 000+--+----+---+----+---+----+---+---+----+---+----+---+----+---+----+---+----+---+---+----+---+----+---+---+
1,500+---+---+----+---+---+----+---+---+----+---+---+----+---+---+----+---+---+----+---+---+----+---+---+---+
1 000 +-+----+---+----+----+----+---+----+----+----+---+----+----+----+---+----+----+----+----+---+----+----+---+----+
50 0 +--+--+----+---+---+--+'---+---+---+--+----+--+----+---+-+ -XXXXXXXXXXX-XX +---+-X + -+ +
XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
0+----+--+----+---+---+---+---+---+---+--+----+--+----+---+-----------+ + + + +---+---------+ + + +
1 2 3 A 5 6 7 8 9 10 II 12 1 2 3 A 5 6 7 8 9 10 11 12
am PM --
Figure 20. Typical Sunday/Holiday' fifteen-minute demand
to


50
working day, which is about 6.5 MMBTU/HR. It represents
about 390 KW of electric power for compressors for eight
hours of the plant's operation. It means that by
utilizing the absorption chiller with a consumption rate
of 6.5 MMBTU/HR, we can shave off a 360 KW of power from
the plant's demand during operating hours. For
simplicity of analysis, the efficiencies of the heating
equipment, the absorption chiller, and the heat recovery
equipment were set on 100%. All other parameters, such
as the utility charges, the gas rates and the generator
characteristics used for computations can be obtained
from the computer printout of our case study in
Appendix C.
The generators which were selected for our
cogeneration system are gas turbine driven and were
selected for their low maintenance costs, low pollution
contribution, and the readily available natural gas
source at the facility.
Several runs of the program were necessary to
determine the optimum size and the cogeneration system
configuration resulting in best economic results. The
first several runs of the program showed that the
possibility of selling the excess power to the utility
company should be rejected. This is due to the fact that
the electrical size of the cogenerating units, that can
provide the amount of recoverable thermal energy matching


51
the one supplied by the service at location "E", is too
small. Options 1 and 3 were then used to determine the
optimum size of the units, which would result in the
maximum economic benefits. With selection of the 3rd
option, which is the option following the power curves of
the three typical days, and power is generated
accordingly, and excess thermal energy is wasted to the
exhaust, if it exists. The summary of the system's
performance is presented in Figure 21. As we can see,
the maximum savings were obtained in a range of 600 to
700 KW of generator size, which results in 1200 KW to
1400 KW of total on site generation. This is due to the
fact that when increasing the size of the units beyond
the power required (less power reduced by absorption
equipment), more thermal energy per KW is required
without increasing the power generated (see Heat of Prime
Movers curve, Figure 21). It also means, that the system
came to the best possible balance between the power
required in the plant (less power reduced) and the power
of the cogeneration system, while the recovered heat of
the exhaust makes the closest match with the heat
required. The same figure shows annual fuel consumption
of the cogeneration system, heat wasted to the exhaust,
and power generated, all related to the combined size of
the units installed.
Although we were able to establish maximum
savings for the selected system (about $13,000.00), the


52
Figure 21. System performance for Option 3.
Power, Heat, and Savings
in relation to Power Installed.


53
final amount of savings seems to be too small to consider
the installation of such a system (cost of installation
of two 600 KW units may be in the range of $800,000.00 to
$900,000.00). While the acceptable Return On Investment
in the industry is three to four years, in our case, the
return would be close to sixty years. For that size of
the unit, when the gas engine was selected in lieu of gas
turbine, the results were even worse due to the much
higher maintenance costs offsetting a little higher
efficiency of the gas engine vs. the gas turbine.
All of the above calculations were performed for
the cogeneration system operating with the third option
selected, which is to follow power demand curve.
Another option provided in the program, which
does not feature power sell to the utility company is
option 1. In this option program follows the heat demand
curve with no power being sold back to the utility
company. The results of the program's run with this
option selected are shown in Figure 22. As is
illustrated, a little better results are achieved in
generation of the power, while following the heat demand
curve for the plant. This time maximum savings for the
selected system configuration was obtained at 500 KW to
550 KW size of the single unit (1000 KW to 1100 KW total
system), which is only 100 KW less than that for the
system following power demand. This seems to indicate


Figure 22.
System performance for Option 1.
Power, Heat, and Savings
in relation to Power Installed.


55
that for units in the range of 500 KW to 650 KW, there is
a best possible match between the power generated and the
amount of the utilized heat of the exhaust of the
cogeneration process. Although the total annual revenues
increased to about $44,000.00 for option 1 of the
cogeneration system, terms for simple payback and Return
On Investment are still not acceptable. The fact, that
a sophisticated control scheme and equipment would be
required to "follow" heat demand curve in the plant,
makes relatively small savings even less significant.
We can conclude from our analysis, that the
hypothetical facility is not a very good candidate for
installation of the cogeneration system. There are
several reasons contributing to this conclusion:
1) Uneven monthly heating load at service
location "E" (almost no heat required during
summer months).
2) Daily load profiles of the required heat vs.
profiles of the power demand differ greatly
for the three typical days.
3) The total amount of the heat required in
the plant and the potential for better
utilization of the exhaust heat is
insufficient.
4) The plant operates one shift only, which
results in poor equipment utilization.


56
5) The cost of natural gas is too high in
relation to the inexpensive electric energy
(see Appendix C).
As an example of a successful installation of the
cogeneration system, a facility with 20 hours of
operation and an almost perfect match between the amount
of thermal energy of the exhaust of the cogeneration
system and the plant's demand is evaluated in Appendix B
(sample). The installation costs for one 115KW unit may
be in the range of $100,000.00 and generated revenues
amount to over $52,000.00 annually. In this case the
Return On Investment is a little less than two years -
the perfect illustration of a successful installation of
the cogeneration system.


CHAPTER VI
CONCLUSION
Since cogeneration means simultaneous generation
of electric power and the useful form of the thermal
energy or shaft power, one might think that all the
facilities with a need for both forms of energy represent
the ideal site for the installation of such a system.
Several other factors need to be evaluate in determining
the profitable cogeneration system installation. One of
the most important, is relation between the cost of the
electric energy versus the cost of the fuel of
cogeneration system; higher the ratio of cost of electric
energy is versus the cost of the fuel, the higher the
potential revenues from every KW of the on site generated
electric energy in the cogeneration cycle. The amount of
required electric and thermal energy may be less
important than the demand or load profiles of those
energies throughout typical days of plant's operation.
Ideally, all recoverable thermal energy of a cogeneration
process should be utilized, in order to obtain the
maximum possible economic results. The developed program
should serve as a tool for initial evaluation of the


58
feasibility of the installation of the cogeneration
system. This program should be able to help the
management of a facility make a decision on whether the
proposed cogeneration system should be implemented. By
manipulating several of the input data, an optimum
cogeneration arrangement can be determined, with the best
suitable size of the units and the mode of operation.
Not every facility with theoretical potential for
installation of a cogeneration system will generate
enough revenue to offset the required initial investment,
and to guarantee desired Return On Investment.


BIBLIOGRAPHY
General:
[1] Harkins, H.L., "PURPA New Horizons for Electric
Utilities and Industry," IEEE Transactions on Power
Apparatus and Systems, Vol. PAS-100, No. 6 June
1981, pp. 2784-2789.
[2] Reddoch, Thomas W., "PURPA and Associated Technical
Issues," Energy Division, Oak Ridge National
Laboratory, Oak Ridge.
Mechanical:
[3] McConnell, John E., "Industrial Cogeneration -
Insights and Observations," ASEA Inc., White Plains,
NY.
[4] Mears, L.D., Russ III, J.E., "Cogeneration
Application of The High Temperature Gas-Cooled
Reactor," IEEE Transactions on Power Apparatus and
Systems, Vol. PAS-103, No. 9, September 1984.
[5] Palmer, James D., "Cogeneration from Waste Energy
Streams Four Energy Conversion Systems Described,"
IEEE Transactions on Power Apparatus and Systems,
Vol. PAS-100, No. 6 June 1981.
[6] Pendergrass, Bonnie B., "Industrial Cogenaration
Design Options," KPFF Consulting Engineers, 700
Lloyd Building, Seattle, WA 98101.
[7] Regan, R.R., "Cogeneration for Commercial Shale Oil
Facilities," Copyright Material IEEE Paper No. PCI-
82-73 .
[8] Renard, Dan, "Energy Recovery Through The Use of
Expader Turbine and Induction Generator, Part 2,"
Copyright Material IEEE, Conference Record 80CH1549-
5 IA, Paper No. PCI-80-9.


60
[9] Show, T.R., "Energy Recovery Through The Use of
Expander Turbine and Induction Generator, Part 1,"
Copyright Material IEEE, Conference Record 80CH1549-
5 IA, Paper No. PCI-80-9.
[10] Solar Turbines Incorporated, "Cogeneration Systems."
[11] Van Housen, R.L., "Cogeneration A Profitable Way
To Save Energy in The Petrochemical Industries,"
Copyright Material IEEE Paper No. PCIC-84-6.
[12] Yuen, Moon H., Solt, Charles J., "Cogeneration for
Capitalization of Heat Requirements," Copyright
Material IEEE, Paper No. PCIC-84-34.
Electrical:
[13] Orlando, Joseph A. and Waukesha Power Systems
Application Engineering Staff, "Waukesha
Cogeneration Handbook," Copyright 1986, Edition 3.
[14] Daley, James M., "Design Consideration for Operating
On-Site Generators in Parallel with Utility
Service," IEEE Transactions on Inustry Applications,
Vol.IA-21, No. 1, January/February 1985.
[15] Donner, Gary L., "Cogeneration Project Sparks
Opportunity for Upgrading of Industrial Power
Distribution System," Copyright Material IEEE Paper
No. PCIC-84-14.
[16] Dugan, R.C., Fisher, P.R., Gilker, G., Kischefsky,
J.A., Ko, C.D., Thomas, S.A., Tong, V.Y.,
"Protection of Electric Distribution Systems With
Dispersed Storage and Generation (DSG) Devices,"
Report Prepared by McGraw-Edison Company for Oak
Rigde National Laboratory, September 1983,
Subcontract No. 7998.
[17] Hogwood, Jr, E.E., Rice, David E., "The Electrical
Aspects of Cogeneraton System Design," Copyright
Material IEEE Paper No. PCIC-85-36.
[18] McEachron, D.E., "Energy Recovery Through The Use of
Expander Turbine and Induction Generator, Part 3,"
Copyright Material IEEE, Conference Record 80CH1549-
5 IA, Paper No. PCI-80-9.
[19] Nason, Randall R., Collier, Steven E., "Metering
Consideration for Consumer-Owned Generation
Facilities," Conference Paper, 1985 IEEE.


