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THE PENNSYLVANIA STATE UNIVERSITY DEPARTMENT OF ARCHITECTURAL ENGINEERING THESIS 2003-2004

NEW INDEPENDENCE HIGH SCHOOL/SHARED USE FACILITY INDEPENDENCE, OHIO

MECHANICAL OPTION JOHN JOSEPH SHAW PFC – DR. FREIHAUT SPRING 04 THESIS REPORT 05APR04 - 20 -

From the macro perspective, the revised National Energy Policy demands consideration of alternative energy systems that maximize building energy efficiency, defined as the total energy “input” (electric and thermal – secondary energy) per the total combustion fuel input (coal, natural gas etc) required to produce the secondary energy. The additional goals involve reducing the total national, fossil fuel energy demand relative to traditional building energy sources (grid and chemical), and reducing environment pollution emissions. A facility that incorporates the national energy policy ideology and implements strategies to meet these goals may result in lower fossil fuel energy consumption, lower fossil fuel demand and less environment pollution. This may result in lower operating costs, maintenance costs, and installation costs. A revised cooling and heating plant that rethinks how buildings use energy may deal with these issues reasonably. Proposed Solution of the Problem In order to address the global problem of reducing total fossil fuel energy demand, pollution emissions, operating cost, and possibly installation costs, Owners may consider integrating a trigeneration plant to substitute or integrate with the existing cooling/heating plant/utility grid. The ultimate goal involves maximizing the combusted fuel energy into useful alternate forms of energy. The choice of the combustion fuel also assists with pollution emissions reduction. Perhaps the strongest reason for considering this option involves power reliability and dependability, and use of waste heat for thermal energy needs. Public school facilities frequently become places of refuge during times of natural disaster or civic troubles. Facilities capable of producing self sustaining power and thermal energy reassures residents and promotes local community and government stability.

Cogeneration/Trigeneration Feasibility Introduction The term, Cogeneration, describes a process of converting chemical energy, through combustion, into two useful alternate energy forms. The combustion process occurs through a reciprocating engine, similar to the engine of a vehicle, or a turbine engine, similar to an airplane combustion turbine engine, without the noise. The engine spins a driveshaft that produces mechanical work and waste heat. The mechanical work drives an electric generator and the waste heat is collected and used as hot water or steam. Recovering waste heat and utilizing it for building energy needs increases the building energy efficiency as defined previously. In addition, the hot water or steam may be used to drive hot water or steam absorption chillers for cooling. When cooling becomes a third useful energy form, the term cogeneration changes to Trigeneration. Typically absorption chiller waste heat is dumped to the atmosphere through a cooling tower, however, this waste heat may be used for domestic hot water heating, through double wall heat exchangers before being dumped to the atmosphere in the cooling tower. The ultimate goal involves utilizing as much of the output energy as feasible for the amount of input energy. Due to low emissions, the preferred fuel choice involves natural gas, however other alternative fuels, such as biomass, methane, diesel, and others may be used. Figure 5 shows a possible trigeneration system idea.




Electricity production typically is integrated with the building distribution and may be used directly at the facility or “pushed” back into the utility grid by a step up transformer for use at overhead voltages. IEEE standard 1547 establishes guidelines for cogeneration system utility interconnections. The recent development of this standard clearly indicates a growing market, due to Owner’s who desire this form of building energy production for reliability, power quality, and utility price reduction reasons. However, Design Professionals must exercise strong communication with local utility representatives due to severe interconnection safety reasons. For example, if an Owner sells power from onsite cogeneration production back to the utility, several safety equipment and configurations must be installed prior to integrating with the electric utility grid. If the grid lost power, utility crews must have a way of repairing utility lines without risk of electrocution due to the Owner’s cogeneration system energizing the utility circuit.

