FILE COP;

DO NOT REMO

HUD

Utilities

Demonstration

Series

Volume Seven

NBSIR 77-1243

Performance Analysis

of the Jersey City

Total Energy Site:

Interim Report

Center for Building Technology

Institute for Applied Technology

National Bureau of Standards

Washington, D C. 20234

July 1977

o mius

MODULAR INTEGRATED UTILITY SYSTEMS

improving community utility services

• supplying electricity, heating, cooling,

and water • processing liquid and solid wastes • conserving energy and

natural resources • minimizing

environmental impact

Prepared for Department of Housing and Urban Development

Division of Energy, Building Technology and Standards

Office of Policy Development and Research

Washington, D.C. 20410

NBSIR 77-1243

PERFORMANCE ANALYSIS OF THE

JERSEY CITY TOTAL ENERGY SITE:

INTERIM REPORT

John Hebrank

Charles W. Hurley

John D. Ryan

William Obright

William Rippey

Center for Building Technology

Institute for Applied Technology

National Bureau of Standards

Washington, D.C. 20234

July 1977

Prepared for Division of Energy, Building Technology and Standards

Office of Policy Development and Research

Department of Housing and Urban Development

Washington, D. C. 20410

U S. DEPARTMENT OF COMMERCE, Juanita M. Kreps, Secretary

Dr. Sidney Harman, Under Secretary

Jordan J. Baruch, Assistant Secretary for Science and Technology

NATIONAL BUREAU OF STANDARDS, Ernest Ambler, Acting Director
.
Table of Contents

Page

Abstract 1

Executive Summary 3

1 .0 Introduction 6

1.1 Site Description 7 1.2 Total Energy Plant Description 7 1.3' NBS Instrumentation and Data 9

Acquisition System

2.0 Engineering Data 23

2.1 Definition of Engineering Variables 23

2.1.1 Electrical Energy Variables 23

2.1.2 Thermal Energy Variables 24

2.1.3 Fuel Variables 26

2.1.4 Efficiencies 28

2.2 Plant Performance Data 29

2.2.1 Engineering Data 29

2.2.2 Accuracy of Engineering Data 30

2. 2. 2.1 Sources of Uncertainty 30

2. 2. 2. 2 Confirmation of Data Accuracy 33

2.3 Profiles of Typical Daily Electrical and 36

Thermal Demands

2.3.1 Plant Profiles 36

2.3.2 Site Building Profiles 37

3.0 Economic Data Summary 50

3.1 Operation and Maintenance Cost Data 51

3.1.1 Cost Collection Methodology 51

3.1.2 Prorated Expenses 52

3.1.3 Subsystem Cost Separation 54

3.1.4 Cost Categories 54

3.2 Capital and Owning Cost Data 55

3.2.1 Capital Equipment Costs 55

3.2.2 Owning Costs 58

3.2.3 Subsystem Cost Separation 59

i
Table of Contents (continued)

Page

4.0 Engineering Factors Influencing the Plant's 68

Energy Effectiveness

4.1 Idle Boilers 69

4.2 Idle Engines 70

4.3 Dry Cooler Losses 71

4.4 Air Conditioning of the CEB 73

4.5 Malfunctioning of Chillers 74

4.6 Summary 76

5.0 Preliminary Energy Comparative Analysis ’ 83

5.1 Description of Comparative Systems 84

5.1.1 JCTE System 84

5.1.2 Modified JCTE System 86

5.1.3 JC System Using Purchased Electric Power 87

and Central Absorption Chillers

5.1.4 JC System Using Purchased Electric Power 88

and Central Electric Compression Chillers

5.2 Comparative Results 89

6.0

Unit Energy Cost and Preliminary Cost Comparison 93

6.1 Need for Cost Separation 93

6.2 Cost Separation Methodology 95

6.2.1 Heat Recovery from Engines 95

6.2.2 Other Intersubsystem Energy Transfers 99

6.2.3 Cost Separation Formulation 100

6.3 Unit Cost of Site Energy - JCTE 103

6.4 Comparative Unit Cost of Utility-Supplied 107

Electrical Energy

6.4.1 Electric Rate Structures 107

6.4.2 Purchased Electric Energy Cost 108

6.4.3 On-Site Costs 109

6.5 Comparative Cost of Conventional Heating and 110

Cool ing

6.6 Preliminary Comparison of Unit Costs 112

6.6.1 Electrical Energy Costs 112

6.6.2 Heating & Cooling Energy Costs 112

ii
Table of Contents (continued)

Page

6.7 Some Factors Influencing Unit Costs 114

6.7.1 Site Occupancy 114

6.7.2 Chiller Operation 115

6.7.3 Heat Recovery from Engine-Generators 116

6.7.4 Plant Cooling 117

6.7.5 Miscellaneous Reductions in Losses 118

7.0

Reliability and Maintenance 131

7.1 Electric Service Reliability 131

7.2 Equipment Maintenance and Reliability 134

Acknowledgement 137

Appendix I Engineering Monthly Data Summaries 138

Appendix II Economic Monthly Data Summaries 152

Appendix III Boiler Fuel Consumption Model 165

References 1 69

iii

ABSTRACT

Under the sponsorship of the Department of Housing and Urban Development

(HUD), the National Bureau of Standards (NBS) has gathered engineering

and economic data from an operating diesel total energy plant which

supplies all electrical power, hot water, and chilled water to a 485 unit apartment/commercial building complex in Jersey City, New

Jersey.

Engineering data has been continuously collected since April 1975 by a data acquisition system (DAS) which monitors approximately 200 sensors located in the plant and site buildings. In this report, data for a one-year period from November 1975 through October 1976 is presented.

Electrical and thermal demands by the site and plant equipment

efficiencies have been determined from this data and are reported.

Reliability data is also reported.

Relative fuel savings by the total energy plant have been determined

from the engineering data. Adjustments were performed to compensate

for the malfunctioning a-bsorption chillers. Calculations indicate that an alternative conventional central plant using purchased electrical power,

oil-fired boilers, and absorption chillers would have required 17.3% more fuel than required by the JCTE plant as adjusted. These savings

correspond to 160,000 gallons (606 m ) of fuel oil annually. Minor

design modifications are suggested in this report which would improve

the JCTE plant performance an additional 5.7%. If the JCTE plant

chillers were properly adjusted and the suggested minor modifications

were performed, the above alternative conventional plant would have

consumed 24.5% more fuel oil annually.

Economic data describing the capital, operating, owning, and maintenance

costs during the one-year period are also presented. Unit costs of

electrical, heating and cooling energy commodities are determined and

compared to conventionally - supplied energy unit costs.

1
• : ?$; t '
Executive Summary

This is an executive summary of the major results contained in

the document: Performance Analysis of the Jersey City Total Energy

Site: Interim Report , HUD Utilities Demonstration Series Volume 7,

NBSIR 77-1243.

The Jersey City total energy plant consists of five diesel

engine-generators with jacket and exhaust heat recovery, two hot-water

boilers, and two absorption chillers. The plant supplies all electrical

power, hot water, and chilled water through an underground distribution

system to four medium- and high-rise apartment buildings (485 apartments

total), a 46,000 square foot (4300 nr) commercial building, a school,

and an outdoor pool. The installed plant has an electrical capacity

of 3000 kW with 9.3 MBtu per hour (2.7 MW) heat recovery capacity, a boiler capacity of 26.8 MBtu per hour (8 MW), and a chilling capacity

of 1092 tons (3.8 MW).

During the reported period (November 1975 through October 1976)

the plant supplied a total of 6,360,000 kWh of electrical energy,

37,400 MBtu (39400 GJ) of heating, and 7,740 MBtu (8160 GJ) of chilling

to the site and distribution system. During this period, the plant

consumed a total of 986,000 gallons (3730 m

3

) of fuel oil. Heat

recovered from the engines was used to meet 39% of the site and chiller

heat demands. During this year, peak engine-generator, boiler, and

chiller output levels were 1350 kW, 14 MBtu per hour (4.1 MW) and

6 MBtu per hour (1.8 MW); or 45%, 52%, and 46% of installed capacity,

respectively. Engine-generator gross electrical efficiency was 32.4%;

and gross electrical plus thermal efficiency was 61.4%. Seasonal

average boiler efficiency was 81.6% and chiller COP was measured as 0.40. The losses of the site distribution systems were not studied.

*MBtu = million Btu

3
Analysis of the plant's electrical reliability indicated that the

plant supplied power to the site for 99.8% of the reported year.

Outages were mostly due to malfunctions in the plant's electrical

control systems.

A preliminary comparative energy analysis between the plant and

two alternative conventional central plants indicates that a central

plant using purchased electrical power, oil-fired boilers, and

absorption chillers would have required 17.3% more fuel oil (based

on chillers in both plants operating at 0.6 COP). This savings

corresponds to 160,000 gallons of fuel oil annually. A central plant

using purchased electrical power, oil-fired boilers, and electrical

driven compression chilling would have required 9.5% more fuel oil

than the JCTE site (assuming JCTE chiller operation at 0.6 COP).

Suggestions for improving the plant's energy effectiveness include

minor modifications such as bypassing an idle boiler, bypassing an idle engine, reducing dry cooler losses, and reducing the amount of

chilled water used to cool the plant. Implementing these minor

modifications will result in an annual fuel savings of at least 5.7%

or approximately 55,000 gallons of fuel oil. It is also suggested

that extensive servicing be applied to the absorption chillers.

Increasing the chiller COP to the manufacturers specifications will

result in an additional annual fuel savings of approximately 7% or

65,000 gallons of oil

.

During the reported year, the total plant costs included $335,000

for fuel oil, $267,000 for operation and maintenance, and $397,000 for

capital costs. Using a preliminary cost separation procedure, the unit

costs of energy consumed by the site are 3.9<t/kWh for electrical power,

9.1 $/MBtu for hot water, and 38.87 $/MBtu for chilled water. A

preliminary analysis indicates that these unit costs are approximately

equal to the cost of equivalent energy services if supplied by conventional

means. Significant impacts on these unit costs appears to have been

experienced due to partial site occupancy, low chiller performance, use

of chilled water for plant cooling and unoptimized heat recovery.

4
The vast majority of the reported engineering data was collected

by a data acquisition system which monitors approximately 200 transducers

at the site. The raw data from the site was processed by computer at

NBS. For the annual period the accuracy of the electrical, thermal,

and fuel data presented in this report is approximately 1% to 3%.

In the main report, for reasons described in the respective

sections, some of the monthly values have uncertainties as high as

15%.

5
Performance Analysis of the Jersey City

Total Energy Site: Interim Report

1 .0 Introduction

The amount Of waste heat normally produced during the generation

of electrical power, and the potential conservation of energy which

would result from the recovery and use of that heat, is widely

recognized. Today, in even the most efficient electrical generation

systems, only 40% or less of the energy in the consumed coal, oil,

or natural gas is converted to electricity. The remaining 60% of

the input energy is usually rejected into the environment as waste

heat.

The total energy concept proposes to make use of the waste heat

associated with the electrical generation process. This heat can

be used to heat buildings and to power absorption chillers for

cooling. The use of this waste heat for heating and cooling conserves

the additional conventional energy which would otherwise be used to

meet these needs. Of course, the total energy concept requires that

electrical generation be located sufficiently near the point of use

of its waste heat; this encourages the application of on-site electrical

generation systems.

The Department of Housing and Urban Development (HUD) has sponsored

the Jersey City Total Energy Plant to test the potential effectiveness

(energy savings, economics, reliability, etc.) of a total energy system

in a building complex. Here, six residential and commercial buildings

located in an urban environment are being supplied with all electrical

energy, heating, and cooling by a central diesel total energy plant.

This plant has five 600 kW diesel engine-generators with waste heat

recovery, two 546 ton (1.9 MW) absorption chillers, and two 400 HP

(3.9 MW) fire tube boilers. Extensive engineering and economic data

is being continually collected by the National Bureau of Standards

(NBS) to determine the energy savings, costs, reliability, and

environmental impact of this system.

6
In this interim report, engineering and economic data covering

one year from November 1975 through October 1976 is presented. This

data includes energy production and consumption by the plant; capital,

operation and maintenance costs, and plant reliability. Engineering

and economic analysis is performed to determine the plant's energy

savings, the unit costs of electrical power, heating, and cooling,

and the potential for further improving the plant's energy effectiveness.

1 .1 Site Description

The 6.35 acre (2.6 hectare) site has four medium- and high-rise

apartment buildings housing thirteen hundred people in 485 apartments,

an elementary school, a swimming pool, a 46,000 ft (4300 m ) commercial building, parking space for tenants, and the total energy

plant that supplies all heating, domestic hot water, air conditioning,

and electrical energy to the buildings. Figure 1-1 shows an aerial view

of the site. Individual buildings are identified by the layout diagram

in figure 1-2.

The residential buildings were designed by three companies

participating in HUD's Operation Breakthrough: Shelley Systems, Camci

Inc., and Descon-Concordia Systems; utilizing the concept of prefabricated

modules. Occupancy of the residential buildings started in March of

1974. The residential area was 96% occupied by October, 1974. The

first commercial tenant moved into a storefront in October 1975, and

the first school session was held in September, 1976.

1 .2 Total Energy Plant Description

The main focus of the energy study at Jersey City is the total

energy plant which produces all electricity, hot water, and chilled

water for the site buildings.

7
The plant is housed in a three-story central equipment building

(figure 1-3). Electrical power is generated by five 600 kW diesel enginegenerators (figures 1-4 and 1-5). Thermal energy for space heating

and domestic hot water production is recovered from the jackets of the

engines and from heat exchangers on their exhausts. Supplementary thermal

energy is supplied by two 13.4 MBtu per hour (4.0 MW) hot-water

boilers (figure 1-6). During the air-conditioning season, the

thermal energy is used in two 546 ton (6.6 MBtu per hour) (1.9 MW)

absorption chillers (figure 1-7) to produce chilled water. The engines

and boilers both burn number 2 fuel oil which is stored in three

25,000 gallon (95 m ) underground tanks. The total energy plant is

completely automatic, allowing unattended overnight and weekend

operation. The plant is operated by Gamze-Korobkin-Caloger, Inc.,

Chicago, Illinois, under contract to HUD.

Heat is recovered from the engine-generators and utilized by a primary hot water (PHW) loop (see figure 1-8). Primary hot water at

a temperature ranging from 180°F to 230°F (82°C to 110°C) is pumped at

a rate of 11000 pounds (5000 kg) per minute, transferring heat from

the engines and boilers to the chillers and site hot water system.

From the engines, the PHW passes through two 25 HP (19 kW) circulation

pumps and then through the boilers where additional heat can be added

if necessary. During the summer the PHW is routed through two 546 ton

(1.9 MW) absorption chillers which provide 45°F (7°C) chilled water

for the site. The PHW then passes through two water-to-water heat

exchangers transferring heat to the site secondary hot water system.

In the rare event that both heating and cooling demands are extremely

low, a forced circulation, dry surface heat exchanger (dry coolers)

(figure 1-9) releases the excess PHW heat to the atmosphere to control

the upper limit of the PHW temperature.

Electricity, hot water, and chilled water are delivered to the

site via underground conduits. Two sets of 480 volt, three-phase

feeders (normal and essential) are used for electric power distribution.

In the event of an electrical plant outage, power is automatically

8
supplied only to the essential feeder from the local utility to

preserve operation of emergency lighting, fire protection systems

and the elevators. Hot and chilled water are circulated by a four-pipe

system (hot water supply and return and chilled water supply and

return). Heat exchangers in the buildings transfer heat to and from

building loops designed for space heating and cooling and domestic

hot water production.

The site is also equipped with a pneumatic trash collection system

(PTC) which pulls trash from the site buildings into a single,

compactor- type receptacle located in the central equipment building.

1 .3 NBS Instrumentation and Data Acquisition System

Evaluation of the performance of the total energy plant and its

components and determination of building utility loads is being

accomplished by analyzing data from approximately 200 transducers

located in the plant and site buildings. These specialized transducers

translate physical variables into analog voltages that are sampled and

recorded electronically. The Data Acquisition System (DAS) (see figure

1-10) is the engineering tool that accomplishes the task of recording

measurements on a 24-hour, year-round basis, at time intervals short enough

to reflect changes in plant status and to accurately measure changing

physical quantities.

The instrumentation consists of a variety of transducers which measure thermal and electrical variables. Water and fuel flow measurements

are made by turbine meters with integrating circuitry or by venturis

with differential pressure cells. Temperatures are measured by copper/

constantan or iron/constantan thermocouples; temperature differentials

are measured more accurately by multi junction thermopiles. Potential

and current transformers placed on electrical buses feed signals to

watt transducers and Voltage transducers. The DC output of the watt

transducer can be amplified for use as an instantaneous power signal

and integrated over time to obtain kilowatt-hour data. Pressure

9
cells generate a signal proportional to gage pressure. Other signals

include 7 weather station signals, plant electrical frequency, main bus

power factor, and the utilility system voltage.

Signal lines from plant transducers directly feed DAS scanning

equipment. This equipment selects one line at a time to feed the system

digital voltmeter. Each of the 8 remote stations in site buildings

have relays controlled by the central DAS. These relays select each

remote transducer signal to be sampled by the DAS. A system time clock

initiates data scans at five minute intervals. In the scan mode, the

DAS selects data channels sequentially. The digital voltmeter digitizes

the analog voltages which are then written with their respective channel

numbers (in EBCDIC code) on an incremental 9-track tape drive. Data

scans occur every 5 minutes and include approximately 130 channels in

the central equipment building plus 13 sub-channels in each of 8 remote

buildings. The entire data scanning process occurs in 30 seconds.

A ten inch (25.4 cm) diameter tape reel will hold 2 weeks of raw data.

The DAS began monitoring and recording plant data in April, 1975.

The first remote building data was recorded in November 1975 from the

Shelley A high-rise building. The remaining buildings have been brought

on line according to building construction and equipment calibration

schedules

.

The DAS functioned continuously during the reported year. With

the exception of a one month period in July, all data losses have

been less than one week in duration and cumulatively equal to less

than 11% of the year. The July data loss resulted from high

temperatures in the DAS operating room. To correct this problem an auxiliary air conditioning unit was installed in the DAS room.

10
The accuracy of the instrumentation system transducers has, for

the most part, met design goals. Where instrumentation system inaccuracies

have been detected, prompt action has been taken to correct the problem.

For example, analysis of engine 1 and engine 2 heat recovery data

showed a discrepancy equivalent to a 1 .4°F (.8°C) temperature measurement

error. Laboratory experiments indicated that this error was caused by

inadequate insulation of the thermopile leads. This problem was corrected by insulating the exposed leads and thermocouple wells.

The most serious instrumentation problem has been that of

inaccuracies in the fuel measurement system. Fuel for engine and boiler

consumption is supplied from day-tanks in continuously circulating, high

flow rate, supply/return loops. Turbine meters were used to measure

supply and return loops of 2 individual engines, all engines as a group,

and the individual boilers. Consumption was calculated by subtracting

return from supply. However, because the flow rates in the fuel supply/

return loops were 5 to 20 times the fuel consumption rates, the

measurement tolerances of the precisely calibrated flow meters (+1%)

resulted in unacceptably, large uncertainties in the fuel consumption

measurements.

As a temporary measure to obtain accurate monthly fuel data,

manually-read flow meters were placed in day-tank filler lines in

April 1976. To permit electronic fuel consumption logging for the

individual units by the DAS, special Pel ton-wheel type turbine meters

have been purchased and calibrated, and are being placed in supply lines

to each engine's fuel injectors and to each boiler's fuel nozzle. A

forthcoming report will describe the instrumentation system, problem

areas and modifications in more detail.

Reels of magnetic tape containing DAS recorded data are sent from

the site to NBS for data processing. The recorded data is converted

into engineering quantities, e.g., kilowatt-hours, Btu's, etc., by a unique configuration of computer hardware and software developed and

assembled by NBS. The computer system used for data processing consists

11
of a central processing unit with 32k of core memory and two disk memories,

7 and 9 track tape drives, cathode ray tube (CRT) visual read out

equipped with hard copy unit, paper tape punch and reader, and a teletype terminal.

Data processing starts by reading a raw data tape from the 9 track

DAS tape unit one five minute scan at a time. For each 5-minute scan, the

software checks each data channel for parity errors, dropped bits,

partial scans and other irregularities that may occur during data

logging, then the approximately 200 data channel voltages are converted

to engineering quantities. Twelve 5-minute scan values are accumulated to

yield a single hourly data point for each channel. All hourly channel

values are written on a single monthly disk, along with calculated daily

and monthly averages. The last processing step calculates the engineering

quantities for each hour of a month, e.g., heat recovered from flow times

delta temperature or site kWh from gross kWh minus plant kWh, according

to equations describing plant component and gross plant and building

status

.

Versatile data output routines have been developed which permit

easy access to the site data contained on a monthly disk. These routines

can present hourly, daily, or monthly averages of any variables in tabular

or graphical form. The graphical output routines will plot up to five

variables on any time scale from one day to the entire month.

The entire data acquisition and processing system from site

transducers to the computer output software has been designed by NBS.

Much of the hardware and software involved has been specially developed

for this project and, as with any "first-time system", some debugging

has been necessary. Because of this necessary debugging, data has

not been presented here for the first six months of DAS operation.

Instead a complete one year period of reliable data has been presented

in this interim report. It is anticipated that a future report will

contain data for a longer period of time as well as a more complete

description and analysis of site operation.

12
Figure 1-1 Aerial view of the Jersey City Total Energy Site.

See Figure 1-2 to identify the buildings at the

Total Energy Site.

13
Commercial

N

Dotted line indicates

site boundaries

T3>

I—

t

PQ

-O

0)

•o

0

1

o | School 1,

<3S']

(U in

cu3s

<<

Newark Avenue

Figure 1-2 Relative location of individual buildings at the

Jersey City Total Energy Site.

14

Summit
Figure 1-3 Central Equipment Building which houses the Total

Energy Plant. The five engine-generators are located

just inside the six sets of doors. The central tower

houses the cooling towers. Ventilation air for

the plant is supplied through the central grill.

15
Figure 1-4 One of the five 600 kW diesel engine-generator sets. The

inclined pipe above the cylinder heads returns primary

hot water from the engine jacket.