61
[20] Nichols, Neil, "The Electrical Considerations in
Cogeneration," IEEE Transactions on Industry
Applications, Vol.IA-21, No. 4, May/June 1985.
[21] Owen, Edward L., Griffith, Glenn R., "Induction
Generator Applications for Petroleum and Chemical
Plants," Copyright Material IEEE Paper No. PCI-82-
14.
[22] Parsons,Jr., John R., "Cogeneration Application of
Induction Generators," IEEE Transactions on Industry
Applications, Vol.IA-20, No. 3, May/June 1984.
[23] Rook, Michael J., Goff, Leon E., Potochney, George
J., Powell, Louie J., "Application of Protective
Relays on a Large Industrial-Utility Tie With
Industrial Cdgeneration," IEEE Transactions on Power
Apparatus and Systems, Vol. PAS-100, No. 6 June
1981.
[24] Soderholm, Leo H., "Cogeneration Interface Update,"
Conference Paper No. 84CH1969-5, B4., USDA-ARS Iowa
State University, Ames, IA 50011.
[25] Woodbury, F.A., "Grounding Considerations in
Cogeneration," IEEE Transactions on Industry
Applications, Vol.IA-21, No. 6, November/December
1985 .
Utility and Cogeneration:
[26] Bengiamin, N.N., "Operation of Cogeneration Plants
with Power Purchase Facilities," IEEE Transactions
on Power Apparatus and Systems, Vol. PAS-102, No.
10, October 1983.
[27] Collier, Steven E., "Dealing with Cogenerators and
Small Power Producers," Coference Paper No.
84CH19690-5.
[28] Colorado-UTE Electric Association, Inc., "Standards
for Interconnection of Cogenerators and Small Power
Producers (Supplement)," January 1984.
[29] Meyer, F.J., "Houston Lighting and Power Company's
Approach to 5,000 Megawatts of Cogeneration,"
Transmission and Substation Design and Operation
Symposium, University of Texas at Arlington,
September, 1984.


62
[30] Moylan, William, "Utility Interconnection Issue with
Cogeneration," Moylan Engineering Associates Inc.,
CH1740-0/82.
[31] Public Service Company of Colorado, "Independent
Power Production Facility Policy Electric Purchase,"
Decision No. C87-10, February 11, 1987.
[32] Public Service Company of Colorado, "Safety,
Interconnection, and Reliability Standards for
Cogeneration and Small Power Producers," November,
1983 .
[33] Public Service Company of Colorado, "Policy
Statement on Interconnection with and Purchases from
Independent Power Producers," June 25, 1982.
[34] Public Service Company of Colorado, "Comprehensive
Plan in Response to Colorado Public Utilities
Commission, Decision C87-1690."
Economic:
[35] Kirby, Kevin A., Rich, John F., Mahoney, Paul J.,
"Cogeneration System Evaluation: A Case Study," IEEE
Transactions on Power Apparatus and Systems, Mol.
PAS-100, No. 6 June 1981.
[36] Tabors, Richard D., Finger, Susan, Cox, Alan J.,
"Economic Operation of Distributed Power Systems
Within an Electric Utility," IEEE Transactions on
Power Apparatus and Systems, Vol. PAS-100, No. 9
September 1981.


APPENDIX A
PROGRAM MANUALS AND SOURCE CODE


PROGRAM MANUALS
The program is written in GWBASIC and to run the
program, the user needs a IBM compatible PC with DOS as
an operating system.
Input data can be divided into two separate
categories: permanent and variable. The permanent data
form an integral part of the program and the first lines
of the program contain all of the required permanent
data. The variable data are the input data which are
entered during the program's execution and canbe
manipulated during multiple runs of the program.
The following is a description of all required
data and entries along with their original names as they
appear in the program:
Permanent Data
SCH utility service charge, depends on Utility
Rate Schedule in which power is purchased
(in $) .
PKR demand charge (in $/KW).
PR energy charge (in $/KWH).
MAXCHRG maximum energy charge (in $/KWH).


65
GASR gas commodity charge (in $/CCF).
LHV gas Lower Heating Value (in BTU/CF).
FUELR cost of turbine or engine fuel (in
$/FUELUNITS).
FUELUNITS number of .fuel units that cost FUELR
(if gas costs $0.35/CCF then FUELR = .35 and
FUELUNITS = 100).
FUELHEAT
VALUE Lower Heating Value of one unit of fuel.
MC unity maintenance costs (in $ per KW
generated).
HEATEFF factor related to efficiency of the
existing heating and absorption cooling
equipment. Quantity of consumed gas that
represents actual heating/ cooling loads in
plant. Thermal energy consumption in the
plant is expressed in GCF of gas. Not all of
the gas consumed is converted to useful
energy (in hundreds of percent).
COOLEFF related to efficiency of existing
nonabsorption cooling equipment used in plant
(in hundreds of percent).
RECOVEFF factor related to efficiency of heat recovery
equipment (in hundreds of percent).
TX all applicable taxes for the area paid on
gas and electricity.


66
SELLR rate at which utility company is willing to
purchase power from Qualifying Facility (in
$/KWH) .
KWVSMBTU amount of power required to generate one
MMBTU/HR of cooling thermal energy in
existing electric chillers. This will
determine the amount of power reduction in
the plant's consumption due to conversion
from electric to absorption equipment (in
KW/MMBTU/HR).
MAXGINPUT full-power input of thermal energy for one
prime mover of the anticipated cogeneration
system (in MMBTU/HR).
MAXGRECOV full-power recoverable thermal energy from
the cogeneration's one prime mover (in
MMBTU/HR).
UNITSIZE full-power of the generator output (in KW) .
P(K) generator's power output (in hundreds of
percent). Generator's characteristic
containing eleven entries from 0.0 to 1.0
of unit's capacity.
G(K) percent of the thermal energy input of prime
mover corresponding to P(K) power generation
(in hundreds of the percent, eleven entries).
H(K) percent of recoverable heat corresponding to
P(K) of generated power (in hundreds of
percent, eleven entries).


67
Variable Data
All of the above data are to be specified within
the program lines before actual program execution. In
the following segment we will discuss all the entries
that are to be made during program execution and are
prompted by the computer program. After inputing the
name of the facility, series of the following selections
have to be made:
- cogeneration system performance (one of four)
- mode of parallel generators operation (one of
two)
- power margin for 3rd selection of the system
performance
- generator power output (in KW for one unit)
- decide either to print all of the supporting
data along with printout of the results
- computations for new facility or rerun of old
existing data
If the new facility set-up is selected, a series
of heat, cooling, and power entries are required along
with other supporting information to simulate the plant's
actual performance on an hourly basis. The first series
of entries is a calendar which contains the number of
working days, Saturdays and Holidays/Sundays in each of
the twelve months of the year. Next, the user is asked to


68
input gas consumption data for every month of the year.
It is the amount of gas consumed in the plant, or its
portion, to generate thermal energy for heating and
absorption cooling intended to be replaced by energy of
the recoverable heat in the cogeneration process. Gas
consumption HRM(M) for month M is in CCF and gas peak
GPK(M) for month M is in CCF/HR. Very similar for the
amount of cooling produced by nonabsorption chillers, and
which the user intends to provide by utilization of
absorption chillers in the cogeneration process. Cooling
consumption CRE(M) is in MMBTU and cooling peak CRPK(M)
is in MMBTU/HR. User will have to convert amount of Tons
of cooling to MMBTU/HR.
For the entered heating and cooling requirements,
hourly load profiles are necessary for all three day
types specified in the calendar. There are 24 entries in
each day and three day types are to be entered for
heating loads as well as for cooling. All the entries
are in hundreds of percent of peak consumption for
heating or cooling energy. Since there are only three
typical load profiles (three typical days) for all twelve
months, adjustments of the profiles are required during
the program's run in order to achieve specified heating
and cooling consumption for every month. The program is
capable of such adjustment in a 30% range. If there is
more than 30% of adjustment required to meet monthly


69
energy consumption with given peak and load profile,
the program is interrupted and manual adjustment of the
load profiles is necessary. Since there is a need to
preserve the peak value from being distorted by profile
adjustment (power cost heavily depends on peak value),
the program is designed to recognize only one value of
1.0 within load profiles for heating, cooling and power
in all of the three day types. Simply, this value is
omitted in the adjustment process during program
execution. If none of the entries are equal to 1.0, .
there is no guarantee that the monthly energy consumption
calculated, will match the one specified. In the
program, gas load profiles GPR0F(I,J) will determine
what percent of the gas peak for a given month is to
become the Ith hour's and Jth day's gas consumption.
Similar for cooling load profiles CPR0F(I,J).
Then power consumption PERC(M) in KWH and power
peak demand PKD(M) in KW, followed by its load profiles
for three typical days are required. Again, the value
1.0 is allowed only once in all three days.
After every series of the inputs for one type of
data, the program allows the user to make certain changes
and adjustments before finally all of the variable data
is saved in the file named COGEN.BAS. If multiple runs
of the program are necessary to determine optimum system
parameters, or in order to experiment with plant's


70
characteristics, all that is required, is to answer "no"
to a question "new facility set-up ?", and all the data
stored in COGEN.BAS is used again with the possibility
yet of various changes and adjustments.
Program Output.
The program's execution takes between five and
ten minutes, depending on the selection of the program's
option. During the program's execution, the following
information about the plant's operation is established
and printed for every month:
old peak demand
new peak demand
plant electric energy consumption
power generated on site
power bought from utility after cogeneration
installation
power sold to utility
power saved or reduced in plant by absorption
chillers
cooling consumption
heating consumption
heat recovered in cogeneration process
wasted heat (recoverable heat that has not
been utilized)
prime movers heat input


71
Most of the described data is then used to
calculate operating costs of the plant before and after
installation of the cogeneration system. The program
prints out those operating costs on a monthly basis and
calculates economic results of the cogeneration system
operation. Also, the annual operating costs for the
plant are calculated. Finally, the program prints the
total annual consumption, and the generation of thermal
and electric energy for the facility. As an option, the
user may request a hard copy of all supporting data used
in the program calculations.


