SAMPLE Initial Feasibility Report: Combined Heat and Power Plant

Transcription

Initial Feasibility Report:
Combined Heat and Power Plant
JULY 2005
SAMPLE
PREPARED BY
Northeast Application Center
Center for Energy Efficiency and Renewable Energy
Department of Mechanical and Industrial Engineering
University of Massachusetts
160 Governors Drive, Amherst, MA 01003
www.northeastchp.org
SAMPLE
Combined Heat and Power Feasibility Study
TABLE OF CONTENTS
1
2
3
4
5
Executive Summary .............................................................................................................1
Financial Summary ..............................................................................................................3
Facility Analysis ..................................................................................................................4
2.1
Facility Description and Existing Operations ..........................................................4
2.2
Energy Billing Analysis...........................................................................................5
2.3
Energy Efficiency Evaluation ..................................................................................7
Data Collection ....................................................................................................................8
3.1
Description...............................................................................................................8
Combined Heat and Power Analysis .................................................................................11
4.1
Goals ....................................................................................................................11
4.2
Technical Review...................................................................................................11
4.3
Design Options.......................................................................................................12
4.3.1 Equipment Selection ..................................................................................14
4.3.2 Analysis Methodology ...............................................................................16
4.3.3 Detailed Analysis Results ..........................................................................21
4.4
Analysis Summary .................................................................................................23
4.5
Project Constraints .................................................................................................24
4.6
Financing Information ...........................................................................................25
4.7
Other Considerations .............................................................................................26
Recommendations..............................................................................................................27
APPENDIX A
Combined Heat and Power
A.1
Technical Review................................................................................................ A-2
Combined Heat and Power Technologies........................................................... A-4
A.2
General Benefits.................................................................................................. A-7
APPENDIX B
Equipment Specifications
APPENDIX C
Weekday and Weekend Load Profiles for 12 Months
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1
EXECUTIVE SUMMARY
The Northeast CHP Application Center operating within the Center for Energy Efficiency and
Renewable Energy (CEERE) at the University of Massachusetts, Amherst, is pleased to present
this report investigating the feasibility of utilizing cogeneration at SAMPLE FACILITY located
in Massachusetts. The primary objectives of this study were to:
•
•
•
•
•
Perform engineering analyses to determine the technical viability of utilizing
cogeneration at SAMPLE FACILITY.
Select and perform savings and cost analyses on a variety of cogeneration configurations
based on the energy consumption and thermal load profiles.
Evaluate previous analyses provided to SAMPLE FACILITY by a cogeneration system
developer.
Provide supplemental information on combined heat and power in general, inclusive of
the various prime mover and heat recovery technologies involved along with a general
description of the benefits and risks associated with implementing cogeneration.
Recommend next steps for the facility to pursue.
Table 1 presents an economic summary of the five cogeneration design options that were
analyzed for SAMPLE FACILITY. The various alternatives were chosen to represent a range of
capital requirements, a range of capacities that could cover a variety of potential applications,
alternate engine deployment strategies, and various heat recovery scenarios. For each option,
Table 1 presents the first year estimated energy savings assuming that the generation is deployed
as noted and that the heat recovered from the generating equipment can be recovered and utilized
in the manner noted. Table 1 also provides an initial estimate of installed cost with and without
any rebate from the GAS COMPANY. Although the actual cost of construction will vary
depending upon final contractor selection, we have chosen to use an installed cost of $1,500/kW
for all systems. Simple payback and the internal rate of return (IRR) are provided in Table 1 as
well. These paybacks and return rates assumed an inflation rate of 1.5%, a discount rate of 5.5%,
and neglected any tax rates.
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Table 1: Annual Savings, Installed Cost, Simple Payback, and Rate of Return (With and Without Utility Rebates)
Cogeneration Option
Annual
Energy
Savings
$41,551
Without GAS COMPANY Rebate
Estimated
Simple
Internal
Installed
Payback
Rate of
Cost
Return
$315,000
7.6 years
13.4%
With GAS COMPANY Rebate6
Estimated
Simple
Internal
Installed
Payback
Rate of
Cost
Return
$256,703
6.2 years
17.0%
Option #1: 210 kW CHP Plant
One 210 kW Reciprocating Engine1
$32,310
$630,000
19.5 years
1.7%
$542,490 16.8 years
3.3%
Two 210 kW Reciprocating Engines2
$56,213
$630,000
11.2 years
7.9%
$560,078 10.0 years
9.4%
3
Two 210 kW Reciprocating Engines
$88,157
$630,000
7.2 years
14.4%
$535,905
6.1 years
17.3%
4
(For Reference Purposes Only)
$10,527
$1,440,000
137 years
N/A
$1,346,228 128 years
N/A
5
(For Reference Purposes Only)
Notes:
1. Option #1 analysis assumes engine is deployed only when facility electric demand exceeds 210 kW and utilizes energy
recovered to displace ONLY natural gas water heater thermal loads.
2. Option #2 analysis assumes at least one engine is deployed during all hours of the year and utilizes energy recovered to
displace ONLY natural gas water heater thermal loads.
3. Option #3 analysis assumes engines are deployed when facility electric demand exceeds 210 kW and utilizes energy
recovered to displace ONLY natural gas water heater thermal loads.
4. Option #4 analysis assumes engines are deployed when facility electric demand exceeds 210 kW and utilizes energy
recovered to displace BOTH steam boiler and natural gas water heater thermal loads.
5. Option #5 analysis assumes at least one engine is deployed during all hours of the year as needed to completely island this
facility from the electric utility and uses energy recovered to displace ONLY natural gas water heater thermal loads.
6. GAS COMPANY rebates are based on $0.75/Therm applied to the energy recovered from the engine(s) and used within
the facility.
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Financial Summary
There are three key factors that contribute to the financial attractiveness of a combined heat and
power project. The first is the coincidence of need for electric power and thermal energy. The
more a facility needs electricity at the same time it needs thermal energy (heating, cooling, or
dehumidification), the more attractive the savings and payback associated with the CHP project
will become. The second factor is the differential between the cost of buying electric power
from the grid and the cost of natural gas. This differential is commonly referred to as the “spark
spread” and the higher the differential, the more attractive the savings and payback associated
with the CHP project become. The final factor is the installed cost differential between the
installed costs of a combined heat and power system and that of a conventional system. The
lower the installed cost differential, the more attractive the savings and payback associated with
the CHP project.
