BNL- 6 3 1 01 

INFORMAL REPORT 

t 

an ADVANCED COGENERATION AND ABSORPTION CHILLERS 

OD POTENTIAL FOR SERVICE TO NAVY BASES 

J. W. Andrews, T. A. Butcher, R W. Leigh 

R J. McDonald, and B. L. Pierce 

April 1996 

Prepared for: 

Strategic Environmental Research and Development Program 

U.S. Department of Defense 

Washington, DC 20301-3030 

Of'fice of the Director of Defense Research and Engineering I 11 ,A'. rn<m -- 

Energy Efficiency and 

Conservation Division 

DEPARTMENT OF APPLIED SCIENCE 

BROOKHAVEN NATIO 

UPTON, LONG ISLP 

NAL 

iND. I 

LABORATORY 

YEW YORK 11973 

R 

DISTRIBUTION OF THIS DOCUMENT IS UNLIMITEDJ, r 
DISWIMER 

This report was prepared as an account of work sponsored by an agency of 

the United States Government. Neither the United States Government nor any 

agency thereof, nor any of their employees, nor any of their contractors, subcontractors, or their employees makes any warranty, express or implied, or 

assumes any legal liability or responsibility for the accuracy, completeness, 

or usefulness of any information, apparatus, product or process disclosed, or 

represents that its use would not infringe privately owned rights. Reference 

herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise, does not necessarily constitute or 

imply its endorsement, recommendation, or favoring by the United States 

Government or any agency thereof. The views and opinions of authors expressed 

herein do not necessarily state or reflect those of the United States Government or any agency, contractor, or subcontractor thereof. 

3 
ADVANCED COGENEMTION AND ABSORPTION CHILLERS 

POTENTIAL FOR SERVICE TO NAVY BASES 

FINAL REPORT 

BY: 

J. W. Andrews, T. A. Butcher, R W. Leigh 

R J. McDonald, and B. L. Pierce 

APRIL 1996 

. Prepared for: 

Strategic Environmental Research and Development Program 

Office of the Director of Defense Research and Engineering 

U.S. Department of Defense 

Washington, DC 20301-3030 

Under Contract No. DE-ACO2-76CHOOO16 

Brookhaven National Laboratory 

Upton, NY 11973 
.. . . 

.I 

Y 
TABLE OF CONTENTS 

1 SUMMARY AND CONCLUSIONS ........................... 1-1 

1.1 Introduction ...................................... 1-1 

1.2 The Reasons for Distributed Cogeneration ................... 1-1 

1.3 Summary of Study Results ............................. 1-2 

1.4 Conclusions ...................................... 1-5 

2 SMALL SCALE COGENERATION TECHNOLOGY ................ 2-1 

2.1 Currently Available Technology ......................... 2-1 

2.2 Technical Problem Area: Reliability ....................... 2-3 

2.3 Near-Term New Technology ........................... 2-4 

2.4 Competing Technology Options ......................... 2-8 

2.5 Environmental Regulations ............................ 2-9 

2.6 Options for Reducing Emissions in Engine Exhaust ............. 2-17 

3 COMpATlBLE ABSORPTION TECHNOLOGY ................... 3-1 

3.1 Currently Available Technology ......................... 3-1 

3.2 Potential Technology Advances .......................... 3-4 

4 MODEL FACILITY DEFl[NITION AND SmATION ............. 4-1 

4.1 Introduction ...................................... 4-1 

4.2 Description of Site .................................. 4-1 

4.3 Energy Use Intensities ............................... 4-1 

4.4 Cogenerators and Chillers ............................. 4-3 

1 

.... -~ ......... __- ~ ...... .- 
5 

TABLE OF CONTENTS (Cont.) 

4.5 

4.6 

Site Characterization in Terms of Energy Inputs ............... 4-4 

Electric Load Duration Curve ........................... 4-4 

4.7 Heating and Cwling Load ........................ 4-6 

4.8 

4.9 

Optimal Installation for a Large Building .................... 4-6 

Heating and Codling the Buildings ........................ 4-8 

4.10 Controllstrategy ................................... 4-9 

4.11 Spreadsheet Analysis of System Operation ................... 4-9 

4.12 District Heating Cogeneration System ...................... 4-11 

4.13 Base Case Results .................................. 4-12 

4.14 Primary Energy Comparisons ........................... 4-13 

4.15 Demand Calculations ................................ 4-13 

4.16 Comparative Emissions of Pollutants ...................... 4-18 

COMPARATIVE ECONOMIC ANALYSIS FOR TRE MOD= FACILITY . 5-1 

5.1 Introduction ...................................... 5-1 

5.2 Economic Assumptions ............................... 5-1 

5.3 Equipment Costs ................................... 5-2 

Analysis for Boilers and Utility Electricity ................... 5-5 

Analysis for Modular Cogeneration ....................... 5-6 

Analysis for District Heating and Cooling System .............. 5-9 

5.4 

5.5 

5.6 

. 

.. 

11 
6 

7 

TABLE OF CONTENTS (Cont.) 

MODULAR COGENERATION IN THE NAVY ................... 6-1 

6.1 Introduction ...................................... 6-1 

6.2 

6.3 

6.4 

6.5 

6.6 

6.7 

AnnualSumm aries .................................. 6-2 

Seasonal Breakdowns ................................ 6-11 

Loads in the Typical Multibuilding Facility .................. 6-28 

Spreadsheet Input Data ............................... 6-35 

Results of Simulations ............................... 6-36 

Demand Calculations for Navy EFD’s ..................... 6-37 

ECONOMICS OF MODULAR COGENERATION IN THE NAVY ....... 7-1 

7.1 Introduction ...................................... 7-1 

7.2 CHESDIV/LAN’IDIV ............................... 7-1 

7.3 NORTHDIV ..................................... 7-2 

7.4 SOUTHDIV ....................................... 7-3 

7.5 WESTDI ........................................ 7-3 

7.6 SWESTDIV ...................................... 7-4 

7.7 Conclusions ...................................... 7-4 

REFERENCES ........................................ R-1 

APPENDIX A . Cogeneration Simulation Spreadsheets for Model 

Facility with National Average Energy Loads ..................... A-1 

APPENDIX B . Cogeneration Simulation Spreadsheets for Model 

Facility with Navy-EFD . Specific Energy Loads ................... B-1 

... 

111 

.. 
TABLE OF CONTENTS (Cont.) 

APPENDIX C . Test of MCC 85 Kw Cogenerator .................. C-1 

APPENDIX D . Cogenerating Fuel Cells ........................ D-1 

iv 

.... 
LIST OF TABLES 

1-1 

1-2 

2-1 

2-2 

2-3 

2-4 

2-5 

2-6 

3-1 

4- 1 

4-2 

4-3 

4-4 

4-5 

4-6 

4-7 

Costs of Cogenerated Thermal Energy (1992 $) ............... 1-2 

Electricity-to-Fuel Price Ratios and Payback Times 

for Modular Cogeneration ............................. 1-5 

Available Small Cogeneration Systems ..................... 2-2 

Duel Fuel Engine Characteristics ......................... 2-7 

Environmental Acronyms ............................. 2-9 

NAAQS Compliance Ratios ............................ 2-12 

Emission Levels for Which BACT is Required ................ 2-14 

Emissions from Alternative Reciprocating Engines ............. 2-18 

Current Absorption Chiller Manufacturers ................... 3-2 

Annual Heating. Cooling. and Non-AC Electrical Loads 

and Energy Intensities for U.S. Commercial Buildings. 1992 ....... 4-3 

Annual and Average Hourly Loads for SpacerWater Heating. 

Space Cooling. and Electric Power Not Used for Space Cooling ..... 4-4 

Annual Energy Quantities for the Model Facility for Various 

Numbers.of Chillers for Each Cogenerator and for the Use of 

District Heating and Cooling ........................... 4-14 

Development of Peak Thermal and Electrical Demands for the 

Model Facility .................................... 4-17 

Emission Factors Used in Comparing Total Amounts of 

Pollution Produced.by Three Scenarios ..................... 4-18 

Comparisons of Total Amount of Pollutant Emissions with Three 

Selected Scenarios ................................... 4-19 

Comparison of Total Amount of On-Site Emissions with Three 

Selected Scenarios .................................. 4-19 

V 
5- 1 

5-2 

5-3 

5-4 

5-5 

5-6 

5-7 

5-8 

6-2-1 . 

6-2-7 

6-3-1 . 

6-3-7a 

6-4-1 . 

6-4-6 

6-5-1 . 

6-5-6 

7-1 

LIST OF TABLES (Cont.) 

Economic Assumptions for Model Facility ................... 5-2 

Equipment Costs ................................... 5-3 

Boilers and Utility Electricity ........................... 5-5 

Modular Cogen. No Absorption Chillers .................... 5-6 

Economic Performance Versus Number of Cogenerators .......... 5-7 

Modular Cogen with One Absorption Chiller ................. 5-8 

Modular Cogen with Two Absorption Chillers ................ 5-9 

District Heating and . Cooling System ...................... 5-10 

Summaries of Navy Data .............................. 6-4 

Quarterly Breakdowns of Electricity and Fuel Use and 

Extractions of Heating and Cooling Loads ................... 6-12 

Annual and Average Hourly Loads for Space Heating. Space Cooling. 

Electric Power Not Used for Space Cooling. and Process Heat for the 

Typical Multibuilding Facilities ......................... 6-29 

Annual Energy Quantities for the Typical Multibuilding Facilities .... 6-38 

Electricity to Fuel Price Ratios. Thermal Energy Use and Payback 

Time for Modular Cogeneration ......................... 7-5 

vi 
3-1 

4- 1 

4-2 

7- 1 

7-2 

7-3 

LIST OF FIGURES 

Performance of Yazaki 10 Ton Chillers . . . . . . . . . . . . . . . . . . . . 3-4 

Electric Load-Duration Curve Used in Analysis . . . . . . . . . . . . . . . 4-5 

Yearly Plot of Thermal Inputs Needed to Heat and Cool One Large 

Building. Months 1-5, Heating Load. Months 7-11, Thermal Input 

Needed to Meet Load with Absorption Chillers . . . . . . . . . . . . . . . . 4-7 

Equipment, Economic Assumptions and Baseline System Costs 

for CHESDIV/LANTDIV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-6 

Economics of Modular Cogeneration, With No Process Heat, 

for CHESDIV/LANTDIV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-7 

Economics of Modular Cogeneration, With 20% Process Heat, 

for CHESDIV/LANTDIV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-8 

7-4 Equipment, Economic Assumptions and Baseline System Costs 

for NORTHDIV :. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-9 

7-5 Economics of Modular Cogeneration, With No Process Heat, 

for NORTHDIV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-10 

7-6 Economics of Modular Cogeneration, With 20% Process Heat, 

for NORTHDIV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-11 

7-7 Equipment, Economics Assumptions and Baseline System Costs 

forSOUTHDIV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-12 

7-8 Economics of Modular Cogeneration, With No Process Heat, 

forSOUTHDIV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-13 

7-9 Economics of Modular Cogeneration, With Process Heat, for 

SO UTHDIV...................................... 7-14 

7-10 Economics of Modular Cogenehion, Two Absorption Chillers 

Per Cogen, for SOUTHDIV . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-15 

vii 
7-1 1 

7-12 

7-13 

7-14 

7-15 

7-16 

LIST OF FIGURES (Cont.) 

Equipment, Economic Assumptions and Baseline System Costs 

forWESTDIV .................................... 7-16 

Economics of Modular Cogeneration, With No Process Heat, 

forWESTDIV .................................... 7-17 

Economics of Modular Cogeneration, With 20% Process Heat, 

forWESTDIV .................................... 7-18 

Equipment, Economic Assumptions'and Baseline System Costs 

forSWESTDIV ................................... 7-19 

Economics of Modular Cogeneration, With No Process Heat, 

forSWESTDIV ................................... 7-20 

Economics of Modular Cogeneration, With 20% Process Heat, 

for SWESTDIV ................................... 7-21 

... vlll 
Acknowledgement: 

We would like to thank Dr. Suresh Garg of the Naval Facilities Engineering Service Center 

and his staff for giving us access to their data base of Navy energy facilities and for helping us to 

make use of it. 

ix 

1 SUMMARY AND CONCLUSIONS 

1.1 Introduction 

The U.S. military uses millions of Btu's of thermal energy to heat, cool and deliver process 

thermal energy to buildings on military bases, much of which is transmitted through a pipeline system 

incorporating thousands of miles of pipe. Much of this pipeline system is in disrepair and is nearing 

the end of its useful lie, and the boilers which supply it are old and often inefficient. In 1993, 

Brookhaven National Laboratory (BNLJ proposed to SERDP a three-year effort to develop advanced 

systems of coupled diesel cogenerators and absorption chillers which would be particularly useM in 

providing a continuation of the services now provided by increasingly antiquated district systems. 

SERDP indicated interest in BNL's proposal by funding a much smaller, one-year effort in 

which BNL was to prepare a detailed work plan for the succeeding years and explain the 

contributions and experience of our proposed industrial partner, Modular Cogeneration Corporation 

(MCC) of New Rochelle, NY. Funding for the program planning effort was received at BNL in 

December, 1994, and work was begun immediately, based on the previously filed SERDP Execution 

Plan. 

In mid-February, 1995, BNL learned that all subsequent hding for our program had been 

canceled, due to the massive decreases in overall SERDP funding and the resulting planned 

elimination of the Energy Conservation Technology Thrust Area. BNL staff continued to develop 

the Program Plan and to adhere to the requirements of the Execution Plan, but began to look for 

ways in which the work could be made relevant to Navy and DoD energy needs even without the 

extensive development plan formerly envisioned. 

The entire program was therefore re-oriented to look for ways in which small scale 

cogeneration and absorption chilling technologies, available through procurement rather than 

development, could provide some solutions to the problem of deteriorated district heating systems. 

The result is, we believe, a striking new approach to the provision of building services on military 

bases: in many cases, serious study should be made of the possibility that the old district heating 

system should be removed or abandoned, and small-scale cogenerators and absorption chillers should 

be installed in each building. In the remainder of this Summary, we develop the rationale behind this 

concept and summarize our findings concerning the conditions under which this course of action 

would be advisable and the economic benefits which will accrue if it is followed. The details are 

developed in the succeeding sections of the report. 

1.2 The Reasons for Distributed Cogeneration 

 coge en era ti on'^ refers to the simultaneous use of both heat and electric power fiom the same 

prime mover. Because the production of electrical energy fiom thermal sources such as fuels is at 

best 30 to 45% efficient, substantial amounts of thermal energy are left over when electricity is 

1-1 
produced by traditional means. Ifthis thermal energy can be put to good use, the over-all efficiency 

of fuel utilization can be very high - up to, 90 or 95%, with parallel positive impacts on thermal 

pollution and atmospheric emissions. Cogeneration has been employed in various applications in all 

parts of the world over the last one hundred years, and is often a cost-effective and worthwhile 

concept today. 

Condensing Turbine 

Back Pressure Turbine 

Combustion Turbine: 

(Extraction) : 

Diesel Enaine: 

However, the thermal energy recovered 

with cogeneration systems is not “fiee” in most 

cases, although the cost will vary with the nature 

of the prime mover. Essentially, thermal energy 

diverted at useM temperatures usually results in 

lower efficiency of electricity production, and 

when this and any incremental capital costs are 

accounted for, one finds the costs of cogenerated 

thermal energy indicated in Table 1-1 (from Ref. 7 

of Chapter 5). Clearly the low costs associated 

with Diesel engines look very attractive; they 

occur because the extraction of heat at up to 

220°F (105OC) has no effect on generation 

efficiency and heat exchange requirements are 

S/MBtu 

4.60-5.30 

3.00-4.00 

0.50-1 .OO 

0.10-0.30 

Table 1-1: Costs of Cogenerated 

Thermal Energy (1 992 $). 

minimal; for this and other reasons, we will focus on these systems in this study. 

Cogeneration systems come in all sizes, fi-om less than 100 kW to industrial systems of many 

megawatts. We focus on systems at the small end of the scale, with thermal outputs comparable to 

the demands of single buildings for heating and cooling, so that it will not be necessary to transport 

thermal energy between buildings. The reason for this is straightfonvard: it is quite expensive to 

transport thermal energy between buildings in insulated pipe networks. In Section 5-3 below we 

show that inter-building delivery costs for hot water run from $2.60-7.00/MBtu (million Btu’s) 

delivered, and that the additional cost to add a chilled water capability is more than twice this. Since 

for diesel engines economies of scale are not large (see Section 5.3), it would seem reasonable to look 

at the option of eliminating the piping and distriiuting smaller cogenerators in each building, and that 

is what we do in this study. 

We assume that all buildings are connected by an adequate intermediate-voltage electric 

distribution system, so the electric energy produced by the cogenerators can be easily shared around 

the facility and exported to the local utility ifthere is a surplus. The technology to assure this is 

mature; institutional relations with the local utility must be worked out individually. 

1.3 Summary of Study Results 

The major portion of the report, contained in Chapters 4 through 7, is a technical and 

economic analysis of the potential for modular cogeneration and absorption chilling to meet the 

1-2 
energy needs of military facilities comprising groups of buildings and their associated activities. The 

approach to this analysis can be summarized as follows, broken into two parts. 

Part I, (Chapters 4 and 5) perf'ormed the following steps to develop methodological tools and 

an object for analysis: 

0 Develop a model of a multi building facility that can be considered sufficiently representative 

to use as a test article in an energy-flow model. 

0 Develop a methodology for assessiig the energy uses of this hcility over the course of a year, 

for various choices of energy-production means. 

0 Establish national-average values of energy-use requirements for commercial buildings, using 

Department of Energy data. 

0 Calculate the amounts of purchased energy (electricity and fbel) used annually by the facility, 

for various choices of cogenerating and non-cogenerating energy delivery systems. 

0 Perform an economic analysis of these options under national-average assumptions 

concerning fbel and electricity prices. 

At this point we had a typical facility and a methodology for analyzing various energy-delivery 

systems, and we also had a preliminary set of results based on national-average values for energy 

usages and prices. What we lacked was a way to relate this to military facilities in a way that would 

be sufliciently region-specific to be useful. It seemed quite possible that military energy-use patterns 

might differ significantly fi-om those in the civilian sector, and it seemed obvious that the value of 

absorption chillers would differ greatly between hot and cool climates. 

We were fortunate to have been given access to a database of energy use maintained by the 

Navy. Although this database did not provide some details we would have liked, such as heating and 

cooling loads, it did give aggregated electricity- and fuel-use data for seven geographic regions on 

a monthly and quarterly basis. We developed a method of estimating heating and cooling loads, 

using the seasonal fluctuations in fbel and electricity use, and found that the results gave intuitively 

reasonable results that agreed, at least on an order-of-magnitude basis, with the national-average data 

fiom DOE. Having thus prepared the necessary inputs, we proceeded to analyze the Navy's data. 

Part 11 (Chapters 6 and 7) therefore performed the following steps: 

0 Prepare regional summaries of the Navy data in a form usefbl to the analysis. 

0 Develop seasonal breakdowns of fbel and electricity use, and from these obtain the heating 

and cooling loads. Check the results for reasonableness. 

1-3 
e 

e 

e 

Apply these loads, for each geographic region, to the "typical multi building facility" that was 

characterized in Part I. 

Obtain the annual fbel and purchased electricity inputs needed by this facility, by region, for 

each choice of cogenerating and non-cogenerating energy delivery system. 

Assess the annual costs of operating each candidate system in each region, incorporating 

initial investment, energy and demand charges for purchased electricity, purchased fbel costs, 

and operation and maintenance costs. 

Evaluate the results for significance to the Navy. Characterize the potential for modular 

cogeneration with and without absorption chilling in each region. 

The signiscance of the results for the Navy is discussed at the end of Chapter 7, and is briefly 

summarized here. We analyzed six regions (combining two of the Navy's regions that overlapped 

geographically). One of these, covering the Pacific Islands and Japan, was dropped fiom fbrther 

analysis because of the great diversity of climates wih the region and especially because natural gas 

appears not to be available at most sites. Of the remaining five regions, two showed good economic 

potential for modular cogeneration, although absorption chillers at current prices were marginal. 

Two regions gave very disappointing results. The fifth region gave intermediate results. 

The results were strongly driven by one factor in particular: the ratio of the price paid by the 

Navy for a unit of electricity to what it paid for a unit of gas. Where electricity was expensive and 

gas was cheap, cogeneration looked good. Where the reverse was true, it looked terrible. Table 1 

shows the relevant values for the five Navy divisions studied. The fbel price ratio used the average 

cost for electricity per kwh, including demand and energy charges and the average price paid for 

natural gas, in dollars per MBtu (divided by 293 kWh/MBtu to represent both energy sources in the 

same units). The value of cogeneration is represented by the inverse of the payback time for the most 

attractive number of absorption chillers (which as it turns out was usually zero--see below). 

The electricity-to-gas price ratio and the inverse payback time are highly correlated, with 

~0.86 and ?-=0.75. This means that three-fourths of the variation in results among regions is 

associated with differences in this ratio. 

The next most important variable may be the fiaction of cogenerated heat that can be utilized, 

as detailed in Section 7.7. Of the two divisions that gave attractive results, NORTHDIV achieved 

a 2.8-year payback with a fbel price ratio of about 8, while WESTDIV had a slightly longer payback 

(3.3 years) despite a &el price ratio that was 40% higher. The difference is probably due to the fact 

that in NORTHDIV, with its high heating loads, 56% of the cogenerated heat was utilized, while in 

WESTDIV only 29% of the heat was used. 

The conclusion is to look for situations where electricity is expensive, gas is cheap, and where 

you have a need for sigdicant amounts of heat at temperatures that cogenerators can provide. 

1-4 
Quantity: Electricity-to-Gas &&/ Payback Inverse 

Division Price Ratio Hmgell Time Payback 

(Yew (l/years 

1 

CHESDIV/ LANTDIV 3.6 47 % 176 0.01 

NORTHDIV 8.0 56 % 2.8 0.36 

SOUTHDIV 4.7 41 % 42 0.02 

WESTDIV 11.3 29 % 3.3 0.30 

SWESTDIV 5.7 22% 8.3 0.12 

Note: Division names are Navy acronyms. For the most part, their geography is as follows: 

CHESDIV and LANTDIV cover Maryland, DC, and Virginia and activities in the North 

Atlantic; NORTHDIV covers New England, the Middle Atlantic, and the Midwest; SOUTHDIV 

covers the Southeast as far west as Texas; WESTDIV covers northern California and the 

Pacific Northwest; and SWESTDIV covers southern California 

Table 1-2: Electricity-to-fuel price ratios and payback times for modular cogeneration. 

The second salient result is that absorption chillers did not significantly improve the 

economics, even in SOUTHDIV where cooling loads were high. Although we were disappointed by 

this result, we were really not surprised. Our initial proposal to SERDP was based on the belief that 

the costs for absorption chillers were generally higher than could be justified by economics alone. 

As discussed in Section 5.5, even price reductions which could perhaps be achieved through hard 

bargaining over large orders might be sufficient to make absorption chillers far more attractive 

economically. Given their environmental benefits and low maintenance requirements, this is a 

proposition that should be studied closely. Development money could also be directed at lowering 

first costs. 

1.4 Conclusions 

- The Navy should examine NORTHDIV for situations where modular cogeneration looks 

promisiig. The site should then be used in a detailed engineering assessment along the lines outlined 

in this report, comparing modular cogeneration, centralized cogeneration with district heating and 

cooling and standard boilers with utility electricity. If modular cogeneration appears preferable on 

the basis of the engineering study, it should be tried on a pilot basis. After assessment of the results, 

the Navy could replicate the tested system, modify it, or abandon the concept. 

-- If the NORTHDIV engineering assessment appears positive, WESTDIV should be 

examined for sites where a modular cogeneration system might prove viable. If one is found, another 

1-5 

. 
engineering assessment should be undertaken, with special attention paid to what prices for 

absorption chillers would be required to meet Navy requirements for return on investment or 

payback. Negotiations with Yazaki or other suppliers should then be undertaken. 

- Component cost reductions which would lead to wider use of energy-efficient technologies 

are possible through technical development in all aspects of modular and centralized cogeneration: 

heat exchanger development, controls, reliability enhancement and thermal distribution. Given the 

size of the armed forces infrastructure, modest fiinding of such technical developments could reap 

dramatic rewards in the three to ten year time frame. 

1-6 
2. SMALL SCALE COGENERATION TECHNOLOGY 

2.1 Currently Available Technology 

Production of small (less than 100 kw) cogeneration systems has collapsed in the United 

States. Only a few years ago, staffat the Gas Research Institute could confidently predict that prices 

on small cogeneration systems would fall and sales increase', while a study done at the Naval Civil 

Engineering Laboratorf listed twelve vendors of systems in the 100 kW and under range. Today, 

sales are low and not well documented, and eleven of those listed firms have either disappeared, 

discontinued cogeneration activities, discontinued the small end of their line or have otherwise lei3 

the field. One fiom that list remains, albeit with a name change, to Tecogen. In this section we 

examine remaining suppliers and their products and the recognized problems with their products to 

find the reasons for this collapse; there is no doubt that cogeneration could be efficient and 

environmentally desirable and it should be cost-effective and popular. 

Initially, of course, we were aware of the "Smart-1" produced by our industrial partner in this 

project, Modular Cogeneration Corp ("MCC"). We also searched the Thomas Registe? for 

companies claiming a capability in reciprocating engine cogeneration. Mer eliminating some on the 

basis of size or other unsuitability, we sent an information request to each of them. The result was 

one positive response (fiom Tecogen); others either did not respond or indicated that they only 

produced much larger units or were no longer in cogeneration. We also established contacts with the 

local distributer for ISI, Inc. We attempted to contact the firms listed in the 1987 Naval Civil 

Engineering Study, with the results reported above. Professional contacts led to several other 

information requests. Perennial Energy, Inc. ("PEI") was typical of several hs that will build 

cogeneration sets to order; none of the others we contacted, however, were actively marketing for 

these jobs at this time. 

The results are summarized in Table 2-1. Various physical characteristics are displayed for 

each machine where available. Economic parameters are to the right, the most important being the 

capital cost.' From these, a total cost for produced electricity is estimated. This is calculated by 

adding all capital and variable costs togethe? and subtracting a credit for thermal energy, 

approximated conservatively as one-halfthe unit energy cost of gas. The table shows clearly that high 

electric efficiency and adiabatic design result in substantially lower unit energy costs. The IS1 120 

kW unit is, like the Smart-1, based on a heavy-duty industrial diesel block. Running on pure natural 

gas, it is supercharged with an intercooler. The remaining units are all derived from automotive Ottocycle engines, and are restricted to lower internal pressures and efficiencies. More detailed economic 

analyses will be carried out in later sections. 

* 

the known (white) values, omitting the 43kW unit. 

The "Capital Costs" shaded in grey are estimates obtained by using the highest cost per kilowatt among 

#. The lifetimes are short, so future expenditures and savings were not discounted, and the capital 

component of total cost is the capital cost divided by the product of electric capacity and engine life. 

2- 1 
I 

1 

Maker Electric Thermal Output Fuel Total Engine Capital Rebld O&MCost Total 

output Consumption cost 

Cap. Effic. Heat @ Temp, Return Gas(1) Oil(2) Effic. Cost Life Var. Fixed 

(kW: mBtulhr OF @ OF SCF/hr aal/hr $(k) k-hrs c/kWh k$/yr c/kWtTable 2-1 : Available Small Cogeneration Systems. 

I) Gas high heat value = 1020 Btu/SCF, cost = $4.88 /mSCF 

2) Oil hinh heat value = 138 mBtu/gal, cost = $1 .OO /gal 
2.2 Technical Problem Area: Reliability , 

Despite the promising economics outlined in the last section, small cogeneration sets have 

enjoyed only modest growth. Most technical characteristics of cogenerators, such as efficiency, fuel 

utilization, power conditioning and so forth all seem either adequate to the task or better than 

adequate. (Fuel utilization is clearly better than that with any other means of providing electric 

energy and heat.) The problem can perhaps be summed up by asserting that for equipment in this size 

range, which must get by with very little individual maintenance, managers and decision makers seem 

to demand reliabiity and performance similar to a furnace, rather than characteristics which might be 

found in an automobile or truck. This is unfortunate, since cogeneration sets are similar to vehicles 

in their complexity. Reliability is therefore the primary technical problem area for small cogenerators. 

There are two complementary paths to sufficiently reliable systems. The first, reviewed 

immediately below, is to make each individual machine as reliable as possible. The second path, 

reviewed mher on in this section, involves invoking the redundancy possible when several smaller 

machines are used to insure that some sources of adequate power will always be available. 

With respect to individual machine reliability, the Gas Research Institute recently 

commissioned a detailed study of 122 cogeneration units4. Of these, those in what they define as 

"Group 1" - auto-derivative reciprocating engines (26 engines), and "Group 2" - industrial 

reciprocating engines (34 engines) are relevant to our concerns. They found that these machines, in 

real-We service, were available 94-96% of the time, with an average mean time between failures of 

500 hours (Group 1) and 330 hours (Group 2). This is actually better reliability than is obtained by 

typical electric utility megawatt-scale power plants. 

Furthermore, the researchers were able to identa the causes of the failures and suggest 

design improvements that should fhrther increase reliability. One completely avoidable but common 

problem was automatic shut-downs due to water returning from the host facility at too high a 

temperature - in other words, with the thermal energy incompletely used. Although it may not always 

be possible to control the host facility, it should be possible to include a completely redundant, 

automated radiator at modest cost to eliminate this source of outages. 

A more serious (and expensive) common problem was engine wrecks "..believed to be caused 

when jacket cooling water entered the engine cylinders fiom leaks in the exhaust heat exchangers. 

This condition, called hydrolocking, usually occurs after the unit is shut down and is especially 

prevalent in installations having exhaust heat exchangers mounted above the engine."' Another cause 

of hydrolocking was the use of exhaust manifolds adapted by blocking unused water ports with 

gasket material alone, easily blown out by high pressure host facility water. These failures can easily 

be avoided through low cost or no cost design changes. 

2-3 
Other recommendations include using high quality pressure, temperature and flow sensors to 

avoid erroneous automated shut-downs, maintaining adequate spare parts and using induction 

generators as starting motors to eliminate all the failure-prone components associated with a separate 

starter motor. In sum, they argue that the forced outage rate can be reduced from 5.9% to 3.1% at 

very low cost. 

However, harried managers will not want to be faced with even a 3% outage rate if they 

believe the systems they have in place give them more reliable service. (In fact, this is unlikely, but 

they may well believe it to be the case.) However, 95% (or 97%) is not necessarily the availability 

of a well-designed cogeneration system, it is the availability of an individual component, and meeting 

load with a system of several units, each smaller than the total anticipated load, ensures a much higher 

level of reliability than one large unit, at comparable cost. 

For example, suppose a building or complex has an electric load of 300 kW and a thermal load 

of 1.5 mml3tu/hr. A single 300 kW cogenerator can meet those loads efficiently, but can be expected 

to be unavailable 5% of the time, or 440 hours per year. During that time, demand charges for 300 

kW will accrue from the local electric utility, and the thermal load will not be served unless an 

expensive alternative boiler has been included in the system. 

Ifthat same building is supplied by five 75 kW cogenerators, each with a 95% availability, the 

system is much more robust. There is a 23% probability that one of the cogenerators will be down, 

but the system will still have the 300 kW(e) and 1.5 mmBtu/hr of thermal energy available. It is less 

likely that a second cogenerator would go down simultaneously: this event (or a worse one) is only 

expected to occur 1.4% of the time, or 120 hours per year. Furthermore, when it does occur, 

demand charges will only accrue on 75 kW rather than 300kW, and 1.1 mmBtu/hr will still flow, 

providing enough thermal energy to keep a building warm or cool or a process in operation at a, 

reduced rate for a few hours while repairs are made. 

Of course this system may cost more than the single larger unit, since it is constructed to be 

25% over capacity. (There is no reliability enhancement from building a single unit larger than 

capacity requirements.) However, there is little economy of scale with diesel engines, so installing 

several smaller units for any given capacity level adds little to the installed system costs. Any small 

increase is normally paid for through he1 savings, since diesel engines become significantly less 

efficient at less than halfload; being able to switch individual units on and off line ensures that most 

of them will operate at or near ftd load and top efficiency much of the time. 

2.3 Near-Term New Technology 

Table 2-1 indicates that most commercially available natural gas fired systems below 100 kW 

have fuel-to-electric efficiencies below 30%. Because they are auto-derivative engines, they are 

restricted to low compression ratios, guaranteeing a low efficiency. 

2-4 
True industrial engines, with bearings and internal structures adequate to support a 

compression ratio of 15-22:1, are common in larger sizes, from 500 kW up to several megawatts. 

Natural gas is the &el of choice where it is available, on the basis of cost and cleanliness, but will not 

ignite from compression heating even at these high ratios. One solution is to retain a spark plug; 

another is to inject a small amount of diesel oil, typically 5-10% of full load fuel energy demand, at 

the top of the compression stroke6. This oil ignites reliably and in turn ignites the gas. The relatively 

slow flame front in the gas-air mixture results in a bum which persists for perhaps the first quarter 

of the expansion stroke, giving an approximation of the constant-pressure power stroke which 

characterizes diesels. 

The most exciting near-tern improvement in small-scale cogeneration technology today is the 

introduction of these heavy-duty, high efficiency systems in the 50-150 kW range. Increasing 

efficiency f?om, for example, 28% to 38% has two important benefits. First, to meet a given electric 

load, the fuel requirements (and costs) drop by 26%, a significant improvement in the economics. 

Second, design of cogeneration systems is often made dZEcult by the fact that in commercial and 

residential applications, the ratio of thermal to electric loads tends to be lower than the ratio of 

thermal to electric power available fiom the machine, leading to "wasted" thermal energy. Increases 

in electric efficiency bring cogeneration systems into better balance with typical demands, and 

increase the number of economically viable applications. 

Emissions are equally important and improving engine design to minimize "engine out'' 

emissions is an important priority for all manufacturers. Once emitted from the engine there are a 

range of exhaust pipe options for controlling pollutant emissions. Post-engine control options are 

discussed in Section 2.6. Engine design changes are discussed in this section. 

In natural gas-fked engines NO, emissions, the primary pollutant of practical concern, can be 

reduced by operating at very lean aidfuel ratios. The lean limit is constrained by ignition. Under very 

lean conditions ignition of the &el air mixture becomes more dif€icult and the lean limit can be 

extended by fueVair charge stratification. This can be accomplished by using a rich precombustion 

chamber connected to the main chamber which is very lean or charge stratification by air injection into 

the intake manifold. At very lean average conditions hydrocarbon emissions may be increased and 

prechamber design is an important factor in this. Practically, NO, reductions of 90% may be 

achieved7**. 

With diesel engines, post-engine controls may be considered for CO, hydrocarbons, and 

particulates (see Section 2.6). There are, however, no practical post-engine controls currently 

available for the size of engine considered in this study and for this reason emphasis must be placed 

on reducing engineout NO, emissions. Uncontrolled NO, emissions from diesels range from 10 to 

15 g/hp-hr. A variety of measures can be taken for NO, reduction including retarded timing in 

combination with higher injection pressures and electronic injection timing and rate control, turbo 

charging with air to air or air to water undercooling, and, possibly, exhaust gas recirculation. 

Effective January 1, 1996 manufacturers of engines in the 175-750 HI? range for non-highway 

applications must meet NO, emission levels of 6.9 ghp-hr. At least one manufacturer can meet these 

2- 5 
limits without turbo charging or gas recirculation. Engines which will not move more often than 

once each year are exempt fi-om these regulations. In 1997 these regulations will apply to engines 

in the 100-174 HP range. The point is that these lower NO, diesel engines are available now for 

application to the cogeneration market. 

Another pollutant of concern with diesel engines is particulates. Measured particulate 

emissions consist of three parts: solid particulate carbon, soluble organics derived fi-om unburned fuel 

and lube oil, and sulfates. The carbon and fuel parts of the particulate emissions can be minimized 

through measures such as injection pressure, head design, and control of lube oil flow into the 

cylinder. Low sulfur fbels (0.05%) which are now mandated for use in highway diesels can also be 

used to achieve about 30% reduction in measured particulate emissions. 

In some ways dual-fuel engines combine the emission characteristics of both gas and diesel 

engines and in some ways they present emission problems of their own. In nearly all dual fuel engines 

the gas is premixed with the incoming air. Diesel fbel used for pilot ignition burns with locally rich 

stoichiometry and the gas burns lean. Uncontrolled NO, emissions with dual fiel engines are very 

roughly 40-60% lower than with diesel engines. The diesel fuel used for pilot ignition contributes 

greatly to the pollutant emission levels and should be minimized. Many dual fbel engines are simply 

converted diesels and retain conventional diesel injectors which allow them to operate on 100% diesel 

fiel at times - a major advantage for the dual fbel option. If operated at very low injection rates 

atomization quality, and combustion performance degrades. This problem can be avoided through 

the use of microinjectors, specifically designed to deliver small quantities of fuel. Such 

microinjectors can be integrated with small, high swirl prechambers to provide reliable ignition. 

Several microinjector systems are described in detail below. Of course this approach eliminates the 

possibility of operating with 100% diesel fuel unless two injectors are installed in each cylinder. 

At low loads dual fuel engines tend toward very high emissions of hydrocarbons and CO 

because of the very lean combustion conditions. Options for addressing this include operation only 

on diesel fuel at low loads, and throttling combustion air. 

Detailed tests have been reported on several dual he1 engines, although often in the larger size 

ranges. Results fi-om several of these are compared in Table 2-2. The firstg, on a Caterpillar 3406 

diesel with a compression ratio of 14.5:l and a nominal power rating of 200kW (mechanical), 

compares operation as a standard oil-fired unit with the simplest form of dual-fie1 conversion, where 

gas is simply vented directly into the air intake and diesel oil is simultaneously cut back to amounts 

that would otherwise be consumed at idle. The result is a modest lowering of efficiency and NOx 

emissions, a dramatic increase in CO and a significant decrease in particulates, as measured by 

drawing the exhaust through filter paper for a set time period and measuring its reflectivity. Each of 

these effects is amplified at part (50%) load. Throughout the paper the authors emphasize that 

optimizing parameters such as injection timing should improve performance, but could not be 

included in that round of tests. 

2- 6 
The next test shows that this is indeed the case. Cooper-Bessemer engineers' set up a 408 

liter four cycle engine as a standard dual-fie1 unit, burning 5.7% diesel oil through the standard 

injectors and adding natural gas to the air intake. Performance was good, at 41% mechanical 

efficiency, but NOx was high at 11.5 ghhp-h and particulate emissions resulted in an exhaust opacity 

of 20%, just legal at the time but a source of complaints. They tested various improvements in 

twenty configurations, ofwhich we mention only two (tests #13 and #21). In the first of these, they 

installed smaller nozzles dedicated to pilot oil injection; they were too small to allow a return to 

100% diesel oil operation, so operations would be restricted to the dual fie1 option in a permanent 

installation, but they provided more precise injection and cleaner burning while efficiency dropped 

slightly, to 39%. 

1) UHC = Unburned hydrocarboons 

2) PM = Particulate Matter 

3) DO = Diesel Oil, DF = Dual Fuel, NG = Natural Gas. 

4) B = Bosch Smoke Number (filters), % = Per Cent Opacity 

Table 2-2: Dual Fuel Engine Characteristics. 

The "CleanBurn" system in the next line is a more radical step, where the pilot oil is burned 

in a small chamber where the mixture is kept too rich to encourage NOx formation. The flame then 

explodes out into the main chamber, which is held too lean to encourage NOx formation, but which 

can none-the-less be reliably ignited by this "torch." Much less pilot oil is used - less than 1% by 

energy content. The result is 40% efficiency with quite low NOx and particulate emissions, 

accompanied by a modest increase in unburned hydrocarbons. This system also retains the standard 

injectors and so can be switched back to 100% oil operation when gas is not available. 

A somewhat similar approach was applied to a Caterpillar 1Y540 all-gas engine and is 

reported on the next line'. Without pilot oil, a spark plug must be used to initiate combustion, but 

2-7 
it ignites a rich mixture of gas in a small ''precombustion chamber" which again sends a jet of flame 

out into the larger combustion chamber, which is filled with a much leaner mixture. The engine was 

run at low loads, since the purpose was to increase efficiency and decrease emissions in this regime, 

where very lean mixtures make clean combustion difficult. The cost of using the lean mixture is 

. apparent in the relatively low efficiency rating, while the benefit is apparent in the low level of NOx 

emissions. The extremely lean burn results in high levels of unburned hydrocarbons (UHC), which 

are in fact mostly unburned methane. These losses are significant: since 48.35 grams of methane 

have a total energy content of one horsepower-hour, the Cat 1Y540's efficiency based on the fuel it 

actually burned is closer to 33% than to the reported 28%. The authors conclude that, "prechamber 

combustion systems can extend the lean operating limit in natural gas engines." 

However, these systems are not yet commercially available in the size ranges we are 

examining. We conclude that only heavy-duty, high compression engines appear to offer a route to 

high efficiency at reasonable levels of emissions, and that the introduction of pre-combustion 

chambers to smaller engines would allow high efficiency operation and lower emissions levels even 

at part-load operation. 

2.4 Competing Technology Options 

Several alternative technologies are available which compete with modular reciprocating 

engine cogeneration and absorption chillers. The most obvious is to continue current use of grid 

electricity for power and cooling and boilers furnaces for thermal loads. We use this as our basic 

alternative technology in the analysis to follow. Also, in some of the case studies to follow, we 

compare the modular cogeneration systems under discussion to a larger (775 kw) reciprocating 

cogenerator, centrally located and connected to a district heating and cooling piping network. 

Another possibility is the use of &el cells, a technology being pursued in other SERDP 

programs. We provide a brief review of the current state of fuel cell technology in Appendix D, 

where we find that despite great technical advantages, without large subsidies they are still too 

expensive to be competitive currently. 

Combustion turbines and large fossil-steam power plants could also serve electric and themal 

loads on larger Navy bases, since these systems are only available on a scale of megawatts and larger. 

These technologies do enjoy substantial economies of scale, so ifaNavy base is large enough to make 

use of the electric power and thermal energy from a ten to one hundred megawatt power plant, they 

will probably appear more attractive than the 775 kW system. Because they are on such a different 

scale, however, direct comparisons are complex, and we use only the 775 kW system to compare 

modular cogeneration systems without thermal distribution to larger centralized systems with thermal 

distribution. 

2- 8 
2.5 Environmental Regulations 

Environmental regulations pertaining to internal combustion engines have been examined. 

Air quality and permitting regulations in California, Maryland, New York, Texas, and Virginia were 

reviewed for their applicability to systems of the type discussed in this report. In addition, permitting 

conditions for similar existing equipment were examined. Environmental regulations are highly 

technical and spec&, and the summary of information provided here must be supplemented by sitespec& inquiries for any particular project. As an aid to comprehension, we include a table of many 

environmentally-related acronyms. 

In general, new equipment is 

subject to regulation in each of the states. 

Regulations are trigered by a combination 

of size, location, and emission levels. 

Small equipment is generally exempt; the 

size that requires permitting varies from 

state to state. More stringent regulations 

are invoked if a facility is located in a 

Prevention of Sigmficant Deterioration 

(PSD) area or in a nonattainment area. 

These areas are defined by each state. 

Permitting requirements may also be 

triggered if uncontrolled emissions exceed 

certain levels, as defined by each state, 

regardless of equipment size. 

Controls may be required on new 

stationary sources. Depending on the 

specific regulation which applies, these 

control requirements may be of three 

AQMD 

0hP-h 

BACT 

IC 

LAER 

NMHC 

NSCR 

PPm 

PSD 

RACT 

RBLC 

SCAQMD 

SCR 

tPY 

voc 

PM,, 

Air Quality Management District 

Best Available Control Technology 

Grams per brake horsepower-hour 

Internal Combustion 

Lowest Achievable Emissions Rate 

Non-Methane Hydrocarbons 

Selective Non-Catalytic Reduction 

Particulate Matter, <= 10 microns 

Parts per million 

Prevention of Significant 

Deterioration 

Reasonably Available Control 

RACT/BACT/LAER Clearinghouse 

South Coast Air Quality 

Management District 

Selective Catalytic Reduction 

Tons per year 

Volatile Organic Compounds 

Technology 

types. A review may be required to 

determine the Best Available Control Table 2-3: Environmental Acronyms. 

Technology (BACT) for a particular type 

of equipment and pollutant. In nonattainment areas, Reasonably Available Control Technology 

(RACT) or Lowest Achievable Emissions Rate (LAER) technologies may be required. Specific 

control technologies are usdy determined by a cost-effectiveness analysis or a determination of the 

types and costs of controls that have been successllly applied. 

In certain areas, for example the Northeast Ozone Transport Region, offsets may be required. 

This means that in order to construct new sources of a given pollutant, existing sources emitting 

higher levels of that pollutant must be eliminated. Offset ratios vary by state. 

2-9 
California 

There are no statewide regulations in California. The California Air Resources Board 

provides oversight and guidelines; permitting is done locally by the various regional Air Quality 

Management Districts (AQMD). Generally, equipment under 50 hp is exempt fiom permitting 

requirements. In some districts, exemptions may apply to equipment up to 500 hp. 

The South Coast AQMD (SCAQMD)'o*ll has the most stringent requirements in California 

and probably in the United States. The SCAQMD includes Los Angeles and Orange Counties, and 

parts of San Bernardino and Riverside Cohties. The SCAQMD requires BACT technology on all 

equipment. There are different BACT requirements for diesel and natural gas engines. For rich burn 

(<4% 09 natural gas engines >50 HP, BACT emission limits are 0.15 g/bhp-hr for NO,, 0.15 g/bhphr for NMHC, and 0.60 g/bhp-hr for CO. For lean burn engines, the NO, limit is 1.5 ghhp-hr but 

0.3 ghhp-hr may be required as technology permits. An electric motor is listed as the alternate basic 

equipment. 

For diesel engines <228 Hp, BACT guidelines are in terms of control equipment rather than 

emission limits. An economic analysis is required to determine the cost-effectiveness of selective 

catalytic reduction (SCR). Otherwise, timing retard greater than or equal to 4 degrees relative to 

standard timing, and turbocharger with intercooler are required. In addition, fie1 oil with less than 

0.05% sdf3r is required. Rule 11 10.2, Emissions From Gaseous- and Liquid-Fueled Internal 

Combastiion Engines, sets allowable emission rates in ppm. These depend on the size of equipment, 

heating value of the &el, and equipment efficiency. Regardless of the BACT guidelines, it is likely 

that catalytic reduction would be necessary to achieve these rates. 

For diesel engines 2.228 HP, catalytic reduction is required. The SCAQMD lists electric 

motors, gas turbiies, and spark ignited engines as alternate basic equipment to diesel engines, and a 

comparative economic analysis may be required. The Board's Clean Fuel Policy lists a dual fie1 

injection engine with methanol and fie1 oil as an alternate. It is unlikely that the use of diesel fuel by 

itself or in a dual-fuel engine could be justifled. 

Further, annual source tests are required for every engine greater than 50 hp. The New 

Source Review procedure requires offsets. 

Maryland 

In Maryland, new equipment is subject to a new source revied2. Permit exemptions are given 

only for very small, emergency-type equipment. 

All metropolitan areas are nonattainment (Baltimore and surroundings - severe; Washington 

and surroundings - serious) and the entire state is in the Ozone Transport Region, so standards have 

been extended to outlying areas. In addition, new sources are subject to PSD standards and Federal 

New Source Performance Standards. 

2-1 0 
If a new source emits >25 T VOC or HC in the Baltimore or Washington areas, a new source 

review and a review for RACT are required. Annual NO, emissions of 25 T in the Baltimore area 

or 50 T in the Washington area trigger a requirement for BACT and LAER review. In both cases, 

offsets at a ratio of 1.3:l are required. 

New York 

As in other areas, various reg~lations'~ are triggered depending on equipment size, emissions, 

and location. In downstate New York (New York City, Long Island, lower Orange County, 

Rockland and Westchester Counties), a facility with >200 hp requires a permit; upstate, a permit is 

required for >400 hp. Note that this is for a facility, so a multiple unit installation could require a 

pennit. 

New York is part of the Ozone Transport Region like Maryland. Downstate emissions >25 

T/yr ofNO, or VOC require a permit and trigger the nonattainment rule. Upstate the limits are 100 

T NO, or 50 T VOC. This requires LAER technology and offsets. The downstate offset ratio is 

1.3:l; upstate, 1.15:l. 

Lowest achievable emissions are determined on a case-by-case basis, with the help of the 

RACTBACTLmR Clearinghouse, described later in this section. 

Texas 

The Texas Clean Air Act'4s15 requires permits for facilities which may emit air contaminants, 

but also allows for exemptions for facilities which would not generate significant air pollution. To 

qualif;, for exemption, a facility must meet annual emission limits and certain other requirements. In 

addition, total emissions fiom the property on which the equipment is located must not exceed certain 

annual limits and there must be no restrictions on any existing Texas permit for that property that 

would preclude an exemption. Finally, ifFederal regulations are triggered (for example, the project 

constitutes a new major source or major modification) an exemption is not allowed. 

a) Total emission limits 

To qualii for a standard exemption, emissions fiom the proposed facility cannot exceed: 

250 TPY (tons per year) of CO, NO,; 

25 TPY of VOC, SO,, PM,,, or other air contaminants. 

For a nonattainment area, emissions fiom the facility cannot exceed: 

the major modfication threshold for CO (100 TPY); 

the major modifkation threshold for NO, and VOC (25-40 TPY); 

25 TPY SO,; 

15 TPY PM,,. 

2-1 1 
Maximum hourly and annual emissions need to be calculated, including upstream and 

downstream changes caused by the project, using AP-42 or other accepted methods. 

b) Standard Exemption 

Once it is determined that the general qualifications for an exemption are met, conditions for 

a specific exemption must be determined. Standard exemption six of the regulations is for gas or 

liquid fuel-fired stationary internal combustion reciprocating engines or gas turbines. Engines and 

turbines rated less than 240 horsepower do not need to be registered but must meet two conditions. 