Basis of Design The success of Cogeneration integration involves determining the current facility heating, cooling, electric load profiles, energy consumption, emissions performance, and economic factors such as equipment installation, operating and maintenance costs. Once determined, a Design Professional may select equipment to displace electrical utility demand and thermal needs. In addition, integration costs including equipment, installation, operating and maintenance costs may also be determined. Finally, a comparison of the proposed cogen system with the current facility heating and cooling plant equipment, costs, and emissions all normalized with national data may be determined. The National Perspective Nationally, education facilities occupy the lower median regarding electric and natural gas energy consumption. In 1999 (recent data unavailable), The Energy Information Administration (EIA)

Figure 5 - Trigeneration Simplified Schematic Source: Midwest CHP Application Center




reports that educational facilities consumed 257 trillion btu’s of electricity and 227 trillion btu’s of natural gas (Figure 6). In 2003, the commercial building industry emitted 9.3metric tons of carbon dioxide by natural gas, 782.5metric tons of CO2 by electricity (utility grid production), and 195.8 metric tons of CO2 by coal. In 2002, 4.7 million tons of Nitrogen Oxide and 9.9 million tons of sulfur dioxide were released to the atmosphere (Figure 7). Although Federal regulations mandate reductions in NOx and SO2, and the annual discharge amounts reduce each year, the EIA predicts a continued growth in CO2 emissions.

Figure 6 - Electrical and Natural Gas Usage Summary Data from www.eia.doe.gov




Current Design Energy Profiles In order to determine the quantity and type of potential trigeneration equipment selection, load and energy modeling was conducted using Trane Trace700. The modeling establishes thermal and electrical demand, consumption, and economic data. The output results were exported into Microsoft Excel to use for analysis and establish graphical results. The results are profiled by monthly data lines for a typical 24 hour day. Both cooling and heating needs are consolidated into thermal (Btu/hr) units. The facility requires a maximum cooling capacity of approximately 650ton and a maximum heating demand of approximately 4000Mbh. Appendix E contains energy modeling results prints. The reader is reminded that education facilities have occupancy schedules that typically operate between 7am and 3pm, and 3pm till 11pm for sporting events, afterschool, and community center activities. Therefore the hours between 11pm and 7am reflect minimal demand to maintain lighting for janitorial services and HVAC night setback thermal and electrical demand. Figures 7-11 reflects occupancy schedules for a typical classroom, lunch, and evening day, electric monthly (Kw) demand, and monthly thermal (Btu/hr) demand profiles over a 24 hour time step. The occupancy schedules indicate a 25th hour that is an error in the chart formation. The report deadline prevented correction to this chart. Since the intent of trigeneration involves displacing the hourly electric and thermal demand, a thorough understanding of these profiles is required. The reader is reminded to review the existing plant summaries in the previous existing conditions section. Table 1 summarizes the maximum thermal and electrical demand and consumption values for the year. Table 2 summarizes monthly energy expenditures. Overall the facility spends approximately $176,555 per year on electric and natural gas. Cogeneration attempts to displace as much of these energy costs as feasible. The utility rate structures mentioned previously result in the costs listed below. The summer month natural gas costs reflect costs for the hot water reheat.

Figure 6 – Pollution Emissions Data www.eia.doe.gov




Table 1 - ELECTRICAL AND THERMAL MAX DEMAND/CONSUMPTION SUMMARY

ELEC Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec On-Pk Cons. (kWh)

64,563 58,183 78,004 74,560 112,705 96,782 99,563 96,215 95,200 79,871 63,294 61,123

Off-Pk Cons. (kWh)

70,999 62,745 54,594 43,686 59,508 58,770 78,010 54,484 53,271 47,576 57,978 69,511

On-Pk Demand

(kW) 374 375 373 461 716 901 926 781 700 486 404 374

On-Pk Cons. (kWh)

64,563 58,183 78,004 74,560 112,705 96,782 99,563 96,215 95,200 79,871 63,294 61,123

NG On-Pk Cons.