16
Figure 1-5 The bank of five engine-generators. Flexible conduits

carry 3 phase 4 wire feeders from each generator to a common 480 volt bus. The exhaust heat exchangers are visible in the upper portion of the picture.

17
Figure 1-6 The two 13.4 MBTU per hour (3.9 MW) fire tube, hot

water boilers. The heat from these boilers supplements

the recovered engine heat to meet site hot water and

absorption chiller demands.

18
Figure 1-7 The two 546 ton (1.9 MW) absorption chillers which

use primary hot water loop heat to produce chilled

water for the site and plant air conditioning.

19
ELECTRIC

POWER

TO

PLANT

AND

SITE

t

ui

Ul3

Sfe

20

Figure

1-8

Schematic

of

the

primary

hot

water

loop.

The

PHW

loop

transfers

thermal

energy

recovered

from

the

engines

and

boilers

to

the

site

secondary

hot

water

system

and

to

the

two

absorption

chillers.
Figure 1-9 The plant roof showing the dry coolers. The eight

fan unit can release primary hot water loop heat to

the atmosphere. The other dry cooler unit (ten fans)

controls the temperature of water used to cool the

engine lubrication oil.

21
Figure 1-10 The Data Acquisition System (DAS) which records

approximately 200 variables in 30 seconds every five minutes . J

22
2.0

Engineering Data

In this section, engineering data recorded at the site Is reported.

This data describes both the energy production and consumption by

the plant and site energy demands. Integrated monthly values

and typical load patterns are presented. The integrated data covers

one complete year of operation from November 1975 through October

1976. A full year's data is required for a complete seasonal evaluation

of the total energy plant. This twelve month period was selected

because it represents the first full year of adequate data collection

for analysis. Data prior to November 1975 was used primarily to

check out the instrumentation system. All data collection is

continuing and will be presented in subsequent reports.

2.1 Definition of Engineering Variables

The engineering variables that are reported in this section describe

the major flows of electrical, thermal and fuel energies in the plant and to

the site. Also these variables are used to determine the efficiencies

and coefficient of performance (COP) of major plant components. Figure 2-1

is a schematic of the major energy flows in the plant; the reported

variables are marked on the schematic. Each of these variables and its

measurement is described in this section.

2.1.1 Electrical Energy Variables

Four electrical energy variables are reported:

° gross electrical energy generated

0 electrical energy consumed by site and PTC

° electrical energy consumed by heating, ventilating and

cooling (HVAC) equipment in the plant

° net electrical energy required by site, PTC and HVAC

processing

The definition and measurement of these terms follows.

Gross Generated is the total electrical energy produced by the

23
generators. This measurement is made by both a DAS transducer and a kilowatt-hour meter connected to the main bus from the generators.

Site consumption including PTC reports the electrical energy

distributed to the site buildings (not including the CEB) by the normal

and essential feeders plus the energy used by the pneumatic trash

collector (PTC) exhauster. The electrical energy consumption by the PTC

is relatively constant from month to month, averaging approximately 3500

kilowatt-hours per month. Electrical power data is measured by DAS

transducers

.

HVAC processing in plant reports the electrical energy required to

operate the boilers, the chillers and their auxiliary equipment (including

the condenser water cooling towers), the secondary loop hot and chilled

water circulation pumps, and the HVAC plant lighting. This data is

determined by periodic manual measurements of electrical power consumption

of these components and by the hours of operation for each component.

The operating hours for each component are determined by computer analysis

of DAS data related to each piece of equipment.

Net electrical energy required by the site, PTC and HVAC processing

in plant reports the electrical energy which would be purchased if

the engine-generators were not used. The net electrical energy is

determined by summing the measured site electrical consumption, the

measured PTC consumption, and the computed electrical energy required

for HVAC processing in plant. The difference between net and gross

electrical energy is approximately equal to the electrical energy required

by the engine-room exhaust fans, the primary loop pumps, the engine

oil -cooler pumps, and the dry cooler fans.

2.1.2 Thermal Energy Variables

Seven thermal energy variables are reported. Five of these, heat

recovered from engines, heat added by boilers, PHW heat used by

chillers, PHW heat used to produce secondary hot water, PHW losses (input

minus output), describe the major energy flows to and from the PHW loop.

24
The two other variables, total chilled water produced and chilled water used

by site, allow determination of the chiller COP and the total site

demand. The definition of these terms follow.

Heat Recovered from Engines reports the total amount of thermal

energy added by the engine jackets and exhaust heat exchangers to the PHW

loop. This variable is calculated using DAS measurement of the total

PHW flow rate through all five engines and of the PHW temperature

differential across the entire engine bank. This variable includes

the heat added to the PHW by engines which are running less the heat

lost from the PHW by idle engines.

Heat Recovered from Boilers reports the thermal energy added by

the boilers to the PHW loop. This variable is calculated using DAS

measurement of the PHW flow rate through the boilers and of the PHW

temperature differential across the boilers. This variable includes the

heat added to the PHW by the boiler(s) which are firing less the heat lost

from the PHW by idle boiler(s).

PHW Heat Used by Chillers reports the amount of thermal energy removed

from the PHW loop by the two absorption chillers. These chillers use

PHW thermal energy to produce chilled water which is circulated in the

plant and from the plant to the site buildings. PHW heat used by the

chillers is calculated using DAS measurement of the PHW flow rate and

PHW temperature difference across the chillers.

PHW Heat Used to Produce Secondary Hot Water reports the amount of

thermal energy removed from the PHW loop by the two site heat exchangers.

The site heat exchangers transfer thermal energy from the PHW to the

secondary hot-water loops which circulate from the plant building to the

site buildings. This quantity is calculated using DAS measurement of the

PHW flow rate and the PHW temperature differential across the exchangers.

25
PHW Dry Cooler and Piping Losses reports the difference between the

thermal energy supplied to the PHW loop by the engines and boilers minus

the heat removed from the PHW loop by the site hot water heat exchangers

and by the absorption chillers. Most of this quantity represents PHW

heat removed by the dry coolers via continual convective losses and via

heat released during erratic operation of the dry cooler fan controls.

Total Cooling Load reports the total amount of thermal energy

absorbed by the chillers from the secondary chilled water system which

supplies cooling to the site buildings and to the plant. This quantity

is the total chiller output and is calculated using DAS measurements of

the secondary chilled water flow rate and temperature differentials

across the chillers.

Site Cooling Load reports the thermal energy absorbed from the

site by the secondary chilled water. This quantity is computed by

subtracting the energy absorbed by the chilled water used in the

plant from the total energy absorbed in the chilled water produced. Both

these quantities are calculated using DAS measurements of water flow

rates and temperature differentials.

2.1.3 Fuel Variables

Four fuel variables are reported: fuel consumed by engines, fuel

consumed by boilers, total fuel consumed, and heat content of fuel. The

reported fuel data from May 1976 through September 1976 is measured data

(see section 1.3). The fuel data from November 1975 through April 1976

and October 1976 was calculated using measured engine and boiler output

data along with engine and boiler efficiency models based upon the May

through September data. The calculated fuel data has been confirmed by

fuel oil delivery records (compensated for storage tank levels). The

definition and determination of fuel variables follows.

26
Fuel Consumed by Engines reports the total amount of fuel oil consumed

by the engines. For five months (May '76 - Sept. '76) this quantity was measured by a manually-read meter recording the amount of fueU which was pumped into the engine day-tanks from the underground storage tanks.

Because the fuel system maintains the day-tank level within 30 gallons,

fuel flow to the day-tank is an accurate (+1%) measurement of monthly

engine fuel consumption. Because engine operating conditions were

unchanged, monthly engine fuel consumption for the prior six months

(Nov. '75 - April '76) and October was determined using the enginegenerator electrical efficiency, 32.4%, as determined during periods of

measured fuel data and monthly gross electrical energy generated

measurements

.

Fuel Consumed by Boilers reports the total amount of fuel oil consumed

by the boilers. From May 76 to Sept. 76 this quantity was measured from

the difference between two manually-read meters: one which recorded the

total fuel pumped to both the engine and boiler day-tanks, the other

which recorded fuel pumped into the engine day-tank (the location of the

boiler day-tank lines prevented installation of direct boiler fuel

metering). For the other months, boiler fuel consumption is determined

using measurements of boiler output data and a model describing the

boiler fuel consumption based upon periods of measured data (see

appendix III). During months of mild weather the uncertainty of measured

boiler fuel data increases. For these months, boiler fuel consumption

may be only 20% of the total fuel consumption, increasing the uncertainty

of boiler fuel consumption data from 2% to 7% (see section 2.2.2).

Total Fuel Consumed reports all fuel consumed by engines and

boilers

.

Fuel Oil Heat Content reports the energy available by complete

combustion of one gallon of the plant fuel oil. The fuel oil heat content

is determined by averaging values of the fuel 's higher heating value

(HHV) reported by a testing laboratory. The testing laboratory determines

27
the heat content of samples from chemical and physical properties measured

using ASTM test procedures D1552, D874, D95, and D287. Fuel oil samples

are taken periodically from the day-tank which supplies the engines.

Both the engines and boilers use the same fuel.

2.1.4 Efficiencies

The operating efficiencies address both selected plant components

and overall plant performance. Engine electrical efficiency, engine

electrical plus thermal efficiency, boiler efficiency, and chiller

COP, describe component performances. Electrical production efficiency

and plant energy effectiveness, describe overall plant performance.

Engine-Generator Gross Electrical Efficiency is defined as the

total electrical energy produced by the generators divided by the energy

in the consumed fuel using consistent units.

Engine-Generator Gross Electrical Plus Thermal Efficiency is

defined as the total electrical energy produced plus total thermal

energy recovered from the jackets and exhaust heat exchangers divided by

by the total heat content of the consumed fuel using consistent units.

Electrical plus thermal efficiency is based upon heat recovered across

the bank of engines; losses from idle engines reduce this efficiency.

Boiler Efficiency is defined as the total thermal energy added to

the PHW by the boilers divided by the total heat content of the consumed

fuel. Because the total boiler output includes the continual losses from

the boiler(s) to their surroundings including periods when they are not

fired, the reported boiler efficiency will decrease during low output

months. The uncertainty of the boiler efficiency reflects the accuracy

of the boiler fuel measurement and may be 5% to 10% during low usage

months.

Chiller COP is defined as the total thermal energy taken from the

secondary chilled water by the chillers divided by the total thermal

energy consumed from the PHW by the chillers. The chiller COP does not

include electrical energy used by the chiller pumps, cooling tower, and

secondary chilled water loops.

28
Engine-Generator Net Heat Rate is defined as the engine-generator's

efficiency in producing the net electrical energy required by the plant

and site. This quantity is computed by dividing the total heat content

of engine fuel in Btu by the net electrical energy produced. In computing this efficiency, net electrical energy rather than total

generated electrical energy is used because the electrical energy used

to operate the electrical plant is not available to the site and HVAC

equipment. The Btu per kWh form is used because it can be directly

compared with the efficiencies of the local electrical utilities.

In 1975, the local utility at Jersey City generated and distributed

electrical energy with a point-of-use heat rate of 11,451 Btu per kWh.

This value has been calculated as follows: The 1975 published net heat

o rate for the Public Service Electric and Gas Company was 10,582 Btu

per kWh. This value was adjusted for distribution losses, by

multiplying by the ratio of "kilowatt hours produced, purchased and

interchanged (net)" to "total sales to customers".

Energy Effectiveness in Meeting Site Demands is defined for the purposes

of this report as the sum of the energy conveyed by the three plant

products; (site electric energy, site hot water, and site chilled water)

divided by the energy content of the total fuel consumed by the site.

The reported values for energy effectiveness do not include the losses

in the distribution systems between the plant and site buildings. It

should be noted that a specific definition for the energy effectiveness

of a total energy system has not been accepted by any recognized group

to date.

2.2 Plant Performance Data

2.2.1 Engineering Data

In this section the plant variables and efficiencies defined in

section 2.1 are reported for each month from November 1975 through

October 1976 and annual totals are given. Table 2-1 reports monthly

and annual electrical data, table 2-2 reports monthly and annual thermal

data, table 2-3 reports monthly and annual fuel data, and table 2-4 reports

29
monthly and annual efficiencies. A table of the monthly summaries which

were prepared for the reported period is shown in appendix I.

During the reported period (November 1975 through October 1976)

the plant supplied a total of 6,363,154 kWh of electrical energy,

37,353 MBtu (3#411 GJ) of heating, and 7,735 MBtu (8161 GJ) of chilling

to the site and distribution system. During this period, the plant

consumed a totl'l of 986,136 gallons (3733 m3) of fuel oil. Heat

recovered from the engines was used to meet 39% of the site and chiller

heat demands. Jingine-generator gross electrical efficiency was 32.4%;

and gross electrical plus thermal efficiency was 61.4%. Average boiler

efficiency was 81.6% and chiller COP was measured as 0.40.

2.2.2 Accuracy of Engineering Data

Confirmation of the accuracy of the engineering data presented

in section 2.2.1 is important for assessing the accuracy of the

Jersey City Total Energy performance evaluations. In this section,

the factors which influence the accuracy of this data are examined

and an analysis is performed which establishes the accuracy of the

engineering data submitted in this report.

2. 2. 2.1 Sources of Uncertainty

The reported engineering data include electrical energy data,

hot- and chilled-water thermal energy data and fuel quantity data.

The major factors that affect the uncertainties of the monthly

engineering quantities are the accuracies of various transducers used

for measurement and the number of hours of acceptable data recorded in

a particular month. In the case of electrical energy data, such as total generated or site consumption, measurements are performed by one

or more Hall -effect wattmeters with hardware integrators. These individual

devices and their associated circuitry have end-to-end uncertainties of

less than 1%.

30
Thermal energy data (such as heat recovered from engines, heat

produced by boilers, heat sent to the site, heat consumed by chillers,

and chilled water sent to the site) require at least one pair of

temperature measurements and one flow measurement for each piece of

data. Some data require several flow and temperature measurements.

Uncertainty of a pair of thermocouple and thermopile temperature

measurements has been less than 0.1°F for pairs in which both measurement

locations experienced similar ambient conditions. These extreme

accuracies are required because of the low temperature differentials

which must be measured. For example, in the primary loop a 0.1 °F

measurement error across the bank of engines will result’in an error in

the monthly heat recovery data of 2% (50 MBtu). A typical flow

measurement is made by a venturi in conjunction with a differential pressure

cell. Despite problems associated with the primary water fouling the

pressure cells, frequent cleaning and calibration has maintained the

uncertainties below 1.5% based on an assumed accuracy in the venturi

and maximum observed drift in the differential pressure cells.

Considering that the specific heat of the plant water is also uncertain

(+1%), the cumulative accuracy of individual thermal data involving

one pair of temperature measurements and one flow measurement is:

2SPECIFIC HEAT

= \/(.l/AT) 2 + (.015)

2 + (,01)

2

where aT is the mean differential temperature measured. Assuming

a typical AT of 5° to 10°F, the typical thermal data uncertainty is

2.7% to 2.1%.

31
Both thermal and electrical monthly data are also affected by DAS

malfunctions which results in blank data periods. For the most part

these periods have been short, however, one period extended from

July 3, 1976 through August 3, 1976. Figure 2-2 charts the hours of

available data for the 12-month period. Compensating for data losses

is frequently complicated and reduced in accuracy because environmental

extremes such as temperature or line voltage variations may trigger

a DAS malfunction. Summaries for periods which include DAS malfunctions

during plant or environmental extremes may have increased uncertainty.

For instance, on August 4, 1976, the plant had voltage control problems

making it necessary to shut off the boilers. The line voltage variations

also resulted in a DAS malfunction so that for the 24 hour period of

unpredictable plant conditions, data was unavailable. As a result the

uncertainty of the August data was increased.

Longer DAS outages may result in noticeable discrepancies between

DAS corrected data and continuously recorded manual fuel data. For

example, because of the long July DAS outage, the monthly thermal data

was based on only several days of the month, whereas fuel data was being

continuously recorded for the entire month. Because boiler output

data was based on only a few days while fuel consumption data covered

the entire month the resulting July boiler efficiency was

77% whereas June boiler efficiency was 80%. The reported August boiler

efficiency is also somewhat affected by this DAS outage.

Fuel consumption data (including fuel consumed by engines, fuel

consumed by boilers, and total fuel consumed) was measured by two

manually-read fuel meters for the last six months of the reported

period. These meters have uncertainties of approximately 1%. One

meter measures total fuel and the other meter measures engine fuel.

*Regarding the problems involving fuel measurement, several items should be

noted. First, the manually read meters were installed as a temporary

method oi overcoming the problems of the original supply/return measurement

system previously described. Second, the method of installation of these

temporary meters was dictated by the physical layout of the plumbing in

the plant. And third, the new individual component metering system now

being designed which will directly measure the fuel consumption of each

component via an individual channel to the DAS, will greatly reduce the

uncertainties of the fuel consumption measurements.

32
Boiler fuel consumption is determined from the difference between the

total and engine fuel data. The boiler fuel measurement uncertainty

varies according to the magnitude of boiler fuel consumption. For

periods when boiler consumption equals engine consumption, as in the

month of January, the measurement uncertainty is 2%. However, for

periods of mild weather, boiler consumption may be one-quarter to

one-tenth engine consumption and the boiler measurement uncertainty

becomes 6% to 15%.

The accuracy of monthly fuel allocations may be affected by the dates

of the manual meter readings. Work schedules frequently cause meter

readings to be made several days before and after the ends of the months

so that monthly fuel data may have to be manually divided between months.

If weather conditions shift near the end of such a month, uncertainties

may result. For example, in one extreme case involving sickness, fuel

measurements for September were not taken on scheduled dates but were

only taken on September 1, 17 and October 8. Also the chillers had

major adjustments on September 21, so that the extrapolation of

exact boiler and total fuel consumption for the entire month of September

is uncertain. For October fuel data is not directly available due to a week of missing fuel data in mid October when the fuel meters were inadvertently bypassed by the plant engineer.

2. 2. 2. 2 Confirmation of Data Accuracy

The accuracy of the most important monthly data can be verified

through independent DAS measurements and plant log information.

The accuracy of thermal energy data for the primary loop including

engine heat recovery, boiler heat production, chiller heat consumption,

site heat consumption and dry cooler heat removal can be assessed by

summing the monthly figures for energy supplied to and consumed from

the primary loop. Performing the computation for the last six months

of data indicates a monthly RMS difference of 4% relative to the mean

33
engine heat recovered. A second method of assessing primary loop

accuracy involves comparison of measurements of heat supplied to and

extracted from the site heat exchangers. This comparison indicates

a monthly RMS difference of 5% which suggests the primary measurement

uncertainty was 5%/\/T or 3.6%. These two results suggest that uncertainty

of the monthly thermal energy data due to instrumentation inaccuracies

is approximately 4%.

Uncertainty of monthly electrical data can be determined by

comparison of gross electrical energy generated as measured by the

DAS with the plant engineer's manual readings of a kilowatt-hour

meter. This comparison over the entire 12 month period indicates a RMS difference of 2.7% between the DAS data and the meter data. Recent

calibration of the DAS kilowatt-hour transducer indicates that this

difference is mostly the result of an incorrect DAS transducer setting.

The monthly values of gross generated electrical power reported in

section 2.2.1 are based upon the kilowatt-hour meter data.

Uncertainty of monthly fuel data can be evaluated by comparison

of the annual total fuel data in section 2.2.1 with the sum of the plant

fuel delivery records during the reported period and storage tank levels

on November 1, 1975 and November 1, 1976. Delivery records indicate

that a total of 958,251 gallons of fuel oil were delivered during

the reported period. On November 1, 1975, plant records indicate

that 56,700 +1000 gallons of fuel oil were in the three storage

tanks. On November 1, 1976, there were 32,100 +3000 gallons of

fuel oil in the storage tanks. Thus, total fuel consumption for the

reported period was 983,000 +4000 gallons.

The monthly fuel data reported in section 2.2.1 is based upon 5 months

of fuel oil data from the manually-read meters and 7 months of fuel

oil projections based upon monthly generator output and boiler output

data and engine-generator and boiler efficiency models determined from

periods during the five months of measured fuel data. Summation of the

five months of measured fuel data and seven months of projected fuel

34
data indicate an annual fuel consumption of 986,136 gallons. The

difference between the fuel data determined from delivery and storage

tank records and the fuel data computed from the monthly data is 0.3%

for the year.

The actual engine fuel uncertainty can be evaluated by comparison

of the engine-generators electrical efficiency with the electrical

efficiencies measured during the factory acceptance tests as reported

in a separate document! In that document the electrical efficiency

measured at 60% load was 31.1%. For the year reported herein, the electrical

load averaged approximately 60% and the electrical efficiency averaged

32.4%. This figure is 1.3 percentage points or 4% above the efficiency

observed during the factory tests, however, it is generally accepted that

diesel engines tend to increase in efficiency several percent after they

have "run-in" for several thousand hours. Thus, the engine fuel uncertainty

is probably in the range of 1% to 2%.

The boiler fuel uncertainty can be evaluated from the manufacturer's

"typical performance" data describing the boilers or from the uncertainties

of the total and engine fuel consumptions as described in the preceeding

two paragraphs. As described in appendix III, a model of the boiler's

performance based on the measured boiler performance has been produced.

This model agrees with the manufacturers "typical performance" within

1% suggesting an uncertainty of approximately 1%. A back-up analysis

based upon uncertainties of total and annual fuel can be performed.

Total annual fuel data has an uncertainty of approximately 1%, engine

fuel uncertainty is less than 4%, and boiler fuel consumption is

approximately one-third of the total annual fuel consumption;

suggesting a boiler fuel uncertainty less than 8%. As mentioned in

section 2. 2. 2.1, the uncertainty of boiler fuel data for individual

months is greater than the uncertainty for longer periods due to the

problems involved in manual fuel meter readings. Uncertainty of monthly

boiler efficiency data is likewise affected by this factor and by the

thermal data uncertainties, so that individual months boiler efficiency

data has uncertainties in the range of 10%.

35
It should be emphasized that the uncertainty of the annual reported

boiler efficiency as computed from total annual fuel consumption is

less than 8% and more likely in the range of 1% to 2%.

In summary, the accuracy of annual electrical and thermal data

is approximately 1% to 3%. Some monthly data are less accurate and as described, the uncertainties range as high as 15%.