The first condition describes the &el: 

"Gas fuel shall be limited to: sweet natural gas or liquid petroleum gas, &el gas containing 

no more than 10 grains total s&r per 100 dry standard cubic feet, or field gas. If field gas 

contains more than 1.5 grains hydrogen sulfide or 30 grains total sulfur compounds per 100 

standard cubic feet (sour gas), the engine owner or operator shall maintain records, including 

at least quarterly measurements of &el hydrogen sulfide and total sulfur content, which 

demonstrate that the annual SO, emissions fiom the facility do not exceed 25 tons per year 

(tpy). Liquid &el shall be petroleum distillate oil that is not a blend containing waste oils or 

solvents and contains less than 0.3 percent by weight sulfur." 

The second condition requires that there be no violations of any National Ambient Air Quality 

Standard. Compliance may be demonstrated by one of three methods: modeling, stack height, or 

property line distance. Ifmodeling is used, either test data or the following ratios must be used: 

. For stack height, all exhausts 

must be released at a height at least 

twice the height of any surrounding 

obstructions to wind flow. For the 

third method of compliance, the total 

of all NOx emissions fiom all sources 

on the property must not exceed the 

more restrictive of 1) 250 tpy, or 2) 

the value (0.3125 D) tpy, where D 

equals the shortest distance in feet 

fiom any existing or proposed stack 

to the nearest property line. 

NO, Emission NOJNOX 

Device Rate (Q) Ratio 

(g/hp-hr) 

IC Engine Less than 2.0 0.4 

IC Engine 2.0 thru 10.0 0.15 + 

(0.5/Q) 

IC Engine Greater than 10.0 0.2 

Turbines 0.25 

IC Engine with 0.85 

catalytic 

converter 

Table 2-4: NAAQS Compliance Ratios 

2-1 2 
c) BACT 

If a permit is required, a BACT analysis must be done. While a BACT determination is 

facility specific, current BACT guidelines for both lean and rich burn natural gas engines are emission 

. rates of 

NO, 2.0 g/bhp-hr 

co 3.0 g/bhp-hr 

voc 1 .O g/bhp-hr. 

Diesel engines are normally authorized for standby use only. 

Virginia 

Regulations'417 are triggered by a combination of facility size, location, and emissions rates. 

It is unclear whether a small dual fuel-fred cogeneration system would trigger some of these 

requirements, unless located in a nonattainment area. Many parts of Virginia are in various control 

areas, which require more stringent controls. 

The owner of any stationary source which has a permit or is subject to state emission 

standards may be required to register with the Virginia State Air Pollution Control Board. The owner 

of any stationary source located in any emissions control area and emitting 25 tons per year or more 

of volatile organic compounds or nitrogen oxides must submit an annual emissions statement to the 

board. 

Permits are required for stationary sources, unless the source meets the requirements for 

exemption. Even if exempt, a source must meet emission standards for existing sources or 

performance standards, whichever is more restrictive. Permits may also be required if a source is 

located in a PSD or a nonattainment area. 

Ea permit is required, applications will be subject to a control technology review to determine 

if performance standards are met. Performance testing is based on US. EPA New Source 

Performance Standards. Best Available Control Technology is required; in nonattainment areas the 

lowest achievable emission rate is required for major sources (see below). 

Stationary Source Permit Exemption Levels 

Exemption levels by emission rate are for facilities with uncontrolled emission rates less than: 

Carbon monoxide 100 tons per year 

Nitrogen dioxide 40 tons per year 

Sar dioxide 40 tons per year 

Particulate matter (PMlo) 15 tons per year 

Volatile organic compounds 25 tons per year 

Lead 0.6 tons per year. 

2-1 3 
In addition, there are separate levels specified for toxic pollutants. 

Uncontrolled emission rate is defined as the emission rate at maximum capacity without air 

pollution control equipment. Annual uncontrolled emissions are based on the maximum annual rated 

capacity (based on 8760 hours of operation per year), unless the source is subject to permit conditions 

which limit the annual hours of operation. If more than one unit is installed, the sum of emissions 

would need to be less than the above rates to qualifj for an exemption. 

Prevention of Simcant Deterioration (PSD) Areas 

Any stationary source which could emit 250 tons per year or more of any pollutant subject 

to the federal Clean Air Act or a major stationary source located in a PSD area is subject to additional 

rules. Amjor stationary source is defined as one emitting lOOtons per year or more of a pollutant 

and included in a list of sources. The list includes: 

- fossil fuel-fired steam electric plants of more than 250 million Btu per hour 

fossil %el boilers (or combmtions thereof) totaling more than 250 million Btu 

heat input; 

- fuel conversion plants; and 

- 

per hour heat input. 

For major sources, best available control technology is required for emissions equal to or 

greater than the levels shown in Table 2-5. 

Total Reduced Sulfur 

Table 2-5: Emission Levels for Which BACT is required. 

2-1 4 
In addition, limits are specified for increases in ambient pollutant concentrations. Permit 

applications must include an analysis of air quality. 

Nonattainment Areas 

Regulations require permits for major stationary sources in nonattainment areas. The current 

list contains no areas classiied as severe; the Northern Virginia area is classified as serious. A major 

stationary source here is defined as: 

"Any stationary source of air pollutants which emits, or has the potential to emit, (I) 100 tons 

per year or more of any pollutant subject to regulation under the federal Clean Air Act, or (ii) 

50 tons per year or more of volatile organic compounds or nitrogen oxides in ozone 

nonattainment areas classified as serious in Appendix K, or (iii) 25 tons per year or more of 

volatile organic compounds or nitrogen oxides in ozone nonattainment areas classified as 

severe in Appendix K." 

Any source that is major for volatile organic compounds is also considered major for ozone. 

Again, the total emissions fiom multiple units must be considered. As above, air quality must be 

analyzed. Offsets are required. The source must meet performance standards and emission 

standards. 

Performance Standards 

All stationary sources must meet performance standards. Performance testing is required per 

EPA regulations (40 CFR Part 60). Standards and exemption levels, in terms of concentrations, are 

specified for toxic pollutants. For opacity, no emissions are allowed with greater than 20 percent 

opacity, except for one six-minute period in any one hour of not more than 30 percent opacity. In 

addition, all stationary sources must use BACT. In nonattainment areas, LAER is required. 

Existing Permit Conditions 

EPA's Office of Air Quality Planning and Standards maintains a network of electronic bulletin 

boards, collectively called the Technology Transfer Network. These bulletin boards cover a range 

of topics, including air emission inventories and emission factors, test methods, regulatory and 

training information. One of these bulletin boards, the RACT/BACT/LAER Clearinghouse (RBLC) 

contains information on RACTBACTLAER determinations made around the U.S. 

The RBLC contains information about facilities that have received permits from various 

pollution control agencies; data are entered by the various regulatory agencies and reviewed and 

maintained by EPA. The RBLC is designed to assist state and local officials in making 

RACTE3ACTLAER determinations and can also be used by private companies to learn what controls 

have been required for specific types of equipment. The database contains permit numbers and 

contact information at the permitting agency, in case more information is desired. 

2-1 5 
A search of the RBLC was made for any equipment similar to that under investigation in this 

project. Only one multi-fuel engine was found, and that is a natural gadpropane 200 hp engine, used 

for nitrogen gas injection and located in California. The permit was issued in 1991, and specifies that 

only propane or natural gas can be used. The basis for control is BACT-PSD. NO, emissions are 

limited to 90 ppmvd at 15% 0, (uncontrolled 115.2 lbdd; controlled 15.8 lbdd) and VOC emissions 

to 0.44 Ibm/h (uncontrolled 46.6 Ibdd; controlled 10.6 Ibdd). Control is with NSCR with a threeway catalyst. 

- 

Most of the equipment listed in the dual fuel category is turbines, with the exception of one 

facility with a digester and one with boilers. The most stringent NO, limit is on a cogeneration facility 

with a turbine/generator burning oil or gas, located in Minnesota. The permit was issued in March 

1995 and limits NO, to 4.5 ppm @ 15% 0, with gas and 16 ppm with oil. The permit basis is BACTPSD, and SCR is used. The same limit applies to the turbines at the Pilgrim Energy Center in New 

York, with an estimated start-up date of December 1995. The permit basis is BACT, and the 

required control method is steam injection followed by SCR. CO, part&date, VOC and NH, 

emissions are also limited. The Holtsville, N.Y. combined cycle plant (150 MW), permitted in 1992, 

has a NO, limit of 42 ppm @ 15% 0,. 

The NAPA Sanitation District has an IC engine with digester gas and supplementary natural 

gas. On the basis of BACT-OTHER, NO, emissions are lited to 1.25 ghhp-h and precursor 

organic compounds to 1 .O g/bhp-h. 

Limits for natural gas or diesel engines were also examined. Diesel-only engines permitted 

in 1992 in Philadelphia have NO, emission lits of 2 g/bhp-h. A large diesel engine in California, 

permitted in 1993, has a NO, limit of 6.6 g/bhp-h, is limited to 500 hours of operation per year, and 

uses a turbocharger, aftercooler, and injection timing retard of >= 4 degrees for control. NO, limits . on natural gas engines range from 1.4 to 2 g/bhp-h. 

Overall, the RBLC database shows no smaU diesel/natural gas-fired engines that have received 

permits. It should be noted, however, that many of the facilities contain multiple turbines or boilers, 

and the permits set emission limits for the total number installed. Thus while one small engine may 

not trigger permitting requirements, installation of several at the same facility may. 

Summary 

Table 2-6 shows emission rates for natural gas, dual fbel, and diesel systems using various 

levels of control (as discussed in Section 2.6, to follow). For the model system, that is seven 120 kW 

units, total annual emissions were also calculated. Annual emissions were calculated assuming fidl 

load operation for 8760 hours per year, based on Virginia regulations. The results are thus the 

maximum annual emissions that could be obtained, and are not likely to be achieved in real-time 

operation. Nevertheless, they allow an overview determination of where permitting and/or control 

requirements are likely to be triggered. 

2-1 6 
Annual NO, and HC emissions fiom an uncontrolled gas system would trigger permitting 

requirements in all areas, while controlled gas systems would not. It should be noted that the 

emission rates for the controlled system do not meet SCAQMD standards, but engines are available 

which do. 

For both the dual fuel and diesel system, annual NO, emissions would trigger permitting and 

control requirements. For Texas, this applies only to nonattainment areas. In New York, the 

controlled dual firel system would not trigger requirements in upstate New York but would in 

downstate areas. 

A site- and engine-speciiic evaluation would be required to determine actual requirements, 

however this overview suggests that it would be much easier to locate a natural gas-fired system than 

either a diesel or dual fuel system. 

2.6 Options for Reducing Emissions in Engine Exhaust 

In any pollution control strategy the first step should be to minimize "engine-out" emissions 

through engine design and adjustments. The current status of gas-fired and dual-fuel engines in this 

area is discussed in Sections 2.1 and 2.3. In this section, options for reducing emissions with exhaust 

gas treatment are discussed for both natural gas and dual fuel engines. 

Natural Gas-Fired Engines 

With gas-fired, spark ignited engines the basic gas treatment approach used in automobiles 

may be extended for use in these engines. Early auto catalytic control systems involved lean 

conditions to. reduce CO and hydrocarbon emissions only. These conditions were achieved by 

adjusting the engine to lean air/fuel ratios and injecting air into the exhaust upstream of the catalyst. 

In the converter CO and hydrocarbons reacted with available oxygen. This approach was followed 

by the use of three-way catalysts where conditions at the converter inlet are controlled to provide 

stoichiometric or very slightly rich gas. In the converter CO and hydrocarbons are oxidized with 

excess oxygen and NO. This approach for NO, reduction is sometimes termed Selective NonCatalytic Reduction or NSCR. In this application it is necessary to maintain very tight limits on 

engine airhe1 ratio. Zirconium oxide sensors are ideally suited for use in maintaining aidfirel ratio 

at about stoichiometric because of the large jump in sensor output as air/firel ratio is reduced toward 

the stoichiometric limit. Under lean conditions these sensors require precise temperature 

compensation or other measures to be useful in controlling air/fuel ratio. 

2-1 7 
. 

r 

A 

a3 

1. For conventional gas, NOx based on discussions with 

Annual Emissions 

dual fuel diesel diesel 

with OX with trap/ conven- with OX with trap/ comp- with OX with trap 

catalyst catalyst tional catalyst catalyst liant catalyst catalyst 

~~ ~~~ ~~ ~~~ 

72.51 72.51 169.20 169.20 169.20 83.39 83.39 83.3s 

5.56 5.56 36.62 7.32 7.32 36.62 7.32 7.32 

1.09 0.36 12.09 7.25 2.42 12.09 7.25 2.42 

5.80 5.80 13.29 2.66 2.66 13.29 2.66 2.6E 

manufacturers. Can vary from .I 5 to 1 .O 

2. For dual fuel, NOx based on test results with the MCC engine and a revie.w of manufacturer's data. 

. Emissions from dual fuel engines vary greatly and lower emission levels are possible with improved design. See Section 2. 

3. For compliant diesel, assumes retarded timing and electronic fuel injection control. 

4. Assumes exhaust gas recirculation, a three way catalyst, zirconium oxide oxygen sensor with feedback air/fuel ratio control. 

Based on Tecogen low-NOx package. 

Table 2-6: Emissions from Alternative Reciprocating Engines. 
Applied to natural gas-fired cogeneration engines, three way converter technology can 

provide very low exhaust emissions, although some special considerations must be made in converter 

formulation. Gas-fired engine exhaust has considerably higher levels of methane, which is dficult 

to oxidize. Palladium has a higher activity level for methane than platinum vs. ruthenium, and the 

palladiudplatinum ratio would be higher for gas-fired engines. Relative to other hydrocarbons, 

methane is not considered as noxious a pollutant. It may not be necessary to realize the same 

conversion efficiencies for methane and non-methane hydrocarbons emissions. 

White et. al. conducted a survey’* of the durability of eight three-way catalytic converters 

applied to gas-fired, spark ignited engines. The optimal aidfuel ratio was found to be at about 

A=.995. (“2’ is the ratio of the actual aidfuel ratio to the stoichiometric air/fbel ratio.) At higher 

values of A, NO conversion decreases sharply and at lower A values CO and HC conversion decrease. 

Conversion levels for COY total hydrocarbons, and NO, were about 72%, 40%, and 75%. 

Gas-fired cogeneration packages with catalytic converters are now offered. A unit available 

fi-om Tecogen includes a standard automotive three-way converter with an oxygen sensor and exhaust 

gas recirculation. This is offered as an optional, low NO, package. Without the package NO, 

emissions are in the range of 11 @Hl?-hr and are reduced to about 1 .O with it. Three-way catalysts 

are considered to be the least expensive NO, control option Johnson Matthey Co. reports over 1000 

such systems currently operating on gas-fired engines in gas wellhead compressor applications. 

In another approach engines can be operated much leaner, yielding somewhat reduced engineout NO, emissions and using a catalytic converter for only CO and hydrocarbon emissions. This is 

essentially the early automotive approach. System NO, emissions would overall be higher than with 

a three-way catalyst because of very low NO, removal in the converter. In studies with gas-fired 

heat pump engines, Creamer and Saundedg obtained catalyst conversion efficiencies for CO and total 

hydrocarbons of +90% and 70-90% respectively. An important advantage of this approach, relative 

to three way catalysts, is avoidance of the need for very close engine air/fbel ratio control. 

Dual Fuel Engines 

The application of catalytic converters to dual-&el engines is more Wcult than with gas-fired 

engines because dual-fuel engines run lean, they have soot in the exhaust, and the exhaust gas has a 

higher sukr content. Because dual-fbel engines run lean, the three-way catalyst approach cannot 

be used to reduce the very high NO, emissions levels with this engine. A great deal of work has been 

done on the development of catalytic convertors and soot trap systems for diesel engines, and this 

work is applicable to dual-fuel engines. 

With dual fie1 engines the diesel firel used to pilot ignition makes a major contribution to both 

particulate and NO, emissions. As discussed in Section 2.1 , measures taken to reduce the diesel fbel 

fraction will improve engine-out emissions. 

2-1 9 
Typically, particulate emissions fiom diesel engines consist of three parts: solid particulate 

carbon, soluble organics derived fiom unburned fie1 and lube oil, and sulfates. Flow-though diesel 

engine catalytic converters are effective in oxidizing CO, gaseous hydrocarbons, and the part of diesel 

particulate emissions which are derived fiom fbel and lube oil. This fiaction is often referred to as 

the soluble organic fiaction (SOF). The SOF part of the particulate emissions is engine dependent. 

Flow through catalysts can reduce measured SOF by 50-70% and total particulates emissions by 5 

to 40%2w'. With a catalyst diesel particulate emissions as low as .08 @HE' hr have been reported 

and these catalysts have proved durable in extended vehicle engine testsQz. Light-off temperatures 

(defined at 50% conversion) for diesel catalytic converters are in the range of 500-700. F. At lower 

temperatures conversion efficiency falls rapidly and at temperatures over 625 F conversion 

efficiencies over 80% are reachable for CO and hydrocarbons. In applications where exhaust gas 

temperature is too low, it may be necessary to use a duct burner or inject fbel into the exhaust pipe, 

which burns in the converter, raising the effective temperature. In lean diesel engine exhaust these 

oxidation catalytic converters have no affect on NO,. 

A great deal of work has been done on the development of catalytic and non-catalytic soot 

traps (ceramic flters) for light and heavy duty diesel vehicles. With both types of traps, achieving 

temperatures required for trap cogeneration (carbon burnoff) under highly variable load conditions 

is an important design issue. Some designs have used small diesel-fbel burners, located in the exhaust 

manifold, to periodically burn-off trapped soot. In other cases electrical heaters are used to 

periodically regenerate the traps. Soot trap systems have been used in off-road applications since 

about 1986. If engine cycles are high enough that the engine exhaust temperature is above 930 F 

for a simcant part of the time, non-catalytic traps can be used. With catalytic traps the soot lightoff temperature can be lowered to 680 F. A considerable amount of work has been done on the use 

of fuel additives that contain catalytic metal compounds and can decrease the soot light-off 

temperature to as low as 530 FZ4. 

Sulfates can have a very signillcant impact on total measured particulates. Across platinumbased catalysts sulfur oxidation to sulfates, which increases measured particulate emissions, is a 

concern although palladium catalysts have a much lower conversion efficiency for sub. With 

catalytic emission control systems low sulfur diesel oil (.05%) should be used. 

Achievable reductions in emissions with catalysts for particulates, COY and hydrocarbons are 

70%, 98% and 82% respectivelf'. Detroit Diesel Corporation has applied a catalytic converter to 

a dual fuel bus engine. Emissions over a standard urban test cycle for particulates, COY and 

hydrocarbons have been reported at 0.9,0.31, and 0.085 g/ghp-P6. 

Dry Systems TechnoIogie~~~ has developed an emissions control system for mine engines 

which may be partially applicable to stationary, duel fbel engines. It includes a catalyzed exhaust 

manifold for CO and hydrocarbon control and a low temperature, inexpensive paper filter for 

particulates control. An exhaust heat exchanger is used to meet the temperature limitations of the 

filter. 

2-20 
Selective Catalytic Reduction 

With diesel engines, dual fbel engines, and lean-burn gas-fired engines Selective Catalytic 

Reduction (SCR) can be used to achieve over 80% reduction in NO, emissions. These systems 

involve the addition of a reducing agent into the exhaust upstream of the catalyst. In the catalyst zone 

the reducing agent selectively reacts with NO, leading to the products nitrogen and water. The 

reducing agent commonly used is ammonia either aqueous or anhydrous. A solution of 60% water 

and 40% solid urea can also be used. The ammonia injection rate must be controlled based on the 

amount of NO, present in the exhaust gas. With an insufEcient injection rate, NO, conversion will 

be poor, while excessive injection rates lead to ammonia slip and unacceptable ammonia emissions. 

Control can be based on a continuous, on-line NO, analyzer, or ammonia injection rate can be 

programmed based on expected engine-out NO, levels. Ammonia slip levels of 10 ppm are 

considered acceptable. With SCR the catalyst must operate in the temperature range fiom 500 to 

800°F. 

Early experience with SCR on engine applications was marked by technical dficulties”. This 

has included fouling of the catalyst, ammonia slip, and control problems. Developments during the 

past 10 years have greatly improved reliability and reduced cost. The cost of an SCR system in 1985 

for a 1000 hp engine was estimated to be 5 to 6 times greater than for a three-way catalyst system. 

A general expression for SCR systems given by Urban et al is: $120,000 + $40 X HP. This is based 

on 1985. In a more recent articlez9 Weaver and McGregor suggest $75,000 + $101 X kW. Both 

of these really apply to engines larger than those under consideration in this study. 

Currently there is a great deal of interest in the development of systems for reducing NO, 

emissions in lean diesel engine exhaust using other reducing agents3’. Approaches involve injecting 

diesel fbel into the exhaust upstream of the converter or operating the engine in a way to greatly 

increase engine-out hydrocarbons. Catalysts being studied include zeolites, copper, and precious 

metals. 

Caterpillar Co. has recently introduced an SCR system based on ethanol injection into the 

exhaust, upstream of a catalyst bed. The system reportedly1 reduces NO, emissions fiom 6.7 to 1.3 

and is being applied to stationary engines larger than about 500 hp. A microprocessor-based 

control system is used to monitor NO, emission levels and control ethanol injection rates. 

2-2 1 
I- 
3. COMPATIBLE ABSORPTION TECHNOLOGY 

Absorption chillers are a venerable technology, dating back to the early nineteenth century. 

Modern metallurgy and chemistry have made them much more reliable than they once were, but 

because they require large amounts of heat exchange dace, they are still relatively costly. The basic 

operating principles, involving evaporation and distillation within an evacuated space, are described 

in many engineering handbooks and will not be repeated here. Broadly, absorption chillers may be 

divided into ‘‘directly fired” Units, which burn ~tural gas or some similar fiel, and hot-water or steam 

powered units, for which the heat has been supplied elsewhere. For cogeneration systems, the heat 

is supplied fiom the cooling circuits of the prime mover, so only hot waterhteam powered units are 

of interest. 

Although several different working fluid combinations are possible in absorption chillers, for 

air conditioning applications the only one in commercial use is a mixture of water and lithium bromide 

salt. Ammonia is used in refiigeration applications where sub-freezing temperatures are required, 

since the working fluid is water in lithium bromide systems. The efficiency of ammonia systems is 

halfthat of lithium bromide systems, so it is never used in applications such as air conditioning, where 

low temperatures are not required. Other fluid combinations are under study, but they are all of 

interest only when high-temperature heat is available, and so are not relevant to engine-fired 

cogeneration. 

Absorption chillers may also be divided into “single effect” and “double effect” units, 

describing the structure of the distillation apparatus within the chiller. Double effect units make use 

of the incoming heat twice, and so have efficiencies nearly double those of single effect units (for 

example, coefficients of performance, or ‘cCOl?’yys, of 1.1 rather than 0.65). They also have higher 

capital costs, so ifthe thermal energy is essentially “free”, as it is in cogeneration, the effect on the 

economics is not as great as iffbel were being purchased. We will examine this issue in detail below. 

So for application in conjunction with modular cogeneration systems, we will examine lithium 

bromide, hot-water (or steam) fired absorption chillers, looking at both single and double effect 

systems. To be consistent with a small number of 65-100 kW prime movers, we will be interested 

in total cooling capacities of under 100 tons (350 kW& with unit sizes ranging down to 10 to 20 tons 

(35-70 kWJ. We first examine what is “off-the-shelf’ today, then look at systems that may become 

available in the near fbture. 

3.1 Currently Available Technology 

To iden* vendors of 20-50 ton* double & single effect units suitable for use in this project 

we consulted various trade journals and the Thomas Register to develop the list of potential suppliers 

* A “ton” of refrigeration refers to the ability to produce one ton of ice per day, and is defined to be 

exactly 12,000 Btu per hour. 

3- 1 
shown in Table 3-1. Inquiry elicited interested response from three of the companies, Sanyo, Yazaki 

and York. Hitachi has turned all of their operations over to York, and Carrier and Trane only 

manuficture units of over hundred tons, larger than would be suitable for our applications. One other 

company, formerly known as Preway/Servel/Arkla and now owned by Robur, produces three to five 

ton chillers, but only in a directly gas fired configuration, so they are of no use in cogeneration 

applications. 

Company . Location “Effect” Size Range 

(Tons) 

American Yazaki Farmers Branch, TX Single 5-50 

Carrier Corporation Syracuse, NY S/D Large 

Hitachi America Ltd. Tarrytown, NY -- > York 

Sanyo/McQuay I Danville, IL I Double I 100-1500 

Trane Co. La Crosse, WI S/D Large 

York International Corp. Baltimore. MD Single 120-1 200 

11 11 I1 $1 II II Double 430-1 500 

Table 3-1 : Current Absorption Chiller Manufacturers 

A single 75 kW cogenerator, running at 36% electrical efficiency, will provide thermal energy 

suf€icient to power 18 tons of single effect capacity, so we would need about six small cogenerators 

to power one of even the smallest of the Sanyo or York systems, and the Trane and Carrier machines 

are similarly oversized for our needs. Ofthe currently commercially available systems, Yazaki seems 

to make the only appropriately sized machines, and we focus on them as the paradigm of available 

absorption technology for small cogeneration systems. 

The Yazaki hot water-fired chillers are designed to be as simple and maintenance-fiee as 

possible. There are essentially three units, of nominal 5, 7.5 and 10 ton capacities. , Clever 

arrangement of the generator and condenser allows the chiller to operate with no internal pumps, so 

electricity is used only for control devices, including valves. Of course the hot water supply, the 

cooling water and the chilled water must be externally pumped through the chiller, and the 

spedications for the flow rates ofthe hot water supply and cooling water are quite demanding (-5%, 

+lo%). A wet cooling tower must be supplied separately. Over a thousand of these machines are 

in service in the U.S., with many more in Japan. 

3-2 
Maintenance involves an annual service visit when controls are checked and the noncondensable gasses are pumped out. If hydrogen is present, indicating corrosion, inhibitor is added; 

otherwise, there is no internal maintenance. Proper operation of the control system is vital to reliable 

operation and prevention of crystallization (which can be reversed through appropriate service). 

Maintenance contracts are available through local engineering firms in most parts of the country. . 

Performance is typical of single effect machines, with a COP which peaks at 0.65. We have 

assumed the standard values of chilled water in at 55°F (13°C) and out at 45°F (7°C) and cooling 

water in at 85°F (29°C) and out at 95°F (35°C). Because performance will depend strongly on the 

temperature of the hot water fiom the engine, we present Yazaki’s predictions for capacity and COP 

in graphical form below. The data is for the 10 ton unit; the 7.5 ton unit seems to perform identically, 

while the 5 ton unit has a COP which is about 14% lower. Since in most applications it would only 

be used as a “trim” unit, we do not describe it in detail. 

The nominal equipment cost forthe ten tonunit is $15,800 in summer, 1995. This represents 

a steep increase above inflation compared to their prices in the mid-1980’~~ and the national distributer 

indicated that engineering firms might be prepared to bargain on the price. Since the actual capacity 

depends on the temperature of the heat source, the actual capital cost varies fiom $1390/ton ifthe 

hot water is available at 203T (95°C) up to $2450/ton if it is only available at 185°F (85°C). We will 

use the nominal values of 10 tons at 90°F hot water for our analyses. A cooling tower will add $2000 

for the ten ton unit’, installation will add 30% onto the chiller cost and overhead and profit will add 

another 26%2, so the installed cost of one Yazaki chiller will be about $26,700. Installation would 

be somewhat simpler for a second or third unit at the same location, since pipe routing will already 

be paid for, but we do not reduce installation costs in this case, since the savings will be very sitespecific. 

Maintenance requirements are minimal in most cases, consisting of an annual checkup and 

pump-down; if hydrogen is present during pump-down, indicating internal corrosion, inhibitor is 

added to the solution at that time. Yazaki representatives assert that with correct annual 

maintenance, system lifetime should be “many” years. We will take maintenance costs at $500 per 

year, representing one day including travel for the first unit at a given site. 

In summary, our survey shows that absorption chillers of acceptable quality are available. It 

would be desirable to have the higher efficiency of double effect systems available in the capacity 

range below 100 tons, however, and the prices for these small units are far higher than for larger 

systems. Clearly, less expensive chillers would have a major impact on overall system value. 

3-3 
I 

0.8 

a 0.6 

0 

0.4 

0.2 

0 

75 80 85 90 95 100 

Hot Water Temperature (oC) 

.cI 

COP 

Capacity 

-c 

Figure 3-1 : Performance of Yazaki 10 Ton Chillers 

3.2 Potential Technology Advances 

Yazaki is considering introducing a new chillerheater combination now available in Japan, 

but the price wiU be even higher than for existing units, and Yazaki is concerned that this may prove 

to be a barrier to market success. We know of no other plans by the established commercial 

companies to introduce innovative products or to significantly upgrade the designs of current 

products, or to produce smaller units which would compete with Yazaki's. In short, the market 

appears to be quite static at present. 

Recent work at Brookhaven National Laboratog hded by the Gas Research Institute holds 

out the promise of substantial decreases in the costs of absorption chillers while maintaining the 

current performance of single effect and double effect systems. Absorption chillers consist largely 

of heat exchangers, and the basic principle involves the development of heat exchangers made from 

thin, flexible polymer films and metal foils. The shape of the heat exchangers is maintained by the 

differential operating pressures. Conceptual designs have been prepared, and model heat exchangers 

fabricated and tested to the point of proof of concept. The amount of material used in the heat 

exchangers can be reduced by a factor of two or three, and if the program is carried forward, the 

result may be capital cost reductions of 2530%. Such advances will make cogeneration a far more 

attractive option, but substantial development fimds are required to make the technological leap. 

The availability of a double effect absorption chiller capable of running on cogenerated heat 

from a reciprocating engine would also enhance the viability of cogeneration, since double effect 

systems produce almost twice the cooling power of currently available single effect systems. Here, 

the changes would primarily be made in the engine, since the operating temperature of the double 

3-4 
effect chiller is largely established by the physical chemistry of lithium bromide brines4. A 

reciprocating engine which could operate with the coolant leaving the engine at 300°F (150°C) and 

returning to it at 280°F (138°C) could drive a double effect absorption chiller of reasonable cost, 

producing 70% more cooling power fiom any given level of reject heat. Operation of an engine 

under these conditions is perfectly possible in theory, using a mixture of water and ethylene glycol 

or propylene glycol, but many detailed issues such as lubricant deterioration, local hot spots and 

optimal coolant circulation remain to be worked out. 

In summary, although there are many steps that could be taken to convert the current marginal 

economic performance of modular cogeneration systems to clear-cut desirability, these steps are a 

clear prerequisite to krther progress and they are not being taken at the current time. 

3-5 

4. MODEL FACILITY DEFINITION AM> SIMULATION 

4.1 Introduction 

A spreadsheet model of a modular cogeneration system was constructed for the sixteenbuilding system modeled by analysts at Oak Ridge National Laboratory (ORNL)’. The main 

difference between the ORNL system and ours is that ORNL always employed a central heat and 

power system with a district heating and cooling (DHC) system to transport the heat and chilled 

water to the buildings. Our approach assumes that the DHC system either does not exist or is so 

decrepit that it requires major repairs, equivalent to a complete re-construction, an option which is 

examined here. In most of the studies to follow, however, instead of a central cogenerator, smallerscale ”modular” cogenerators are placed in the larger buildings. Heat produced by these cogenerators 

is used to meet heating and hot water loads, and with the assistance of absorption chillers, to meet 

cooling loads as well. Heat is not transported between buildings, however, and this means that 

buildings too small to warrant their own cogenerators are not served by cogenerated heat. In contrast 

to heat, electricity is easily shipped from building to building, and so on the electrical side it doesn’t 

matter where the cogenerators are physically located. 

The approach to assessing energy produced and used to meet heating, cooling, and electrical 

loads is to use the national-average values for commercial buildings contained in DOE’S 1994 Office 

of Building Technologies Core Data Book2 (“OBT”). These annual loads are broken down into 

hourly rates by means of a piecewise load-duration curve for electrical energy use and piecewise 

heating- and cooling-load profiles for the buildings. 

4.2 Description of Site 

The site analyzed by ORNL is a generic facility used for the training of personnel, such as a 

college campus or a military base. Its buildings have a total floor area of 399,249 fl?. Seven large 

buildings, each with a floor area of 41,520 fl?, make up 73% of the floor area of the site, with nine 

smaller buildings composing the remainder. 

4.3 Energy Use Intensities 

Energy use intensities were derived fiom OBT, using 1992 data. Total commercial floor 

space in that year was 66.1 X lo9 fl? [OBT, Table 1.3.31. Total primary energy use in commercial 

buildings was 13.07 quads (1 quad = 10’’ Btu), while site energy use (net of power-plant losses in 

electricity generation) was 6.79 quads [OBT, Table 1-3-11. 

The site energy use was disaggregated [OBT, Table 1.3.21, with total energy and energy 

per square foot as follows: 

4- 1 
o Space and Water Heating used 2.69 quads, 97% of which was in the form of gaseous and 

liquid fuels. 

o Space Cooling (referred to in charts below as A/C or AC) used 0.27 quads, more than 96% 

electricity. 

o Non-AC Electricity Demands (about half of which was lighting) used 2.56 quads. # 

o Other Fuel Demands (cooking, laundry, and other commercial uses) totaled 1.26 quads. 

From these values, the heating and cooling loads were determined under the following assumptions: 

o Heating is accomplished largely by boilers with an aggregate seasonal efficiency of 70%. 

OBT, Table 5.1.6 shows average commercial gas and oil space heating efficiencies for 

existing stock (1986) of 70% for oil and 71% for natural gas, with new equipment installed 

that year averaging 71% and 72% for oil and gas, respectively. The actual space and water 

heating load is then 2.69 X 0.70 or 1.88 quads. 

o Cooling is accomplished largely by electric-driven chillers having an aggregate Seasonal 

Energy Efficiency Ratio of 10.36. [OBT Table 5.1.6, 1986 stock]. (New equipment installed 

in that year had an average SEER of 10.58.) The coefficient of performance (COP) 

corresponding to this is 10.36/3.415=3.03, which translates to an annual cooling load of 0.27 

X 3.03 = 0.82 quads. 

Table 4-1 presents these values translated into energy intensities (annual energy per unit floor 

area). The "other fuels" category reported by OBT is assumed to be independent of whether there 

is a central heat and power system, modular cogenerators, or individual-building boilers and electricpowered chillers. It is therefore dropped fiom the remainder of this analysis. 

4-2 
Load Category 

Space and Water 

Heatina 

%ace Coolina 

Non-AC Electric 

Note: Intensities are obtained b 

case of electricity, conversion fi 

Total Intensity 

(1 015 Btu/yr) (Btu/ft2/yr) 

28,400 

0.82 I 12.400 

2.56 38,700 

( 1 1 .33 kWh/ft2/yr) 

' dividing loads by commercial floor area of 66.1 billion ft'. In the 

,rn Btu to kWh is also carried out. 

Table 4-1 : Annual Heating, Cooling, 'and non-AC Electrical Loads and Energy 

Intensities for U.S. Commercial Buildings, 1 992. 

4.4 Cogenerators and Chillers 

The analysis is based on a particular choice of commercially available cogenerator, the IS1 unit 

described in Chapter 2, and on the Yazaki ten-ton single-effect absorption chiller described in 

Chapter 3. Their characteristics may be summarized as: 

0 

0 

Cogenerator: 

Absorption 

Chiller: 

Electric Capacity 120 kW 

Electric Efficiency 0.38 

Thermal Capacity 165 kW, or 563,000 Btu/h 

Thermal Efficiency 0.52 

Cooling Capacity 10 tons or 120,000 Btu/h 

Coefficient of Performance 0.65 

Thermal Input 185,000 Btu/h @ 200 F 

The thermal input to a chiller is slightly less than one-third of the output fiom the cogenerator. 

Therefore a cogenerator could be mated to anywhere from zero to three chillers. The relative 

magnitudes of heating and cooling loads, together with economic tradeoffs, will dictate the optimal 

number of chillers to use within this constraint. 

4-3 
4.5 

Heating, 

Annual 

Heating, 

Hourly 

Cooling, 

Annual 

Cooling, 

Hourly 

Non-AC Elec 

Annual 

Site Characterization in Terms of Energy Inputs 

Whole Site 

399250 ft2 

11339 MBtu 

1294 kBtuh 

4951 MBtu 

565 kBtuh 

4524 MWh 

The site described above is now characterized in terms of the energy inputs required. The 

energy intensities are translated to annual and average hourly energy inputs required by the whole 

. site, a single large building, the seven large buildings together, and by the aggregate "rest of site." 

Table 4-2 presents the results: 

One Large 

Building 

41520 ft2 

Seven Large 

Buildings 

290640 ft2 

Rest of Site 

10861 0 ft2 

1179 MBtu 8254 MBtu 3085 MBtu 

135 kBtuh 942 kBtuh 352 kBtuh 

515 MBtu 3604 MBtu 1347 MBtu 

58.8 kBtuh 411 kBtuh 154 kBtuh 

______~ 

471 MWh 3293 MWh 1231 MWh 

Non-AC Elec 1516 kw 

Hourlv 

53.8 kW 376 kW 140 kW 

Note: MBtu = IO6 Btu; Btuh Btu/h 

Table 4-2: Annual and Average Hourly Loads for Space/Water Heating, Space 

Cooling, and Electric Power Not Used for Space Cooling. 

4.6 Electric Load Duration Curve 

In order to set up the spreadsheet analysis, it is necessary to make an estimate of the 

variability of the thermal and electrical loads over the course of the year. In the electric case, this is 

achieved by means of a load-duration curve. Such a curve plots electrical load against the number 

of hours in which the load is greater than the given value. This gives a monotonic hction starting 

with a y-value equal to the peak load at zero hours and declining to the minimum load encountered 

during the year at 8760 hours. Although this curve is in reality a smooth knction, for the purpose 

4-4 
of this analysis it is convenient to present it in a piecewise-constant fashion, with four pieces each 

representing an averaged load over some subset of the hours during the year. As a baseline, we will 

use the curve plotted in Figure 4-1. This assumes five load levels: a peak load equal to 5 times the 

base load, encountered for a negligible number of hours; a near-peak load equal to 4 times the base 

load, encountered for 10% of the year; moderate loads equal to 3 and 2 times the base load, 

encountered for 20% and 30% of the yeaq and the base load, encountered for 40% of the year. This 

approximates the general shape of a typical utility load-duration curve. Under this assumption, the 

base load will equal one-halfthe average hourly load for the year as given in Table 4-2, with the other 

steps proportionate to this. 

s 

774 

51 6 

258 

TOTAL SITE DEMAND, kW 

1032 

Figure 4-1 : Electric Load-Duration Curve Used in Analysis 

FRACTION OF YEAR WITH EQUAL OR GREATER LOAD 

4-5 
4.7 Heating and Cooling Load Curves 

The heating and cooling loads in this national-average site are expected to be moderate in 

nature, such as might be encountered in the states bordering the North-South divide, e.g. Virginia, 

Kentucky, Missouri Kansas. As a baseline, we have taken the heating and cooling loads to be spread 

over 5 months each, with the remaining 2 months as a shoulder season having no heating or cooling 

load. Within the heating and the cooling periods, we have assumed three load levels in the ratio 

123, building up and then down in stepwise fashion 1:2:3:2: 1 over the 5-month season. In addition, 

a mow peak existing for a negligible number of hours can be assumed at the top of the distribution. 

This peak will govern the maximum capacity required to meet the load at all times, but will not affect 

energy calculations. For the purpose of this analysis, we assume this peak to rise to 4 times the 

lowest step. Because of the five-month duration of the pattern for either load, the hourly load for the 

lowest step can be calculated as follows: . 

(2)(730)(x)+(2)(730)(229+( 1)(730)(3X) = 8760 (Average Hourly Load) 

where X is the hourly load for the lowest step (with 2X and 3X the higher-step loads), 730 is the 

. average number of hours per month, and the fist two terms have an additional factor of two because 

there are two steps at each of these levels. This yields: 

Hourly Load for the Lowest Step = 1.333 Average Hourly Load. 

4.8 Optimal Installation for a Large Building 

We now focus on the heating and cooling needs of a single large building on the site. Because 

we cannot ship heat or chilled water fiom building to building, we need to match the thermal 

generation capacity of a cogenerator as well as we can to the needs of a building. 

We would like to perform cooling in the large buildings using absorption chillers mated to the 

cogenerator. Because the COP of the chiller is less than one, the average thermal input to chillers 

required to cool the building will be greater than the cooling load cited above in Table 2. In fact, the 

average thermal input needed to cool a large building with absorption chillers will be 58.8/0.65 or 

90.5 kBtu/h. 

Using the average thermal inputs for heating and cooling, respectively, of 135 and 90.5 

kBtu/h, the steps of the heating and cooling load curves are constructed by multiplying these numbers 

by 1.33,2.67, and 4.00 and plotted in Figure 2. Also plotted in the figure are the thermal output of 

a cogenerator and the thermal input requirement of 1,2, and 3 chillers. 

4- 6 
Heat Input, Thousand Bfu/h 

400 

300 

200 

100 

0 

1 2 

I 

3456789101112 

Month 

Figure 4-2: Yearly Plot of Thermal.lnputs Needed to Heat and Cool One Large 

Building. Months 1-5, Heating Load. Months 7-1 1, Thermal input Needed to Meet 

Load with Absorption Chillers. 

4-7 
From this figure we see that, under the assumptions described above, one cogenerator can 

meet the heating load of the building, except for the short-duration peak which can be met with an 

auxiliary boiler, as discussed in detail below. packup boilers in each building can also .carry the 

heating load in case of cogenerator failure). The cooling load can be met by two chillers in all but 

the extreme peak situations. Here it might be argued that short-term met loads could be 

acceptable. Alternatively, when a peak-day load is anticipated, the chillers could be run in a control 

strategy that would overcool the building the previous night and thus provide some thermal storage. 

If we do put one cogenerator in each large building, then the site as a whole will have a 

capacity of seven times 120 kW, or 840 kW. The average electric demand of the site is 5 16 kW. 

From the discussion of the electric load-duration curve, the four values of electrical load encountered 

are 0.5, 1.0, 1:5, and 2.0 times.this average value, or 258, 516, 774, and 1032 kW. (A small 

additional load will be needed to air-condition the smaller buildings that don't have cogenerators.) 

Thus, the cogenerators can meet the site's electrical needs 90% of the year, and most of its needs the 

remaining time. It appears that the seven cogenerators are reasonably well matched to the system 

load profile. 

For these reasons, in the analysis to follow, we will assume as a base case that each large 

building has one cogenerator and two absorption chillers. 

4.9 Heating and Cooling the Buildings 

The heating load inputs for the seven large buildings are 1.33, 2.67, and 4.00 times 942 

kBtu/h for the three levels of heating load. The heat inputs required to meet the cooling load are 

1.33,2.67, and 4.00 times 41 U0.65, with the divisor 0.65 representing the COP of the chillers. 

Hasing decided to heat and cool the large buildings with cogenerators and absorption chillers, 

we need to know how we will heat and cool the smaller buildings. We assume this is done with 

individual-building boilers and electrically-driven air conditioners. Therefore, we need to know the 

electric load due to this demand, which is not included in the "non-AC electric load." The average 

AC load for the rest of the site, as shown in Table 4-2, is 154 kBtu/h. Assuming this load is met by 

average equipment with an SEER of 10.36, the average electrical load is 14.9 kW. The loads for the 

three cooling-load steps are then 1.33,2.67, and 4 times this value, or 20,40, and 60 kW. 

4- 8 
4.10 

0 

0 

0 

0 

Control Strategy 

Several control strategies are possible for the cogenerators. Four of these are: 

Run flat out at all times and sell excess power offsite, e.g. to the local utility. 

Run to meet the thermal load of the site, using as much of the electrical energy onsite as 

possible, selling the rest offsite. Purchase any shortfd fiom the local utility. 

Run to meet the electrical load of the site, using what thermal energy is available. If excess 

heat is produced, throw it away. Ifnot enough heat is obtained fiom the cogenerators, use 

the boilers for the remainder. 

Run to meet the larger of the electrical and thermal loads. Ifthe thermal load is larger, sell 

excess electric power offsite. Ifthe electrical load is larger, throw away the excess heat. 

The fist of these strategies would maximize the utilization of the cogenerator, and is in fact 

the strategy that many independent power producers seek to pursue. 

The second strategy appears to be suboptimal, in that it would involve shutting down the 

cogenerators for much of the year or running them at a low level. It is rejected on the basis that it 

would often require the site to purchase electricity even while cogenerators were sitting idle. 

The third strategy should in general be better than the second because electrical energy is 

more valuable than heat. Thus, controlling on electrical needs should be better than controlling on 

thermal needs. 

The fourth strategy does everything that the third strategy does, but in addition permits 

additional heat to be gained fiom the cogenerators for use when needed for space heating or cooling, 

without the need to fire up backup boilers. 

The fourth strategy was selected for the initial analysis because it does better than the second 

in making the site self-sufficient, while requiring less power to be sold than strategy 1, to a perhaps 

unwilling customer. Tradeoffs between strategies 1,3, and 4 need to be analyzed in greater detail, 

but meaningfid results would probably require a more detailed hour-by-hour simulation, which is 

beyond the scope of this analysis. 

4.1 1 Spreadsheet Analysis of System Operation 

The spreadsheet analysis is based on the assumption that the electrical load (net of air 

conditioning) and the thermal loads of the buildings are statistically independent. That is, there is as 

much chance of a peak electrical load occurring during a high thermal demand period as during one 

of low thermal demand. This permits the entire year to be broken down into a 4 X 7 array of 

4-9 
conditions, each holding for a small fiaction of the year. The spreadsheet will compute the electrical 

and thermal demands and outputs of interest for each of these conditions, then add them to get an 

annual picture of the performance of the modular cogeneration system. 

For ease of following nomenclature, electrical quantities are denoted by the letter E, heats by 

H, and fuels by F. Energy rates in kW or kBtu/h have a prime after the letter, while integrated energy 

values in Mwh or Ml3tu do not have the prime. Specific quantities within categories are denoted by 

subscripts. 

Inputs to the spreadsheet are as follows: 

Global constants: . Cogenerator electric capacity in kW (Ftcapacity) 

Cogenerator heatlelectric ratio 

The spreadsheet then calculates the cogenerator thermal capacity 

in kBtu/h using the formula Hqacity = 3.415 Etcapacity &e 

Electrical descriptors (one set of values for each of 4 loads): 

Fraction of year at this load (fc) 

Whole-site non-AC electrical load (Fi'nm-Ac), kW 

Thermal descriptors (one set of values for each of 7 conditions): 

Fraction of year at this condition (fJ 

Cogenerated buildings heat load (H',>, kBm 

Rest of buildings heat load @'ROB), kBtu/h 

Rest of buildings AC electric load (E'RoB-Ac), kW 

. Given these 2 + 2 X 4 + 4 X 7 = 38 inputs, the spreadsheet proceeds to calculate the 

following numbers for each of the 28 blocks: 

*demand Site heat demand, in kBtu/h, equal to HC- + HROB 

E',, Cogenerated electric power, in kW, equal to the greater of E'drmand and H',/(3.415 

he):, up to the limit Etwci,,,, i.e. min(max@?drmanb HcG/(3.415 &e)],E1ap~ty). 

*- Cogenerated heat, ir? kBtu/h, equal to 3.415 E',, he. 

*used Usefid cogenerated heat, in kBtu/h, equal to the lesser of HCB and Hex,. 

4-1 0 
Each of these quantities is then multiplied by the number of hours in the block, i.e. 8760 f, fb 

to obtain an integrated energy value. For example, the total electric energy used for the block Edemand 

is equal, in kwh, to 8760 f, fh Etdemand. The spreadsheet divides this by 1000 to report MWh. Each 

block thus contains ten quantities, as follows: 

Finally, the spreadsheet adds the values of thetive right-hand quantities for all 28 blocks, to 

get annual totals displayed at the bottom. In addition, the amount of electricity that must be 

purchased is found by adding Ewd - E, for those blocks for which this quantity is positive. 

Similarly, E- - Edcmand added for those blocks for which this quantity is positive yields the amount 

of electricity that can be sold. The spreadsheet also calculates Hbders, the amount of heat that must 

be supplied by on-site boilers. This could occur in the cogenerated buildings ifthe cogenerator's 

thermal output were insuflicient to meet the load at any time, although in the base case this does not 

happen. The rest of the site must always be heated with boilers. In general, the sum of these two 

heats is given by Hud - Qg,. 

Not shown on the spreadsheet, but easily calculated, is the fie1 F- required to run the 

cogenerator. This will equal, in MBtu, either 3.415 times E-, divided by the electrical efficiency 

(0.38), or Hcogdl divided by the thermal efficiency (0.52). The &el Fboilcn needed to fire the boilers is 

just & divided by the boiler efficiency. We will take this efficiency to be 0.80. FmM is the sum of 

the f5el used by cogenerators and boilers (Fwg,+Fboaers). 

4.12 District Heating Cogeneration System 

In addition to the modular cogeneration systems or the case of local boilers and utility 

electricity, military bases can be (and often are) served by district heating systems. In these systems 

pressurized hot water or steam is produced in a central facility and is shipped through insulated pipes 

to the various buildings. Older systems were often constructed around a central boiler, but most 

recent installations get heat from a cogeneration plant which also generates electricity, and in regions 

with appreciable air conditioning load, there will also be a large absorption chiller driven off the 

cogenerator when there is cooling load, with chilled water shipped around the base in a separate set 

of insulated pipes. With such a system, even the heating and cooling loads of the smaller buildings 

can be supplied through cogenerated heat, allowing an improvement in &el efficiency compared to 

the modular systems, which are limited to the larger buildings. 