One of the reasons for supplying the various design options presented in Table 1 were to address
the first of these financial factors. Since the SAMPLE FACILITY has already made a significant
investment in the geothermal heat pump system for the main hotel building and the
administration building, this limits the amount of recovered thermal energy that can be actually
used on site. Option 1 and 2 above address the scenario where the combined heat and power
plant is installed to serve only the sports center electric loads and the thermal energy recovered is
used exclusively within the sports center for space heating, pool heating, pool area
dehumidification, and/or domestic hot water heating. Options 3 and 4 will produce an excess of
thermal energy which will not be able to be recovered and will reduce overall system efficiency,
but may still be an economically attractive alternative. All options above assumed a thermal load
profile that could utilize recovered generator heat for space heating and domestic hot water
loads.
The billing analysis provided in Section 3 can be used to determine the “spark spread” that is the
second key financial factor that contributes to the attractiveness of each of the cogeneration
options presented in Table 1. Based on current billing structure, SAMPLE FACILITY is paying
approximately $0.1344/kWh ($39.37/MMBtu) for electricity. Based on the prevailing
distributed generation natural gas rates, post-installation natural gas should cost approximately
$8.00/MMBtu. Thus, the “Spark Spread” for this facility is $31.37/MMBtu. Typically, values
greater than $12/MMBtu are worthy of further investigation.
The final financial factor is the cost differential between installing a cogeneration system or the
primary alternative, do nothing and continue to pay the electric utility for all electricity used at
the facility. The four alternatives presented in Table 1 cover a wide range of installation costs to
provide various first cost options. All have a simple payback under 10 years with two of the
options have rates of return over 10%.
Overall, the analysis indicates that this site has a well above average potential for implementing a
cost effective and successful cogeneration plant.
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2
FACILITY ANALYSIS
This section provides an overview of the observations that were made during the 1-day site visit
and results from a review of the utility bills for this facility.
2.1
Facility Description and Existing Operations
The SAMPLE FACILITY is located in LOCATION and contains a number of different
buildings including: a main office / engineering building, the foundry building, the machine
shop, shipping, dryer shop, assembly shop, finishing & painting areas, outdoor storage, and a
heat treating center. Figure 1 below shows a layout of the entire facility.
Figure 1: Facility Layout
The most energy intensive area is the foundry. Within this space the following equipment is
housed:
• Two coreless electric induction arc furnaces, each with 7.5 tons capacity each. On
average 30,000 lbs of molten metal is poured per day (on average 4-5 days per week).
• Induction furnace cooling system. Ethyl-glycol-water cooling tower loop.
• Natural gas charge preheater & Natural gas ladle preheater
• New natural gas sand reclamation unit
• Mechanical sand reclamation unit
• 2 oil fueled fire tube boilers used for space heating.
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2.2
Energy Billing Analysis
The analysis performed as part of this study utilized the current electrical, and natural gas energy
requirements of SAMPLE FACILITY as obtained from online billing history provided by
ELECTRIC and GAS COMPANY.
Table 2 and Table below summarize the annual electric and natural gas consumption and costs
over the course of a one-year time period for the A and B buildings respectively.
Table 2: A Building Annual Electric Energy Consumption and Cost Summary
Month
Electric
Electric
Electric
Natural
Natural
Energy
Demand
Cost
Gas
Gas Cost
(kWh)
(kW)
(MMBtu)
January
33,120
94
$4,842
547
$6,031
February
32,880
96.0
$4,852
659
$6,975
March
31,680
101.0
$4,820
553
$6,082
April
30,240
96.0
$4,594
442
$5,146
May
30,240
130.0
$5,171
309
$4,025
June
51,120
194.0
$8,304
109
$2,339
July
55,680
178.0
$8,479
119
$2,423
August
58,320
187.0
$8,891
114
$2,381
September
60,480
180.0
$8,983
123
$2,457
October
43,200
156.0
$6,882
121
$2,440
November
32,400
96.0
$4,805
251
$3,536
December
34,800
96.0
$5,040
494
$5,584
TOTAL
494,160
194.0
$75,664
3,841
$49,420
Including all charges, the average cost of electricity for this facility is $0.1531/kWh
($44.86/MMBtu). Natural gas cost an average of $1.287/Therm ($12.87/MMBtu) again
including all charges.
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Table 3: B Building Annual Electric Energy Consumption and Cost Summary
Month
Electric
Electric
Electric
Natural
Natural
Energy
Demand
Cost
Gas
Gas Cost
(kWh)
(kW)
(MMBtu)
January
20,640
52.0
$2,906
181
$2,215
February
20,520
53.0
$2,911
166
$2,033
March
18,720
48.0
$2,650
125
$1,535
April
17,400
46.0
$2,486
55
$684
May
17,640
61.0
$2,765
23
$330
June
28,320
97.0
$4,422
7
$108
July
28,200
88.0
$4,258
7
$108
August
27,720
90.0
$4,245
6
$94
September
31,440
95.0
$4,694
6
$94
October
22,320
83.0
$3,597
6
$94
November
18,120
52.0
$2,659
42
$526
December
21,360
52.0
$2,976
130
$1,596
TOTAL
272,400
97.0
$40,568
754
$9,417
Including all charges, the average cost of electricity for this facility is $0.1489/kWh
($43.63/MMBtu). Natural gas cost an average of $1.249/Therm ($12.49/MMBtu) again
including all charges.
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2.3
Energy Efficiency Evaluation
In addition to the combined heat and power recommendations presented in this report, there were
a number of energy efficiency items that were noted during the site visit, personnel interviews,
and through utility billing analysis. Furthermore, the optimum combined heat and power
projects are those that are not implemented as stand-alone projects, but as part of a
comprehensive facility energy master plan that is continuously examining ways to reduce energy
consumption and/or costs.
Overall, high-efficiency lighting was being used in places within this facility. However, it is
recommended that high-efficiency lamps and ballasts be installed throughout. A sophisticated
energy management control system was in place and being used to monitor the operation of the
ground source heat pump system. This type of system can play a critical role in energy
management through data tracking/trending. Although this system is controlling many of the
systems, it is likely not optimized. Further enhancements such as room temperature setbacks,
operating schedule control, and lighting controls (if applicable) should be examined.