2.3 Profiles of Typical Daily Electrical and Thermal Demands

2.3.1 Plant Profiles

The rate of engine heat recovery is proportional to engine-generator

electrical load, and because of this, a good match between electrical and

thermal demands is important for effective total energy plant operation.

The thermal and electrical site demands served by the plant vary during

each day. In this section examples of these daily thermal and electrical

load profiles are shown. The four, four-day periods used in this section were selected as typical, examples for each of the four seasons.

Figure 2-3 illustrates the typical site, HVAC, and total electrical

demands for each of the four seasons. Note that the site demand follows

a fairly consistent diurnal cycle from a peak near 900 kW in the evening

to a low near 500 kW before dawn. The mean daily site electrical demand

is approximately constant year round. In contrast, the plant HVAC

electrical demand is diurnal ly unvarying, but varies from approximately

300 kW in summer to 100 kW in fall, winter, and spring. The increased summer demand is due to the absorption chiller pumps, their condenser

water cooling towers, and other associated pumps.

Site thermal demands also show large variations (see figure 2-4).

Because thermal demands are based more upon the weather than upon the

cumulative habits of the site occupants, the site thermal demands have

a diurnal profile which is much less regular than the diurnal electrical

demand profile. (One thermal demand which exhibits a regular diurnal

36
cycle is the hot water demand. This can be seen in summer when occupant

domestic hot water demand is the only site hot water demand.) Section

2.3.2 more fully describes individual building demands.

The site thermal demands are met through the hot-water heat exchangers

and the chillers which draw heat from the primary loop according to

the site hot and chilled water thermal demands. In figure 2-5, the

PHW thermal demands resulting from the site hot and chilled water

demands are plotted along with the rate of engine heat recovery.

Note that in summer, the chiller PHW demands are similar to the winter

site hot water demands; and that in spring and fall, heat recovered

from the engines is approximately equal to PHW demands from the site.

Examination of all the spring and fall data indicates that rarely

do PHW thermal demands fall below the rate of engine heat recovery.

Never during the year reported here did the dry coolers have to

release PHW heat due to very low site thermal demands.

Inspection of profile data for the entire reported year was used

to establish peak engine-generator, boiler, and chiller loads. Peak

engine-generator load was 1350 kW or 45% of installed capacity. Peak

boiler load was 14 MBtu per hour (4.1 MW) or 52% of installed capacity.

Peak chiller load was 6 MBtu per hour (1.8 MW) or 46% of installed

capacity.

2.3.2 Site Building Profiles

Extensive data describing the electrical energy used for normal

and for essential services, the thermal energy used for space heating

and for domestic hot water production, and the thermal energy absorbed

for space cooling are monitored by the DAS for all site buildings which

utilize these services.

37
These data are available as hourly profile data or as integrated

daily or monthly values. However, because the building instrumentation

systems have just recently been brought on line and calibrated, building

demand data are not yet available for a complete year. Therefore,

building data will be presented in subsequent reports.

Figures 2-6 and 2-7 present examples of individual site buildings

electrical demand, space heating demand, space cooling demand, and

domestic hot water demand for the winter, spring, and summer seasons.

38
OPERATION

OF

OPERATION

OF

ELECTRICAL

HVAC

CC

O LU

•—i Q£ h- LU

UJ CSC LU LU

C 1— 1— 1— 12 (— 3 i—i

•—i t_)

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00 LU Q. oo h- _J O LU =c

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39

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<D szo

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Reported

integrated

variables

are

marked

(0).
AMOUNT

OF

DATA

RECORDED

%

75 75 76 76 76 76 76 76 76 76 76 76

Figure 2-2. Percentage of t otal monthly data recorded by DAS.

DAS inoperative because of failure of plant office

area cooling system.

40
ELECTRICAL

POWER

ENGINE

OUTPUT

2>

SITE

DEMAND

3-

HUAC

PROCESSING

IN

PLANT I

Figure

2-3

Typical

profiles

of

gross

electrical

power

generated

(1),

site

electrical

demand

(2),

and

HVAC

electrical

demand

(3)

for

the

four

seasons.
42

thermal

demands

for

four

seasons.
Figure

2-5

Typical

profiles

of

site

PHW

demands

(1),

chiller

PHW

demands

(2),

and

heat

added

to

the

PHW

by

the

engines

(3).
CAMCI

44

spate

cooling

(3)

thermal

demands

of

Camci

apartments

forwinter,

spring

and

summer.
TOTAL

POWER

USED

BY

45

I

Figure

2-7

Typical

electrical

demand

by

Camci

apartments

for

winter,

spring,

and

summer.
Table 2-1

Monthly and annual integrated electrical data

(kilowatt-hours)

Gross Site and HVAC plant Net required by

generated PTC 1 oad load site, PTC, and HVAC

November 1975 594800 485906 71269 557175

December 1975 654100 539589 76612 616201

January 1976 674500 536732 79411 616143

February 1976 622400 507440 70594 578034

March 1976 654500 527840 75708 603548

April 1976 607100 484335 63499 547834

May 1976 631600 488367 67094 555461

June 1976 797700 566763 186330 753093

July 1976 821100 577302 209671 786973

August 1976 851900 570811 231836 802647

September 1976 808400 546427 211095 757522

October 1976 661200 531642 77152 608794

November 1975

through

October 1976

8,379,300 6,363,154 1 ,420,271 7,783,425

46
Table

2-2

Monthly

and

annual

integrated

thermal

data

(Millions

of

Btu)

Site

**

cooling

load

47

1745 2296 2274 1269 104

7,735

Total

**

cool

ing 1

oad

54

2050 2713 2735 1536 129

9,217

PHW

dry

cooler

and

piping

losses

488 631 619 442 408 308 408 677 141 282 303 473 o00

* LO

PHW

heat

*

to

secondary

hot

water

3360 5546 6903 5158 4376 2871 1748 1144 1081 1090 1124 2952

37,353

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47

I

*

Equivalent

to

Site

Heating

Load,

Including

Distribution

System

Losses

**

Cooling

Load

Including

Distribution

System

Losses
Table 2-3

Monthly and annual integrated fuel data

(gallons)

Consumed by

engines

Consumed by

boilers

Total

consumed

Heat content

(Btu per gallon)

Nov. 1975 45324* 18340* 63664 138200

Dec. 1975 49475* 36699* 86174 139226

Jan

.

1976 50955* 49327* 100282 139400

Feb. 1976 46876* 33750* 80626 139824

Mar. 1976 49232* 25621* 74853 140000

Apr. 1976 45666* 11811* 57477 140000

May 1976 48361 5455 53816 138971

June 1976 60267 41505 101772 138364

July 1976 62824 36794 99618 138364

Aug. 1976 64586 47618 112204 138364

Sept 1976 61906 29450 91356 138200

Oct. 1976 49174* 15120* 64294 141600

Nov. 1975

through

Oct. 1976

634,646 351,490 986,136 139,100

Fuel Data Determined from Models Based Upon May 1976 to Sept. 1976

Fuel, Engine-Generator Output, and Boiler Output data. See Sections

2.1.3, 2. 2. 2. 2., and Appendix III.

48
Table

2-4

Monthly

and

annual

component

and

plant

performances

to

to

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49 I

Based

On

Fuel

Consumption

Model.

See

sections

2.1.3,

2.2.2,

appendix

III.

Data

uncertainties

because

of

DAS

outage

or

fuel

measurement

problems

impact

these

monthly

values.

See

section

2.

2.

2.1.
3.0 Economic Data Summary

The purpose of this section is to present and analyze the actual

costs as they have occurred during the 12-month period covered by this

report. The following types of costs are considered:

1. Operation and Maintenance (0 & M) costs for the 12 months.

2. Initial capital costs and capital improvements and their

equivalent annualized capital recovery.

3. Owning costs other than capital recovery (i.e. property

insurance and taxes).

Indirect revenue from providing utilities to tenants and income tax

effects are not considered.

For this interim report, the cost data are presented "as reported"

for the JCTE plant, with no modification or normalization to reflect a generic situation. (For example, any additional "overhead" costs due to

government sponsorship requirements have not been removed from the data.)

Further, no attempt is made to present a typical year or a life-cycle

cost picture. With the exception of engine-generator overhaul costs, no attempt is made to project future costs.

This section deals with direct costs only. Direct costs are the

costs associated with subsystem inputs (goods, services or capital equipment) for which actual payment is made to a supplier. These direct costs

are separated into cost components for the electrical, heating, cooling

and PTC subsystems. Indirect costs are the costs associated with transfers

of energy between subsystems within the T.E. plant and for which no actual monetary transaction is made. Indirect costs are a means of further

allocating direct costs to the subsystems so that unit costs U/kWh,

$/MBtu) can be calculated. This further allocation of costs is the subject of section 6 of this report.

50
Actual cost data for the plant have been gathered continuously:

capital costs since site construction began in November, 1971, and operation and maintenance costs since plant start-up in January, 1974. Therefore, the reported costs for the 12 months are only a portion of the cost

data base which will eventually be available for economic analysis. Collection of cost data is continuing and it is expected that four years of

data will be available for a comprehensive economic evaluation, to be

presented in future reports.

3.1 Operation and Maintenance Cost Data

3.1.1 Cost Collection Methodology

Cost data are submitted to NBS by the firm operating the plant

(Gamze-Korobkin-Caloger, Inc., Chicago, Illinois) (GKC) on a monthly

basis in the form of individual disbursements to other companies as well as charges made by themselves for operating the plant. These

data are also collated and reported to HUD by GKC in accordance with

GKC/HUD accounting procedures.

Only one 0 & M cost item is not directly reported by GKC. This is

the cost of water consumed by the plant. Water is supplied to the en- tire Summit Plaza site by the City of Jersey City and invoices rendered

to the site owner do not separately show the water consumption of the

plant. A portion of the water for the plant is separately metered by

the plant operator for maintenance reasons, but no monetary transactions

are made for the water consumed. The water is mainly for make-up purposes

in the cooling tower, the heat transfer circuits within the plant and

the site distribution systems. For this report, the total monthly

water consumption based on measurements and calculations is used along

with the appropriate city water rate to develop monthly 0 & M cost

data for this item. The rate used is for the highest incremental con- sumption category since plant use can be considered additional to the

basic residential use. This rate is $3.80 per 1000 ft^ ($0,134 per m^)

and has been in effect from March 20, 1975 to the present. The annual

51
cost for this item is quite small, 2.4% of total 0 & M costs other than

fuel

.

The monthly cost data described above include all expenditures as they occurred during the 12-month period. With the four exceptions

treated in the next paragraph, this report uses this data on individual

expenditures directly in terms of magnitude of expenditure and the

time of its occurrence during the year.

3.1.2 Prorated Expenses

Four large expenditure items occurred during the year in such a way as to substantially distort month-to-month costs if they were used

directly in terms of magnitude or time-occurrence. Three of these

expenditures (engine overhauls, lube oil and insurance) are prorated so that, for each month, a cost is incurred which is equivalent to one- twelfth of the appropriate cost for the 12-month period. The expenditure for fuel oil is based on actual monthly fuel use, which varies

from month to month. By. means of these adjustments, the monthly and

quarterly cost data in this report more accurately reflect the actual

level of plant production and maintenance in each period. The four

prorated major expense items are further described below:

1. Engine overhauls . The projected overhaul schedule in use during the 12-month period consisted of three overhauls, two

minor and one major, for each engine during a running time of

36,000 hours. This schedule meant that overhauls would occur

less than once per year for any given engine. Thus, use of

overhaul costs actually experienced during the 12 months (if

any) could significantly distort the expected cost picture for

overhauls. For this report, the total cost for this overhaul

cycle is estimated based on the actual cost of minor overhauls

performed to date and the estimated cost of a future major

overhaul provided by the overhaul contractor. The individual

cost items are not escalated for inflation nor discounted. To

52
develop monthly engine cost data, this total estimated cost Is

divided by the average number of months It Is expected to take

for an engine to reach 36,000 hours. This period Is estimated

to be 82 months.

The actual cost of overhauls experienced during the 12-month

period was $27,976. This resulted from minor overhauls on two engines. This total cost of overhauls for the 12 months

Is Increased by $8,000 to properly reflect the projected costs

for the entire overhaul cycle.

In the course of actual operation of the plant , the projected overhaul schedule may be modified and actual overhauls

may occur more frequently or less frequently than the 36,000-

hour cycle. Based on engine condition of the time of completed

minor overhauls, the plant operator is presently increasing

the period between overhauls such that only one minor and one major overhaul will be required over a 36,000 to 40,000 hour

overhaul cycle. Future economic reports will be based on the

actual overhaul schedule as this develops.

2* Lubrication Oil . Several expenditures for lube oil used in the

engine-generators were made during the period. These ex- penditures were for lube oil used prior to, during, and after

the 12 months being reported. Examination of all data collected

to date indicates that $8,400 is an appropriate yearly ex- penditure for this item. The data in this report include this

item by means of a $700 per month cost.

3. Insurance. Premium for liability insurance (for accidents

occurring in the plant) is generally paid once for an entire

year. Since this item is significant ($5,400 for the 12-

month period), the data in this report include a $450 per month

cost for this item. Month-to-month distortions in cost are thereby eliminated.

53

I
4.

Fuel Oil. Expenditures for fuel are made monthly but fuel

deliveries and invoicing can be somewhat irregular. For ex- ample, a substantial delivery can be made/bi lied on the last

day of a month for fuel which would be used in the following

month. Since fuel cost is a significant single item (56% of

total 0 & M costs), a more accurate representation of monthly

fuel costs is desired. Therefore, monthly cost data in this

report is developed from the fuel actually consumed by the

plant during the month (as measured by NBS) and the average

unit cost of fuel for the month.

3.1.3 Subsystem Direct Cost Separation

Each direct cost item is assigned to the subsystem to which it

pertains, except when a single item pertains to two or more subsystems.

For these items the cost is divided between the subsystems either

by estimation or by use of secondary data. In some cases the cost

is divided between subsystems according to an estimated fixed percentage. These percentages are estimated by the plant operator and reviewed

by NBS. In other cases, secondary data allows accurate division of

cost items between subsystems. For example, the direct expenditure for

fuel oil is charged to the electrical and heating subsystems according to

the actual fuel consumption of each, as registered by the NBS data ac- quisition system.

3.1.4 Cost Categories

After the individual monthly expenditures are assigned to the subsystems to which they belong, they are condensed into the following

categories:

1 . Fuel

2. Contract maintenance

3. Direct labor and overhead

4. Plant burden

5. Direct material

6. Miscellaneous

54
The plant burden category includes those services which are Incidental to plant operation and generally not associated with a particular

subsystem. Examples are: telephone service, insurance, standby power

and GKC operating fee.

Direct material includes non-capital operation and maintenance items

not provided by contract maintenance services. Examples are: water

treatment chemicals, lubrication oil, tools and spare parts.

The 0 & M costs for each of the four subsystems (electrical, heating,

cooling and PTC) are given in table 3-1 for each of the six cost categories for the 12-month period, November, 1975 through October, 1976. Appendix II presents 0 & M costs on a monthly basis.

Fuel cost is a significant portion of overall JCTE system costs

During the period being reported (November 1, 1975 through October 31,

1976) the price of fuel has averaged 34. U per gallon ($90.1 per m ), or $2.43 per MBtu ($2.56 per GJ). The actual as-delivered fuel costs

since plant start-up in early 1974 are shown in figure 3-1. Costs

have remained relatively stable since the initial increase resulting from

the "oil crisis" of 1974.

3.2 Capital and Owning Cost Data

Owning costs, usually including a capital recovery component, are often termed "fixed charges". These costs are fixed in that they do

not vary with plant production quantities.

3.2.1 Capital Equipment Costs

Capital equipment costs represent the initial investment as well as capital improvements and replacements during the life of the plant.

The initial investment consists of all energy and PTC equipment

external to the served buildings and is reported in the following cost
categories according to the separate construction contracts:

Engine-generators

Mechanical system

Electrical system

Distribution

Central equipment bldg.

Design fee

These actual initial costs are presented in table 3-2. These costs were incurred during plant construction which took place from November,

1971 through mid-1974. No cost is included for the cost of land occupied by the CEB.

These initial capital costs must be converted to an equivalent annual basis in order to make them comparable with the annual 0 & M cost

data. To accomplish this conversion, the initial capital costs are multiplied by the appropriate uniform capital recovery (UCR) factor.

Determination of UCR depends on the interest rate and the life span of

the plant. The interest rate depends on the viewpoint of the 12-month

analysis. The analysis can be formulated to display a typical year in

the life of the plant, thereby giving a picture of the life-cycle cost

relationship between 0 & M and capital recovery expenses. In this case

the effective or real interest rate (i.e. excluding inflation) should

be used. Alternatively, the analysis can simply present actual expenditures which have occurred during the period. In this case, the nominal

(i.e. including inflation) interest rate is appropriate. This latter

approach is used in this report. This report therefore provides actual

0 & M and capital recovery expenditures in approximately the third year

of plant operation (1976). 0 & M costs have been influenced by inflation

during the two years since plant start-up while capital recovery costs

are constant over the life of the plant.

Capital recovery costs are based on financing the plant with 100%

debt at a nominal interest rate which was typical of early 1973 when

56
the present owner purchased the entire Summit Plaza site. Industrial

and public utility A-rated bond yields were approximately 7.3% and 7.8%,

respectively, during that period. Major Insurance company financing

of Income-producing multi-family and non-residential mortgages in the same time period averaged 8.6%. Housing developers however, when

financing a partly subsidized housing project such as Summit Plaza usu- ally obtain Federally-guaranteed loans at an Interest rate less than they

could obtain under normal circumstances. For this report, an Interest

rate of 8.0% Is used in determining the UCR factor.

Electric utilities generally use a service life of 30 years

4

In

estimating capital recovery of conventional large steam generating equipment, which should outlast a diesel Total Energy facility. Also, the

minimum useful life of chillers, boilers and engines for depreciation

5 purposes is generally estimated at 20 years. Therefore the life span

of the JCTE plant for capital recovery purposes is conservatively

assumed to be 20 years. Applying a life of 20 years and the interest

rate of 8.0%, UCR is calculated as follows:^

(UCR, 8.0%, 20) = 0-08

il‘°

8 ^ 2 0

= 0.10185

(1.0820 - 1)

This is equivalent to an annual fixed charge rate of 10.185% of the

initial capital costs. Monthly and quarterly cost entries for capital

recovery are one-twelfth and one-quarter, respectively, of the annual

cost.

Certain equipment replacement and improvement items, which have

occurred during the first three years of operation, are considered to

be capital expenses and are thus included in the reported capital re- covery cost entries. These capital expense items are individually

reported by GKC as they occur. Examples of such expenses are: pump

replacement, control system modifications, etc. The capital cost entries

are determined in the same manner as for initial capital costs. They

57
are based on the year in which the expense is incurred, the remaining

life of the plant and the same interest rate as for the initial capital

investment. For example, capital improvement items occurring in the

second year of plant operation (1975) are annualized by a UCR corresponding to 8.0% and an 18-year life.

This report does not attempt to forecast future replacement or improvement items. Also, in assuming that the prior replacement/improvement items are capitalized in the year in which the expense oc- curred and have useful life equal to the remaining plant life, the

data in this report do not account for the lower level of capital

recovery during the years prior to the incurring of such costs. This

approach, therefore, presents the actual expenditures for the plant in

its third year of operation without including life-cycle cost considerations or a typical year approach in developing the data.

3.2.2 Other Owning Costs

Owning costs other than capital recovery consist of expenditures

for property taxes and property insurance by the site owner. Invoices

for these items are based on the entire Summit Plaza complex and do not

separately include the TE plant. In addition, the magnitude of these

cost items is not affected by the existence of the plant. For

example, the Summit Plaza complex has real estate tax exemption pursuant to New Jersey statutes, NJSA 55.14 J-l , et^. seq . , as set forth in an agreement with the City of Jersey City. This agreement provides

that the real estate taxes payable for the complex will be 15% of the

annual "shelter rent" of the complex. Therefore, the actual expenditures for real estate taxes do not directly depend on the value of

equipment used for providing utility services. In presenting the actual costs as experienced for the JCTE plant, this report includes no portion of the total Summit Plaza cost for real estate taxes or property

insurance.

58
Generic studies of TE plant economics may require that part of

the costs for these Items be allocated to the Total Energy plant. To

accomplish this, data on the construction cost of the various elements

(residential, commercial, Institutional and utility) of the entire

Summit Plaza complex and Information on the tax and Insurance valuation/

assessment process should be utilized. This effort Is being undertaken

so that future generic reports will Include any Incremental owning cost

of the plant.

3.2.3 Subsystem Cost Separation

In table 3-2, the capital costs are assigned to the four subsystems

on the basis of the function of each piece of equipment. Costs for

equipment shared between two or more subsystems are separated using

relevant indices. For example, fuel storage costs are apportioned by

annual average boiler and engine fuel consumption, and CEB envelope

costs are proportioned by square feet of floor area.

Tables 3-3 through 3-7 present, on a quarterly and yearly basis,

the total costs for each of the subsystems including a capital cost

component. The term "Other 0 & M Cost" in these tables is the sum of

0 & M cost categories 2 through 6 of section 3.1.3.

59
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60

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61
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62
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3-3.

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66
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67 I
4.0 Engineering Factors Influencing the Plant's Energy Effectiveness

Many factors influence the plant's energy effectiveness. Several

of these factors can be changed by corrections in plant operation,

relatively minor modifications to the plant configuration and combinations

of these two items. This section focuses on five engineering factors

which have the potential for significantly improving the JCTE plant's

energy effectiveness without requiring extensive modifications or degradation of the plant's operating longevity or safety. Some of these

modifications may not be implemented due to considerations other than

energy effectiveness such as reliability, while others have already been

accomplished. However, each factor warrants discussion due to its

applicability to the JCTE plant and to other TE plants. This report only

examines the energy effectiveness factors involving the plant and not the

site distribution systems or building loads.

The five factors selected are: 1) primary-loop thermal losses from

idle boiler(s) connected into the primary loop; 2) primary-loop thermal

losses from idle engines; 3) excessive dry cooler primary-loop thermal

losses from continuous convective heat transfer and from improper

fan control; 4) excessive energy consumption of the chillers due to use of chiller output for air-conditioning the engine room; 5) excessive

thermal energy consumption by the absorption chillers. The potential

savings and ramifications of modifications will be discussed for each

of these five factors.