A spreadsheet describing such a system is included in Appendix B and the results are included 

in the discussions below. The treatment was similar to that for the modular systems with the 

4-1 1 
following exceptions: 1) All Rest of Buildings Heating and AC Electric Loads (ROB Ht Ld and ROB 

AC Elec Ld) were set to zero, since heated and chilled water now supply heating and cooling to these 

buildings; 2) These thermal loads were added to those in the “cogenerating buildings”; and 3) All 

thermal energy supplied to the district piping system equaled demand divided by 0.8, corresponding 

to an 80% efficiency in the piping system. The result, as can be seen in the spreadsheet or in the 

summary tables, is a system which makes better use of its reject heat, but one for which the first costs 

are higher, as will be discussed in the next chapter. 

4.13 Base Case Results 

The spreadsheet for the base case with two absorption chillers per cogenerator is displayed 

as Table B-1 in the Appendix and summarized in the fourth column of Table 4-3. For this base case, 

the annual electricity used on the site was 4652 MWh. The cogenerators produced 4972 MWh. 

Because of time mismatches between production and consumption, 18 1 MWh had to be bought and 

502 MWh were available to be sold. It is worth noting that about halfthis amount (229 MWh) was 

available (net sales - purchases) during the periods of highest thermal demand in the heating and 

cooling seasons. Even though we have posited independence of the thermal and non-AC related 

electrical demands on the site, offsite electrical and thermal demands are expected to be positively 

correlated due to the presence of heat pumps, resistance heating, and electric-powered air 

conditioners oGite. An offsite utility might look with favor on a cogenerator that has so much of its 

available power at just such times. 

The other salient result is that., of 23 345 MBtu of heat cogenerated, 13 790 MWh was used, 

or 59% of the total. This is a very respectable utilization factor for cogenerated heat in a buildingsrelated application. 

It was also desired to study the effect of using fewer than two chillers per cogenerator. 

Spreadsheets for a system identical to the base case, but with fewer chillers per cogenerator, are 

shown in Figures B-2 and B-3 of the Appendix. Table 4-3 compares the salient results for the three 

cases, along with a comparison case in which there is no cogeneration, all electricity is purchased and 

all heating is done with on-site boilers. The demands for electricity and heat in this case will be the 

same as for the cogeneration case with no chillers. 

Finally, the results for the DHC system are presented in the fifth column of Table 4-3. It is 

clear that the ability to transport thermal energy allows substantial improvements in system efficiency 

- 78% of cogenerated thermal energy is used, a very high overall efficiency. Fuel consumption is 

higher than for the other cases, but this is because more electricity is sold back to the utility, resulting 

in less he1 being consumed off site. 

4-1 2 
4.14 Primary Energy Comparisons 

We now compare the primary energy for energy under each of the five cases shown in Table 

4-3. Primary energy of fuel is rated at the energy content of the he1 in MBtu. Primary energy of 

electricity is obtained by multiplying the net purchased electricity (purchases minus sales) by the 

factor 3.415 to convert Mwh to MBtu and by 3.159 to account for power-plant and transmission 

losses. [OBT Table 1.1.13 The primary energy totals for each system are shown in Row 12 of Table 

3. It can be seen that the cogenerating systems save 3 1% to 34% of the primary energy used by the 

non-cogenerating system, with the greatest savings for the system with the most chillers. The effect 

of chillers on primary energy savings is not large in percentage terms, however. For the DHC 

system, primary resource consumption is substantially lower than for the other cases studied, since 

now the off-site fuel saved by electricity sales is included in the accounting. 

4.15 Demand calculations. 

In addition to the spreadsheet calculations of various modes of energy production just 

presented, assessment of the comparative economics of these energy supply systems requires 

knowledge of the peak thermal and electric demands they will make, since this determines the 

required capacities of the cogenerators, chillers and boilers. In this section we derive these peak 

demands, again using a simple spreadsheet model. (Note that although "kW and c'BBtu/hour" were 

used in the previous discussion, they always referred to average power over some extended time 

period. In this discussion we refer to the @ power called for during a month or some similar 

period. ) 

The calculation is presented in Table 4-4. The first column consists of titles, to be 

discussed below. The four central columns indicate the peak power or required capacity for one 

of the seven large buildings, for one of the nine small buildings, the site totals (derived differently 

for different quantities as discussed below) and the units for that line. The next column indicates 

how many ten-ton absorption chillers are associated with each cogeneration unit at the large 

buildings. To keep the amount of calculation reasonable, we assume that the nine small buildings 

are identical. 

4-1 3 
Cogen (yh): 

Chillers/cogen. 

Annual Energy 

Flows 

No Yes 

1 

Yes 

DHC 

Yes 

0 

5 000 4 744 4 652 4 520 

11 333 15 400 16 872 23 684 

5 137 

24 123 

8 252 

(34%) 

4 945 

23 219 

12 319 

(53%) 

4 972 

23 345 

13 790 

(59%) 

181 

502 

3 081 

5 527 

25 954 

20 119 

(78%) 

225 

1232 

3 564 

264 

40 1 

201 

401 

3 081 .3 081 

46 138 44 440 44 683 49 641 

4 455 

54 096 

3 851 3 851 

48 291 

46 130 

3 851 

48 534 

45 070 

48 785 

47 260 43 239 

Table 4-3: Annual Energy Quantities for the Model Facility for Various Numbers of 

Chillers for Each Cogenerator and for the Use of District Heating and Cooling. 

The heating demands are developed in the upper block of the table, and of course do not 

depend on how many absorption chillers are present. The heating load is assumed to have the basic 

shape shown in Figure 4-2 and discussed above, with five temporal components of equal length, here 

taken to be months. To make the loads consistent with the total annual energy consumption (as 

explained above), the (period) average load during the first and fifth steps was taken as 1.333 times 

the (annual) average load, the (period) average loads during the second and fourth periods was twice 

that and the (period) average load during the third, central period was three times the first step. 

However, to calculate demand, we also assume that during each period there is an additional load, 

of height equal to the first step but of negligible duration. Pictorially, for each building, each demand 

period has the line indicated in Fig. 4-2 added to it, and although he1 consumption in meeting this 

load wiU be negligible, the capacity of the equipment must be adequate to ensure that it can be met. 

4-1 4 
These "spikes" represent both the one cold night that may show up in an otherwise temperate period 

in an average year, and the likelihood that every few years there will be an exceptionally cold winter. 

We also assume such spikes exist in the month before and the month after the first and last non-zero 

heat loads, labeled as months "6" and "12" in Figure 4-2. 

This concept then allows the "Annual Peaks" for individual c'large'y and "small" buildings to 

be derived fiom the annual energy data. This "Annual Energy" is taken fiom Table 4-2 and inserted 

into the upper block of this table. Then, for a given building, the 

Annual Peak = 4 * (First period average load) 

= 4 * (4/3) * (Annual average load) 

= 4 * (Annual Energy) / (1.3 14 * n), 

where llnll is the number of months in the heating season (here, five, but variable in later analysis) and 

the Annual Peak is in thousands of Btu per hour while the annual energy is in millions of Btu. 

The resulting peaks give accurate specifications for boilers and cogeneration systems for 

single buildings, but for the district system we must add the loads together, and here the diversity of 

' the peak demands is important. Ifthey were to all occur at the same time, the correct answer would 

be the sum of the individual peaks, or 7*718 + 9*209 = 6907 kBtuh. On the other hand, ifthe 

%pike" loads were truly of negligible duration and were not correlated with each other, only the five 

period loads of non-zero duration would add together coherently, and all the individual building 

spikes would occur at different times, so only one representative of the largest of these would 

contribute. In this case, the system peak demand would equal 7*(3/4)*718 + 9*(3/4)*209 + 

(1/4)*718= 5360 kBtuh. Because neither of these extreme cases is likely to be correct, we 

incorporate a 'Diversity Factor" which interpolates linearly between them, and for these studies leave 

it set at 50%. The result is the 6130 kBtuh total site peak demand shown in the table. 

Annual peak cooling demand (in kBtuh) is calculated in a completely analogous way in the 

next section of the table, including the same diversity calculation for the total site cooling demand. 

The required capacity of chillers (other than the modular ten-ton absorption units) is then calculated 

for the case of no modular absorption chillers for large and small buildings and for the whole site by 

simple conversion at 12 kBtuh per ton. Thus peak demand that must be supplied by a central chiller 

in the DHC case is 223 tons, which, when increased to compensate for 20% thermal transmission 

losses, requires a 280 ton absorption chiller. Similarly, large buildings require 26 tons of electric 

chilling capacity and small buildings require eight tons. If ten-ton absorption chillers are installed in 

the large buildings, their capacity requirements drop accordingly, but since the buildings are not 

connected thermally in this case, there is no change in the small building demands and the total site 

demand is not meaningfbl. 

In the next section of Table 4-4 the non-AC electric demand is calculated fiom the total 

annual non-AC electric energy in Table 4-2, assuming the load duration curve shown in Figure 4-1. 

As explained above, the height of each step must be one-halfthe annual average power, here 258kW. 

4-1 5 

.-I- 
As for the heating and cooling loads, we assume that the load duration curve is topped by a spike of 

negligible duration and energy, but the same height as one step. Again, these spikes arise more or 

less independently in the individual buildings. The non-AC electric demand for the entire site is 

calculated by summing the individual building demands for the sections of the load with significant 

. energy consumption and adding the spikes using a 50% diversity factor, calculated just as for heating 

and cooling. 

In the next section, the total electric demand for individual buildings and the entire site is 

calculated by adding together the non-AC electric demands discussed in the previous paragraph and 

the electric demand required to meet the cooling demands developed in the paragraph before that, 

still assuming an SEER of 10.36. Again, the loads corresponding to non-zero energy blocks are 

simply summed, adding together in each cooling period the’peak non-AC electric load and the 

corresponding electric load for AC. However, the spikes in non-AC and AC based electric demand 

are completely uncorrelated, so here the diversity factor is taken as zero. The result is a peak demand 

of 1175 kW in the five months when there is no cooling demand whatsoever, and for shoulder months 

where the non-AC demand spike is greater than the AC demand spike. Moving into the cooling 

season, the peak load increases as shown, mitigated by the presence of seven, fourteen or twenty-one 

absorption chillers. 

Finally, in the bottom block of the table, the power provided by the .cogeneration units is 

subtracted off to leave the peak power required from the utility, against which demand charges 

will be levied. We will see below that it is economically advantageous to include one or more 

“extra” generation units to shave peak load; the calculation shown in the table is thus for nine 

cogenerators, although the extra two are not assumed to provide any thermal energy, since thermal 

demands in the buildings they occupy are probably already met. The final upshot is that with, for 

example, one absorption chiller for each of the first seven cogenerators, there is one month with 

a peak utility load of 236 kW, two months with utility peaks of 163 kW and nine months with 

peak loads of 95 kW. 

4-1 6 
Largd Small Total for 

Building Building Site (1) 

of Buildings: 7 9 

eating Demand: 3ivers-@ Factor = 50% 

5 Month Season 

Annual Energy: 1179 343 f 1339' 

Annual Peak: 71 8 209 61 30 

Units Vumber of 

10 ton 

Absorption 

Chillers per 

MBtu cogen unit 

kBtuh 1 

'actor = 

150 

91 

7.6 

7.6 

7.6 

7.6 

ooling Demand: 

GMonth Season 

Annual Peak: 

Capacity 

Annual Energy: 

Requirement 

3iversity 

515 

31 4 

26.1 

16.1 

6.1 

0.0 1 50% 

. . 1. . .. 495q:iMBtu 

. .. 

2677 

223 

na 

kBtuh 

tonswith 

tons 

natons 

nqtons 

There are 2.0 2.0 2.0 

when P(AC)= 40.2 112.9 185.6 

(in kw) 40.2 40.2 107.9 

40.2 40.2 40.2 

40.2 40.2 40.2 

Ion-AC Electric: Large Small Tota 

Annual Energy 471 j 136 4524 

Peak Demand: 134 39 1175 

1 .o months 

258.4 0 

180.6 1 

102.8 2 

40.2 3 

DF= 50' 

MWh 

kW for 5 months 

Table 4-4: Development of Peak Thermal and Electrical Demands for 

the Model Facility. 

There are 2 2 2 

when P(tot)= 1175 1248 1321 

(inkW) 1175 1175 1243 

1175 1175 1175 

1175 1175 1175 

4-1 7 

1 

1394 0 

1316 1 

1238 2 

1175 3 

There are 2 2 2 1 

when P(tot)= 95 168 241 314 

(in kw) 95 95 163 236 

95 95 95 158 

95 95 95 95 

months 

0 ar 

1 

2 wi 

3 9 
4.16 Comparative Emissions of Pollutants. 

I b/M Btu 

Ib/MBtu 

Ib/MBtu 

It is useful to evaluate the total impact which the implementation of cogeneration can make 

on total pollution emissions. For this purpose three scenarios from Table 4-3 have been selected. 

This includes the baseline in which there is no cogeneration, the case of cogeneration with a single 

chiller, and the case of cogeneration integrated with district heating. Included in the comparison 

are emissions from the off-site utility, emissions from the engine, and emissions from the on-site 

boiler used to provide heating. To estimate the utility emissions an oil-fired boiler with an 

electrostatic precipitator was assumed. For particulates it was simply assumed that the boiler just 

meets the current EPA New Source Performance Standard limit of 0.03 lb/MMBtu. Emission 

factors for other pollutants were taken from EPA AP 42, 1995. In the case of the engine a sparkignited gas engine with a three way catalyst for emissions control was assumed. Emission factors 

were as listed in Table 2-5. The on site boiler was assumed to be fired with natural gas and 

again emission factors were taken from EPA AP 42. Table 4-5 below provides a summary of the 

emission factors used in this comparison in common units. 

utility on-site boiler engine 

.03 0 0 

.447 .I 33 .324 

.0334 .033 .IO5 

particulates 

Ib/MBtu 

co 

hydrocarbons ,00695 .0055 .322 

Table 4-5: Emission Factors Used in Comparing Total Amounts of Pollution 

Produced by Three Scenarios. 

Table 4-6, below lists the results of the comparison. Negative numbers for particulates in the 

two cogeneration scenarios result from the sale of more electric power back to the utility than was 

purchased from it, leading it to generate less electricity. Also, while the total amount of emissions 

is important, facilities must consider the total amount of emissions produced on site. Table 4-7 below 

is a modification of Table 4-6 in which off-site utility emissions are not considered. 

4-1 8 
particulates 

hydrocarbons 

tons/year 

to ns/year 

to n s/y e a r 

to n s/y e a r 

baseline-no 

cogeneration 

.75 

12.1 6 

1.07 

.21 

cogeneration cogeneration 

with 1 chiller integrated 

with district 

heating 

-.03 -.I 5 

7.00 6.08 

2.36 2.51 

7.1 6 7.97 

Table 4-6: Comparison of Total Amount of Pollutant Emissions with Three 

Selected Scenarios 

particulates I tons/year 

co 

hydrocarbons 

tons/year 

tons/year 

tons/yea r 

baseline-no 

cogeneration 

0 

cogeneration cogeneration 

with 1 chiller integrated 

with district 

heating 

0 

.94 17.40 18.39 ~~ 

.23 2.40 2.68 

.039 7.17 8.00 

Table 4-7: Comparison of Total Amount of On-Site Emissions with Three Selected 

Scenarios 

These calculations indicate that the cogeneration systems enjoy a substantial advantage with 

respect to NO, when total emissions are considered and because they burn only gas, with particulates. 

However, the incomplete burning characteristic of internal combustion engines leads to significant 

increases in CO and hydrocarbons. (The hydrocarbons are largely unburned methane.) Which 

pollutants are most signiscant will depend on local conditions. However, when only on-site emissions 

are considered, cogeneration's advantages with respect to NO, emissions are no longer apparent. At 

this time the environmental permitting process described in Chapter 2 is the only legally significant 

descriptor of acceptable emissions, but many cogenerators view the EPA's failure to account for 

reduced utility emissions a major institutional barrier to increased energy efficiency. 

4-1 9 

5. COMPARATIVE ECONOMIC ANALYSIS FOR THE MODEL FACILITY 

5.1 Introduction 

In this chapter we combine the technical simulation results for the model facility derived in 

the previous chapter with realistic comparative capital and operating costs to determine the relative 

economic merit of the various systems being investigated. Using the simplest case of local boilers and 

purchased utility electricity as a starting point, we calculate both the additional capital investment and 

the annual savings associated with the various modular cogeneration schemes and with the district 

heating and cooling (DHC) plant. For each case we then calculate two "figures of merit": a simple 

payback, which is simply the incremental capital divided by the annual savings, and the twenty-year 

return on investment 0, which is the effective interest being paid on the capital investment by the 

annual savings. 

We will see that the results are somewhat marginal. The modular cogeneration systems show 

a modest 5% ROI. (Since all calculations are in constant 1995 dollars, inflation must be added to this 

before comparing it to alternative investments.) The DHC system is comparable under the most 

fhvorable assumptions, and is sometimes not viable. However, bear in mind that these are results for 

national average enerq quantities. Far more meanin@ results will be presented in the following 

two chapters, where this analysis is applied to the climates of particular Navy divisions. Even then 

we would caution against using this or any similar study to determine specific investment decisions; 

choices about what energy system will be best can only be made in the context of site-specific 

engineering studies. Work such as is presented here can be used to help decide where such 

engineering studies should be carried out fist, and to establish technical needs requiring research and 

development, and we will point to these results as they emerge. 

5.2 Economic Assumptions 

The simplicity of the ROI approach allows us to base the analysis on one economic 

assumption: we use a study life of twenty years. This period is a suf€iciently long period to expect 

capital intensive projects to pay for themselves, and is appropriate for a large, stable institution such 

as the Navy. The ROI then represents the return generated by the additional capital needed to install 

a more energy efficient system, return realized as annual savings in %el and electric bills. If "K" is 

the additional capital, "A" the annual operating savings and "n'l the number of years (here, 20), then 

WA = [ 1 -( l+ROI)'"]/ROI. 

This transcendental equation must be solved iteratively for ROI, but this is accomplished 

automatically by spreadsheet subroutines. The ROI is of course the return on the investment over 

and above that needed to pay off the original capital. 

5- 1 

_I___ 
Because the annd savings are largely lowered electric costs, they can be expected to increase 

more or less with inflation. The ROI is calculated usiig the annual savings in 1995 dollars, and hence 

represents a constant dollar return. An expected rate of inflation (perhaps 2% for electricity) should 

be added before the ROI is compared with other investments not discussed in this study. More 

importantly, the ROI is primarily suggested as a means of comparing results within this study. 

L 

Electricity Costs: Gulf Power (Pensacola) 

Energy: $0.0398 kWh 

Demand: 11.61 kW-mnth 

Ratchet: 1 months 

Service: $227 /month 

Purchases $0.0373 kWh 

Gas: $0.474 /therm 

= $4.74/MBtu 

Service: $50 /month 

Inflation: Use constant 1995 dollars 

Studv duration: 20 vears 

Fuel Cost: 

Economics: 

- 

The other economic assumptions are 

displayed in Table 5-1. Electricity costs 

include service, demand and energy charges, 

and are proportional to those of GulfPower, to 

be discussed below. However, both the energy 

and the demand charges have been scaled up so 

that the aveme cost of electric energy (that is, 

the total electric bill divided by the total 

kilowatt-hours delivered) comes out equal to 

the national average cost of electricity in the 

commercial sector, 7.46 #/kWh'. We assume 

in this chapter that power can be sold back to 

the utility for one-halfthis rate, or 3.73 #/kWh. 

Fuel costs refer only to natural gas, and 

we use the national average rate of 

$4.74/MBtu2, with an added monthly service 

Table 5-1 : Economic Assumptions for 

Model Facility. 

charge of $50, which has a negligible impact on the economics. 

5.3 Equipment Costs 

The portfolio of available equipment is displayed in Table 5-2. The 12OkW units are the IS1 

spark-ignited natural gas machines discussed in Chapter 2. Both the capital equipment cost and the 

O&M are manufhcturer's prices, and the O&M charge includes regular replacement or rebuilding of 

the units as they age. 

5-2 
08tM 

($Wear) 

14.0 

90.4 

0.5 

0.6 

2.0. 

0.5 

2.0 

0.8 

0.9 

I .o 

15.0 

8.0 

1) Capacitv incrernented to 

- Cooling Tower - Capac'w Cost 

(tons) ($1 000's) 

42 5.0 

270 15.0 

C - 

Total 

Capital 

I1 0.0 

485.0 

11.5 

25.3 

104.2 

Cogenerators: 

120 kW: 

775 kW: 

210 kBtuh 

720 kBtuh 

5000 kBtuh (1) 

Boilers 

Equipment 

($1 OOOts) 

105.0 

470.0 

5.9 

14.2 

60.9 

4.7 2.0 I 26.7 

55.0 

1.6 

2.8 

3.2 

4.1 

47.6 

1.8 

2.7 

3.6 

:over 20% losses in DH( 

' 19 

535 

I1 

Inc. 

Inc. 

n 

Y 

68.0 353.8 

2.0 , 14.7 

19.0 

24.9 

151 5.0 

780.0 

8 ton 

16 ton 

26 ton 

DHC System: 

MaxCapCost: 

MinCapCost: 

Table 5-2: Equipment Costs 

9.3 

13.4 

18.1 

Any generator that is to run when there is no or low thermal demand must have a radiator to. 

eliminate the thermal energy; since this can be done at engine temperatures (180-190'T), the radiator 

will have a lower unit cost than the cooling towers associated with air conditioning. Its capacity is 

nonetheless measured in "tons", as for all the cooling towers'. 

The 775 kW cogenerator, used in the DHC system, is also a spark-ignited reciprocating 

engine, albeit much larger. It is typical of units available fiom Detroit Diesel, Waukeshaw or several 

other manufacturers. The installed cost, derived from DOE sources3 and updated to mid-1995 

dollars4 is consistent with those used in the OW study cited previously. 

Three different sizes of boilers are needed to suit the various configurations. The installed 

capital costs are derived fiom estimating manuals6 and the O&M costs, principally for cleaning, are 

based on estimates of one to four person-days per year, consistent with the cleanliness of natural gas. 

* "TOIIS" refers to the capacity a compression chiller with a COP of about 3.0 could have with this cooling tower 

dissipating all the reject thermal energy, so one ton of heat dissipation capacity equals 12,000 Btuh*(1+1/3.0) or 16,000 

Btuh. 

5-3 
The ten ton absorption chillers are the Yazaki units discussed in Chapter 3. The capital costs 

are fiom Yazaki, with estimated installation expenses6 added. The 280 ton absorption chiller, used 

in the DHC system, is priced completely from estimating manuals. Three different sizes of 

compression chillers are needed to fit the.various configurations, and their capital costs are also 

broken out from estimating manuals as indicated. 

Finally, the district heating system costs are far too uncertain to assign a specific number to, 

depending as they do on many site-specific fictors. Here we are only considering the costs of piping 

and associated heat exchangers, since the energy sources have been itemized. High cost could arise 

because of diflicult, rocky terrain or because of many preexisting ini?astructure components (gas and 

telephone lines or roads) that must be avoided. Ifthe system is replacing a deteriorated but existing 

district heating system, costs may be lowered because the trenches must be dug to remove old pipe, 

and perhaps some of it may be salvageable, but the installation of the cooling water circuits will still 

be costly. The amount of speculation that can go on in the absence of a particular site is endless and 

expensive, so rather than attempt to work up any detailed roster of costs for particular systems, we 

draw on previous work to determine a range, where most district heating and cooling distribution 

systems can be expected to have installed capital costs lying within that range. 

The previous work, a recent BNL study7, examined several district heating and cooling system 

configurations and found that the cost of a system delivering hot water was $2.60-7.0O/MBtuy which 

would correspond to a capital cost for this 11340 MBtu/year system of $295-794k. (Capital costs 

were annualized at 10% per year in that study.) In the same study, for a system delivering 4950 

MBtu of cold water per year, the cost of adding the cold water piping was found to be $6.80- 

17.60/MBtu of delivered chilled water, corresponding here to an additional capital cost of $337-871k. 

These costs (for delivering chilled water) may seem high, but they are realistic. The basic problem 

is that there is only a ten degree temperature swing as the chilled water travels through the system. 

Consequently, three to five times as much water must be moved per MBtu as in the case of hot water 

distriiution. Combining these uncertainties following the methods of the earlier study' we find that 

capital costs will likely range between $780k and $1515k, and we work out the economic 

consequences of being at both ends of this range in the analysis to follow. 

These piping expenses are substantial amounts of money, and to krther validate them we 

examined the system defined in the ORNL reportg. A figure in the report showed the rough layout, 

and assuming that the buildings were separated by distances comparable to their sizes, we laid out 

a very rough distribution network and found about 6000 feet of pipe trench was needed, with four 

times that much pipe. Our costs fiom the previous paragraph then imply a unit cost of $130-250 per 

foot of trench, consistent with figures from estimation manuals6 when the need for insulation, 

drainage, expansion sections and the other complexities of DHC are taken into account. 

5-4 
5.4 Analysis for Boilers and Utility Electricity 

Boilers: 

9 210 kBtuh 

7 720 kBtu h 

The fist case examined was that of local boilers in each building and utility electricity. It is 

certainly the system with lowest capital cost, and the equipment is described in Table 5-3. Each large 

building gets a large (720 kBtuh) boiler, and we here simplify the model facility by assuming that each 

of the nine small buildings are identical and can be served by one 210 kBtuh boiler. Capital and 

variable (O&M) costs are taken f?om Table 5-2 by multiplying by the number of boilers in each case. 

Fuel costs are found by multiplying the he1 use indicated in Table 4-3 (broken out by building type 

as in Appendix B) by the natural gas price in Table 5-1. 

Capita Variable Fue @ eff 

($k: ($Wear) ($Wear: 

103 4.5 18.3 80 

177 4.2 48.9 80 

Cooling is supplied by a single 

compression chiller for each building, 

sized to meet the cooling demands 

developed in Table 4-4; again the nine 

small buildings are treated as if they 

were identical. Compression Chillers 

9 8 ton 1 32 

7 26 ton 174 

Electricity 

FKed Demand 

(k$iyear) (k$/year) 

2.7 171 

The annual cost of electricity is 

developed in detail. First the monthly 

service charge from Table 5-1 is 

multiplied by twelve (months) and 

entered as a fixed annual amount. 

Then the "Total Electric Demands" for 

each month fiom Table 4-4 are 

multiplied times the demand charges @ 

Table 5-1 and entered in Table 5-3 

under "Demand"; this is the annual 

7.2 

7.0 

Energy Total Average 

(k$iyear) (ksiyear) ($kWh) 

199 373 0.074 

Totals: 

Capital outlay: $586 k 

Annual Outlay: $463 k 

The "Non-Ac Table 5-3: Boilers and Utility Electricity Energy" (Here, 4524 MWh) is taken 

f?om?able 4-2 or 4-4 and is added to the electric energy required by the compression chillers, derived 

by dividing the total Annual Cooling Energy fiom Table 4-2 or 4-4 (Here, 4951 MBtu) by the 

national average seasonal energy efficiency rating (SEER) of 10.36. This sum is then multiplied by 

the energy charge to calculate the annual total spent on energy charges (here, $199k). 

These three quantities are then summed to give the total annual electric bill (Here, $373k). 

This total is then divided by the total energy delivered to derive the average cost of a kilowatt-hour, 

including all demand and fixed charges. It is this number that we set to the national average cost of 

electricity, 7.46 #kWh by adjusting the energy and demand charges for the model facility in Table 

5-1. 

The various quantities are then separately totaled to give the one-time capital outlay (here 

$586k) and the annual operating costs (here $463k). These are not the total cost of operating the 

energy plant for the model facility. They only include components which will be replaced if the 

5-5 
modular cogeneration system or the DHC system are employed instead of the boilerhtility electricity 

systeq. Items such as thermal and electric distribution within each building are completely omitted 

since they will be the same, or nearly the same. These costs will serve as a meaningfbl basis for 

comparison between the systems discussed in this report; because of the many omissions, they should 

not be used for comparison of these systems with other conceptual designs which may have included 

more or less detail in their calculations. 

. 

Sogenerators: 

9 120 kW 

3oilers: 

16 210lkBtuh 

4bsorption Chillers: 

0 10 tons 

Zompression Chillers: 

9 8ton 

7 26ton 

5.5 

Capital Variable Fuel @effic. 

($k) ($wear) ($k/year) 

990 112 226 381 

183 8 18 80? 

0. 0 0.6: 

132 7 3.0: 

174 7 3.0: 

Analysis for Modular Cogeneration 

Fbted 

(k$/year) 

2.7 

- Sales: 

A similar analysis for 

modular cogeneration is presented in 

Table 5-4. Many quantities are 

treated just as they were in Section 

5.4, and will not be described in 

detail again. Here each of the seven 

large buildings has one 120 kW 

cogenerator, while two other 120 

kW units are on site somewhere but 

are not assumed to produce useM 

thermal energy. These two 

additional units are included because 

the analysis reported just below 

indicates that under the assumptions 

of Table 5-1, the system pays 

substantial demand charges to the 

utility ifit has only seven generation 

units. Because these units are used 

at very low load factors and are not 

assumed to cogenerate, their variable 

O&M charges are taken as one-half 

those used in the fist seven units, 

presented in Table 5-2. Their capital 

charges are not reduced. 

Demand Energy Total Average 

(k$/year) (k$/year) (k$/year) ($/kWF 

20.9 3.8 27.4 0.101 

(I 5.0) (Income] 

The thermal output of the 

cogenerators is not adequate to meet 

rotals: 

Capital outlay: 

Annual Outlay: 

$1,479 k 

’ 391 k 

the Peak heating demands of the Table 5-4: Modular Cogen, No Absorption Chillers. 

large buildings (Table 44, but in 

contrast to the situation with boilers and utility electricity (Section 5.4), the large buildings now need 

only the smaller 210 kBtuh boilers, so capital costs for boilers are somewhat reduced. There are no 

absorption chillers, and the system is served by the same set of compression chillers as in the boilers 

and utility electricity case. 

5-6 
Electricity accounting is pefiormed as it was for the case of boilers and utility purchases, 

except that now the demand is obtained from the lowest rectangle in Table 4-4, where the demand 

met by the nine cogenerators has been subtracted out. The result, shown in Table 5-4, when totaled 

and divided by purchased energy, is that the purchased energy costs 10.4 #/kWh. This dramatic 

. increase @om 4.74 #/kWh) is due to the low load factor of the residual purchases. The total capital 

and total annual outlays are summed and presented as before. 

9 

893 

27 

72 

12.3 

In the lowest section they are compared to the case of boilers. The “incremental capital 

outlay” is the amount by which “total capital” just above exceeds the “total capital” for the case of 

boilers. The “annual savings” are the amount by which the “annual outlay” for the case of boilers 

exceeds the “annual outlay” just above. “Simple payback” is just the incremental capital divided by 

the savings, since the ROI is the constant dollar interest rate obtained when the savings are treated 

as levelized payments on a debt the size of the incremental capital. Thus the raw capital, with no 

interest, would be returned in 15.5 years, and an agency which invested an extra $1479k to build this 

system would see a net return on its investment of 2.5% over twenty years. 

10 11 

1003 1113 

13 7 

80 78 

12.5 14.2 

As mentioned above, two extra generators are included in the system, giving a total of nine. 

These could either be located in one of the seven large buildings as spares, or elsewhere on site. They 

could perhaps be located in one of the smaller buildings and provide usem thermal energy there, but 

we have not assumed this, since their presence can be justifled solely on the basis of electrical savings. 

This is demonstrated in Table 5-5, where the results of calculations for this system with seven through 

eleven cogeneration units are displayed. For each case we show the total cost of purchased electricity 

and the incremental capital and annual savings relative to the case of boilers and purchased electricity, 

and the derived simple payback, as explained just above. The simple payback is shortest for nine 

generators, although the differences are small, and we have found that this choice seems optimal or 

nearly optimal for all the systems examined in this report. 

# Cogenerators: 17 

Incremental Capital (Sk): I 673 

Electric Purchases (Sk): 

Annual Savings (Sk): 

12.6 

8 

783 

47 

63 

12.5 

Table 5-5: Economic Performance versus Number of Cogenerators 

5-7 
We then examined a 

system with seven ten-ton Yazaki 

chillers included, as shown in 

Table 5-6. The absorption chillers 

allowed a reduction in the 

compression chillers required to 

meet peak cooling loads in the 

large buildings, so the associated 

capital increment is less than bare 

cost of the absorption units. 

O&M costs increase somewhat, 

but the cost of purchased 

electricity drops by nearly $7k, 

and &el costs go down $8k. The 

overall result is that the capital 

cost of the system has increased 

by $145k, while operating costs 

have decreased by $12k. Looking 

at the system as a whole, this has 

resulted in an insignificant 

increase in the simple pay back 

and a tiny decrease in the ROI. 

Looking only at the additional 

chillers, one can easily calculate 

fiom Tables 5-5 and 5-6 that their 

incremental capital costs were 

$145k, and that they saved about 

Zogenerators: 

3oilers: 

4bsorption Chillers: 

Zompression Chillers: 

9 120 kW 

16 210kBtuh 

7 10tons 

9 8ton 

7 16 ton 

Capital Variable Fuel @ effic. 

($k) ($wear) ($wear) 

990 112 21 8 385 

183 8 18 805 

1 87 4 0.6f 

132 7 3.0: 

133 6 3.0: 

$12k per year, giving a simple Table 5-6: Modular Cogen with One Absorption Chiller. 

payback of 12 years and offering 

an ROI of 5.6%. Absorption chillers, at these prices and in this national average/model facility case, 

seem to be an investment comparable to the modular cogeneration system itself- an investment a 

carefid planner will find worth making, but not a tembly exciting one. 

Fwed Demand Energy 

(k$/year) (k$/year) (k$/year) 

2.7 16.5 1.3 

- Sales: 

Note that these calculations are for the only small absorption chiller available in the U.9 

today, available at what we consider to be a high price compared to what is possible. Calculations 

similar to those above, but based on a 25% reduction in the cost of the chiller unit indicate that 

payback periods would be reduced to six to seven years and ROI's increased to 12-14%, making the 

chillers a much more interesting investment. This kind of price reduction could probably be brought 

about without technical breakthroughs, simply by hard bargaining for large numbers of chillers. It 

is certainly possible if development money is directed at cost reduction. 

Total Average 

(k$/year) ($/kWh) 

20.5 0.071 

(1 5.0) (income) 

5-8 

Totals: 

Capital outlay: 

Annual Outlay: 

$1,625 k 

378 k 

~ncremental Capital Outlay: 

4nnual Savings: 

Simple Payback: 

Xeturn on Investment: 

$1,039 k 

85 k 

12.3 years 

5.2%/vear 
We also examined the case 

where two absorption chillers are 

added for each cogenerator, and 

the results are displayed in Table 

5-7. The incremental savings at 

the bottom of the table indicate that 

this system is somewhat less 

attractive than the system with 

one absorption chiller per cogen 

unit. A careful look, however, 

indicates that the second 

absorption chiller is a very bad 

investment under these conditions. 

The capital outlay has increased 

by Sl57Iq while the annual outlay 

has also increased! Not only do 

the chillers not save money, but 

their small maintenance costs 

outweigh their electricity savings, 

making them undesirable even if 

capital costs were zero. 

Zogenerators: 

3oilers: 

4bsorption Chillers: 

Zompression Chillers: 

9 120 kW 

16 2lOlkBtuh 

14 10tons 

16 8ton 

0 16ton 

Under the assumptions 

used here, of national average 

thermal and electric loads and 

prices and the equipment costs 

enumerated above, modular 

Capital ’Variable Fuel @ effic. 

($k) ($k/year) ($wear) 

990 112 21 9 385 

183 8 18 805 

373 7 0.6: 

235 ‘ 13 3.0: 

0 0 3.0: 

Fbted 

(k$/year) 

- Sales: 

2.7 

cogeneration does appear to be a Table 5-7: Modular Cogen with Two Absorption Chillers 

desirable option, and systems with 

one absorption chiller per cogeneration unit appear to be optimal. As we cautioned above, this result 

should only be used to indicate that these systems are worthy of fiuther study; the regional studies 

to be presented in the next two chapters will hrther refine our assessments of where and under what 

circumstances modular cogeneration should be pursued at the level of engineering studies. 

Demand Energy Total Average 

(k$/year) (k$/year) (k$/year) ($/kWh) 

14.0 0.5 17.3 0.08E 

(1 5.0) (income) 

5.6 

Totals: 

Capital outlay: 

Annual Outlay: 

Analysis for District Heating and Cooling System 

$1,782 k 

379 k 

Before proceeding to regional studies, we briefly examine an obvious competitor to modular 

cogeneration, centralized cogeneration with “district heating and cooling” (DHC), a system of 

insulated pipes to distribute heated and chilled water around the base. We have discussed the 

equipment costs and given a brief description of the DHC system above. Again, because the cost of 

the piping system depends so strongly on many local variables, we work out the economics for two 

ncremental Capital Outlay: 

4nnual Savings: 

Simple Payback: 

?eturn on Investment: 

5-9 

$1,195 k 

84 k 

14.2 years 

3.5% 
I. 

Cog enerator: 

1 775 kW 

0 120 kW 

1 50001kBtuh 

1 280tons 

Boilers: 

Absorption Chiller: 

DHC Pipe, etc.: 

max: 

min: 

Capital Variable Fuel @ effic. 

($ k) ($Wear) ($wear) 

485 90 235 387 

0 0 0 387 

104 2 21 807 

354 2 0.6! 

1515 15 80? 

780 8 809 

FHed 

(k$iyear) 

- Sales: 

2.7 

Demand Energy Total Average 

(k$/year) (k$/year) (k$/year) ($/kWh) 

55.8 9.0 67.5 0.30( 

(46.0) (Income) 

Totals: 

Capital outlay: 

Annual Outlay: 

Max Min 

$2,458 $1,723 k 

387 380 k 

Incremental Capital Outlay: 

4nnual Savings: 

Simple Payback: 

qeturn on Investment: 

Min 

systems, one near the upper limit of expected piping costs, the other near the lower limit. The results 

are in Table 5-8. 

The large capital 

requirements of the DHC piping 

system result in substantial capital 

outlays in both cases. At the low 

end of the piping cost spectrum, 

the capital outlay is comparable to 

that for the modular cogeneration 

system with one chiller per cogen 

unit, but at the high end of the 

cost spectrum it is nearly 50% 

higher. The annual outlay is quite 

similar to that of the modular 

system, so the overall comparison, 

either in terms of simple payback 

or ROI, favors the modular 

system slightly over the low-cost 

DHC system and greatly over the 

high-cost DHC system. 

We would like to 

emphasize that we do not regard 

this comparison as a 

demonstration that "modular 

cogeneration is better than DHC"; 

such categorical statements are 

meaningless for systems as 

individual and complex as energy 

supply systems. We have 

demonstrated, we believe, that on 

the basis of national -average Table 5-8: District Heating and Cooling System 

statistics, in bases where the 

installation or major overhaul of a DHC system is being studied, a conceptual study of a competitive 

modular cogeneration system wilI be worth carrying out. 

In the following chapters, we examine modular cogeneration systems in different climatic and 

economic regions to see where they are most likely to be advantageous. Because the same factors - 

fbel and electric prices and thermal loads - will tend to make both DHC and modular cogeneration 

more or less valuable, and because of the great uncertainty in piping costs, we have not examined 

DHC systems in all the different regions. However, Table 5-8 indicates that DHC systems and 

5-1 0 
cogeneration systems can be quite close in value, so we recommend a side-by-side evaluation of both 

systems at any site where either appears to be promising. 

5-1 1 

6. MODULAR COGENERATION IN THE NAVY 

6.1 Introduction 

The preceding analysis of modular cogeneration, using national-average energy-use data for 

commercial buildings showed that modular cogeneration offered an attractive alternative to 

conventional boilers and utility electricity. The questions remain whether these results are applicable 

to military energy-use conditions, and in what climates these technologies will prove most attractive. 

In this chapter we cany out simulations of the operation of modular cogeneration systems using 

actual data characterizing Navy activities. In the following chapter we perform an economic analysis 

based on the results of these Siulations. To carry out this program, we made use of data on energy 

use in the Navy, which were made available to us through the Energy Audit Report (EAR) database. 

The Navy maintains the "Navy Energy Works'' bulletin board to provide assistance and 

information to its energy managers. One of the fknctions of the bulletin board is the EAR system. 

This microcomputer data system allows energy managers to report energy consumption, cost, and 

building floor area as required by Federal policy. 

Navy energy use by fie1 type is collected for each individual shore activity on a monthly basis 

and reported quarterly. Data are available for each individual activity and also in several aggregated 

forms. For this analysis, we chose data aggregated by Engineering Field Division (EFD), which is 

based on geographical area. Altogether about 400 locationally distinct energy-using activities are 

included in the seven EFD's, some of which may be subdivided into two or more reporting categories. 

The Navy's seven EFD's are given the acronyms CHESDIV, LANTDIV, NORTHDIV, 

SOUTHDIV, WESDIV, SWESTIV, and PACDIV. These are (for the most part) geographically 

contiguous regions into which the Navy's various activities are grouped. CHESDIV comprises 

activities mostly in the Washington, DC area, including nearby areas in Maryland and Virginia. 

LANTDIV includes the Navy's extensive facilities in coastal Virginia as well as a smaller number of 

activities in surrounding states. It also includes activities on foreign soil in the Atlantic and 

Mediterranean. NORTHDIV includes New England, the Middle Atlantic states, and the Midwest. 

SOUTHDIV stretches from South Carolina to Texas, with a major concentration in Florida. 

WESTDIV activities are mostly in northern California and Washington State. SWESTDIV comprises 

the extensive range of Navy activities in San Diego and other parts of southern California. PACDIV 

is composed mainly of Navy activities in Hawaii, Guam, and Japan. 

For each of these EFD's, we obtained a data set for calendar 1994 that broke energy use down 

into categories of facilities. Some of these categories were not buildings-related. These include "cold 

iron," which is ships at the dock that take power fiom shore; transmitters; simulators; and 

miscellaneous. These were not included in the analysis. Another category not included was 

"GOCO, " which means "Government owned, contractor operated'' facilities. For most EF'D's the 

6-1 
GOCO category was a small &action of the total, and in one the energy use numbers were so large 

as to represent a special case. 

The remaining categories represented housing and work areas operated by the Navy and the 

Marine Corps: Navy Housing, Marine Housing, Marine Activity, and Shore Activity. For each of 

these categories a 12-month summary of energy use by &el is given, including electricity, natural gas, 

&el oils of various types, propane gas, coal, and steam and hot water. The unit cost of each energy 

input was also given, as well as the total dollar cost of that &el. The total area of buildings in each 

category was also given. 

In addition to the annual summary, monthly and quarterly breakdowns were also provided. 

These proved crucial in separating out the space-heating and air-conditioning components of the 

energy use. Finally, we were also able to obtain a listing of the activities located in each of the EFD's. 

This allowed us to assess the average size of an activity in terms of its annual energy use and building 

floor area, to compare with the typical multi building facility used in our earlier analysis. If the 

average Navy activity were much smaller than this typical multi building facility, we would worry that 

the results might not be applicable. On the other hand, if the Navy's administrative units were orders 

of magnitude larger than our typical multi building facility, one could be concerned that the modular 

cogeneration approach might strike managers as being too incremental to address their larger 

concerns. In fact, we concluded that the average Navy activity in the Em's are three to six times as 

large, in terms of building area, as our typical multi building facility. Because our approach is 

modular, the results should scale to the Navy's activities without much distortion. Moreover, using 

a somewhat smaller base than the Navy's average has the advantage that its results are applicable even 

to smaller-than-average administrative groupings,'while at the same time scaling linearly to larger 

ones, because of the modularity of the approach. 

6.2 Annual Summaries 

The first step was to summarize the energy-use and pricing information for each of the 

categories within each EFD, and thereby to obtain EFD-wide averages. These summaries are shown 

in Tables 6-2-1 through 6-2-7. Each table gives a breakdown of the locations of Navy activities 

within the EED. Also, the availability and price of natural gas is brought out, because of our use of 

a natural-gas fired cogenerator in the'analysis. 

Within each table, Column 1 is total building area. Column 2 is electricity, in Gwh, delivered 

to the site, while column 3 converts this to primary energy (&el at the power plant) using DOE'S 

standard heat rate of 11 000 Btu/kWh. Although primary energy is not an input to our later analyses, 

which emphasize dollar cost, it does enable us to compare the energy intensities (energy use per unit 

area) of buildings in the Navy with the national average for commercial buildings. We wanted jirst 

to make sure that our numbers were reasonable, and second to see ifthere were any discernible 

differences between the Navy and the civilian sector with regard to total primary energy use. 

6-2 
Column 4 gives total fuel use (other than electricity), while column 5 adds fie1 to electricityprimary to obtain total primary energy. Columns 6 and 7 give the price of electricity and the average 

price for fie1 paid by each category within the EFD. These fie1 prices were obtained by averaging 

the fuel prices for the individual fkels used, as given in the Navy data set, weighted by energy content 

- of the fkel. 

The first four rows of each table give these quantities for each category within the EFD. Row 

5 gives the EFD totals. For columns 1-5, these are just the sums of the individual numbers for the 

categories listed above. The electricity and fuel prices are averages weighted by electricity and fuel 

energy use, respectively, for each of the four categories. 

Row 6 gives the energy-use quantities for an average-sized activity in the EFD, obtained by 

dividing the Row 5 totals by the number of activities in the listing mentioned above. Row 7 gives 

energy-use totals per million square feet, so that comparisons between EFD's will not be skewed by 

the differences in building areas among them. Finally, Row 9 gives natipnal-average values for 

commercial buildings, per million square feet, as given in the OBT Data Book. 

The total primary energy in Gbtu per million square feet (which is the same as kBtu per ft.7 

is given in Row 7, with the national average value (198 kE3tu/fl?) just below it. For four of the EFD's, 

the Navy's energy-use intensity is much higher than the national average; for two it is about the same; 

and for one it is less. 

6-3 
Table 6-2-1 Summary of Navy Data for CHESDIV 

Category Building Elec tricity Fuel 

Area Site Primary 

(IO6 ft2) (GWh) (GBtu)' (GBtu) 

Navy Housing 3.74 24 268 80 

Marine Housing 2.41 21 234 255 

Marine Activity 6.27 94 1043 1320 

In CHESDIV, 27 activities were represented in at least one major category with buildings (Navy and Marine housing and shore 

activities, but excluding ships, GOCO's, simulators, transmitters, and miscellaneous). These were distributed geographically as follows: 

Total Elec. 

Primary Price 

(GBtu) (S/MWh) 

348 59.88 

489 50.95 

2363 48.39 

DC 7 MD 16 VA 4 

1, ~~ 

Shore Activity 30.70 700 7700 401 1 11711 56.51 

TOTALS 

PER ACTIVITY 

PER IO6 ft2 

NAT'L.AVG. *** 

43.1 2 840 9244 5668 14912 55.49 

1.60 31 .I 342 21 0 552 ---- 

----- 19.5 217 131 346 ---- 

----- 12.9 142 59 198 74.57 

Fuel Price 

($/MBtu) 

6.52 

1.70 

3.41 

5.50 

4.85 

4.84 

*Note 3: National average energy-use values in kWWft2 or kBtu/ft2. Electricity price and average of oil and gas price, respectively, in ** 

$/MWh and $/MBtu (not per square foot). 

6-4 

. 
Table 6-2-2: Summary of Navy Data for LANTDIV 

Category Building Elec tricity Fuel 

Area Site Primary ** 

(IO6 ft2) (GWh) (GBtu)'* (GBtu) 

Navy Housing 20.85 169 1859 1288 

Marine Housing 8.38 150 1646 0 

Marine Activity 23.59 352 3874 2355 

Shore Activity 79.09 1318 14495 6100 

TOTALS 131.91 1989 21874 9743 

PER ACTIVITY 1.59 24.0 264 117 

PER IO6 ft2 ----- 15.1 166 74 

NAT'L.AVG. *** ----- 12.9 142 59 

In LANTDIV, 83 activities were represented in at least one major category with buildings (Navy and Marine housing and shore 

activities, but excluding ships, GOCO's, simulators, transmitters, and miscellaneous). These were distributed geographically as follows: 

Total Elec. Fuel Price 

Primary Price (S/MBtu) 

(GBtu) (SIMWh) 

3147 66.71 6.03 

1646 63.14 n/a 

6229 50.63 3.30 

20595 57.20 4.05 

31617 57.29 4.13 

381 ---- ---- 

240 

198 74.57 4.84 

---- ---- 

VA 40 NC,WV,MD,KY,PR 13 FOREIGN (ATLANTIC, MEDITERRANEAN) 27 

6-5 
Table 6-2-3: Summary of Navy Data for NORTHDIV 

Building 

Area 

(IO6 ft2) 

16.74 

0.41 

In NORTHDIV, 51 activities were represented in at least one major category with buildings (Navy and Marine housing and shore 

activities, but excluding ships, GOCO's, simulators, transmitters, and miscellaneous). These were distributed geographically as follows: 

NEWENGLAND 16 MIDDLE ATLANTIC 22 MIDWEST 13 

Elec tricity Fuel Total Elec. 