72
10 REHmmtt PROGRAM ECONOMIC EVALUATION OF THE COGENERATION SYSTEH ittmi
20 REHtHmfttitftifftttttff COST SAVING ANALYSIS ttm*mt*M**i*ttftttt
30 REM
^(j MAINTENANCE
50 REM SERV. CHARGE, PEAK RATE, ENERGY RATE, MAX ENER CHARGE, GAS RATE, GAS LHV, FUEL RATE, FUEL UNITS, FUEL HEAT VALUE,'
COST, HEATEFF, COOLEFF, RECOVEFF
GO REM
70 DATA 10.9,9.76,.02604,.12,.3270,837,.3270,100,837,.0033,1,1,1
80 REM
90 REM TAX,POKER SELL RATE.CH1LERS KH VS HNBTUH
100 REM
110 DATA 7.1,.0,60
120 REM
130 REM MAX GEN HEAT INPUT,MAX GEN HEAT RECOVERABLE, SIZE OF THE UNIT
140 REM
150 DATA 16.217,7.973,1000
160 REM
170 REM GENERATOR CHARACTERISTICS (P(K), S(K), H(K), ELEVEN EACH)
180 REM
190 DATA .0,.47,.42,.1,.52,.51,.2,.57,.54,.3,.61,.58,.4,.64,.61,.5,.67,.64
200 DATA .6,.7,.67,.7,.77,.75,.8,.84,.84,.9,.93,.91,1,1,1
210 CLS
220 WIDTH LPTls,132
230 OPEN *LPT1:' ASI2
240 LPRINT CHRS(15)
250 PRINT ECONOMIC EVALUATION OF COGENERATION SYSTEM
260 PRINT
270 PRINT COST SAVING ANALYSIS
280 INPUTNAME THE PROJECT: ,S$
290 BEEPiPRINTPLEASE SET THE PAPER AT A TOP OF THE PAGE. PRESS F5 TO CONTINUE
300 STOP
310 LPRINTDATE ; DATE!
320 LPRINTTIME ; TIME*
330 LPRINT ECONOMIC EVALUATION OF COGENERATION SYSTEM
340 LPRINT
350 LPRINT*
360 LPRINT
370 OPTION BASE 1
380 CLS
390 PRINT
400 PRINT
410 PRINT
420 PRINTl COVER HEAT DEHAND;NO POKER SELL
430 PRINT2 COVER HEAT DEMAND;SELL EXCESS TO UTILITY
440 PRINT3 COVER POKER DEMAND;UTILIZE MAX OF THE EXHAUST
450 PRINT4 MAX POKER GENERATION KITH SELL OF EXCESS TO UTILITY
460 PRINT
470 PRINT
480 PRINT
490 KHILE SELECTOl AND SELECT02 AND SELECT03 AND SELECT04: INPUTENTER YOUR SELECTION =';SELECT:WEND
500 PRI NT"YOU SELECTED ;SELECT
510 CLS
520 IF SELECT=4 THEN GOTO 640
530 PRINTSELECT OHE OF THE FOLLOWING OPTIONS
540 PRINT
550 PRINT
COST SAVING ANALYSIS* sLPRINT
PROJECT NAME: ;S(
SELECT ONE OF FOUR SYSTEH PERFORMANCES


560 PRINT-1 GENERATORS ESUALY LOADED AFTER FIRST LOADS TO 1001'
570 RRINT-2 1ST LOADS TO 1001 THEN SECOND PICKS UP THE REMAINED POWER'
580 PRINT
530 PRINT
600 WHILE HODEOl AND H0DEO2: INPUT'ENTER YOUR SELECTION';NODE:UENO
610 PRINT'YOU SELECTED 'jMODE
620 IF SELECT=3 THEN INPUT'ENTER POWER ALLOWED FROM UTILITY ='jPHAR
630 PRINT
640 INPUT'GENERATOR POWER OUTPUT =';PU
650 PRINT
660 PRINT'DO YOU WISH TO PRINT ALL INPUT DATA ?;Y DR N'
670 AINP$=:WHILE AINPIO'N' AND AINP$<>'Y':AINPi=INKEY$:WEND
680 DIM PS(24,3):DIN W(12):DIM C06PKD(12)
630 DIM CR(24,3):DIH M(12)
700 DIM PR(24,3):DIM L(12)
710 DIM P6(24,3):DIH PWRC(12)
720 DIM HC(24,3):DIN PKDC12)
730 DIM T6(24,3):DIH CRE(12)
740 DIM NPR(24,3):DIM CRPK(12)
750 DIN HR(24r12):DIM 8PK(12)
760 DIM P(11):DIH 6(11):DIN H(ll)
770 DIN HRM(12):DIM 8PR0F(24,3)
780 DIM T6i(24,3):DIH CPR0F(24,3)
730 DIM HCH24,3):DIM PPROF(24,3)
800 DIM PG1(24,3):DIH GMULTC12)
810 DIM S(12):DIH CHULT(12>
820 DIM UTILRC12):DIM PMULU12)
830 DIM T0THTREJ(12)
840 DIM PSELL(24,3)
850 DIM C06RC12)
860 DIM T0TSELLC12)
870 DIM T0TGASU2)
880 DIM HTREB(12)
830 DIN PWRSVDU2)
300 DIM HT8ENC12)
310 DIM COOLREQC12)
320 DIM USEDPWRU2)
330 DIM 8ENPWRU2)
340 DIM UTILPWR(12)
350 READ SCH,PKRtPRlNAXCHRG(GASR,LHV,FUELRtFUELUNITSrFUELHEATVALUEtHC,HEATEFF.COOLEFF.RECOVEFF
360 READ TX,SELLR,KUVSMBTU
370 READ MAX6INPUT,HAX6RECQV,UNITS.IZE
380 FOR K=1 TO 11
330 READ P(K),6(K),H(K)
1000 NEXT K
1010 TAX=TX/100+1
1020 FR=(FUELR/FUELUNITS*1000000!/FUELHEATVALUE)*TAX
1030 6R=(6ASR10000/LHV)*TAI
1040 TG=PU/UNITSIZEMAXGINPUT
1050 HU=PU/UNITSUEMAISRECOV
1060 FOR K=1 TO 11
1070 P(K)=P(K)PU
1080 6(K)=G(K)*TG
1030 H(K)=H(K)HU
1100 NEXT K
1110 CLS


1120 PRINT NEU FACILITY SET-UP ?, Y FOR YES, N FOR NO
1130 PRINTIF ANSWER IS -NO- EXISTING DATA FRON COGEN.BAS HILL BE LOADED
1140 NO* =*
1150 WHILE NDtOY AND NDtOH":ND*=INKEY*:HEND
1160 PRINT ; ND$
1170 IF ND*=Y GOTO 1100
1180 IF ND$=N GOTO 5820
1190 REN INITIAL INPUT OF DATA
1200 REN
1210 REN
1220 CLS
1230 PRINT'
1240 PRINT
1250 PRINT ENTER CALENDAR-
1260 FOR N=1 TO 12
1270 PRINTNO. = jNj
1280 INPUTjWORKING DAYS = \H(H)
1200 PRINT i
1300 INPUT;SATURDAYS = ,N(N)
1310 PRINT ;
1320 INPUTSUND. & HOL = ,L(N)
1330 NEXT N
1340 CLS
1350 PRINT HEAT DATA
1360 PRINTENTER AMOUNT OF GAS USAGE IN ICCFI AND GAS PEAK IN ICCF/HR3*
1370 PRINT(ONLY THE AMOUNT YOU INTENT TO COVER IN C06EN PROCESS)
1380 PRINT(HAETING, COOLING, PROCESS)
1330 FOR H=1 TO 12
1400 PRINTNO. = jN;
1410 INPUT;GAS CONSUH =,HRH(N)
1420 PRINT ;
1430 INPUTGAS PEAK = ,GPK(N)
1440 NEXT It
1450 CLS
1460 PRINTENTER AMOUNT OF COOLING THAT IS PRODUCED BY ELECTRICAL
1470 PRINTCHILLERS AND YOU INTENT TO COVER IN COGENERATION
1480 PRINT(HHBTU FOR CONSUH, HHBTU/HR FOR PEAK)"
1490 PRINT
1500 FOR H=1 TO 12
1510 PRINTHO. = ";H;
1520 INPUT;COOL. REQ. = ,CRE(H)
1530 PRINT ";
1540 INPUTCOOL. PEAK = ",CRPK(H)
1550 NEXT H
1560 CLS
1570 REH DAY PROFILE FOR GAS USE
1580 IF NDt=*Y" THEN 60T0 1650
1590 PRINTYOU WISH TO HAKE ANY CHANGE IN EXISTING DATA?;Y DR N
1600 A$=:WHILE A<>Y AND A<>N:A$=INKEY*:WEND
1610 IF At=N" THEN GOTO 2670
1620 PRINTWISH TO INPUT NEW LOAD PROFILES FOR GAS ?;Y OR N
1630 Ai=:WHILE A$<>Y" AND A$<>N:A$=INKEY$:WEND
1640 IF At=N" THEN GOTO 1730
1650 PRINTENTER DAY PROFILES FOR GAS CONSUMPTION (0 TO 1.0)
1660 PRINTENTER VALUE 1,0 ONLY ONCE FOR ALL THREE DAY TYPES I!!
1670 FOR J=1 TO 3