(therms) 5,793 5,290 3,932 981 838 909 918 951 736 1,160 1,788 4,820

On-Pk Demand

(therms/hr) 41 47 37 14 4 4 4 4 4 16 21 38

Building Energy Consumption = 75,077 Btu/(ft2-year) Total Kwh/of

fpk 980,062 Total Therm 28,116

Source Energy Consumption = 133,368 Btu/(ft2-year) Total Kwh/o

npk 711,132 Total Therm /hr 47

Total Kw 926 Floor Area =

114,330

ft2

Total Kwh 1,691,194

Total 600

Table 2 - ELECTRICAL AND THERMAL MAX DEMAND/CONSUMPTION SUMMARY ELEC Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec

On-Pk Cons. ($) 4,049 3,654 4,775 5,049 7,598 6,497 6,613 6,255 6,420 4,862 3,973 3,850

On-Pk Demand

($) 4,557 4,572 4,540 5,575 9,408 11,794 12,044 10,385 9,209 4,809 4,019 3,735

Total ($): 8,606 8,226 9,315 10,625 17,006 18,291 18,657 16,640 15,629 9,671 7,992 7,586

On-Pk Cons. ($) 4,049 3,654 4,775 5,049 7,598 6,497 6,613 6,255 6,420 4,862 3,973 3,850

NG On-Pk

Cons. ($) 5,741 5,284 3,938 997 849 925 945 1,015 752 1,173 1,833 4,859

Elec Cons. ($) 63,596 Elec Demand ($) 84,647

Gas Cons. ($) 28,312 Total ($): 176,555

Floor Area (ft2)

114,330




Figure 7 - Occupancy Schedule Profiles

TYPICAL CLASS/ADMIN OCCUPANCY SCHEDULE

00.10.20.30.40.50.60.70.80.9

1

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

HOUR

PER

CEN

TAGE

Jan-Dec Clg Dsn Heating Jan-May WkdyJun-Aug Wkdy Sep-Dec Wkdy Jan-Dec Sat-Sun

TYPICAL LUNCH OCCUPANCY SCHEDULE

00.10.20.30.40.50.60.70.80.9

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TYPICAL EVENING USE OCCUPANCY SCHEDULE

00.10.20.30.40.50.60.70.80.9

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YEARLY DESIGN HOURLY KW DEMAND

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YEARLY DESIGN THERMAL DEMAND

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Figure 8 - Yearly Design Kw and Thermal Hourly Demand Profiles




YEARLY WEEKDAY KW DEMAND

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YEARLY WEEKDAY THERMAL DEMAND

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Figure 9 - Yearly Weekday Kw and Thermal Hourly Demand Profiles




YEARLY SAT KW DEMAND

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YEARLY SAT THERMAL DEMAND

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Figure 10 - Yearly Saturday Kw and Thermal Hourly Demand Profiles




YEARLY SUN KW DEMAND

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YEARLY SUN THERMAL DEMAND

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Figure 11 - Yearly Sunday Kw and Thermal Hourly Demand Profiles




Economic factors such as central plant installation costs, operating costs, and maintenance costs were also entered into the energy model. The model was based on a 10 year finance period and declining balance payback schedule. Table 3 summarizes the economic factors including annual utility costs from Table 2. The costs specifically indicate the heating and cooling equipment and some supporting pipe, pump, insulation, infrastructure costs. The entire facility HVAC scope (all HVAC items and infrastructure) cost approximately $4.4 million.

Table 3 - ECONOMIC FACTORS Equip/Installed Energy

Op $ Maint

Chillers $285,000 Elec $148,243 2 units NG $28,312 Boilers $130,000 11 units Infrastructure $40,000 Total $455,000 $176,555 $4,000

Table 4 outlines the existing heating plant emissions from the natural gas fired boilers. These values establish the pollution from the current heating plant for purposes of comparison to the cogen pollution production. Natural gas with appropriate pollution cleaning devices release low quantities of pollutants. Dr. Freihaut provided assistance with the pollution calculations due to the combustion chemistry.