It should be noted that correction of idle boiler losses was implemented during the year of operation covered by this report (May 1976);

correction of idle engine losses and engine room air conditioning involves

minor modifications to the plant configuration; correction of dry cooler

losses requires a minor modification to one of the components of the plant

and an improvement in the plant operation or the installations of more

reliable controls; and, improvement of chiller COP involves an improvement

in the plant operation by more reliable servicing.

68
4.1 Idle Boilers

The JCTE plant has two 13.4 MBtu per hour (3.9 MW) oil-fired,

hot-water boilers capable of meeting all primary loop thermal demands,

even without engine heat recovery. The two boilers are piped and valved

so that both, either, or neither can be connected into the primary loop

(see figure 4-1). This versatile boiler arrangement was originally

conceived to permit both boilers to be connected to the primary loop in

series or to allow a boiler to be valved off and cooled for servicing

and cleaning. With both boilers in the primary loop, the most extreme

heating loads can be met without engine heat recovery.

DAS data indicates that an idle boiler heated by the PHW continually

loses an average of 100 kBtu per hour (29 kW) of primary loop thermal

energy to the surrounding plant. When both boilers are connected to the

primary loop, the losses by the idle boiler must be made up by the

operating boiler. At the boiler firing efficiency of 84% (see appendix III),

the operating boiler consumes approximately an additional 630 gallons

(2.4 m^) of fuel oil each month to make up the continual losses from the

idle boiler.

Because valving a boiler in and out of the primary loop in its

present design would require manual operator intervention and could

thermally stress the boiler's refractory material, a study was made to

determine how often both boilers have been needed to meet boiler heat

demands. The November 1975 through October 1976 JCTE data indicated that

under normal operating conditions one boiler could always meet the primary

loop heat demands not supplied by the thermal output of the engines.

Analysis of peak boiler load data for the most severe winter and summer

months during this period indicates that the boiler demand rarely approaches

100% rated capacity of a single boiler. For example, figure 4-2 indicates

the boiler demand for January 1976, with the capacity of one boiler marked.

It is anticipated that during infrequent, severe weather conditions both

boilers may be needed.

69
Based upon the measured idle boiler losses, the fact that one boiler could meet heat demands, and the ease of valving off a boiler,

the plant operator made the decision in May 1976 to valve off one boiler.

The impact of this decision will be a future annual oil savings of

7500 gallons (28.4 m ) of fuel oil and an improvement in plant energy

effectiveness of approximately 1%.

4.2 Idle Engines

The five engines at the JCTE plant have heat recovered from them by

primary hot water (PHW) which flows through their jackets and exhaust

heat exchangers. Although the electrical demand can always be met by

any three engines, five engines are provided so that at least one engine

can back up the running engines while the fifth engine is undergoing

required maintenance. Currently PHW circulates through all five engines

in parallel whether or not an engine is running.

An analysis of the data from the DAS indicates that an idle engine

including its exhaust-exchanger loses approximately 120 kBtu per hour

(35 kW) of PHW heat, and that a running engine has an average of 1100 kBtu

per hour (320 kW) of heat recovered from it by the PHW.

The PHW thermal energy which is lost by an idle engine is made

up by increased boiler firing. On a monthly basis, the PHW heat lost

from one idle engine is equivalent to firing 750 gallons (2.8 m ) of

oil in the boilers. By always bypassing one idle engine, approximately

9,000 gallons (34 m ) of fuel oil can be saved annually.

Aspects other than fuel savings must be considered in the decision

to bypass one or more idle engines. Of primary concern is the risk of

running an engine without proper coolant flow and causing severe

thermal stresses within the engine. To prevent this, a fail-safe

interlock must be installed. If two engines are bypassed, equipment

must be provided to automatically valve in a back-up engine before it

is started. Automatic valving could cause equipment damage if it did

70
not operate properly. For example, with the present engine control

system, If an engine was called upon to start and It was receiving

Insufficient or no cooling water, It would shut down. However,

because the site load dictates that another engine generator Is required, the

start-up and malfunction sequences would be repeated. This could be

repeated several times before an operator could respond to an alarm

and physically check the engine control system. To Install additional

controls to protect against this possibility would Increase the complexity

and possibly reduce the reliability of the engine control system.

No action has been taken to bypass one or more idle engines. Due

to the need for additional control circuitry, bypassing more than one engine may not be advisable. As for bypassing one engine, a decision

has not been made whether the potential for engine injury and need for

additional automatic control or increased requirement for manual operator

intervention is justified by the potential fuel savings. If one idle

engine were bypassed, the plant's energy effectiveness could be improved

about V/o.

4.3 Dry Cooler Losses

The dry cooler functions to release PHW thermal energy whenever the

PHW temperature exceeds a preset limit. This limit is set at a value

which provides adequate engine cooling. When the PHW exceeds this value,

the dry cooler fans turn on and forced-air convection transfers PHW heat

to the atmosphere.

The designer of the dry cooler anticipated that its fans would

operate only during rare times in the spring or fall when PHW demands

dropped below the engine heat recovery rate or during times when site

hot or chilled water loops were shut down for maintenance. However,

due to both incorrect setting and malfunction of the dry cooler fan

controllers, large quantities of PHW heat have been released and had

to be replaced by boiler firing. For instance, from June 1 to June 7,

1975, the dry cooler fans continuously operated and dumped approximately

71
1500 MBtu (1600 GJ) of PHW heat. Simultaneously, one boiler fired at

its maximum rate, unnecessarily consuming 13,000 gallons (49.2 m ) of

fuel oil. This problem of simultaneous running of the boilers and dry

coolers happened numerous times during the reported year and wasted

at least 5,000 gallons (19 m

3

) of fuel oil.

The dry cooler also loses PHW heat via continual natural convection.

The dry cooler is constructed with open top ducts containing the fan

blades (see figure 1-8 in the first chapter). Outside air can freely

move from below the dry cooler, through it, and out the top duct.

The finned coils, which carry PHW, transfer heat to this freely flowing

air, causing it to rise, and carry heat away from the coils. Data from

the DAS indicates that 200 to 500 kBtu per hour (59 to 145 kW) of heat

is continually lost, depending on ambient wind and temperature conditions.

Annually 5,000 MBtu (5300 GJ) are lost from the dry coolers via

continuous natural convection.

An experiment was performed at the JCTE site on October 19, 1976,

to determine the potential for cutting dry cooler losses by covering

the open dry cooler fan ducts. In this experiment the dry cooler ducts were covered with 3.5 inch (9 cm) glass fiber mat to simulate louvers

placed over the ducts (see figure 4-3). It is recognized that although

both glass fiber mats and louvers could equally stop convection through

the duct, louvers may conduct and radiate more heat from inside the dry

cooler than would the glass fiber mat. However heat lost from the warmed

louvers would be much less than the open duct convective losses. As

shown in figure 4-4, data from the DAS indicates that dry cooler losses were more than halved during the test period when the ducts were covered.

Recognizing that louvers on the dry cooler ducts may conduct

more heat from inside the dry cooler than the glass fiber mat, a reasonabl

estimate for the reduction in dry cooler loss by installing louvers

is 30 to 40%. A 30% to 40% reduction in the current rate of dry cooler

convective loss would save 12,000 to 16,000 gallons (45.4 m to 60.6 m ) of fuel oil annually.

72
A second method for reducing dry cooler continual convective losses

would involve placing an automatic valve in the PHW line to the dry

cooler. This valve would be connected to the dry cooler motor control

lines so that it would only open and allow PHW to flow to the dry cooler

when the dry cooler fans were energized. This technique would save approximately 30,000 gallons (151 m ) of fuel oil annually. This

alternative would require measures to avoid water freezing in the dry

coolers during the winter.

4.4 Air Conditioning the CEB

The ventilation system for the CEB forces outside air into the

engine and boiler rooms. This air is filtered and, in summer, is cooled

by a large chilled water fan-coil. The ventilation system with cooling

utilizes a significant portion of the produced chilled water and affects

the overall plant energy effectiveness. It should be pointed out the

plant is a public demonstration project; creating a comfortable environment for visitors was a design consideration.

During the summer of 1976, 1482 MBtu (1560 GJ) of heat was added

to the chilled water system by the plant ventilation air. This heat

represents 16% of the total chilled water thermal load. To provide

plant cooling the chillers consumed 3705 MBtu (3910 GJ) of PHW heat

corresponding to 31,700 gallons (120 m ) of additional fuel oil con- sumption. If the chillers had operated properly (with a COP of 0.6),

then approximately 21,000 gallons (80 m ) of fuel oil would have been

required for plant cooling.

The value of cooling plant air is debatable. As mentioned earlier,

this plant is cooled partly to make its environment comfortable for

visitors. Also, a cooler plant environment may result in better servicing

of the engines. However, the energy and resulting cost trade-off

must be considered. Possibly increased plant ventilation with cooling

only during engine maintenance periods in the hottest months is a realistic alternative to continuous summer cooling. Adequate cleaning

73
of the ventilation system filters and reducing primary loop and engine

heat losses (for example covering the engine turbocharger assemblies

with removable insulating blankets) will also improve engine room conditions.

No action has been taken to modify the plant to reduce or eliminate

the chilled water required to "cool the plant." After other plant

modifications such as bypassing an idle engine and boiler are performed,

an increased ventilation rate may be sufficient to keep the engine

room at tolerable temperatures without the use of chilled water.

Restricting cooling of the plant air to maintenance periods during the

hottest part of the summer is an alternative. Currently the air is

chilled from May to October.

4.5 Malfunctioning of Chillers

The JCTE plant has two single stage absorption chillers which use

PHW heat to produce 45°F (7°C) chilled water for plant and site cooling.

The COP of these chillers is defined in this report as the total thermal

energy removed from the chilled water divided by the PHW thermal energy

consumed by the chillers. During the summer, the chiller PHW heat

requirements are larger than can be met by recovered engine heat and

require large heat outputs from the boiler to meet these demands. Thus,

efficient chiller operation is vital for plant energy effectiveness.

During the summer of 1976 the chillers produced a total of 9200

MBtu (9700 GJ) of chilled water and consumed 23,000 MBtu (24300 GJ)

of PHW heat. Thus, their overall COP was .40. The ASHRAE handbook7

states that a COP from .60 to .65 is to be expected from single-stage

absorption chillers. Also, representatives of the company which produce

the chillers installed at the site have informed the authors they have

observed COP 1 s from .60 to .70 for similar chillers in field operation.

Two distinct conditions appear to have caused the observed low

overall chiller COP: 1) several periods of extremely low COP operation

74
(COP's between .2 and .3); and, 2) a generally low COP during "normal"

operation (COP of less than .53). At least three periods of extremely

low COP operation occured in the summer of 1976. These periods ranged

in duration from four to seven days. During these periods the chillers

required continuous high-output boiler firing.

An example of a period of extremely low COP operation is shown

in figure 4-5 which reports PHW heat input and chilled water produced

during September 1976. Note the large amount of PHW heat required between

the fourteenth and the twenty-first of September. This chiller heat

demand resulted in a high-output boiler operation during that period

(see figure 4-6). "Normal" chiller operation was restored on September 21, 1976, by the chiller servicing contractor who reportedly

adjusted controls, reducing the concentration of the solution in

the concentrator. The periods of extremely low COP operation by the

chillers wasted at least 2600 MBtu (2700 GJ) of PHW heat in 1976,

requiring that an additional 22,000 gallons (83.3 m ) of fuel oil

be consumed by the boilers.

Periods of "normal" chiller operation during 1976 showed low

COP's. During two-to-three day periods of moderate to full -load chiller

operation in 1976, the highest average chiller COP measured was .53.

This value is significantly below the .6 to .7 reference COP and

below the .62 COP determined from DAS measurements for the site chillers

during several days in late June 1975. The reason for the low COP

during the 1976 season is not known, however, it may relate to a problem detected at the end of the 1975 chilling season. At that time,

it was discovered that several large gaskets in the chillers had been

improperly installed during routine contractor servicing. Fragments

of these shredded gaskets may have blocked flows inside the chillers.

Had the chillers operated with an overall COP of .6 during the

1976 cooling season, the chillers would have required only 15,400 MBtu

(16,250 GJ) of PHW heat rather than 22,994 MBtu (24,259 GJ) they

actually consumed. The additional PHW heat consumed due to low chiller

75
COP, 7660 MBtu (8240 GJ), is equivalent to firing 65,000 gallons (246 m

3

) of fuel oil in the boilers. If the low chiller COP is corrected, another

summer of DAS data will provide opportunity to determine the improved

system energy effectiveness.

4.6 Summary

Five factors affecting plant energy effectiveness have been

discussed here. Table 4-1 presents the possible improvement in plant

effectiveness and fuel savings which could result from implementing

these measures. Implementing the four minor modifications would result

in a fuel savings of at least 56,500 gallons (214 m ) of fuel oil annually

and an improvement in plant energy effectiveness of 5.5%. The fifth

factor, improved servicing of the chillers, would result in a savings

of 65,000 gallons (246 m ) of fuel oil. Together, all five measures

would result in an annual fuel savings of 121,500 gallons (460 m ) of

fuel oil or 12.4%.

In section 5, these measures are implemented in an analytic

model of the JCTE system. Improvement in seasonal performance is

shown in that comparative analysis.

76
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r;=^==0===3===$==S==

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78

Figure

4-2

Boiler

output

duriag

most

severe

winter

month

of

1976.
Figure 4-3 Dry cooler convective heat loss Experiment:

in this experiment the natural convective flow

through the ducts was restricted usinq qlass fiber mat.

r

79
11-

3-76

10761137

HEAT

REMOVED

BY

DRY

COOL

C2)

INSULATION

EXPERIMENT

OCTOBER

19/

1976

CM

cm

<p4

4. 00

**M>

* * CM

80

Figure

4-4

Results

of

dry

cooler

convective

heat

loss

experiment.

Dry

cooler

ducts

were

fully

covered

at

1600

hours.

Dotted

line

indicates

loss

expected

if

the

dry

coolers

were

uncovered.
}

81

Figure

4-5

Example

of

chiller

malfunction.

From

September

14

to

September

21st

large

amounts

of

PHW

heat

(1)

were

used

by

chiller

to

accomplish

moderate

chilled

water

production

(2).

Chiller

adjusted

on

September

21,

1976

See

figure

4-6.
sanoH mm a n*i*s oni>

82

Figure

4-6

Boiler

heat

demand

before

and

after

chiller

adjustment

on

September

21,

1976.
Table 4-1

Summary of annual fuel savings which would

result from suggested minor plant

modifications and chiller adjustment

Action Annual Fuel Oil Savings

1 . Bypass Idle Boiler

2. Bypass one idle engine

3. (a) Improve dry cooler

controller

(b) Louver dry cooler

fan ducts

4. No cooling of plant

ventiiation air

7,500 gallons (28m

3

)

9.000 gallons (34m3

)

5.000 gallons (19m

3

)

14.000 gallons (53m

3

)

21 .000 gallons (80m3

)

All Minor Modifications 56,500 gallons (214m3

)

Chiller Adjustment 65,000 gallons (246m3

)

All minor modifications and

chiller adjustment 121,500 gallons (460m3

)

Assumes chiller COP is 0.6.
.

'
5.0 Preliminary Comparative Energy Analysis

To provide a basis for evaluating the relative fuel performance of

the JCTE plant. It is necessary to make at least a preliminary comparison

with alternative systems. In this section, engineering models are used

to compare the fuel consumption of the JCTE plant (with and without

adjustments for the malfunctioning chillers) with the fuel consumptions

of two non-TE types of central plants and with the consumption of the

JCTE plant incorporating the minor modifications described In section 4.

The two non-TE central plants which are modeled represent alternative

central plants using conventional technologies which might have been

installed at the Jersey City site. Both use electrical power purchased

from the local utility; both produce site hot water with oil-fired

boilers; and both use site distribution systems like the present JCTE

system. However, one non-TE plant produces chilled water via boilerdriven absorption chillers and the other uses electric-motor-driven

compression chillers. Actual fuel consumption by the JCTE plant is

presented with and without adjustments to compensate for the malfunctioning absorption chillers.

The three comparative systems selected were chosen to place the

present JCTE fuel consumption in perspective by determining the fuel

consumption of two non-TE types of central plants which would have

been applicable to the Jersey City site and by determining the fuel

consumption which can be achieved by the JCTE plant with minor

modifications. Non-central comparative systems, such as purchased

electrical power and individual heat pumps, or combinations of electric

resistance baseboard heating and electric room air conditioners are

not modeled in this report. A study involving several additional

alternate systems is underway as a part of the final reporting on the

Jersey City project.

83
The data from the JCTE plant and site is fundamental to the

preliminary energy analysis presented here. This data is used in two

ways, first, to establish the combined energy demands of the site and

its distribution system, and second, to establish component efficiencies

for plant equipment such as the boilers and engines. These two bodies of

data, plus published information on electrical utility generationdistribution efficiency and chiller COP's are the basis for the

comparative models.

The fuel data for all the comparative models is normalized to the

average heat content per gallon of fuel oil delivered to the JCTE site

(139,000 Btu per gallon). This is done so that all results are expressed as gallons of fuel oil. The authors recognize that actual

systems may consume other fuels, however, the total heat content of

the other fuels will be equal to the total heat content expressed as gallons of fuel oil

.

It should be noted that for this comparative study the JCTE fuel

data is also obtained from a model. This is done to normalize the

fuel data to a constant heat content to allow compensation for the

chiller malfunctions. The fuel consumption predicted by this model

is within .5% of the annual fuel consumption of the site as given

in section 2. 2. 2. 2.

The following sections discuss each comparative system, the model,

assumptions in the model and the method of computing fuel data. Results

are reported in section 5.2.

5.1 Description of Comparative Systems

5.1.1 JCTE System

The JCTE System is fully described in the introductory section

of this report. Briefly, the JCTE System uses engine-generators to

produce electric power for the site, the HVAC plant, the PTC, and the

84
electric plant operation. Heat is recovered from the engine bank by

a primary hot water (PHW) loop. The PHW heat is used to heat secondary

hot water distributed to the site and is used by absorption chillers

which provide secondary chilled water for the site. A hot water,

oil-fired boiler supplements the engine heat to meet PHW demands. A

dry cooler, installed to provide the engines with adequate cooling

during rare periods of very low PHW heat demands, continually transfers

some PHW heat to the atmosphere.

In the JCTE System model, engine-generator fuel consumption is

computed from engine efficiency measurements and from month-by-month

electrical consumption measurements. The engine-generator electrical

efficiency, as determined from JCTE data, averages 32.4%. The combined

electrical demand of the site, PTC, HVAC plant, and electrical plant

is determined from JCTE kilowatt-hour data taken at the output of the

generators. Fuel oil heat content is set at 139,000 Btu per gallon

(38.7 GJ per m^)

.

In the JCTE System model , primary thermal demands are computed

month-by-month from the measured secondary hot water demands, the

measured chilled water demands divided by the chiller COP, and the

measured dry cooler losses. These demands are met by heat recovered

from the engines and produced by the boiler(s). Analysis of monthly

data indicates that heat is recovered from the engines at a rate of

3.061 kBtu per gross kWh produced (3.230 MJ per kWh) (this number

is a 12 month average having a month-by-month standard deviation of 4%).

The necessary boiler(s) output is determined from the heat demand minus

the recovered engine heat. The boiler(s) fuel consumption is computed

from the boiler output using an analytic boiler model (see appendix III).

The boiler fuel model has a continual heat loss term of 100 kBtu per hour

per boiler (29 kW) (the heat loss rate from a boiler heated to the PHW

temperature) and a boiler firing efficiency term of 84% (percentage

of combusted fuel's heat content which is transfered to the boiler

water). This boiler fuel model is used for all four comparative

systems. It is more"' fully explained in appendix III.

85
To compute the actual JCTE System consumption the chiller COP is

set to the measured value of 0.40. To compute the JCTE System con- sumption with adjustments for the chiller malfunctions, the chiller

COP is set to a conservative reference value of 0.60^. All other steps

in the two computations are the same for both models.

5.1.2 Modified JCTE System

The modified JCTE System is essentially the same as the JCTE

System except that it incorporates the energy saving suggestions of

section 4. These suggestions are:

1) having only one boiler in the PHW loop

2) bypassing one of the two idle engines

3) louvering the dry cooler and improving the fan controller

4) eliminating cooling of plant ventilation air.

This model also assumes properly functioning chillers.

Fuel consumption of the modified JCTE System is equal to the

boiler fuel computed from the modified JCTE System boiler heat load

plus the computed JCTE System engine fuel. Boiler heat load is

determined by summing the dry cooler, secondary hot-water, and chiller

heat and subtracting heat recovered from the engines. Dry cooler heat

losses are assumed to be 300 kBtu/hr (88 kW) in summer, 350 kBtu/hr

(103 kW) in the spring and fall, and 400 kBtu/hr (117 kW) in winter based

on the installation of louvers and proper controller adjustment. These

numbers are based upon a one-third reduction from current convective

loss rates. The amount of heat transferred from the PHW to secondary

hot-water loops is the same as the measured JCTE value. Chiller

primary heat requirements assume a properly adjusted chiller COP of

0.6

7 and assume that no chilled water is used for cooling the engine

plant. Chiller primary heat is computed by dividing the measured site

chilled water requirements by 0.6. The heat recovered from the engines

is equivalent to the JCTE System values plus 120 kBtu per hour (35 kW)

86
due to bypassing one idle engine. Boiler fuel consumption is computed

by adding the continual 100 kBtu/hr (29 kW) boiler heat loss to the

boiler load and dividing that quantity by the boiler firing efficiency,

84%, and the fuel heat content 139,000 Btu/gallon (38.7 GJ per m

3

).