Generally, ground source heat pump (GSHP) systems are efficient systems that can, over time,
payback their high initial costs. The GSHP system at this facility was found to have a few
inefficiencies that will decrease this systems operating efficiency.
•
•
Commissioning, including testing and balancing is a critical component that
should be completed as soon as is feasible on this system. According to facility
personnel, incorrect valves were likely installed which has been causing flow
deficiency problems within the GSHP system.
Currently the steam to hot water heat exchanger that is used to maintain a 60ºF
loop temperature in winter is adding heat to the return water instead of the
building supply. In other words, this heat is being added to the water that is
flowing out to the 120 ground loops and NOT to the water flowing to the
individual heat pump units.
The banquet halls and other large common areas offer opportunities for a number of energy
conservation measures. For example, because many of these areas are frequently unoccupied,
particularly during the winter months, lighting controls and temperature setbacks may be
implemented to reduce the energy consumption of these rooms. Bi-level lighting controls or
occupancy sensors may be used to reduce lighting levels within these rooms during unoccupied
hours. Allowing the space temperatures to setback during unoccupied hours is an excellent way
to reduce heating and air conditioning energy consumption of these spaces. Based on a cursory
review of the existing building control system, it was determined that no additional capital cost
would be required to implement the temperature setbacks. Finally, it was also noted that the
banquet halls typically have two heat pump units operating in a single room. It is recommended
that controls be installed that prevent these units from counteracting each other (i.e. one unit
cooling the space while the other is trying to heat).
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3
DATA COLLECTION
3.1
Description
In addition to the utility billing data collected and summarized above, onsite observations and
measurements were also taken to assist in this report development. Detailed electrical amperage
monitoring of several key electrical outputs was also performed. In all cases, instrumentation
was placed on the electrical lead(s) and allowed to record data for a period of 2 days. The
following systems were monitored:
•
•
•
•
•
•
Hot water heater natural gas supply (0-20mA) and hot water heater fan motor energy
(amps)
Discharge water flow rate (0-20mA) and pump motor energy (amps)
Steam boiler fan energy (amps)
Filter supply water pump (amps) and fresh water supply flow rate (0-20mA)
Facility hot water supply pump (amps)
Temperatures across the heat exchanger (Waste Water In & Out, Fresh Water In & Out)
In addition to the data obtained from the above monitoring, an electrical hourly profile was
obtained from ELECTRIC COMPANY. The hourly electrical data is summarized for a 1 year
period in Figure 2 below. Based on the measurements taken from the steam boiler and natural
gas hot water heater, an hourly natural gas consumption profile was created for a typical
operating day. Using this data in conjunction with daily natural gas consumption values
obtained from GAS COMPANY utility bills, an hourly natural gas consumption profile was
created for both the natural gas hot water heater alone (Figure 3) and the entire facility (Figure
4). These demand profiles were subsequently used by the detailed combined heat and power
system analysis software as described in Section 4.
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Figure 2
Hourly Electrical Demand Profile
1000
900
800
Demand (kW)
700
600
500
400
300
200
100
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Figure 3
Hourly Water Heater Natural Gas Profile
7
6
Demand (MMBtu)
5
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Figure 4
Hourly Total Natural Gas Profile
25
Demand (MMBtu)
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4
COMBINED HEAT AND POWER ANALYSIS
4.1
Goals
The goals of this combined heat and power analysis are as follows:
• Perform engineering analyses to determine the technical viability of utilizing
cogeneration at the facility.
• Select and perform savings and cost analyses on a variety of cogeneration configurations
based on the energy consumption and thermal load profiles.
• Evaluate previous analyses provided to SAMPLE FACILITY by a cogeneration system
developer.
• Recommend next steps for the facility to pursue.
4.2
Technical Review
Energy is the most significant driving force of our economy. All buildings need electric power
for lighting and operating equipment and appliances. One of the major consumers of energy in
buildings is the equipment for space conditioning. Most commercial and institutional buildings
for businesses, education, and healthcare require space conditioning for cooling, heating, and/or
humidity control.
Two-thirds of all the fuel used to make electricity in the U.S. is generally wasted by venting
unused thermal energy, from power generation equipment, into the air or discharging into water
streams. While there have been impressive energy efficiency gains in other sectors of the
economy since the oil price shocks of the 1970's, the average efficiency of power generation
within the U.S. has remained around 33% since 1960.
Combined heat and power (CHP) or cogeneration is the production of two forms of useful
energy from a single fuel source. In most CHP applications, energy from a fuel source such as
natural gas or oil is converted to both mechanical and thermal energy. The mechanical energy is
used to generate electricity, while the thermal energy or heat is used to produce steam, hot water,
or hot air. Depending on the application, CHP is referred to by various names including
Building Cooling, Heating, and Power (BCHP); Cooling, Heating, and Power for Buildings
(CHPB); Combined Cooling, Heating, and Power (CCHP); Integrated Energy Systems (IES), or
Distributed Energy Resources (DER).
Integrated systems for cooling, heating and power (CHP) systems significantly increase
efficiency of energy utilization, up to 85%, by using thermal energy from power generation
equipment for cooling, heating and humidity control systems. These systems are located at or
near the building using power and space conditioning, and can save about 40% of the input
energy required by conventional systems. In other words, conventional systems require 65%
more energy than the integrated systems, as illustrated in Figure 5. Please refer to Appendix A
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for a more thorough technical review including descriptions of the relevant technologies
involved.
Figure 5: Energy Utilization Summary
4.3
Design Options
This section provides a detailed description of the design options that were analyzed for this
study. For each option it provides a description of the equipment analyzed, the operational and
design assumptions made, the overall analysis methodology, and a detailed results breakdown.
To start, the following is a brief summary of each of the design options considered:
Option #1: 210 kW combined heat and power plant.
This option consists of three 70 kW microturbines complete with exhaust heat recovery. This
option is the lowest installed kW option. Details of specific microturbine selection are provided
below. This option was chosen because it simulates the case where combined heat and power is
applied to the country club sports complex facility only. In other words, this case assumes that
all of the electricity generated and heat recovered from the microturbines would be utilized
within the sports complex building and none of the other buildings. This case is important
because the sports complex potentially offers the best opportunity for heat recovery via space
heating, domestic hot water production, pool water heating, and pool area dehumidification.
Furthermore, since the sports complex will be undergoing renovations in the near future,
incorporation heat recovery in the design now would be a less costly alternative as compared to a
post-installation retrofit.