Site Primary ** Primary Price 

(GWh) (GBtu)* (GBtu) (GBtu) (S/MWh) 

113 1238 1444 2682 83.97 

4 39 23 62 61 .OO 

No cogeneration activity M 

0.1 6 

69.27 

86.58 

11 Navy Housing 

2 20 6 26 148.23 

978'' 10758 8340 19098 48.56 

1097 12055 9813 21868 52.43 

11 Marine Housing 

1.70 

----- 

----- 

11 Marine Activity 

21.5 236 192 429 ---- 

12.7 139 113 253 ---- 

12.9 142 59 198 74.57 

TOTALS 

PER ACTIVITY 

PER IO6 ft2 

'Note 1 : Site electricity cc 

Note 2: Includes no stea ** nverted to primary electricity using a power-plant heat rate of 11,000 Btu/kWh. 

n and hot water. 

Fuel Price 

(S/MBtu) 

4.40 

4.16 

5.00 

3.93 

4.00 

---- 

---- 

4.84 

'Note 3: National average energy-use values in kWh/fi2 or kBtu/fi2. Electricity price and average of oil and gas price, respectively, in 

$/MWh and $/MBtu (not per square foot). 

'Note 4: Adjusted for anomalous value of electricity use in the fourth quarter. Fourth quarter set equal to base-year (1 985) value increased 

by average increase of other three quarters over their base-year values. 

*+ 

6-6 

u 1 P 
Table 6-2-4: Summary of Navy Data for SOUTHDIV 

Category 

Navy Housing 

In SOUTHDIV, 94 activities were represented in at least one major category with buildings (Navy and Marine housing and shore 

activities, but excluding ships, GOCO's, simulators, transmitters, and miscellaneous). These were distributed geographically as follows: 

Building Elec- tricity Fuel 

Area Site Primary 

(1 o6 ft2) (GWh) (GBtu)* (GBtu) 

17.70 193 21 26 41 7 

FL 38 GA 9 

54.07 

50.54 

45.95 

48.32 

48.79 

SC 16LA 9 

4.98 

6.89 

3.02 

3.80 

3.78 

TX 6 TN,AL,MS,AR 10 

Marine Activity 

Shore Activity 

TOTALS 

PER ACTIVITY 

PER IO6 ft2 

NAT'L.AVG. *** 

In addition, there was one cogeneration activity listed. 

11.76 142 1563 1121 

73.39 1429 15718 4691 ** 

105.81 1800 19806 6314 

1.13 19.1 21 1 67 

----- 17.0 187 60 

12.9 142 59 

Natural gas comprised 75% if fuel use, at an average price of $3.39/MBtu. 

I I I I 

Marine Housing I 2.96 I 36 I 399 I 85 

I I I I 

Total 

Primary 

(GBtu) 

2543 

484 

2684 

20409 

261 20 

278 

247 

198 

Note 1: Site electricity converted to primary electricity using a power-plant heat rate of 11, 

'"Note 2: Includes 641 GBtu of steam and hot water. 

Fuel Price 

(S/MWh) 

74.57 4.84 

30 Btu/kWh. 

"Note 3 : National average energy-use values in kWh/fiz or kBtu/fiz. Electricity price and average of oil and gas price, respectively, in ** 

$/MWh and $/MBtu (not per square foot). 

6-7 
Table 6-2-5: Summary of Navy Data for WESTDIV 

Category Building 

Area 

(IO6 ft2) 

Navy Housing 22.40 

Marine Housing none 

Marine Activity none 

Shore Activity 83.68 

TOTALS 106.08 

PER ACTIVITY 1.63 

PER IO6 ft2 ----- 

N AT' L. AVG. ** ----- 

In WESTDIV, 65 activities were represented in at least one major category with buildings (Navy and Marine housing and shore 

activities, but excluding ships, GOCO's, simulators, transmitters, and miscellaneous). These were distributed geographically as follows: 

Elec- tricity Fuel Total Elec. Fuel Price 

Site Primary ** Primary Price (S/MBtu) 

(GWh) (GBtu)" (GBtu) (GBtu) (S/MWh) 

178 1956 994 2950 52.51 4.98 

1090 11992 6530 18522 47.87 2.91 

1268 13948 7524 21 472 48.52 3.18 

19.5 21 5 116 330 

12.0 131 71 202 

12.9 142 59 198 74.57 4.84 

---- ---- 

---- ---- 

CA(north) 37 WA 21 AK,ID,NV 4 

6-8 

t 
Table 6-2-6: Summary of Navy Data for SWESTTDIV 

Category Building Elect- ricity Fuel Total 

Area Site ' Primary Primary 

(1 o6 ft2) (GWh) (GBtu)* (GBtu) (GBtu) 

Navy Housing 17.09 74 81 5 482 1297 

Marine Housing 16.04 95 1040 515 1555 

Marine Activity 35.14 361 3970 1651.. 5621 

Shore Activity 46.1 1 609 6694 2346** 9040 

TOTALS 114.38 1139 12519 4994 1751 3 

PER ACTIVITY 2.43 24.2 266 106 373 

PER IO6 ft2 ----- 10.0 109 44 153 

NAT'L.AVG.  ----- 12.9 142 59 198 

e 

Elec. Fuel Price 

Price ( WMBtu) 

( WMWh) 

76.92 7.03 

90.99 5.73 

79.21 4.05 

69.61 4.98 

74.91 4.95 

---- ---e 

---- ---- 

74.57 4.84 

In SWESTDIV, 47 activities were represented in at least one major category with buildings (Navy and Marine housing and shore 

activities, but excluding ships, GOCO's, simulators, transmitters, and miscellaneous). These were distributed geographically as follows: 

CA(south) 43 Az,NM 3 

6-9 
Table 6-2-7: Summary of Navy Data for PACDIV 

Category Building Elec- tricity Fuel Total 

Area Site Primary **  Primary 

(1 o6 ft2) (GWh) (GBtu)* (GBtu) (GBtu) 

Navy Housing 19.05 252 2768 756 3524 

Marine Housing 4.85 41 455 49 504 

Marine Activity 26.33 343 3771 579 4350 

Shore Activity 41.79 656 721 8 2103 9321 

TOTALS 92.02 1292 14212 3487 17699 

PER ACTIVITY 1.56 21.9 241 59 300 

PER IO6 ft2 ----- 14.0 154 38 192 

N AT' L. AVG . ----- 12.9 142 59 198 

In PACDIV, 59 activities were represented in at least one major category with buildings (Navy and Marine housing and shore 

activities, but excluding ships, GOCO's, simulators, transmitters, and miscellaneous). These were distributed geographically as follows: 

Elec. Fuel Price 

Price (S/MBtu) 

(S/MWh) 

90.86 6.19 

97.97 12.71 

138.58 4.80 

95.64 5.50 

106.18 5.63 

---- ---- 

---- ---- 

74.57 4.84 

HI 23 GUAM 11 JAPAN 19 OTHER 6 

6-10 

P 
6.3 Seasonal Breakdowns 

In order to use the Navy data in an analysis similar to that performed on the typical multibuilding facility using national-average data, we needed to know specifically what the space-heating 

and air-conditioning loads were for the Navy buildings. Because these were not broken out 

separately, we decided to make use of the fact that these two loads are seasonally dependent. The 

simplif?ying assumption was made that the seasonal variation in he1 use was due to space heating 

demands, while the seasonal variation in electricity use was due to space cooling demands. The 

calendar quarter with the Iowest fuel use was taken to represent a fuel-use baseload (consisting of 

various forms of process heat and hot water) while anything above that in other quarters was taken 

to represent space heating. The first test of this assumption was whether the maximum fbel use 

always occurred in the winter quarter while the minimum was in the summer. It turned out that this 

was true for all of the EFD's. Similarly, for electricity, the highest use was always in the summer 

quarter, while the lowest was in either the winter or spring quarter. 

Tables 6-3-1 through 6-3-7 show the quarterly breakdowns of electricity and fbel use. For 

fbels, natural gas, fitel oils, and other fbels are shown separately. Following each table, a 14-step 

process of pulling out the seasonal loads is shown. In lines 1-3, electricity use for air conditioning 

is obtained by subtracting four times the minimum quarterly electricity use fiom the annual use. This 

is then converted to an air-conditioning load (line 4) by multiplying by the national-average SEER 

of 10.36 Btun;Vh. Line 5 gives the building area (fiom Tables 6-2-1 through 6-2-7). Line 6 shows 

the air-conditioning load per square foot of building area. Line 7 obtains the non-AC electricity use 

as Line 2 divided by Line 5. 

Lines 8-14 deal with fitel use in an analogous way. Fuel uses other than space heat are called 

''process heat." They are taken as the minimum quarterly fbel use multiplied by four (line 9), and 

subtracted fiom total he1 use (line 8) to obtain space-heat fitel use (line 10). The space heat load is 

then obtained by multiplying by an assumed average boiler efficiency of 0.7. Finally, the space-heat 

load per unit area is obtained by dividing this by the building square footage (line 12). The process 

heat load and load per square foot are shown in lines 13 and 14. 

For the special case of CHESDIV and LANTDIV, a combined analysis is shown following 

Table 6-3-2. It was judged reasonable to combine these two Em's because the building area for 

CHESDIV was much less than for the other EFD's and because they are in the same geographical 

region. It was also the case that the space heating intensities for CHESDIV and LANTDIV were 

quite Werent, for unknown reasons. This was the only real anomaly encountered in the procedure, 

and it was judged better to strike an average by combining the two EFD's. 

6-1 1 
Table 6-3-1. Quarterly Breakdowns of Electricity and Fuel Use in CHESDIV 

20 

30 

40 

1Q 

Yr. 

Navy 

Housg. 

7 

5 

7 

5 

24 

Electricitv (GWh) 

Marine 

Housg. 

53 

13 

8 

182 

256 

Fuels 

Marine 

Act' y. 

347 

19 

12 

123 

2 

3 

(GBtu) 

Shore 

Act'y. 

896 

590 

117 

288 

492 

96 

95 I 155 

7 

2 

114 

585 

238 

183 

202 

545 

Note:. First line under fuels is fuel oils of all kinds; second line is natural gas; third line is all other fhels. 

Note: Other fuel in Shore Activity is 99% coal. 

6-12 

4 

Total 

2074 

1030 

692 

1866 

5662 
Table 6-3-la: Extraction of Heating and Cooling Loads for CHESDIV 

1. Total Electric 

2. Non-AC Electric 198 X 4 

3. AC Electric [1]-[2] 

4. AC Load [3] X 10.36 

5. Bldg. Area 

6. AC Load/ft2 [4]/[5] 

7. Non-AC Electric/ft2 [2]/[5] 

8. TotalFuel 

9. Process Heat Fuel 692 X 4 

10. Space Heat Fuel [SI-[9] 

11. Space Heat Load [lo] X 0.7 

12. Space Heat Load/ft2 [ 11]/[5] 

13. Process Heat Load [9] X 0.7 

14. Process Heat Load/R2 [13]/[5] 

842 GWh 

792 GWh 

50 GWh 

518 GBtu 

43.12 X 106ft2 

12000 Btu/ft2 

18.4 kWh/ft2 

5662 GBtu 

2768 GBtu 

2894 GBtu 

2026 GBtu 

47000 Btu/ft2 

1938 GBtu 

44900 Btu/R2 

6-13 
Table 6-3-2: Quarterly Breakdowns of Electricity and Fuel Use in LANTDIV 

2Q 

3Q 

40. 

1Q 

Yr. 

Electricity (GWh) Fuels 

Navy Marine Marine Shore Total Navy Marine Marine 

Housg. Housg. Act'y. Act'y. Housg. Housg. Act'y. 

42 51 72 312 477 257 41 0 

188 1 

15 438 

41 29 86 31 1 467 21 3 210 

78 4 

9 280 

48 39 106 363 556 191 137 

34 4 

5 274 

38 30 89 332 489 221 249 

64 11 

12 338 

169 149 353 1318 1989 1287 2356 

GBtu) 

Shore 

Act'y. 

1603 

599 

250 

71 8 

41 2 

100 

644 

290 

91 

748 

520 

125 

6100 

Total 

3761 

2024 

1670 

2288 

9743 

6-14 
Table 6-3-2a: Extraction of Heating and Cooling Loads in LANTDIV 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10 

11 

12 

13. 

14. 

Total Electric 

Non-AC Electric 467 X 4 

AC Electric [ 11-[2] 

AC Load [3] X 10.36 

Bldg. Area 

AC Load/R2 [4]/[5] 

Non-AC Electric/R2 [2]/[5] 

Total Fuel 

Process Heat Fuel 1670 X 4 

Space Heat Fuel [SI-[9] 

Space Heat Load [lo] X 0.7 

Space Heat Load/ft2 [ 1 1]/[5] 

Process Heat Load [9] X 0.7 

Process Heat Load/R2 [ 13]/[5] 

1989 GWh 

1868 GWh 

121 GWh 

1254 GBtu 

131.91 X lo6 ft2 

9 500 Btu/ft2 

14.2 kWh/R2 

9743 GBtu 

6680 GBtu 

3063 GBtu 

2144 GBtu 

16300 Btu/ft2 

4676 GBtu 

35400 Btu/R2 

6-15 
Table 6-3-2c: Extraction of Heating and Cooling Loads in CHESDIV and LANTDIV Combined 

1. Total Electric 842 + 1989 2831 GWh 

2. Non-AC Electric 792 + 1868 2660 GWh 

3. AC Electric 50+ 121 171 GWh 

4. ACLoad 518 + 1254 1772 GBtu 

5. Bldg. Area 43.12 + 131.91 175.03 X lo6 R2 

6. AC Load/ft2 [4]/[5] 

7. Non-AC Electric/R2 [2]/[5] 

10 100 Btu/ft2 

15.2 kWh/ft2 

8. TotalFuel 5662 + 9743 15405 GBtu 

9. Process Heat Fuel 2768+6680 9448 GBtu 

10. Space Heat Fuel 2894+3063 5957 GBtu 

1 1. Space Heat Load 2026+2144 4170 GBtu 

12. Space Heat Load/R2 [ 11]/[5] 23 800 Btu/ft2 

13. Process Heat Load 1938 + 4676 6614 GBtu 

14. Process Heat Load/ft2 [13]/[5] 37 800 Btu/ft2 

6-16 
Table 6-3-3: Quarterly Breakdowns of Electricity and Fuel Use in NORTHDIV 

Marine 

Act'y. 

4 

Electricity (GWh) Fuels (GBtu) 

I 1 It I I I 

Shore 

Act'y. 

21 55 

1555 

25 

26 1 

~5 8338 

Marine Total 

Act'y. 

Marine 

Housg. 

Marine 

Act'y. 

245 

264 

158 

235 

2Q 4563 

3Q 

4Q 

10 

Yr. 

Note: : 

15 

27 1 1906 

5 

1 260 I 291 11 36 1048 

2 

238. I 265 11 135 984 2293 

1039 

4 

i2 

112 I 4 2 978 I 1096 11 1443 9810 ~~~ ~ 

rst line under fuels is fuel oils of all kinds; second line is natural gas; third line is all other fuels. 

+Note: The value reported, 533 GWh, was not consistent either with other quarters of the referenced year nor with baseline values from 

1985. A corrected value increasing the baseline by the average of the percentage increase of the other three quarters from baseline was 

substituted as more representative of an average year, regardless of whether the stated value was in error or represented an "unusual event." 

6-17 
Table 6-3-3a: Extraction of Heating and Cooling Loads in NORTHDIV 

1. Total Electric 

2. Non-AC Electric 264 X 4 

3. AC Electric [1]-[2] 

4. AC Load [3] X 10.36 

5. Bldg. Area 

6. AC Load/ft2 [4]/[5] 

7. Non-AC Electric/ft2 [2]/[5] 

I 

I 

1 

8. Total Fuel 

9. Process Heat Fuel 1048 X 4 

10. Space Heat Fuel [8]-[9] 

11. Space Heat Load [lo] X 0.7 

12. Space Heat Load/ft2 [ 1 114 51 

13. Process Heat Load [9] X 0.7 

14. Process Heat Load/ft2 [13]/[5] 

1096 GWh 

1056 GWh 

40 GWh 

414 GBtu 

86.58 X 106ft2 

4 800 Btu/ft2 

12.2 kWh/ft2 

9810 GBtu 

4192 GBtu 

5618 GBtu 

3933 GBtu 

45 400 Btu/ft2 

2934 GBtu 

33 900 Btu/ft2 

6-18 
Table 6-3-4: Quarterly Breakdowns of Electricity and Fuel Use in SOUTHDIV 

193 I 36 I 143 I 1429 I 1801 

20 

41 6 I 83 

30 

4Q 

10 

Yr. 

'ote: : 

Navy 

Housg. 

Marine Marine Shore Total 

Housg. Act'y. Act'y. 

49 I 9 I 36 I 375 I 469 1 

71 

0 

13 

~ Hous . Hous . 

64 

41 

12 44 392 512 

7 32 343 423 

0 

55 

1 

92 

I 

Fuels (GBtu) 

0 

11 

0 

24 

Marine 

Act' y. 

35 

344 

1 

Shore 

Act'y. 

244 

1261 

264 

2 

222 

163 

595 

192 

1 

237 

1 

278 

1121 

152 

49 1 

I90 

132 

81 1 

197 

Total 

2380 

1259 

1137 

1536 

631 2 

Note: Other fbel in Shore Activity is 76% steam and hot water and 24%coal, 

6-19 
Table 6-3-4a: Extraction of Heating and Cooling Loads in SOUTHDIV 

1. Total Electric 

2. Non-AC Electric 397 X 4 

3. AC Electric [ 11-[2] 

4. AC Load [3] X 10.36 

5. Bldg. Area 

6. AC Load/ft2 [4]/[5] 

7. Non-AC Electric/ft2 [2]/[5] 

8. TotalFuel 

9. Process Heat Fuel 1137 X 4 

10. Space Heat Fuel [SI-[9] 

1 1. Space Heat Load [ 101 X 0.7 

12. Space Heat Load/ft2 [ 11]/[5] 

13. Process Heat Load [9] X 0.7 

14. Process Heat Load/R2 [13]/[5] 

1801 GWh 

1588 GWh 

213 GWh 

2207 GBtu 

105.81 X106 ft2 

20 900 Btu/ft2 

15.0 kWh/R2 

6312 GBtu 

,4548 GBtu 

1764 GBtu 

1235 GBtu 

11 700 Btu/ft2 

3184 GBtu 

30 100 Btu/R2 

6-20 
I 

Marine 

Housg. 

I 

Marine Shore 

Act'y. Act'y. 

258 

1193 

465 

Table 6-3-5: Quarterly Breakdowns of Electricity and Fuel Use in WESTDIV 

Fuels (GBtu) 

209 

899 

300 

261 

704 

157 

245 

1522 

31 8 

178 I I I 1090 I 1268 ]I 994 6531 

Note: First line under fuels is fuel oils of all kinds; second line is natural gas; third line is all other fuels. 

Note: Marine Housing and Marine Activity are not represented in this division. 

Note: Other fuel in Shore Activity is 92% coal. 

Total 

2261 

1610 

'1 330 

2324 

7525 

6-2 1 
Table 6-3-5a: Extraction of Heating and Cooling Loads in WSTDIV 

1. Total Electric 

2. Non-AC Electric 3 12 X 4 

3. AC Electric [ 11-[2] 

4. AC Load [3] X 10.36 

5. Bldg. Area 

6. AC Load/ft2 [4]/[5] 

I 7. Non-AC Electric/ft2 [2]/[5] 

8. TotalFuel 

9. Process Heat Fuel 1330 X 4 

10. Space Heat Fuel [8]-[9] 

11. Space Heat Load [lo] X 0.7 

12. Space Heat Load/ft2 [11]/[5] 

13. Process Heat Load [9] X 0.7 

1268 GWh 

1248 GWh 

20 GWh 

207 GBtu 

106.08 X lo6 ft2 

2000 Btu/ft2 

11.8 kWh/ft2 

7525 GBtu 

5320 GBtu 

2205 GBtu 

1544 GBtu 

14 600 Btu/ft2 

3724 GBtu 

35 100 Btu/ft2 

6-22 

. . 
Table 6-3-6: Quarterly Breakdowns of Electricity and Fuel Use in SWESTDIV 

Marine 

Housg. 

21 

Electricitv (GWh) 

Marine Shore Total 

Act'y. Act'y. 

82 146 268 

Fuels 

Marine 

Act"y. 

17 

495 

115 

12 

260 

45 

23 

29 

(GBtu) 

Shore 

Act'y. 

4 

434 

31 6 

4 

428 

278 

87 151 279 

106 157 31 1 

Navy 

Housg. 

19 

61 

8 

21 2 

41 

95 I 361 I 608 482 I 514 1653 2344 

Marine Total 

Housg. 

199 

20 1761 

3Q 18 1255 

4Q 

10 

Yr. 

1 130 98 

19 2 852 

318 

139 

3 

308 

110 

71 

18 

156 I 3;; 

1125 

100 

74 4993 

6-23 
Table 6-3-6a: Extraction of Heating and Cooling Loads in SWESTDIV 

1. Total Electric 

2. Non-AC Electric 268 X 4 

3. AC Electric [ 11-[2] 

4. AC Load [3] X 10.36 

5. Bldg. Area 

6. AC Load/ft2 [4]/[5] 

7. Non-AC Electric/R2 [2]/[5] 

8. TotalFuel 

9. Process Heat Fuel 852 X 4 

10. Space Heat Fuel [8]-[9] 

11. Space Heat Load [lo] X 0.7 

12. Space Heat Load/R2 [11]/[5] 

13. Process Heat Load [9] X 0.7 

14. Process Heat Load/ft2 [13]/[5] 

1138 GWh 

1072 GWh 

66 GWh 

684 GBtu 

114.38 X lo6 R2 

6 000 Btu/R2 

9.4 kWh/ft2 

. 4993 GBtu 

3408 GBtu 

1585 GBtu 

1110 GBtu 

9700 Btu/ft2 

2386 GBtu 

20 800 Btu/ft2 

6-24 
Table 6-3-7: Quarterly Breakdowns of Electricity and Fuel Use in PACDIV 

Electricitv (GWh) Fuels GBtu) 

11 67, 

493 785 

1 

8 

468 725 

7 

467 810 

1 

7 

2103 I3487 

6-25 
Table 6-3-7a: Extraction of Heating and Cooling Loads in PACDIV 

1. Total Electric 

2. Non-AC Electric 284 X 4 

3. AC Electric [ 11-[2] 

4. AC Load [3] X 10.36 

5. Bldg. Area 

6. AC Load/ft2 [4]/[5] 

7. Non-AC Electric/ft2 [2]/[5] 

8. TotalFuel 

9. Process Heat Fuel 725 X 4 

10. Space Heat Fuel [SI-[9] 

11. Space Heat Load [lo] X 0.7 

12. Space Heat Load/ft2 [ 11]/[5] 

13.' Process Heat Load [9] X 0.7 

14. Process Heat Load/ft2 [13]/[5] 

1293 GWh 

1136 GWh 

157 GWh 

1627 GBtu 

17 700 Btu/R2 

92.02 X lo6 ft2 

12.3 kWh/ft2 

3487 GBtu 

2900 GBtu 

587 GBtu 

411 GBtu 

4500 Btu/ft2 

2030 GBtu 

22 000 Btu/ft2 

6-26 
To evaluate the reasonableness of the numbers obtained in this way, we can do two things. 

First, we can compare the intensities (loads per square foot) with national-average values. Second, 

we can see whether the space heating intensities are higher in cold regions than in warm ones, and 

whether the reverse is true for air conditioning. The table below summarizes the space heating and 

space cooling intensities for the EFD's, arranged in approximate order from most northerly to most 

southerly. 

NORTHDIV 

WESTDIV 

CHESDIVLANTDIV 

SWESTDIV 

PACDIV 

SOUTHDIV 

NAVY AVEMGE 

NATIONAL AVG. 

(COMMZ. BLDGS.) 

Heating cooling 

Btu/P Btu/ft2 kWhlft2 

45 400 4 800 

14 600 2 000 

23 800 

9 700 

4 500 

11 700 

18 200 

28 400 

10 100 

6 000 

17 700 

20 900 

10 200 

12 400 

Non-AC 

Electric 

Btu/ft2 

12.2 

11.8 

15.2 

9.4 

12.3 

15.0 

12.9 

11.3 

Process 

Heat 

33 900 

35 100 

37 800 

20 800 

22 000 

30 100 

30 700 

13 300 

From this table it can be seen that the heating loads are more or less in line with geographical 

region, with NORTHDIV having the highest and PACDIV (which includes Hawaii and Guam) having 

the lowest. SOUTHDIV and PACDIV have the highest air-conditioning loads, while NORTHDIV 

and WESTDIV have the lowest. The Navy appears to have lower heating loads on average than the 

nation as a whole. (This may be because the Navy's facilities are preferentially located in more 

southerly locales.) The air-conditioning loads are somewhat lower than the national average also, and 

this may give cause for concern about the method used. It is plausible, though, that the average 

Navy facility is not as well air conditioned as the average commercial building. 

Non-AC electric use was quite similar in all the EFD's, and the Navy average was not very 

different fiom the national average. For process heat, however, the Navy's usage greatly exceeded 

that of the average commercial building. This should not be surprising, since the Navy must have 

many uses of energy that would be more akin to industrial than to commercial in the civilian sector. 

It also helps to explain why the Navy's energy intensity is generally higher than the national average 

for commercial buildings. 

6-27 
6.4 Loads in the Typical Multibuilding Facility 

The next step in the analysis is to relate the loads per square foot developed in the preceding 

section to the typical multibuilding facility. This was done in the same fashion that Table 5-2 was 

developed in the preceding analysis for national-average heating, cooling, and electrical loads. These 

per-square-foot loads, and also the process-heat load, were multiplied by the number of square feet 

for the whole site (399250), one large building (41520), seven large buildings (290640), and the 

smaller buildings that composed the rest of the site (108610). Average hourly loads were then 

obtained by dividing these values by 8760 hours per year. Tables 6-4-1 through 6-4-6 show the 

results for the EFD's, with CHESDIV and LANTDIV combined. (Hourly loads are expressed in 

kBtU/h and kW, while annual loads are in Mbtu/h and Mwh, so the divisor is actually 8760/1000 or 

8.76.) 

The other piece of information necessary for the analysis is the length of the heating, cooling, 

and shoulder seasons for each EFD. The shoulder season was defined as the number of hours 

between 60 F and 70 F in a major city located in the EFD's geographical area. For the EFD's along 

the Atlantic seaboard, this was equal to a nearly uniform 2.5 months. The western EFD's had longer 

shoulder seasons, ranging f?om 4 to 5 months. The remainder of the year was then divided between 

heating and cooling seasons, using weather data as a guide. The lengths of each season used in the 

analysis for each EFD are shown below the tables. 

6-28 
1 

Whole Site One Large Seven Large 

Building Buildings 

399250 ft2 41 520 ft2 290640 ft2 

Rest of Site 

108610 ft2 

Heating, 

Annual 

Heating, 

Hourly 

Cooling, 

Annual 

Cooling, 

I 2586MBtu 

9502 MBtu 988 MBtu 6916 MBtu 

1085 kBtuh 113 kBtuh 

4032 MBtu 419 MBtu 

460 kBtuh 48 kBtuh 

789 kBtuh 

2933 MBtu 

335 kBtuh 

296 kBtuh 

1099 MBtu 

125 kBtuh 

6-29 

Non-AC Elec 

Annual 

Non-AC Elec 

Hourly 

Proc. Heat 

Annual 

Proc. Heat 

Hourly 

6069 MWh 631 MWh 4417 MWh 1652 MWh 

693 kW 72 kW 504 kW 189 kW 

15092 MBtu 1569 MBtu 10983 MBtu 4109 MBtu 

1723 kBtuh 179 kBtuh 1254 kBtuh 469 kBtuh 
Heating, 

Annual 

Whole Site One Large Seven Large Rest of Site 

108610 ft2 

Building Buildings 

399250 ft2 41520 ft2 290640 ft2 

181 26 MBtu 1885 MBtu 131 95 MBtu 4931 MBtu 

Cooling, 

Annual 

Cooling, 

Hourly 

Non-AC Elec 

Annual 

Non-AC Elec 

Hourly 

Proc. Heat 

Annual 

Heating, 

Hourly 

~ 1916MBtu 

2069 kBtuh 215 kBtuh 1506 kBtuh 563 kBtuh 

219 kBtuh ' 23 kBtuh 

507 MWh 

58 kW 

1407 MBtu 

4871 MWh 

~~ 

159 kBtuh 60 kBtuh 

3546 MWh 1325 MWh 

405 kW 151 kW 

9853 MBtu 3682 MBtu 

556 kW 

Proc. Heat 

Hourly 

13535 MBtu 

1545 kBtuh I61 kBtuh 1125 kBtuh 420 kBtuh 

~ 199 MBtu I 1393 MBtu I 523 MBtu 

6-30 
I 

I 

. 

Table 6-4-3: Annual and Average Hourly Loads for Space Heating, Space Cooling, Electric Power Not Used for Space Cooling, and 

Whole Site 

399250 ft2 

Heating, 4671 MBtu 

Annual 

Heating, 533 kBtuh 

Hourly 

~ Cooling, 8344 MBtu 

~ Annual 

Cooling, 953 kBtuh 

1 Hourly 

~ Non-AC Elec 5989 MWh 

One Large Seven Large Rest of Site 

Building . Buildings 

10861 0 ft2 

41 520 ft2 290640 ft2 

486 MBtu 3400 MBtu 1271 MBtu 

55 kBtuh 388 kBtuh 145 kBtuh 

868 MBtu 6074 MBtu 2270 MBtu 

99 kBtuh 693 kBtuh 260 kBtuh 

623 MWh 4360 MWh 1629 MWh 

Non-AC Elec 

Hourly 

684 kW 71 kW 498 kW 186 kW 

Proc. Heat 

Annual 

Proc. Heat 11 Hourly I I I I 

Note: MBtu = lo6 Btu; Btuh = Btu/h 

Shoulder Season = 2.5 months. Heating Season = 3.5 months. Cooling Season = 6 months. 

12017 MBtu 1250 MBtu 8748 MBtu 3269 MBtu 

1372 kBtuh 143 kBtuh 999 kBtuh 373 kBtuh 

6-3 1 
I 

Heating, 

Annual 

Heating, 

Hourly 

I 

Whole Site 

399250 ft2 

5829 MBtu 

665 kBtuh 

Table 6-4-4: Annual and Average Hourly Loads for Space Heating, Space Cooling, Electric Power Not Used for Space Cooling, and 

Cooling, 

Annual 

Cooling, 

Hourly 

Non-AC Elec 

Annual 

798 MBtu 

91 kBtuh 

4711 MWh 

Non-AC Elec 

Hourly 

Proc. Heat 

Annual 

Proc. Heat 11 Hourly 

538 kW 

1401 4 MBtu 

1600 kBtuh 

Facility in WESTDIV. 

I 

1457 MBtu 

166 kBtuh 

One Large 

Building 

10201 MBtu 

1164 kBtuh 

Seven Large 

Buildings 

606 MBtu 4213 MBtu 

69 kBtuh I 484 kBtuh 

83 MBtu I '581 MBtu 

9 kBtuh 1 66 kBtuh 

490MWh I 3430MWh 

56 kW I 392 kW 

Rest of Site 

10861 0 ft2 

1586 MBtu 

181 kBtuh 

217 MBtu 

25 kBtuh 

1281 MWh 

146 kW 

3813 MBtu 

435 kBtuh 

Shoulder Season = 4 months. Heating Season = 6 months. Cooling Season = 2 months. 

6-32 
Table 6-4-5: Annual and Average Hourly Loads for Space Heating, Space C 

Process Heat for the Typical Multibuilding Facility in SWESTDIV. 

II I I I 

Heating, 

Annual 

Heating, 

Whole Site 

399250 ft2 41520 ft2 290640 ft2 

3873 MBtu 403 MBtu 281 9 MBtu 

442 kBtuh 46 kBtuh 322 kBtuh 

One Large 

Building 

Cooling, 

Annual 

Cooling, 

Hourly 

Non-AC Elec 

Annual 

Non-AC Elec 

Hourly 

Proc. Heat 

Annual 

Seven Large 

Buildings 

2396 MBtu 249 MBtu 1744 MBtu 

274 kBtuh 28 kBtuh 199 kBtuh 

3753 MWh 390 MWh 2732 MWh 

428 kW 45 kW 312 kW 

8304 MBtu 864 MBtu 6045 MBtu 

I 948 kBtuh I 99 kBtuh 1 690 kBtuh 11 Hourly I I I 

Note: MBtu = 10' Btu; Btuh = Btu/h 

Shoulder Season = 5 months. Heating Season = 5 months. Cooling Season = 

ooling, Electric Power Not Used for Space Cooling, and 

Rest of Site 

10861 0 ft2 

1054 MBtu 

120 kBtuh 

652 MBtu 

75 kBtuh 

1021 MWh 

116 kW 

2259 MBtu 

258 kBtuh 

2 months. 

6-33 
Table 6-4-6: Annual and Average Hourly Loads for Space Heating, Space Cooling, Electric Power Not Used for Space Cooling, and 

Process Heat for the TvDical Multibuilding Facilitv in PACDIV. 

Seven Large 

Buildings 

290640 ft2 

1308 MBtu 

Whole Site One Large 

Building 

Rest of Site 

108610 ft2 

Heating, 489 MBtu 

Annual 

Heating, 

Hourly 

Cooling, 

Annual 

Cooling, 

Hourly 

Non-AC Elec 

Annual 

807 kBtuh 

4911 MWh 

Non-AC Elec 561 kW 

Hourlv 

84 kBtuh 

511 MWh 

58 kW 

+ 1797 MBtu 187 MBtu 205 kBtuh 21 kBtuh 

Proc. Heat 

Annual 

Proc. Heat 

7067 MBtu I 735 MBtu 

8784 MBtu 913 MBtu 

1003 kBtuh 104 kBtuh 11 Hourly I I 

Note: MBtu = lo6 Btu; Btuh = Btu/h 

149 kBtuh I 56 kBtuh 

5144 MBtu I 1923 MBtu 

587 kBtuh I 220 kBtuh 

3575 MWh I 1336 MWh 

408 kW I 153kW 

6394 MBtu 1 2390 MBtu 

I 730 kBtuh 273 kBtuh 

Shoulder Season = 5 months. Heating Season = 1 month. Cooling Season = 6 months. 

6-34 
6.5 Spreadsheet Input Data 

The next step was to prepare inputs to the spreadsheet for each EFD. It was decided to 

analyze cases with no chillers and with one chiller per cogenerator. In addition, because of the large 

amount of "process heat" used by the Navy, we wanted to determine the impact of meeting part of 

this load through cogeneration. The djfIiculty here is that most process heat in industrial applications 

is needed at temperatures far too high for cogenerators to supply. We have no direct information on 

the Navy's situation in this regard. Nevertheless, it seems reasonable to assume that at least a small 

fiaction of this heat could be met by cogeneration. As a benchmark, therefore, we analyzed a 

hypothetical situation where 20% of the process heat in the cogenerated buildings could be met'by 

cogenerated heat. (This would correspond to about 14% of all process heat, since we are not 

assuming that heat produced in one building can be transported to another, and therefore none of the 

process heat in non-cogenerated buildings is accessible to being served by Cogeneration.) The four 

situations analyzed are therefore: 

No chillers, no process heat via cogeneration. 

One chiller per cogenerator, no process heat via cogeneration. 

No chillers, 20% of process heat in cogenerated buildings met by cogeneration. 

One chiller per cogenerator, 20% of process heat in cogenerated buildings met by 

cogeneration. 

In addition, a case with no cogeneration was run on the spreadsheet, as a test to make sure that the 

numbers agree with the original input data for heat and electricity demands. 

The inputs were calculated as follows: 

Electricity. The whole-base non-AC electric load was taken fiom the appropriate table from 3.1 

through 3.6, and then the hourly loads for the four steps were computed as 0.5, 1.0, 1.5, and 2.0 

times this average load. 

Process Heat. For analyses where no process heat is met by cogeneration, the whole-base hourly 

process heat load was taken fiom the appropriate table fiom 3.1 through 3.6 and added to the "ROB 

heat load" for all heating, cooling, and shoulder cases. Where 20% of the cogenerated-building 

process heat was to be met by cogenerated heat, 20% of the "7 large buildings'' process heat load was 

added to the "CgB heat load" for all heating, cooling, and shoulder cases, and a like amount was 

subtracted from the "ROB heat load" amount used in the case immediately above. For example, in 

CHESDTVLAJYTDIV, where no process heat is met by cogeneration, 1723 kBtu/h is added to the 

"ROB heat load." Where 20% of cogenerated-building process heat is met by cogeneration, 20% of 

1254, or 25 1 kBtuh is added to the CgB heat load, while 1723-25 1 or 1472 kBtu/h is added to the 

ROB heat load, over and above whatever is there because space heating and cooling. 

6-3 5 
Space Heating;. The fiaction of the year in the shoulder season is the number of months divided by 

12. For the three space heating levels, the fkctions of the year are 0.4,0.4, and 0.2 times the number 

of months divided by 12. A "low step multiplier" M is calculated in the same way as described in the 

section on heating and cooling load curves in the preceding analysis. This number, when multiplied 

by the average hourly heating load, gives the hourly heating load during the lowest heating-load step. 

The second and third steps are then 2 and 3 times this. ENh is the number of months in the heating 

season, and is the average hourly heating load, then in order to have the annual heating load in 

the analysis equal the actual annual heating load, we must have 

which yields 

The cogenerated-building (CgB) and rest-of-buildings (ROB) heat loads for the low, medium, and 

high heating steps are then calculated by multiplying the average hourly loads for the 7 large buildings 

and rest of site fiom the appropriate table fiom 3.1 - 3.6 by M, ZM, and 3M, respectively, and then . adding in any process heat load as described in the preceding section. 

Space Coolinq. The "low-step multiplier" M is calculated for cooling the same as for heating, but 

using the number of months in the cooling season. Ifthere are no chillers, the ROB AC electrical load 

is calculated by multiplying M by the all-base average cooling load fiom one of the Tables 3.1 - 3.6 

and dividing by the average SEER (10.36 Btu/Wh). Ifthere are chillers, then a heat input for the 

cooling steps is calculated as the lesser of the 7 buildings cooling load and the total chiller capacity. 

Any excess cooling load is then met electrically as discussed immediately above, with an SEER of 

10.36. 

Calculations of Inputs. Because the process is somewhat involved, we have summarized the 

calculations of the actual input data used in the spreadsheets in detail. These calculations, and the 

spreadsheets themselves, are presented in Appendix B of this report. 

6.6 Results of Simulations 

The salient energy quantities for each situation analyzed are given in Tables 6-5-1 through 6- 

5-6. The first thing that leaps fiom these tables is that much more of the cogenerated heat is used in 

CHESDIVLANTDIV, NORTHDIV, and SOUTHDIV than in the more westerly divisions. In 

NORTHDIV, about halfthe cogenerated heat is used even without chillers or a process-heat hookup. 

In CHESDIV/LANTDN and SOUTHDIV, one has to use chillers and serve process heat in order 

to achieve similar levels of utilization. 

6-36 
Of course, the primary criterion is not heat utilization but cost savings. The economic analysis 

in Chapter 7 details the consequences of the various choices for each of the EFD’s studied. 

6.7 Demand Calculations for Navy EFD’s 

In addition to deriving energy utilization through the simulation spreadsheets, it is also 

necessary to derive peak thermal and electrical demands to determine the sizes and types of 

equipment that msut be installed. This was carried out for each EFD, using data f?om Tables 6-5-1 

through 6-5-5, following the methods described in Section 4.15 closely. The lengths of the heating 

and cooling seasons, given in Table 6-4-1 through 6-4-6, vary significantly between EFD’s, and had 

a strong influence on the peak demands as they were entered into the demand spreadsheets. 

Because they are somewhat tedious, the demand spreadsheets are included in Appendix By 

after the energy utilization spreadsheets, rather than reproduced here. The resulting demands are 

used in Chapter 7 as part of the economic evaluaiton of EFD’s. 

6-37 
Table 6-5-1 : Annual Energy Quantities for the Typical Multibuilding Facility in CHESDIVLANTDIV. 

Cogen. 

Heat 

Used 

(MBtu) 

6912 

9 899 

9 102 

12089 

Heat from 

Boilers 

(MBtu) 

17687 

17 687 

15497 

15497 

Chil-lers 

Per 

Cogen. 

Process Elect. Elect. Elect. Elect. Heat Cogen. 

Heat by Demnd Cogen. Bought Sold Demnd Heat 

Cogen.. (MWh) (MWh) (MWh) (MWh) (MBtu) (MBtu) 

0 0 6459 5 585 969 94 24599 26224 

1 0 6271 5472 893 94 27 586 25697 . 

0 

1 

6-3 8 

20% 6459 5641 969 150 24599 26487, 

20% 6271 5528 893 150 27 586 25 960 

Chil-lers Process Elect. Elect. Elect. Elect. Heat Cogen. 

Per Heat by Demnd Cogen. Bought Sold Demnd Heat 

Cogen. Cogen.. (MWh) (MWh) (MWh) (MWh) (MBtu) (MBtu) 

0 0 5 056 5410 292 646 31 649 25 405 

1 0 4937 5327 256 646 33528 25015 

0 20% 5056 5 517 292 753 31 649 25 907 

I 20% 4937 5438 256 757 33538 25536 

Cogen. Heat from 

Heat Boilers 

Used (MBtu) 

(MBtu) 

12 821 18 828 

14710 18828 

14 554 17 095 

16443 17095 
I I I I I I I 

?ercent of Drocess heat in cogenerated buildings only. 

I I 

Elect. Heat Cogen. 

Sold Demnd Heat 

(MWh) (MBtu) (MBtu) 

26 16687 26899 

26 22159 25992 

124 25178 25913 

41 16687 26969 

41 22159 26062 

183 25178 26193 

If no cogenerators, electric dekand is 6797 MWh (ai bought) and heat demand is 16687 MJ3tu (all from boilers). 

Cogen. Heat from 

Heat Boilers 

Used (MBtu) 

3399 13289 

8870 13289 

11 890 13289 

5 151 11 537 

10622 11537 

13642 11537 

Chil-lers Process Elect. Elect. Elect. Elect. Heat Cogen. Cogen. 

Per Heat by Demnd Cogen. Bought Sold Demnd Heat Heat 

Cogen. Cogen.. (MWh) (MWh) (MWh) (MWh) (MBtu) (MBtu) Used 

0 0 4790 4595 221 26 19840 21 578 4239 

1 0 4734 4551 209 26 20728 21 371 5 128 

0 20% 4790 4619 221 50 19840 21 691 6280 

1 20% 4734 4575 209 50 20728 21 484 7169 

6-3 9 

Heat from 

Boilers 

(M Btu) 

15601 

15601 

13560 

13560 
Chil-lers Process Elect. 

Per Heat by Demnd 

Cogen. Cogen.' (MWh) 

0 0 3981 

Elect. Elect. Elect. Heat Cog en. 

Cogen. Bought Sold Demnd Heat 

(MWh) (MWh) (MWh) (MBtu) (MBtu) 

3957 41 18 12175 18581 ~ 

1 0 3872 3863 26 18 13905 18140 

0 20% 3 981 3 966 41 26 12 175 18621 

1 20% 3872 3874 26 28 13905 18190 

I1 

Chit-lers Process Elect. 

Per Heat by Demnd 

Cogen. Cogen.' (MWh) 

0 0 5 597 

1 0 5273 

2 0 5 123 

Elect. Elect. Elect. Heat 

Cogen. Bought Sold Demnd 

(MWh) (MWh) (MWh) (MBtu) 

5 192 456 41 10 582 

4955 358 41 15 735 

4981 31 3 172 18118 

0 

1 

20% 5 597 5 189 456 48 10 582 

20% 5273 4962 358 48 15 735 

2 20% 5 123 5 021 31 3 212 18118 

Cogen. 

Heat 

Used 

2 819 

Heat from 

Boilers 

(MBtu) 

9 356 

9 356 

8 147 

8 147 

). 

4 550 

4 028 

5 759 

From boiler! 

V. 

Cogen. 

Heat 

(MBtu) 

Cogen. 

Heat 

Used 

Heat from 

Boilers 

(MBtu) 

24 334 9 277 

23 268 

23 391 

1305 

6 458 9 277 

8 841 9 277 

24 366 2 584 7 998 

23 300 7 737 7 998 

23 577 10 120 7 998 

1 MBtu (all kom boiler! 

6-40 

, 
7. Economics of Modular Cogeneration in the Navy 

7.1 Introduction 1 

In Chapter 6 we analyzed available data on Navy energy use in the seven Engineering Field 

Divisions (EFD’s) and used the results to simulate the operation of modular cogeneration systems 

installed in our “model faciliiy” with energy demands typical of each EFD. In this chapter we extend 

the economic analysis of Chapter 5 to these regional studies to project expected economic 

performance in the different EFD’s. We then compare the results of these different studies, and find 

that the economic perfbrmance of modular cogeneration is essentially driven by two factors: the ratio 

of electric prices to gas prices and the availability of a load to make use of the reject heat. 

We did not carry out an economic assessment of the model facility using the characteristics 

derived in Chapter 6 for PACDIV because of the lack of availability of gas and the extremely diverse 

entities that were averaged together to derive the statistics. 

7.2 CHESDNLANDIV 

As discussed in Chapter 6, CHESDN and LANTDIV are combined into one equivalent EFD 

with energy-weighted average characteristics. The economic parameters used are shown in the lower 

left box of Figure 7-1. We were unable to obtain actual rates for electricity purchased by the Navy 

since they are negotiated by special contract and Navy officials were hesitant to release the terms of 

the contract without approval. (This also meant that published utility rates would be inaccurate.) We 

do, however, have the average price paid for electricity, $0.0568/kWh, an energy-weighted average 

from Tables 6-2-1 and 6-2-2. The service, energy and demand charges were initially taken to be 

those of GulfPower (shown in Figure 7-7, below) but the energy and demand charges were then 

scaled up so that overall average cost of electricity in the case of boilers and utility electricity came 

out equal to that average price for CHESDIV and LANTDIV. The result is the rate structure shown. 

As before and throughout this section, we assume that power sold back to the utility commands a 

price equal to one-halfthe average cost of power €tom the utility. The cost of gas is also an energyweighted average of theCHESDIV and LANTDIV gas costs shown in Tables 6-2-1 and 6-2-2. 

The thermal and electric demands discussed in Section 6.7 and presented in Appendix B are 

different from the national average and require equipment in somewhat different sizes. The 

equipment is listed in the upper table in Figure 7-1; the costs have been derived fiom different entries 

in the same sources as Table 5-2. Here and in succeeding Em’s the equipment changes are relatively 

minor. 

We do analyze the possibility of meeting some process heat load through cogeneration in 

the EFD studies, but have included no capital costs for any process heat boilers, since we have 

no knowledge of what they are, and in any event, they will presumably not change when 

cogeneration is introduced. Even in the case where 20% of the process heat in the buildings 

equipped with cogenerators is met by those cogenerators, we take no credit for the removal of 

7- 1 
boilers due to the uncertainty in what that credit should be. This results is a very slightly 

conservative bias in the value derived for modular cogeneration, which we will ignore in our 

assessments. 

In the lower right table in Figure 7-1 the economics for the baseline case, boilers and utility 

electricity, are displayed. The capital cost are quite similar to the national average figures of Chapter 

5, while the annual operating expenses are somewhat higher, due in part to the presence of the 

process heat load. These capital and operating costs will serve as the baseline against which various 

modular cogeneration options will be evaluated. 

Figure 7-2 presents two economic summary tables, one for modular cogeneration with no 

absorption chillers and one for the case where each cogenerator has a single absorption chiller 

attached to it. The economics are not promising in either case. For the “no absorption chiller” case, 

an investment of $844k has shifted the bulk of annual outlays fiom electricity to he1 (gas), but has 

still resulted in an increase in annual expenses. Adding one absorption chiller makes the situation 

slightly less bad, but does not turn it around. The incremental capital outlay of $140k for the 

absorption units has lowered annual outlays by $6k, corresponding to a 23 year payback, so even 

if the cogeneration were being installed for some other reason, the absorption units would be a 

marginal (although not money-losing) investment. We will compare these results with those fiom 

other EFD’s at the end of this chapter to attempt to isolate the factors leading to this lack of 

economic practicality. 

Figure 7-3 presents the results for the case where 20% of the process heat consumed in the 

buildings with cogenerators can be provided by cogenerated thermal energy, as explained in Chapter 

6. The situation is similar to the case of no process heat, although not quite as negative. 

7.3 NORTHDIV 

Figure 7-4 presents the background economic tables for NORTHDIV. Here we use actual 

electric rates for a large commercial customer of the Philadelphia Electric Company’. The gas price 

is the NORTHDIV average fiom Table 6-2-3. Again the equipment sizes have been adjusted slightly 

to accommodate the demands calculated for NORTHDN and presented in Appendix B as discussed 

in Section 6.7. The resulting economic analysis for boilers and utility electricity is presented in the 

lower right table of Figure 7-4. Although the average cost of electricity for this scenario came out 

greater than the average value for NORTHDN reported in Table 6-2-3, it was decided to use the 

actual PECO rates rather than to adjust them to give the reported average because many Navy 

facilities must be paying them and it was thought advisable to use as much “real-world” data as 

possible. 

Figure 7-4 reveals that in this case modular cogeneration is a very promising technology. For 

the case of no absorption chillers, very large savings pay back the incremental capital in less than three 

years, offering a very attractive return on investment. However, comparison with the one absorption 

chiller per cogenerator case indicates that absorption chillers are not a very good investment here, 

7-2 
either, at current prices: the $142k initial capital investment results in only a $5k decrement in annual 

expenses and a thirty year payback. Of course the shorter cooling season contributes to the poor 

economy of these capital-intensive items. 

Figure 7-6 presents the economics for the case where some process heat is served by 

cogeneration. As might be expected, all the economics improve somewhat, although not strikingly, 

since the thermal loads were already fairly large. In either case, modular cogeneration is clearly 

worth in-depth examination in NORTHDIV. 