Table 4 – Existing Boiler Emission Performance Data Patterson-Kelly Model NM-2000

CO 302 ppm Equipment performance

Full output

Modulating output SO2 0 ppm Equipment performance

Full output

NOX 7 ppm Equipment performance

Full output

Quantity 11 Table 5 outlines the existing utility generating station emissions for a national utility grid serving the facility and a boiler plant emissions. The electric utility supplier is The Electric Illuminating Company. Dr. Freihaut provided assistance with the pollution calculations due to the combustion chemistry. The area served by the new high school contains 70.7% coal combustion and 29.3% nuclear.




Table 5 - EXISTING ELECTRIC UTILITY GRID EMISSONS lbm Pollutantj /kWh U.S.

Fuel % Mix U.S. Particulates SO2/kWh NOx/kWh CO2/kWh

Coal 55.7 6.13E-04 7.12E-03 4.13E-03 1.20E+00

Oil 2.8 3.03E-05 4.24E-04 7.78E-05 5.81E-02

Nat. Gas 9.3 0.00E+00 1.26E-06 2.36E-04 1.25E-01

Nuclear 22.8 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Hydro/Wind 9.4 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Totals 100.0 6.43E-04 7.54E-03 4.44E-03 1.38E+00

lbm Pollutantj /kWh %Indpendence OH Particulates SO2/kWh NOx/kWh CO2/kWh

70.7 7.78E-04 9.04E-03 5.24E-03 1.52E+00

0.0 0.00E+00 0.00E+00 0.00E+00 0.00E+00

0.0 0.00E+00 0.00E+00 0.00E+00 0.00E+00

29.3 0.00E+00 0.00E+00 0.00E+00 0.00E+00

0.0 0.00E+00 0.00E+00 0.00E+00 0.00E+00

100.0 7.78E-04 9.04E-03 5.24E-03 1.52E+00 Grid Kwh 1,691,194 1315.7lbs 15288.4lbs 8861.9lbs 2,570,614.9lbs

lbm Pollutantj /kWh US Gas Boiler

Particulates SO2/kWh NOx/kWh CO2/kWh 0.00E+00 0.00E+00 2.00E-05 5.20E-01

Boiler Therms

28,116 OR Kwh 8239986.2 0 0 5.6E-4lbs 14.56lbs Particulates SO2 NOx CO2 Total 1315.7lbs 15288.4lbs 8861.9 2,570,619.5lbs




Proposed Trigeneration System Equipment Selection Strategy Mechanical The selection of trigeneration equipment depends on electric and thermal displacement strategies and the performance of the equipment. Cogeneration equipment involves two primary thermodynamic cycles, the top and bottom cycle. Top cycles produce electrical power with waste heat as the byproduct and bottom cycles produce more thermal energy (through waste heat) with electricity as the byproduct. Microturbine engines offer low maintenance, highly reliable, less part load tolerance equipment while reciprocating engines offer higher maintenance, moderately-highly reliable, more part load tolerance equipment. Therefore, a microturbine shall be selected to displace the building base electric and thermal load, and one reciprocating engine shall displace the energy demand between the normally occupied times of 7am-11pm. The utility grid shall remain connected to displace design day demand, one air cooled chiller and two hot water boilers shall remain. The cogeneration equipment can be controlled via DDC controls to energize based on time clock schedule or load demand. Based on the profiles shown previously, the Elliot Microturbines model 100 Kw CHP shall displace the building base load of 75-100Kw and varying thermal load of up to 500mbh. One Hess Microgen model 375 unit shall displace the normal occupancy demand as well as produce 1700Mbh thermal capacity. During heating season, the Hess thermal output provides 200° water into a common header as well as the Elliot unit for heating needs. This hot water supplies air-handler heating coils as well as air terminal reheat coils. Excess thermal energy may be exchanged with domestic water to meet shower and kitchen hot water needs although these calculations have not been completed. During Cooling season, the Elliot thermal output provides hot water for reheat and/domestic hot water and the Hess thermal output provides hot water to a Cention HW absorption chiller. The absorption chiller flowrate requires hot water from the two backup boilers in addition to the Hess Microgen unit. The absorption chiller rejected heat is dissipated either through the Century cooling tower or may be utilized for domestic hot water heating prior to discharge to the cooling tower. Showers, sink, and lavatory domestic hot water use may require up to 35gpm of 100°F water which is the inlet cooling tower water temperature. This heat may be exchanged through a double wall heat exchanger to avoid using the natural gas domestic water heater except for kitchen use. Figure 12 shows a diagram of the Hess reciprocating engine and the Cention hot water chiller. The equipment selection strategy involves only replacing one of the electric, air cooled chillers and replacing all of the boilers except two for backup or extra capacity needs. The boiler setpoints must be adjusted to provide the 200°F water. Appendix F contains equipment cut sheets. Please note that the cogeneration thermal output water temperatures can be altered to suit traditional HVAC system design with negligible performance impact.