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Option #2: 480 kW combined heat and power plant.
This option consists of one 480 kW reciprocating engine complete with exhaust and engine
jacket heat recovery. This option uses reciprocating engine technology. This option was
selected for inclusion in this report as it represents the best alternative from a financial standpoint
at this stage of the analysis. This generator would be a base loaded system and could potentially
operate more efficiently than one requiring part-load operation. This system, however, would
require interconnection to either the main building or some combination of the main building and
sports complex. This adds some complexity to interconnection and also heat recovery issues as
the main building already uses a new ground source heat pump system for all space and domestic
hot water heating.
Option #3: 480 kW distributed generation only plant
This option consists of one 480 kW reciprocating engine with no heat recovery equipment
installed. This case is important in that it provides a basis for comparison to the other options if
no heat could be recovered and the system was operated strictly as an electric generating plant.
It is also useful to compare Options #2 and #3 to realize the important role heat recovery plays
when examining the financial benefit of combined heat and power as compared to a power plant
only.
Option #4: 960 kW combined heat and power plant
This option consists of two 480 kW reciprocating engines complete with exhaust and engine
jacket heat recovery. This option was selected for inclusion in this report as it represents the
alternative for an electric load following system capable of meeting the country club’s electric
demand a high percentage of the time. However, electric backup and periodic electricity
purchases would still be needed based upon this analysis.
Option #5: 1,440 kW combined heat and power plant
This option consists of three 480 kW reciprocating engines complete with exhaust and engine
jacket heat recovery. This case is important in that it provides an analysis of the alternative
where the entire facility can be electrically islanded (disconnected) from the electric utility. The
sizing of this system contains some redundancy to allow for near full load operation on only 2
out of the three generators to account for both planned and unplanned generator repairs and
maintenance. Although capital intensive, additional annual savings may be realized in avoided
electric utility stand-by charges.
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4.3.1
Equipment Selection
Reciprocating engines can be fueled by diesel or natural gas, with varying emission
outputs. Almost all engines used for power generation are four-stroke. The process
begins with fuel and air being mixed. In turbocharged applications, the air is compressed
before mixing with fuel. The fuel/air mixture is introduced into the combustion cylinder
and ignited with a spark. For diesel units, the air and fuel are introduced separately with
fuel being injected after the air is compressed. Reciprocating engines are currently
available from many manufacturers in many size ranges. They are typically used for
either continuous power or backup emergency power. Cogeneration configurations are
available with heat recovery from the gaseous exhaust.
These engines are the fastest growing segment of the market for CHP systems under 5
MW. Capacities range from about 5 kW to 10 MW. They offer better load following
and part load operation than most of the other prime mover technologies. Reciprocating
engines are fueled by natural gas, diesel, or gasoline. CHP systems most commonly use
natural gas because it results in significantly lower emissions. A typical reciprocating
engine equipped with engine exhaust gas heat recovery and engine-jacket coolant heat
recovery is capable of utilizing up to 80% of the input energy (30% electrical power, 50%
recovered heat). Thus only 20% of the input energy is lost via exhaust and radiation. .
Table 4 summarizes the reciprocating engine parameters that were utilized for all of the
options contained within this analysis. Detailed specification sheets from the
manufacturer are included in Appendix B. Although engine data from ENGINE
MANUFACTURER is presented here and used in the analysis, other manufacturers offer
similar products.
Table 4: Engine Properties
Parameter
Net Output
Heat Rate (HHV)
Jacket Water Temperature
Installed Cost
(with heat recovery)
Variable Operational &
Maintenance Costs
75 kW Properties
75 kW
12,240 Btu/kWh
230ºF
$2,200/kW
$0.0175/kW/year
Microturbines are newer, smaller combustion turbines that are compact in size and can be
brought on-line quickly, and require less maintenance because they have a smaller
number of moving parts. These have the best potential to be applied for commercial
building combined heat and power applications. Microturbines are capable of burning
natural gas, propane, and gases produced from landfills, sewage treatment facilities, and
animal waste processing plants. Thus they have the versatility to be applied in remote
areas. Exhaust gas temperatures are suitable for producing steam of hot water. NOx
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emissions are lower when compared to reciprocating engines but higher than gas. The
following table summarizes the microturbine parameters that were utilized for Option #2
of this analysis. A detailed specification sheet from the manufacturer is included in
Appendix B.
Table 5: Microturbine Properties
Parameter
Net Output
Heat Rate (HHV)
Rating Conditions
Installed Cost
(with heat recovery)
Fixed Operational &
Maintenance Costs
Variable Operational &
Maintenance Costs
July 2005
Value
30 kW
12,600 Btu/hr
59.5 F
0’ Altitude
$2,200/kW
$1,980/year
$0.0007/kW/year
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4.3.2
Analysis Methodology
This section briefly describes how the various design options were analyzed and the
significant assumptions involved. All analyses were completed using a distributed
generation / combined heat and power software packaged called D-Gen Pro. This
software is an economic screening tool to determine the feasibility of distributed power
generation and combined heat and power applications. The following is a description of
the information used by the software tool and the assumptions that were required to
complete the analysis.
Project and Facility Information
This information is general contact and facility information. Relevant to the analysis is
the assumption that the facility is located at FACILITY LOCATION. This assumption
was needed to define the annual outdoor weather conditions at the facility, which is then
used to determine only inlet air conditions for the engine.
Existing Utility Consumption
The data used to create the hourly electric and natural gas consumption profiles shown in
Figure 2 and Figure 4 above was imported directly into the software to create the baseline
utility consumption profiles.
Hourly Electric and Thermal Load Profiles
As previously mentioned, the coincidence of electric and thermal loading is one of the
critical factors in having an economically viable site for combined heat and power.
Figure 6 and Figure 7 below show the two electric-thermal coincidence curves for the
two scenarios considered within this report. In both figures, the dark red lines indicate
the heat that hypothetically would be available from a generator meeting the entire
electric load of the facility during each hour of the year. The dark blue lines show the
natural gas load (Figure 6 considers the case where the natural gas load consists solely of
the natural gas water heater load, while Figure 7 considers the natural gas load from both
the water heater and steam boiler). The green lines indicate the difference between the
thermal energy that would be hypothetically available from a generator and the actual
hourly gas demand. Therefore, hours where the green line greater than zero indicate
hours where the natural gas load is greater than the hypothetical energy recovered from
the generator, thus indicating that the energy recovered can be utilized. Conversely,
hours where the green line is less than zero indicate hours where the energy recovered
cannot be utilized. Therefore, in Figure 6, poor coincidence between electrical and
thermal loading means that at best only approximately 60% of the available waste energy
from the engine can actually be utilized for a system running every hour of the year.