7.4 SOUTHDIV 

The background tables for SOUTHDIV are presented in Figure 7-7. Again, actual electric 

rates for GulfPower are used2; they assure us that several Naval bases use these "large commercial" 

rate structures. As before, the equipment costs are broken out above and the economics of boilers 

and utility electricity summarized in the lower right hand table. The low cost of electric power is 

balanced by the low cost of gas fiom Table 6-2-4, and the result is an annual outlay (for the baseline 

system) which is 36% lower than in NORTHDIV. 

Figure 7-8 shows that when fbel and electricity is inexpensive, capital-intensive systems like 

cogeneration are less attractive. Although the systems are not a loss, they take so long to pay for 

themselves as to be fairly uninteresting. However, with the long southern cooling system, ifthe 

cogeneration system goes in, the absorption chiller is a reasonable option: its incremental cost of 

$145k results in an $Ilk decrease in operating expenses, corresponding to a 13 year simple payback 

or a 4.8% return on investment over twenty years. 

Figure 7-9 shows that, as for the previously-examined systems, the addition of the process 

heat loads makes modular cogeneration somewhat more attractive, but not enormously so. Finally, 

Figure 7-10 shows what happens ifwe add a second absorption chiller to each cogeneration unit. 

For both the case with no process heat and that with process heat load being served by cogeneration, 

the addition of a second absorption chiller, which costs $152k, actually increases the annual outlay 

by $1-2k! The electricity savings are so small that they are outweighed by maintenance on the 

chillers. 

7.5 WESTDIV 

The treatment of WESTDIV begins in Figure 7-1 1. We use electric rates fiom Pacific Gas 

and Electric3. Some Navy facilities receive Western Area Power Authority (WAPA) power at 

considerably lower rates, but many facilities are on the PG&E large commercial schedule, and our 

results should be taken as applying to them. The very low gas price is the WESTDIV average fiom 

Table 6-2-5. Because both heating and cooling loads are low, the equipment requirements are also, 

and the capital outlay for boilers and compression chillers is much smaller than in the cases already 

discussed. 

7-3 
Figure 7-12 shows the economics of modular cogeneration for WESTDIV with and without 

absorption chillers, and here, as in NORTHDIV, the systems are clearly very attractive. Since loads 

are not large, the high electric rates and low gas price must be the primary influence. Interestingly, 

the absorption chillers are not completely unreasonable: a $1 12k capital investment results in $7k per 

year savings, a 17 year payback and a 1.7% return on investment over twenty years. The addition 

of process heat load in Figure 7-13 produces only marginal improvement in the overall economics. 

- 

7.6 SWESTDIV 

Finally, the economic background materials for SWESTDIV are presented in Figure 7-14. 

Relatively expensive electricity is purchased from San Diego Gas and Electric4, and gas prices, taken 

from Table 6-2-6, are considerably higher than for WESTDIV. The boilers are smaller than in 

WESTDIV, but the chillers are significantly larger, leading to a capital outlay more comparable to 

the previously studied EFD’s than to WESTDIV. 

As for WESTDIV, modular cogeneration appears to be an attractive investment in 

SWESTDIV. With or without absorption chillers or process heat, the simple paybacks are eight to 

ten years and the returns on investment attractive. Absorption chillers are not so attractive, saving 

only about $3k per year for a --year payback. 

7.7 Conclusions 

The following table summarizes our results in a way that may prove helpfbl. Of the variables 

contributing to the value of cogeneration technologies, the prices of gas and electricity and the ability. 

to actually use the cogenerated thermal energy seemed most likely to be relevant. Accordingly, for 

each EFD we calculated the “electricity-to-gas price ratio” by dividing the overall average cost of 

electricity (calculated in the “Economics of Boilers and Utility Electricity” tables) by the cost of gas 

(from the “Economic Parameters” tables) and multiplying the resulting ratio by 293 kWh/MBtu to 

remove the energy units. Then for each EFD we chose the scenario which was most attractive (had 

the shortest simple payback period) and calculated the ratio I&JE3,,,for that case from the 

simulation spreadsheet data in Appendix B. (The numbers are in the summary at the bottom of each 

spreadsheet.) We also recorded the payback time for each case (from the tables in this chapter) and 

calculated its inverse. The results are presented in Table 7-1: 

7-4 
Quantity: 

Division 

Electricity-toGas Price Ratio 

Hused/ 

Hcogen 

1 I 

CHESDIV/ LANTDIV I 3.6 47% 

NORTHDIV I 8.0 156% 

SOUTHDIV 41 % 

WESTDIV 29% 

S W ESTD I V 22% 

Payback 

~ Time 

1 (years) 

176 

2.8 

42 

3.3 

8.3 

Inverse 

Payback 

(1 /years) 

0.01 

0.36 

0.02 

0.30 

0.1 2 

Table 7-1 : Electricity to fuel price ratios, thermal energy use and payback times for 

modular cogeneration. 

The electricity-to-gas price ratio and the inverse payback time are highly correlated, with 

~0.86 and ?=0.75. This means that three-fourths of the variation in results among regions is 

associated with differences in this ratio. 

The next most important variable may be the fiaction of cogenerated heat that can be utilized. 

Of the two divisions that gave attractive results, NORTHDIV achieved a 2.8-year payback with a &el 

price ratio of about 8, while WESTDN had a slightly longer payback (3.3 years) despite a &el price 

ratio that was 40% higher. The difference is probably due to the fact that in NORTHDN, with its 

high heating loads, 56% of the cogenerated heat was utilized, while in WESTDN only 29% of the 

heat was used. 

In short, it appears that even at current prices, there is a significant value to modular 

cogeneration in NOR"DN, WESTDN and SWESTDIV. As previously discussed, these areas are 

likely to prove attractive for central cogeneration with district heating and cooliig, also, and detailed 

comparative studies should be carried out at particular sites before conclusions are drawn. 

7-5 
---- Cooling Tower -- 

Capacity Cost Total 

(tons) ($1 000's) Capital 

42 5.0 110.0 

270 15.0 485.0 

10.3 

20.8 

104.2 

19 2.0 26.7 

O&M 

($k/year) 

14.0 

90.4 

0.5 

0.6 

2.0 

0.5 

equipmen lnstallatio 

($1 000's) ($1 000's) 

Zogenerators: 

120 kW 105.0 

775 kW 470.0 

3oilers 

150 kBtuh 5.3 3.1 

68.01 353.81 2.0 

I I 

Overhead 

& Profit 

'1.9 

2.0 I 

500 kBtuh 11.1 

5000 kBtuh (1) 60.9 

4bsorption Chillers 

10 ton AC: I 15.8 

20.5 16.21 

6.3 3.5 

28.4 14.9 

4.7 4.1 

0.8 

0.9 

325 ton AC(1) I 183.2 

Zompression A[ 

10 ton 10.1 

20 ton 14.7 

55.0 47.6 535 

2.1 2.0 I1 

2.9 2.9 Inc. 

30 ton 

DHC System: 

lectricity Costs: CHESDIWLAN TDlV Average 

Energy: $0.0300 /kWh 

Demand: 8.75 /kW-mnth 

Ratchet: 1 months 

Service: $227 /month 

Purchases $0.0284 /kWh 

Gas: $0.465 /therm 

= $4.65 /MBtu 

Service: $50 /month 

Inflation: Use constant 1995 dollars 

uel Cost: 

conomics: 

19.8 3.4 3.9 Inc. 27.1 1 .o 

Study duration: 20 years 

Economic Parameters 

MaxCapCost: 

MinCapCost: 

Capital Variable Fuel @ effic. 

($k) ($k/year) ($k/year) 

Boilers: 

151 5.0 15.0 

780.0 8.0 

9 150 kBtuh 80% 

7 500 kBtuh 80% 

9 8ton 146 3.03 ~.~ ~ 

7 26ton I90 7.0 3.03 

Electricity 

Fixed Demand Energy Total Average 

(k$/year) (k$/year) (k$/year) (k$/year) ($/kWh) 

2.7 170 194 367 0.0568 

Capital outlay: $574 k 

Annual Outlay: $532 k 

Economics for Boilers and Utiltiy Electricity 

Figure 7-1 : Equipment, Economic Assumptions and Baseline System Costs for CHESDIVILANTDIV 
Cogenerators: 

Boilers: 

9 120 kW 

9 150 kBtuh 

& Process 

Absorption Chillers: 

Compression Chillers: 

0 10 tons 

9 10 ton 

7 30 ton I 1901 71 I 3.03 

Electricity - purchasesCapital Variable Fuel @ effic. 

($k) ($klyear) ($klyear) 

990 112 240 30% 

92 5 103 80% 

0 0 0.65 

146 7 3.03 

Fixed ]Demand (Energy ITotal IAverage 

Capital 

($k) 

Cogenerators: 

Capital outlay: 

(k$/year) I (k$/year) I (k$/year) I (k$/year) I ($/kWh) 

2.7 I 47.7 I 24.0 I 74.4) 0.077 

Variable Fuel @ effic. 

($k/year) ($klyear) 

$1,558 k 

- 

9 120 kW 

9 150 kBtuh 

Boilers: 

& Process 

Absorption Chillers: 

7 10 tons 

Compression Chillers 

9 10 ton 

7 30 ton 

No Absorption Chillers 

990 

92 

187 

146 

144 

-Sales: I 

Totals: 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

2.7 I 45.3 

-Sales: I 

Totals: 

I (2.7) I (Income) 

$1,418 k 

545 k 

$844 k 

Electricity: 

(13) k 

NA years 

NA 

112 

5 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

$984 k 

(6) k 

NA years 

NA 

4 

7 

6 

Energy 

(k$/ y ea r) 

21.7 

38% 

80% 

Annual Outlay: I 539 k 

Comparison to Boilers & Utility Electricity: 

One Absorption Chiller per Cogenerator 

Figure 7-2: Economics of Modular Cogeneration, with no process heat, for CHESDWLANTDIV. 
112 

5 

Cog enerators: 

Boilers: 

9 120 kW 

9 150 kBtuh 

& Process 

Absorption Chillers: 

7 10 tons 

Compression Chillers: 

9 'IO ton 

7 30 ton 

242 

90 

Capital Variable 

($k) ($k/year) 

990 112 

92 5 

187 4 

146 7 

144 61 I 3.03 

Capital Variable Fuel 

($k) ($k/year) ($k/year) 

Cogenerators: 

Boilers: 

& Process 

Absorption Chillers: 

Compression Chillers: 

9 120 kW 990 

9 150 kBtuh 92 

0 IO tons 0 

9 10 ton 'l46 

7 30 ton 190 7: 

Energy I 

@ effic. 

38% 

80% 

0.65 

3.03 

3.03 7 

Total 

(k$/yea r) 

- Sales: 

2.7 

(k$/yea r) (k$/iear) (k$/yea r) ($/kWh) 

47.7 24.0 74.4 0.077 

(4.3) (Income) 

Capital outlay: I $1,418 k 

Totals: 

(k$/year) 

- Sales: 

2.7 

Annual Outlay: I 533 k 

Comparison to Boilers & Utility Electricity: 

(k$/year) (k$/year) (k$/year) ($/kWh) 

(4.3) (Income) 

45.3 21.7 69.8 0.072 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

No Absorption Chillers 

$1,558 k 

527 k 

$984 k 

6k 

175.8 years 

Electricity: 

NA 

Incremental Capital Outlay: - 

Annual Savings: 

Simple Payback: 

Return on Investment: 

Fuel 

($k/year) 

238 

90 

$844 k 

(1) k 

NA years 

NA 

38% 

80% 

0.65 

3.03 

One Absorption Chiller per Cogenerator 

Figure 7-3: Economics of Modular Cogeneration, with 20% process heat, for CHESDIV/LANTDIV. 
~~ 

kquipmen 

($1 000's) 

Cogenerators: 

120 kW: 105.0 

775 kW: 470.0 

3oilers 

240 kBtuh 5.9 

820 kBtuh 15.4 

5000 kBtuh (I) 60.9 

4bsorption Chillers 

IO ton AC: ( )I 325 ton AC I 

Zompression AC 

10 ton 

20 ton 

DHC System: 

MaxCapCost: 

g Tower -- 

cost 

($1 000's) 

5.0 

15.0 

2.0 

68.0 

2.0 

I[ yinc;pC;t: I 

1 Ca acit incrementedi 

Total 

Capital 

110.0 

485.0 

11.4 

27.3 

104.2 

26.7 

353.8 

10.9 

14.2 

20.5 

151 5.0 

780.0 

I 

3.4 I 2.1 

7.3 4.6 

28.4 14.9 

2.0 

2.9 2.9 

cover 20% losses it 

Equipment Costs 

Electricity Costs: NORTHDIV - PtCO 

Demand: 12.76 /kW-mnth 

Ratchet: 1 months 

Service: $287 /month 

Purchases $0.0543 /kWh 

Gas: $0.397 /therm 

= $3.97 /MBtu 

Service: $50 /month 

Inflation: Use constant 1995 dollars 

Study duration: 20 years 

tconomic Parameters 

Energy: $0.0690 /kWh 

Fuel Cost: 

Economics: 

==-Ea 

Capacity 

(tons) 

42 

270 

I& 

535 

11 

I nc, 

I nc, 

DHC sysi Nm . 

Boilers: 

9 240 kBtut 

7 820 kBtut 

Pro cess 

Compression Chillr 

Electricity 

9 6ton 

7 20ton 

Fixed 

(k$/year) 

3.4 

-EqiEr0 

103 

191 

98 

Demand 

(k$/year) 

144 

197 

VariatSle 

($k/yearl 

4.5 

4.2 

7.2 

7.0 

Energy 

(k$/year) 

349 

Fuel 

($k/year) 

24.5 

65.5 

67.1 

Total 

(k$/year) 

549 

@ effic.: 

80% 

80% 

80% 

3.03 

3.03 

Average 

($/kWh) 

0.1 086 

Totals: 

Capital outlay: $536 k 

Annual Outlay: $729 k 

tconomics for Boilers and Utility Electricity 

Figure 7-4: Equipment, Economic Assumptions and Baseline System Costs for NORTHDIV 
-Fizl- 

($k/year) 

199 

93 

Cogenerators: 

Bo i I e rs: 

9 120 kW 

16 240 kBtuh 

& Process 

Absorption Chillers: 

0 10 tons 

Compression Chillers: 

9 6 ton 

7 20 ton 

Electricity - purchases 

Fixed 

.- (k$/year) 

3.4 

- Sales: 

Total 

Capital Variable 

($k) ($k/year) 

990 112 

183 8 

0 0 

98 7 

144 7 

Demand Energy 

(k$/year) (k$/year) (k$/year) ($/kWh) 

23.4 8.5 35.3 0.121 

(35.1) (Income) 

@ effic. 

Totals: 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility Electricity: 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

38% 

80% 

$1,415 k 

427 k 

$879 k 

302 k 

2.9 years 

34.3% 

Cog enerators: 

Boilers: 

9 120 kW 

16 240 kBtuh 

& Process 

Absorption Chillers: 

Compression Chillers: 

7 10 tons 

9 6 ton 

7 10 ton 

0.65 

Capital Variable Fuel @ effic. 

($k) ($k/year) ($k/year) 

990 112 196 38% 

183 8 93 80% 

. 187 4 0.65 

98 7 3.03 

99 . 6 3.03 

3.03 

3.03 

. (k$/year) 

- Sales: 

3.4 

Average 

(k$/year) (k$/year) (k$/year) ($/kWh) 

21.2 6.1 30.7 0.105 

(35.1) (Income) 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

$1,021 k 

307 k 

3.3 years 

29.9% 

Capital outlay: I $1,557 k 

Annual Outlay: I 422 k 

Comparison to Boilers & Utility Electricity: 

No Absorption Chillers One Absorption Chiller per Cogenerator 

Figure 7-5: Economics of Modular Cogeneration, with no process heat, for NORTHDIV. 
Capital 

($k) 

Cogenerators: 

Boilers: 

9 120 kW 990 

16 240 kBtuh 183 

& Process 

Absorption Chillers: 

Compression Chillers 

0 10 tons 0 

9 6 ton 98 

7 20 ton 144 

Fixed Demand 

(k$/yea r) (k$/yea r) 

3.4 23.4 

- Sales: 

Electricity - purchases 

Totals: 

Capital outlay: 

Annual Outlay: I 416 k 

Comoarison to Boilers & Utility Electricity: 

Variable 

($klyear) 

112 

8 

0 

7 

71 I 3.03 

Energy Total Average 

(k$/yea r) (k$/yea r) ($/kW h) 

8.5 35.3 0.121 

(40.9) (Income) 

$1,415 k 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

No Absorption Chillers 

$1,021 k 

318 k 

3.2 years 

31 .O% 

Fuel 

($k/year) 

203 

85 

Incremental Capital Outlay: - Annual Savings: 

Simple Payback: 

Return on Investment: 

38% 

80% 

0.65 

3.03 

$879 k 

313 k 

2.8 years 

35.5% 

Cogenerators: 

Boilers: 

9 120 kW 

16 240 kBtuh 

& Process 

Absorption Chillers: 

7 10 tons 

Compression Chillers 

9 6 ton 

7 10 ton 

Fixed 

Electricity - purchase: 

Capit 

183 * 

Demand I Enerw 

11 outlay: I $1.557 

@e IC. 

$W ear 

38% 

80% 

k 

Annual Outlay: I 411 k 

Comparison to Boilers & Utility Electricity: 

One Absorption Chiller per Cogenerator 

Figure 7-6: Economics of Modular Cogeneration, with 20% process heat, for NORTHDIV. 
---- Cooling Tower -- 

Equipmen lnstallatio Overhead Capacity Cost Total O&M 

($1 000's) ($1 000's) & Profit (tons) ($1 000's) Capital ($Myear) 

120 kW 105.0 42 5.0 110.0 14.0 

775 kW 470.0 270 15.0 485.0 90.4. 

125 kBtuh 5.0 3.0 1.8 9.9 0.5 

425 kBtuh 8.0 4.2 2.4 14.7 0.6 

5000 kBtuh (I) 60.9 28.4 14.9 104.2 2.0 

Absorption Chillers 

10 ton AC: 15.8 4.7 4.1 19 2.0 26.7 0.5 

325 ton AC(1): 183.2 55.0 47.6 535 68.0 353.8 2.0. 

Compression AC 

11 ton 10.1 2.1 2.0 Inc. 14.2 0.8 

27 ton 19.1 3.4 3.7 Inc. 26.2 0.9 

37 ton 23.7 3.9 4.6 Inc. 32.2 1 .o 

DHC System: 

MaxCapCost : 151 5.0 15.0 

MinCapCost: 780.0 8.0 

1) Capacity incremented to cover 20% losses in DHC system. 

Cogenerators: 

Boilers 

Equipment Costs 

Demand: 8.57 /kW-mnth 

Ratchet: 1 months 

Service: $227 /month 

II 

Boilers: 

9 125 kBtuh 

7 425 kBtuh 

Process 

Compression Chillers 

9 11 ton 

7 37ton 

Fixed 

(k$/year) 

Electricity 

2.7 

Purchases $0.0274 /kWh 

IlFuel Cost: 

Capital Variable Fuel 

($k) ($Myear) ($Myear) 

89 4.5 5.4 

103 4.2 14.4 

50.9 

128 7.2 

225 7.0 

Demand Energy Total 

(k$/year) (k$/year) (k$/year) 

169 200 372 

Gas: $0.339 /therm 

= $3.39 /MBtu 

Service: $50 /month 

Inflation: 

Economics: 

Use constant 1995 dollars 11 Totals: I I 

It Capital outlay: $545 k 

@ effic. 

80% 

80% 

80% 

3.03 

3.03 

Average 

($/kWh) 

0.0547 

Annual Outlay: $465 k 

Economics for Boilers and Utility Electricity 

Figure 7-7: Equipment, Economic Assumptions and Baseline System Costs for SOUTHDIV 
Fuel 

($Wyear) 

I 74 

56 

ITotal 

(k$/year) 

1 85.7 

I (0.7) 

@ effic. 

38% 

80% 

0.65 

3.02 

3.02 

Average 

($/kWh) 

0.07E 

(Income) 

7 37 ton I 225 I 71 I 3.03 

Electricitv - Durchases 

Capital 

($k) 

Cog enerators: 

Boilers: 

9 120 kW 990 

9 125 kBtuh 89 

& Process 

Absorption Chillers: 

Compression Chillers: 

7 10 tons 187 

9 11 ton 128 

7 27 ton 184 

Variable 

($Wyear) 

112 

5 

4 

7 

6 

No Absorption Chillers 

Variable Fuel 

($Wyear) ($klyear) 

112 180 

5 56 

0 

7 

@ effic. 

38% 

80% 

0.65 

3.03 

Cog enerators: 

Boilers: 

9 120 kW 

9 125 kBtuh 

& Process 

Absorption Chillers: 

0 10 tons 

Compression Chillers 

9 11 ton 

Capital 

($k) 

990 

89 

0 

128 

Capital outlay: 1. $1,577 k 

Fixed Demand 

(k$/year) (k$/year) 

2.7 64.1 

- Sales: 

Totals: 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

Energy Total Average 

(k$/year) (k$/year) ($/kWh) 

27.2 94.1 0.086 

(0.7) (Income) 

$1,432 k 

460 k 

$887 k 

6k 

161.3 years 

Electricity: 

NA 

(k$/ y ea r) 

- Sales: 

2.7 

One Absorption Chiller per Cogenerator 

(k$/year) (k$/year) 

60.1 22.9 

Figure 7-8: Economics of Modular Cogeneration, with no process heat, for SOUTHDIV. 

Incremental Capital Outlay: 

, Annual Savings: 

i Simple Payback: I Return on Investment: 

$1,032 k 

17 k 

NA 

60.8 years 
Cog enerators: 

Boilers: 

9 120 kW 

9 125 kBtuh 

& Process 

Absorption Chillers: 

7 10 tons 

Compression Chillers 

9 11 ton 

7 27 ton 

Fixed 

(k$/yea r) 

- Sales: 

Electricity - purchases 

2.7 

No Absorption Chillers 

Capital Variable 

($k> ($klyear) 

990 112 

89 5 

187 4 

128 7 

184 6 

. 

Demand Energy 

(k$/yea r) (k$/year) 

60.1 22.9 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

Fuel 

($k/year) 

174 

49 

$1,432 k 

453 k 

$887 k 

13 k 

NA 

Electricity: 

68.7 years 

Total 

(k$/y ea r) 

85.7 

. (1.1) 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

38% 

80% 

$1,577 k 

441 k 

$1,032 k 

24 k 

NA 

Electricity: 

42.4 years 

0.6! 

3.0: 

3.0: 

Average 

($/kWh) 

0.07t 

11 ncome) 

One Absorption Chiller per Cogenerator 

Figure 7-9: Economics of Modular Cogeneration, with process heat, for SOUTHDIV. 
! 

Cogenerators: 

Bo i I ers: 

9 120 kW 

9 125 kBtuh 

& Process 

Absorption Chillers: 

14 10 tons 

Compression Chillers: 

9 6 ton 

7 16 ton 

I Capital IVariable lFuel I@ effic. 11 I Capital IVariable IFuel I@ effic. 

($kj 

990 

89 

373 

128 

149 

To ta I s: 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

- Sales: I 

$1,729 k 

449 k 

$1,185 k 

16 k 

NA 

Electricity: 

73.0 years 

Cogenerators: 

Boilers: 

9 120 kW 

9 125 kBtuh 

& Process 

Absorption Chillers: 

14 10 tons 

Compression Chillers: 

9 11 ton 

7 16 ton 

($Myear) 

112 

5 

($k) 

990 

89 

373 

128 

139 

7 

($k/year) 

7 

6 

Energy 

(k$/year) 

20.6 

($k/year) ($k/year) 

173 

56 

112 

Total 

(k$/year) 

83.5 

(0.71 

38% 175 38% 

80% 

0.65 

3.03 

' 3.03 

Average 

($/kWh) 

0.088 

(Income) 

(k$/iear) 

20.6 

(k$/year) ($/kWh) 

83.5 0.088 

- Sales: I 

Totals: 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility El 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

No Process Heat 20% Process Heat 

' 51 491 80% 

,,, 3.03 

Enerw ITotal ]Average 

I (I .I) I (Income) 

$1,719 k 

xtricity: 

$1,175 k 

22 k 

NA 

52.8 years 

Figure 7-1 0: Economics of Modular Cogeneration, two absorption chillers per cogen, for SOUTHDIV. 
I ---- Cooling Tower -- 

quipment nstallatior Overhead Capacity Cost Total O&M 

($1 000's) ($1 000's) & Profit (tons) ($1 000's) Capital (Wyear) 

2ogenerators: 

120 kW: 105.0 42 5.0 110.0 14.0 

775 kW: 470.0 270 15.0 485.0 90.4 

3oilers 

90 kBtuh 4.3 2.6 1.6 8.5 0.5 

31 0 kBtuh 6.3 3.6 2.0 11.9 0.6 

5000 kBtuh (1) 60.9 28.4 14.9 104.2 2.0 

325 ton AC(1) 183.2 55.0 47.6 535 68.0 353.8 2.0, 

Absorption Chillers 

Compression AC 

3.1 ton 3.2 0.7 0.6 Inc. 4.4 0.8 

10 ton AC: 15.8 4.7 4.1 19 2.0 26.7 0.5 

10.1 ton I 7.6 1.6 1.5 Inc. 10.7 0.9 

10.1 ton 

DHC System: 

MaxCapCost: 

MinCapCost: I I I I I I 780.0 I 8.0 

1) Capacity incremented to cover 20% losses in DHC system. 

Equipment Costs 

7.6 1.6 1.5 Inc. 10.7 1 .o 

151 5.0 15.0 

$0.0645 /kWh 

Demand: 12.72 /kW-mnth 

Ratchet: 1 months 

Service: $310 /month 

Capital. Variable Fuel 

($k) ($k/year) ($k/year) 

Purchases $0.0523 /kWh 

he1 Cost: 

@ effic. 

Gas: $0.271 /therm 

Inflation: Use constant 1995 dollars 

77 

83 

rs 

40 

75 

Demand 

(k$/y ea r) 

188 

Study duration: 20 years 

Economic Parameters 

4.5 5.4 80% 

4.2 14.4 80% 

47.5 80% 

7.2 3.03 

7.0 3.03 

Energy Total Average 

(k$/ y ea r) (k$/y ea r) ($/kW h) 

309 501 0.1046 

Boilers: 

9 90 kBtuh 

7 310 kBtut 

Process 

Compression Chill€ 

9 3.1 ton 

7 10.1 ton 

Fixed 

(k$/year) 

3.7 

Electricity 

Totals: 

Capital 01 

Annual 0 

Economi 

I I I 

tlay: $274 k 

itlay: $591 k 

:s for Boilers and Utility Electricity . 

Figure 7-1 I : Equipment, Economic Assumptions and Baseline System Costs for WESTDIV 

, 
Annual Outlay: I 321 k 

Comparison to Boilers & Utility Electricity: 

Annual Outlay: I 314 k 

Comparison to Boilers & Utility Electricity: 

Figure 7-12: Economics of Modular Cogeneration, with no process heat, for WESTDIV. 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

$907 k Incremental Capital Outlay: $1,019 k 

270 k Annual Savings: 277 k 

3.4 years Simple Payback: 3.7 years 

29.6% Return on Investment: 26.9% 
Variable Fuel @ effic. 

($k/year) ($k/year) 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility E 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

Capital Variable Fuel @ effic. 

($k) ($k/year) ($k/year) 

Cog enerators: Cog enerators: 

Boilers: 

9 120 kW 

9 90 kBtuh 

& Process 

Absorption Chillers: 

0 10 tons 

Compression Chillers 

9 3.1 ton 

7 10.1 ton 

Capital 

($k) 

990 

77 

0 

40 

75 

112 

No Absorption Chillers One Absorption Chiller per Cogenerator 

- 

117 30% 9 120 kW 990 112 115 38% 

Boilers: 

Figure 7-13: Economics of Modular Cogeneration, with 20% process heat, for WESTDIV. 

5 

0 

7 

7 

Energy 

(k$/year) 

3.4 

46 80% 9 90 kBtuh 77 5 46 80% 

& Process 

Absorption Chillers: 

Compression Chillers: 

Electricity - purchases 

0.65 7 10 tons 187 4 0.65 

3.03 9 3.1 ton 40 7 3.03 

3.03 0 10.1 ton 0 0 3.03 

Total Average Fixed Demand Energy Total Average 

(k$/year) ($/kWh) (k$/year) (k$/year) (k$/year) (k$/year) ($/kWh) 

22.8 0.103 3.7 14.3 2.6 20.7 0.094 

(2.6) (Income) - Sales: (2.6) (Income) 

$1 ,I 81 k 

313 k 

$907 k 

278 k 

lectricity: 

3.3 years 

30.4% 

Totals: 

Capital outlay: $1,293 k 

Annual Outlay: 307 k 

Comparison to Boilers & Utility Electricity: 

Incremental Capital Outlay: $1,019 k 

Annual Savings: 284 k 

Simple Payback: 3.6 years 

Return on Investment: 27.7% 
I .4 

2.5 

O&M 

($k/year) 

14.0 

90.4 

0.5 

0.6 

2.0, 

0.5 

2.0 

0.8 

0.9 

1 .o 

15.0 

8.0 

---- Cooling Tower -- 

Capacity Cost 

(tons) ($1 000's) 

42 5.0 

270 15.0 

19 2.0 

535 68.0 

Inc. 

Inc. 

Inc. 

$0.0546 /kWh 

Demand: 11.90 /kW-mnth 

Ratchet: 1 months 

Service: $160 /month 

Total 

Capital 

110.0 

485.0 

7.6 

14.8 

104.2 

26.7 

353.8 

13.3 

22.6 

29.0 

151 5.0 

Equipmen 

($1 000's) 

120 kW: 105.0 

775 kW: 470.0 

75 kBtuh 3.9 

250 kBtuh 7.9 

5000 kBtuh (1) 60.9 

Absorption Chillers 

10 ton AC: 15.8 

325 ton AC(1) 183.2 

Compression AC 

10 ton 9.5 

22 ton 16.2 

32 ton 21.2 

DHC System: 

MaxCapCost: 

MinCapCost: 

Cog enerators: 

Boilers 

I I 780.0 

DHC system. 

nstallatio Overhead 

($1 000's) & Profit 

2.3 

4.5 

28.4 14.9 

4.7 4.1 

55.0 47.6 

2.0. 1.9 

3.2 3.2 

3.7 4.2 

Purchases $0.0455 /kWh 

Gas: $0.470 /therm 

= $4.70 /MBtu 

Service: $50 /month 

Inflation: Use constant 1995 dollars 

Study duration: 20 years 

Economic Parameters 

Economics: 

Boilers: 

9 75 kBtuh 

7 250 kBtuk 

Process 

Compression Chille 

Electricity 

9 IO ton 

7 32ton 

Fixed 

(k$/year) 

1.9 

Totals: 

Capital 01 li 

Figure 7-14: Equipment, Economic Assumptions and Baseline System Costs for SWESTDIV 
I 

Cogenerators: 

Boilers: 

9 120 kW 

9 75 kBtuh 

& Process 

Absorption Chillers: 

Capital Variable Fuel @ effic. 

($k) ($Wyear) ($k/year) 

990 112 169 38% 

68 5 55 80% 

Cogenerators: 

Boilers: 

9 120 kW 

9 75 kBtuh 

& Process 

Absorption Chillers: 

II 

($kj ($k/yearl 

990 112 

68 5 

9 10 ton I 

(k$/year) (k$/year) (k$/year) 

1.9 0.4 0.0 

- Sales: 

1201 

(k$/year) ($/kWh) 

2.3 0.056 

(0.8) (Income) 

I 1 

3.03 

0 10 tons 0 0 0.65 

Compiession Chillers: 

7 32 ton I 203 I I 3.03 11 Electricity - Purchases 

7 10 tons 

Compression Chillers: 

II - Fixed IDemand IEnergy ITotal IAverage 

187 4 

(k$/year) I (k$/year) I (k$/year) I (k$/year) I ($/kWh) 

1.91 1.41 0.0 I 3.41 0.082 

Totals: 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

-Sales: I I I (0.8) I (Income\ 

$1,523 k 

354 k 

$1,028 k 

103 k 

10.0 years 

7.7% 

Electricity: 

Totals: 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

No Absorption Chillers 

$1,381 k 

357 k 

$886 k 

100 k 

9.4% 

Electricity: 

8.9 years 

I Capital IVariable IFuel I@ effic. 

9 10 ton I 120 I 7 

7 22 ton I 1581 6 

Electricity - mirchases 

- Fixed IDemand IEnergy 

($k/year) 

164 

55 

Total 

’ One Absorption Chiller per Cogenerator 

- 

38% 

80% 

0.65 

3.03 

3.03 

Average 

Figure 7-15: Economics of Modular Cogeneration, with no process heat, for SWESTDIV. 
Capital Variable 

($k) ($k/year) 

Cog enerators: 

Boilers: 

9 120 kW 990 112 

9 75 kBtuh 68 5 

& Process 

Absorption Chillers: 

Compression Chillers 

0 10 tons 0 0 

9 10 ton 120 7 

7 32 ton 203 7 

tuel @ effic. 

($k/year) 

169 38% 

48 80% 

0.65 

3.03 

3.03 

Capital outlay: I $1,381 k 

- 

38% 

80% 

0.65 

3.03 

3.03 

Average 

($/kWh) , 

0,056 

Jncome) 

Annual Outlay: I 350 k 

Comparison to Boilers & Utility Electricity: 

(k$/year) 

- Sales: 

I .9 

(k$/year) (k$/iiar) (k$/year) ($/kWh) 

(1.2) (Income) 

1.4 0.0 3.4 0.082 

No Absorption Chillers 

Capital outlay: 

Annual Outlay: 

Comparison to Boilers & Utility 

Incremental Capital Outlay: 

Annual Savings: 

Simple Payback: 

Return on Investment: 

I Capital IVariable IFuel I@ effic. 11 

$1,523 k 

347 k 

$1,028 k 

110 k 

8.6% 

Electricity: 

9.4 years 

Cog enerators: 

Boilers: 

9 120 kW 

9 75 kBtuh 

& Process 

Absorption Chillers: 

7 10 tons 

Compression Chillers: 

9 10 ton 

Incremental Capital Outlay: - 

Annual Savings: 

Simple Payback: 

Return on Investment: 

7 22 ton 

Fixed 

(k$/year) 

- Sales: 

Electricity - purchases 

1.9 

Totals: 

$886 k 

107 k 

8.3 years 

10.4% 

($kj 

990 

68 

187 

120 

158 

Demand 

(k$/y ea r) 

0.4 

$k/ ear $k/ ear 

'~ 

7 

One Absorption Chiller per Cogenerator 

Figure 7-16: Economics of Modular Cogeneration, with 20% process heat, for SWESTDIV. 

References for Chapter 2: 

1. L. J. Kostrzewa and K. Davidson, "Packaged Cogeneration", ASHRAE J., Feb. 1988, p. 22. 

2. T. Y. Lee and S. deMonsabert, "Users Guide for Small Packaged Cogeneration System (PCS) 

Applications", TM #: M-73-87-06, Naval Civil Engineering Laboratory, Port Hueneme CA 93043, 1987. 

3. Thomas Register of Industrial Companies. 

4. H. W. Brown and F. S. Stuber, "Reliability of Natural Gas Cogeneration Systems", Gas Research 

Institute, 8600 Bryn Mawr Ave, Chicago IL 60631, GRI 93/0020 (1992). 

5. Brown 8z Stuber, op. cit., p. 4-5. 

6. C. S. Weaver and S. H. Turner, "Dual Fuel Natural Gas/Diesel Engines: Technology, Performance and 

Emissions", in Alternative l31-W nllty F qines, SP-1027, Society of Automotive Engineers, 

Warrendale PA (1994). 

7. D. T. Bliizard, F. S. Schaub and J. G. Smith, "Development of the Cooper-Bessemer CleanBurn GasDiesel (Dual-Fuel) Engine", Trans. ASME, Vol 114, p. 480 (July 1992). 

8. M. E. Crane and S. R. King, "Emission Reductions Through Precombustion Chamber Design in a natural 

Gas, Lean Burn Engine", Trans. ASME, Vol114, p. 466 (July 1992). 

9. G. E. Doughty, S. R. Bell and K. C. Midkiff, "Natural Gas Fueling of a Caterpillar 3406 Diesel Engine", 

J. Engineering for Gas Turbines and Power, Vol114, p. 459 (July 1992). 

10. South Coast Air Quality Management District, Rule 1110.2 - Emissions From Gmeous and Liquid Fueled 

Internal Combustion Engines, 1990. 

11. South Coast Air Quality Management District, telephone conversation. 

12. Maryland Department of the Environment, telephone conversation. 

13. New York State Department of Environmental Conservation, telephone conversation. 

14. Texas Natural Resource Conservation Commission, Technical Guidance Package for Cornbution Section 

Sources - Reciprocating Engines, March 1995. 

15. Texas Natural Resource Conservation Commission, telephone conversation. 

16. Commonwealth of Virginia State Air Pollution Control Board, Regzdations For the Control and Abatement 

of Air Pollution, January 1992. 

17. Commonwealth of Virginia State Air Pollution Control Board, telephone conversation. 

18. J. J. White, J. N. Carroll, C. T. Hare and J. G. Lourenco, "Emission Control Strategies for Small 

Utility Engines", SAE Paper No. 911807 

19. Creamer,K. S., and Saunders, J.H. Evaluation of a catalytic converter for a 3.73 kW natural gas engine. 

Society of Automotive Engineers paper 930221, 1993. 

R-1 
20. Rao, V.D.N., Cikanek, H.A., and Horrocks, R.W. Diesel particulate control system for Ford 1.8L 

Sierra Turbo-Diesel to meet 1997-2003 particulate standards. Society of Automotive Engineers paper 940458, 

1994. 

21. Paw, G.M., Baumgard, K. J. , Gratz, L. D., Bagley, S. t., Leddy, D. G., and Johnson, J. H. Effects 

of an oxidation catalytic converter on regulated and unregulated diesel emissions. Society of Automotive 

En,geers paper 940243, 1994. 

22. Cartellieri, W., Kriegler, W., and Schweinzer, F. Strategies to meet worldwide heavy-duty diesel 

emission standards. Proc. Instn. Mech. Engrs. 2Q6, 161-171 (1992). 

23. Omk, S., McKinnon, D.K., -0, J. L., Irigo, B., andSam, J. International experience using diesel 

catalytic converters for urban buses. Society of Automotive Engineers paper 940238, 1994. 

24. McKinnon, D.L. Seven years experience with diesel particulate filter systems in nonroad applications, 

Society of Automotive Engineers paper 940234, 1994, 

25. P. Zelanka, W. Kriegler , P. L. Herzog and W. P. Cartellieri, “Ways Toward the Clean Heavy Duty 

Diesel”, SAE paper No. 900602, in Diesel Particulate Emissions, Johnson, Baines and Clerk, eds., SOC. 

Automotive Eng., Warrendale PA (1992). 

26. S. H. Turner and C. S. Weaver, “Dual-Fkel Natural Gas/Diesel Engines: Technology, Performance and 

Emissions”, GFU-940094, Gas Research Institute, Chicago (1994). 

27. Brezonie, M. Lowering emissions in mine engines, Diesel Progress 72-73, September 1993. 

28. Urban, C. M., Dietzmann, H. E., and Fanick, E.R. Emission control technology for stationary natural 

gas engines. Journal of Engineering for Gas Turbines and Power, V. 111, pp 369-374, American Society 

of Mechanical Engineers (July 1989). 

29. Weaver, C.S. and McGregor, B. Emission control technology for locomotive engines. Society of 

Automotive Engineers paper 940453, 1994. 

30. Heimrich, M.J. Diesel NO, catalytic converter development: a review. in Heavy Duty Engines: A Look 

at the Future, American Society of Mechanical Engineers, ICE-Vol. 22 (1994). 

31. Anon. Exhaust after treatment system developed for Caterpillar engines, Diesel and Gas Turbine 

Worldwide (June 1995). 

R-2 
References for Chapter 3 : 

1. R. S. Means Co, “Means Mechanical Cost Data”, 19th ed., 157-240, Kingston MA 02364-0800 (Oct. 

1995). 

2. R. S. Means Co., ibid, A8.8-130. 

3. R. W. Leigh, H. S. Isaacs, J. Kirley and A. Rawe, “Capital Cost Reductions in Absorption Chillers”, 

ASHRAE Transactions 1989, Vol. 95, Pt. 1. 

4. ASHRAE 1989 Handbook of Fundamentals (I-P Edition), American Society of Heating, Refrigerating and 

Air-conditioning Engineers, 1791 Tullie Circle NE, Atlanta GA 30329 (1989) 
References for Chapter 4: 

1. J. A. Shonder and H. A. McLaii, “Energy Savings Potential for Cogeneration in the United States”, 

CADDET Energy Efficiency Newsletter (PO Box 17,6130 AA, Sittard, The Netherlands) No. 3 (Sept. 

1995). 

2. U.S. Department Of Energy, Office of Building Technologies “Core Databook”, Washington DC (June 

1994). 

R-4 
References for Chapter 5 

1. U.S. DOE, Office of Building Technologies, op. Cit. 

2. U.S. DOE, Office of Building Technologies, op. Cit. 

3. C. L. Segaser, “Internal Combustion Engines”, Oak Ridge National Laboratory, Oak Ridge TN, 

ANL/CES/TE 77-1 (1977); C.L.Segaser, ‘Conventional A-C Generators and Engine Generator Sets”, ORNL 

ANL/CES/TE 78-1 (1978); C.L.Segaser, “Heat Recovery Equipment for Engines”, ORNL, ANL/CES/TE 

77-4 (1977). 

4. U.S. Dept. Of Commerce, Statistical Abstract of the United States - 1994, Table 753, Washington DC 

(1995), and current updates. 

5. J. A. Shonder, private communication 

6. R.S.Means Co, Inc., “Means Mechanical Cost Data - 1996”, Kingston MA 02364 (1995). 

7. R. W. Leigh and M. Piraino, “Increased Use of Reject Heat from Electric Generation”, BNL-60174, 

Brookhaven National Laboratory, Upton NY 11973 (1994). 

8. To fiid the range Al - A,, the sum of two ranges B1 - B2 and C1 - C;, let AI,, = &,+A, where 

= (B1+B3/2+(C,+C-3/2 and A = ((B2-B1)2+(&-C1)2)’/2. See the previous reference for a detailed 

explanation. 