5.1.3 JC System Using Purchased Electric Power and Central

Absorption Chillers

The JC System using purchased power and absorption chillers assumes

that electrical power for the site, HVAC plant, and PTC is purchased

from the local utility; secondary hot-water is produced by central

boilers; and secondary chilled water is produced by a central boiler

and absorption chiller combination. The secondary hot and chilled

water loops are the same as the actual JCTE system and building demands

are all the same. The model's fuel oil consumption is based on utility

fuel requirements to produce the necessary electrical energy and the

fuel consumed by this plant's hot water boilers. The local utility's

electrical generation-distribution efficiency is obtained from their

8 published 1975 annual report. Boiler efficiency is set at the measured

JCTE value and the absorption chiller COP is set to a conservative

reference value of 0.6?

The energy consumed by the local utility in meeting the plant and

site electrical demand is computed by multiplying the measured JCTE

electrical site demand plus the JCTE HVAC plant demand times the utility

electrical generation distribution efficiency, 11,451 Btu per kWh

(12.081 MJ per kWh). Boiler thermal loads are determined from chiller

heat requirements and from measured site hot water demands. The chiller

heat requirement is obtained from the site chilled water demand divided

by the chiller COP, 0.6. Boiler fuel consumption equals boiler load plus

a continual boiler loss of 100 kBtu per hour (29 kW) per boiler divided

by the boiler firing efficiency (84%) and the heat content of fuel oil,

139,000 Btu per gallon (38.7 GJ per m

3

).

87
5.1.4 JC System Using Purchased Electrical Power and Central

Electrical Compression Chillers

For this comparative model it is assumed that all site, PTC, and

HVAC electrical energy will be purchased from the local utility; secondary

hot water will be produced by central boilers; and site chilled water

will be produced by an electric-motor-driven compression chiller. The

electrical, hot water, and chilled water distribution systems are assumed

the same as the actual JCTE site, and site electrical, site hot water, and

site chilled water demands equal the measured JCTE values.

The efficiencies and loads used in this model are determined from

JCTE data and reference data. The boiler efficiency is equivalent to

JCTE boiler measurements. The utility electrical production-distribution

o efficiency is equivalent to 1975 published local utility reports. The

compression chiller COP is set at a handbook value of 3.0? A field

study on a large compressor chilling facility reports a 3.5 chiller

COP. Additional HVAC electrical requirements for secondary pumps, fans,

etc., are the same as JCTE data, except that compression chilling requires

half the cooling tower capacity, no hot water pumps, no small internal

pumps and the same chilled water pumps; thus auxiliary HVAC processing

power is approximately 80 kW less than JCTE measured HVAC power during summer months.

The fuel used by the local utility is computed from the site and

plant electrical consumption times the utility generation-distribution

efficiency, 11,451 Btu per kWh (12.081 MJ per kWh) divided by the heat

content of fuel oil, 139,000 Btu per gallon (38.7 GJ per m^). The

electrical consumption of the plant and site is equal to the measured JCTE

site consumption, plus the measured JCTE site chilled water thermal load

divided by a COP of 3.0, and plus the measured JCTE HVAC processing

electrical consumption minus 80 kW times the hours of chiller operation.

The boiler fuel consumption is equal to the measured JCTE secondary hotwater thermal load plus the continual 100 kBtu per hour (29 kW) boiler

heat loss, divided by the boiler firing efficiency, 84%, and the heat

content of fuel oil, 139,000 Btu per gallon (38.7 GJ per m^)

.

88
5.2 Comparative Results

Figure 5-1 shows the projected annual fuel consumption of the four

comparative systems: JCTE System (with and without adjustments for the

malfunctioning chillers), Modified JCTE System, JC System using purchased

electrical power and absorption chillers, and JC System using purchased

electrical power and consumption chillers.

The models indicate the following annual fuel consumptions: JCTE

System (without adjustments for the malfunctioning chillers) would require

988,000 gallons of fuel oil, JCTE System (with adjustments for the malfunctioning chillers) would require 923,000 gallons of fuel oil. Modified

JCTE System would require 870,000 gallons of fuel oil, JC using purchased

electrical power and absorption chilling would require 1,083,000 gallons

of fuel oil, and JC using purchased electrical power and compression

chilling would require 1,011,000 gallons of fuel oil.

A comparison between the JCTE System (with adjustments to compensate

for the malfunctioning chillers) and the two purchased power systems

indicate that the system using purchased electrical power with absorption

chilling would annually require 17.3% more fuel and the system using

purchased electrical power with compression chilling would annually

require 9.5% more fuel than required by the JCTE System. If the JCTE

System were modified according to the suggestions in section 4, then it

would annually consume 5.7% less fuel than is consumed by the JCTE

System. The purchased power with absorption chilling system would

require 24.5% more fuel and the purchased power with compression

chilling system would require 16.2% more fuel than the Modified JCTE

System.

These results indicate that an alternative conventional plant using

purchased electrical power, oil-fired boilers, and absorption chillers,

would annually require 160,000 gallons more fuel oil than the JCTE

plant (with adjustments for absorption chiller malfunctions).

89
The seasonal fuel consumption of the comparative systems is

shown in figure 5-2. For this comparison the winter season includes

December 1975, January 1976, and February 1976; the spring season

includes March, April, and May of 1976; the summer season includes

June, July, and August of 1976; and the fall season includes

September 1976, October 1976, and November 1975. In general, the

non-TE plants cause approximately 14% more fuel to be consumed during

the winter months than was consumed by the JCTE System.

During the summer cooling season, a comparison of the JCTE System

(adjusted to compensate for the malfunctioning chillers) and the systems

using purchased electrical power indicates that the system using purchased

power with absorption chilling would require approximately 17% more

fuel and the system using purchased power with compression chilling would

require approximately 4% less fuel oil than required by the JCTE System.

It should be noted that the low JCTE chiller COP has significantly

affected the JCTE summer fuel consumption. If the JCTE System were modified

according to the suggestions in section 4, then during the summer the

system using purchased power with absorption chilling would require

approximately 28% more fuel and the system using purchased power with

compression chilling would require approximately 6% more fuel than the

Modified JCTE System.

90
C4 O QO CO

^

CM

(suojieg jo spuesnoifj.) no mi

91

Figure

5-1

Annual

fuel

consumption

projected

for

the

four

systems.

Hatched

area

above

JCTE

system

represents

additional

fuel

consumed

due

to

malfunctioning

chillers.
CO CM

(SUOIIB0 JO spuesnoiji) no llflj

92

Figure

5-2

Seasonal

fuel

consumption

projected

for

the

four

systems.

Hatched

area

above

JCTE

system

represent

fuel

consumed

due

to

malfunctioning

chillers.
6.0 Unit Energy Cost and Preliminary Cost Comparison

Economic evaluation of the JCTE plant should be based on comparative

total costs for various Total Energy (TE) and alternative conventional

system concepts. Major required steps of such a comparative evaluation

are:

1. design and capital cost estimating for the hypothetical

alternative systems; and

2. computer simulation of TE and conventional plants to determine energy consumption and 0 & M costs.

Design and capital costing efforts are currently in progress under

contract to NBS. This design data as well as a larger data base of actual

plant 0 & M costs will be available in the future for economic evaluation

of the JCTE Project. Therefore, the complete comparative economic evaluation of alternatives based on total cost cannot be completed at this

time.

As an interim measure for this report, the actual cost data of

section 3 are utilized to develop the unit costs (<t/kWH, $/Btu) of

energy commodities delivered to the site buildings. These data can be

compared with available data for conventional systems to put the JCTE

plant costs into perspective. The comparisons are limited and do not

constitute a thorough and complete economic analysis of alternatives.

This section develops a means of accounting for energy transfers

between subsystems so that unit costs can be calculated for electricity,

hot water and chilled water provided by the JCTE plant. Estimated data

are developed for one case on the cost of equivalent conventional ser- vices and a preliminary comparison with the plant costs is presented.

6.1 Need for Cost Separation

The purpose of cost separation in this report is to provide an equitable allocation of total plant costs to the various subsystems

so that meaningful unit costs can be calculated for each energy product.

93
These unit costs can be used to compare with other data, but the results

are only an approximate indication of comparative economic viability due

to the difficulty in obtaining directly comparable data for conventional

plant costs.

Cost separation assumptions can influence the cost of the subsystems

in a major way. However, since total costs for the plant do not change

in any way through cost separation, overall cost comparisons should not

be influenced. It should be further noted that whatever methods are used for cost separation, only total costs are relevant. Economic com- parisons of alternative energy systems must include costs for all energy

services used by site buildings.

As shown in figure 6-1, the quantity of utility services supplied

to the site is not the same as that produced by the subsystems due to

energy flows internal to the plant between subsystems. In order to calculate unit costs of utility services supplied to the site, cost separation must be used to account for these internal energy flows. Energy

flows requiring consideration are as follows:

' thermal energy recovered from engines and used in heating

and cooling subsystems.

* electrical energy used for the heating, cooling and PTC

subsystems

.

* heat used by the chillers for production of chilled water.

chilled water used to cool plant office and equipment areas.

It should be noted that any supplementary heating required by plant

office areas or for cooling tower freeze protection is supplied by the

waste heat from the engine-generators' lubrication oil coolers and com- bustion air aftercoolers, not by hot water from the heating subsystem.

This has not been included as a factor in cost separation since the heat

actually used is quite small and because it would be quite tenuous to

attach costs to a waste heat commodity with limited use.

94
It appears possible to make an adequate comparison of the economic

performance of single-purpose (conventional HVAC) and dual-purpose

(Total Energy electricity and HVAC) plants by means of careful cost

separation. The method is to derive the cost of thermal energy produced

by the dual-purpose plant using actual cost data from a single-purpose

plant. All remaining costs for the TE plant can then be allocated to

electric power production. If this can be accomplished, a straightforward comparison with published electric utility costs and rate

structures (as done later in this section) constitutes an adequate eco- nomic analysis of two alternatives.

This incremental approach requires detailed investigation of 0 & M

costs such as operating labor as well as design of a hypothetical con- ventional plant in enough detail to discern capital cost differences.

This process should be followed even if the hypothetical plant is exactly

the same basic design as the TE plant but without electrical production.

Such analysis will be undertaken after design and costing efforts for

hypothetical alternative plant designs are complete.

6.2 Cost Separation Methodology

6.2.1 Heat Recovery from Engines

The electrical subsystem direct costs reported heretofore must be

apportioned to the electrical and heat-using subsystems to reflect the

thermal energy generated by the diesel engines for use by other subsystems. This must be done because the electrical subsystem primarily

exists for the dual purpose of electrical & thermal energy production.

A number of techniques can be devised for electrical /thermal cost

separation. However, there appears to be no consensus among engineers

and economists regarding cost separation from dual-purpose diesel energy

systems. Decisions to be made regarding cost separation for heat recovery

involve the following points:

95
1. Whether recovered heat should be individually allocated to

the heating and cooling subsystems in some way.

2. Whether the costs of rejected heat (i.e. recovered heat not

actually used) should be charged to recovered heat, electrical

production or both.

3. Whether net or gross electric energy should be used as a basis

of cost allocation to the electrical subsystem.

4. Whether equivalent energy units of recovered heat and electricity should be equally valuable (equal in cost) or on what

basis their costs should be separately developed.

5. Whether different treatment should be accorded to electrical

subsystem components related to electricity only, to recovered

heat only, and to both products.

6. Whether variable costs (O&M) should be treated differently from

fixed costs (capital recovery).

The cost separation technique used in this report to account for

recovered heat is quite simple and is adequate for preliminary data

presentation purposes. Important assumptions relating to the above

decision points are:

1. The heating subsystem is responsible for all heat production/

recovery and hence cost separation only involves the electrical

and heating subsystem. The chiller receives all its heat from

the heating subsystem. This assumption does not affect results,

but merely streamlines cost separation accounting. Recovered

heat is assumed to be indistinguishable from boiler-produced

heat, and therefore the heating and cooling subsystems share

the benefits of recovered heat in proportion to their use of

heat.

2. Recovery and efficient use of heat from the diesel enginegenerators is one function of the heating subsystem in a TE

plant. Both design features and operating practices can greatly

affect the quantity of heat actually recovered and/or utilized.

In the JCTE plant, the heating subsystem can contribute to cost

96
minimization by (1) proper design & maintenance of diesel engine

heat recovery devices to recover the maximum possible heat and

(2) proper design & control of excess heat rejection devices

to utilize the maximum possible amount of heat recovered. In

developing the appropriate level of potential heat recovery as

a baseline for cost separation, potential design changes to the

existing plant are not considered. Heating subsystem operating

and maintenance practices, where the expected effect on heat

recovery/utilization is known, are considered in formulating

cost separation.

Heat Recovery - Inefficiency in recovery of heat can be re- flected in added costs to the heating subsystem. Operating and

maintenance practices related to heat recovery include operation

of. the engines to maximize recoverable heat and maintenance

(cleaning) of the heat recovery devices. 0 & M practices have

been formulated by the plant operator and have not been evaluated by NBS for energy or economic effectiveness. Changes in

these practices to improve heat recovery may be justified.

Since the additional heat recovery is somewhat hypothetical at

this time, possible improvements in heat recovery will not be

used in establishing a baseline for cost separation.

Heat Utilization - For the 12 months, 8% of the total PHW heat

from engines and boilers has been rejected unused (see table 2-2).

The bulk of this loss was due to operating conditions within the

heating subsystem (see section 4.3). It is clear from section

4.3 that relatively minor changes to the plant could have nearly

eliminated such losses. Therefore, this report considers re- covered heat (rather than utilized heat) as the basis for cost

separation. Had the heat rejection from JCTE been largely due to

a time-wise mismatch of thermal /electrical demand periods, the

cost separation probably should be based on utilized heat, not on recovered heat. However, periods of mismatch between heat production & demand were quite rare during the period as indicated

97
by figure 2-5. Hence the use of recovered heat for allocating

costs to the heating subsystem is considered valid for this report.

3. Minimization of parasitic losses and auxiliary loads (e.g.

PHW pumps) within the electrical subsystem is one function

of the electrical subsystem. Therefore, the costs of such

electrical energy should be borne by the electrical subsystem.

Costs are separated (and allocated to the electrical subsystem)

on the basis of gross electrical energy generated rather than

net energy generated.

4. Separation of costs is based on the energy equivalence of

recovered heat and electricity (i.e., heat and electricity are considered equally valuable on an energy quantity basis).

5. All electrical subsystem components are considered in heat/

electricity cost separation with the exception of site distribution costs which are allocated only to site electrical energy.

(Electrical switchgear relates only to electrical energy production and could be separately allocated to electrical energy

only but it is a rather small part of the total electrical subsystem cost.)

6. Variable costs (O&M) and fixed costs (capital recovery) are treated the same for heat recovery cost separation. This means

that a portion of the capital recovery costs as well as O&M

costs associated with the electrical subsystem are allocated

to the recovered heat. In this sense the heat and electricity

are inseparable joint products of the electrical subsystem.

Neither can be considered an incremental or optional product

which incurs only incremental production costs.

The above assumptions allow the formulation of cost separation for

heat recovery as follows:

Ce > h

= C e ' EfTE

g

Ce ,h is that portion of the electrical costs to be allocated to the

heating subsystem to account for heat recovery and C'e is the total

98
electrical subsystem direct costs (less site distribution) including

fuel, O&M and capital recovery costs. E r is the thermal energy re- covered from the engines by the PHW and E g is the gross electrical energy

generated in the same units as E^. (Both E r and E

g are defined more

fully in sections 2.1.2 and 2.1.1, respectively.) The quantity

E r/(E

r+Eg) is designated "x" later in this section. The value of x is

dependent only on the thermal characteristics of the diesel enginegenerators and heat recovery devices. Its value is relatively constant

throughout the year and averaged 0.47 for the 12-month period.

As stated under item 4 above, the costs transferred to the heating

subsystem include a portion of the capital recovery costs of the electrical subsystem. In designing a TE plant, the heating subsystem should

consider engine-generator recovered heat as added heat production capacity. Therefore, the installed boiler capacity of a dual-purpose T.E.

plant should be less than that of a single-purpose conventional HVAC

plant. The resultant reduced capital costs would be offset by the

portion of engine-generator capital costs allocated to the heating subsystem in the cost separation technique developed in this report. Details on the design approach and the extent to which boiler size was reduced by recovered heat availability will be covered in a future design report to be prepared by the plant design engineer.

6.2.2 Other Intersubsystem Energy Transfers

In developing an approach for cost separation for other than re- covered heat, a basic assumption was that the unit cost of a particular

energy product at the producing subsystem is the same regardless of how

it is used (by another subsystem or site buildings). This means that

all uses of an energy product are considered to share proportionately

in 0 & M and capital recovery expenses of the producing subsystem. (This

also conveniently allows use of unit cost in cost separation equations

rather than absolute costs.) Allocating capital recovery costs to

energy commodities used within the plant also means that these energy

outputs are not optional outputs which bear only incremental production

99
costs. This is clearly the case with all intersubsystem energy exchanges

with the possible exception of the chilled water used for plant equipment area cooling.

The cost of energy commodities as provided to the site buildings

is being developed in this section. In cost separation for the intersubsystem energy transfers in figure 6-1, site distribution costs are

not included in plant subsystem direct costs. Site costs are applied

only to the energy quantities delivered to the site. This was done be- cause distribution costs are a significant portion (approximately 10%)

of the costs of their respective subsystems but only relate to energy

products delivered to the site. For this reason, the unit cost of each

energy product as delivered to the site will be slightly higher than the

plant unit cost used for cost separation between subsystems.

6.2.3 Cost Separation Formulation

In formulating the cost separation, the following basic equation

has been used:

Direct cost + indirect cost of energy from other subsystems (1)

= cost of products

The direct cost is that cost already described in section 3, i.e., the

reported costs before cost separation. Applying this equation to each

subsystem will result in a set of equations which can be solved simultaneously. This should provide a basis for solving the cost separation

problem. In applying eq. (1), the following notation is used:

C

' ^ = total direct cost of subsystem i, less distribution costs.

This item is primed to indicate "as reported" costs, before

cost separation.

E. . = quantity of product energy transferred from subsystem

i to subsystem j

.

c

1 = unit cost of energy produced at plant by subsystem i.

for i : e = electrical; h = heating; c = cooling;

100
p = pneumatic trash collection

for j: same as above except s = site and n = net (useful)

For the electrical subsystem, the net cost of energy from other subsystems consists of the added cost of the chilled water energy used

for plant cooling and the reduction in cost due to heat recovery. The

entire cost of plant cooling is assigned to the electrical subsystem be- cause only a very small portion of the plant cooling is used for space

conditioning of the office area, while the cooling of the areas surrounding the engine-generators constitutes the greater portion. The reduction

in cost due to recovered thermal energy is the total electrical subsystem

cost (including the cost of chilled water energy) multiplied by a heat

recovery factor, (denoted by "x") as described in section 6.1.1. Thus,

for the electrical subsystem, eq. (1) becomes:

C'e + E c,e c c

“ x(C'e + E Cs6 Cc ^ E e,n Ce

or (1-x) (C'

e + E c>e ’c c ) = E e>n

'c e ( 2 )

where: E e>n = E e>s

+ Ee>c + t e>h 'e,p

For the heating subsystem, the net cost of energy from other subsystems

consists of the added cost of recovered heat plus the added cost due to

electric energy consumption by the heating subsystem. Thus for the

heating subsystem, eq. (1) becomes:

C* + x (C 1 + E ’c ) + E i c = E. * c. h A ' e c,e c e,h e h,n h (3)

where: E. = E. + E. h,n h,s h,c

For the cooling subsystem, the cost of energy from other subsystems con- sists of the added cost due to use of hot water energy in the absorption chillers plus the added cost due to electric energy consumption.

Equation (1) for the cooling subsystem becomes:

101
where: E = E + E c,n c,s c,e

For the pneumatic trash collection system, the cost of electric energy

consumed is the only cost element to be considered in addition to the

direct costs. Equation (1) becomes:

Equations (2) through (4) represent a system of three equations in

three unknowns. The unknowns are the unit costs c’ , c. and cf . Assume h c ing consistency and independence of this set of equations, the solution

is a straightforward matter. Moreover, negative unit costs or other

anomalous solutions are unlikely because costs are separated in proportion to energy flows which are reasonable and consistent.

Since published data often provide only 0 & M costs for comparison

purposes, it is desirable to provide site unit costs for the JCTE plant

showing 0 & M and capital recovery components separately. The set of

equations (1) through (4) is used three times to calculate the three

unit cost components: fuel, other 0 & M, and capital. By this process,

each of the direct cost components of a particular subsystem is allocated

to other subsystems in proportion to the amount of energy utilized. This

procedure also guarantees that the cost structure of a particular energy

commodity is the same whether used as a final site product or as an input to another subsystem. Taking the fuel cost component as an example,

equation (4) for the cooling subsystem becomes:

C

1 f + E. *c. f + E *c f

- E *c c,f f h,c h,f e,c e,f c,n c,f

C'

c which is the direct fuel costs for the cooling subsystem, is zero as shown in table 3-7 since the chillers consume no fuel directly.

However, the electric energy and hot water energy used by the cooling

subsystem have fuel cost components associated with them and thus the

102
fully allocated unit cost for cooling contains a fuel cost component.

This is c .. c,f

The data for these equations are readily available from the cost

data base of section 3 and from production quantities reported in

section 2. However, the items E , and E may require some clarifiG 9 n G 5 c cation. Referring to table 2-1, only the sum of E Q . and E is

directly available from the column entitled "HVAC plant load." However,

E g ^ is relatively constant over the year. Thus, by taking the average

consumption during the months the chillers were not operating, an approximate average value for the E . can be obtained. This value can

C j1

1

be subtracted from the values in the column for the months the chillers were operating to obtain an approximate average value for E . Data

G jC

for E has been directly collected, but was not processed and availG

able for this report. Future reports will utilize actual values of E G >C

6.3 Unit Cost of Site Energy - JCTE

By combining the direct costs for site distribution with the unit

costs of energy products at the plant, the unit cost for energy products

delivered to the site buildings can be calculated.

Conceivably, the site distribution costs could include both capital

recovery and 0 & M components. The reported data of section 3 does not

separately show 0 & M costs for site distribution. The plant operator's

responsibility theoretically ends at the TE plant building wall and maintenance of distribution equipment on the site grounds and inside site buildings is the responsibility of the site owner/operator. This division of

responsibility has not always been adhered to, resulting in some plant labor being expended on site distribution. During the period under investigation, overall site distribution 0 & M activities have been minor except

for the PTC subsystem and only a small percentage of plant labor has been

involved. Thus the assumption of zero 0 & M costs for site distribution

of energy products up to the site building wall is a relatively good one.