However, when both the natural gas water heater and steam boiler are considered as in
Figure 7, the coincidence improves such that 99% of the available waste energy from the
engine could potentially be utilized. However, significant system modification would be
required to allow the waste heat to be utilized to displace the steam boiler load.
July 2005
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Sample
Figure 6
Hourly Estimated Thermal Availability From Generator
Versus Hourly Water Heater Load
8
Natural Gas Load - Water Heater Only
Available Heater From Generator
Difference
6
MMBtu
4
2
October
November
December
October
November
December
September
August
July
June
May
April
March
February
January
0
-2
-4
Figure 7
Hourly Estimated Thermal Availability From Generator
Versus Hourly Facility Total Natural Gas Load
20
Natural Gas Load
Available Heater From Generator
Difference
15
MMBtu
10
5
September
August
July
June
May
April
March
February
January
0
-5
July 2005
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D-Gen Pro uses 24 x 2 x 12 electrical and thermal data sets to evaluate the economics of
the combined heat and power systems considered in this report. In other words, the
profiles D-Gen Pro uses consist of 24 hour data for a typical weekday and weekend for
each of the 12 months per year. Based upon the hourly electric utility data collected,
typical weekday and weekend electric load profiles were created. A sample winter
weekday and summer weekday profile is shown in Figure 8 and Figure 9 respectively.
Also shown in these figures is the hourly natural gas load profile for both the hot water
heater and the steam boiler. These graphs highlight the difference between steam boiler
energy and the natural gas hot water heater energy consumption. These load profiles
were created using the monitored data and daily natural gas consumption. Appendix C
contains the weekday and weekend hourly load profiles for each month of the year.
Figure 8: Estimated Thermal Load Profile – January Typical Weekday
July 2005
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Sample
Figure 9: Estimated Thermal Load Profile – July Typical Weekday
Utility Rate Structure
D-Gen Pro uses electric and natural gas utility rate structures to determine the existing
utility costs as well as those costs that will be realized following a distributed generation
or combined heat and power installation. Based on our analysis of electric utility bills, it
was determined that after December 2005 a peak electric energy rate of $0.0917/kWh and
an off-peak rate of $0.0888/kWh would be charged to the facility. In addition, there is an
electric demand rate of $6.3548/kW based on actual hourly demand. The net effect of
this demand charge is a net electric charge including demand of $0.1617/kWh after
December 2005. As previously mentioned, since it is assumed that the electric furnaces
will be islanded, no additional electric stand-by rate charges were assumed in the analysis
of this project.
For natural gas rates, the current rate based on the billing information received and used
by D-Gen Pro for this analysis is $0.667/Therm ($6.77/MMBtu). This accounts for both
the natural gas and cheaper fuel oil rate combined into a single value. Based on current
natural gas rates offered in STATE, it was assumed that a distributed generation natural
gas rate would be available to the foundry in the post-installation case. This rate is
$0.871/Therm ($8.71/MMBtu).
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Equipment Selection
Table 4 above provides a specification summary of the two generator types that were
selected for inclusion in this analysis. The data above is from catalog data and is
contained within the D-Gen Pro equipment library. All engines were assumed to be
deployed in the following manner:
•
•
•
•
•
Option #1 - 210 kW combined heat and power plant assumes the engine is
deployed only when facility electric demand exceeds 210 kW.
Option #2 - 420 kW combined heat and power plant assumes at least one engine
is deployed during all hours of the year.
Option #3 - 420 kW combined heat and power plant assumes engines are
deployed when facility electric demand exceeds 210 kW.
Option #4 - 420 kW combined heat and power plant assumes engines are
deployed when facility electric demand exceeds 210 kW.
Option #5 - 960 kW combined heat and power plant assumes at least one engine
is deployed during all hours of the year as needed to completely island this facility
from the electric utility.
In all cases, a heat recovery package was assumed to be installed on the engine/generator
sets.
Economic Analysis Parameters
The inclusion of various economic parameters in the D-Gen Pro software allows various
life cycle and financial metrics to be determined. For the purpose of this analysis, the
following were assumed:
• Discount Rate: 5.5%
• Inflation Rate: 1.5%
• Project Life Time: 20 years for the reciprocating engines.
• This analysis did not account for any tax implications of this project.
July 2005
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Sample
4.3.3
Detailed Analysis Results
This section provides some of the detailed results from this analysis. Note that negative
life cycle savings values occur where simple payback is longer than the project lifetime
assumed. Additional detail is provided in Appendix D.
Table 6: OPTION #1 - 480 kW combined heat and power plant– Detailed Results
Utility Consumption
Electricity
Peak Electric Demand
Natural Gas
Utility Generated
Electricity
Waste Heat Recovered
Annual Utility Costs
Electricity
Natural Gas
Generator O&M
Total Utility Costs
Option #2
Annual Results
Option #2
Annual Savings
Option #2
Percent Savings
1,792,218 kWh
612.2 kW
44,006 MMBtu
3,134,034 kWh
479.8 kW
-25,757 MMBtu
64%
44%
-141%
3,134,034 kWh
9,590 MMBtu
9,590 MMBtu
53%
$260,417
$415,293
$60,318
$736,027
$401,452
-$214,149
-$60,318
$126,986
61%
-106%
15%
Although this option is the most financially attractive, it may not be the optimum
selection since there is no redundancy built in to this option. During all hours of the year,
the facility would be relying on one generator, with only the utility to provide expensive
back-up power in the event of generator maintenance or un-planned failure. However,
there are addendums to this option that retain some of the financial attractiveness, while
increasing the reliability and overall life of this project. For example, if a second 480 kW
generator were installed, then the overall project cost increases. However, if only one
generator is allowed to run at a time and each generator is deployed such that each
operates an equal amount of time, this can reduce the annual run-time on each generator
and extend the project lifetime. Upon analysis, this scenario maintains a fairly attractive
rate of return of approximately 12.00%. Furthermore, this redundant system provides
ample opportunity to perform scheduled maintenance tasks.