YEARLY WEEKDAY KW DEMAND

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JAN TOTAL KW WKDY FEB TOTAL KW WKDY MAR TOTAL KW WKDY APR TOTAL KW WKDYMAY TOTAL KW WKDY JUN TOTAL KW WKDY JUL TOTAL KW WKDY AUG TOTAL KW WKDYSEP TOTAL KW WKDY OCT TOTAL KW WKDY NOV TOTAL KW WKDY DEC TOTAL KW WKDY

YEARLY WEEKDAY THERMAL DEMAND

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JAN TOTAL THERMAL MBH WKDY FEB TOTAL THERMAL MBH WKDY MAR TOTAL THERMAL MBH WKDYAPR TOTAL THERMAL MBH WKDY MAY TOTAL THERMAL MBH WKDY JUN TOTAL THERMAL MBH WKDYJUL TOTAL THERMAL MBH WKDY AUG TOTAL THERMAL MBH WKDY SEP TOTAL THERMAL MBH WKDYOCT TOTAL THERMAL MBH WKDY NOV TOTAL THERMAL MBH WKDY DEC TOTAL THERMAL MBH WKDY

Weekday Kw and Thermal Hourly Demand Displacement Strategy

Elliot Unit Base Load

Elliot Unit Base Load Hess Microgen Unit

Hess Microgen Unit




Figure – 12 Hess Reciprocating Engine and Cention Hot Water Chiller




Electrical Each unit provides 480/277V, 3-phase power with power factor detection and correction components built in. IEEE standard 1547 outlines electric interconnection standards for integrating cogeneration systems with utility grid connections to buildings. Depending on cost effectiveness, Owner’s desire, and Design Professional’s recommendations, these systems may produce power for the building independently with the utility providing standby power, may produce power in parallel with a building utility connection (peak shaving etc), or may produce excess power for distribution back to the utility grid where the utility purchases the excess power. Electric utility companies typically desire power buy back options to produce at least 1MW of excess power. First the Owner must pay for an interconnection study conducted by the utility irregardless. Second, if the Owner desires to sell power back to the utility, the utility will only purchase the power at the utilities displaced cost. Most utilities only purchase the power at 1.5 cents/Kwh. In addition, the Owner must purchase a step up transformer in order to supply power at overhead distribution voltages. Larger cogen plants, 1MW-hundreds of MW’s, have generators that produce the required overhead voltages to minimize transformer costs. In this option, the Owner then provides a step down transformer for the Owner’s normal electrical needs. Therefore, utility buy back requirements, fees, and rates prevent small cogen systems from cost effectively utilizing this option. The thesis redesign involves a parallel interconnection with the cogen units providing the majority of the power and the utility remains actively connected (no automatic transfer switch) as reserve power for excess demand. In this manner, the IEEE standard and utility companies require overcurrent, over/under frequency, reverse power, under power, under/over voltage, synchronism check relays, and breaker protection for the incoming electric distribution and each cogen unit connection. This equipment including the required breaker protection may be purchased in cubicle switchgear that may be attached to the building main switchgear. The proposed cogeneration system connects schematically per figure 13.