75
1680 IF JOl THEN CLS:PRINT,ENTRY FOR DAY J
1690 FOR 1=1 TO 24
1700 PRINT'FOR DAY ;J;:PRINT*FOR HR *;I;:INPUT'BAS USE PROF*;GPROF(I,J)
1710 NEXT I
1720 NEXT J
1730 CLS
1740 PRINT'HISH TO INPUT NEH LOAD PROFILES FOR C00LIN6 ?;Y OR N'
1750 AT=":UHILE ATO'Y' AND ATO"N':AT=INKEYT:UEND
1760 IF AT='N" THEN SOTO 1850
1770 PRINT'ENTER DAY PROFILE FOR COOLING USAGE (0 TO 1.0)*
1780 PRINT'ENTER VALUE 1.0 ONLY ONCE FOR ALL DAY TYPES !!!'
1790 FOR J=1 TO 3
1800 IF JOl THEN CLS:PRINT"ENTRY FOR DAY *;J
1810 FOR 1=1 TO 24
1820 PRINT'FOR DAY *;J;:PRINT'F0R HR *;I;:INPUTCOOL. USE PROF ".CPROFII,J)
1830 NEXT I
1840 NEXT J
1850 REH CHANGE SUBRTN FOR HEAT AND POUER DATA
1860 REH
1870 REH
1880 CLS
1890 PRINT'CHANGE HTLY GAS CONSUHPTION AND PEAK ?,Y OR N'
1900 AT="
1910 UHILE ATO'Y' AND ATO'N':AT=INKEYT:HEND
1920 PRINT AT
1930 IF AT='Y' THEN INPUT'INPUT MNTH FOR CHANGE';J:PRINT'HO.=";J;:PRINT'OLD HNLY GAS CONS.; OLD PEAK'; HRH(J),GPK(J):
EH GAS CONSUH.; NEH PEAK';HRH(J),GPK(J):FLIPP=1 INPUT'INPUT N
1940 PRINT'MDRE CHANGES ?,Y OR N'
1950 At="
1960 UHILE ATO'Y' AND ATO'N':AT=INKEYT:HEND
1970 PRINT AT
19B0 IF AT='Y" GOTO 1930
1990 CLS
2000 PRINT'CHANGE CODLING DATA ?,Y OR N'
2010 AT="
2020 UHILE ATO'Y' AND ATO'N':AT=INKEYT:HEND
2030 PRINT AT
2040 IF AT='Y' THEN INPUT'INPUT HNTH ;l FOR CHANGE'iJ:PRINT'HO.=';J;:PRINT'OLD HNTHLY COOL CONS. ; OLD PEAK =*;CRE(J>,
NPUT NEH COOL CONS. ;NEH PEAK';CREIJ),CRPKCJ) CRPK(J):INPUT*I
2050 PRINT'HORE CHANGES ?,Y OR N'
2060 AT="
2070 UHILE ATO'Y' AND ATON":AT=INKEY$:HEND
2080 PRINT AT
2090 IF AT='Y' GOTO 2040
2100 PRINT'ALL DONE HITH HEAT/COOLING ?,Y OR N'
2110 AT=
2120 UHILE ATO'Y' AND ATO'N':AT=INKEYT:UEND
2130 PRINT AT
2140 IF AT='Y GOTO 2150 ELSE IF AT='N" GOTO 1890
2150 REH POUER PARAHETERS INPUT
2160 REH
2170 REH
2180 IF NDT="N' THEN GOTO 2320
2190 CLS
2200 PRINT' POUER PARAHETERS INPUT-
2210 PRINT
2220 PRINT
2230 PRINT'ENTER TOTAL PLANT HONTHLY POUER CONSUHPTION AND PEAK'


76
2240 PRINT1(KUH AND KU)
2250 PRINT
2260 FDR H=1 TO 12
2270 PRINTHO. = 'jN;
2260 INPUT;"PORER CONSUN. = *,PHRC(M)
2290 PRINT1 ;
2300 INPUT'PDUER PEAK = ",PKD!H)
2310 NEXT H
2320 CLS
2330 IF ND^T THEN GOTO 2370
2340 PRINT-WISH TO INPUT NEW LOAD PROFILES FOR POWER ?;Y OR N1
2350 At=": WHILE AtOY* AND A$<)1N1:A$=INKEY$:NEND
2360 IF At=-N" THEN GOTO 2460
2370 PRINTENTER DAY PROFILE FOR POKER (0 TO 1.0)
2380 PRINT-ENTER VALUE 1.0 ONLY ONCE FOR ALL TREE OAY TYPES !.!!"
2390 FOR J=1 TO 3
2400 IF JOl THEN CLSiPRINTENTRY FOR DAY 1;J
2410 FOR 1=1 TO 24
2420 PRINT'FOR DAY 1;J;sPRIKT-FOR HR I;
2430 INPUTPDHER PROF = ".PPROFtI,J)
2440 NEXT I
2450 NEXT J
2460 CLS
2470 PRINT-CHANGE POKER CDNSUtl AND/OR PEAK) ?,Y OR N1
2480 A$="
2490 WHILE A$(>"Y" AND At<>'N'!A$=INXEY$:UEND
2500 PRINT At
2510 IF A*="N1 THEN GOTO 2600
2520 INPUT-INPUT HONTH FOR CHANGE1;H
2530 PRINT-OLO POWER AND PEAK =-;PHRC(H),PKD(H)
2540 INPUT-INPUT NEK VALUE OF POKER AND PEAK =-,PHRC(H),PKD(H)
2550 PRINT-ALL DONE ?,Y OR N1
2560 Ai="
2570 WHILE ASOT AND A*< >*N; A*=INKEY*: WEND
2580 PRINT At
2590 IF At=-N- THEN GOTO 2520
2600 CLS
2610 PRINT-DO YOU KISH TO HAKE THE ENTRIES/CHANGES PERMANENT?;Y OR N"
2620 At=": WHILE AtO'Y1 AND AtO"N':A$=INKEYt:WEND
2630 IF A$=-N- THEN GOTO 2670
2640 PRINT-ALL HEATING, C00LIN6 AND POWER LOAD DATA1
2650 PRINT-WILL BE STORED IN FILE NAHED: COGEN.BAS"
2660 GOTO 5710
2670 CLS
2680 PRINT-COMPUTING...WAIT FOR RESULTS..1
2690 LPRINT
2700 LPRINT
2710 LPRINT'HO. EN HEAT- OLD ELECT NEW ELECT ELECT POWER POWER POWER POWER COOLING HEAT
2720 LPRINT- NPUT- PK DEK. PK DEH. CONSUHP GENER BOUGHT SOLD SAVED CONSUHP CONSUHP
2730 LPRINT- IKW) IKW) £ KWH I [KUH] [KWH I [KUH] [KUH) [HHBTUI IHHBTU)
HMBTUI-
2740 LPRINT
2750 FOR H=1 TO 12
2760 DGRED=0:DCRE0=0:DPREfi=0
2770 FOR J=1 TO 3
2780 6REB=0:CREB=0:PREDU=0
2790 IF J=I THEN X=W(N)
HEAT
RECOVRD
IHHBTU)


77
2800 IF J=2 THEN X=(h)
2810 IF J=3 THEN X=LCM)
2820 FDR 1=1 TQ 24
2830 IF fiPROFCI.JKM THEN GREB=6RE0+6PK(H)*GPRDF(I,J) ELSE YG=X
2840 IF CPROFdjJJOl THEN CREQ=CREQ+CRPK(H)*CPR0F11,J) ELSE YC=X
2850 IF PPR0F(I,JX>1 THEN PREQU=PREQU+PKD(H)PPR0F(IrJ) ELSE YP=X
2860 NEXT 1
2870 DSREQ=DGREQ+SREQ*X
2880 DCREB=DCREQ*CREBX
2830 DPREQ=DPREQ+PREBU*X
2900 NEXT J
2910 IF D6REQOO THEN 6HULT(H)=(HRNCN)-D6REQ-Y6GPK(H))/DGREB+1
2920 IF DCREQOO THEN CMULTtM)=tCRECM)-DCREB-YC*CRPKtM))/DCREB+l
2930 IF DPREBOO THEN PHULTtK)=(PHRC(W)-DPREQ-YP*PKDtM)1/DPREQ+1
2940 IF GHULT(H)>1.3 OR GHULT(HK.7 THEN GOTO 2970 ELSE 60T0 3000
2950 IF CHULT(H)>1.3 OR CHULT(HX.7 THEN GOTO 2980 ELSE GOTO 3000
2960 IF PHULT(H)>1.3 OR PKULT(KK.7 THEN GOTO 2990 ELSE GOTO 3000
2970 BEEPiPRINT'YOUR GAS BAY PROFILES ARE HORE THAN 302 OFF. PLEASE CORRECT >*:GOTO 5930
2980 BEEPiPRINT'YOUR C00LIN6 DAY PROFILES ARE MORE THAN 302 OFF. PLEASE CORRECT !':GOTO 5930
2990 BEEPiPRINT'YOUR POWER DAY PROFILES ARE HORE THAN 302 OFF. PLEASE CORRECT !:60T0 5800
3000 FOR J=1 TO 3
3010 FDR 1=1 TO 24
3020 IF GPRDFd,JX>1 THEN GPROFtI,J)=GPROF(IIJ)*GHULT(H)
3030 IF CPROFtI,J)<>1 THEN CPROFU,J)=CPROF(I,JHCHULT(H)
3040 IF PPR0F(I,J)<>1 THEN PPRDFCl,J) =PPROFCI,J)*P(1ULTCH)
3050 NEXT l
3060 NEXT J
3070 T0TSELL=0
30B0 T0THTREJ=0
3090 T0TGAS=0
3100 HTREB=0
3110 PNRSVD=0
3120 HTGEN=0
3130 C0OLREQ=O
3140 USEDPNR=0
3150 GENPUR=0
3160 UTILPHR=0
3170 FOR J=1 TO 3
3180 HTR=0
3190 PSE=0
3200 61=0
3210 HR=0
3220 H6=0
3230 PRE=0
3240 6P=0
3250 UTP=0
3260 PS=0
3270 CR=0
3280 IF J=1 THEN X=H(N)
3290 IF J=2 THEN X=HCN)
3300 IF J=3 THEN X=L(H)
3310 FOR 1=1 TO 24
3320 HR(I,N)=6PK(H)6PR0F(I,j)LHV/10000HEATEFF/RECOVEFF
3330 CRlI,J)=CRPK(H)CPRQF(I,J)/COOLEFF/RECOVEFF
3340 PS(I, J) =CR11, J)KHVSHBTUCOOLEFF
3350 PR(I,J)=PKD(H)tPPROF(I,J)