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Table 7: OPTION #2 - 1,640 kW combined heat and power plant – Offsite heat loads –
Detailed Results
Utility Consumption
Electricity (furnace)
Peak Electric Demand
Natural Gas (assumed)
Utility Generated
Electricity
Waste Heat Recovered
Annual Utility Costs
Electricity
Natural Gas
Generator O&M
Total Costs
4.4
Option #1
Annual Results
Option #1
Annual Savings
Option #1
Percent Savings*
0 kWh
0 kW
14,296 MMBtu
1,407,854 kWh
1,290 kW
-10,696 MMBtu
33%
52%
-145%
1,407,854 kWh
0 MMBtu
-
-
$0
$110, 268
$20,980
$142,320
$227,607
-$78,965
-$20,980
$127,662
64%
-149%
25%
Analysis Summary
Table 1 above presented an economic summary of the cogeneration design options that were
analyzed for SAMPLE FACILITY. The various alternatives were chosen to represent a range of
capital requirements, a range capacities that could cover a variety of potential applications,
alternate engine deployment strategies, and various heat recovery scenarios. For each option,
Table 1 presents the first year estimated energy savings assuming that the generation is deployed
as noted and that the heat recovered from the generating equipment can be recovered and utilized
in the manner noted. Table 1 also provides an initial estimate of installed cost with and without
any rebate from GAS COMPANY. Although the actual cost of construction will vary depending
upon final contractor selection, we have chosen to use an installed cost of $/kW for all systems.
Simple payback and the internal rate of return (IRR) are provided in Table 1 as well. These
paybacks and return rates assumed an inflation rate of 1.5%, a discount rate of 5.5%, and
neglected any tax rates. From the detailed tables above, the annual average electric generating
efficiency and annual average combined heat and power system efficiency values are also
presented. These values provide an indication of how efficiently the various systems perform as
well as how part-load operation and availability of a thermal load affects engine and system
performance.
July 2005
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Sample
Project Constraints
There are several factors that may act as barriers to the success of this project. At the present
time, these are items that warrant further attention.
•
Thermal Energy Recovery: This study has assumed that thermal energy would be
able to be recovered and will be able to be used in a useful way to displace both hot
water process loads that exist within the facility. However, the actual execution of
this heat recovery warrants further investigation and may affect the economics of this
project.
•
Unfavorable Utility Tariffs: For Options 1 through 4, some electric utility service is
still required during at least some hours of the year. Option 5 is the case where the
facility could operate completed separate (islanded) from the electric utility.
Depending on the individual electric utility, standby changes, backup rates, and exit
fees may be charged which could affect the project economics.
•
Utility Interconnection: Cogeneration systems, when not islanded, require electric
grid interconnection. Electric grid interconnection can be a barrier since it is
dependent on site specific conditions, is dictated by the electric utility you are
reducing your load on, and can thus be an unpredictable cost. In addition to updating
the facilities electric infrastructure, a new gas service line may be required depending
upon the capacity and pressure of the existing feeder. Natural gas line pressure near
the facility may also be an issue.
•
Permitting: Permitting can be a long process which should be started at the earliest
onset of this project. New stationary sources of air emissions are subject to Federal
EPA performance standards. Depending on the final size of the installation, a
licensing procedure may be required. Separate permits are typically required prior to
the commencement of construction and additionally prior to actual operation. The
permitting process can sometimes be streamlined depending on projected emissions,
fuel choice, and selected equipment.
July 2005
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Sample
4.5
Financing Information
There are several avenues that the SAMPLE FACILITY could pursue to finance a combined heat
and power plant. The first and overall lowest cost option is, if the funds are available, to pay for
the entire project upfront. Most facilities do not have this availability of funds and must secure
financing either through an Energy Service Company (ESCO) or through third party lending
institutions. The advantage of arranging financing with an ESCO is simplicity and possibly
guaranteed performance. Depending on the individual ESCO, several options may be available
such that no capital expenditure is required and all ESCO debt payments are made from existing
utility budgets, realizing no increase in monthly expenditures. Additionally, if equipment
performance that is guaranteed fails to satisfy the requirements agreed upon in the contract
development stage, the ESCO would be required to reduce the debt payments by a pre-agreed
upon amount. Going to a third party lender could provide an overall less expensive option if
interest rates are favorable since you would no longer be necessarily paying for the convenience
of ESCO financing or the performance guarantees.
July 2005
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4.6
Other Considerations
Aside from all of the technical and economic items mentioned above, there are a few other
considerations that may also affect the facilities decision to pursue a cogeneration project. In
some instances they may act as constraints to a project, in other cases, the same issues may be
used to bolster the overall project success.
•
Staffing: Some combined heat and power systems may require full time facility staff
supervision. Likely, this expertise does not currently exist on site and will likely have to
be recruited. Other systems require only periodic maintenance that can be arranged
through the project contractor or equipment supplier.
•
Physical Equipment Location: Depending on the size and type of system selected, the
equipment can take up a large footprint. It is worth thinking about whether the space
already exists within the facility for this equipment, or if additional spaces or building(s)
will require construction. Also, as the equipment does tend to produce a significant
amount of noise, location along with sound attenuation will be critical decisions for
installations in applications such as this where unwanted sound needs to be minimized.
•
Facility Electrical Distribution System: The complexity of interconnection will rely
partly on the existing electrical distribution design within the facility. If newer electrical
switchgear is already being employed in a single central location, this will likely simplify
the installation. If the facility has multiple electrical meters, a dispersed distribution
system throughout a large campus, with older electrical switchgear components, the issue
of loading the electrical generation and interconnection may be more complicated.
•
Power Outages: The cost of a power outage is facility dependent. In some instances it
may only be a minor inconvenience, while for others, it may cost a facility millions of
dollars for every hour without power. Combined heat and power systems can improve
the electric reliability of a facility, even in systems completely isolated from the electric
utility (islanded systems).
July 2005
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Sample
5
RECOMMENDATIONS
Based on the analysis included in this report, it is recommended that the SAMPLE FACILITY
take the next steps towards implementing a combined heat and power plant. Specifically, it is
suggested that Options #? and #? be considered further. A potentially valuable first course of
action would be to discuss with the natural gas supplier and/or utility if a more attractive
cogeneration natural gas price is available. This could have the effect of increasing the spark
spread and increase the return on investment for each of the options. An additional area to
pursue would be to investigate the details of recovering and coordinating heat recovery with the
existing heat exchanger / natural gas hot water heater system. Overall, the analysis indicates that
this site has the potential for implementing a cost effective and successful cogeneration plant.