9. J. A. Shonder and H.A.McClain, op.cit. 

R-5 
References for Chapter 7 

1. PECO (Philadelphia Electric Company), Philadelphia PA, rate card supplied by facsimile. 

2. Gulf Power Co., Pensacola, telephone conversation. 

3. PG&E (Pacific Gas and Electric), San Francisco CA, rate cards supplied by facsimile. 

4. San Diego Gas and Electric (SDGE), San Diego CA, rate cards supplied by facsimile. 

R- 6 
Appendix A 

Cogeneration Simulation Spreadsheets 

for 

Model Facility 

with 

National Average Energy Loads 

A-l 
COGEN ELEC. CAP., kW 840 HEAT/ELEC. RATIO, nd 1.375 

0.4 

258 

258 151 

0 0 

258 151 

121 1 707 

0 0 

258 151 

1725 1007 

267 156 

1256 734 

1256 734 

258 151 

3450 2015 

535 31 2 

2512 1467 

2512 1467 

258 75 

51 75 1511 

802 234 

3768 1100 

3768 1100 

331 193 

0 0 

331 193 

1554 908 

0 0 

404 236 

0 0 

404 236 

1897 1108 

0 0 

477 139 

0 0 

477 139 

2240 654 

IfraC. of Year Elec. nd 0.3 0.2 0.1 

516 774 1032 

51 6 226 774 226 1032 151 

0 0 0 0 0 0 

51 6 226 774 226 840 123 

2423 1061 3634 1061 3944 576 

0 0 0 0 0 0 

51 6 226 774 226 1032 151 

1725 756 1725 504 1 725 252 

51 6 226 774 226 840 123 

2423 1061 3634 1061 3944 576 

1256 550 1256 367 1256 183 

51 6 226 774 226 1032 151 

3450 1511 3450 1007 3450 504 

535 234 774 226 840 123 

2512 1100 3634 1061 3944 576 

2512 1100 2512 734 2512 367 

51 6 113 774 113 1032 75 

51 75 1133 51 75 756 51 75 378 

802 176 802 117 840 61 

3768 825 3768 550 3944 288 

3768 825 3768 550 3768 275 

589 258 847 247 1105 161 

0 0 0 0 0 0 

589 258 840 245 840 123 

2766 121 1 3944 1152 3944 576 

0 0 0 0 0 0 

662 290 920 269 1178 1 72 

0 0 0 0 0 0 

662 290 840 245 840 123 

31 09 1362 3944 1152 3944 576 

0 0 0 0 0 0 

735 161 993 145 1251 91 

0 0 0 0 0 0 

735 161 840 123 840 61 

3451 756 3944 576 3944 288 

All Base nonAC Elec Ld, kW 

SHOULDER 

EACH BLOCK 

Edemand kW MWh/yr 5000 MWh/yr Ebought 264 MWh/yr 

Hdemand kBtuh MBtu/yr 11 333 MBtu/yr Esold 401 MWh/yr 

Ecogen kW MWh/yr 5137 MWh/yr Hboilers 3081 MBtu/yr 

Hcogen kBtuh MBtu/yr 24123 MBtu/yr 

,Hused kBtuh MBtdyr 8252 MBtu/yr 

fY heat, nd 0.166667 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 0 

HEATING, LOW 

fY heat, nd 0.166667 

CgB Ht Ld, kBtuh 1256 

ROB Ht Ld, kBtuh 469 

ROB AC Elec Ld, kW 0 

HEATING, MED 

fY heat, nd 0.1 66667 

CgB Ht Ld, kBtuh 2512 

ROB Ht Ld, kBtuh 938 

ROB AC Elec Ld, kW 0 

HEATING, HIGH 

fY heat, nd 0.083333 

CgB Ht Ld, kBtuh 3768 

ROB Ht Ld, kBtuh 1407 

ROB AC Elec Ld, kW 0 

COOLING, LOW 

fY heat, nd 0.1 66667 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 73 

COOLING, MED 

fY heat, nd 0.1 66667 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 146 

COOLING, HIGH 

fY heat, nd 0.083333 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 21 9 

0 01 0 01 0 01 0 0 

WHOLE SYSTEM 

A-2 
I COGEN ELEC. CAP., kW 840 HEAT/ELEC. RATIO, nd 1.375 

frac. of Year Elec. nd 0.4 0.3 0.2 0.1 

.All Base nonAC Elec Ld, kW 258 51 6 774 1032 

SHOULDER 

258 151 

0 0 

258 151 

1211 707 

0 0 

Wheat, nd 0.166667 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 

HEATING, LOW 

fY heat, nd 0.166667 

CgB Ht Ld, kBtuh 1256 

ROB Ht Ld, kBtuh 469 

ROB AC Elec Ld, kW 0 

HEATING, MED 

fY heat, nd 0.166667 

CgB Ht Ld, kBtuh 251 2 

ROB Ht Ld, kBtuh 938 

ROB AC Elec Ld, kW 0 

HEATING, HIGH 

fY heat, nd 0.083333 

CgB Ht Ld, kBtuh 3768 

ROB Ht Ld, kBtuh 1407 

ROB AC Elec Ld, kW 0 

COOLING, LOW 

W heat, nd 0.166667 

CgB Ht Ld, kBtuh 843 

ROB AC Elec Ld, kW 20 

COOLING, MED 

N heat, nd 0.166667 

CgB Ht Ld, kBtuh 1295 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 65 

COOLING, HIGH 

N heat, nd 0.083333 

CgB Ht Ld, kBtuh 1295 

ROB AC Elec Ld, kW 137 

0 

ROB Ht Ld, kBtuh a 

ROB Ht Ld, kBtuh a 

51 6 226 

0 0 

51 6 226 

2423 1061 

0 0 

EACH BLOCK 

Edemand I kW MWh/yr 

774 226 

0 0 

774 226 

3634 1061 

0 0 

1032 151 

0 0 

840 123 

3944 576 

0 0 

258 151 

1725 1007 

267 156 

1256 734 

1256 734 

258 151 

3450 2015 

535 312 

2512 1467 

2512 1467 

258 75 

51 75 1511 

802 234 

3768 1100 

3768 1100 

278 162 

a43 492 

278 162 

1305 762 

843 492 

323 189 

1295 756 

323 189 

1517 886 

1295 756 

395 115 

1295 378 

395 115 

1855 542 

1295 378 

WHOLE 

51 6 226 

1725 756 

51 6 226 

2423 1061 

1256 550 

51 6 226 

3450 1511 

535 234 

2512 1100 

2512 1100 

51 6 113 

51 75 1133 

802 176 

3768 825 

3768 825 

536 235 

843 369 

536 235 

2517 1102 

843 369 

581 254 

1295 567 

581 254 

2728 1195 

1295 567 

653 143 

1295 284 

653 143 

3066 672 

1295 284 

SYSTEM 

774 226 

1725 504 

774 226 

3634 1061 

1256 367 

774 226 

3450 1007 

774 226 

3634 1061 

251 2 734 

774 113 

802 117 

3768 550 

. 3768 550 

794 232 

843 246 

794 232 

3728 1089 

843 246 

839 245 

1295 378 

839 245 

3940 1150 

1295 378 

91 1 133 

1295 189 

840 123 

3944 576 

I 1295 189 

51 75 756 

Cogen Heat Cap., kBtuh 3944.325 BASE CASE, 1 CHILLER PER COGEN 

1032 151 

1725 252 

840 123 

3944 576 

1256 183 

1032 151 

3450 504 

840 123 

3944 576 

2512 367 

1032 75 

840 61 

3944 288 

3768 275 

1052 154 

843 123 

840 123 

3944 576 

843 123 

1097 160 

1295 189 

840 123 

3944 576 

1295 189 

1169 85 

1295 95 

840 61 

3944 288 

1295 95 

51 75 378 

A-3 
I COGEN ELEC. CAP., kW 840 HEAT/ELEC.. RATIO, nd 1.375 

0.3 

51 6 

51 6 226 

0 0 

51 6 226 

2423 1061 

0 0 

51 6 226 

1725 756 

516 . 226 

2423 1061 

1256 550 

51 6 226 

3450 1511 

535 234 

2512 1100 

2512 1100 

516 113 

51 75 1133 

802 176 

3768 825 

3768 825 

536 235 

843 369 

536 235 

251 7 1102 

843 369 

556 244 

1686 738 

556 244 

261 1 1144 

1686 738 

576 1 26 

2529 554 

576 126 

2705 592 

0.4 

258 

Ifrac. of Year Elec. nd I 0.2 

774 

774 226 

0 0 

774 226 

3634 1061 

0 0 

774 226 

1725 504 

774 226 

3634 1061 

1256 367 

774 226 

3450 1007 

774 226 

' 3634 1061 

2512 734 

774 113 

51 75 756 

802 117 

3768 550 

3768 550 

794 232 

843 246 

794 232 

3728 1089 

843 246 

81 4 238 

1686 492 

814 238 

3822 1116 

1686 492 

834 122 

2529 369 

834 122 

391 6 572 

All Base nonAC Elec Ld, kW 

SHOULDER 

N heat, nd 0.083333 

CgB Ht Ld, kBtuh 3768 

ROB Ht Ld, kBtuh 1407 

ROB AC Elec Ld, kW 0 

COOLING, LOW 

W heat, nd 0.1 66667 

CgB Ht Ld, kBtuh 843 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 20 

COOLING, MED 

N heat, nd 0.166667 

CgB Ht Ld, kBtuh 1686 

ROB Ht Ld, kBtuh 0 

ROB AC Eiec Ld, kW 40 

W heat, nd 0.166667 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 0 

HEATING, LOW 

Wheat, nd 0.1 66667 

CgB Ht Ld, kBtuh 1256 

ROB Ht Ld, kBtuh 469 

ROB AC Elec Ld, kW 0 

258 75 

51 75 1511 

802 234 

3768 1100 

3768 1100 

278 162 

843 492 

278 162 

1305 762 

843 492 

298 1 74 

1686 985 

359 21 0 

1686 985 

258 151 

0 0 

258 151 

121 1 707 

0 0 

N heat, nd 0.083333 

CgB Ht Ld, kBtuh 2529 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 60 

258 151 

1725 1007 

267 156 

1256 

HEATING, MED 

0.166667 

CgB Ht Ld, kBtuh 2512 3450 201 5 

ROB Ht Ld, kBtuh 938 535 31 2 

ROB AC Elec Ld, kW 251 2 1467 

31 8 93 

2529 738 

539 157 

2529 738 

2512 1467 

HEATING, HIGH 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

16872 MBtu/yr Esold 502 MWh/yr 

4972 MWh/yr Hboilers 3081 MBtu/yr 

23345 MBtu/yr 

13790 MBtu/yr 

I 1686 985 

COOLING, HIGH 

2529 5541 2529 369 

SYSTEM 

0.1 

1032 

1032 151 

0 (I 

840 123 

3944 576 

0 0 

1032 151 

1725 252 

840 123 

3944 576 

1256 183 

1032 151 

3450 504 

840 123 

3944 576 

2512 367 

1032 75 

5175 378 

840 61 

3944 288 

3768 275 

1052 154 

843 123 

840 123 

3944 576 

843 123 

1 072 157 

1686 246 

840 123 

3944 576 

1686 246 

1092 80 

2529 185 

840 61 

3944 288 

2529 185 

A-4 
I COGEN ELEC. CAP., kW 775 HEAT/ELEC. RATIO, nd 1.375 

0.2 

774 

774 226 

774 226 

3634 1061 

0 0 

0 0 

774 226 

21 56 630 

774 226 

3634 1061 

21 56 630 

774 226 

431 2 1259 

775 226 

3639 1063 

3639 1063 

774 113 

6468 944 

775 113 

3639 531 

' 3639 531 

774 226 

1449 423 

774 226 

3634 1061 

1449 423 

774 226 

2897 846 

774 226 

3634 1061 

2897 846 

774 113 

4346 635 

775 113 

3639 531 

3639 531 

Ifrac. of Year Elec. nd 0.1 

1032 

1032 151 

775 113 

3639 531 

0 a 

0 a 

1032 151 

2156 31 5 

775 113 

3639 531 

2156 31 5 

1032 151 

431 2 630 

775 113 

3639 531 

3639 531 

1032 75 

6468 472 

775 57 

3639 266 

3639 266 

1032 151 

1449 21 2 

775 113 

3639 531 

1449 21 2 

1032 151 

2897 423 

775 113 

3639 531 

2897 423 

1032 75 

4346 31 7 

775 57 

3639 266 

3639 266 

AC Elec Ld, kW 

258 151 

0 0 

258 151 

121 I 707 

0 0 

258 151 

21 56 1259 

459 268 

21 56 1259 

21 56 1259 

258 151 

431 2 251 8 

775 453 

3639 21 25 

3639 21 25 

258 75 

6468 1889 

775 226 

3639 1063 

3639 1063 

258 151 

1449 846 

309 180 

1449 846 

1449 846 

258 151 

2897 1692 

61 7 360 

2897 1692 

2897 1692 

ff heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

51 6 226 

0 0 

51 6 226 

2423 1061 

0 0 

51 6 226 

21 56 944 

51 6 226 

2423 1061 

21 56 944 

51 6 226 

431 2 1889 

775 339 

3639 1594 

3639 1594 

51 6 113 

6468 1417 

775 170 

3639 797 

3639 797 

51 6 226 

1449 635 

51 6 226 

2423 1061 

1449 635 

516 226 

2897 1269 

617 270 

2897 1269 

2897 1269 

0.1 66667 

0 

0 

0 

258 75 

4346 1269 

775 226 

3639 1063 

HEATING, LOW 

fY heat, nd 0.1 66667 

CgB Ht Ld, kBtuh 21 56 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 0 

HEATING, MED 

~Nheat, nd 0.166667 

'CgB Ht Ld, kBtuh 4312 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 0 

516 

4346 

775 

3639 

HEATING, HIGH 

fY heat, nd 0.083333 

CgB Ht Ld, kBtuh 6468 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 0 

Hdemand 

Ecogen 

Hcogen 

Hused 

COOLING, LOW 

Wheat, nd 0.1 66667 

CgB Ht Ld, kBtuh 1449 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 0 

COOLING, MED 

fY heat, nd 0.166667 

CgB Ht Ld, kBtuh 2897 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 0 

COOLING, HIGH 

fY heat, nd 0.083333 

CgB Ht Ld, kBtuh 4346 

ROB Ht Ld, kBtuh 0 

ROB AC Elec Ld, kW 0 

kBtuh MBtu/yr 23684 MBtu/yr 

kW MWhIyr 5527 MWh/yr 

kBtuh MBtu/yr 25954 MBtulyr 

kBtuh MBtu/yr 201 19 MBtulyr 

0.4 

113 

952 

170 

797 

EACH BLOCK 

Edemand I kW MWh/yr I 

3639 1063 I 3639 797 

WHOLE SYSTEM 

Cogen Heat Cap., kBtuh 

Ebought 

Esold 

Hboilers 

3639 BASE CASE, DHC COGEN & ABS. CHILLER 

225 MWhIyr 

1232 MWh/yr 

3564 MBtu/yr 

A-5 

Appendix B 

Cogeneration Simulation Spreadsheets 

for 

Model Facility 

with 

Navy EFD - Specific Energy Loads 

B-1 
Appendix B: Input Data and Spreadsheet Analyses for Navy EFD's 

fy heat CgB ht load ROB ht load . 

kBtu h kBtu h 

Shoulder 0.208 0 0 

Low 0.200 877 329 

CHESDIV/LANTDIV SPREADSHEET INPUTS 

ROB AC elec 

kW 

0 

0 

ELECTRIC: Whole Base Non AC Avg. Load = 693 kW 

Low step = 0.5 X above = 346 kW 

2nd step = 1.0 X above = 693 kW 

3rd step = 1.5 X above = 1040 kW 

4th step = 2.0 X above = 1386 kW 

High 

PROCESS HEAT: If no process heat is obtained from cogeneration, then add the Hourly 

Average Process Heat for Whole Site, or 

1723 kBtuh 

to the "ROB Ht Ld" in the spreadsheet for all heating, cooling, and shoulder seasons. If 20% 

of process heat in cogenerated buildings is carried by cogenerators, then add 0.2 X Hourly 

Average Process Heat for 7 Buildings, or. 

to all "CgB Ht Ld" inputs for all seasons, and reduce the "ROB Ht Ld" by the same amount, 

below what it was in the former case. 

0.2 X 1254 Btuh = 251 Btuh 

0.1 00 2630 987 0 

SHOULDER SEASON: Months in season = 2.5 

HEATING SEASON: Months in season = 6.0 

Low step multiplier = 6.667honths in season = 1.11 1 

Medium I 0.200 I 1753 I 658 lo 

I 

CgB hload = Avg. CgB heat load X low step multiplier X [1,2 or 31 

ROB hload = Avg. ROB heat load X low step multiplier X [1,2 or 31 
CHESDIV/LANTDIV SPREADSHEET INPUTS 

fy cool All Base Avg 

Cooling Load 

kBtuh 

Low 0.1 17 460 

Med 0.117 460 

High 0.058 460 

COOLING: Months in season = 3.5 

Low step multiplier = 6.667/months in season = 1.905 

Low Step ROB AC elec 

Multiplier kW 

X 1.905 X 1/10.36 = 85 

X 1.905 X 2/10.36 = 169 

X 1.905 X 3/10.36 = 254 

If no chillers, all base cooling met as "ROB AC Elec M" 

Notmet 

by chlrs. 

kBtuh 

RoBAC 

elec. 

kW 

If one chiller per cogenerator, the chillers meet as much of the cooling load as they can. Any 

excess, together with non-cogenerated building cooling load, is met electrically 

238 

7 bldgs 

cooling 

kBtuh 

Low I638 638 982 

840 1292 

476 I 840 11292 

7 bldgs. cooling load = avg. 7 bldgs. cooling load X low step 

ROB cooling load = rest of site avg. cooling load X low step 

Met by chillers = lesser of 7 bldgs cooling load and 840 Btuh 

CgB thermal input = met by chillers/O.65 

Not met by chillers = 7 bldgs cooling load - met by chillers + ROB cooling load 

multiplier X [1,2 or 31 

multiplier X [1,2 or 31 

ROB AC electric = Not met by chillers/l0.36 
COGEN ELEC. CAP., kW 0 HEAT/ELEC. RATIO, nd 1.375 

0.1 

1386 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 0.208 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 1723 

ROB AC Elec Ld, kW 0 

0.4 

346 

0.3 

693 

0.2 

1040 

253 

31 4 

0 

0- 

0 

346 ' 252 

1723 1256 

0 0 

0 0 

0 0 

693 

1723 

0 

0 

0 

379 

942 

0 

0 

0 

1040 

1723 

0 

0 

0 

379 

628 

0 

0 

0 

1386 

1723 

0 

0 

0 

HEATING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

877 

2052 

0 

346 242 

2929 2053 

0 0 

0 0 

0 0 

693 

2929 

0 

0 

0 

364 

1539 

0 

0 

0 

1040 

2929 

0 

0 

0 

364 

1026 

0 

0 

0 

1386 

2929 

0 

0 

0 

243 

513 - 

0 

0 

0 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1753 

2381 

0 

' 346 242 

41 34 2897 

0 0 

0 0 

0 0 

693 

41 34 

0 

0 

0 

364 

21 73 

0 

0 

0 

1040 

41 34 

0 

0 

0 

364 

1449 

0 

0 

0 

1386 

41 34 

0 

0 

0 

243 

724 

0 

0 

0 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

121 

468 

0 

0 

0 

0.1 

2630 

271 0 

0 

346 121 

5340 1871 

0 0 

0 0 

0 0 

693 

5340 

0 

0 

0 

182 

1403 

0 

0 

0 

1040 

5340 

0 

0 

0 

1 82 

936 

0 

0 

0 

1386 

5340 

0 

0 

0 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.117 

0 

1723 

85 

778 

1723 

0 

0 

0 

239 

530 

0 

0 

0 

1125 

1723 

0 

0 

0 

231 

353 

0 

0 

0 

1471 

1723 

0 

0 

0 

151 

177 

0 

0 

0 

431 

1723 

0 

0 

0 

177 

706 

0 

0 

0 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 17 

0 

1723 

169 

51 5 

1723 

0 

0 

0 

21 1 

706 

0 

0 

0 

862 265 

1723 . 530 

0 0 

0 0 

0 0 

1209 

1723 

0 

0 

0 

248 

353 

0 

0 

0 

1555 

1723 

0 

0 

0 

159 

177 

0 

0 

0 

COOLING, HIGH 

N heat, nd 0.058 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 1723 

ROB AC Elec Ld, kW 254 

83 

88 

0 

0 

0 

600 122 

1723 350 

0 0 

0 0 

0 0 

WHOLE SYSTEM 

6459 

24599 

0 

0 

0 

947 

1723 

0 

0 

0 

144 

263 

0 

0 

0 

1294 

1723 

0 

0 

0 

131 

175 

0 

0 

0 

1640 

1723 

0 

0 

0 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Ebought MWh/yr 

Esold MWh/yr 

HboileFs MBtu/yr 

6459 

0 

24599 

Cogen Heat Cap., kBtuh 0 CHESDIV/lANTDIV, NO COGEN 

B-4 

8 
COGEN ELEC. CAP., kW 840 HEAT/ELEC. RATIO, nd 1.375 

0.2 

1040 

1040 

1723 

840 

3944 

0 

1040 

2929 

840 

3944 

877 

1040 

41 34 

840 

3944 

1753 

1040 

5340 

840 

3944 

2630 

1125 

1723 

840 

3944 

0 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

Wheat, nd 0.208 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 1723 

ROB AC Elec Ld, kW 0 

0.4 

346 

0.3 

693 

693 

1 723 

693 

3254 

0 

693 

2929 

693 

3254 

877 

693 

41 34 

693 

3254 

1753 

693 

5340 

693 

3254 

2630 

778 

1 723 

778 

3653 

0 

0.1 

1386 

252 

1256 

252 

1184 

0 

242 

2053 

242 

1139 

61 5 

242 

2897 

262 

1229 

1229 

121 

1871 

196 

922 

922 

177 

706 

177 

830 

0 

379 

942 

379 

1779 

0 

379 

628 

306 

1437 

0 

346 

1723 

346 

1625 

0 

1386 

1723 

840 

3944 

0 

HEATING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

877 

2052 

0 

346 

2929 

346 

1625 

877 

346 

41 34 

373 

1753 

1753 

346 

5340 

560 

2630 

2630 

431 

1723 

431 

2024 

0 

364 

1539 

364 

1710 

461 

364 

1 026 

294 

1382 

307 

1386 

2929 

840 

3944 

877 

HEATING, MED 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1753 

2381 

0 

364 

21 73 

364 

1710 

921 

364 

1449 

294 

1382 

614 

1386 

41 34 

840 

3944 

1753 

HEATING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 

2630 

271 0 

0 

182 

1403 

182 

855 

691 

182 

936 

1 47 

691 

461 

1386 

5340 

840 

3944 

2630 

COOLING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.117 

0 

1 723 

85 

239 

530 

239 

1123 

0 

231 

353 

1 72 

809 

0 

1471 

1723 

840 

3944 

0 

COOLING, MED 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.117 

0 

1723 

169 

51 5 

1723 

51 5 

241 8 

0 

21 1 

706 

21 1 

991 

0 

862 265 1209 

1723 530 1723 

840 258 840 

3944 1213 3944 

0 0 0 

947 144 1294 

1723 263 1723 

840 128 840 

3944 601 3944 

0 0 0 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

248 

353 

1 72 

809 

0 

1555 

1723 

840 

3944 

0 

COOLING, HIGH 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.058 

0 

1723 

254 

600 122 

1723 350 

600 122 

281 7 573 

0 0 

WHOLE SYSTEM 

6459 

24599 

5585 

26224 

6912 

131 

1 75 

85 

401 

0 

1640 

1723 

840 

3944 

0 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

969 

94 

17687 

Cogen Heat Cap., kBtuh 3944.325 CHESDIV/LANTDIV, NO CHILLERS, NO PROC. HEAT 

B-5 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 

’ CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.208 

0 

1723 

0 

0.2 

877 

2052 

0 

0.2 

1753 

2381 

0 

0.1 

2630 

271 0 

0 

0.1 17 

982 

1723 

23 

0.117 

1292 

1723 

88 

0.058 

1292 

1723 

173 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

840 

0.4 

346 

346 

1723 

346 

1625 

0 

346 

2929 

346 

1625 

877 

346 

41 34 

373 

1753 

1753 

346 

5340 

560 

2630 

2630 

369 

2705 

369 

1733 

982 

434 

301 5 

434 

2038 

1292 

51 9 

301 5 

51 9 

2437 

1292 

HEAT/ELEC. RATIO, nd 

252 

1256 

252 

1184 

0 

242 

2053 

242 

1139 

61 5 

242 

2897 

262 

1229 

1229 

121 

1871 

196 

922 

922 

151 

1109 

151 

71 0 

403 

178 

1236 

178 

835 

530 

105 

61 3 

105 

495 

263 

WHOLE SYSTEM 

6271 

27586 

5472 

25697 

9899 

0.3 

693 

693 

1723 

693 

3254 

0 

693 

2929 

693 

3254 

877 

693 

41 34 

693 

3254 

1753 

693 

5340 

693 

3254 

2630 

71 6 

2705 

71 6 

3362 

982 

781 

301 5 

781 

3667 

1292 

866 

301 5 

840 

3944 

1292 

379 

942 

379 

1779 

0 

364 

1539 

364 

1710 

461 

364 

21 73 

364 

1710 

921 

1 82 

1403 

182 

855 

691 

220 

832 

220 

1034 

302 

240 

927 

240 

1128 

397 

132 

460 

128 

601 

197 

1.375 

0.2 

1040 

1040 

1723 

840 

3944 

0 

1040 

2929 

840 

3944 

877 

1040 

41 34 

840 

3944 

1753 

1040 

5340 

840 

3944 

2630 

1063 

2705 

840 

3944 

982 

1128 

301 5 

840 

3944 

1292 

1213 

301 5 

840 

3944 

1292 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

379 

628 

306 

1437 

0 

364 

1 026 

294 

1382 

307 

364 

1449 

294 

1382 

61 4 

1 82 

936 

147 

691 

461 

21 8 

554 

172 

809 

201 

231 

61 8 

172 

809 

265 

123 

306 

85 

401 

131 

893 

94 

17687 

0.1 

1386 

1386 

1723 

840 

3944 

0 

1386 

2929 

840 

3944 

877 

1386 

41 34 

840 

3944 

1753 

1386 

5340 

840 

3944 

2630 

1409 

2705 

840 

3944 

982 

1474 

301 5 

840 

3944 

1292 

1559 

301 5 

840 

3944 

1292 

Cogen Heat Cap., kBtuh 3944.325 CHESDIVAANTDIV, 1 CHILLEWCOGEN, NO PROC. HEAT 

B-6 

~~ ~ -~ 

253 

31 4 

153 

71 9 

0 

243 

513 - 

147 

691 

154 

243 

724 

1 47 

691 

307 

121 

468 

74 

346 

230 

144 

277 

86 

404 

101 

151 

309 

86 

404 

132 

79 

153 

43 

200 

66 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.208 

250 

1473 

0 

0.2 

1127 

1802 

0 

0.2 

2003 

21 31 

0 

0.1 

2880 

2460 

0 

0.1 17 

250 

1473 

85 

0.117 

250 

1473 

169 

0.058 

250 

1473 

254 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtulyr 

Hused kBtuh MBtu/yr 

840 

0.4 

346 

346 

1 723 

346 

1625 

250 

346 

2929 

346 

1625 

1127 

346 

41 34 

427 

2003 

2003 

346 

5340 

61 3 

2880 

2880 

431 

1723 

431 

2024 

250 

51 5 

1723 

51 5 

241 8 

250 

600 

1723 

600 

281 7 

250 

HEAT/ELEC.. RATIO, nd 

252 

1256 

252 

1184 

1 82 

242 

2053 

242 

1139 

790 

242 

2897 

299 

1404 

1404 

121 

1871 

21 5 

1009 

1009 

177 

706 

177 

830 

102 

21 1 

706 

21 1 

991 

1 02 

122 

350 

122 

573 

51 

WHOLE SYSTEM 

6459 

24599 

5641 

26487 

91 02 

0.3 

693 

693 

1723 

693 

3254 

250 

693 

2929 

693 

3254 

1127 

693 

41 34 

693 

3254 

2003 

693 

5340 

693 

3254 

2880 

778 

1723 

778 

3653 

250 

862 

1723 

840 

3944 

250 

947 

1723 

840 

3944 

250 

379 

942 

379 

1779 

137 

364 

1539 

364 

1710 

592 

364 

21 73 

364 

1710 

1053 

1 82 

1403 

182 

855 

757 

239 

530 

239 

1123 

77 

265 

530 

258 

1213 

77 

144 

263 

128 

601 

38 

1.375 

0.2 

1040 

1040 

1723 

840 

3944 

250 

1040 

2929 

840 

3944 

1127 

1040 

41 34 

840 

3944 

2003 

1040 

5340 

840 

3944 

2880 

1125 

1723 

840 

3944 

250 

1209 

1723 

840 

3944 

250 

1294 

1723 

840 

3944 

250 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

379 

628 

306 

1437 

91 

364 

1 026 

294 

1382 

395 

364 

1449 

294 

1382 

702 

182 

936 

147 

691 

505 

231 

353 

172 

809 

51 

248 

353 

1 72 

809 

51 

131 

175 

85 

401 

25 

969 

150 

15497 

0.1 

1386 

1386 

1723 

840 

3944 

250 

1386 

2929 

840 

3944 

1127 

1386 

41 34 

840 

3944 

2003 

1386 

5340 

840 

3944 

2880 

1471 

1723 

840 

3944 

250 

1555 

1723 

840 

3944 

250 

1640 

1723 

840 

3944 

250 

Cogen Heat Cap., kBtuh 3944.325 CHESDIV/LANTDIV, NO CHILLERS, 20% PROC. HEAT IN CgB 

253 

31 4 

153 

71 9 

46 

243 

51 3 

147 

69 1 

I 97 

243 

724 

1 47 

691 

351 

121 

468 

74 

346 

252 

151 

177 

86 

404 

26 

159 

I77 

86 

404 

26 

83 

88 

43 

200 

13 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.208 

250 

1473 

0 

0.2 

1127 

1802 

0 

0.2 

2003 

21 31 

0 

0.1 

2880 

2460 

0 

0.117 

1232 

1473 

23 

0.117 

1542 

1473 

88 

0.058 

1542 

1473 

173 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

840 

0.4 

346 

346 

1723 

346 

1625 

250 

346 

2929 

346 

1625 

1127 

346 

41 34 

427 

2003 

2003 

346 

5340 

61 3 

2880 

2880 

369 

2705 

369 

1733 

1232 

434 

301 5 

434 

2038 

1542 

51 9 

301 5 

51 9 

2437 

1542 

HEAT/ELEC. RATIO, nd 

WHOLE SYSTEM 

6271 

27586 

5528 

25960 

12089 

252 

1256 

252 

1184 

1 82 

242 

2053 

242 

1139 

790 

242 

2897 

299 

1404 

1404 

121 

1871 

21 5 

1009 

1009 

151 

1109 

151 

71 0 

505 

178 

1236 

178 

835 

632 

105 

61 3 

105 

495 

31 3 

0.3 

693 

693 

1723 

693 

3254 

250 

693 

2929 

693 

3254 

1127 

693 

41 34 

693 

3254 

2003 

693 

5340 

693 

3254 

2880 

71 6 

2705 

71 6 

3362 

1232 

781 

301 5 

781 

3667 

1542 

866 

301 5 

840 

3944 

1542 

379 

942 

379 

1779 

137 

364 

1539 

364 

1710 

592 

364 

21 73 

364 

1710 

1053 

1 82 

1403 

1 82 

855 

757 

220 

832 

220 

1034 

379 

240 

927 

240 

1128 

474 

132 

460 

128 

601 

235 

1.375 

0.2 

1040 

1040 

1723 

840 

3944 

250 

1040 

2929 

840 

3944 

1127 

1040 

41 34 

840 

3944 

2003 

1040 

5340 

840 

3944 

2880 

1063 

2705 

840 

3944 

1232 

1128 

301 5 

840 

3944 

1542 

1213 

301 5 

840 

3944 

1542 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

379 

628 

306 

1437 

91 

364 

1026 

294 

1382 

395 

364 

1449 

294 

1382 

702 

1 82 

936 

147 

691 

505 

21 8 

554 

172 

809 

253 

231 

61 8 

172 

809 

31 6 

123 

306 

85 

401 

157 

893 

150 

15497 

0.1 

1386 

1386 

1723 

840 

3944 

250 

1386 

2929 

840 

3944 

1127 

1386 

41 34 

840 

3944 

2003 

1386 

5340 

840 

3944 

2880 

1409 

2705 

840 

3944 

1232 

1474 

301 5 

840 

3944 

1542 

1559 

301 5 

840 

3944 

1542 

253 

31 4 

153 

719 

46 

243 

513 - 

147 

691 

197 

243 

724 

147 

691 

351 

121 

468 

74 

346 

252 

144 

277 

86 

404 

126 

151 

309 

86 

404 

158 

79 

153 

43 

200 

78 

Cogen Heat Cap., kBtuh 3944.325 CHESDIV/MNTDIV, 1 CHILLEWCOGEN, 20% PROC. HEAT IN CgB 

B-8 

____- ~ - -I_-- 
of Buildings: 

ieating Demand: 

...... :.6. Month Season 

Annual Energy: 

Annual Peak: 

:ooling Demand: 

$; Month Season 

Annual Energy: 

Annual Peak: 

Capacity 

Requirement 

Large Small Total for 

Building Building Site (1) Units Number of 

Diversity Factor = 50% Absorption 

7 9 10 ton 

i... i................ ii. ....... ............... ............... 

........... ..43g: 

364 

30.4 

20.4 

10.4 

.............. 

.................... ..... 

106 31 14 kBtuh 

8.9 260 tonswith 0 

8.9 na tons 1 

8.9 na tons 2 

I 0.4 I 8.9 I na I tons 31 

Electric Demand with EER 10.36 BtuNVh, DF= 50% 

There are 1.4 1.41 1.41 0.7 I months 

when P(AC)= 46.7 131.31 216.01 ' 300.61 01 

(in kw) 

46.7 46.7 46.7 67.31 31 

....................... Large Small Total DF= 50% ........................ 

84 :j i i li i,i i,i (iEQ.: MWh 

Peak Demand: 180 52 1577 kW for 7.1 months 

'otal Electric Demand DF= 0% 

months 

:i:.:. 

Ion-AC Electric: .................. ...... Annual Energy ;;,iiiii:yi$$$ 

There are 

when P(tot)= 

(in kw) 

46.7-71 

1382 2228 

46.7 53*6i 60141 145:oI :I 

1.4 1.4 1.4 0.7 

1577 1661 1746 1831 0 

1 577 1584 1668 1753 1 

1577 1577 1591 1675 2 I. 15771 1577 I 1577 I 15971 3 

ltility Demand with 9 120 kW cogenerators: 

There are 

when P(tot)= 

(in kw) 

- 

1.4 1.4 1.4 0.7 months 

497 581 666 751 01 an( 

I 497 I 497 I 497 I 49; 

1 See discussion of diversity in text. 

Demand Table - CHESDIVLANTDIV 

.. 

B-9 
NORTHDIV SPREADSHEET INPUTS 

. fy heat 

Shoulder 0.209 

Low 0.233 

Medium 0.233 

High 0.1 17 

ELECTRIC: Whole Base Non AC Avg. Load = 556 kW 

Low step = 0.5 X above = 278 kW 

2nd step = 1.0 X above = 556 kW 

3rd step = 1.5 X above = 834 kW 

4th step = 2.0 X above = 1112 kW 

CgB ht load ROB ht load ROB AC elec 

kBtuh kBtuh kW 

0 0 0 

1434 535 0 

2867 1072 0 

4301 1608 0 

PROCESS HEAT: If no process heat is obtained from cogeneration, then add the Hourly 

Average Process Heat for Whole Site, or 

1545 kBtuh 

to the "ROB Ht M" in the spreadsheet for all heating, cooling, and shoulder seasons. If 20% 

of process heat in cogenerated buildings is carried by cogenerators, then add 0.2 X Hourly 

Average Process Heat for 7 Buildings, or 

to all "CgB Ht Ld" inputs for all seasons, and reduce the "ROB Ht M" by the same amount, 

below what it was in the former case. 

0.2 X 1125 kBtuh = 225 kBtuh 

SHOULDER SEASON: Months in season = 2.5 

HEATING SEASON: Months in season = 7.0 

Low step multiplier = 6.667/months in season = 0.952 
NORTHDIV SPREADSHEET INPUTS 

Low 

Med 

High 

COOLING: Months in season = 2.5 

Low step multiplier = 6.667/months in season = 2.667 

fy cool All Base Avg Low Step ROB AC elec 

Cooling Load Multiplier kW 

kBtuh 

0.083 219 X 2.667 X 1/10.36 = 56 

0.083 21 9 X 2.667 X 2/10.36 = 11 3 

0.042 21 9 X 2.667 X 3/10.36 = 169 

- 

If no chillers, all base cooling met as "ROB AC Elec M" 

Low 

Med 

High 

7 bldgs ROB Met by CgB Notmet RoBAC 

cooling cooling chil-lers thermal by chlrs. elec. 

load. load kBtuh input kBtuh 

kBtu h kBtuh kBtuh kW 

424 160 424 652 160 15 

848 320 840 1292 328 32 

1272 480 840 1292 912 88 

If one chiller per cogenerator, the chillers meet as much of the cooling load as they can. Any 

excess, together with non-cogenerated building cooling load, is met electrically 

multiplier X [1,2 or 31 

multiplier X [1,2 or 31 

7 bldgs. cooling load = avg. 7 bldgs. cooling load X low step 

ROB cooling load = rest of site avg. cooling load X low step 

Met by chillers = lesser of 7 bldgs cooling load and 840 kBtuh 

CgB thermal input = met by chillers/O.65 

Not met by chillers = 7 bldgs cooling load - met by chillers + ROB cooling load 

ROB AC electric = Not met by chillers/l0.36 

B-11 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.209 

0 

1545 

0 

0.233 

1434 

2080 

0 

0.233 

2867 

261 7 

0 

0.1 17 

4301 

31 53 

0 

0.083 

0 

1545 

56 

0.083 

0 

1545 

113 

0.042 

0 

1545 

169 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Cogen Heat Cap., kBtuh 

0 

0.4 

278 

278 

1545 

0 

0 

0 

278 

3514 

0 

0 

0 

278 

5484 

0 

0 

0 

278 

7454 

0 

0 

0 

334 

1545 

0 

0 

0 

391 

1545 

0 

0 

0 

447 

1545 

0 

0 

0 

HEAT/ELEC. RATIO, nd 

204 

1131 

0 

0 

0 

227 

2869 

0 

0 

0 

227 

4477 

0 

0 

0 

114 

3056 

0 

0 

0 

97 

449 

0 

0 

0 

114 

449 

0 

0 

0 

66 

227 

0 

0 

0 

WHOLE SYSTEM 

5056 

31 649 

0 

0 

0 

0.3 

556 

556 

1545 

0 

0 

0 

556 

351 4 

0 

0 

0 

556 

5484 

0 

0 

0 

556 

7454 

0 

0 

0 

61 2 

1545 

0 

0 

0 

669 

1545 

0 

0 

0 

725 

1545 

0 

0 

0 

305 

849 

0 

0 

0 

340 

21 52 

0 

0 

0 

340 

3358 

0 

0 

0 

171 

2292 

0 

0 

0 

133 

337 

0 

0 

0 

146 

337 

0 

0 

0 

80 

171 

0 

0 

0 

1.375 

0.2 

834 

834 

1545 

0 

0 

0 

834 

351 4 

0 

0 

0 

834 

5484 

0 

0 

0 

834 

7454 

0 

0 

0 

890 

1545 

0 

0 

0 

947 

1545 

0 

0 

0 

1003 

1545 

0 

0 

0 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

0 NORTHDIV, NO COGEN 

B-12 

305 

566 

0 

0 

0 

340 

1434 

0 

0 

0 

340 

2239 

0 

0 

0 

171 

1528 

0 

0 

0 

129 

225 

0 

0 

0 

138 

225 

0 

0 

0 

74 

114 

0 

0 

0 

5056 

0 

31 649 

0.1 

1112 

1112 

1545 

0 

0 

0 

1112 

3514 

0 

0 

0 

1112 

5484 

0 

0 

0 

1112 

7454 

0 

0 

0 

1168 

1545 

0 

0 

0 

1225 

1545 

0 

0 

0 

1281 

1545 

0 

0 

0 

204 

283 

0 

0 

0- 

227 

717 - 

0 

0 

227 

1119 

0 

0 

0 

114 

764 

0 

0 

0 

85 

112 

0 

0 

0 

89 

112 

0 

0 

0 

47 

57 

0 

0- 

0 

-0 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.209 

0 

1545 

0 

0.233 

1434 

2080 

0 

0.233 

2867 

2617 

0 

0.1 17 

4301 

31 53 

0 

0.083 

0 

1545 

56 

0.083 

0 

1545 

113 

0.042 

0 

1545 

169 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Cogen Heat Cap., kBtuh 

840 

0.4 

278 

278 

1545 

278 

1305 

0 

278 

3514 

305 

1434 

1434 

278 

5484 

61 1 

2867 

2867 

278 

7454 

840 

3944 

3944 

334 

1545 

334 

1568 

0 

391 

1545 

391 

1836 

0 

447 

1545 

447 

2099 

0 

HEATAZLEC. RATIO, nd 

204 

1131 

204 

956 

0 

227 

2869 

249 

1171 

1171 

227 

4477 

498 

2341 

2341 

114 

3056 

344 

1617 

1617 

97 

449 

97 

456 

0 

114 

449 

114 

534 

0 

66 

227 

66 

309 

0 

WHOLE SYSTEM 

5056 

31 649 

541 0 

25405 

12821 

0.3 

556 

556 

1545 

556 

261 1 

0 

556 

3514 

556 

261 1 

1434 

556 

5484 

61 1 

2867 

2867 

556 

7454 

840 

3944 

3944 

612 

1545 

61 2 

2874 

0 

669 

1545 

669 

3141 

0 

725 

1545 

725 

3404 

0 

305 

849 

305 

1434 

0 

340 

21 52 

340 

1599 

878 

340 

3358 

374 

1756 

1756 

171 

2292 

258 

1213 

1213 

133 

337 

133 

627 

0 

146 

337 

146 

685 

0 

80 

171 

80 

376 

0 

1.375 

0.2 

834 

834 

1545 

834 

391 6 

0 

834 

351 4 

834 

391 6 

1434 

834 

5484 

834 

391 6 

2867 

834 

7454 

840 

3944 

3944 

890 

1545 

840 

3944 

0 

947 

1545 

840 

3944 

0 

1003 

1545 

840 

3944 

0 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

3944.325 NORTHDIV, NO CHILLERS, NO PROC. HEAT 

B-13 

305 

566 

305 

1434 

0 

340 

1434 

340 

1599 

585 

340 

2239 

340 

1599 

1170 

171 

1528 

1 72 

809 

809 

129 

225 

122 

574 

0 

138 

225 

122 

574 

0 

74 

114 

62 

290 

0 

292 

646 

18828 

0.1 

1112 

1112 

1545 

840 

3944 

0 

1112 

351 4 

840 

3944 

1434 

1112 

5484 

840 

3944 

2867 

1112 

7454 

840 

3944 

3944 

1168 

1545 

840 

3944 

0 

1225 

1545 

840 

3944 

0 

1281 

1545 

840 

3944 

0 

204 

283 

154 

722 

0 

227 

71 7 

171 

805 

293 

227 

1119 

171 

805 

585 

114 

764 

86 

404 

404 

85 

112 

61 

287 

0 

89 

112 

61 

287 

0 

47 

57 

31 

145 

0 
COGEN ELEC. CAP., kW 840 HEATIELEC. RATIO, nd 1.375 

0.1 

1112 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 0.209 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 1545 

ROB AC Elec Ld, kW 0 

0.4 

278 

0.3 

556 

0.2 

834 

278 

1545 

278 

1305 

0 

204 556 

1131 1545 

204 556 

956 2611 

0 0 

305 

849 

305 

1434 

0 

834 

1545 

834 

3916 

0 

305 

566 

305 

1434 

0 

1112 

1545 

840 

3944 

0 

204 

283 

154 

722 

0 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.233 

1434 

2080 

0 

278 

3514 

305 

1434 

1434 

. 227 556 

2869 3514 

249 556 

1171 261 1 

1171 1434 

340 

21 52 

340 

1599 

878 

834 

351 4 

834 

391 6 

1434 

340 

1434 

340 

1599 

585 

1112. 

351 4 

840 

3944 

1434 

227 

717 - 

171 

805 

293 

0.233 

2867 

261 7 

0 

278 

5484 

61 I 

2867 

2867 

227 556 

4477 5484 

498 61 1 

2341 2867 

2341 2867 

340 

3358 

374 

1756 

1756 

834 

5484 

834 

391 6 

2867 

340 

2239 

340 

1599 

1170 

1112 

5484 

840 

3944 

2867 

227 

1119 

171 

805 

585 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.117 

4301 

31 53 

0 

278 

7454 

840 

3944 

3944 

114 556 

3056 7454 

344 840 

1617 3944 

1617 3944 

171 

2292 

258 

1213 

1213 

834 

7454 

840 

3944 

'3944 

171 

1528 

172 

809 

809 

1112 

7454 

840 

3944 

3944 

114 

764 

86 

404 

404 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.083 

652 

1545 

15 

293 

21 97 

293 

1 376 

652 

85 571 

639 2197 

85 571 

400 2681 

I90 652 

125 

479 

125 

585 

142 

849 

21 97 

840 

3944 

652 

1127 

21 97 

840 

3944 

652 

82 

160 

61 

287 

47 

123 

31 9 

122 

574 

95 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.083 

1292 

1545 

32 

31 0 

2837 

31 0 

1456 

1292 

90 588 

825 2837 

90 588 

423 2761 

376 1292 

128 

61 9 

128 

602 

282 

866 

2837 

840 

3944 

1292 

126 

41 3 

122 

574 

188 

1144 

2837 

840 

3944 

1292 

83 

206 

61 

287 

94 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

44 

104 

31 

145 

48 

0.042 

1292 

1545 

88 

366 54 

2837 41 8 

366 54 

1719 253 

1292 190 

WHOLE SYSTEM 

4937 

33538 

5327 

2501 5 

1471 0 

644 

2837 

644 

3024 

1292 

71 

31 3 

71 

334 

143 

922 

2837 

840 

3944 

1292 

68 

209 

62 

290 

95 

256 

646 

18828 

1200 

2837 

840 

3944 

1292 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

Cogen Heat Cap., kBtuh 3944.325 NORTHDIV, 1 CHILLEWCOGEN, NO PROC. HEAT 

B-14 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.209 

224 

1321 

0 

0.233 

1658 

1856 

0 

0.233 

3091 

2393 

0 

0.1 17 

4525 

2929 

0 

0.083 

224 

1321 

56 

0.083 

224 

1321 

113 

0.042 

224 

1321 

169 

EACH BLOCK 

Edemand kW MWhIyr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Cogen Heat Cap., kBtuh 

840 

0.4 

278 

278 

1545 

278 

1305 

224 

278 

3514 

353 

1658 

1658 

278 

5484 

658 

3091 

3091 

278 

7454 

840 

3944 

3944 

334 

1545 

334 

1568 

224 

391 

1545 

391 

1836 

224 

447 

1545 

447 

2099 

224 

HEAT/ELEC. RATIO, nd 

204 

1131 

204 

956 

164 

227 

2869 

288 

1354 

1354 

227 

4477 

537 

2524 

2524 

114 

3056 

344 

1617 

1617 

97 

449 

97 

456 

65 

114 

449 

114 

534 

65 

66 

227 

66 

309 

33 

WHOLE SYSTEM 

5056 

31 649 

551 7 

25907 

14554 

0.3 

556 

556 

1545 

556 

261 1 

224 

556 

3514 

556 

261 1 

1658 

556 

5484 

658 

3091 

3091 

556 

7454 

840 

3944 

3944 

61 2 

1545 

612 

2874 

224 

669 

1545 

669 

31 41 

224 

725 

1545 

725 

3404 

224 

305 

849 

305 

1434 

123 

340 

21 52 

340 

1599 

1015 

340 

3358 

403 

1893 

1893 

171 

2292 

258 

1213 

1213 

133 

337 

133 

627 

49 

146 

337 

146 

685 

49 

80 

171 

80 

376 

25 

1.375 

0.2 

834 

834 

1545 

834 

391 6 

224 

834 

3514 

834 

3916 

1658 

834 

5484 

834 

3916 

3091 

834 

7454 

840 

3944 

3944 

890 

1 545 

840 

3944 

224 

947 

1545 

840 

3944 

224 

1003 

1545 

840 

3944 

224 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

305 

566 

305 

1434 

82 

340 

1434 

340 

1599 

677 

340 

2239 

340 

1599 

1262 

171 

1528 

172 

809 

809 

129 

225 

122 

574 

33 

138 

225 

122 

574 

33 

74 

114 

62 

290 

16 

292 

753 

17095 

3944.325 NORTHDIV, NO CHILLERS, 20% PROC. HEAT IN CgB 

B-15 

0.1 

1112 

1112 

1545 

840 

3944 

224 

1112 

351 4 

840 

3944 

1658 

1112 

5484 

840 

3944 

3091 

1112 

7454 

840 

3944 

3944 

1168 

1545 

840 

3944 

224 

1225 

1545 

840 

3944 

224 

1281 

1545 

840 

3944 

224 

204 

283 

154 

722 

41 

227 

71 7 

171 

805 

338 

227 

1119 

171 

805 

631 

114 

764 

86 

404 

404 

85 

112 

61 

287 

16 

89 

112 

61 

287 

16 

47 

57 

31 

145 

8 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

AI1 Base nonAC Elec Ld, kW 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.209 

224 

1321 

0 

0.233 

1658 

1856 

0 

0.233 

3091 

2393 

0 

0.117 

4525 

2929 

0 

0.083 

876 

1321 

15 

0.083 

1516 

1321 

32 

0.042 

1516 

1321 

88 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

840 

0.4 

278 

278 

1545 

278 

1305 

224 

278 

3514 

353 

1658 

1658 

278 

5484 

658 

3091 

3091 

278 

7454 

840 

3944 

3944 

293 

21 97 

293 

1376 

876 

31 0 

2837 

323 

1516 

1516 

366 

2837 

366 

1719 

1516 

HEAT/ELEC. RATIO, nd 

204 

1131 

204 

956 

164 

227 

2869 

288 

1354 

1354 

227 

4477 

537 

2524 

2524 

114 

3056 

344 

1617 

1617 

85 

639 

85 

400 

255 

90 

825 

94 

441 

441 

54 

41 8 

54 

253 

223 

WHOLE SYSTEM 

4937 

33538 

5438 

25536 

16443 

0.3 

556 

556 

1545 

556 

261 1 

224 

556 

3514 

556 

261 1 

1658 

556 

5484 

658 

3091 

3091 

556 

7454 

840 

3944 

3944 

571 

21 97 

571 

2681 

876 

588 

2837 

588 

2761 

1516 

644 

2837 

644 

3024 

1516 

305 

849 

305 

1434 

123 

340 

21 52 

340 

1599 

1015 

340 

3358 

403 

1893 

1893 

171 

2292 

258 

1213 

1213 

125 

479 

125 

585 

191 

128 

61 9 

128 

602 

331 

71 

31 3 

71 

334 

167 

1.375 

0.2 

834 

834 

1545 

834 

391 6 

224 

834 

3514 

834 

391 6 

1658 

834 

5484 

834 

391 6 

3091 

834 

7454 

840 

3944 

3944 

849 

21 97 

840 

3944 

876 

866 

2837 

840 

3944 

1516 

922 

2837 

840 

3944 

1516 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

305 

566 

305 

1434 

82 

340 

1434 

340 

1599 

677 

340 

2239 

340 

1599 

1262 

171 

1528 

1 72 

809 

809 

123 

31 9 

122 

574 

127 

126 

41 3 

122 

574 

220 

68 

209 

62 

290 

112 

256 

757 

17095 

0.1 

1112 

1112 

1545 

840 

3944 

224 

1112 

3514 

840 

3944 

1658 

1112 

5484 

840 

3944 

3091 

1112 

7454 

840 

3944 

3944 

1127 

21 97 

840 

3944 

876 

1144 

2837 

840 

3944 

1516 

1200 

2837 

840 

3944 

1516 

204 

283 

154 

722 

41 

227 

717 - 171 

805 

338 

227 

1119 

171 

805 

631 

114 

764 

86 

404 

404 

82 

160 

61 

287 

64 

83 

206 

61 

287 

110 

44 

104 

31 

145 

56 

Cogen Heat Cap., kBtuh 3944.325 NORTHDIV, 1 CHILLEWCOGEN, 20% PROC. HEAT IN CgB 

B-16 
Large 

Building 

.... 

::iZ Month Season ........................ 

Annual Energy: z;iz;:;;x;e$g 

Annual Peak: 820 

Cooling Demand: Diversity 

............... 

2jgi Month Season ........................ ............... Annual Energy: $iii ii:ii ,;i.1.99 

Annual Peak: 242 ........................ 

Capacity 20.2 

Requirement 10.2 

0.2 

0.0 5.9 naltons 31 

# of Buildings: 

Heating Demand: 

7 

Diversity 

..................... 

G~~!!$~f~rjjf 

...................... 2072 

173 

na 

na 

58 

71 

5.9 

5.9 

5.9 

MBtu 

kBtuh 

tons with 

tons 

tons 

31 .I 31 .I 31.1 31.11 31 

Non-AC Electric: Total DF= 50% .......... ............. Law. Small ......................... 

Annual Energy i::.;;;;;;;i;%i,5.Q~] 147 !iii!f?iiiig&g;$i MWh ....................... 

dumber of 

10 ton 

Absorption 

>hillers per 

:ogen 

I 

unit 

Peak Demand: 1 1451 42 I 1266 I kW for 8.5 months 

There are 1 1 1 0.5 months 

Total Electric Demand DF= OW 

I (in kw) 1266 1266 1300 1357 1 

when P(tot)= 1266 1322 1378 1434 0 

1266 1266 1266 1279 2 

1266 1266 1266 1266 3 

Utility Demand with 9 120 kW cogenerators: 

There are 1 1 1 0.5 months 

when P(tot)= 186 242 298 354 0 and 

186 186 186 199 2 with 

(in kw) 186 186 220 277 1 5 

0 

1 

2 

There are 1 .o 1 .o 1 .o 0.5 

when P(AC)= 31 .I 87.4 143.7 200.0 

(in kw) 31 .I 31 .I 65.9 122.2 

31 .I 31 .I 31.1 44.4 

months 

0 

1 

2 

I 1861 1861 1861 I861 31 18E 

I See discussion of diversity in text. 

Demand Table - NORTHDIV 
SOUTHDIV SPREADSHEET INPUTS 

fy heat CgB ht load ROB ht load ROB AC elec 

kBtuh kBtuh kW 

Shoulder 0.208 0 0 0 

Low 0.1 17 739 276 0 

Medium 0.1 17 1478 552 0 

High 0.058 221 7 829 0 

ELECTRIC: Whole Base Non AC Avg. Load = 684 kW 

Low step = 0.5 X above = 342 kW 

2nd step = 1.0 X above = 684 kW 

3rd step = 1.5 X above = 1026 kW 

4th step = 2.0 X above = 1368 kW 

PROCESS HEAT: If no process heat is obtained from cogeneration, then add the Hourly 

Average Process Heat for Whole Site, or 

1372 kBtuh 

to the "ROB Ht M" in the spreadsheet for all heating, cooling, and shoulder seasons. If 20% 

of process heat in cogenerated buildings is carried by cogenerators, then add 0.2 X Hourly 

Average Process Heat for 7 Buildings, or 

to all "CgB Ht Ld" inputs for all seasons, and reduce the "ROB Ht M" by the same amount, 

below what it was in the former case. 