103
Equations are developed for the cost of site energy commodities

using the following basic equation:

site unit cost = plant unit cost + site distribution unit cost (5)

In applying eq. (5), the following notation is used:

c*. . . = the unit cost for subsystem energy product i, of cost

1 » J component k provided to j.

C' i}k = Direct cost for subsystem i of cost component k (plant

cost only)

C

1 . . . = As above except denotes added direct cost for j

i »k,j

for i: subsystems e, h s c are as defined as before

for k: f = fuel cost; o = other 0 & M; d = capital recovery

for j : s = site; p - plant

and other notation is as before.

Since there are no reported 0 & M costs for site distribution, both the

fuel and 0 & M site unit costs components are the same as at the plant.

Therefore, eq. (5) for fuel and 0 & M unit costs for each site energy

commodity becomes the following:

electrical

c e,f»s

~ c e,f,p (6)

c" = c* e,o,s e,o,p (7)

heating

S,f,s ' S,f,p (8)

c h,o,s

~ c h,o,p (9)

cool ing

C X = C X C,f,s c ,f ,p

(10)

c = c c,o,s c,o,p (ID

The capital costs for site distribution are separately reported in

104
section 3 of this report. Equation (5) for capital recovery unit cost

for each site energy commodity becomes:

electrical

c. = c . + C

1 j/E e,d,s e,d,p e,d,s' e,s

heating

ch,d,s

= ch,d,p

+ C

'h,d,s/E

h,s

cool ing

c , = c , +C ,/E c,d,s c,d,p c,d,s' c,s

Site unit energy costs are directly calculated using eq. (1)

through (14) and presented quarterly in tables 6-1 and 6-2 for electrical

and hot water energy respectively.

Chilled water unit cost data are not presented on a seasonal basis

since the spring and fall periods of operation are not meaningful,

representing only 6 and 34 days of operation, respectively. However,

seasonal direct cost data for the cooling subsystem need to be developed

in order to determine (using eqs. (2), (3) and (4)) the costs of plant

electrical and hot water energy on a seasonal basis. Since cooling subsystem costs are incurred even in the winter when no cooling takes

place, the total 12-month cooling subsystem costs need to be spread

over the period the cooling subsystem operated. This is done by allocating total 0 & M cost by the quantity of chilled water produced each

month and allocating total capital recovery expenses by the number of

days the chilling subsystem operated in each month. Monthly cooling

subsystem costs obtained in this way are used in the cost separation

equations to develop the electrical and hot water data of tables 6-1

and 6-2.

A 12-month summary of site unit cost data including chilled water

is presented in table 6-3. Site total allocated costs are also presented for the 12-month period in table 6-4. The unit cost of site

electrical energy is also calculated monthly and presented in table 6-5.

105

( 12 )

(13)

(14)
The unit cost of electrical energy is greatly affected by cost

separation for heat recovery and for cooling energy use. Since there

are several techniques for calculating the effect of heat recovery and

since the cost of cooling has been excessively high over the period

being reported, it is important to show the effect on costs of these

subsystem interactions as developed in this report. Data are presented

in table 6-5 for electrical energy cost with and without cost separation.

The following equations are used to calculate the electrical energy unit

costs based on total direct costs, without cost separation:

c' x = C' x/E e,f,s e,r e,n

c e,o,s

“ C e,o^

E e,n

c e,d,s

" C e,d^

E e,n

+ C e,d,s^

E e,s

The first column in table 6-6 shows the cost of site electrical energy

calculated by eqs. (15), (16) and (17). The second column shows the

cost of site electrical energy after recovered heat costs have been

allocated to the heating subsystem. The third column shows the final

cost of site electrical energy after the cost of chilled water energy

used by the electrical subsystem is included.

Quarterly and monthly unit costs are developed to provide additional

insight into the affects of plant operation on costs. It should be

noted, however, that it is not possible to reproduce the yearly unit

costs by any simple weighted averaging of quarterly or monthly unit

costs. Due to the form of the cost separation equations, the allocation

of total costs to the site energy commodities does depend on whether the

cost separation is done monthly, quarterly, or yearly. The total

allocated cost data presented in table 6-4 are based on applying the

cost separation equation to the full 12-month period. Legitimate

differences of up to 10% in these values can be obtained by summing

quarterly costs based on the unit cost data of tables 6-1 and 6-2 which

were developed by applying the equations quarterly.

(15)

(16)

(17)

106
6.4 Comparative Unit Cost of Utility-Supplied Electrical Energy

This section develops estimates of the cost of electricity if purchased from the local electric utility company and delivered to site

buildings. Existing rate schedules are used. These data are prepared

for the purpose of putting the JCTE plant costs into some perspective.

When these conventional electrical energy cost data are combined with

heating and cooling costs for conventional systems, an approximate

overall cost comparison with the TE plant can be accomplished.

The cost for electrical energy is based on the demand and consumption pattern of the reported JCTE "Net" electrical energy data presented

in table 2-1, which includes the site, HVAC and PTC. This electrical

energy pattern therefore is equivalent to that of a central conventional

HVAC plant utilizing absorption chillers, oil-fired boilers, and other

equipment in the same way as the existing JCTE plant but without the

electrical generation subsystem. It is felt that for this type of con- ventional central HVAC system, the costs developed for electrical energy

are quite accurate. Other types of conventional HVAC systems will have

different electrical demand and consumption patterns and therefore will

have different costs. Thus, the electrical unit costs presented represent only one case of a comparative conventional energy system and

therefore (when combined with conventional heating and cooling data) do

not answer the question of overall comparative economic viability of

Total Energy.

6.4.1 Electric Rate Structures

The local electric utility serving the areas adjacent to the Summit

Plaza site is the Public Service Electric and Gas Company (PSE&G). In

consultation with PSE&G personnel it was determined that the Large Power

and Lighting Schedule (LPL) would be applicable to the site if a central

conventional energy plant was installed at Summit Plaza. (Standby or "Breakdown" electrical service is currently provided by PSE&G to the

107
Summit Plaza site under the LPL rate.) Under the present situation of

including utilities in the rent, this rate would be the most attractive

available rate structure to the site owner/operator. (That is, it

affords the lowest cost energy to the site.)

The basic LPL rate has been revised upwards twice during the period

covered by this report. On November 7, 1975 the rate was increased approximately 14% for the demand/consumption levels of the site. On

October 20, 1976, the rate was increased again approximately 9%. The

energy adjustment charge (fuel adjustment charge) portion of the rate is

calculated by PSE&G on a monthly basis. In the period under consideration, this has varied over a range of +20%, with no discernable overall

trend.

6.4.2 Purchased Electric Energy Cost

Data for net electrical energy demand and consumption required by

the site, PTC and HVAC (as defined in section 2.1.1) for each month was

used for calculating purchased electricity cost. This amount of electrical energy consumption and electrical power demand is consistent with

the use of a conventional single-purpose central HVAC plant with absorption chillers and boilers (i.e. the existing JCTE plant less the enginegenerators and their auxiliaries). The monthly demand for billing purposes as stated in the rate schedule is based on the highest 15-minute

interval demand.

These demand and consumption data were used along with the appropriate PSE&G rate schedules and energy adjustment charges to determine

electricity cost. These data and results are shown in table 6-6. Costs

in table 6-6 vary considerably not just due to the site demand and con- sumption variations but also due to the monthly variations in the energy

adjustment charge.

108
6.4.3 On-Site Costs

The total cost of electric energy to site buildings in the utilitysupplied case must include the cost of on-site equipment necessary for

distribution of purchased electricity from a conventional HVAC central

equipment building (CEB). This on-site equipment includes CEB equipment

and site distribution. CEB equipment includes switch-gear, an emergency

generator and CEB space; this equipment relates to the total quantity of

electrical energy purchased. Site distribution equipment is nearly identical to that for the actual JCTE case and relates to electrical energy

delivered to the site. The reported capital cost of JCTE site distribution

(from table 3-£ ) , less $16,000 for equipment for standby service, can thus be used for the utility-supplied case. For the conventional CEB

equipment there is no such direct correlation with JCTE plant equipment.

Conceptual design and costing efforts for alternative systems are being conducted under contract to NBS for future comparative studies

as noted previously. The preliminary results of this work indicate that

the cost of switchgear, an emergency generator and central equipment building space for a conventional utility-supplied central HVAC case is at least equal to the cost of site distribution. (The complete

conventional system design and costing data will be the subject of a future report.) Therefore, as a conservative approximation, the added

capital cost for conventional CEB equipment is assumed equal to the re- ported cost of the JCTE site distribution in order to calculate the

total cost of site electrical energy in the utility-supplied case.

No additional 0 & M cost is added for the site electrical distribution or conventional CEB electrical equipment. The actual costs for

the JCTE plant presented earlier also did not include any 0 & M costs

for site distribution.

These plant and site distribution costs are added to the cost of

purchased electric energy by means of the following equation:

= c. + t / e,p e,p C *

I 109

(18)
where:

c = unit cost of electric energy delivered to the site, $/kWh

e s s

c* = unit cost of electric energy as purchased, $/kWh

e,p

C

1 = on-site plant equipment direct capital recovery cost, $

(= $198,000 x UCR)

C'e s = site distribution direct capital recovery cost, $

(= $198,000 x UCR)

E = Net electrical energy purchased, kWh

e,n

E = Electrical energy delivered to the site, kWh

e , s UCR = Uniform capital recovery factor

The added unit cost due to on-site equipment and the resultant

total unit cost for electric energy delivered to site buildings are calculated monthly by eq. (18) and results are presented in table 6-7.

The 12-month average electric energy cost to the site buildings is

4.15 <t/kWh

.

6.5 Comparative Cost of Conventional Heating & Cooling

In contrast to electrical energy there is no direct supply of hot

water, steam or chilled water energy from central utility sources in the

Jersey City vicinity. Thus, directly-comparable costs for a conventional

option to the JCTE plant are not readily available. As stated previously,

heating and cooling costs for conventional single-purpose plants can be

estimated based on separation of TE plant costs but this requires that

a conventional plant design be executed and analyzed. At this time, re- liance must be placed on published actual cost data from existing building complexes. In general, published data are either aggregated data

based on national -regional surveys of a particular class of building or detailed case study data based on a particular plant. In either case,

these data provide only an approximate indication of the cost of

possible conventional systems at Summit Plaza.

110
Several separate sources of aggregated data exist for the operating

cost of office buildings, apartments, campuses, shopping centers and

hospital facilities. One of these has been selected as the basis of

the initial comparison in this report.

The Building Owners and Managers Association International (BOMA)

publishes each year cost data for owning, operating and maintaining office

buildings. This data is based on a nationwide survey which, in 1975,

included a total of 1,023 individual buildings. Cost data is reported

in 16 cost categories. Respondees to the BOMA survey can report HVAC

0 & M costs either of two ways: in separate categories for heating and

air-conditioning-ventilating or in a combined HVAC category. Energy

costs are separately reported in a single category and not allocated to

HVAC, lighting, etc., nor identified by fuel type or average cost. Alterations (capital improvements) and fixed charges (i.e., capital re- covery) are also separately reported and not allocated. The BOMA data

provides a good source for HVAC 0 & M costs, exclusive of energy. Separation of fuel costs is desirable because of the great variability in

the cost of the various energy sources used in the surveyed buildings.

BOMA data is aggregated by region, city size and building characteristics: size, age and number of stories. Variations in HVAC costs due

to building size, age, stories and city size are much less than the variations due to location. By using data for the Middle Atlantic Region to

compare with JCTE, the most significant variations (probably due to

climatic and labor cost effects) should be excluded.

The BOMA report for calendar year 1975 provides the data shown in

table 6-8 for downtown buildings. Examination of these data in relation

to the entire data base indicates that the New York City data provides

a good basis for comparison with the JCTE data. The combined HVAC cost

for New York City compares well with Middle Atlantic and other locations.

The sum of the individual heating and A/C-ventilating costs also nearly

matches the combined HVAC value, although the sample size for the separate

111
reporting is small.

6.6 Preliminary Comparison of Unit Costs

A comparison of unit costs is presented here for the purposes of

adding perspective to the JCTE unit cost data of section 6.3. This

comparison uses the fairly accurate costs for purchased electrical

energy developed in section 6.4 and the approximate 0 & M costs for

conventional HVAC energy commodities presented in section 6.5.

It should be emphasized that the level of detail and scope of this

preliminary comparative analysis is an approximate indication of com- parative economics. Evaluation of economic viability should examine

alternative systems in detail and should consider various entrepreneurial

and societal measures for economic evaluation. The comparison presented

in this section is not intended to be a decisional basis for either a developer or utility or for TE policy decisions by governmental/

regulatory entities.

6.6.1 Electrical Energy Costs

Figure 6-2 compares the purchased electricity cost data from table

6-8 with the electricity cost of the JCTE plant from table 6-1;

As figure 6-2 shows, the electrical power cost of JCTE and the utility

supply are essentially equal given the approximations inherent in the

JCTE cost separation approach. Unit costs for electricity for the 12

months is 3.93<t/kWh for JCTE and 4.1 5<t/kWh for one conventional case of

a central HVAC plant (with absorption chillers) with utility-supplied

electric energy.

6.6.2 Heating & Cooling Energy Costs

The BOMA data presented in section 6.5 are developed on a cents per

square foot of building basis. The Summit Plaza site contains a total

112
of 547,400 ft^ (50,850 m^), excluding the CEB.

The heating and cooling subsystem 0 & M cost data for JCTE from

table 6-4 along with the BOMA data are used in the following comparison:

i

0 & M COST COMPARISON, ifr/ft

2

JCTE BOMA

Heating 17.3 20.2

Cooling VL5 ]1_J_

Total HVAC 30.8 37.9

The Individual BOMA heating and cooling values used above are based on New York City data from table 6-8 proportionately adjusted so that

the sum of heating and cooling is equal to the BOMA-reported "Combined

HVAC" category for New York City.

The BOMA data is exclusively collected from office buildings. In

using this data for a comparison with JCTE, a primarily residential site, some inconsistencies are obviously introduced. For example, office

buildings often require some space cooling year-round, thus increasing

2

the cooling costs on a t/ft basis. Also, their occupancy and resultant

load patterns can be significantly different than apartment buildings.

Office buildings are, however, often served by centralized HVAC systems

which may have much in common with a hypothetical central conventional

system for Summit Plaza.

Within the limitations stated above, the comparison shows that

JCTE heating and cooling 0 & M costs, other than fuel, are about the same as, or somewhat lower than, could be expected from a conventional

plant in the same geographical area.

The BOMA data generally include costs for maintenance of end-use

items (e.g. ductwork, fan-coil units) which are excluded from the JCTE

113
data base. This tends to shift the cost comparisons to favor JCTE.

The BOMA HVAC data excludes two non-allocated items (water supply and

plumbing) which are included in the JCTE data. For the Middle Atlantic

2

region, water supply and plumbing costs are 3.1 and 3.3 <£/ft , respectively.

A small portion of these items is probably allocable to the HVAC systems

in the BOMA data. The absence of these costs tends to shift the comparison against JCTE slightly.

6.7 Some Factors Influencing Unit Costs

Several factors which are known to have a significant influence on the

JCTE unit cost data are discussed below. The discussions are to make the

reader aware of some of the possible influences on plant economics which

will be reflected in future plant operating data and/or in future NBS analytical reports. A thorough and complete evaluation of the factors discussed has not been undertaken. Thus the magnitude of cost changes

presented herein are rough estimates only. Not all factors which could

affect costs in a major way have been identified and examined at this

time. Other factors may be of equal or greater significance than the

ones discussed.

6.7.1 Site Occupancy

During the 12 months under examination in this interim report, all

apartment buildings were essentially 100% occupied. However, the school was initially occupied in September, 1976 and the commercial building

has been only partially occupied (approximately 37% of floor space)

during the entire 12-month period. The design electrical demand and

consumption for these facilities, obtained from the plant design engineers,

is as follows:

Design Design

Facility demand, kW consumption, kWh

Commercial 191 950,300

School 60 199,000

Totals 251 1 ,149,300

114
The magnitude of these design loads indicate they may have a significant beneficial effect on the electrical energy unit cost since this

parameter is quite sensitive to net electric energy produced. It is

estimated that full occupancy of the commercial building and 9 months'

use of the school would add 753,300 kWh, a 12% increase In net electric

energy. Fuel costs are directly dependent on output and would increase

by approximately this amount. Other 0 & M and capital recovery costs

would remain essentially constant. Since fuel represents 41% of total

allocated costs, the 12% increase in fuel cost would result in total cost

increasing only 5%. Thus overall electrical energy unit costs could be

expected to decrease by approximately 6%. The effect of site occupancy

will be examined in detail in future performance reports if full occu- pancy of the commercial building is not realized.

The anticipated increase in electrical loads from full occupancy

would not greatly impact heating and cooling costs. The reduction in

boiler fuel due to the availability of additional recovered heat would

be offset by additional fuel costs transferred from the electrical subsystem to account for the additional recovered heat.

6.7.2 Chiller Operation

As the data of table 2-4 indicate and as discussed in section 4.5,

the performance of the chillers has been quite poor during the 12-month

period under analysis. Section 4.5 indicates that a 33% decrease in

energy consumption by the chillers can be expected with proper operation

and maintenance. This will lead to a significant reduction in site

chilled water unit cost because 36% of this cost is due to hot water

consumption by the chillers.

The 33% reduction in energy use by the chillers translates to a 26% decrease in energy output by the heating subsystem during the summer. The cost of in-plant hot water energy during the summer quarter

is equal to the value shown in table 6-2 less site distribution capital

115
recovery costs, or 7.28 $/MBtu. This value would increase to approximately

9.10 $/MBtu due to the reduction in hot water output. Using this value

and the reduced energy input for cooling, the total quarterly cost of

hot water used for production of chilled water is estimated to decrease

by approximately $23,800 or 19%. Site chilled water unit costs would

decrease by 9%. The 33% reduction in energy use by the chillers in- creases the annual unit cost of site hot water by about 10% due to the

reduced hot water output. Also, the cost of electric energy would de- crease slightly due to reduced cost of plant cooling.

6.7.3 Heat Recovery from Engine-Generators

Maximum recovery of heat from the diesel engine-generators is

vital for economical plant operation. Any heat recovery inefficiency is

reflected in high exhaust gas temperatures downstream of the waste heat

recovery devices indicating removal of less than the maximum possible

heat from the exhaust gases. During the 12-month period the stack ex- haust gas temperature averaged 440-475'°F (227-246°C), indicating only

partial recovery of heat. Exhaust gas temperatures upstream of the

heat recovery devices have averaged 570-660°F (300-350°C). It is felt

that the heat recovery mufflers could be designed to lower the average

exhaust temperature to 350°F (177°C) without danger of low-temperature

corrosion. If this were done, calculations show that an increase of

about 20% in the total thermal energy recovered from the engines could

be obtained.

This additional heat would substantially change the cost separation

results. Electrical energy unit costs would decrease approximately 10%

due to the allocation of a larger portion of electrical subsystem direct

costs to the heating subsystem. Hot water unit costs would increase

since the reduction in boiler fuel cost would be more than offset

by the added fuel , 0 & M and capital recovery direct costs allocated

to the heating subsystem. This dichotomous situation occurs because the

original formulation of heat recovery cost separation (in section 6.2.1)

did not include the maximum possible heat recovery as a basis for

116
allocating costs to the heating subsystem. However, overall plant

economics would improve since less fuel would be used while providing

the same services to the site.

The exhaust gas temperature of a diesel engine decreases as the

load is decreased. For this reason, the average level of exhaust gas

temperature leaving the heat recovery mufflers is dependent on maintaining a minimum exhaust temperature of about 300°F (150°C) during minimumload operation. The impact of this requirement is mitigated when engines

are operated so as to achieve a high average load, i.e. shutting the

third engine down when two engines can carry the load reliably. The

combination of optimal engine operating criteria and improved exhaust

heat recovery design may possibly achieve an increase in total heat

recovery greater than the 20% stated above. Efforts are currently being

made by the JCTE plant operator to improve heat recovery within the

constraints of the equipment now in place.

6.7.4 Plant Cooling

As discussed in section 4.4, it is desirable to reduce or eliminate,

if possible, the use of chilled water to cool plant ventilation air in

order to reduce fuel consumption. Sixteen percent of total chilled

water production is used within the CEB. The economic effect of com- plete elimination of plant cooling is shown in table 6-6 to be a de- crease in annual average electrical energy unit cost of 0.38 <t/kWh, or a 10% reduction. During the summer quarter, the decrease is more

dramatic, 0.80 <t/ kWh

.

The effect of plant cooling on electrical energy unit costs for

June through October is not readily apparent in the data of table 6-5.

This is because of the opposing effect of increased electrical energy

production for the cooling subsystem auxiliaries. (See section 2.3.1

for a discussion of chiller electrical loads.) The dual effect of

plant cooling and increased electrical output on the unit cost of electrical energy is shown in figure 6-3. Note that the unit cost during the

summer season would be approximately 3.1 <£/kWh if plant cooling is eliminated entirely.

117
The unit costs of hot water and chilled water energy would increase

slightly if plant cooling were reduced or eliminated since a smaller

quantity of output would be produced. Total plant costs would of course decrease and overall plant economics would improve.

6.7.5 Miscellaneous Reductions in Losses

Sections 4.1, 4.2 and 4.3 examine three possible actions to reduce

plant thermal losses:

* bypassing the idle boiler,

* bypassing one idle engine and

' improving waste heat management.

Using the approximate fuel oil savings for each of these actions

from the referenced sections, the impact on unit cost can be roughly

estimated. The fuel oil savings is obtained by reduced firing rates for the

boiler for a given net heat output by the heating subsystem. As stated

in section 4, the estimated aggregate fuel oil savings for the three

actions is 35,500 gal (134 m

3

), or $12,105 at an average of 34.1^/gal.

The cost of in-plant hot water energy is equal to the value shown in

table 6-3 less site distribution capital recovery costs, or 8.82 $/MBtu.

This would decrease to 8.62 and would decrease the unit cost of site

chilled water as well as site hot water. The decrease in annual site

hot water unit cost is approximately 2 % while the decrease in site

chilled water unit cost is less than 1%.