Depending on how the SAMPLE FACILITY wishes to proceed, the Northeast CHP Application
Center can offer a variety of additional services including:
•
•
Upon receipt of design documents and contractor bidding by third parties, we can offer
an independent and objective review and comparison of all documents.
Permitting assistance (offered through our partner PACE University).
July 2005
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APPENDIX A
Combined Heat and Power
A.1
A.2
July 2005
Technical Review
General Benefits
A-1
Sample
A.1
TECHNICAL REVIEW
This section provides a brief discussion of many of the technologies relevant to combine heat
and power projects.
Source: C. B. Oland, 2004, Guide To Combined Heat and Power Systems for Boiler Owners and
Operators, Oak Ridge National Laboratory.
Combined heat and power (CHP) or cogeneration is the sequential production of two forms of
useful energy from a single fuel source. In most CHP applications, chemical energy in fuel is
converted to both mechanical and thermal energy. The mechanical energy is generally used to
generate electricity, while the thermal energy or heat is used to produce steam, hot water, or hot
air. Depending on the application, CHP is referred to by various names including Building
Cooling, Heating, and Power (BCHP); Cooling, Heating, and Power for Buildings (CHPB);
Combined Cooling, Heating, and Power (CCHP); Integrated Energy Systems (IES), or
Distributed Energy Resources (DER).
The principal technical advantage of a CHP system is its ability to extract more useful energy
from fuel compared to traditional energy systems such as conventional power plants that only
generate electricity and industrial boiler systems that only produce steam or hot water for process
applications. By using fuel energy for both power and heat production, CHP systems can be
very energy efficient and have the potential to produce electricity below the price charged by the
local power provider. Another important incentive for applying cogeneration technology is to
reduce or eliminate dependency on the electrical grid. For some industrial processes, the
consequences of losing power for even a short period of time are unacceptable. A major
economic incentive for applying cogeneration technology is to reduce operating expenses by
generating electricity at a lower cost than it can be purchased from the local power provider.
Optimum conditions for implementing cogeneration occur when the price of electricity is high
and rising and the price of fuel is low. Economic viability of cogeneration is sharply influenced
by the marginal cost of generating electricity. This cost is a function of capital investments and
production expenses, including fixed charges, fuel payments, and operational and maintenance
costs. In assessing economic viability, it is important to calculate the production costs of
electricity as an excess above the generating costs of thermal energy alone and then to compare
the cost of production with the cost of purchased electricity. For situations where the cost of fuel
needed to generate a unit of electricity exceeds the unit cost of purchased electricity, the decision
to proceed must be based on other criteria such as improved electric reliability because
cogeneration is not a viable economic option.
New or existing boiler installations with high CHP potential usually fit the following profile, but
CHP may also be viable at installations meeting only a few of these criteria:
• high electricity prices (greater than $0.05/kWh),
• high electricity demand and peak energy usage charges,
• average electric load greater than about 1 MW,
July 2005
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•
•
•
•
•
•
•
ratio of average electric load to peak load exceeding about 0.7,
additional process heat needed,
cost of CHP fuel is low compared to electricity rates,
high annual operating hours,
thermal demand closely matching electric load,
steady thermal loads or steady process waste heat streams, and
issues concerning energy security and reliability.
The following factors enhance the potential of successfully applying cogeneration technology at
new or existing ICI boiler installations:
1. The CHP system is sized to satisfy the thermal needs of the process. In some, but not all
cases, oversized systems are generally more costly and less efficient.
2. Unless inexpensive solid, liquid, or gaseous fuels are available, natural gas is the
preferred fuel for most new CHP applications because of its low emissions and generally
wide availability.
3. To enable efficient electric power generation, it may be necessary to generate thermal
energy at substantially higher pressures and temperatures than that needed for process
applications.
4. Heat load and power demand occur simultaneously.
5. In general, simultaneous demands for heat and power must be present for at least 4,500
h/year, although there are applications where CHP systems may be cost effective with
fewer hours. For example, when electricity rates are high or when the local power
provider offers incentives, this operating period could be as low as 2,200 h/year. The
most cost-effective applications are those that operate continuously (8,760 h/year).
6. Power-to-heat ratio for the plant should not fluctuate more than 10%.
7. Appropriate cogeneration technology is commensurate with the required power-to-heat
ratio of the installation.
8. The viability of cogeneration technology depends on energy prices. The highest potential
for CHP occurs when the price for purchased electricity is high while the price for CHP
fuel is low.
9. The economic feasibility of a CHP system is inversely related to capital and maintenance
costs. In other words, the higher the capital costs or the higher the maintenance costs, the
less likely CHP will be economically viable.
10. The CHP system needs to have high availability.
July 2005
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Combined Heat and Power Technologies
CHP technologies are conventional power generation systems with the means to make use of the
energy remaining in exhaust gases, cooling systems, or other energy waste stream. The
following is a description of typical CHP prime movers.
Reciprocating Engines
Reciprocating engines can be fueled by diesel or natural gas, with varying emission
outputs. Almost all engines used for power generation are four-stroke. The process
begins with fuel and air being mixed. In turbocharged applications, the air is compressed
before mixing with fuel. The fuel/air mixture is introduced into the combustion cylinder
and ignited with a spark. For diesel units, the air and fuel are introduced separately with
fuel being injected after the air is compressed. Reciprocating engines are currently
available from many manufacturers in many size ranges. They are typically used for
either continuous power or backup emergency power. Cogeneration configurations are
available with heat recovery from the gaseous exhaust.
These engines are the fastest growing segment of the market for CHP systems under 5
MW. Capacities range from about 5 kW to 10 MW. They offer better load following
and part load operation than most of the other prime mover technologies. Reciprocating
engines are fueled by natural gas, diesel, or gasoline. CHP systems most commonly use
natural gas because it results in significantly lower emissions. A typical reciprocating
engine equipped with engine exhaust gas heat recovery and engine-jacket coolant heat
recovery is capable of utilizing up to 80% of the input energy (30% electrical power, 50%
recovered heat). Thus only 20% of the input energy is lost via exhaust and radiation.