78
3360 HTREJ=0
3370 NPR=0
33B0 PSELL=0
3390 P6KI,J)=0:P8CIf J)=0
3400 HC1(If J)=0:HC(I,J)=0
3410 TGI(Ir J)=0sT6CI,J)=0
3420 TKR=HR(l,H)+Cft(IlJ)
3430 IF SELECT=1 OR SELECTS THEN SOTO 3670
3440 IF SELECT=3 THEN GOTO 3460
3450 IF SELECTS THEN GOTO 3620
3460 PREB=PR d,J)-PS d, J)-PMAR
3470 IF PREB<.1PU THEN PG(I,J)=0:TG(I,J)=0;HC(IFJ7=0:PStIfJ)=0:PREB=PRd,J)-PSd,J):60T0 3940
3480 IF PREQ>=2*PU THEN PGCI,J)=2*PU:HCCIfJ)=2*HU:TG(I,J)=2*TS:G0T0 3590
3490 IF PREQ>PU AND PREQ<2*PU THEN IF MODEM THEN PG1tI,J)=.5*PREQ ELSE IF MODEM THEN P61d,J)=PREB-PU
3500 IF PREB>PU AND PREfi<2PU THEN IF PGld.JXPd) THEN PG(I,J)=PU:HC11,J) =HU:TG(IrJ) =TS:GOTO 3590
3510 IF PRES<=PU THEN PG1(I,J)=PREB
3520 FOR KM TO 11
3530 N=K-1
3540 IF PG1(I,J)>=P(N) AND PGld.JXPOO THEN GOTO 3560
3550 NEXT K
3560 HCin,J)M(H(K)-H(N))/(P(K)-P(N))t(PGldfJ)-P(N)))+H(N):T61dlJ)M(6(K)-G(N))/(P(K)-P(N))(P61d,J)-P(N)))+G(N)
3570 IF PREBXPU AND PREfl<2PU THEN IF MODEM THEN HC(I,J)=2*HC1CI,J);TGtI,J)=2*TG1tI,J>:PG(I,J)=PG1CI,J)*2 aSE IF MODEM
J)=HC1tIrJ)+HUjT6(I,J)=TG1(I,J)+TGsPG(I,J)=PG1ClfJ7+PU
3580 IF PREQ<=PU THEN PGtI,J)=PG1(I,J):HC(I,J)=HC1(I,J):TGCIrJ)=TG1(I,J)
3590 IF HCU,JKCR(I,J) THEN BEEP;PRINT'INCREASE THE SIZE OF A GENERATOR SETS FOR BEST RESULTS !':GOTO 5930
3600 IF HCd,J)>THR THENHTRE J=HCd,J)-THR;HCII, J) MHR
3610 GOTO 3940
3620 PRE8=PR(I,J)-PS(I,J)
3630 PS(I,J)=2*PU!T6(If JJ='2*TG:HC(I,J) =2*HU
3640 IF HCd,JXCRd,J) THEN BEEP;PRINT'INCREASE THE SIZE OF A GENERATOR SETS FOR BEST RESULTS !';GOTO 5930
3650 IF HCd,JTHR THEN HTREJ=HC(1,J)-THR:HCCI,J)=THR
3660 GOTO 3930
3670 IF THR 3680 IF THR>=2*HU THEN HC 3690 IF THR>HU AND THR<2*HU THEN IF HODEM THEN HC1(I,J)=.5THR ELSE IF MODEM THEN HC111rJ)=THR-HU:GOTO 3710
3700 IF THR<=HU THEN HCKI,J)=THR
3710 FOR KM TO 11
3720 N=K-1
3730 IF HCld,J)>=H(N) AND HCld.,JXH(K) THEN GOTO 3750
3740 NEXT X
3750 PG1(I,J)=((P(K)-P(N))/(H(K)-H(N))*(HC1(I,J)-H(N)))+P(N)
3760 TGld,J)=((6(K)-6(N))/(H(K)-H(N))*(HCl(I,J)-H(N)))+6(N)
3770 IF THRJHU AND THR<2*HU THEN IF MODEM THEN HC(I,J)=HC1 ,J)=2*HCl(IlJ):TGtI, J)=2*TGI(I,J):PG(1,J)=2*PG1(I,J)
3780 IF THR 3790 IF HCd,JKCRd,J) THEN BEEP:PRINTINCREASE THE SIZE OF THE UNIT FOR BEST RESULTS !!!':GOTO 5930
3B00 PREfl=PRd,J)-PSd,J)
3810 IF P6d,JX=PRE8 GOTO 3940 ELSE IF SELECTM THEN GOTO 3930
3820 IF PREBXPU THEN IF M0DE=1 THEN PGKI,J)=.5PREB ELSE IF MODEM THEN PGld,J)=PREB-PU:GOTO 3B40
3830 IF PREB<=PU THEN PG1(I,J)=PRE6
3B40 FOR KM TO 11
3850 N=K-1
3860 IF P61(I,J)>=P(N) AND PG1 (I,JXP(K) THEN GOTO 3BB0
3870 NEXT K
3880 HCldIJ)M(H(K)-H(N))/(P(K)-P(N))*(P61dIJ)-P(N)))+H(N):T61d,J)M(6(K)-6(N/(P(K)-P(N)H(P61d,J)-P(N)))*6(N)
3890 IF PREBXPU THEN IF MODEM THEN HC(I,J)M*HC1 (I,J):TG(I,J) =2*TG111,J) ELSE IF MODEM THEN HCd,J)=HC1(I,JHHU:TGd,J)=TG1
G
3900 IF PREB 3910 IF HCd.JXCRd.J) THEN BEEP:PRINT'INCREASE THE SIZE OF THE UNIT FOR BEST RESULTS !!!':GOTO 5930


3920 Pe(I,J)=PREB
3930 IF P6U,J)>PRE0 THEN PSELL=PGCI,JJ-PREQ
3940 REN PRINT'H(N) B(N) PIN) N I J N
3950 REN PRINT H(N);6(N);P(N);N;I;J;H
3960 REN PRINTHCU.J) T6(I,J) PB(I,J) PR(I,J) PS(I,J) HR(I,N) THR PSELL HTREJ'
3970 REN PRINT HCtI,J)(TSU,J)fP6(I,J);PR(I,J);PS(I,J)jHRtl,H)jTHR;PSELL;HTREJ
39B0 REN STOP
3990 HR=HR+HRCI,N)
4000 PSE=PSE+PSELL
4010 HTR=HTR+HTREJ
4020 61=BI+TB(I,])
4030 HG=HG+HC(IfJ>
4040 PS=PS+PS(I,J)
4050 PRE=PRE+PR(I,J)
4060 CR=CR+CR(I,J)
4070 6P=GP*P6(I,J)
4080 NPR=PREQ-P6(I,J)+PSELL+PHAR
4090 UTP=UTP+HPR
4100 REN PRINTPOHERSELL=;PSE
4110 REN PRINT-UTILPOHER =";UTP
4120 REN PRINT'PSAVEO-';PS
4130 REN PRINT"P6EN= *;8P
4140 REN PRINT-PREB=*;PRE
4150 IF NPR>COGPKD(N) THEN COSPKD(N)=NPR
4160 NEXT I
4170 TOTHTREMDTHTREJtHTRU
41B0 TOTSELL=TOTSELL+PSE*X
4190 T0T6AS=T0T6AS*6IU
4200 HTREQ=HTREB+HR*X
4210 PURSVD=PHRSVD+PSX
4220 HTGEN=HT6EN+H6*X
4230 COOLREQ=CQOLREG+CR*X
4240 USEDPHR=USEDPUR+PRE*X
4250 SENPHR=SENPUR*6P*X
4260 UTILPHR=UTILPHR+l!TP*X
4270 REN STOP
4280 NEXT J
4290 TOTHTREJ CN)=TOTHTREJ
4300 TOTSELL(h)=TOTSELL
4310 TOT6AS(H)=TOTSAS
4320 HTRES(N)=HTRES
4330 PURSVD(HJ=PHRSVD
4340 HTGEN(N)=HTGEN
4350 CQQLREB CH)=COOLREfl
4360 USEDPUR(H)=USEDPUR
4370 BENPHR(N)=BENPHR
4380 UTILPHR(N=imLPUR
4390 XJTILR(H) = (SCHtPKD(H) *PKR+USEDPyRPR)/USEDPHRUAX
4400 IF UTILPHR=0 THEN C0BR(H)=UT1LR(N):60T0 4420
4410 COBR(N)1(SCH*COGPKD(N)*PKR+UTILPHRPR)/UTILPHR*TAX
4420 IF COBR(N)>NAXCHRG THEN COGR(N)=NAXCHRG
4430 LPRINT USIN6 *;;
4440 LPRINT USING III! ";PKDCN);CDGPKD(N);sLPRINT"
4450 LPRINT USING ;USEDPUR;6ENPHR;UTILPHR;TQTSELLfPWRSVD;COOLREB;HTREB}HTGEN;TOTHTREJ; TQTGA3
4460 NEXT N
4470 LPRINT


80
4480 IPRINT
4490 IF MDDE=1 THEN LPRINT'LOAD ON THE GENERATORS DIVIDES EQUALY.*j:LPRINT' TWO UNITS DF';PUf:LPRINT"IKH] EACH*
4500 IF M0DE=2 THEN LPRINT"FIP.ST 6ENEP.AT0R LOADS TO 100 PERCENT THEN SECOND UNIT KICKS ON AND PICKS THE EXCESS LOAD. TWO UNITS
U;:LPRINT'[THI EACH"
4510 IF SELECTS THEN LPRINTCOVER HEAT DEHAND; NO EXCESS POKER SOLD TO UTILITY"
4520 IF SELECT=2 THEN LPRINfCOVER HEAT DEHAND; EXCESS POKER SOLD TO UTILITY"
4530 IF SELECT=3 THEN LPRINTCOVER POKER DEHAND LESS MARSIN=";PHAR;sLPRINT" IKK!"
4540 IF SELECTM THEN LPRINT'BOTH UNITS AT FULL POKER =";2*PU;:LPRINT"EKHH]:LPRINT" EXCESS POKER SOLD TO UTILITY"
4550 REH LPRINT
4560 REH LPRINT'HODE SELECT PU TG HU"
4570 REH LPRINT HODE;SELECT;PU;TG;HU
4580 LPRINT
4590 LPRINT" BEFORE COGENERATION AFTER COGENERATION"
4600 LPRINT'HO. t/HT REQUIRED J/UTIL PUR S/HT AFTER i/FUEL COST S/POHER AFTER l/HAINTENANCE t/PHR SOLD
LY SAVING"
4610 LPRINT
4620 FOR H=1 TO 12
4630 HTB=HTREQ(H)GR
4640 PRB=USEDPHR(H)UTILR(H)
4650 IF HTGENCM)>COOLREQCH) THEN HTA=(HTREQ(H)-HTGEN(H)+COOLRES(H))*GR ELSE HTA=HTREQ(H)*GR
4660 FC0ST=T0T6AS(H)*FR
4670 PRA=UTILPHR(H)COGR(H)
4680 KA=GENPWR(H)HC
4690 SL=TDTSELL(H)*SELLR
4700 SCH) =HTB+PRB-(HTA+FCOST+PRA-MA)+SL
4710 LPRINT USING "";H;:LPRINT USING $$lll,llll.ir;HTB;PRB;HTA;FCOST;PRA;HA;SL;S(H)
4720 3AVING=SAVING*-S(N)
4730 CHB=CHB+HTB
4740 CPB=CPBPRB
4750 CHA=CHA+HTA
4760 CFUL=CFUL*FCOS(
4770 CPA=CPA+PRA
4780 CHA=CHA>MA
4730 CSEL=CSEL+SL
4800 TGS=T6GtT0TGAS(H)
4810 THEAT=THEAT+HTREB (H)
4820 TCOOL=TCOOL+COOLREQ(H)
4830 THU=THU+HTREQ(HHCOOLREQ(M)
4840 TPSVD=TPSVD+PKRSVD(H)
4350 THG=TH8*HTGEN(H)
4860 TPU=TPUrUSEDPKR(M)
4870 TPG=TPG+GENPHR(M)
4830 TPSLD=TPSLD+TOTSELL(M)
4B90 TPB=TPB+UTILPKR(H)
4900 THTR=THTRf-TOTHTREJ(H)
4910 NEXT H
4920 LPRINT:LPRINT" ;
4930 LPRINT USING " $11111,111.II";CHB;CPBjCHAjCFUL;CPA;CHA;CSEL;SAVING
4940 LPRINT
4950 LPRINT" YEARLY GAS/HEAT AND ELECTRIC POKER CONSUMPTION"
4960 LPRINT
4970 LPRINT" GAS/HEAT";:LPRINT" ";
4980 LPRINT" ELECTRIC POKER
4990 LPRINT
5000 LPRINT USING "GENERATORS FUEL INPUT =1111111111";TGG*1000000!/FUELHEATVALUE/FUELUNITS;:LPRINT" CFUELUNITSI";
5010 LPRINT USING "POKER USED IN PLANT
5020 LPRINT USING "GENERATORS HEAT INPUT
5030 LPRINT USING "POKEP. GENERATED
=IIIIIIIIII";TPU;:LPRINT" EKHH]"
=1111111111";TGG;:LPRINT" EHHBTUT";:LPRINT
=IIIIIIHH";TPG;:LPRINT" IKKHI"