118
PLANT

COOLING

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energy

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120

Figure

6-2.

Electrical

Energy

Cost

Comparison
ELECTRICAL

ENERGY

SITE

ELECTRICAL

CONSUMPTION

-

MWh

ENERGY

COST

-

(/kWh

Figure 6-3. Effect of net electrical energy

consumption and plant cooling on unit cost

121
—

FaTI

quarter 1.57 1.16 CO

3.91

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123
Table

6-3.

Cost

of

site

thermal

and

electrical

energy

UD

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124
Table

6-4.

Total

allocated

site

costs

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125
Table 6-5. Monthly unit cost of site electrical energy

Month Site energy*, kWh Cost, tf/kWh

Nov. 75 482,400 4.19

Dec. 536,100 3.53

Jan. 76 533,200 4.25

Feb. 503,900 3.81

Mar. 524,300 3.83

Apr. 480,800 3.91

May 484,900 4.21

Jun. 563,300 3.72

Jul

.

573,800 3.86 •

Aug. 567,300 4.08

Sept. 542,900 3.78

Oct. 528,100 3.68

12 months 6,321,000 3.93

* Includes site only, does not include HVAC or PTC energy

requirements. Data is from table 2-1, column entitled

"Site and PTC Load", less a constant 3500 kWh per month

for the PTC consumption (see section 2.1.1) and rounded

to nearest 100 kWh.

126
Table

6-6.

Effect

of

cost

separation

on

cost

of

site

electrical

energy

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127
Table 6-7. Cost of purchased electrical energy

PSE&G rate schedule "LPL"

Month

Net energy

consumption*

kWh

Net billing

demand

kW

Total

cost**

$

Unit

cost

<t/kWh

Nov. 75 557,175 1070 21,935 3.94

Dec. 616,201 1145 21,176 3.44

Jan. 76 616,143 1144 23,130 3.75

Feb. 578,034 1147 20,287 3.51

Mar. 603,548 1118 22,504 3.73

Apr. 547,834 1037 19,445 3.55

May 555,461 1019 19,087 3.44

Jun. 753,093 1326 26,214 3.48

Jul

.

786,973 1303 28,880 3.67

Aug. 802,647 1364 28,284 3.52

Sept. 757,522 1354 24,949 3.29

Oct. 608,794 1254 21,525 3.54

12 months 7,783,425 14,281 277,416 3.57

* includes site, PTC and HVAC auxiliaries (from table 2-1)

** includes energy, demand & fuel adjustment components

128
Table 6-8. Unit cost of site electrical energy

when supplied by utility

Month Site

energy*

kWh

U nit cost, <t/ kWh

Purchased

On-site

capital

recovery Total

Nov. 75 482,400 3.94 0.65 4.59

Dec. 536,100 3.44 0.59 4.03

Jan. 76 533,200 3.75 0.59 4.34

Feb. 503,900 3.51 0.63 4.14

Mar. 524,300 3.73 0.60 4.33

Apr. 480,800 3.55 0.66 4.21

May 484,900 3.44 0.65 4.09

Jun. 563,300 3.48 0.52 4.00

Jul

.

573,800 3.67 0.51 4.18

Aug. 567,300 3.52 0.51 4.03

Sept. 542,900 3.29 0.53 3.82

Oct. 528,100 3.54 0.59 4.13

12 months 6,321,000 3.57 0.58 4.15

Season

Winter 1,573,200 3.57 0.60 4.17

Spring 1,490,000 3.58 0.63 4.21

Summer 1,704,400 3.56 0.51 4.07

Fall 1,553,400 3.52 0.65 4.17

* Includes site only, does not include PTC and HVAC energy requirements.

Data is from table 2-1, column entitled "Site and PTC Load", less a con- stant 3500 kWh per month for the PTC consumption (see section 2.1.1) and

rounded to nearest 100 kWh.

129
Table 6-9. Cost of conventional space heating and cooling

Regional aggregation <t/f1: 2

(# buildings ) * Heating A/C-Vent Combined HVA(

New York City 20.5 (3) 18.0 (3) 37.9 (39)

Middle Atlantic ** 9.9 (57) 16.2 (51) 36.6 (87)

All U.S. 9.1 (245) 13.3 (215) 27.5 (419)

* ./f

.

O&M costs only, no fuel or capital recovery

‘ total building floor area

# buildings: number of individual building responses in the

regional/cost category aggregations.

** Middle Atlantic Reg.; New England states plus NY., PA., MD., DE.,

NJ., DC.

*** Data is from calendar year 1975 BOMA data for downtown buildings

from reference 7.

130
7.0 Reliability and Maintenance

7.1 Electric Service Reliability

The Jersey City Total Energy plant is designed to provide highly

reliable electrical power for the site buildings. The plant has five

diesel engine-generators; any three of these units can meet the plant

and site electrical demand. Automatic controls regulate these engines,

keeping their voltage and frequency constant. The controls also will

start and parallel an additional engine or stop an engine in response

to electrical demands. Should an engine malfunction occur, the controls

can stop an engine and shed load (cut power to non-vi tal loads in a predetermined sequence) if the remaining on-line engine-generators are overloaded. Should the plant go down, other controls automatically

connect site essential buses to the local utility buses. The essential

buses provide back-up power for restoring plant power and for site

emergency lights, fire protection, and elevators. Any time a malfunction

is encountered by the automatic controls, a signal is sent to a telephone

center and the plant engineer is notified via his radio call device (beeper).

The automatic controls, stand-by engine, and operator beeper have

resulted in reliable electric power production. From November 1975

through October 1976 the plant supplied the site with power 99.8% of

the time.

There were eleven electrical outages in the period from November

1975 through October 1976 (see table 7-1). These outages ranged from

10 minutes to 4.5 hours in duration and had a cumulative duration of

approximately twenty hours. Six of the outages were caused by

electrical control system malfunctions. These outages had a cumulative

duration of approximately seven hours. Two of the outages were caused

by fuel control system problems and had a cumulative duration of approximately

three hours. The other three outages were related to maintenance and

modification of the electrical control system. These outages had a cumulative

duration of ten hours. Two of these were planned outages. Descriptions of

131
the outages follow. These descriptions are based on an engineering analysis

of data from the plant engineer's logs, kilowatt strip-chart recordings,

the plant operator, utility electric bills, the DAS, the daily NBS logs

and reports by authorized persons present during the outages.

The first outage of this one year period occured at 2:47 am on February 14, 1976 and lasted several hours. The plant engineer was beeped at home, came to the plant, and quickly restored power. He

diagnosed the shut down as resulting from spurious overspeed alarms.

To restore engine-generator operation, he temporarily disconnected the

faulty overspeed alarm circuits. Later that week an electrical controls

consultant found that most of the speed switches were not operating

according to specifications.

The second outage occured at 2:29 pm on February 14, 1976 and lasted

for 10 to 20 minutes. The plant engineer was in the plant and quickly

restored electrical production. This outage was probably caused by the

same controls problem as the first outage.

The third outage occured on Sunday morning, February 15, 1976, and

lasted for several hours. The outage was not related to the February 14

outages. The plant engineer was beeped while in his car. He drove

directly to the plant and diagnosed the problem as a malfunction in the

automatic equipment which switches the plant fuel supply from one underground storage tank to another. The plant engineer manually switched

the storage tank valves, bled the air from the engine injectors,

restarted the engines, and put them on-line.

The fourth outage occured at 4:50 am on February 21, 1976 and

lasted three hours. This outage was planned by the plant operator

so that the plant engineer and an electrical controls consultant

could clean, tighten, and adjust the engine-generator control equipment.

Site occupants were notified in advance of this outage.

132
The fifth outage occured at 2:15 am on March 2, 1976 and lasted

approximately one and one-half hours. The plant engineer was notified

at home by the site resident manager. Responding to the call, the plant

engineer found generator circuit-breaker alarms on four engines and

the fifth engine showing an excessive start-time alarm. He restarted

three engines and put them back on-line. These events imply a malfunction of the engine-generator control equipment.

The sixth outage occured at 5:05 pm on August 4, 1976 and lasted

approximately ten minutes. The plant engineer was in the plant when

the outage occured and he restarted the engines and put them back on-line.

The exact cause of the outage is not known, however, for several hours

preceeding the outage the generator bus voltage had been dropping

from 480 volts to 425 volts, implying the outage was caused by the

engine-generator control equipment. The problem may have been

relieved as the plant engineer readjusted the voltage and frequency

of the individual engines while he was putting them back on-line.

The seventh outage. occured at 10:27 am on August 5,1976 and

lasted for approximately ten minutes. This outage was caused by an engine control circuitry problem.

The eighth outage occured at 9:00 am on August 12, 1976 and lasted

several hours. The outage occured when four fuses where jarred lose

by an electrical controls consultant during servicing of the electrical

control equipment. The consultant restored plant operation.

The ninth outage occured at 9:15 am on August 17, 1976 and lasted

four and one-half hours. This was a planned outage, made so that

modifications could be made to the electrical control equipment and

the plant switchgear. Site occupants were notified in advance of this

outage. During this outage it was necessary to cut off utility power

from the essential buses to modify several 480 volt circuits.

133
The tenth outage occured at 8:12 pm on October 4, 1976 and lasted

for two or three hours. The plant engineer was beeped in his car. The engines had gone down showing overspeed alarms. During the process

of restoring plant operation, the plant engineer found large variations

in the output voltages and frequencies of the individual enginegenerators, suggesting that they were maladjusted or that the engine

control equipment was malfunctioning.

The eleventh outage occured at 8:26 pm on October 15, 1976 and lasted

approximately twenty minutes. This outage was caused by an engine-generator

fuel shortage from a failure in the engines' back up fuel system.

In summary, the plant supplied electrical power to the site for

99.8% of the reported year. Most outages were due to malfunctions

in the plant electrical control systems.

7.2 Equipment Maintenance and Reliability

Plant maintenance is accomplished by the plant engineer, his two

assistants, and several outside contractors who perform the maintenance

on specalized plant equipment. Because the plant was designed to

operate automatically, the plant engineer and his assistants work only

a weekday shift. The plant engineer notifies outside contractors

when routine engine, boiler, or chiller maintenance is necessary or when

one of these devices malfunctions. The routine contracted maintenance

operations include: 1,000 hour engine service; minor engine overhauls;

muffler cleanings; cleaning, inspection and adjustment of the chillers;

and cleaning, inspection, and adjustment of the boilers. The plant

engineer also routinely sends samples of the engine lube oil for chemical

analysis to detect engine problems. The plant engineer and his assistants

service and repair most other plant mechanical equipment.

The plant equipment reliability, as documented by the plant log

has, in general, been good. Most maintenance which has been performed

has been routine or to repair statistical or expected failures. However,

134
several systems have required a larger than expected share of maintenance.

Examples of these types of problems will be discussed in the following

paragraphs.

The electrical control equipment has shut down one or more

individual engines more than twenty-five times in the last year.

The plant log Indicates that very few of these shutdowns were due to an actual engine problem. Most shutdowns were related to problems in

the engine control equipment. Problems have included out-of-specification

sensors, malfunctioning circuitry, overheated circuitry, and blown

fuses. The variety and number of problems related to the electrical

control equipment seems excessive for properly designed, installed,

and adjusted control equipment.

Seven secondary hot water pipes in site buildings have split from

freezing. The reasons given for this splits have included low flow rates

due to inadequately wired pumps and low flow rates due to accumulation

of dirt in the pipes.

Problems have been encountered with the absorbers including difficulty

in starting them at the beginning of the cooling season, splits in

their air lines, and blown and improperly installed gaskets. As pointed

out in section 4.4, the chillers have had periods of very low COP

operation.

Although the PTC system is not considered as a part of the total

energy plant, previous to the reported year it has occupied a large

amount of plant personnel time. At least thirty times during the

reported year the PTC has shut down or discharge valves have jammed and

required manual intervention to restore operation. However, most of

the major initial problems of the PTC have been corrected.

135
Table 7-1

Summary of electrical outages from

November 1975 through October 1976

Date Beginning

of Outage

Duration Probable Cause

Feb. 14, 1976 2:47 am several hours electrical controls

Feb. 14, 1976 2:28 pm 10 to 20 minutes electrical controls

Feb. 15, 1976 several hours fuel supply equipment

Feb. 21, 1976 4:50 am 3 hours planned outage

Mar. 2, 1976 2:15 am 1 .5 hours electrical controls

Aug. 4, 1976 5:05 am 10 minutes electrical controls

Aug. 5, 1976 10:27 am 10 minutes electrical controls

Aug. 12, 1976 9:00 am several hours maintenance error

Aug. 17, 1976 9:15 am 4.5 hours planned outage

Oct. 4, 1976 8:12 pm several hours electrical controls

Oct. 15, 1976 8:26 pm 20 minutes fuel supply equipment

Essential buses used utility power for a total of 18 hours

136
Acknowledgment

The authors wish to acknowledge the contributions of Charles Bulik

and Dan E. Rorrer In the collection and processing of JCTE engineering

data. Charles Bulik has directed the debugging, the calibration,

the maintenance and the upgrading of the JCTE on-site instrumentation

and data acquisition system. Through Mr. Bulik's efforts the

instrumentation system was made operational, kept operational, and

has been Improved in accuracy. Dan E. Rorrer has developed the

equations, engineering techniques, and computer software necessary

to convert the raw data from the 5-minute site data tapes into

engineering data. Furthermore, Mr. Rorrer has developed computer

systems which permit rapid and simple accessing of this data in

numerical or graphical form. Both Mr. Bulik and Mr. Rorrer are in

the Mechanical Systems Section at NBS.

137
Appendix I

Engineering Monthly Data Summaries

138
Appendix I

Engineering Monthly Data Summaries

1. Schematic Diagram of System and Related Items Listed in

the Monthly Summaries.

2. Definition of Terms Used in Presenting Monthly Engineering

Performance Data.

3. Monthly Summaries of Engineering Data for November, 1975

through October, 1976.

4. Monthly Summaries of Engineering Data with Fuel Measurements

and Comparative Analysis for May, 1976 through October, 1976.

139
140

Figure

1-1

Energy

flow

diagram

Bracketed

letters

refer

to

Items

in

tables

in

this

appendix
DEFINITION OF TERMS LISTED IN ENGINEERING PERFORMANCE DATA

ELECTRICAL ENERGY

A. Gross Generated Is the total electrical energy produced by the

generators. This measurement is made by both a DAS transducer

and a kilowatt-hour meter connected to the main bus from the

generators.

B. Net (Required If purchased from utility) is the amount of electrical'

energy generated minus the electrical energy used in the electrical

production process. The net electrical energy is determined by

summing the measured site electrical consumption, the measured PTC

consumption, and the computed electrical energy required for boiler

and chiller operation. The boiler and chiller electrical energy

consumption is extrapolated from boiler and chiller thermal output data.

The difference between net and gross electrical energy is approximately

equal to the electrical energy required by the engine-room exhaust fan,

the primary loop pumps, the engine oil -cooler pumps, and the dry

cooler fans.

C. Site consumption including PTC exhauster and compactor is the electrical

energy required by the site not including the CEB. Energy for the pneumatic

trash collector (PTC) exhauster and compactor is included. The electrical

energy required for the air supply for the PTC pneumatic controls is not

included. Electrical energy data is measured by DAS transducers.

HVAC processing in plant reports the electrical energy required to

operate the boilers, the chillers (including the cooling towers),

and the secondary hot and chilled water circulation pumps.

141
THERMAL ENERGY ADDED TO PHW LOOP

D. Thermal Energy Recovered from Engines reports the total amount of

thermal energy added by the engine jackets and exhaust exchangers to

the primary hot water (PHW) loop. This quantity is measured by DAS

instrumentation for the total PHW flow rate through all five engines

and for the PHW temperature differential across the entire engine

bank. This quantity includes the heat added to the PHW by running

engines minus the heat lost from the PHW by idle engines.

E. Thermal Energy Recovered from Boilers reports the total amount of thermal

energy added by the boilers to the primary hot water (PHW) loop. This

quantity is measured by DAS instrumentation for the PHW flow rate through

the boilers and for the PHW temperature differential across the boilers.

This quantity includes the heat added to the PHW by firing boilers minus

the heat lost from the PHW by idle boilers.

F. Total Thermal Energy Recovered is the sum of the thermal energy recovered

from the engines and the boilers. It represents the total thermal energy

added to the PHW by running engines and firing boilers minus the thermal

energy lost by idle engines and idle boilers.

THERMAL ENERGY CONSUMED

G. Thermal Energy Extracted from the PHW loop to Produce Hot Water is the

amount of thermal energy removed from the primary hot water (PHW) loop

by the two site heat exchangers. The site heat exchangers transfer

thermal energy from the PHW to the secondary hot water loops which

circulate from the central equipment building (CEB) to the site buildings.

This quantity is measured by DAS instrumentation for the PHW flow rate and

for the PHW temperature differential across the exchangers.

142
H. Thermal Energy Extracted from the PHW Loop to Produce Chilled Water

is the amount of thermal energy removed from the PHW loop by the two

absorption chillers. These chillers use PHW thermal energy to produce

chilled water which is circulated from the CEB to the site buildings.

PHW thermal energy extracted by the chillers Is measured by DAS

"instrumentation for the PHW flow rate and for PHW temperature difference

across the chillers.

I. Total Thermal Energy Extracted from PHW Is the amount of thermal

energy removed from the primary hot water (PHW) loop by the heat

exchangers and by the absorption chillers. This quantity reports

the thermal energy which was supplied to the secondary hot water

loop for heating and domestic hot water production and to the

absorption chillers for production of secondary chilled water.

Two measurements, PHW heat consumed by the heat exchangers (G)

and PHW heat consumed by the chillers (H), are summed to determine

this quantity.

J. Thermal Energy PHW Loop Losses: Input MINUS Output is the difference

between the thermal energy supplied to the primary hot water loop (PHW)

by the engines and boilers (F) and the thermal energy removed from the

PHW loop for site use by the site heat exchangers and the absorption

chillers (I). This quantity reports thermal energy removed from the

primary loop by the dry coolers, by the emergency heat exchanger, and

by some of the piping losses. Most of this quantity represents PHW heat

removed by the dry coolers via continuous convective losses and via heat

dumped during running of the dry cooler fans.

K. Thermal Energy Released in Secondary Hot Water System is the amount

of thermal energy supplied to the secondary hot water system by the

site heat exchangers. This quantity is measured by DAS instrumentation

for secondary hot water flow rate and temperature differential. Within

the limits of measurement accuracy, the thermal energy released in the

secondary system equals the thermal energy extracted from the PHW to

produce site hot water minus heat exchanger losses to the surroundings.

143
L. Thermal Energy Absorbed by Secondary Chilled Water System reports the

total amount of thermal energy absorbed by the chillers from the

secondary chilled water system which supplies cooling to the site

buildings and to the CEB. This quantity is equivalent to the total

chiller output and is measured by DAS instrumentation for the secondary

chilled water flow rates and temperature differentials across the

chiller.

M. Thermal Energy Absorbed by the Secondary Chilled Water System from Site

reports the thermal energy absorbed from the site by the secondary chilled

water. This quantity is computed by subtracting the chilled water used

in the CEB from the total chilled water produced. Both these quantities

are measured by DAS instrumentation for water flow rates and temperature

differentials. Most of the chilled water used to cool the CEB was used

to cool the engine-generators space.

FUEL CONSUMPTION

AA. Fuel Oil Heat Content reports the energy available by completely

combusting one gallon of the plant fuel oil. The fuel oil heat

content is determined by averaging weekly values of the fuel 's higher heating value (HHV) reported by a testing laboratory.

Fuel oil samples are taken from the day tanks which supply

the engines. Both the engines and boilers use the same fuel.

BB. Fuel Consumed by Engines reports the total amount of fuel oil consumed

by the engines. This quantity is measured by a manually-read meter

recording the amount of fuel which is pumped into the engine day-tanks

from underground storage tanks. The fuel system maintains the

day-tank level within 30 gallons, to provide an accurate measurement

of monthly engine fuel consumption.

CC. Fuel Consumed by Boilers reports the total amount of fuel oil consumed

by the boilers. This quantity is determined from the difference

between two manually-read meters; one which records the total fuel pumped

to the engine and boiler day-tanks and the other which records fuel

pumped into the engine day-tank . This quantity has good accuracy

except during months of mild weather. During these months, boiler fuel

consumption may be only 10% of the total fuel consumption causing the

accuracy of boiler fuel consumption data to be 6% to 15%.

144
DD. Total Fuel Consumed at Site reports the total amount of fuel consumed

by the engines and boilers. This quantity is measured by a manually-read

meter which records the total amount of fuel oil pumped up to the engine

and boiler day-tanks.

PLANT PERFORMANCE

The operating efficiencies address both individual plant components

and overall plant performance. The first four indices, engine electrical

efficiency, engine electrical plus thermal efficiency, boiler efficiency,

and chiller COP, describe component performances. The last two Indices,

electrical production efficiency and plant effectiveness, describe overall

plant performance.

EE. Engine Efficiency in Producing Gross Electrical Energy reports the

engine-generator electrical efficiency for the total power produced.

This efficiency is determined by dividing total electrical energy

produced by the generators (A) (using the 3412 Btu per kWh conversion

factor) by the energy in the consumed fuel (gallons of fuel consumed

(BB) times its heat content per gallon ( AA ) )

.

FF. Engine Efficiency in Producing Gross Electrical Plus Thermal Energy

reports the efficiency of electrical plus thermal energy production

by the engine bank. This efficiency is determined by dividing the

total electrical energy produced (A) (normalized to BTU's) plus total

thermal energy recovered from the jackets and exhaust exchangers (D) by

the total heat content of the consumed fuel (AA • BB). Electrical

plus thermal efficiency is based upon heat recovered across the bank

of engines; losses from idle engines reduce this efficiency.

GG. Boiler Efficiency reports the total thermal energy added to the PHW by

the boilers (E) divided by the energy content of the consumed fuel (gallons

of fuel consumed (CC) times its heat content (AA)). In that the heat

recovered includes losses during periods when the boiler is idle, the

reported boiler efficiency will decrease during low usage months. The

accuracy of the boiler efficiency reflects the accuracy of the boiler fuel

measurement and may degrade to 5% to 10% during low usage months.

