Sample CHP Feasibility Study 080405users.csc.calpoly.edu/.../Sample_CHP_Feasibility_Study_080405.pdf · Sample Combined Heat and Power Feasibility Study July 2005 1 1 EXECUTIVE SUMMARY

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

July 2005 i

TABLE OF CONTENTS

1 Executive Summary .............................................................................................................1 Financial Summary ..............................................................................................................3 2 Facility Analysis ..................................................................................................................4 2.1 Facility Description and Existing Operations ..........................................................4 2.2 Energy Billing Analysis...........................................................................................5 2.3 Energy Efficiency Evaluation ..................................................................................7 3 Data Collection ....................................................................................................................8 3.1 Description...............................................................................................................8 4 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 5 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

Sample Combined Heat and Power Feasibility Study

July 2005 1

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.


July 2005 2

Table 1: Annual Savings, Installed Cost, Simple Payback, and Rate of Return (With and Without Utility Rebates)

Without GAS COMPANY Rebate With GAS COMPANY Rebate6 Cogeneration Option Annual

Energy Savings

Estimated Installed

Cost

Simple Payback

Internal Rate of Return

Estimated Installed

Cost

Simple Payback

Internal Rate of Return

Option #1: 210 kW CHP Plant One 210 kW Reciprocating Engine1

$41,551 $315,000 7.6 years 13.4% $256,703 6.2 years 17.0%

Option #2: 420 kW CHP Plant Two 210 kW Reciprocating Engines2

$32,310 $630,000 19.5 years 1.7% $542,490 16.8 years 3.3%


$56,213 $630,000 11.2 years 7.9% $560,078 10.0 years 9.4%


(For Reference Purposes Only)

$88,157 $630,000 7.2 years 14.4% $535,905 6.1 years 17.3%


(For Reference Purposes Only)

$10,527 $1,440,000 137 years N/A $1,346,228 128 years N/A

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.


July 2005 3

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.


July 2005 4

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.


July 2005 5

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 Energy (kWh)

Electric Demand

(kW)

Electric Cost

Natural Gas

(MMBtu)

Natural Gas Cost

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.


July 2005 6

Table 3: B Building Annual Electric Energy Consumption and Cost Summary

Month Electric Energy (kWh)

Electric Demand

(kW)

Electric Cost

Natural Gas

(MMBtu)

Natural Gas Cost

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.


July 2005 7

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).


July 2005 8

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.


July 2005 9

Figure 2

Hourly Electrical Demand Profile

0

100

200

300

400

500

600

700

800

900

1000

Janu

ary

Februa

ryMarc

hApri

lMay

June Ju

ly

Augus

t

Septem

ber

Octobe

r

Novem

ber

Decem

ber

Dem

and

(kW

)

Figure 3

Hourly Water Heater Natural Gas Profile

0

1

2

3

4

5

6

7

Janu

ary

Februa

ryMarc

hApri

lMay

June Ju

ly

Augus

t

Septem

ber

Octobe

r

Novem

ber

Decem

ber

Dem

and

(MM

Btu

)


July 2005 10

Figure 4

Hourly Total Natural Gas Profile

0

5

10

15

20

25

Janu

ary

Februa

ryMarc

hApri

lMay

June Ju

ly

Augus

t

Septem

ber

Octobe

r

Novem

ber

Decem

ber

Dem

and

(MM

Btu

)


July 2005 11

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


July 2005 12

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.


July 2005 13

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.