0.2 x 999 kBtuh = 200 kBtuh 

SHOULDER SEASON: Months in season = 2.5 

HEATING SEASON: Months in season = 3.5 

Low step multiplier = 6.667!months in season = 1.905 

B-18 
SOUTHDIV SPREADSHEET INPUTS 

Low 

Med 

High 

COOLING: Months in season = 6.0 

Low step multiplier = 6.667/months in season = 1.111 

fy cool All Base Avg Low Step ROB AC elec 

Cooling Load Multiplier kW 

kBtuh 

0.200 953 x 1.111 X 1/10.36 = 102 

0.200 953 x 1.111 X 2/10.36 = 204 

0.100 953 x 1.111 X 3/10.36 = 307 

If no chillers, all base cooling met as "ROB AC Elec M" 

1292 

1292 

1278 123 

2337 226 

If one chiller per cogenerator, the chillers meet as much of the cooling load as they can. Any 

excess, together with non-cogenerated building cooling load, is met electrically 

kBtuh kBtuh 

High I 2310 I 867 

Met by 

chil-lers 

kBtuh 

770 

840 

840 

CgB 

thermal 

input 

kBtuh 

1185 

kBtuh 

7 bldgs. cooling load = avg. 7 bldgs. cooling load X low step 

ROB cooling load = rest of site avg. cooling load X low step 

Met by chillers = lesser of 7 bldgs cooling load and 840 kBtuh 

CgB thermal input = met by chillerdO.65 

Not met by chillers = 7 bldgs cooling load - met by chillers + ROB cooling load 

ROB AC electric = Not met by chillers/lO.36 

multiplier X [1,2 or 31 

multiplier X [1,2 or 31 

B-19 
If two chillers per cogenerator, the chillers again meet as much of the cooling load as they can, 

but now the limit is 2 X 840 = 1680 KBtuh of cooling load. 

1680 

Low 

2585 

Med 

High 

7 bldgs 

cooling 

load 

kBtuh 

770 

1540 

231 0 

ROB 

cooling 

load 

kBtu h 

289 

578 

867 

kBtuh 

Not met 

by chlrs. 

kBtuh 

289 

578 

ROB AC 

elec. 

kW 

28 

56 

144 
COGEN ELEC. CAP., kW 0 HEATIELEC. RATIO, nd 1.375 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

0.4 

342 

0.3 

684 

684 

1372 

0 

0 

0 

684 

2387 

0 

0 

0 

684 

3402 

0 

0 

0 

684 

441 8 

0 

0 

0 

786 

I 372 

0 

0 

0 

888 

1372 

0 

0 

0 

991 

1 372 

0 

0 

0 

0.2 

1 026 

0.1 

1368 

SHOULDER 

N heat, nd 

CgB Ht id, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

249 

1000 

0 

0 

0 

140 

979 

0 

0 

0 

140 

1395 

0 

0 

0 

70 

898 

0 

0 

0 

31 1 

961 

0 

0 

0 

383 

961 

0 

0 

0 

227 

481 

0 

0 

0 

374 

750 

0 

0 

0 

21 0 

734 

0 

0 

0 

21 0 

1046 

0 

0 

.O 

104 

673 

0 

0 

0 

41 3 

721 

0 

0 

0 

467 

721 

0 

0 

0 

260 

361 

0 

0 

0 

374 

500 

0 

0 

0 

21 0 

489 

0 

0 

0 

21 0 

697 

0 

0 

0 

1 04 

449 

0 

0 

0 

395 

481 

0 

0 

0 

431 

481 

0 

0 

0 

234 

240 

0 

0 

0 

6797 

0 

16687 

249 

250 

0 

0 

0 

0.208 

0 

1372 

0 

342 

1 372 

0 

0 

0 

1026 

1372 

0 

0 

0 

1368 

1372 

0 

0 

0 

HEATING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.117 

739 

1648 

0 

342 

2387 

0 

0 

0 

1026 

2387 

0 

0 

0 

1368 

2387 

0 

0 

0 

140 

245 

0 

0 

0 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 17 

1478 

1924 

0 

342 

3402 

0 

0 

0 

1 026 

3402 

0 

0 

0 

1368 

3402 

0 

0 

0 

140 

349 

0 

0 

0 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.058 

221 7 

2201 

0 

342 

441 8 

0 

0 

0 

1 026 

441 8 

0 

0 

0 

1368 

441 8 

0 

0 

0 

70 

224 

0 

0 

0 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

0 

1372 

102 

444 

1372 

0 

0 

0 

1470 

1372 

0 

0 

0 

258 

240 

0 

0 

0 

1128 

1372 

0 

0 

0 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

0 

1372 

204 

546 

1372 

0 

0 

0 

1230 

1372 

0 

0 

0 

1333 

1372 

0 

0 

0 

1572 

1372 

0 

0 

0 

275 

240 

0 

0 

0 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 

0 

1 372 

307 

649 

1 372 

0 

0 

0 

1675 

1372 

0 

0 

0 

147 

120 

0 

0 

0 

EACH BLOCK WHOLE SYSTEM 

Edemand kW MWh/yr 6797 

Hdemand kBtuh MBtu/yr 16687 

Ecogen kW MWh/yr 0 

Hcogen kBtuh MBtu/yr 0 

Hused kBtuh MBtu/yr 0 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

Cogen Heat Cap., kBtuh 0 SOUTHDIV, NO COGEN 

B-21 
COGEN ELEC. CAP., kW 840 HEATIELEC. RATIO, nd 1.375 

0.3 

684 

684 

1372 

684 

321 2 

0 

684 

2387 

684 

321 2 

739 

684 

3402 

684 

321 2 

1478 

684 

441 8 

684 

321 2 

221 7 

786 

1372 

786 

3691 

0 

888 

1372 

840 

3944 

0 

991 

1372 

840 

3944 

0 

0.1 

1368 

0.2 

1 026 

frac. of Year Elec. nd 

AI1 Base nonAC Elec Ld, kW 

0.4 

342 

SHOULDER 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

249 

1000 

249 

1170 

0 

374 

750 

374 

1756 

0 

374 

500 

306 

1437 

0 

249 

250 

153 

71 9 

0 

342 

1372 

342 

1606 

0 

1026 

1 372 

840 

3944 

0 

1368 

1 372 

840 

3944 

0 

0.208 

0 

1 372 

0 

HEATING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec id, kW 

0.117 

739 

1648 

0 

342 

2387 

342 

1606 

739 

140 

979 

140 

658 

303 

21 0 

734 

21 0 

988 

227 

1026 

2387 

840 

3944 

739 

21 0 

489 

1 72 

809 

151 

1368 

2387 

840 

3944 

739 

140 

245 - 

86 

404 

76 

HEATING, MED 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

1 026 

3402 

840 

3944 

1478 

21 0 

697 

1 72 

809 

303 

1368 

3402 

840 

3944 

1478 

0.1 17 

1478 

1 924 

0 

342 

3402 

342 

1606 

1478 

140 

1395 

140 

658 

606 

21 0 

1046 

21 0 

988 

454 

140 

349 

86 

404 

151 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

70 

898 

96 

451 

451 

104 

673 

104 

490 

338 

1 026 

441 8 

840 

3944 

2217 

104 

449 

85 

401 

225 

1368 

441 8 

840 

3944 

221 7 

70 

224 

43 

200 

113 

0.058 

221 7 

2201 

0 

342 

441 8 

472 

221 7 

221 7 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

0 

1372 

1 02 

258 

240 

147 

691 

0 

444 

1372 

444 

2085 

0 

31 1 

961 

31 1 

1461 

0 

41 3 

721 

41 3 

1940 

0 

1128 

1372 

840 

3944 

0 

395 

481 

294 

1382 

0 

1470 

1372 

840 

3944 

0 

COOLING, MED 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

0 

1372 

204 

1572 

1372 

840 

3944 

0 

275 

240 

147 

691 

0 

546 

1372 

546 

2564 

0 

383 

961 

383 

1797 

0 

467 

721 

442 

2073 

0 

1230 

1372 

840 

3944 

0 

431 

481 

294 

1382 

0 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

649 

1372 

649 

3047 

0 

227 

481 

227 

1068 

0 

260 

361 

221 

1037 

0 

1333 

1372 

840 

3944 

0 

234 

240 

147 

691 

0 

1675 

1372 

840 

3944 

0 

147 

120 

74 

346 

0 

0.1 

0 

1372 

307 

EACH BLOCK WHOLE SYSTEM 

Edemand kW MWh/yr 6797 

Hdemand kBtuh MBtu/yr 16687 

Ecogen kW MWh/yr 5729 

Hcogen kBtuh MBtu/yr 26899 

Hused kBtuh MBtu/yr 3399 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

1095 

26 

13289 

Cogen Heat Cap., kBtuh 3944.325 SOUTHDIV, NO CHILLERS, NO PROC. HEAT 

B-22 
COGEN ELEC. CAP., kW 840 HEAT/ELEC. RATIO, nd I .375 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

Wheat, nd 0.208 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 1372 

ROB AC Elec Ld, kW 0 

0.4 

342 

0.3 

684 

0.2 

1 026 

0.1 

1368 

249 

1000 

249 

1170 

0 

374 

500 

306 

1437 

0 

249 

250 

153 

71 9 

0 

342 

1372 

342 

1606 

0 

684 

1372 

684 

321 2 

0 

374 1026 

750 1 372 

374 840 

1756 3944 

0 0 

1368 

1372 

840 

3944 

0 

HEATING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.117 

739 

1648 

0 

342 

2387 

342 

1606 

739 

140 

979 

140 

658 

303 

684 

2387 

684 

321 2 

739 

21 0 1 026 

734 2387 

21 0 840 

988 3944 

227 739 

21 0 

489 

172 

809 

151 

1368 

2387 

840 

3944 

739 

140 

245 

86 

404 

76 

HEATING, MED 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

342 

3402 

342 

1606 

1478 

0.117 

1478 

1924 

0 

140 

1395 

140 

658 

606 

684 

3402 

684 

321 2 

1478 

21 0 1 026 

1046 3402 

21 0 840 

988 3944 

454 1478 

21 0 

697 

I 72 

809 

303 

1368 

3402 

840 

3944 

1478 

140 

349 

86 

404 

151 

HEATING, HIGH 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.058 

221 7 

2201 

0 

342 

441 8 

472 

221 7 

221 7 

1 04 1 026 

673 441 8 

104 840 

490 3944 

338 221 7 

70 

898 

96 

451 

451 

684 

441 8 

684 

321 2 

221 7 

104 

449 

85 

401 

225 

1368 

441 8 

840 

3944 

221 7 

70 

224 

43 

200 

113 

COOLING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1185 

1372 

28 

370 

2557 

370 

1737 

1185 

259 

1792 

259 

1218 

830 

71 2 

2557 

71 2 

3343 

1185 

374 1054 

1344 2557 

374 840 

1757 3944 

623 1185 

369 

896 

294 

1382 

41 5 

1396 

2557 

840 

3944 

1185 

245 

448 

147 

691 

208 

COOLING, MED 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld. kW 

0.2 

1292 

1372 

123 

465 326 

2664 1867 

465 326 

21 83 1530 

1292 905 

568 199 

2664 933 

568 199 

2667 935 

1292 453 

WHOLE SYSTEM 

6454 

221 59 

5535 

25992 

8870 

807 

2664 

807 

3789 

1292 

424 1149 

1400 2664 

424 840 

1992 3944 

679 1292 

403 

933 

294 

1382 

453 

1491 

2664 

840 

3944 

1292 

261 

467 

147 

691 

226 

COOLING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 

1292 

1372 

226 

91 0 

2664 

840 

3944 

1292 

239 1252 

700 2664 

221 840 

1037 3944 

340 1292 

21 9 

467 

1 47 

691 

226 

1594 

2664 

840 

3944 

1292 

140 

233 

74 

346 

113 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

946 

26 

13289 

Cogen Heat Cap., kBtuh 3944.325 SOUTHDIV, 1 CHILLEWCOGEN, NO PROC. HEAT 

B-23 
, COGEN ELEC. CAP., kW 840 HEAT/ELEC. RATIO, nd 1.375 

0.1 

1368 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

Wheat, nd 0.208 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 1372 

ROB AC Elec Ld, kW 0 

0.4 

342 

0.3 

684 

0.2 

1 026 

342 

I 372 

342 

1606 

0 

249 684 

1000 1 372 

249 684 

1170 321 2 

0 0 

374 

750 

374 

1756 

0 

1 026 

1 372 

840 

3944 

0 

374 

500 

306 

1437 

0 

1368 

1372 

840 

3944 

0 

249 

250 

153 

719 . 

0 

HEATING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.117 

739 

1648 

0 

1026 

2387 

840 

3944 

739 

21 0 

489 

172 

809 

151 

1368 

2387 

840 

3944 

739 

140 

245 - 

86 

404 

76 

342 

2387 

342 

1606 

739 

140 684 

979 2387 

140 684 

658 321 2 

303 739 

21 0 

734 

21 0 

988 

227 

HEATING, MED 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 17 

1478 

1 924 

0 

342 

3402 

342 

1606 

1478 

140 684 

1395 3402 

140 684 

658 321 2 

606 1478 

21 0 

1046 

21 0 

988 

454 

1 026 

3402 

840 

3944 

1478 

21 0 

697 

1 72 

809 

303 

1368 

3402 

840 

3944 

1478 

140 

349 

86 

404 

151 

HEATING, HIGH 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

1368 

441 8 

840 

3944 

221 7 

70 

224 

43 

200 

113 

0.058 

221 7 

2201 

0 

342 

441 8 

472 

221 7 

221 7 

70 684 

898 441 8 

96 684 

451 321 2 

451 221 7 

104 

673 

104 

490 

338 

1 026 

441 8 

840 

3944 

221 7 

104 

449 

85 

401 

225 

COOLING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1185 

1372 

28 

259 71 2 

1792 2557 

259 71 2 

1218 3343 

830 1185 

374 

1344 

374 

1757 

623 

1054 

2557 

840 

3944 

1185 

369 

896 

294 

1382 

41 5 

1396 

2557 

840 

3944 

1185 

245 

448 

147 

691 

208 

370 

2557 

370 

1737 

1185 

COOLING, MED 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

2369 

1372 

56 

398 

3741 

505 

2369 

2369 

279 740 

2622 3741 

354 740 

1660 3475 

1660 2369 

389 

1966 

389 

I 826 

1245 

1082 

3741 

840 

3944 

2369 

379 

1311 

294 

1382 

830 

1 424 

3741 

840 

3944 

2369 

249 

655 

147 

691 

41 5 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

205 

693 

147 

691 

453 

1512 

3957 

840 

3944 . 2585 

132 

347 

74 

346 

226 

0.1 

2585 

1372 

144 

486 170 

3957 1387 

551 193 

2585 906 

2585 906 

WHOLE SYSTEM 

6265 

251 78 

551 8 

2591 3 

11890 

828 

3957 

828 

3888 

2585 

21 8 

1040 

21 8 

1 022 

679 

1170 

3957 

840 

3944 

2585 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Ebought MWhlyr 

Esold MWh/yr 

Hboilers MBtu/yr 

870 

1 24 

13289 

Cogen Heat Cap., kBtuh 3944.325 SOUTHDIV, 2 CHILLERWCOGEN, NO PROC. HEAT 

B-24 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.208 

200 

1172 

0 

0.117 

939 

1448 

0 

0.117 

1678 

1724 

0 

0.058 

241 7 

2001 

0 

0.2 

200 

1172 

1 02 

0.2 

200 

1172 

204 

0.1 

200 

1172 

307 

EACH BLOCK 

Edernand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Cogen Heat Cap., kBtuh 

840 

0.4 

342 

342 

1372 

342 

1606 

200 

342 

2387 

342 

1606 

939 

342 

3402 

357 

1678 

1678 

342 

441 8 

51 5 

241 7 

241 7 

444 

1372 

444 

2085 

200 

546 

1372 

546 

2564 

200 

649 

1 372 

649 

3047 

200 

HEAT/ELEC. RATIO, nd 

249 

1000 

249 

1170 

146 

140 

979 

140 

658 

385 

140 

1395 

1 47 

688 

688 

70 

898 

105 

491 

491 

31 1 

961 

31 1 

1461 

140 

383 

961 

383 

1797 

140 

227 

481 

227 

1068 

70 

WHOLE SYSTEM 

6797 

16687 

5743 

26969 

51 51 

0.3 

684 

684 

1372 

684 

321 2 

200 

684 

2387 

684 

3212 

939 

684 

3402 

684 

321 2 

1678 

684 

441 8 

684 

321 2 

241 7 

786 

1372 

786 

3691 

200 

888 

1372 

840 

3944 

200 

991 

1372 

840 

3944 

200 

374 

750 

374 

1756 

109 

21 0 

734 

21 0 

988 

289 

21 0 

1046 

21 0 

988 

51 6 

104 

673 

104 

490 

368 

41 3 

721 

41 3 

1940 

105 

467 

721 

442 

2073 

105 

260 

361 

221 

1037 

53 

1.375 

0.2 

1026 

1 026 

1372 

840 

3944 

200 

1 026 

2387 

840 

3944 

939 

1 026 

3402 

840 

3944 

1678 

1 026 

441 8 

840 

3944 

241 7 

1128 

1372 

840 

3944 

200 

1230 

1 372 

840 

3944 

200 

1333 

1 372 

840 

3944 

200 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

374 

500 

306 

1437 

73 

21 0 

489 

1 72 

809 

192 

21 0 

697 

1 72 

809 

344 

104 

449 

85 

401 

246 

395 

481 

294 

1382 

70 

431 

481 

294 

1382 

70 

234 

240 

147 

691 

35 

1095 

41 

1 1537 

3944.325 SOUTHDIV, NO CHILLERS, 20% PROC. HEAT IN CgB 

B-25 

0.1 

1368 

1368 

I 372 

840 

3944 

200 

1368 

2387 

840 

3944 

939 

1368 

3402 

840 

3944 

1678 

1368 

441 8 

840 

3944 

241 7 

1470 

1372 

840 

3944 

200 

1572 

1372 

840 

3944 

200 

1675 

1 372 

840 

3944 

200 

249 

250 

153 

71 9 

36 

140 

245 

86 

404 

96 

140 

349 

86 

404 

1 72 

70 

224 

43 

200 

123 

258 

240 

147 

691 

35 

275 

240 

147 

691 

35 

147 

120 

74 

346 

18 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.208 

200 

1172 

0 

0.117 

939 

1448 

0 

0.117 

1678 

1724 

0 

0.058 

241 7 

2001 

0 

0.2 

1385 

1172 

28 

0.2 

1492 

1172 

123 

0.1 

1492 

1172 

226 

EACH BLOCK 

Edernand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

840 

0.4 

342 

342 

1372 

342 

1606 

200 

342 

2387 

342 

1606 

939 

342 

3402 

357 

1678 

1678 

342 

441 8 

51 5 

241 7 

241 7 

370 

2557 

370 

1737 

1385 

465 

2664 

465 

21 83 

1492 

568 

2664 

568 

2667 

1492 

HEAT/ELEC. RATIO, nd 

249 

1000 

249 

1170 

146 

. 140 

979 

140 

658 

385 

140 

1395 

147 

688 

688 

70 

898 

105 

491 

49 1 

259 

1792 

259 

1218 

971 

326 

1867 

326 

1530 

1046 

I99 

933 

199 

935 

523 

WHOLE SYSTEM 

6454 

221 59 

5550 

26062 

10622 

0.3 

684 

684 

1372 

684 

321 2 

200 

684 

2387 

684 

321 2 

939 

684 

3402 

684 

321 2 

1678 

684 

441 8 

684 

321 2 

241 7 

71 2 

2557 

71 2 

3343 

1385 

807 

2664 

807 

3789 

1492 

91 0 

2664 

840 

3944 

1492 

374 

750 

374 

1756 

109 

21 0 

734 

21 0 

988 

289 

21 0 

1046 

21 0 

988 

51 6 

104 

673 

1 04 

490 

368 

374 

1344 

374 

1757 

728 

424 

1400 

424 

1992 

784 

239 

700 

221 

1037 

392 

1.375 

0.2 

1 026 

1 026 

1372 

840 

3944 

200 

1 026 

2387 

840 

3944 

939 

1026 

3402 

840 

3944 

1678 

1 026 

441 8 

840 

3944 

241 7 

1054 

2557 

840 

3944 

1385 

1149 

2664 

840 

3944 

1492 

1252 

2664 

840 

3944 

1492 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

374 

500 

306 

1437 

73 

21 0 

489 

1 72 

809 

1 92 

21 0 

697 

1 72 

809 

344 

104 

449 

85 

401 

246 

369 

896 

294 

1382 

485 

403 

933 

294 

1382 

523 

21 9 

467 

1 47 

691 

261 

946 

41 

1 1537 

0.1 

1368 

1368 

1 372 

840 

3944 

200 

1368 

2387 

840 

3944 

939 

1368 

3402 

840 

3944 

1678 

1368 

441 8 

840 

3944 

241 7 

1396 

2557 

840 

3944 

1385 

1491 

2664 

840 

3944 

1492 

1594 

2664 

840 

3944 

1492 

Cogen Heat Cap., kBtuh 3944.325 SOUTHDIV, 1 CHILLEWCOGEN, 20% PROC. HEAT IN CgB 

B-2 6 

249 

250 

153 

719 . 

36 

140 

245 = 

86 

404 

96 

140 

349 

86 

404 

1 72 

70 

224 

43 

200 

123 

245 

448 

147 

691 

243 

261 

467 

1 47 

691 

261 

140 

233 

74 

346 

131 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld. kW 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.208 

200 

1172 

0 

0.117 

939 

1448 

0 

0.117 

1678 

1724 

0 

0.058 

241 7 

2001 

0 

0.2 

1385 

1172 

28 

0.2 

2569 

1172 

56 

0.1 

2785 

1172 

144 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

840 

0.4 

342 

342 

1372 

342 

1606 

200 

342 

2387 

342 

1606 

939 

342 

3402 

357 

1678 

1678 

342 

441 8 

51 5 

241 7 

241 7 

370 

2557 

370 

1737 

1385 

398 

3741 

547 

2569 

2569 

486 

3957 

593 

2785 

2785 

HEAT/ELEC. RATIO, nd 

249 

1000 

249 

1170 

146 

140 

979 

140 

658 

385 

140 

1395 

147 

688 

688 

70 

898 

105 

491 

491 

259 

1792 

259 

1218 

971 

279 

2622 

383 

1800 

1800 

170 

1387 

208 

976 

976 

WHOLE SYSTEM 

6265 

251 78 

5578 

261 93 

13642 

0.3 

684 

684 

1372 

684 

321 2 

200 

684 

2387 

684 

321 2 

939 

684 

3402 

684 

321 2 

1678 

684 

441 8 

684 

3212 

241 7 

71 2 

2557 

71 2 

3343 

1385 

740 

3741 

740 

3475 

2569 

828 

3957 

828 

3888 

2785 

374 

750 

374 

1756 

109 

21 0 

734 

21 0 

988 

289 

21 0 

1046 

21 0 

988 

51 6 

104 

673 

104 

490 

368 

374 

1344 

374 

1757 

728 

389 

2966 

389 

1 826 

1350 

21 8 

1040 

21 8 

1022 

732 

1.375 

0.2 

1 026 

1 026 

1372 

840 

3944 

200 

1 026 

2387 

840 

3944 

939 

1 026 

3402 

840 

3944 

1678 

1 026 

441 8 

840 

3944 

241 7 

1054 

2557 

840 

3944 

1385 

1082 

3741 

840 

3944 

2569 

1170 

3957 

840 

3944 

2785 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

374 

500 

306 

1437 

73 

21 0 

489 

172 

809 

192 

21 0 

697 

1 72 

809 

344 

104 

449 

85 

401 

246 

369 

896 

294 

1382 

485 

379 

1311 

294 

1382 

900 

205 

693 

147 

691 

488 

870 

183 

1 1537 

0.1 

1368 

1368 

1372 

840 

3944 

200 

1368 

2387 

840 

3944 

939 

1368 

3402 

840 

3944 

1678 

1368 

441 8 

840 

3944 

241 7 

1396 

2557 

840 

3944 

1385 

1424 

3741 

840 

3944 

2569 

1512 

3957 

840 

3944 

2785 

Cogen Heat Cap., kBtuh 3944.325 SOUTHDIV, 2 CHILLERSKOGEN, 20% PROC. HEAT IN CgB 

249 

250 

153 

71 9 

36 

140 

245 

86 

404 

96 

140 

349 

86 

404 

1 72 

70 

224 

43 

200 

123 

245 

448 

147 

691 

243 

249 

655 

1 47 

691 

450 

132 

347 

74 

346 

244 
Large Small Total for 

Building Building Site (1) Units 

# of Buildings: 7 9 

Heating ...... Demand: Diversity ,Factor = . 50% 

3i% Month Season 

? Month Season 

Annual Energy: : 

Annual Peak: 440 

Capacity 

Requirement 

36.7 10.7 313 tons with 

26.7 10.7 na tons 

16.7 10.7 na tons 

qumber of 

10 ton 

4bsorption 

:hillers per 

0 

1 

2 

6.7 I 10.7 I na I tons - 3 

Electric Demand with EER 10.36 BtuNVh, DF= 50% 

There are I 2.4 I 2.4 I 2.4 I 1.21 months 

when P(AC)=I 56.41 158.51 260.71 362.91 01 

(in kw, I 56.41 80.81 182.91 285.1 1 

56.4 56.4 105.2 207.3 

56.4 56.4 56.4 129.51 31 

Law? Small ......................... Total DF= 50% Non-AC Electric: .::::.:::y::*:,.., ,:..:.: Annual Energy ~~~~~q~~g~~~: 181 .[~~~~~i~~&~~@~ .:::::::::::: .............. MWh 

Peak Demand: 178 52 1556 kW for 3.6 months 

There are 2.4 2.4 2.4 1.2 months 

Total Electric Demand DF= 0% 

when P(tot)= 1556 1658 1760 1863 0 

(in kw) 1556 1580 1683 1785 1 

1556 1556 1605 1707 2 

1556 1556 1556 1629 3 

Utility Demand with 120 kW cogenerators: 

There are 1 2.:i 2-11 

I!! when P(tot)= 476 578 680 

(in kw) 476 500 603 

476 476 

- 

5 

I 4761 476 I 476 

1 See discussion of diversity in text. 

Demand Table - SOUTH1 

with 

549 47E 

B-28 
WESTDIV SPREADSHEET INPUTS 

Shoulder 

Low 

ELECTRIC: Whole Base Non AC Avg. LoaG = 538 kW 

Low step = 0.5 X above = 269 kW 

2nd step = 1.0 X above = 538 kW 

3rd step = 1.5 X above = 807 kW 

4th step = 2.0 X above = 1076 kW 

fy heat CgB ht load ROB ht load ROB AC elec 

kBtuh kBtu h kW 

0.333 0 0 0 

0.200 538 201 0 

PROCESS HEAT: If no process heat is obtained from cogeneration, then add the Hourly 

Average Process Heat for Whole Site, or 

1600 kBtuh 

to the "ROB Ht Ld" in the spreadsheet for all heating, cooling, and shoulder seasons. If 20% 

of process heat in cogenerated buildings is carried by cogenerators, then add 0.2 X Hourly 

Average Process Heat for 7 Buildings, or 

to all TgB Ht M" inputs for all seasons, and reduce the "ROB Ht M" by the same amount, 

below what it was in the former case. 

0.2 X 1164 Btuh = 116 kBtuh 

Medium 

SHOULDER SEASON: Months in season = 4.0 

0.200 1075 402 0 

HEATING SEASON: Months in season = 6.0 

Low step multiplier = 6.667/months in season = 1.111 

Cogenerated Buildings Heat Load and Rest of Buildings Heat Load, Due to Space Heating 

Onlv (Not Including: Process Heat) 

High Io.100 I1613 I 603 lo 

CgB hload = Avg. CgB heat load X low step multiplier X [1,2 or 31 

ROB hload = Avg. ROB heat load X low step multiplier X [1,2 or 31 
'WESTDIV SPREADSHEET INPUTS 

Low 

Med 

High 

COOLING: Months in season = 2.0 

Low step multiplier = 6.667/months in season = 3.333 

fy cool All Base Avg Low Step ROB AC elec 

Cooling Load Multiplier kW 

kBtuh 

0.067 91 x 3.333 X 1/10.36 = 29 

0.067 91 ' x 3.333 X 2/10.36 = 59 

0.033 91 x 3.333 X 3/10.36 = 88 

If no chillers, all base cooling met as "ROB AC Elec Ld" 

If one chiller per cogenerator, the chillers meet as much of the cooling load as they can. Any 

excess, together with non-cogenerated building cooling load, is met electrically 

7 bldgs 

cooling 

kBtuh 

1 load 

Med 1 440 

High I 660 

ROB 

cooling 

load 

kBtuh 

83 

167 

250 

kBtu h 

440 I 677 

660 I1014 

Not met 

by chlrs. 

kBtuh 

83 

167 

250 

ROB AC 

elec. 

kW 

8 

16 

24 

7 bldgs. cooling load = avg. 7 bldgs. cooling load X low step multiplier X [1,2 or 31 

ROB cooling load = rest of site avg. cooling load X low step multiplier X [1,2 or 31 

Met by chillers = lesser of 7 bldgs cooling load and 840 Btuh 

CgB thermal input = met by chillers/O.65 

Not met by chillers = 7 bldgs cooling load - met by chillers + ROB cooling load 

ROB AC electric = Not met by chillers/lO.36 

B-3 0 
COGEN ELEC. CAP., kW 0 HEATELEC. RATIO, nd 1.375 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 0.333 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 1600 

ROB AC Elec Ld, kW 0 

0.4 

269 

0.3 

538 

0.2 

807 

0.1 

1076 

31 4 

1867 

0 

0 

0 

314 

467 

0 

0 

0 

269 

1600 

0 

0 

0 

538 471 

1600 1400 

0 0 

0 0 

0 0 

807 

1600 

0 

0 

0 

471 

933 

0 

0 

0 

1076 

1600 

0 

0 

0 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

538 

1801 

0 

269 

2339 

0 

0 

0 

189 

1639 

0 

0 

0 

538 283 

2339 1229 

0 0 

0 0 

0 0 

807 

2339 

0 

0 

0 

283 

820 

0 

0 

0 

1076 

2339 

0 

0 

0 

189 

41 0 

0 

0 

0 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1075 

2002 

0 

269 

3077 

0 

0 

0 

189 

21 56 

0 

0 

0 

538 283 

3077 1617 

0 0 

0 0 

0 0 

807 

3077 

0 

0 

0 

283 

1078 

0 

0 

0 

1 076 

3077 

0 

0 

0 

189 

539 

0 

0 

0 

HEATING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 

1613 

2203 

0 

269 

381 6 

0 

0 

0 

94 

1337 

0 

0 

0 

538 141 

381 6 1003 

0 0 

0 0 

0 0 

807 

381 6 

0 

0 

0 

141 1 076 

669 3816 

0 0 

0 0 

0 0 

94 

334 

0 

0 

0 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

0 

1600 

29 

298 

1600. 

0 

0 

0 

70 

376 

0 

0 

0 

567 

1600 

0 

0 

0 

100 

282 

0 

0 

0 

836 

1600 

0 

0 

0 

98 

188 

0 

0 

0 

1105 

1600 

0 

0 

0 

65 

94 

0 

0 

0 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

0 

1600 

59 

328 

1600 

0 

0 

0 

77 

376 

0 

0 

0 

597 

1600 

0 

0 

0 

105 866 

282 1600 

0 0 

0 0 

0 0 

1 02 

188 

0 

0 

0 

1135 

1600 

0 

0 

0 

67 

94 

0 

0 

0. 

COOLING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.033 

0 

1600 

88 

357 41 

1600 185 

0 0 

0 0 

0 0 

WHOLE SYSTEM 

4790 

19840 

0 

0 

0 

626 

1600 

0 

0 

0 

54 895 

139 1600 

0 0 

0 0 

0 0 

52 

93 

0 

0 

0 

1164 

1600 

0 

0 

0 

34 

46 

0 

0 

0 

EACH BLOCK 

Ed em and kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtulyr 

Hused kBtuh MBtu/yr 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

4790 

0 

19840 

Cogen Heat Cap., kBtuh 0 WESTDIV, NO COGEN 

B-31 

-__- 
COGEN ELEC. CAP., kW 840 HEAT/ELEC. RATIO, nd 1.375 

0.1 

1076 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

N heat, nd 0.333 

* CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 1600 

ROB AC Elec Ld, kW 0 

0.4 

269 

0.3 

538 

0.2 

807 

269 

1600 

269 

1263 

0 

31 4 

1867 

31 4 

1474 

0 

538 

1600 

538 

2526 

0 

471 

1400 

471 

221 1 

0 

807 

1600 

807 

3789 

0 

471 

933 

471 

221 1 

0 

1076 

1600 

840 

3944 

0 

31 4 

467 

245 

1151 

0 

HEATING, LOW 

N heat, nd 

CgB Ht id, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

538 

1801 

0 

269 

2339 

269 

1263 

538 

189 538 

1639 2339 

189 538 

885 2526 

377 538 

283 

1229 

283 

1328 

283 

807 

2339 

807 

3789 

538 

283 

820 

283 

1328 

189 

1076 

2339 

840 

3944 

538 

189 

410 * 

147 

691 

94 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1075 

2002 

0 

269 

3077 

269 

1263 

1075 

189 

21 56 

189 

885 

753 

538 

3077 

538 

2526 

1075 

283 

1617 

283 

1328 

565 

807 

3077 

807 

3789 

1075 

283 

1078 

283 

1 328 

377 

1076 

3077 

840 

3944 

1075 

189 

539 

147 

691 

188 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 

1613 

2203 

0 

269 

381 6 

344 

1613 

1613 

94 

1337 

120 

565 

565 

538 

381 6 

538 

2526 

1613 

141 

1003 

141 

664 

424 

807 

381 6 

807 

3789 

1613 

141 

669 

141 

664 

283 

1076 

381 6 

840 

3944 

1613 

94 

334 

74 

346 

141 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

0 

1600 

29 

298 

1600 

298 

1399 

0 

70 

376 

70 

329 

0 

567 

1600 

567 

2662 

0 

100 

282 

100 

469 

0 

836 

1600 

836 

3926 

0 

98 

188 

98 

461 

0 

1105 

1600 

840 

3944 

0 

65 

94 

49 

232 

0 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, Wtuh 

ROB AC Elec Ld, kW 

0.067 

0 

1600 

59 

328 

1600 

328 

1540 

0 

77 

376 

77 

362 

0 

597 

1600 

597 

2803 

0 

105 

282 

105 

494 

0 

866 

1600 

840 

3944 

0 

1 02 

188 

99 

463 

0 

1135 

1600 

840 

3944 

0 

67 

94 

49 

232 

0 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

54 

139 

54 

255 

0 

895 

1600 

840 

3944 

0 

52 

93 

49 

228 

0 

1164 

1600 

840 

3944 

0 

34 

46 

24 

114 

0 

0.033 

0 

1600 

88 

357 41 

1600 185 

357 41 

1676. 194 

0 0 

WHOLE SYSTEM 

4790 

19840 

4595 

21 578 

4239 

626 

1600 

626 

2939 

0 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Ebought MWhIyr 

Esold MWh/yr 

Hboilers MBtu/yr 

221 

26 

15601 

Cogen Heat Cap., kBtuh 3944.325 WESTDIV, NO CHILLERS, NO PROC. HEAT 

B-3 2 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.333 

0 

1600 

0 

0.2 

538 

1801 

0 

0.2 

1075 

2002 

0 

0.1 

1613 

2203 

0 

0.067 

338 

1600 

8 

0.067 

677 

1600 

16 

0.033 

1014 

1600 

24 

EACH BLOCK 

Edernand kW MWh/yr 

Hdernand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Cogen Heat Cap., kBtuh 

840 

0.4 

269 

269 

1600 

269 

1263 

0 

269 

2339 

269 

1263 

538 

269 

3077 

269 

1263 

1075 

269 

381 6 

344 

1613 

1613 

277 

1938 

277 

1301 

338 

285 

2277 

285 

1338 

677 

293 

261.4 

293 

1376 

1014 

HEATELEC. RATIO, nd 

31 4 

1867 

314 

1474 

0 

189 

1639 

189 

885 

377 

189 

21 56 

189 

885 

753 

94 

1337 

120 

565 

565 

65 

455 

65 

305 

79 

67 

535 

67 

31 4 

159 

34 

302 

34 

159 

117 

WHOLE SYSTEM 

4734 

20728 

4551 

21 371 

51 28 

0.3 

538 

538 

1600 

538 

2526 

0 

538 

2339 

538 

2526 

538 

538 

3077 

538 

2526 

1075 

538 

3816 

538 

2526 

1613 

546 

1938 

546 

2564 

338 

554 

2277 

554 

2601 

677 

562 

2614 

562 

2639 

1014 

471 

1400 

471 

221 1 

0 

283 

1229 

283 

1328 

283 

283 

1617 

283 

1328 

565 

141 

1003 

141 

664 

424 

96 

341 

96 

451 

60 

98 

401 

98 

458 

119 

49 

227 

49 

229 

88 

1.375 

0.2 

807 

807 

1600 

807 

3789 

0 

807 

2339 

807 

3789 

538 

807 

3077 

807 

3789 

1075 

807 

381 6 

807 

3789 

1613 

81 5 

1938 

81 5 

3827 

338 

823 

2277 

823 

3864 

677 

831 

2614 

831 

3902 

1014 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

471 

933 

471 

221 1 

0 

283 

820 

283 

1328 

189 

283 

1 078 

283 

1 328 

377 

141 

669 

141 

664 

283 

96 

227 

96 

449 

40 

97 

267 

97 

454 

79 

48 

151 

48 

226 

59 

209 

26 

15601 

3944.325 WESTDIV, 1 CHILLEWCOGEN, NO PROC. HEAT 

B-33 

0.1 

1 076 

1076 

1600 

840 

3944 

0 

1076 

2339 

840 

3944 

538 

1076 

3077 

840 

3944 

1075 

1076 

3816 

840 

3944 

1613 

1084 

1938 

840 

3944 

338 

1092 

2277 

840 

3944 

677 

1100 

261 4 

840 

3944 

1014 

31 4 

467 

245 

1151 

0 

189 

41 0 

147 

691 

94 

189 

539 

1 47 

691 

188 

94 

334 

74 

346 

141 

64 

114 

49 

232 

20 

64 

134 

49 

232 

40 

32 

76 

24 

114 

29 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.333 

233 

1367 

0 

0.2 

771 

1568 

0 

0.2 

1308 

1769 

0 

0.1 

1846 

1970 

0 

0.067 

233 

1367 

29 

0.067 

233 

1367 

59 

0.033 

233 

1367 

88 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtulyr 

840 

0.4 

269 

269 

1600 

269 

1263 

233 

269 

2339 

269 

1263 

771 

269 

3077 

279 

1308 

1308 

269 

3816 

393 

1846 

1846 

298 

1600. 

298 

1399 

233 

328 

1600 

328 

1540 

233 

357 

1600 

357 

1676 

233 

HEAT/ELEC. RATIO, nd 

31 4 

1867 

31 4 

1474 

272 

189 

1639 

189 

885 

540 

189 

21 56 

195 

91 7 

91 7 

94 

1337 

138 

647 

647 

70 

376 

70 

329 

55 

77 

376 

77 

362 

55 

41 

185 

41 

1 94 

27 

WHOLE SYSTEM 

4790 

19840 

461 9 

21 691 

6280 

0.3 

538 

538 

1600 

538 

2526 

233 

538 

2339 

538 

2526 

771 

538 

3077 

538 

2526 

1308 

538 

3816 

538 

2526 

1846 

567 

1600 

567 

2662 

233 

597 

1600 

597 

2803 

233 

626 

1600 

626 

2939 

233 

471 

1400 

471 

221 1 

204 

283 

1229 

283 

1328 

405 

283 

1617 

283 

1328 

687 

141 

1003 

141 

664 

485 

100 

282 

100 

469 

41 

105 

282 

105 

494 

41 

54 

139 

54 

255 

20 

1.375 

0.2 

807 

807 

1600 

807 

3789 

233 

807 

2339 

807 

3789 

771 

807 

3077 

807 

3789 

1308 

807 

3816 

807 

3789 

1846 

836 

1600 

836 

3926 

233 

866 

1600 

840 

3944 

233 

895 

1600 

840 

3944 

233 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

471 

933 

471 

221 1 

136 

283 

820 

283 

1328 

270 

283 

1078 

283 

1328 

458 

141 

669 

141 

664 

323 

98 

188 

98 

461 

27 

1 02 

188 

99 

463 

27 

52 

93 

49 

228 

13 

221 

50 

13560 

Cogen Heat Cap., kBtuh 3944.325 WESTDIV, NO CHILLERS, 20% PROC. HEAT IN CgB 

B-34 

~~ 

0.1 

1076 

1076 

1600 

840 

3944 

233 

1076 

2339 

840 

3944 

771 

1076 

3077 

840 

3944 

1308 

1076 

381 6 

840 

3944 

1846 

1105 

1600 

840 

3944 

233 

1135 

1600 

840 

3944 

233 

1164 

1600 

840 

3944 

233 

31 4 

467 

245 

1151 

68 

189 

410 - 

147 

691 

135 

189 

539 

147 

691 

229 

94 

334 

74 

346 

162 

65 

94 

49 

232 

14 

67 

94 

49 

232 

14 

34 

46 

24 

114 

7 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld. kW 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.333 

233 

1367 

0 

0.2 

771 

1568 

0 

0.2 

1308 

1769 

0 

0.1 

1846 

1970 

0 

0.067 

571 

1367 

8 

0.067 

91 0 

1367 

16 

0.033 

1247 

1367 

24 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Cogen Heat Cap., kBtuh 

840 

0.4 

269 

269 

1600 

269 

1263 

233 

269 

2339 

269 

1263 

771 

269 

3077 

279 

1308 

1308 

269 

3816 

393 

1846 

1846 

277 

1938 

277 

1301 

571 

285 

2277 

285 

1338 

91 0 

293 

261 4 

293 

I 376 

1247 

HEAT/ELEC. RATIO, nd 

314 

1867 

314 

1474 

272 

189 

1639 

189 

885 

540 

189 

21 56 

195 

91 7 

91 7 

94 

1337 

138 

647 

647 

65 

455 

65 

305 

134 

67 

535 

67 

31 4 

21 4 

34 

302 

34 

159 

144 

WHOLE SYSTEM 

4734 

20728 

4575 

21484 

71 69 

0.3 

538 

538 

1600 

538 

2526 

233 

538 

2339 

538 

2526 

771 

538 

3077 

538 

2526 

1308 

538 

3816 

538 

2526 

1846 

546 

1938 

546 

2564 

571 

554 

2277 

554 

2601 

91 0 

562 

261 4 

562 

2639 

1 247 

471 

1400 

471 

221 1 

204 

283 

1229 

283 

1328 

405 

283 

1617 

283 

1328 

687 

141 

1003 

141 

664 

485 

96 

341 

96 

451 

101 

98 

401 

98 

458 

160 

49 

227 

49 

229 

108 

1.375 

0.2 

807 

807 

1600 

807 

3789 

233 

807 

2339 

807 

3789 

771 

807 

3077 

807 

3789 

1308 

807 

381 6 

807 

3789 

1846 

81 5 

1938 

81 5 

3827 

571 

823 

2277 

823 

3864 

91 0 

831 

2614 

831 

3902 

1 247 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

471 

933 

471 

221 1 

136 

283 

820 

283 

1328 

270 

283 

1078 

283 

1328 

458 

141 

669 

141 

664 

323 

96 

227 

96 

449 

67 

97 

267 

97 

454 

107 

48 

151 

48 

226 

72 

209 

50 

13560 

0.1 

1076 

1 076 

1600 

840 

3944 

233 

1076, 

2339 

840 

3944 

771 

1076 

3077 

840 

3944 

1308 

1 076 

381 6 

840 

3944 

1846 

1084 

1938 

840 

3944 

571 

1092 

2277 

840 

3944 

91 0 

1100 

261 4 

840 

3944 

1 247 

3944.325 WESTDIV, 1 CHILLERKOGEN, 20% PROC. HEAT IN CgB 

B-3 5 

I.__ __ . 

31 4 

467 

245 

1151 

68 

189 

41 0 

147 

691 

135 

189 

539 

147 

691 

229 

94 

334 

74 

346 

162 

64 

114 

49 

232 

34 

64 

134 

49 

232 

53 

32 

76 

24 

114 

36 
: of Buildings: 

leating Demand: 

!6 Month Season 

Annual Energy: 

Annual Peak: 

:ooling Demand: 

7."'.: 

[? Month Season ..... 

Annual Energy: 

Annual Peak: 

Capacity 

Requirement 

Large 

Building 

Small Total for 

Building Site (1) Units 

91 

Factor = 50% 

.................... 176 $:::::::::33:2:$ .... ,. ... I x:::::::::. .................. .. 

I 0.0 I 3.1 I na I tons 

89 I 2626 

Factor = 50% 

- 3 

24 

37 

3.1 

3.1 

3.1 

MBtu 

kBtuh 

MBtu 

kBtuh 

tons with 

tons 

tons 

....................... ............. .:,~,i,iji~:~;~,i.i,i,i.i,~~8 

1079 

90 

na 

na 

qumber of 

10 ton 

Ibsorption 

>hillers per 

:ogen I 

unit 

There are 0.8 0.8 0.8 

when P(AC)= 16.2 45.5 74.8 

(in kw) 16.2 16.2 16.2 

16.2 16.2 16.2 

0 

1 

2 

0.4 months 

'104.1 0 

26.3 1 

16.2 2 

- There are 0.8 0.8 0.8 1 0.4 

when P(tot)= 144 173 203 I 232 

There are 0.8 0.8 I 0.8 0.4 months 

when P(tot)= 1224 1253 I 1283 1312 01 

months 

01 and 

I. 12241 1224 I 1224) 12241 31 

Itilitv Demand with 9 120 kW cogenerators: 

(in kw) 144 144 144 154 1 5 

144 144 144 144 2 with 

144 144 144 144 3 144 

1 See discussion of diversity in text. 

Demand Table - WESTDIV 
SWESTDIV SPREADSHEET INPUTS 

fy heat 

Shoulder 0.41 6 

Low 0.1 67 

Medium 0.1 67 

High 0.083 

ELECTRIC: Whole Base Non AC Avg. Load = 428 kW 

Low step = 0.5 X above = 214 kW 

2nd step = 1.0 X above = 428 kW 

3rd step = 1.5 X above = 642 kW 

4th step = 2.0 X above = 856 kW 

CgB ht load ROB ht load ROB AC elec 

kBtuh kBtuh kW 

0 0 0 

429 160 0 

858 320 0 

1288 480 0 

PROCESS HEAT: If no process heat is obtained from cogeneration, then add the Hourly 

Average Process Heat for Whole Site, or 

948 kBtuh 

to the "ROB Ht Ld" in the spreadsheet for all heating, cooling, and shoulder seasons. If 20% 

of process heat in cogenerated buildings is carried by cogenerators, then add 0.2 X Hourly 

Average Process Heat for 7 Buildings, or 

to all "CgB Ht Ld" inputs for all seasons, and reduce the "ROB Ht Ld" by the same amount, 

below what it was in the former case. 