Combustion Gas Turbines
Combustion turbines range in size from simple cycle units starting at about 1 MW to
several hundred MW when configured as a combined cycle power plant. Industrial
turbines are currently available from numerous manufacturers. Multiple stages are
typical and along with axial blading differentiate these turbines from the smaller
microturbines described below. These turbines have relatively low installation costs (per
kW), low emissions, and infrequent maintenance requirements. However, their low
electric efficiency has limited turbines to primarily peaking unit and combined heat and
power applications. Cogeneration DG installations are particularly advantageous when a
continuous supply of steam or hot water is desired.
Used for large systems where high-pressure steam is needed since exhaust gases leaving
a turbine are a high temperatures. These engines are best suited for base-load
applications. These turbines are much more compact and lighter than similar capacity
reciprocating engines, and NOx emissions are lower than those from reciprocating
engines.
July 2005
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Microturbines
MicroTurbines are small-scale distributed power generation units in the 30-400 kW size
range. The basic technology used in microturbines is derived from aircraft auxiliary
power systems, diesel engine turbochargers, and automotive designs. Microturbines
consist of a compressor, combustor, turbine, and generator. Most microturbine units are
designed for continuous-duty operation and are recuperated to obtain higher electric
efficiencies.
These are newer, smaller combustion turbines that are compact in size and can be brought
on-line quickly, and require less maintenance because they have a smaller number of
moving parts. These have the best potential to be applied for commercial building
combined heat and power applications. Microturbines are capable of burning natural gas,
propane, and gases produced from landfills, sewage treatment facilities, and animal waste
processing plants. Thus they have the versatility to be applied in remote areas. Exhaust
gas temperatures are suitable for producing steam of hot water. NOx emissions are lower
when compared to reciprocating engines but higher than gas turbines.
Boilers with Steam Turbines
Steam turbines are one of the most versatile and oldest prime mover technologies still in
general production. Power generation using steam turbines has been in use for about 100
years, when they replaced reciprocating steam engines due to their higher efficiencies and
lower costs. Conventional steam turbine power plants generate most of the electricity
produced in the United States. The capacity of steam turbines can range from 50 kW to
several hundred MWs for large utility power plants. Steam turbines are widely used for
combined heat and power (CHP) applications.
Unlike gas turbine and reciprocating engine CHP systems where heat is a byproduct of
power generation, steam turbines normally generate electricity as a byproduct of heat
(steam) generation. A steam turbine is captive to a separate heat source and does not
directly convert fuel to electric energy. The energy is transferred from the boiler to the
turbine through high-pressure steam that in turn powers the turbine and generator. This
separation of functions enables steam turbines to operate with an enormous variety of
fuels, from natural gas to solid waste, including all types of coal, wood, wood waste, and
agricultural byproducts (sugar cane bagasse, fruit pits, and rice hulls). In CHP
applications, steam at lower pressure is extracted from the steam turbine and used directly
or is converted to other forms of thermal energy.
July 2005
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Fuel Cells
There are many types of fuel cells currently under development in the 5-1000 kW size
range, including phosphoric acid, proton exchange membrane, molten carbonate, solid
oxide alkaline, and direct methanol. Only a small number is available currently for
commercial and industrial applications, while a larger number is close to marketplace
introduction. Although the numerous types of fuel cells differ in their electrolytic
material, they all use the same basic principle. A fuel cell consists of two electrodes
separated by an electrolyte. Hydrogen fuel is fed into the anode of the fuel cell. Oxygen
(or air) enters the fuel cell through the cathode. With the aid of a catalyst, the hydrogen
atom splits into a proton and an electron. The proton passes through the electrolyte to the
cathode and the electrons travel in an external circuit. As the electrons flow through an
external circuit connected as a load they create a DC current. At the cathode, protons
combine with hydrogen and oxygen, producing water and heat. Fuel cells have very low
levels of NOx and CO emissions because the power conversion in an electrochemical
process. Fuel cells require hydrogen for operation. Typically, hydrogen must be
extracted from hydrogen-rich sources such as gasoline, propane, or natural gas. Cost
effective, efficient fuel reformers that can convert various fuels to hydrogen are necessary
to allow fuel cells increased flexibility and commercial feasibility.
July 2005
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A.2
GENERAL BENEFITS
This section provides a brief discussion of many of the overall benefits that a combined heat and
power system.
Saving Money
By improving efficiency, CHP systems can reduce fuel costs associated with providing heat and
electricity to a facility.
Improving Power Reliability
CHP systems are located at the point of energy use. They provide high-quality and reliable
power and heat locally to the energy user, and they also help reduce congestion on the electric
grid by removing or reducing load. In this way, CHP systems effectively assist or support the
electric grid, providing enhanced reliability in electricity transmission and distribution.
Reducing Environmental Impact
Because of its improved efficiency in fuel conversion, CHP reduces the amount of fuel burned
for a given energy output and reduces the corresponding emissions of pollutants and greenhouse
gases.
Conserving Limited Resources of Fossil Fuels
Because CHP requires less fuel for a given energy output, the use of CHP reduces the demand on
our limited natural resources – including coal, natural gas, and oil – and improves our nation’s
energy security.
Combined heat and power projects also benefit the local electric utilities by providing
alternatives to utility distribution grid expansions and possible reducing grid congestion.
July 2005
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APPENDIX B
Equipment Specifications
.
July 2005
B-1
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APPENDIX C
Weekday and Weekend Load Profiles for 12 Months
July 2005
C-1
Sample
January Average Weekday Hourly Load Profiles
Weekday Average Electrical Energy
Weekday Average Boiler Energy
Weekday Average Hot Water Energy
800
10
9
700
Electrical Energy (kWh)
7
500
6
400
5
4
300
3
200
Thermal Energy (MMBtu)
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
January Average Weekend Hourly Load Profiles
Weekend Average Electrical Energy
Weekend Average Boiler Energy
Weekend Average Hot Water Energy
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
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February Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
February Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-3
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March Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
March Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-4
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April Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
April Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-5
Sample
May Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
May Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-6
Sample
June Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
June Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-7
Sample
July Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-8
Sample
August Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
August Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-9
Sample
September Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
September Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-10
Sample
October Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
October Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-11
Sample
November Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
November Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-12
Sample
December Average Weekday Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
December Average Weekend Hourly Load Profiles
800
10
9
700
7
500
6
400
5
4
300
3
200
8
600
2
100
1
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
July 2005
C-13

SAMPLE Initial Feasibility Report: Combined Heat and Power Plant

Transcription

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