July 2005 14

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 75 kW Properties Net Output 75 kW

Heat Rate (HHV) 12,240 Btu/kWh Jacket Water Temperature 230ºF

Installed Cost (with heat recovery)

$2,200/kW

Variable Operational & Maintenance Costs

$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


July 2005 15

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 Value Net Output 30 kW

Heat Rate (HHV) 12,600 Btu/hr Rating Conditions 59.5 F

0’ Altitude Installed Cost

(with heat recovery) $2,200/kW

Fixed Operational & Maintenance Costs

$1,980/year

Variable Operational & Maintenance Costs

$0.0007/kW/year


July 2005 16

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 17

Figure 6

Hourly Estimated Thermal Availability From Generator Versus Hourly Water Heater Load

-4

-2

0

2

4

6

8

Janu

ary

Febr

uary

Mar

ch

April

May

June July

Augu

st

Sept

embe

r

Oct

ober

Nov

embe

r

Dec

embe

r

MM

Btu

Natural Gas Load - Water Heater OnlyAvailable Heater From GeneratorDifference

Figure 7

Hourly Estimated Thermal Availability From Generator Versus Hourly Facility Total Natural Gas Load

-5

0

5

10

15

20

Janu

ary

Febr

uary

Mar

ch

Apr

il

May

June July

Aug

ust

Sept

embe

r

Oct

ober

Nov

embe

r

Dec

embe

r

MM

Btu

Natural Gas LoadAvailable Heater From GeneratorDifference


July 2005 18

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 19

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).


July 2005 20

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 21

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

Option #2

Annual Results Option #2

Annual Savings Option #2

Percent Savings Utility Consumption Electricity 1,792,218 kWh 3,134,034 kWh 64% Peak Electric Demand 612.2 kW 479.8 kW 44% Natural Gas 44,006 MMBtu -25,757 MMBtu -141% Utility Generated Electricity 3,134,034 kWh - - Waste Heat Recovered 9,590 MMBtu 9,590 MMBtu 53% Annual Utility Costs Electricity $260,417 $401,452 61% Natural Gas $415,293 -$214,149 -106% Generator O&M $60,318 -$60,318 - Total Utility Costs $736,027 $126,986 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.


July 2005 22

Table 7: OPTION #2 - 1,640 kW combined heat and power plant – Offsite heat loads – Detailed Results

Option #1

Annual Results Option #1

Annual Savings Option #1

Percent Savings*Utility Consumption Electricity (furnace) 0 kWh 1,407,854 kWh 33% Peak Electric Demand 0 kW 1,290 kW 52% Natural Gas (assumed) 14,296 MMBtu -10,696 MMBtu -145% Utility Generated Electricity 1,407,854 kWh - - Waste Heat Recovered 0 MMBtu - - Annual Utility Costs Electricity $0 $227,607 64% Natural Gas $110, 268 -$78,965 -149% Generator O&M $20,980 -$20,980 - Total Costs $142,320 $127,662 25%

4.4 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 23

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 24

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 25

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 26

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 A-1

APPENDIX A

Combined Heat and Power

A.1 Technical Review A.2 General Benefits


July 2005 A-2

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 A-3

• 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 A-4

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 A-5

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 A-6

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 A-7

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 B-1

APPENDIX B

Equipment Specifications

.


July 2005 C-1

APPENDIX C

Weekday and Weekend Load Profiles for 12 Months


July 2005 C-2

January Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)

Weekday Average Electrical Energy Weekday Average Boiler Energy

Weekday Average Hot Water Energy

January Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)

Weekend Average Electrical Energy Weekend Average Boiler Energy

Weekend Average Hot Water Energy


July 2005 C-3

February Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



February Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-4

March Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



March Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-5

April Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



April Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-6

May Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



May Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-7

June Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



June Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-8

July Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



July Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-9

August Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



August Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-10

September Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



September Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-11

October Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



October Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-12

November Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



November Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)




July 2005 C-13

December Average Weekday Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



December Average Weekend Hourly Load Profiles

0

100

200

300

400

500

600

700

800

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

Elec

tric

al E

nerg

y (k

Wh)

0

1

2

3

4

5

6

7

8

9

10

Ther

mal

Ene

rgy

(MM

Btu

)



Documents

Sample CHP Feasibility Study 080405users.csc.calpoly.edu/.../Sample_CHP_Feasibility_Study_080405.pdf · Sample Combined Heat and Power Feasibility Study July 2005 1 1 EXECUTIVE SUMMARY