81
HHtiltlit'
=1111111111
=titiintr
=iiiiiittr
Miiiiiiiir
=1111111111
Miiiiiiiir
=1111111111'
THEAT;:LPRINT [HHBTU];:LPRI NT
TPBjsLPRINT [KHHJ"
TCOQLj:LPRINT [HhBTU];sLPRINT
TPSLDj:LPRINT" [KWH]
THU;sLPRINT- CMHBTU3";sLPRINT"
TPSVD;sLPRINT* [KWH]
THTR;sLPRINT' [HHBTU]
THG;sLPRINT [HHBTU]
5040 LPRINT USING HEAT USED IN PLANT
5050 LPRINT USING POWER BOUGHT FROH UTIL
5060 LPRINT USING COOLING USED IN PLANT
5070 LPRINT USING POWER SOLD
5080 LPRINT USING HEAT REQUIRED FROH EXHAUST
5090 LPRINT USING POWER SAVJED BY ABSORPTION CHLR.
5100 LPRINT USING HEAT UASTED/EXHAUST
5110 LPRINT USING HEAT UTILIZED/EXHAUST
5120 FOR 1=1 TO 7
5130 LPRINTsNEXT I
5140 IF AINPI=N THEN GOTO 5680
5150 CLS
5160 LPRINT SlsLPP.INI
5170 LPRINT "NUHBER OF EACH DAY TYPE PER HONTH
5180 LPRINT
5190 LPRINTDAY TYPE 1 WORKING DAY:LPRINT"DAY TYPE 2 SATURDAYsLPRINTDAY TYPE 3 SUNDAYsLPRINT
5200 LPRINTHO. DAY TYPEsLPRINT 1 2 3
5210 LPRINT -------------------------
5220 LPRINT
5230 FOR H=1 TO 12
5240 LPRINT USING U';N;:LPRINT USING'IIIIII';W(H);H(H);L(H)
5250 NEXT H
5260 LPRINTsLPRINT
5270 LPRINT
5280 LPRINTsLPRINT
GAS AND POWER CONSUHPTION FOR THE PLANT
GAS
PEAK CONSUHP PEAK CONSUHP PEAK CONSUHP POWER HEAT INPT
[CCF/HI [CCFI [HHBTU/HI IHHBTU3 [KW] [KWH] [KW] [HHBTU/HR]
COOLING ELECTRICsLPRINT
............ ............. GENERATOR CHARACTERISTICS"sLPRINT
5290 LPRINT
RECOV
5300 IPRINTHO.
U/HR3'
5310 LPRINT
5320 FOR H=1 TO 12
5330 LPRINT USING Sl*-;H;:LPRINT USING l#";6PK(H);HRH(H);CRPK(H);CRECH)jPKD(H);PWRC(h);
5340 IF H<=11 THEN LPRINT USING"tMIIl.lir;P(H);G(H);H(H)
5350 NEXT H
5360 LPRINTiLPRINT sLPRINT sLPRINT:LPRINT:LPRINTsLPRINT:LPRINTsLPRINT sLPRINT:LPRINT:LPRINT:LPRINT:LPRIHT sLPRINT;LPRINT sLPRINT;
PRINTsLPRINTsLPRINT
5370 LPRINT SIsLPRINT
53B0 LPRINT LOAD PROFILESsLPRINT
5390 LPRINT GAS COOLING ELECTRIC
5400 LPRINT DAY TYPE DAY TYPE DAY TYPE
5410 LPRINTHOUR 123 123123
5420 LPRINT" -----------------------------------------------------.......-"sLPRINT
5430 OPEN COGEN.BAS FOR INPUT AS II LEN=15
5440 FOR H=1 TO 12
5450 INPUT lrHRH(H),GPKCH]rCRE(H)tCRPK(H),PHRC(H),PKD(H),H(h),H(M),L(H)
5460 NEXT K
5470 FOR J=1 TO 3
5480 FOR 1=1 TO 24
5490 INPUT 1,6PR0F(I,J),CPROF 5500 NEXT I
5510 NEXT J
5520 FOR 1=1 TO 24
5530 LPRINT USINSIII;I;sLPRIHT ";sLPRINT USING -!.;GPROF[1,13;GPRDF(1,2);8PR0F(1,3);CPROF(1,1);CPROF(1,2);
F11,1); PPROF(1,2); PPROF(1,3)
5540 NEXT 1
5550 CLOSE il
5560 LPRINTsLPRINT
5570 LPRINT OTHER SYSTEH CHARACTERISTICS
5580 LPRINT
5590 LPRINT USING GENERATOR POWER OUTPUT l#S;PU;sLPRINT [KW]


5600
5610
5620
5630
5640
5650
5660
5670
5680
5690
5700
5710
5720
5730
5740
5750
5760
5770
5780
5790
5800
5810
5820
5830
5840
5850
5860
5870
5880
5890
5900
5910
5920
5930
5940
LPRINT USING "6AS LOVER HEATING VALUE
LPRINT USING GAS CHARGE
LPRINT USING 'COST OP 1 HHBT
HIM"
t.ttr
Mil'
LHVjiLPRINT' CBTU'
GASR;:LPRINT' II/CCFI
GRj:LPRINT" tl/NHBTUl
LPRINT USING 'UTILITY SERVICE CHARGE III.II'
LPRINT USING 'UTILITY DEHAND CHARGE I.IH*
LPRINT USING 'ENERGY CHARGE .Hill'
LPRINT USING 'ALL APLICABLE TAXES I.IH'
LPRINT USING 'MAINTENANCE COSTS .1111
PRINT'CALCULATIONS COMPLETED SUCCESSFULY. THANK YOU
GOTO 5930
SCH;:LPRINT' HI'
PKR;:LPRINT' II]'
PR;:LPRINT' HI'
TX;:LPRINT' II]'
MC;iLPRINT' II/KHI'
REM SAVE ALL THE DATA
OPEN 'COGEN.BAS' FOR OUTPUT AS II LEN=15
FOR M=1 TO 12
URITE f1,HRH(M),GPK(H),CRE(H),CRPKCM),PURCCM),PKD(M),UCH)rM(H)tL(H>
NEXT H
FOR J=1 TO 3
FOR 1=1 TO 24
URITE 11, GPROFd, J), CPROF (I, J), PPROFII, J)
NEXT I
NEXT J
CLOSE 11
GOTO 2670
OPEN 'COGEN.BAS' FOR INPUT AS II LEN=15
FOR H=1 TO 12
INPUT tl,HRHCM)fGPK(M)fCRECM),CRPKCM),PURCCM),PKD(M),UtM),M(M)rL(M)
NEXT M
FOR J=1 TO 3
FOR 1=1 TO 24
INPUT II,GPROFd,J),CPROF(I,J),PPROFII,J)
NEXT I
NEXT J
CLOSE 11
GOTO 1590
LPRINT CHRK18)
END