145
HH. Chiller COP reports the total thermal energy extracted from the

chilled water by the chillers (L) divided by the total thermal energy

consumed from the PHW by the chillers (H)

.

AAA. Btu of Fuel per kWh of Net Electrical Energy Production reports the

engine-generators' efficiency in producing the electrical energy

required by the plant and site (B). This quantity is computed by

dividing the total heat content of engine fuel (AA • BB) by the net

electrical energy produced (B). The Btu per kWh form can be compared

with the efficiencies of the local electrical utilities. In computing

this efficiency, net electrical energy rather than total generated

electrical energy is used because the electrical energy used to operate

the electrical plant is not usable by the site or HVAC equipment. In

1975, the local utility at Jersey City distributed electrical energy

with an efficiency of 11 ,451; Btu per kWh.

BBB. Energy Effectiveness in Meeting Site Demands reports the sum of the

energy conveyed by the three plant products; site electric power (C),

site hot water ( K) , and site chilled water (M); divided by the energy

content of the total fuel consumed by the site (AA • DD) . The energy

effectiveness is not a direct measure of thermal efficiency due to the

second-law operation of the chillers. It is a relative measure of the

effectiveness of plant energy usage.

146
COMPARATIVE ANALYSIS OF J.C.T.E. PLANT WITH CONVENTIONAL PLANT USING

CHILLERS AND PURCHASED UTILITY POWER

The comparative analysis section of the monthly summary compares the

total fuel used by the J.C.T.E. plant with the fuel required by an electrical

utility and a boiler for a central plant in which electrical power is

purchased from the local utility, boilers produce secondary hot water,

and absorption chillers produce secondary chilled water. The electrical energy,

hot water and chilled water required by the site are determined from reported

data on net electrical energy, thermal energy released in secondary hot water,

and thermal energy absorbed from site by the secondary chilled water system.

In this analysis, the "conventional system" is not required to produce 1)

electrical energy used by the T.E. site for electrical energy production,

2) thermal energy to make up primary loop losses, or 3) chilled water to

air condition the engine-generator facility. Utility electrical production

efficiency is obtained from local utility annual reports. Boiler and

chiller efficiencies used in the "conventional system" are obtained from

T.E. boiler and chiller data reported in the summary. It should be noted

that during the first two summers of operation the COP of the hot-water-driven

T.E. absorption chillers is significantly below the COP of other absorption

chilling systems and compressor chilling systems.

The total fuel used by a "conventional system", in which electric energy

is purchased and hot and chilled water are produced by a central oil-fired

boiler, and absorption chiller, respectively, is computed in three parts. The

first part is the fuel required by a utility to produce the net electric energy

(LL). This quantity (LL) is computed by multiplying the net electrical energy

(B) required by the T.E. site (including T.E. HVAC processing and the pneumatic

trash collection system) times the local utility's efficiency in distributing

electric energy (Btu per kWh) ( KK) divided by the heat content per gallon of

fuel oil (AA). The second part is the fuel required by boilers to produce

secondary hot water (NN). This quantity (NN) is computed by dividing the

thermal energy released in the T.E. secondary hot water system (K) by the

T.E. boiler efficiency (GG) and the fuel oil heat content per gallon (AA).

The third part is the fuel required by a boiler-absorption system to produce

chilled water (QQ). This quantity (QQ) is computed by dividing the site

147
thermal energy absorbed by the T.E. secondary chilled water (M) by the

combined boiler and absorber COP (PP) and the heat content per gallon

of fuel oil (AA). The above technique assumes the COP of the "conventional"

plant hot water absorber is similar to the COP observed for the J.C.T.E.

plant absorber.

During the first two summers of operation, the COP of the T.E.

absorbers was significantly different from commonly referenced COP for

absorption chillers. Common reference handbook values for single stage

absorption chiller COP range from .6 to .7. Assuming a boiler efficiency

of 85%, the combined boiler-absorber COP would be .5 to .6. Common

values for the motor-compressor COP of a compressor chiller are 2.5 to 3.0.

Assuming an electric generation efficiency equal to the local utilities

efficiency of 30% (3412/11451), the compressor chiller has an end-to-end COP

of .75 to .9. Thus, the range of COP which might be used to compare a "conventional" plant to the J.C.T.E. plant could range from .5 to .9.

Computation of the total fuel required by the "conventional" system

( RR) involves summing the fuel used by the electric utility for electric

energy production (LL), plus fuel required by a boiler to produce the

site hot water (NN), pi us. the fuel required to operate the boiler-fired

absorption chiller (QQ). Additional fuel required by "conventional" plant

(UU) is computed by subtracting the fuel used in the T.E. plant (DD) from

the fuel extrapolated for a "conventional" plant (RR).

148
Engineering

Performance

Data

Total

Energy

System,

Jersey

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1975

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1976

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151
Appendix II

Economic Monthly Data Summaries

152
Table

1

- 1.

Direct

O&M

costs

-

November,

1975

153
Table 11

-2.

Direct

O&M

costs -

December

1975 , IX} +-> o+->

+-> c

fO o CTl CM , *3’ ro o ro |— CO to Ol to co ro to CM CM

rt #» 0* cn LO LO r— cn

CM

co- & o o O O o to 1— O Ol. to

#» #»• r— P-— CO- COOl o O o o o G CO CO cr= LO LO r~ E o

CU o

+-> t_> to CO- CO- >4

c/r JD3

CO crc1 to o CO l— o to fscma •r* o to CO CM CO

+j to LO CT> fO #* •* CU CNJ CM r— T'. n: r— r— CO COrd *d- O'! CO i— o CM u cr. to to o ro o •r— cn ro to CT> r-». f''- S- *> •» «t -M to LO ro CM c^ O r— CM

cu UJ CO COoc • o r—

+J + «3 c •r“ 00

•r— sC %, 3

rd o <u CU o E «Q •o 4-> cu >! <o S- cd c

i. -(-> r— 3 E «o o o JD f—

Ol +-> +J r—

aj> S- o -M

u 0J

4-> r—4-> cu

C CU c_> •0 cu c S- fO %, to u 3 o •r— r— •r= •r- to

Li- o Q Q_

Q 21 f—

-M Id

<un 4-® o • • • • • • o o 1— CM ro to to H

154
Table

1

1

-3

.

Direct

O&M

costs

-

January

1976

155
Table

1

1

-4

.

Direct

O&M

costs

-

February,

1975

I

156
Table 11

-5.

Direct

O&M

costs -

March,

1976

rd

+-> O 00 oo CM VO OO

O CO

+> CO CM CM LO o r— o LO CM r-* LO CM

+J •> 0> 0» 0» •» C un 00 CM CO

fd CM r—

Q_ (Si / O o 00 O o o 00 (J 00 LO o

l— CM 1

LO

o_ * •» ' r— vo (Si- o o O o LO O lO

VO VO

•r— r—

E o

<D

4-> o

<_> (Si (Si

V)>,

(A

_Q

Z3

(Si crc 1 LO OO 00 o- o

•r- CM 00 CM oo o

4-> VO 00 CTl VO r^.

9% CM o

fd<u 00 CM •— LO

rn (Si

fd co , 00 0- o VO u uo O VO i— cn LO CTl •r- LT> CM CM CM t

0% e* 0% 4-> UO VO *3" CM J

U r— CO

<u’ VjO UJ

re • o ITTM +J + fd c in

•r— J- c i. 3

fd o eu OJ

O E JO a +J (1> >5 fd $- fd tz

S- +-> r— Z3 E fd o u JO r—3 cr fd -m +J

<L> s- o +» o <u +J r— +-> <u C Of o

fd 0J> c i. fd s_ to u o •r— r— •r— •r— «A u_ o a Q_ Q s: r—

4-> «d +J o • • • « • • o . . o '

CM oo LO VO 1-

157
Table 1

-6.

Direct

O&M

costs -

April,

1976 , «3

+-> r— CT> in CO f"* o in O r—- CXi o 00

+-> ro on o in o o * #1 4-> cn 1 CO <3- CO m C r— l—»

id tO to

o_ ' O o CO o o CM

r— CM o CM tj- in 1—

O- ' ' <0 to

Olc o O

O o CM

rTM in in

r-=

C\J in 00 E o

«•» 9% <u

+-> in oo to

to

>jtA

JQ3

to Ol *d- r^. CO , 00 o CO

>d- CO r— in CO 1 * cr> O CO CO 00 o #> rt 9> rd

CD CO •d- CM 1— CO

:n to- to

id , in 00 o 00 o* in ID CO in o CO r-. o in in

S- 9* #* 9* #» +J in in CM f—

cr> o

05 r_ CM

LU to to • o ff—

+-> + <d c •r— in

•r— sC t. 3

id o <u CL)

O E JD *o •M 0) >i id £_ fd e

s_ +j r— 3 E id o O m r—

er id +-> +-» ff— 0) s- 4-» o ©

-M 4-» a» c <u

a

*d 0) e k. id 1,m o 3 o Off— ff— er— •r— in

Ll_ c_>

Q CL.

Q s: r—

+J <d

in 4-» © • • • • • • o ; o f— CM co in in h158
Table 1

-7.

Direct

O&M

costs -

May,

1976

r—m+-> o CTi (XI co d- CO o VO

+-> o oo CO o r— C\J o 04 cn LO

+-» #» •N •» •» 9\ c CO o CO r— | «a '

1

CL bO

J o O CO VO o o cn o r— 00 LO dh" uo 04 00 CL r* 1 bO- bO

0TJ o r-*. LO o VO CO c cn CO 00 CO cn

VO r- 04 r—

9L E

OS oo

bO- " 1

4-> oLO>1

(A

-O

CO CT VO VO LO

O CO 1— cn LO LO VO 04

+J 00 00 00

— CO

<d

•Mr,' r— cvj VO

:n bO- bOrO CO 1 04 d" o d- o CO d- LO CO LO CO

•r- 04 o O cn 04 CXI

9V e% 91 #*

A

+-> VO r^. LO t r— 1 O r— CO

Ol bO- bO- UJ c • o 0=— +J + (d c •r* in

®r* s_ c i-

<d o <u 0J o E X3 •o 4-S m

>1 fO S- <d c.

S- +-> F— E <o o O JQ tp=-» CT id +» +»

as sO +J o as r— +-> <U c 0) o

<d 01 £Z

u £-

m o o •r— IT— •IP” •p° «/> li_ o Q Q_ Q 2:

p=® +4 «d

+-> o • 9 • • • • 0 o '

CVS CO ’St' LO VO h159
Table II

-8.

Direct

O&M

costs -

June,

1976 , 03o CO 00 ro ,

co o *0"

+-> CO cn 00 CO

CM CO cn 1— 00 LO

+J r* * A r> * •s c.

«!* ro CO ro CM o

OS ro LO

Ou -bo- bo O o cn cn O o 00

CO 00

C_) cn CM CM 1—

CL. *bo

cr

O o LD LO CM o CM

r- ro LO

•r* co LO E o

r-— ro

OS

+-> o

C_> CO>1

or -Q3

cn cr CO

CO o CM

CO

rv. 00 o ro

co La cn r— ro LO

#» +-> OSOS ro ,

LOr_

X •faO- fcO-

<0 o • 00 CO CO o r=» o CO 00 cn O cn CO

‘•r—1 CM CO CM cn <n

#* #%

a

+-> o o ro ro f o

as CM ro

LsJ bO- bo

oc • o r—

+» + as

e: •r— t/> •1— t. £C s- 3

ITS o as as o E JO *o +-> as

03 s. fO c

s. +-> r—

3 E as o a xj

cr ia +j 4-> r—

OJ Ju +-»

O a>

M r— 4J as c as

u

as QJC t as s- CO

O 3 o •f •r— r— to U- o a a. Q r—»

+J as

CO 4-» o • • • • • • o ; o r— CM ro LO co t—

160
Table

1

-9

.

Direct

O&M

costs

-

July,

1976

lfil
Table

1

1

-10.

Direct

O&M

costs

-

August,

1976

162
Table

11-11.

Direct

O&M

costs -

September,

1976

r_

ITJ 4~> o r— cr> co CO o o r—

4-> nv. C\J CO cn 0 C\J co o uo o CO

4-> r\ •c •s •t

A c 1— co 00 CO C\J 00

<o CO a. tO- to- O O on o o 00 o CO CO

hCL.

C\J* CO LOn 1 1 tO toCT o co cn LD o r— 00 *=J- cn c

•rC\J CO CO i

CO E o r~' CO

<u +j oo

to- to

</) cn JQ3 r

— CO cn CO CO o CO

</) cr 00 o t— CTi LO LO

•r*c o r— CO 0 * r» -t-> o r— CM

(O f—

OJ

-bO- tofO o o r— CO cn o o oo CO i

CO CO CO

•r- 1— o o 00 0 S- * r» #» +-> 1— CO r—.

r— o CSJ CO

cu

-bO- to- LU

oc • a r—

+-> + 03 c •r cn

•1“ s- c S- 3

03 o 0) <DO E JO -a -M <U >i 03 s- 03 c

S- -M r— 3 E 03 o a -Q r—

cr. 03 4J -t-> r—

CD Sa 4->

a <u +J r— +J <u E a* u

03 CJ c s- 03 s_ cn o 3 o •r— r— •r— *r— in

Li- o Q Q_a 2: r—

+J 03

+-> o • • • • • • 0 o '

CVJ CO in CO h163
Table

11-12.

Direct

O&M

costs

-

October,

1976

164
Appendix III

Boiler Fuel Consumption Model

165
Annendix III - Boiler Fuel Consumption Model

A mathematical boiler model has been devised to determine the

boiler fuel consumption for months when fuel data was unavailable.

This model predicts the fuel consumed by the boiler(s) from monthly

DAS measurements of the total boiler(s) output.

The boilers at the JCTE site are fire-tube , hot-water boilers

having a rated full -load of 13.4 MBtu per hour (3.9 MW). Unless

a boiler is bypassed, primary hot water continuously flows through it.

The construction of a fire-tube boiler is such that the boiler shell

inner walls are maintained at the temperature of the boiler water

while the endplates are heated by the combustion gases.

The mathematical boiler model is described by two terms. The

first term, constant loss , results mostly from heat losses from the

boiler's shell. This shell is held at a relatively constant temperature

by the primary hot water flowing through the boiler. The second

term, constant firing efficiency , results from a fixed percentage of

the combusted fuel's heat content being transfered to the boiler water.

The firing efficiency is relatively constant due to boiler mechanisms

which carefully regulate the fuel /air mixture and due to boiler controls

which only allow firing at rates greater than 30% full -load. The boiler

model is expressed by the equation:

BO = (mf )(HV)(F) - (L)(T)(N) (1)

where BO is the DAS measurement of boiler output for the time

period T.

m^r is the constant boiler firing efficiency

HV is the higher heating value of one gallon of fuel oil

F is the gallons of fuel oil consumed in the

time period T

L is the constant boiler loss rate,

and N is the number of boilers connected Into the

primary loop during time interval T.

166
Note that the boiler firing efficiency is different from the boiler

operating efficiency which includes shell losses.

Numerical values for the two terms of the boiler model were determined from DAS measurements and boiler fuel measurements. From

DAS measurements of idle boiler PHW heat, the constant loss term was

found to be approximately 100 kBtu per hour. Using a regression

analysis based on eq. (1) and specific periods of boiler output and

boiler fuel data when uninterrupted DAS and fuel data were available,

the average firing efficiency was determined to be 84%. Once the

firing efficiency and constant loss terms are known, the boiler fuel

consumption and boiler operating efficiency can be determined for

any period in which boiler output data is available.

The manufacturer's data sheet which describes boiler part-load

operating efficiency is in agreement with this model. The model predicts

operating efficiencies of 83.3% at 100% load and 82.0% at 30% steadystate load. These values are within 1% of the typical performance

curve given by the manufacturer.

Computation of boiler fuel consumption using the model requires

only data for the total boiler output and the duration that the

boiler(s) were valved into the primary loop (generally this is all or none of a month). To compute fuel consumption, the boiler(s) loss

rate is multiplied by the duration of time that each boiler was "valved

in" and added to the measured total boiler(s) output. This quantity

is divided by the boiler firing efficiency and the fuel's heat content.

This computation is represented by the following rearrangement of

equation (1):

F = B0 + [L] [T] [N] , Qr

[HV] [mf]

F(gallons) =

B°( Btu ) + D°° kBtu/h] [T(hours)][N]

[.84] [HV(Btu/gallon)]

167
The operating efficiencies of the boiler(s) are determined by

dividing the measured boiler output by the fuel consumption times the

fuel heat content. Measured fuel consumption data is used when available,

however, when measured data is not available the boiler model is used

to determine fuel data. Due to the constant loss term, the monthly

operating efficiency of the boiler(s) may drop below 80% during low

output months.

168
References

1. Coble, J.B., Kuklewicz, M.E. and Hebrank, J.H., "Performance of

the Engine-Generator Used in the Jersey City Total Energy Plant",

National Bureau of Standards (U.S.), NBSIR 77-1207 (October 1976).

2. , "Industrial Bond Yields", Public Utilities

Fortnightly, Vol . 98, No. 4 (August 12, 1976), page 41 and

_ "Public Utility Bond Yields", Public Utilities

Fortnightly, Vol. 98, No. 6 (September 9, 1976), page 33.

3. American Council of Life Insurance, "Survey of Mortgage

Commitments on Multi -family and Nonresidential Properties

Reported by 15 Life Insurance Companies - Second Quarter,

1976", Investment Bulletin, No. 755 (November 5, 1976), page 3.

4. Federal Power Commission, "The 1970 National Power Survey, " page 1-19-6 (December 1971).

5. American Society of Heating, Refrigeration and Air Conditioning

Engineers, Inc., "ASHRAE Handbook and Product Directory - 1976

Systems," Chapter 44 (1976).

6. Grant, E.L., Ireson, W.G., and Leavenworth, R.S., "Principles of

Engineering Economy, " 6th ed., p. 34, (Ronald Press Co., 1976).

7. American Society of Heating, Refrigeration, and Air Conditioning

Engineers, Inc., "ASHRAE Guide and Data Book - Systems and

Equipment," (1967), p. 143.

8. Public Service Electric and Gas Co., "Financial and Statistical

Review, 1975 Report, " 80 Park Place, Newark, New Jersey, 07101.

9. Pfeiffer, D.C., "SMU Study Gives Large Chiller 0 & M Costs,"

Journal of Heating, Piping, Air Conditioning, Vol. 43 No. 5 (May 1971).

10. Building Owners and Managers Association International," 1976

Downtown and Suburban Office Building Experience Exchange Report

for the Calendar Year 1975," (1976).

169
NBS-1 14A (REV. 7-73)

U.S. DEPT. OF COMM. BIBLIOGRAPHIC DATA

SHEET

1. PUBLICATION OR REPORT NO. NBSIR 77-1243

2. Gov’t Accession

No.

4. TITLE AND SUBTITLE

"Performance Analysis of the Jersey City Total Energy

Site: Interim Report"

7. author(S) John Hebrank, Charles W. Hurley, John D. Ryan,

William Obright, William Rippey

3. Recipient’s Accession No.

5. Publication Date July 1977

6. Performing Organization Code

8. Performing Organ. Report No.

9. PERFORMING ORGANIZATION NAME AND ADDRESS

NATIONAL BUREAU OF STANDARDS

DEPARTMENT OF COMMERCE

WASHINGTON, D.C. 20234

10. Project/Task/Work Unit No. 462 6382

11. Contract/Grant No.

12. Sponsoring Organization Name and Complete Address (Street, City, State, ZIP)

Department of Housing and Urban Development

Division of Energy, Building Technology and Standards

Office of Policy Development and Research

Washington, D.C. 20410

13. Type of Report & Period Covered

14. Sponsoring Agency Code

15. SUPPLEMENTARY NOTES

16. ABSTRACT (A 200-word or less factual summary of most significant information. If document includes a significant

bibliography or literature survey, mention it here.) Under the Sponsorship of the Department of Housing

and Urban Development (HUD), the National Bureau of Standards (NBS) has gathered engineer

ing and economic data from an operating diesel total energy plant which supplies all

electrical power, hot water, and chilled water to a 485 “unit apartment /commercial building

complex in Jersey City, New Jersey.

Engineering data has been continuously collected since April 1975 by a data acquisition

system (DAS) which monitors approximately 200 sensors located in the plant and site

buildings. In this report, data for a one-year period from November 1975 through October

1976 is presented. Electrical and thermal demands by the site and plant equipment

efficiencies have been determined from this data and are reported. Reliability data is

also reported.

Relative fuel savings by the total energy plant have been determined from the engineering

data. Adjustments were performed to compensate for the malfunctioning absorption chill

Calculations indicate that an alternative conventional central plant using purchased

electrical power , oil-fired boilers, and absorption chillers would have required 17.3% mq

fuel than required by the JCTE plant as adjusted. These savings correspond to 160,000

gallons (606 m^) of fuel oil annually. Minor design modifications are suggested in this

report which would improve the JCTE plant performance an additional 5.7%. If the JCTE

plant chillers were properly adjusted and_the suggested minor modifications were perforae

the above alternative conventional plant would have consumed 24.5% more fuel oil annually

Economic data describing the capital, operating, owning, and maintenance costs during

the one-year period are also presented. Unit costs of electrical, heating and cooling

energy commodities are determined and compared to conventionally-supplied energy unit

costs.

17. KEY WORDS (six to twelve entries; alphabetical order; capitalime only tfie first letter of the first key word unless a proper name; separated by semicolons

)

Absorption chillers; boiler performance; central utility plant; diesel engine

performance; engine-generator efficiency; heat recovery; total energy systems.

ers

re

d.

18. AVAILABILITY Eg! Unlimited

For Official Distribution. Do Not Release to NTIS

I I Order From Sup. of Doc., U.S. Government Printing Office (3 ,

i (I Washington. D.C. 20402. SD Cat. No. Cl

. IX 1 Order From National Technical Information Service (NTIS)

Springfield, Virginia 22151

19. SECURITY CLASS

(THIS REPORT)

UNCL ASSIFIED

20. SECURITY CLASS

(THIS PAGE)

UNCLASSIFIED

21. NO. OF PAGES

175

22. Price

6.75

USCOMM-DC 29042-P74


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