Switchgear

Figure 13 – Utility Interconnection Requirements Source: AP Energy




Constructability Issues When installing and using the proposed cogen system for this facility, Owners, Design Professionals, and Contractors must be aware of several issues. First the proposed units are configured for indoor use, but have outdoor enclosure kits, and may be located in the current main boiler mechanical room. These units would displace the boiler battery footprint and provide easy electrical connection to the main switchgear. This minimizes additional pipe and conduit distribution. The indoor installation requires dedicated ductwork to outdoor air louvers for the combustion air. This ductwork could be routed near the existing air-handling unit outdoor air louvers. In addition the combustion exhaust ductwork could be routed near the displaced boiler batter exhaust ductwork. These units require concrete equipment pads and it is recommended that a diesel storage tank be installed to assist the cogen engine operation for the reciprocating type engines. The Elliot model occupies a footprint of 120”Lx36”Wx83”H high and weighs 4,000lbs. The Hess model occupies a footprint of 122”Lx46”Wx70”H and weighs 11,600lbs. Second, both units require 16 weeks lead time for delivery and with the optional sound reducing options; the units produce sound levels comparable or slightly less than typical central station air handlers. Cogeneration systems do require special permits that the Owner secures under Design Professional’s assistance. Third, due to their small size, both units typically would have maintenance performed by factory personnel under a maintenance contract with the Owner. The Elliot model has the following maintenance schedule:

The Hess unit has the following maintenance schedule

Hess Microgen (Maintenance schedule) Item Intervals

Initial inspections

Preventive Maintenance




As req’d

50hr 250hr 750hr 1500hr 3000hr 6000hr 12000hr 24000hr

Oil/filter --Oil filter $32.00 --oil 5gal x $4.50=$22.50 --labor

x x x x x x x x

Take Oil sample x x x x x x x x Inspect Air Filter x x x Replace Air Filter x x x x x Inspect belts/hoses x x x x x Replace Belts/hoses x x x x Inspect electrical connections x x x x x x x x x Inspect coolant x x x x x x Replace Coolant x x x Inspect plugs x x x Replace plugs x x x x x x As

req 50 250 750 1500 3000 6000 12000 24000

Check Racor x x x Replace Racor filter x x x x x x Ohm wires (record) x x Replace wires x x x x x x Compression Test x x x x x Retorque head bolts x x x x x Adjust valve lash x x x x x x Inspect Generator x x x x x Test Generator insulation And connections

x x x

Inspect Cview Connections x x x x x x x x Inspect Intercooler Chiller x x x x x x x Document fuel consumption As

req 50 250 750 1500 3000 6000 12000 24000

Document average exhaust temp x x x x x x x x Document emissions data x x x x x Inspect charging system x x x x x x x x Rebuild P-1 Pump x x x Inspect main breaker Contacts

x x x x x x x x

Clean unit x x x x x x x x x Flush dump radiator x x x Clean cabinet/generator windings with dry low pressure compressed air

x x x x

Install Catalyst converter x Clean/rotate catalyst x x x x x x Perform top end inspection x x x Perform bottom end inspection x x




Results In order to determine the success of the displaced energy, the fuel utilization efficiency must be determined. This is a simple, rule-of-thumb calculation procedure since complex modeling is required for true system performance evaluation. Sophisticated software models could not be acquired due to software Owners refusal for trademark protections. The following table outlines the calculation procedure and table 6 outlines the results summary for the proposed cogeneration equipment. The calculation procedure compares the cogen output with the current plant efficiency in order to determine the cogen operating efficiency and current design displaced energy savings. The calculations indicate a 35% total fuel savings compared to the current facility fuel consumption.