APPENDIX B
SAMPLE
COMPUTER PRINT-OUT


DATE 01-01-1980
TIME 01:35:56
ECONOMIC EVALUATION OF C0SENERAT10N SYSTEM
COST SAVINS ANALYSIS
PROJECT NAME: SAMPLE PROJECT
NO. OLD ELECT NEW ELECT ELECT POWER POUER POWER POUER COOLING HEAT HEAT HEAT
PK DEN. PK DEN. CONSUHP 6ENER BOUGHT SOLD SAVED CONSUNP CONSUHP RECOVRD HASTED
CKHI IKH1 CKHHI CKHHI CKHHI CKHHI CKHHI CNNBTUI CNNBTUI CNNBTUI CNNBTUI
1 222 107 98000 78430 19570 0 0 0 2315 625 0
2 222 107 106000 70840 35160 0 0 0 1694 565 0
3 211 96 99000 78430 20570 0 0 0 1108 625 0
4 222 107 98000 75900 22100 0 0 0 1083 605 0
5 222 107 101000 78430 22570 0 0 0 748 625 0
6 222 107 104000 75900 28100 0 0 0 666 605 0
7 222 107 119000 78430 40570 0 0 0 983 .. 625 0
a 222 107 94000 78430 15570 0 0 0 629 624 1
9 233 118 121000 75900 4S100 0 0 0 765 605 0
10 233 118 111000 78430 32570 0 0 0 963 625 0
li 222 107 117000 . 75900 41100 0 0 0 1252 605 0
12 233 ua 112000 78430 33570 0 0 0 1701 625 0
OTHER THAN FIRST YEAR OF COGENERATION SYSTEH OPERATION
LOAD ON THE GENERATORS DIVIDES ESUALY. TUO UNITS OF 57.5 CKHI EACH
COVER POWER DEHAND LESS HARB!N= 0 CKHI
BEFORE COGENERATION AFTER C06ENERATI0N
HO. $/HT REQUIRED $/HTIL PUR $./HT AFTER $/FUEL COST $/PDHER AFTER $/HAINTENANCE $/PUR SOLD
1 $11,569.37 $10,987.93 $8,444.01 $6,356.95 $2,348.40 $705.87 $0.00
2 $8,465.61 $11,673.36 $5,642.70 $5,741.77 $4,219.20 $637.56 $0.00
3 $5,537.20 $10,947.55 $2,411.92 $6,356.95 $2,468.40 $705.87 $0.00
4 $5,411.34 $10,987.92 $2,386.79 $6,151.B9 $2,652.00 $683.10 $0.00
5 $3,738.00 $11,244.96 $612.64 $6,356.95 $2,708.40 $705.87 $0.00
6 $3,328.67 $11,502.00 $304.13 $6,151.89 $3,372.00 $683.10 $0.00
7 $4,912.03 $12,787.21 $1,786.67 $6,356.95 $4,749.46 $705.87 $0.00
8 $3,144.24 $10,645.21 $24.23 $6,356.95 $1,868.40 $705.87 $0.00
9 $3,823.47 $13,084.62 $798.93 $6,151.89 $5,263.64 $683.10 $0.00
10 $4,813.07 $12,227.82 $1,687.71 $6,356.95 $3,908.40 $705.87 $0.00
11 $6,257,00 $12,615.85. $3,232.45 $6,151.89 $4,794.87 $683.10 $0.00
12 $8,501.60 $12,313,51 $5,376.24 $6,356.95 $4,028.40 $705.87 $0.00
$69,501.68 $141,017.90 $32,708.43 $74,848.01 $42,381.57 $8,311.05 $0.00
YEARLY 6AS/HEAT AND ELECTRIC POWER CONSUHPTION
GAS/HEAT ELECTRIC POWER
GENERATORS FUEL INPUT - 166395. CFUELUNITSI POWER USED IN PLANT 5 1280000 CKUHI
GENERATORS HEAT INPUT = 14976 CNNBTUI POWER GENERATED s 923450 CKHHI
HEAT USED IN PLANT = 13906 CNNBTUI POWER BOUGHT FRON UTIL = 356550 CKHHI
COOLING USED IN PLANT = 0 CNNBTUI POWER SOLD = 0 CKUHI
HEAT REQUIRED FRON EXHAUST 13906 CNNBTUI POUER SAVED BY ABSORPTION CHLR. = 0 CKUHI
HEAT HASTED/EXHAUST * 1 CMMBTUJ
HEAT UTILIZED/EXHAUST ? 7362 CMHBTUI
84
GEN HEAT
INPUT
CMMBTUJ
1272
1149
1272
1231
1272
1231
1272
1272
1231
1272
1231
1272
MNTLY SAVING
$4,702.06
$3,897.75
$4,541.68
$4,525.48
$4,599.10
$4,319.55
$4,100.28
$4,833.99
$4,010.53
$4,381.95
$4,010.53
$4,347.64
$52,270.54


85
SAMPLE PROJECT
NUMBER OF EACH DAY TYPE PER MONTH
DAY TYPE 1 WORKING DAY
DAY TYPE 2 SATURDAY
DAY TYPE 3 SUNDAY
MO. DAY TYPE
1 2 3
1 21 5 5
2 20 4 4
3 21 5 5
4 21 5 4
5 21 5 5
G 23 3 4
7 22 4 5
8 23 4 4
9 22 4 4
10 21 5 5
11 22 5 3
12 22 5 4
GAS ANO POWER CONSUMPTION FOR THE PLANT
GAS COOLING ELECTRIC
GENERATOR CHARACTERISTICS
PEAK CONSUNP PEAK CONSUMP PEAK CONSUMP POWER HEAT INPT HEAT RECOV
HO. CCCF/HI ICCFI IHMBTU/H1 CMMBTUI IKWI I KWH I IKWI TMMBTU/HRI CMMBTU/HRI
1 4G.100 25720.000 0.000 0.000 222.000 98000.000 0,000 0.438 0.193
2 37.300 18820.000 0.000 0.000 222.000 106000.000 5.750 0.4B5 0.234
3 22.000 12310.000 0.000 0.000 211.000 99000.000 11.500 0.532 0.248
4 22.300 12030.000 0.000 0.000 222.000 98000.000 17.250 0.569 0.266
5 14.900 8310.000 0.000 0.000 222.000 101000.000 23.000 0.597 0.280
6 13.700 7400.000 0.000 0.000 222.000 104000.000 28.750 0.625 0.293
7 19.600 10920.000 0.000 0.000 222.000 119000.000 34.500 0.653 0.307
8 12.530 6990.000 0.000 0.000 222.000 94000.000 40.250 0.718 0.344
9 15.740 8500.000 0.000 0.000 233.000 121000.000 46.000 0.783 0.385
10 19.170 10700.000 0.000 0.000 233.000 111000.000 51.750 0.867 0.417
11 25.760 13910.000 0.000 0.000 222.000 117000.000 57.500 0,932 0.458
12 33.870 18900.000 0.000 0.000 233.000 112000.000


SAMPLE PROJECT
LOAD PROFILES
SAS C00LIN6 ELECTRIC
DAY TYPE DAY TYPE DAY TYPE
HOUR 1 2 3 1 2 3 1 2 3
1 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
3 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
4 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
5 0.900 0,900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
S 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
7 0.900 0,900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
8 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
9 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
10 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
11 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
12 1.000 0.900 0.900 0.000 0.000 0.000 1.000 0.900 0.900
13 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.300
14 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
15 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
16 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
17 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
18 0.900 0.900 0.300 0.000 0.000 0.000 0.900 0.900 0.900
19 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
20 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
21 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
22 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
23 0:900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
24 0.900 0.900 0.900 0.000 0.000 0.000 0.900 0.900 0.900
OTHER SYSTEM CHARACTERISTICS
SENERATOR POWER OUTPUT
6AS LOWER HEATINS VALUE
SAS CHARSE
COST OF 1 MMBT
UTILITY SERVICE CHARSE
UTILITY DEMAND CHAR6E
ENERSY CHAR6E
ALL APLICABLE TAKES
MAINTENANCE COSTS
58 IKK]
BOO CBTU
0.420 U/CCF1
4.990 [S/MMBTUI
44.10 m
*10.700 [$]
.08000 It!
7.100 III
.0090 Ct/KHl


APPENDIX C
COMPUTER PRINT-OUT/A CASE STUDY


88

DATE 03-11-19B9
TIME 00:51:47
ECONOMIC EVALUATION OF COGENERATION SYSTEM
COST SAVING ANALYSIS
PROJECT NAME: COGENERATION PLANT/OPTION 1
HO. OLD ELECT NEW ELECT ELECT POWER POWER POWER POWER COOLING HEAT HEAT HEAT GEN HEAT
PK DEM. PK DEM. CONSUHP 8ENER BOUGHT SOLD SAVED CONSUHP CONSUHP RECOVRD WASTED INPUT
IKWI IKWI CKWH1 [KWH] [KWH] [KWH] [KWHl [flMBTU] [HHBTU] [HHBTU] [MHBTUI [HHBTU]
1 1830 441 654800 535932 53348 0 65520 1092 5530 4403 0 9061
2 1818 439 669600 513018 94182 0 62400 1040 5022 4171 0 8573
3 1835 448 686000 551755 68725 0 65520 1092 6724 4503 0 9237
4 1915 1230 '719200 266411 387269 0 65520 1092 1721 2696 0 5639
5 2070 909 743200 413597 264083 0 65520 1092 2669 3435 0 7098
6 2185 1285 728000 207271 448969 0 71760 1196 1444 2549 0 5265
7 2175 1395 746400 121977 559240 0 65183 1144 33 1096 0 2245
8 2142 1322 731200 126342 536712 0 68146 1196 6 ;- 1138 0 2334
3 2117 1214 650B00 122717 462900 0 65183 1144 49 1102 0 2253
10 2110 1092 690800 332931 292349 0 65520 1092 2100 3017 0 6282
11 2088 814 720800 413117 239043 0 68640 1144 2626 3423 0 7062
12 2086 677. 731200 532026 130534 0 68640 1144 4657 4387 0 9024
LOAD ON THE 6ENERAT0R5 DIVIDES EQUALY. TWO UNITS OF 500 [KU] EACH
COVER HEAT DEMAND; NO EXCESS POWER SOLD TO UTILITY
BEFORE COGENERATION AFTER C06ENERATI0N
HO. $/HT REQUIRED $/UTIl pwr $/.ht AFTER $/FUEL COST $/POWER AFTER $/MAINTENANCE S/PWR SOLD HNTLY SAVING
1 $23,138.49 $37,402.21 $9,285.96 $37,911.79 $6,110.52 $1,875.76 $0.00 $5,356.66
2 $21,013.02 $37,689.52 $7,911.58 $35,869.36 $7,230.35 $1,795.56 $0.00 $5,895.63
3 $28,134.34 $38,324.60 $13,864.07 $38,650.65 $6,591.64 $1,931.14 $0.00 $5,421.44
4 $7,200.81 $40,086.75 $487.30 $23,594.73 $23,667.10 $932.44 $0.00 -$1,334.01
5 $11,167.38 $42,376.28 $1,365.06 $29,700.39 $16,882.87 $1,447.59 $0.00 $4,147.75
6 $6,041.95 $43,154.47 $378.91 $22,029.97 $25,969.89 $725.45 $0.00 $92.19
7 $137.99 $43,563.10 $137.99 $9,393.41 $30,192.73 $426.92 $0.00 $3,550.04
a $25.11 $42,794.24 $25.11 $9,767.58 $28,794.69 $442.20 $0.00 $3,789.77
S $205.58 $40,290.65 $205.58 $9,426.53 $25,607.87 $429.51 $0.00 $4,826.74
10 $8,786.60 $41,333.02 $729.93 $26,286.23 $19,580.27 $1,165.26 $0.00 $2,357.33
n $10,987.71 $41,939.74 $1,453.62 $29,547,97 $15,184.24 $1,445.91 $0.00 $5,295.71
12 $19,485.72 $41,999.81 $5,917.36 $37,759.09 $10,730.05 $1,862.09 $0.00 $5,216.95
$136,324.70 $490,954.50 $41,762.46 $309,937.70 $216,542.20 $14,479.82 $0.00 $44,556.87
YEARLY 6AS/HEAT AND ELECTRIC POWER CONSUMPTION
SAS/HEAT
ELECTRIC POWER
GENERATORS FUEL INPUT = 884988 [FUELUNITS] POWER USED IN PLANT 8472000 [KWH]
GENERATORS HEAT INPUT = 74073 [HHBTU] POWER GENERATED = 4137093 [KWH]
HEAT USED IN PLANT = 3258! CMHBTUI POWER BOUGHT FROH UTIL 3537355 [KWH]
COOLING USED IN PLANT = 13468 [HHBTU] POWER SOLD 0 [KWH]
HEAT REQUIRED FROM EXHAUST = 46049 [HHBTU] POWER SAVED BY ABSORPTION CHLR. = 797553 [KWH]
HEAT WASTED/EXHAUST 0 [HHBTU]
HEAT UTILIZED/EXHAUST = 35919 [HHBTU]


89
COGENERATION PLANT/OPTION 1
NUHBER OF EACH DAY TYPE PER MONTH
DAY TYPE 1 - WORKING DAY
DAY TYPE 2 - SATURDAY
DAY TYPE 3 - SUNDAY
NO. DAY TYPE
1 2 3
1 21 5 5
2 20 4 4
3 21 5 5
4 21 5 4
5 21 5 5
6 23 3 4
7 22 4 5
8 23 4 4
9 22 4 4
10 21 5 5
11 22 5 3
12 22 5 4
GAS AND POWER CONSUMPTION FOR THE PLANT
GAS COOLING ELECTRIC
GENERATOR CHARACTERISTICS
PEAK CONSUNP PEAK CONSUNP PEAK CONSUNP POWER HEAT INPT HEAT RECOV
NO. CCCF/HI CCCF1 INHBTU/Hj CNHBTUI 1KWI IKWH] IKWI CHNBTU/HRl CHHBTU/HR]
I 90.550 66069.000 6.500 1092.000 1830.000 654800.000 0.000 3.811 1.674
2 85.000 60000.000. 6.500 1040.000 1810.000 669600.000 50.000 4.216 2.033
3 110.000 80334.000 6; 500 1092.000 1835.000 686000.000 100.000 4.622 2.153
4 28.000 20561.000 6.500 1092.000 1915.0,00 719200.000 150.000 4.946 2.312
5 . 44.000 31887.000 6.500 1092.000 2070.000 743200.000 200.000 5.189 2.432
G 23.000 17252.000 6.500 1196.000 2185.000 728000.000 250.000 5.433 2.551
7 0.540 394.000 6.500 1144.000 2175.000 746400.000 300.000 5.676 2.671
B 0.100 71.700 5.500 1196.000 2142.000 731200.000 350.000 6.244 2.990
9 0.820 587.000 6.500 1144.000 2117.000 650800.000 400.000 6.811 3.349
10 34,400 25089.000 6.500 1092.000 2110.000 690800.000 450.000 7.541 3.628
11 43.000 31374.000 6.500 1144.000 2088.000 720800.000 500.000 8.108 3.387
12 7G.300 55639.000 6.500 1144.000 2066.000 731200.000



COGENERATION Pl.ANT/OPTION 1
LOAD PROFILES
GAS COOLING ELECTRIC
DAY TYPE DAY TYPE DAY TYPE
HOOR 1 2 3 1 2 3 1 2 3
1 0.990 0.990 0.990 0.000 0.000 0.000 0.350 0.250 0.200
2 0.990 0.990 0.800 0.000 0.000 0.000 0.350 0.250 0.200
3 0.990 0.990 0.900 0.000 0.000 0.000 0.370 0.250 0.200
4 0.990 0.990 0.990 0.000 0.000 0.000 0.400 Q,250 0.200
5 .0.990 0.990 0.900 0.000 0.000 0.000 0.430 0.250 0.200
6 0.990 0.990 0.990 0.000 0.000 0.000 0.690. 0.250 0.200
7 0.990 0.990 0.800 0.200 0.000 o.poo 0.800 0.250 0.200
8 0.990 0.990 0.900 0.300 0.000 0.000 0.900 0.250 0.200
9 0.990 0.900 0.880 0.500 0.000 0.000 0.900 0.250 0.200
10 0.990 0.930 0.900 0.930 0.000 0.000 0.900 0.250 0.200
11 0.990 0.990 0.900 0.990 0.000 0.000 L.OOO 0.250 0.200
12 0.990 6.990 0,880 0.990 0.000 0.000 0.900 0,250 0.200
13 1.000 0.990 0.990 1.000 0.000 0.000 0.900 0.250 0.200
14 0.990 0.990 0.990 0.990 0.000 0.000 0,900 0,250 0.200
15 0.990 0.900 0.990 0.990 0.000 0.000 0.900 0.250 0.200
16 0.990 0.900 0.990 0.500 0.000 0.000 0,770 0.250 0.200
17 0.990 0.900 0.990 0.300 0.000 0.000 0.770 0.250 0.200
18 0.990 0.800 0.990 0.200 0,000 0.000 0.760 0.250 0.200
10. 0.990' 0.900 0.990 0.000 0.000 0.000 0.750 0.250 0.200
20 0.990 0.880 0.990 0.000 0.000 0.000 0.740 0,250 0.200
21 0.990 0.900 0.990 0.000 0.000 0.000 0.730 0.250 0.200
22 0.990. 0.990 0.900 0.000 0.000 0.000 0.690 0.250 0.200
23 0.990 0.900 0.990 0.000 0.000 0.000 0.690 0.250 0.200
24 0.990 0.900 0.900 0.000 0.000 0.000 0.550 0.250 0.200
OTHER SYSTEM CHARACTERISTICS
GENERATOR POWER OUTPUT 500 [CHI
GAS LONER HEATING VALUE 837 IBTU
GAS CHARGE 0.327 tt/CCF]
COST OF 1 M8T . 4.184 Ct/NNBTU)
UTILITY SERVICE-CHARGE 10.90 It!
UTILITY DEMAND CHARGE 9.760 It]
ENERGY CHARGE .02604 It]
ALL.APLICABLE TAXES 7.100 m
MAINTENANCE COSTS .0035 l$/KU]


91
DATE 09-11-1909
TIME 01:49:33
ECONOMIC EVALUATION OF C06ENERATI0N SYSTEM
COST SAVING ANALYSIS
PROJECT NAME: COGENERATION PLANT/OPTION 3
MO. OLD ELECT NEW ELECT ELECT POWER POWER POWER POWER COOLING HEAT HEAT HEAT GEN HEAT
PK DEM. PK DEM. CONSUHP GENER BOUGHT SOLD SAVED CONSUMP CONSUMP RECOVRD WASTED INPUT
CKW1 IKWI IKWH1 CKWHT [KWH1 [KWH] [KWH] [MHBTU1 [KHBTU1 CMKBTU] [MMBTU1 [HHBTU]
1 1830 141 654800 586317 2964 0 65520 1092 5530 4718 239 10254
2 1818 139 669600 600505 6695 0 62400 1040 5022 4594 353 10245
3 1835 146 686000 616044 4436 0 65520 1092 6724 5119 43 10695
4 1915 226 719200 643315 10365 0 65520 1092 1721 2813 2481 10941
5 2070 38 i 743200 661476 16204 0 6552.0 1092 2669 3704 1764 11291
6 2185 496 728000 643089 13151 0 71760 1196 1444 2640 2707 11065
7 2175 r* CD cn 746400 662378 15382 0 68640 1144 33 1177 42B8 11308
8 2142 453 731200 647567 11874 0 71760 1196 6 1202 4201 11181
9 2117 428 650800 572741 9419 0 68640 1144 49 1193 3677 10070
10 .2110 42! 690800 615116 10164 0 65520 1092 2100 3154 ' 2002. 10684
11 2088 399 720800 640594 11566 0 68640 1144 2626 3651 1647 10969
12 2066 377 731200 651206 11354 0 68640 1144 4657 4701 693 11170
LOAD ON THE GENERATORS DIVIDES EQUALY. THO UNITS OF 650 Util EACH
COVER ROVER DEMAND LESS KARGIN? 0 IKHI
BEFORE COGENERATION AFTER COGENERATION
KO. $/HT REQUIRED $/UTIl PWR $/HT AFTER l/FUEL COST 1/POWER AFTER l/MAINTENANCE t/PWR SOLD MNTLY SAVINS
1 $2.3,138.43 $37,402.21 $7,968.02 $42,906.01 $355.63 $1,934.84 $0.00 $7,376.20
2 $21,013.02 $37,689.52 $6,144.35. $42,866.88 $803.38 $1,931.67 $0.00 $6,906.26
*3 .. 528,134.34 - $38,224.60 $11,284.23 $44,749.74 $532.35 $2,032.94 $0.00 $7,859.67
4 67,200.81 $40,086.75 ' -$0.00 $45,777,53 $1,243.80 $2,122.94 $0.00 -$1,856.71
5 $11,167.38 $42,376.28 $239.57 $47,242.74 $1,944.45 $2,182.87 $0.00 $1,934.04
6 $6,041.95 $43,154.47 $0.00 $46,299.88 $1,578.08 $2,122.19 $0.00 -$803.75
7 $137.99 $43,553.10 - $0.00 $47,316.79 $1,845.88 $2,185.85 $0.00 -$7,647.43
a $25.11 . $42/794.24 $0.00 $46,785.12 $1,424.83 $2,136.97 $0,00 -$7,527.57
9 $205.58 140,290.65 $0.00 $42,136.02 $1,130.24 $1,890.05 $0.00 -$4,660.08
10 $8,786.60 $41,333.02 $157.69 $44,702.21 $1,219.72 $2,029.88 $0.00 $2,010.11
11 . $10,987.71 '$41,939.74 $498.02 $45,896.30 $1,387.90 $2,113.96 $0.00 $3,031.27
12 $13,485.72 $41,393.81 $4,602.66 $46,738.42 $1,362.44 $2,148.98 $0,00 $6,633.04
$136,324,70 $490,954,50 $30,894.54 $543,417,60 $14,828.71 $24,883.15 $0.00 $13,255.04
YEARLY GAS/HEAT AND ELECTRIC POWER CONSUMPTION
GAS/HEAT ELECTRIC POWER
GENERATORS-FUEL INPUT GENERATORS HEAT INPUT HEAT USED IN-PLANT C08LINS .USED. IN; PLANT HEAT REQUIRED .FROM EXHAUST HEAT WASTED/EJHAUST HEAT UTILIZED/EIHAUST -- 1551660 [FUELUNITS] = 129874 IHHBTU] = 32581 [HHBTU] = 13468 [HHBTU] = 46049 [HHBTU] 24101 [MHBTU1 = 38665 [HMBTU] POWER USED IN PLANT POWER SENERATED POWER BOUGHT FROM UTIL POWER SOLD POWER SAVED BY ABSORPTION CHLR. = 8472000 CKWHI 7540348 [KUH1 123573 [KWH] 0 [KWH! 808080 [KWH