Table 6 - FUEL UTILIZATION RESULTS SUMMARY Indv Output Total Output Total Input Quantity

Boiler EFFq 0.85 Kw Mbh Mbh Mbh Qeff Elec Gen EFFp 0.34

Elliot Sys 100 587 928.3 1235.51 1 0.48

EEFshp 0.52 Hess Sys 375 1900 3179.9 3831.2 1 0.50

Figure 14 – Fuel Utilization Savings Calculation




EEFchp 0.82 Hours Run Kwh

EEFferc 0.57 1 8688 868,800 FUE 0.55 1 4732 887,250 S 0.35

Total Kwh 1,756,050 1,691,194

Calculated Fr Energy Model

Table 7 lists equipment costs, installation costs, operating costs, and maintenance costs for the proposed trigeneration system. One factor mentioned without any values includes the permits and grants columns. Cogeneration systems require special permits due to the energy production at the facility. These permits address electrical interconnection permits and combustion emission permits. Grants provide a means to reduce the obvious enormous first costs. The Federal government and State governments offer grant incentives for this and other alternate energy technologies. The thesis deadline prevented an investigation of the quantity and type of these grants to be included in this report, however, this is a real cost reduction method. In addition, natural gas suppliers may offer cogeneration utility rate reductions for the use of natural gas. This would further reduce the operating utility costs. Finally, continued manufacturing production, due to increased market demand, will also reduce equipment, installation, and maintenance costs. Governmental bodies and a growing market support this technology.

Table 7 - ECONOMIC FACTORS

Equip Installed Fuel Op $

Maint Permits Grants

Elliot $95,000 $19,000 $109/yr $13,945 $1,700 Annual ?

1 unit $12,000 12,000hrs

$21,000 24,000hrs

Hess $450,000 $50,000 $72/yr $100,816 $4,364 Annual ?

1 unit

$9,803 12,000hrs

$18,887 24,000hrs

Cention Chiller $210,000 $50,000 $3,000

Cention Cooling Tower

$25,000 $11,000 $4,000

Elec Cubicle Breaker/Relays

$65,000 Annual incl avg for 12/24 overhauls

Total $845,000 $130,000 $181 $74,754 ? ? Note: the over maintenance at 12k and 24k hrs were averaged over their run cycle to get the annual

cost. The Hess Microgen unit run hours was estimated from the kw profiles.




Table 8 lists the emissions performance of the cogen system. The choice of natural gas eliminates the particulates and SO2 pollution.

Table 8 - TRIGENERATON EQUIPMENT EMISSIONS ELLIOT Quantity - 1 CO <1.56 lbs/MWhr (<41 ppm) NOx <1.49 lbs/MWhr (<24 ppm) SO2 None

lbm Pollutantj /kWh Gas Turbine

Particulates SO2/kWh NOx/kWh CO2/kWh

0.00E+00 0.00E+00 2.50E-04 1.75E+00 868,800 Kwh 0 0 217.2lbs 1,520,400 HESS CO <0.15g/bhp-hr(<9 ppm) Quantity - 1 NOx <0.60g/bhr-hr(<84ppm)

SO2 None

lbm Pollutantj /kWhGas Recip Engine

Particulates SO2/kWh NOx/kWh CO2/kWh

0.00E+00 0.00E+00 6.25E-03 1.12E+00 887,250 Kwh 0 0 5501lbs 993,720lbs

Summary and Conclusion Although the building utilizes the chemical energy combustion more efficiently, the costs associated with this type of installation initially appear to be a bad investment at current prices. The cogen approach costs $1,334,714 while the current design costs $633,555. Initially, this type of investment would not experience a payback when compared to the existing system design. However, additional funding assistance through grants and reduced natural gas price incentives for cogeneration would reduce the total costs substantially. Due to the thesis deadline, these specific incentives were not able to be determined. In addition, given the predicted substantial increase in electric demand and limited generation station production capacity, electric utility rates will continue to escalate. The reader should refer to the electric demand and natural gas price predictions from the

the pennsylvania state university...the pennsylvania state university department of architectural...

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