0.2 X 690 kBtuh = 138 Btuh 

SHOULDER SEASON: Months in season = 5.0 

HEATING SEASON: Months in season = 5.0 

Low step multiplier = 6.667/months in season = 1.333 

B-3 7 
SWESTDIV SPREADSHEET INPUTS 

Low 

Med 

High 

COOLJNG: Months in season = 2.0 

Low step multiplier = 6.667/months in season = 3.333 

fy cool All Base Avg Low Step ROB AC elec 

Cooling Load ' Multiplier kW 

kBtuh 

0.067 274 x 3.333 X 1/10.36 = 88 

0.067 274 x 3.333 X 2/10.36 = 176 

0.033 274 x 3.333 X 3/10.36 = 264 

If no chillers, all base cooling met as "ROB AC Elec M" 

1327 

1990 

500 

750 

If one chiller per cogenerator, the chillers meet as much of the cooling load as they can. Any 

excess, together with non-cogenerated building cooling load, is met electrically 

Low 

Med 

High 

kBtuh kBtuh 

840 I 1292 

840 I1292 

Not met 

by chlrs. 

kBtuh 

250 

987 

1900 

ROB AC 

elec. 

kW 

24 

95 

183 

7 bldgs. cooling load = avg. 7 bldgs. cooling load X low step 

ROB cooling load = rest of site avg. cooling load X low step 

Met by chillers = lesser of 7 bldgs cooling load and 840 kBtuh 

CgB thermal input = met by chillerdO.65 

Not met by chillers = 7 bldgs cooling load - met by chillers + ROB cooling load 

ROB AC electric = Not met by chillers/lO.36 

multiplier X [1,2 or 31 

multiplier X [1,2 or 31 

B-38 
COGEN ELEC. CAP., kW 0 HEAT/ELEC. RATIO, nd I .375 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 0.41 6 

CgB Ht Ld, kBtuh 0 

ROB Ht Ld, kBtuh 948 

ROB AC Elec Ld, kW 0 

0.4 

21 4 

0.3 

428 

0.2 

642 

0.1 

856 

468 

1036 

0 

0 

0 

468 

691 

0 

0 

0 

312 

345 

0 

0 

0 

214 

948 

0 

0 

0 

31 2 

1382 

0 

0 

0 

428 

948 

0 

0 

0 

642 

948 

0 

0 

0 

856 

948 

0 

0 

0 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 67 

429 

1108 

0 

21 4 

1537 

0 

0 

0 

125 428 

899 1537 

0 0 

0 0 

0 0 

188 

675 

0 

0 

0 

642 

1537 

0 

0 

0 

188 

450 

0 

0 

0 

856 

1537 

0 

0 

0 

125 

225 

0 

0 

0 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.167 

858 

1268 

0 

21 4 

21 26 

0 

0 

0 

125 428 

1244 2126 

0 0 

0 0 

0 0 

188 

933 

0 

0 

0 

642 

21 26 

0 

0 

0 

188 

622 

0 

0 

0 

856 

21 26 

0 

0 

0 

125 

31 1 

0 

0 

0 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.083 

1288 

1428 

0 

21 4 

271 6 

0 

0 

0 

62 428 

790 271 6 

0 0 

0 0 

0 0 

93 

592 

0 

0 

0 

642 

271 6 

0 

0 

0 

93 

395 

0 

0 

0 

856 

271 6 

0 

0 

0 

62 

197 

0 

0 

0 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

0 

948 

88 

302 

948 

0 

0 

0 

71 

223 

0 

0 

0 

51 6 

948 

0 

0 

0 

91 

167 

0 

0 

0 

730 

948 

0 

0 

0 

86 

111 

0 

0 

0 

944 

948 

0 

0 

0 

55 

56 

0 

0 

0 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

0 

948 

176 

390 92 

948 223 

0 0 

0 0 

0 0 

478 55 

948 110 

0 0 

0 0 

0 0 

WHOLE SYSTEM 

3981 

121 75 

0 

0 

0 

604 106 

948 167 

0 0 

0 0 

0 0 

81 8 

948 

0 

0 

0 

96 

111 

0 

0 

0 

1032 

948 

0 

0 

0 

61 

56 

0 

0 

0 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

692 

948 

0 

0 

0 

60 

82 

0 

0 

0 

906 

948 

0 

0 

0 

52 

55 

0 

0 

0 

1120 

948 

0 

0 

0 

32 

27 

0 

0 

0 

0.033 

0 

948 

264 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

3981 

0 

121 75 

Cogen Heat Cap., kBtuh 0 SWESTDIV, NO COGEN 

B-39 
COGEN ELEC. CAP., kW 840 

0.4 

21 4 

21 4 

948 

21 4 

1005 

0 

21 4 

1537 

21 4 

1005 

429 

21 4 

21 26 

21 4 

1005 

858 

21 4 

2716 

274 

1288 

1288 

302 

948 

302 

1418 

0 

390 

948 

390 

1831 

0 

478 

948 

478 

2245 

0 

HEAT/ELEC. RATIO, nd 1.375 

0.2 

642 

642 

948 

642 

301 5 

0 

642 

1537 

642 

301 5 

429 

642 

2126 

642 

301 5 

858 

642 

271 6 

642 

301 5 

1288 

730 

948 

730 

3428 

0 

81 8 

948 

81 8 

3841 

0 

906 

948 

840 

3944 

0 

0.3 

428 

428 

948 

428 

201 0 

0 

428 

1537 

428 

201 0 

429 

428 

21 26 

428 

201 0 

858 

428 

271 6 

428 

201 0 

1288 

51 6 

948 

51 6 

2423 

0 

604 

948 

604 

2836 

0 

692 

948 

692 

3249 

0 

0.1 

856 

frac. of Year Elec. nd 

All Base nonAC Elec id, kW 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.416 

0 

948 

0 

312 

1382 

312 

1465 

0 

468 

1036 

468 

21 97 

0 

468 

691 

468 

21 97 

0 

856 31 2 

948 345 

840 306 

3944 1437 

0 0 

HEATING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.167 

429 

1108 

0 

125 

899 

125 

588 

251 

188 

675 

188 

882 

188 

188 

450 

188 

882 

126 

856 

1537 

840 

3944 

429 

125 

225 - 123 

577 

63 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 67 

858 

1268 

0 

125 

1244 

125 

588 

502 

188 

933 

188 

882 

377 

188 

622 

188 

882 

251 

856 

2126 

840 

3944 

858 

125 

31 1 

123 

577 

126 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.083 

1288 

1428 

0 

93 

592 

93 

438 

281 

93 

395 

93 

438 

187 

856 

271 6 

840 

3944 

1288 

62 

197 

61 

287 

94 

62 

790 

80 

375 

375 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

0 

948 

88 

71 

223 

71 

333 

0 

91 

1 67 

91 

427 

0 

86 

111 

86 

402 

0 

944 

948 

840 

3944 

0 

55 

56 

49 

232 

0 

COOLING, MED 

N heat, nd 

CgB Ht.Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

0 

948 

1 76 

96 

111 

96 

451 

0 

1032 

948 

840 

3944 

0 

61 

56 

49 

232 

0 

92 

223 

92 

430 

0 

106 

167 

106 

499 

0 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.033 

0 

948 

264 

55 

110 

55 

260 

0 

60 

82 

60 

282 

0 

52 

55 

49 

228 

0 

1120 

948 

840 

3944 

0 

32 

27 

24 

114 

0 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

WHOLE SYSTEM 

3981 

121 75 

3957 

18581 

281 9 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

41 

18 

9356 

Cogen Heat Cap., kBtuh 3944.325 SWESTDIV, NO CHILLERS, NO PROC. HEAT 

B-40 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 

’ CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.41 6 

0 

948 

0 

0.167 

429 

1108 

0 

0.167 

858 

1268 

0 

0.083 

1288 

1428 

0 

0.067 

1020 

948 

24 

0.067 

1292 

948 

95 

0.033 

1292 

948 

183 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWhIyr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Cogen Heat Cap., kBtuh 

840 

0.4 

21 4 

21 4 

948 

21 4 

1005 

0 

21 4 

1537 

21 4 

1005 

429 

21 4 

21 26 

21 4 

1005 

858 

21 4 

271 6 

274 

1288 

1288 

238 

1968 

238 

1118 

1020 

309 

2240 

309 

1451 

1292 

397 

2240 

397 

1864 

1292 

HEAT/ELEC. RATIO, nd 

31 2 

1382 

31 2 

1465 

0 

125 

899 

125 

588 

251 

125 

1 244 

125 

588 

502 

62 

790 

80 

375 

375 

56 

462 

56 

262 

239 

73 

526 

73 

341 

303 

46 

259 

46 

21 6 

149 

WHOLE SYSTEM 

3872 

13905 

3863 

18140 

4550 

0.3 

428 

428 

948 

428 

201 0 

0 

428 

1537 

428 

201 0 

429 

428 

21 26 

428 

201 0 

858 

428 

271 6 

428 

201 0 

1288 

452 

1968 

452 

21 22 

1020 

523 

2240 

523 

2456 

1292 

61 1 

2240 

61 1 

2869 

1292 

468 

1036 

468 

21 97 

0 

188 

675 

188 

882 

188 

188 

933 

188 

882 

377 

93 

592 

93 

438 

281 

80 

347 

80 

374 

180 

92 

394 

92 

432 

227 

53 

1 94 

53 

249 

112 

1.375 

0.2 

642 

642 

948 

642 

301 5 

0 

642 

1537 

642 

301 5 

429 

642 

21 26 

642 

3015 

858 

642 

271 6 

642 

301 5 

1288 

666 

1968 

666 

3127 

1 020 

737 

2240 

737 

3461 

1292 

825 

2240 

825 

3874 

1292 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

468 

691 

468 

21 97 

0 

188 

450 

188 

882 

126 

188 

622 

188 

882 

251 

93 

395 

93 

438 

I 87 

78 

231 

78 

367 

120 

87 

263 

87 

406 

152 

48 

130 

48 

224 

75 

26 

18 

9356 

3944.325 SWESTDIV, 1 CHILLEWCOGEN, NO PROC. HEAT 

B-41 

0.1 

856 

856 

948 

840 

3944 

0 

856 

1537 

840 

3944 

429 

856 

21 26 

840 

3944 

858 

856 

271 6 

840 

3944 

1288 

880 

1968 

840 

3944 

1 020 

951 

2240 

840 

3944 

1292 

1039 

2240 

840 

3944 

1292 

312 

345 

306 

1437 

0 

125 

225 

123 

577 

63 

125 

31 1 

123 

577 

126 

62 

197 

61 

287 

94 

52 

116 

49 

232 

60 

56 

131 

49 

232 

76 

30 

65 

24 

114 

37 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

840 HEAT/ELEC. RATIO, nd 1.375 

0.1 

856 

0.4 

21 4 

0.3 

428 

0.2 

642 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.41 6 

138 

81 0 

0 

21 4 

948 

21 4 

1005 

138 

312 

1382 

31 2 

1465 

201 

125 

899 

125 

588 

332 

125 

1 244 

125 

588 

583 

62 

790 

88 

41 5 

41 5 

71 

223 

71 

333 

32 

92 

223 

92 

430 

32 

55 

110 

55 

260 

16 

428 468 

948 1036 

428 468 

201 0 21 97 

138 151 

642 

948 

642 

301 5 

138 

468 

691 

468 

21 97 

101 

856 

948 

840 

3944 

138 

312 

345 

306 

1437 

50 

HEATING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 67 

567 

970 

0 

125 

225 

123 

577 

83 

21 4 

1537 

21 4 

1005 

567 

428 

1537 

428 

201 0 

567 

188 

675 

188 

882 

249 

642 

1537 

642 

301 5 

567 

188 

450 

188 

882 

166 

856 

1537 

840 

3944 

567 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 67 

996 

1130 

0 

. 214 

21 26 

21 4 

1005 

996 

428 

21 26 

428 

201 0 

996 

188 

933 

188 

882 

437 

642 

21 26 

642 

301 5 

996 

188 

622 

188 

882 

291 

856 

21 26 

840 

3944 

996 

125 

31 1 

123 

577 

146 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.083 

1426 

1290 

0 

21 4 

271 6 

304 

1426 

1426 

428 

271 6 

428 

201 0 

1426 

93 

592 

93 

438 

31 1 

642 

271 6 

642 

301 5 

1426 

93 

395 

93 

438 

207 

856 

271 6 

840 

3944 

1426 

62 

197 

61 

287 

104 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

138 

81 0 

88 

944 

948 

840 

3944 

138 

55 

56 

49 

232 

8 

302 

948 

302 

1418 

138 

51 6 

948 

51 6 

2423 

138 

91 

167 

91 

427 

24 

730 

948 

730 

3428 

138 

86 

111 

86 

402 

16 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

138 

81 0 

1 76 

390 

948 

390 

1831 

138 

604 106 

948 , 167 

604 106 

2836 499 

138 24 

81 8 

948 

81 8 

3841 

138 

96 

111 

96 

451 

16 

1032 

948 

840 

3944 

138 

61 

56 

49 

232 

8 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

478 

948 

478 

2245 

138 

0.033 

138 

81 0 

264 

692 

948 

692 

3249 

138 

60 

82 

60 

282 

12 

906 

948 

840 

3944 

138 

52 

55 

49 

228 

8 

1120 

948 

840 

3944 

138 

32 

27 

24 

114 

4 

EACH BLOCK WHOLE SYSTEM 

Edernand kW MWh/yr 3981 

Hdernand kBtuh MBtulyr 12175 

Ecogen kW MWhlyr 3966 

Hcogen kBtuh MBtu/yr 18621 

Hused kBtuh MBtu/yr 4028 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

41 

26 

81 47 

Cogen Heat Cap., kBtuh 3944.325 SWESTDIV, NO CHILLERS, 20% PROC. HEAT IN CgB 

B-42 
COGEN ELEC. CAP., kW 840 HEAT/ELEC. RATIO, nd 1.375 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 0.41 6 

CgB Ht Ld, kBtuh 138 

ROB Ht Ld, kBtuh 81 0 

ROB AC Elec Ld, kW 0 

0.4 

21 4 

0.3 

428 

0.2 

642 

0.1 

856 

856 

948 

840 

3944 

138 

31 2 

1382 

312 

1465 

201 

468 

691 

468 

21 97 

101 

312 

345 

306 

1437 

50 

21 4 

948 

21 4 

1005 

138 

428 468 

948 1036 

428 468 

201 0 21 97 

138 151 

642 

948 

642 

301 5 

138 

HEATING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.167 

567 

970 

0 

214 

1537 

21 4 

1005 

567 

125 

899 

125 

588 

332 

428 

1537 

428 

201 0 

567 

188 642 

675 1537 

188 642 

882 3015 

249 567 

188 

450 

188 

882 

166 

856 

1537 

840 

3944 

567 

125 

225 

123 

577 

83 

HEATING, MED 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.167 

996 

1130 

0 

21 4 

21 26 

21 4 

1005 

996 

125 

1244 

125 

588 

583 

428 

21 26 

428 

201 0 

996 

188 642 

933 21 26 

188 642 

882 3015 

437 996 

188 

622 

188 

882 

29 1 

856 

21 26 

840 

3944 

996 

125 

31 1 

123 

577 

146 

HEATING, HIGH 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.083 

1426 

1290 

0 

21 4 

271 6 

304 

1426 

1426 

62 

790 

88 

41 5 

41 5 

428 

271 6 

428 

201 0 

1426 

93 642 

592 271 6 

93 642 

438 301 5 

31 1 1426 

93 

395 

93 

438 

207 

856 

271 6 

840 

3944 

1426 

62 

1 97 

61 

287 

104 

COOLING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

1158 

81 0 

24 

238 

247 

1158 

1158 

1968. 

56 

462 

58 

272 

272 

452 

1968 

452 

21 22 

1158 

80 666 

347 1968 

80 666 

374 31 27 

204 1158 

78 

231 

78 

367 

136 

880 

1968 

840 

3944 

1158 

52 

116 

49 

232 

68 

COOLING, MED 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.067 

1430 

81 0 

95 

309 

2240 

309 

1451 

1430 

73 

526 

73 

341 

336 

92 737 

394 2240 

92 737 

432 3461 

252 1430 

523 

2240 

523 

2456 

1430 

87 

263 

87 

406 

168 

951 

2240 

840 

3944 

1430 

56 

131 

49 

232 

84 

COOLING, HIGH 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.033 

1430 

81 0 

183 

397 46 

2240 259 

397 46 

1864 216 

1430 165 

WHOLE SYSTEM 

3872 

13905 

3874 

181 90 

5759 

61 1 

2240 

61 1 

2869 

1430 

53 825 

194 2240 

53 825 

249 3874 

124 1430 

48 

130 

48 

224 

83 

1039 

2240 

840 

3944 

1430 

30 

65 

24 

114 

41 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

26 

28 

8147 

Cogen Heat Cap., kBtuh 3944.325 SWESTDIV, 1 CHILLEWCOGEN, 20% PROC. HEAT IN CgB 

B-43 
Annual Peak: 

1.61 9.2 I na I tons 

:::I 

9.2 

31 

270 tons with 

na tons 

na tons 

Non-AC Electric: 

Annual Energy 

Peak Demand: 

qumber of 

10 ton 

lbsorption 

>hillers per 

:ogen I unit 

48.6 48.6 48.6 79.31 31 

. Small Total DF= 50% 

: 114; 

32 9.2 months 

0 

1 

.2 

There are 

when P(tot)= 

(in kw) 

Utility Demand with 

There are 

when P(tot)= 

(in kw) 

0.8 0.8 0.8 0.4 months 

975 1063 1151 1239 0 

975 985 1073 1161 1 

975 975 996 1084 2 

975 975 975 1006 3 

0.8 0.8 0.8 0.4 months 

9 120 kW cogenerators: 

0 0 71 159 0 anc 

0 0 0 81 1 

0 0 0 42 witt 

0 0 0 03 C 

c 

146.8 234.8 

On kw)I 69.01 157.01 2 II

B-44 
PACDIV SPREADSHEET INPUTS 

Shoulder 

Low 

Medium 

High 

ELECTRIC: 

0.41 7 0 0 0 

0.033 993 373 0 

0.033 1987 747 0 

0.01 7 2980 1120 0 

Whole Base Non AC Avg. Load = 561 kW 

Low step = 0.5 X above = 280 kW 

2nd step = 1.0 X above = 561 kW 

3rd step = 1.5 X above = 842 kW 

4th step = 2.0 X above = 1122 kW 

PROCESS HEAT: If no process heat is obtained from cogeneration, then add the Hourly 

Average Process Heat for Whole Site, or 

1003 Btuh 

to the "ROB Ht MI' in the spreadsheet for all heating, cooling, and shoulder seasons. If 20% 

of process heat in cogenerated buildings is carried by cogenerators, then add 0.2 X Hourly 

Average Process Heat for 7 Buildings, or 

0.2 X 730 kBtuh = 146 kBtuh 

to all "CgB Ht M" inputs for all seasons, and reduce the "ROB Ht M" by the same amount, 

below what it was in the former case. 

SHOULDER SEASON: Months in season = 5.0 

HEATING SEASON: Months in season = 1.0 

Low step multiplier = 6,667/months in season = 6.667 

Cogenerated Buildings Heat Load and Rest of Buildings Heat Load, Due to Space Heating 

My (Not Including Process Heat) 

1 I 1 I II 

CgB ht load ROB ht load ROB AC elec I kBtuh I kBtuh I kW 

B-45 
PACDIV SPREADSHEET INPUTS 

Low 

Med 

High 

COOLING: Months in season = 6.0 

Low step multiplier = 6.667/months in season = 1-11 1 

fy cool All Base Avg Low Step ROB AC elec 

Cooling Load Multiplier kW 

kBtuh 

0.200 807 x l.tll X 1/10.36 = 87 

0.200 807 x 1.111 X 2/10.36 = 173 

0.100 807 x 1.111 X 3/10.36 = 260 

If no chillers, all base cooling met as "ROB AC Elec M" 

652 1003 

840 1292 

840 1292 

244 24 

953 92 

1849 178 

If one chiller per cogenerator, the chillers meet as much of the cooling load as they can. Any 

excess, together with non-cogenerated building cooling load, is met electrically 

Low 

Med 

High 

kBtuh kBtuh 

652 244 

1304 489 

1956 733 

7 bldgs. cooling load = avg. 7 bldgs. cooling load X low step multiplier X [1,2 or 31 

ROB cooling load = rest of site avg. cooling load X low step multiplier X [1,2 or 31 

Met by chillers = lesser of 7 bldgs cooling load and 840 Btuh 

CgB themal input = met by chillers/O.65 

Not met by chillers = 7 bldgs cooling load - met by chillers + ROB cooling load 

ROB AC electric = Not met by chillers/lO.36 

B-4 6 
If two chillers per cogenerator, the chillers again meet as much of the cooling load as they can, 

but now the limit is 2 X 840 = 1680 KBtuh of cooling load. 

Low 

Med 

High 

7 bldgs ROB Met by CgB Notrnet RoBAC 

cooling cooling chil-lers thermal by chlrs. elec. 

load load kBtuh input kBtuh 

kBtuh kBtu h kBtuh kW 

652 244 652 1003 244 24 

1304 489 1304 2006 489 47 

1956 733 1680 2585 1009 97 

B-47 

-- 
COGEN ELEC. CAP., kW 0 HEAT/ELEC. RATIO, nd 1.375 

0.2 

842 

842 

1003 

0 

0 

0 

842 

2369 

0 

0 

0 

842 

3737 

0 

0 

0 

842 

51 03 

0 

0 

0 

929 

1003 

0 

0 

0 

1015 

1003 

0 

0 

0 

1102 

1003 

0 

0 

0 

0.3 

561 

561 

1003 

0 

0 

0 

561 

2369 

0 

0 

0 

561 

3737 

0 

0 

0 

561 

51 03 

0 

0 

0 

648 

1003 

0 

0 

0 

734 

1003 

0 

0 

0 

821 

1003 

0 

0 

0 

0.1 

1122 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

0.4 

280 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.41 7 

0 

1003 

0 

409 

1466 

0 

0 

0 

61 5 

1099 

0 

0 

0 

61 5 

733 

0 

0 

0 

49 

137 

0 

0 

0 

49 

21 6 

0 

0 

0 

25 

152 

0 

0 

0 

326 

351 

0 

0 

0 

356 

351 

0 

0 

0 

193 

176 

0 

0 

0 

5597 

0 

10582 

41 0 

366 

0 

0 

0 

280 

1003 

0 

0 

0 

1122 

1003 

0 

0 

0 

HEATING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.033 

993 

1376 

0 

280 

2369 

0 

0 

0 

32 

274 

0 

0 

0 

49 

205 

0 

.o 

0 

1122 

2369 

0 

0 

0 

32 

68 - 

0 

0 

0 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.033 

1987 

1750 

0 

280 

3737 

0 

0 

0 

32 

432 

0 

0 

0 

49 

324 

0 

0 

0 

1122 

3737 

0 

0 

0 

32 

108 

0 

0 

0 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.017 

2980 

21 23 

0 

280 

51 03 

0 

0 

0 

17 

304 

0 

0 

0 

25 

228 

0 

0 

0 

1122 

51 03 

0 

0 

0 

17 

76 

0 

0 

0 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

0 

1003 

87 

367 

1003 

0 

0 

0 

257 

703 

0 

0 

0 

341 

527 

0 

0 

0 

1209 

1003 

0 

0 

0 

21 2 

176 

0 

0 

0 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

0 

1003 

173 

1295 

1003 

0 

0 

0 

227 

176 

0 

0 

0 

453 

1003 

0 

0 

0 

31 7 

703 

0 

0 

0 

386 

527 

0 

0 

0 

COOLING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 

0 

1003 

260 

540 

1003 

0 

0 

0 

189 

351 

0 

0 

0 

21 6 

264 

0 

0 

0 

1382 

1003 

0 

0 

0 

121 

88 

0 

0- 

0 

EACH BLOCK WHOLE SYSTEM 

Hdemand kBtuh MBtu/yr 10582 

Edemand kW MWh/yr 5597 

Ecogen kW MWh/yr 0 

Hcogen kBtuh MBtulyr 0 

Hused kBtuh MBtu/yr 0 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

Cogen Heat Cap., kBtuh 0 PACDIV, NO COGEN 

B-48 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld. kW 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.41 7 

0 

1003 

0 

0.033 

993 

1 376 

0 

0.033 

1987 

1750 

0 

0.01 7 

2980 

21 23 

0 

0.2 

0 

1003 

87 

0.2 

0 

1003 

173 

0.1 

0 

1003 

260 

EACH BLOCK 

Edemand kW MWh/yr 

Hdernand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

Cogen Heat Cap., kBtuh 

840 

0.4 

280 

280 

1003 

280 

1315 

0 

280 

2369 

280 

1315 

993 

280 

3737 

423 

1987 

1987 

280 

51 03 

635 

2980 

2980 

367 

1003 

367 

1723 

0 

453 

1003 

453 

21 27 

0 

540 

1003 

540 

2536 

0 

HEAT/ELEC. RATIO, nd 

409 

1466 

409 

1921 

0 

32 

274 

32 

152 

115 

32 

432 

49 

230 

230 

17 

304 

38 

178 

178 

257 

703 

257 

1208 

0 

31 7 

703 

317 

1491 

0 

189 

351 

189 

888 

0 

WHOLE SYSTEM 

5597 

10582 

51 82 

24334 

1305 

0.3 

561 

561 

1003 

561 

2634 

0 

561 

2369 

561 

2634 

993 

561 

3737 

561 

2634 

1987 

561 

51 03 

635 

2980 

2980 

648 

1003 

648 

3043 

0 

734 

1003 

734 

3447 

0 

821 

1003 

821 

3855 

0 

61 5 

I099 

61 5 

2887 

0 

49 

205 

49 

228 

86 

49 

324 

49 

228 

172 

25 

228 

28 

133 

133 

341 

527 

341 

1599 

0 

386 

527 

386 

1812 

0 

21 6 

264 

21 6 

1013 

0 

1.375 

0.2 

842 

842 

1003 

840 

3944 

0 

842 

2369 

840 

3944 

993 

842 

3737 

840 

3944 

1987 

842 

51 03 

840 

3944 

2980 

929 

1003 

840 

3944 

0 

1015 

1003 

840 

3944 

0 

1102 

1003 

840 

3944 

0 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

3944.325 PACDIV, NO CHILLERS, NO PROC. HEAT 

B-49 

61 5 

733 

614 

2882 

0 

49 

1 37 

49 

228 

57 

49 

21 6 

49 

228 

115 

25 

1 52 

25 

117 

89 

326 

351 

294 

1382 

0 

356 

351 

294 

1382 

0 

193 

176 

1 47 

691 

0 

456 

41 

9277 

0.1 

1122 

1122 

1003 

840 

3944 

0 

1122, 

2369 

840 

3944 

993 

1122 

3737 

840 

3944 

1987 

1122 

51 03 

840 

3944 

2980 

1209 

1003 

840 

3944 

0 

1295 

1003 

840 

3944 

0 

1382 

1003 

840 

3944 

0 

41 0 

366 

307 

1441 

0 

32 

68 

24 

114 

29 

32 

108 

24 

114 

57 

17 

76 

13 

59 

44 

21 2 

176 

147 

691 

0 

227 

176 

147 

691 

0 

121 

88 

74 

346 

0 
COGEN ELEC. CAP., kW 840 HEAT/ELEC. RATIO, nd 1.375 

0.1 

1122 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

0.4 

280 

0.3 

561 

0.2 

842 

SHOULDER 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

61 5 

733 

614 

2882 

0 

41 0 

366 

307 

1441 

0 

1122 

1003 

840 

3944 

0 

0.41 7 

0 

1003 

0 

280 

1003 

280 

1315 

0 

409 

1466 

409 

1921 

0 

561 

1003 

561 

2634 

0 

61 5 

1099 

61 5 

2887 

0 

842 

1003 

840 

3944 

0 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.033 

993 

1376 

0 

49 

205 

49 

228 

86 

842 

2369 

840 

3944 

993 

49 

137 

49 

228 

57 

1122 

2369 

840 

3944 

993 

32 

24 

114 

29 

68 - 

280 

2369 

280 

1315 

993 

32 

274 

32 

152 

115 

32 

432 

49 

230 

230 

561 

2369 

561 

2634 

993 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.033 

1987 

1750 

0 

280 

3737 

423 

1987 

1987 

561 

3737 

561 

2634 

1987 

49 

324 

49 

228 

172 

842 

3737 

840 

3944 

1987 

49 

21 6 

49 

228 

115 

1122 

3737 

840 

3944 

1987 

32 

108 

24 

114 

57 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

1122 

51 03 

840 

3944 

2980 

17 

76 

13 

59 

44 

0.01 7 

2980 

21 23 

0 

280 

51 03 

635 

2980 

2980 

17 

304 

38 

178 

178 

561 

51 03 

635 

2980 

2980 

25 

228 

28 

133 

133 

842 

51 03 

840 

3944 

2980 

25 

1 52 

25 

117 

89 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1003 

1003 

24 

866 

2006 

840 

3944 

1003 

303 

703 

294 

1382 

351 

1146 

2006 

840 

3944 

1003 

201 

351 

147 

691 

176 

304 

2006 

304 

1 427 

1003 

21 3 

1406 

21 3 

1000 

703 

585 

2006 

585 

2747 

1003 

307 

1054 

307 

1444 

527 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1292 

1003 

92 

261 

1608 

261 

1224 

905 

653 

2295 

653 

3066 

1292 

343 

1206 

343 

1612 

679 

934 

2295 

840 

3944 

1292 

327 

804 

294 

1382 

453 

1214 

2295 

840 

3944 

1292 

21 3 

402 

147 

691 

226 

372 

2295 

372 

I 747 

1292 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

1300 

2295 

840 

3944 

1292 

114 

201 

74 

346 

113 

458 

2295 

458 

21 51 

1292 

0.1 

1292 

1003 

178 

160 739 

804 2295 

160 739 

754 3470 

453 1292 

194 

603 

194 

91 2 

340 

1020 

2295 

840 

3944 

1292 

179 

402 

1 47 

691 

226 

EACH BLOCK WHOLE SYSTEM 

Edemand kW MWhIyr 5273 

Hdemand kBtuh MBtu/yr 15735 

Hcogen kBtuh MBtu/yr 23268 

Hused kBtuh MBtu/yr 6458 

Ecogen kW MWh/yr 4955 

358 

41 

9277 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

Cogen Heat Cap., kBtuh 3944.325 PACDIV, 1 CHILLEWCOGEN, NO PROC. HEAT 

B-50 
COGEN ELEC. CAP., kW 840 HEATIELEC. RATIO, nd I .375 

0.2 

842 

842 

1003 

840 

3944 

0 

842 

2369 

840 

3944 

993 

842 

3737 

840 

3944 

1987 

842 

51 03 

840 

3944 

2980 

866 

2006 

840 

3944 

1003 

889 

3009 

840 

3944 

2006 

939 

3588 

840 

3944 

2585 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

0.4 

280 

0.3 

561 

561 

1003 

561 

2634 

0 

561 

2369 

561 

2634 

993 

561 

3737 

561 

2634 

1987 

561 

51 03 

635 

2980 

2980 

585 

2006 

585 

2747 

1003 

608 

3009 

608 

2855 

2006 

658 

3588 

658 

3090 

2585 

0.1 

1122 

SHOULDER 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.41 7 

0 

1003 

0 

0.033 

993 

1 376 

0 

280 

1003 

280 

1315 

0 

409 

1466 

409 

1921 

0 

61 5 

1099 

61 5 

2887 

0 

49 

205 

49 

228 

86 

49 

324 

49 

228 

1 72 

25 

228 

28 

133 

133 

307 

1054 

307 

1444 

527 

320 

,1582 

320 

1501 

1054 

173 

943 

173 

812 

679 

61 5 

733 

61 4 

2882 

0 

41 0 

366 

307 

1441 

0 

1122 

1003 

840 

3944 

0 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

280 

2369 

280 

1315 

993 

32 

274 

32 

1 52 

115 

49 

137 

49 

228 

57 

1122 

2369 

840 

3944 

993 

32 

68 

24 

114 

29 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.033 

1987 

1750 

0 

280 

3737 

423 

1987 

1987 

32 

432 

49 

230 

230 

49 

21 6 

49 

228 

115 

1122 

3737 

840 

3944 

1987 

32 

108 

24 

114 

57 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.017 

2980 

21 23 

0 

280 

51 03 

635 

2980 

2980 

17 

304 

38 

178 

178 

25 

152 

25 

117 

89 

1122 

51 03 

840 

3944 

2980 

17 

76 

13 

59 

44 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1003 

1003 

24 

304 

2006 

304 

1427 

1003 

21 3 

1406 

21 3 

1000 

703 

303 

703 

294 

1382 

351 

1146 

2006 

840 

3944 

1003 

201 

351 

147 

691 

176 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

2006 

1003 

47 

327 

3009 

427 

2006 

2006 

229 

21 09 

299 

1406 

1406 

31 2 

1054 

294 

1382 

703 

1169 

3009 

840 

3944 

2006 

205 

527 

1 47 

691 

351 

COOLING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.1 

2585 

1003 

97 

377 

3588 

551 

2585 

2585 

132 

1257 

193 

906 

906 

165 

629 

147 

691 

453 

1219 

3588 

840 

3944 

2585 

107 

314 

74 

346 

226 

EACH BLOCK WHOLE SYSTEM 

Hdemand kBtuh MBtu/yr 18118 

Ecogen kW MWh/yr 4981 

Hcogen kBtuh MBtu/yr 23391 

Hused kBtuh MBtu/yr 8841 

Edemand kW MWh/yr ’ 5123 Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

31 3 

1 72 

9277 

Cogen Heat Cap., kBtuh 3944.325 PACDIV, 2 CHILLERS/COGEN, NO PROC. HEAT 

B-51 

0 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

W heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.41 7 

146 

857 

0 

0.033 

1139 

1230 

0 

0.033 

21 33 

1604 

0 

0.017 

31 26 

1977 

0 

0.2 

146 

857 

87 

0.2 

146 

857 

173 

0.1 

146 

857 

260 

EACH BLOCK 

Edernand kW MWh/yr 

Hdernand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

840 

0.4 

280 

280 

1003 

280 

1315 

146 

280 

2369 

280 

1315 

1139 

280 

3737 

454 

21 33 

21 33 

280 

51 03 

666 

31 26 

31 26 

367 

1003 

367 

1723 

146 

453 

1003 

453 

21 27 

146 

540 

1003 

540 

2536 

146 

HEAT/ELEC. RATIO, nd 

WHOLE SYSTEM 

5597 

10582 

51 89 

24366 

2584 

409 

1466 

409 

1921 

21 3 

32 

274 

32 

1 52 

1 32 

32 

432 

53 

247 

247 

17 

304 

40 

186 

186 

257 

703 

257 

1208 

1 02 

31 7 

703 

31 7 

1491 

1 02 

189 

351 

189 

888 

51 

0.3 

561 

561 

1003 

561 

2634 

146 

561 

2369 

561 

2634 

1139 

561 

3737 

561 

2634 

21 33 

561 

51 03 

666 

3126 

3126 

648 

1003 

648 

3043 

146 

734 

1003 

734 

3447 

146 

821 

1003 

821 

3855 

146 

61 5 

1099 

61 5 

2887 

160 

49 

205 

49 

228 

99 

49 

324 

49 

228 

185 

25 

228 

30 

140 

140 

341 

527 

341 

1599 

77 

386 

527 

386 

1812 

77 

21 6 

264 

21 6 

1013 

38 

1.375 

0.2 

842 

842 

1003 

840 

3944 

146 

842 

2369 

840 

3944 

1139 

842 

3737 

840 

3944 

21 33 

842 

51 03 

840 

3944 

3126 

929 

1003 

840 

3944 

146 

1015 

1003 

840 

3944 

146 

1102 

1003 

840 

3944 

146 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

61 5 

733 

614 

2882 

107 

49 

1 37 

49 

228 

66 

49 

21 6 

49 

228 

123 

25 

152 

25 

117 

93 

326 

351 

294 

1382 

51 

356 

351 

294 

1382 

51 

193 

176 

1 47 

691 

26 

456 

48 

7998 

0.1 

1122 

1122 

1003 

840 

3944 

146 

1122 

2369 

840 

3944 

1139 

1122 

3737 

840 

3944 

21 33 

1122 

51 03 

840 

3944 

3126 

1209 

1003 

840 

3944 

146 

1295 

1003 

840 

3944 

146 

1382 

1003 

840 

3944 

146 

41 0 

366 

307 

1441 

53 

32 

68 '. 

24 

114 

33 

32 

108 

24 

114 

62 

17 

76 

13 

59 

47 

212 

176 

147 

691 

26 

227 

176 

147 

691 

26 

121 

88 

74 

346 

13 

Cogen Heat Cap., kBtuh 3944.325 PACDIV, NO CHILLERS, 20% PROC. HEAT IN CgB 

B-52 
COGEN ELEC. CAP., kW 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

SHOULDER 

fY heat, nd 

. CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

HEATING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, LOW 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, MED 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

COOLING, HIGH 

fY heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.41 7 

146 

857 

0 

0.033 

1139 

1230 

0 

0.033 

21 33 

1604 

0 

0.017 

3126 

1977 

0 

0.2 

1149 

857 

24 

0.2 

1438. 

857 

92 

0.1 

1438 

857 

178 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

840 

0.4 

280 

280 

1003 

280 

1315 

146 

280 

2369 

280 

1315 

1139 

280 

3737 

454 

21 33 

21 33 

280 

51 03 

666 

3126 

3126 

304 

2006 

304 

1427 

1149 

372 

2295 

372 

1747 

1438 

458 

2295 

458 

21 51 

1438 

HEAT/ELEC. RATIO, nd 

409 

1466 

409 

1921 

21 3 

32 

274 

32 

152 

132 

32 

432 

53 

247 

247 

17 

304 

40 

186 

186 

21 3 

1406 

21 3 

1000 

805 

261 

1608 

261 

1224 

1008 

160 

804 

160 

754 

504 

WHOLE SYSTEM 

5273 

15735 

4962 

23300 

7737 

0.3 

561 

561 

1003 

561 

2634 

146 

561 

2369 

561 

2634 

1139 

561 

3737 

561 

2634 

21 33 

561 

51 03 

666 

31 26 

31 26 

585 

2006 

585 

2747 

1149 

653 

2295 

653 

3066 

1438 

739 

2295 

739 

3470 

1438 

61 5 

1099 

61 5 

2887 

160 

49 

205 

49 

228 

99 

49 

324 

49 

228 

185 

25 

228 

30 

140 

140 

307 

1054 

307 

1444 

604 

343 

1206 

343 

1612 

756 

194 

603 

1 94 

91 2 

378 

1.375 

0.2 

842 

842 

1003 

840 

3944 

146 

842 

2369 

840 

3944 

1139 

842 

3737 

840 

3944 

21 33 

842 

51 03 

840 

3944 

3126 

866 

2006 

840 

3944 

1149 

934 

2295 

840 

3944 

1438 

1 020 

2295 

840 

3944 

1438 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

61 5 

733 

61 4 

2882 

107 

49 

137 

49 

228 

66 

49 

21 6 

49 

228 

123 

25 

152 

25 

117 

93 

303 

703 

294 

1382 

403 

327 

804 

294 

1382 

504 

179 

402 

1 47 

691 

252 

358 

48 

7998 

Cogen Heat Cap., kBtuh 3944.325 PACDIV, 1 CHILLERICOGEN, 20% PROC. HEAT IN CgB 

0.1 

1122. 

1122 

1003 

840 

3944 

146 

1122 

2369 

840 

3944 

1139 

1122 

3737 

840 

3944 

21 33 

1122 

51 03 

840 

3944 

3126 

1146 

2006 

840 

3944 

1149 

1214 

2295 

840 

3944 

1438 

1300 

2295 

840 

3944 

1438 

41 0 

366 

307 

1441 

53 

32 

68 

24 

114 

33 

32 

108 

24 

114 

62 

17 

76 

13 

59 

47 

201 

351 

147 

691 

201 

21 3 

402 

147 

691 

252 

114 

201 

74 

346 

126 
COGEN ELEC. CAP., kW 840 

0.4 

280 

280 

1003 

280 

1315 

146 

280 

2369 

280 

1315 

1139 

. 280 

3737 

454 

21 33 

21 33 

280 

51 03 

666 

31 26 

31 26 

304 

2006 

304 

1427 

1149 

327 

3009 

458 

21 52 

21 52 

HEATELEC. RATIO, nd 1.375 

0.1 

1122 

frac. of Year Elec. nd 

All Base nonAC Elec Ld, kW 

0.3 

561 

0.2 

842 

SHOULDER 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

409 

1466 

409 

1921 

21 3 

32 

274 

32 

152 

132 

32 

432 

53 

247 

247 

17 

304 

40 

186 

186 

21 3 

1406 

21 3 

1000 

805 

229 

21 09 

321 

1508 

1508 

61 5 

1099 

61 5 

2887 

160 

61 5 

733 

614 

2882 

1 07 

41 0 

366 

307 

1441 

53 

0.41 7 

146 

857 

0 

561 

1003 

561 

2634 

146 

842 

1003 

840 

3944 

146 

1122 

1003 

840 

3944 

146 

HEATING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.033 

1139 

1230 

0 

561 

2369 

561 

2634 

1139 

49 

205 

49 

228 

99 

842 

2369 

840 

3944 

1139 

49 

137 

49 

228 

66 

1122 

2369 

840 

3944 

1139 

32 

68 

24 

114 

33 

HEATING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

1122 

3737 

840 

3944 

21 33 

32 

108 

24 

114 

62 

0.033 

21 33 

1604 

0 

561 

3737 

561 

2634 

21 33 

49 

324 

49 

228 

185 

842 

3737 

840 

3944 

21 33 

49 

21 6 

49 

228 

123 

HEATING, HIGH 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

561 

51 03 

666 

3126 

31 26 

25 

228 

30 

140 

140 

842 

51 03 

840 

3944 

31 26 

25 

152 

25 

117 

93 

1122 

51 03 

840 

3944 

3126 

17 

76 

13 

59 

47 

0.01 7 

31 26 

1977 

0 

COOLING, LOW 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

1149 

857 

24 

585 

2006 

585 

2747 

1149 

307 

1054 

307 

1444 

604 

866 

2006 

840 

3944 

1149 

303 

703 

294 

1382 

403 

1146 

2006 

840 

3944 

1149 

201 

351 

1 47 

691 

201 

COOLING, MED 

N heat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

0.2 

21 52 

857 

47 

205 

527 

147 

691 

377 

608 

3009 

608 

2855 

21 52 

320 

.I582 

320 

1501 

1131 

889 

3009 

840 

3944 

21 52 

31 2 

1054 

294 

1382 

754 

1169 

3009 

840 

3944 

21 52 

COOLING, HIGH 

Wheat, nd 

CgB Ht Ld, kBtuh 

ROB Ht Ld, kBtuh 

ROB AC Elec Ld, kW 

939 

3588 

840 

3944 

2731 

165 

629 

147 

691 

478 

1219 

3588 

840 

3944 

2731 

1 07 

31 4 

74 

346 

239 

0.1 

2731 

857 

97 

377 

3588 

582 

2731 

2731 

132 

1257 

204 

957 

957 

658 

3588 

658 

3090 

2731 

173 

943 

173 

81 2 

71 8 

EACH BLOCK 

Edemand kW MWh/yr 

Hdemand kBtuh MBtu/yr 

Ecogen kW MWh/yr 

Hcogen kBtuh MBtu/yr 

Hused kBtuh MBtu/yr 

WHOLE SYSTEM 

51 23 

18118 

5021 

23577 

10120 

Ebought MWh/yr 

Esold MWh/yr 

Hboilers MBtu/yr 

31 3 

21 2 

7998 

Cogen Heat Cap., kBtuh 3944.325 PACDIV, 2 CHILLERWCOGEN, 20% PROC. HEAT IN CgB 

B-54 
APPENDIX C: Test of MCC 85 Kw cogenerator 

In preparing our proposals and program plans, we had used as a baseline the cogeneration 

system designed and marketed by our industrial partner, Modular Cogeneration Corporation 

(“MCC”), which they call the ‘Smart-1”. The Smart-1 is designed around a six cylinder Fiat 

industrial diesel engine, and incorporates the primary advance identified in Chapter 2 - a reliance 

on a heavyduty, high compression engine to provide high efficiency in the production of valuable 

electrical power. Because MCC’s specifications for the machine go beyond any other generation 

units available in the regime below 100 kW,it was necessary to verify these claims. As part of 

our preparation of a program plan, we planned an independent test of the performance and 

emissions of the Smart-1 system, testing a machine installed at MCC’s facility in New Holland, 

PA. The protocols and results are presented in this chapter after a brief description of the Smart1 itself. In summary, the test produced only limited data, since the machine over heated and the 

coolant blew out a major heat exchanger before full power operations could be monitored. 

C. 1 The Smart-1 Cogeneration System 

This six-liter engine, ~t~~illy aspirated with a 17: 1 compression ratio, should be capable 

of mechanical efficiencies approaching 40% with low environmental emissions when operated in 

the dual fuel mode. The system is described by a block diagram in Figure A-1. The fuel supply 

system is simple, with diesel fuel metered into the fuel injectors at a rate sufficient to maintain idle 

operation, while ~tural gas or propane is metered directly into the air intake to provide the bulk 

of the energy content of the fuel. The system requires a small amount of diesel fuel for ignition, 

so it cannot operate on 100% gas, but it can revert to 100% diesel fuel operation if desired. This 

would produce an increase in emissions levels, but we did not test under these circumstances. 

The Smart-1 is available with either an induction or a synchronous generator. An 

induction generator results in a simpler system, since it automatically provides power in phase 

with that of the local utility, and the generator can also serve as an induction motor to start the 

cogenerator, allowing elimination of the twelve-volt DC startedgenerator subsystem. However, 

the induction generator cannot run in a stand-alone mode, so if the local utility has a black-out, 

the cogeneration system will also. The induction generator also cannot improve the power factor 

above that of the local utility, so if reactive power is present on the line, that inefficiency will be 

present in the cogenerated power as well. Consequently, MCC prefers the synchronous generator 

option in most circumstances, and the system we tested had a 100 ampere, 480 volt (83 kw) 

Newage synchronous generator, directly connected to the local utility. 

The Sm-1 uses heat both from the jacket cooling water (with or without an isolating heat 

exchanger, depending on the application) and from the water-cooled exhaust manifold in the same 

circuit. Additionally, if a domestic hot water load is available, a stainless steel condensing heat 

exchanger at the end of the exhaust system preheats the cold water and condenses most of the 

water out of the exhaust stream, contributing to lowered emissions. 

c- 1 
T 

1;:; ................................................................... 

Manifold 

Engine 

Block 

Air3 T 1 

......................... 

Exhaust 

T2 

DHW 

darn . 

main 

I Load 

From 

e Thermal _------ I 

. ' Load 

Water Electricity 

Figure C-I : Smart-I Block Diagram. 

Several other features should contribute ease of use and efficient operation. The entire 

system is inside a sealed, sound-insulated container which will easily fit through standard doors 

and into elevators. Incoming air is used to cool the generator, so this heat ends up back in the' 

engine and is recovered in the water circuits, allowing an overall recovery of 90-95% of the 

energy content of the fuel if appropriate hot water loads are present. 

Plans also call for the incorporation of an on-board computer which will monitor many 

functions and analyse them for signs of problems, calling for help over a modem if trouble arises. 

We supplied OUT own instrumentation, and did not test this feature of the machine. 

C.2 Test Protocols and Equipment 

The testing was carried out entirely using equipment brought from BNL. The electrical 

efficiency was the cluantity of primary interest, with emissions and thermal efficiency also closely 

monitored. The following sub-sections discuss the methods and equipment used for each physical 

guantityC.2.1 Electrical Power. 

c-2 
The installed system feeds back to the local utility through a standard Sagamon electric 

meter which has been recently calibmted. Although these are usually quite accurate, we preferred 

to maintain the independence of our testing by bringing our Dranetz Series 808 Electric Power 

Demand Analyser. This is a self-contained system incorporating current transformers and voltage 

probes and true RMS measuring circuitry. It can measure power, current, voltages, power 

factors, phase angles and all related qyintites on up to three active phases. The results are 

accurate to 1/4% and are NIST WS) traceable; the unit had been factory calibrated three months 

before the tests. The Dranetz also incorporates a substantial memory and an input/output port 

allowing control by and data export to an external computer. The system was programmed to 

monitor power flows in detail once every minute for the duration of our tests. 

C.2.2 Fuel Inputs 

Diesel oil is consumed at a rate of about 20 ml (0.7 oz) per minute. Fuel was monitored 

by setting the fuel vessel on a Sartorius 3802MP digital scale, readable to 0.1 g, accurate to 0.1- 

0.3g, with a capacity of 6 kg. Care was taken that the weight of the flexible fuel line stayed 

constant throughout the experiment, and the mass of the fuel container was recorded at the 

beginning and end of each timed run, giving the mass of the fuel consumed during the run. 

Natural gas is not available at the MCC facility, so the system is normally operated on 

LPG from a 500 gallon tank, with fuel supplied by a local dealer. At full load, the system 

consumes about 40 liters per minute (1.5 cfm) of fuel, monitored by a bellows type gas meter on 

the line. We used this supply for all tune-up and acclimatization runs reported here. 

Uncertainty about the precise fractions of non-propane fuel gasses in the LPG and about 

the calibration of the meter led us to purchase cylinders of chemically pure (less than 1% 

impurities) propane. Since the impurities are propylene and other fuel gasses, this results in an 

uncertainty in the energy content well below 1 %. Also, rather than rely on the gas meter, the 

primary data on propane consumption was to be taken by setting the propane cylinder on a 1000 

lb scale, readable to 0.1 lb. This would have allowed very accurate determinations of system 

efficiency, but unfortunately the engine failed before we could use this method. 

In most applications the Smart-1 will run on a combination of diesel fuel and natural gas, 

so to eliminate any chance that its performance on propane might differ from that on natural gas, 

we also purchased a cylinder of chemically pure methane, enough to run the system for about onehalf hour. (The Smart-1 requires about 4 cfm of methane at full load.) The setup is the same 

as for chemically pure propane, measuring weight change as methane is withdrawn from the 120 

lb cylinder. Again, we did not get an opportunity to initiate these tests. 

c-3 
C.2.3 Exhaust emission Measurements 

In measuring engine exham emissions a dilution tunnel approach was taken, as illustrated 

in Figure A-2. Exhaust gas from the engine system condensing economizer is divided into two 

parts. One part, about 80% of the gas, is simply vented through PVC pipe. The other portion 

goes to the dilution tunnel where is is mixed with filtered ambient air at a ratio of about 5/1 

(aidgas). The dilution tunnel was consbxcted of 6" diameter stainless steel ducting and the total 

tunnel length was 10'. In sampling for particulates the dilution tunnel provides two advantages. 

First, particulates are mixed with ambient air, simulating the types of processes which occur when 

raw diesel exhaust is normally vented. This includes the condensation of semi-volatile organics 

and other compounds on the particulates. A second advantage of the dilution tunnel is the 

elimination of engine pressure pulsations at the point of sampling. In the dilution tunnel the flow 

Reynolds number was typically about 30,000 and the exhaust gas was injected in a direction 

opposite to the bulk flow. Both of these points promote mixing of gas and dilution air early in 

the tunnel. 

In particulate sampling a metered portion of the diluted exhaust gas was drawn through a 

standard, unheated 47 mm quartz filter. To establish the dilution ratio CO, measurements were 

made in the raw and diluted exhaust gas using a non-dispersive infrared analyzer (Rosemont). A 

condensation type sample gas hdler was used to feed clean, dry gas to this analyzer ( Clean Air 

Engineering). A wet-electrochemical cell type gas analyzer (ENERAC E 2000, Energy 

Efficiency Systems) was used to measure oxygen, carbon monoxide, and NO, in the dilution 

tunnel. From the CO, levels in the dilution tunnel the concentrations of particulates, CO, and 

NO, were converted to a per-unit of fuel and per-unit of output power basis. 

C.2.4 Heat Recovery 

The engine water jacket heat was easily monitored, since the Smart-1 has fourteen 

thermistors mounted in the engine water at various points using 3/8" NPT fittings. For the test, 

we replaced those shown in Figure 3 with Type K thermocouples wired into our Campbell 

multichannel datalogger. This allowed us to monitor temperatures during the entire process, 

including warm-up and normal full load operation. The cooling circuit is serial, connecting the 

water jacket in the block and the water-cooled exhaust manifold as shown in Figure 3, and 

includes a 55 gallon drum as a reservoir. There is also a radiator, which would normally dissipate 

thermal power in excess of the demands of the local facility. There is no thermal load at the MCC 

facility, so the radiator transferred all the engine heat to the atmosphere. Temperature control is 

accomplished with a throttling valve. We also installed a Ramapo target flow meter into an 

appropriate point in the water circuit, and fed that signal into the Campbell datalogger as well. 

The flowmeter had been calibrated in the datalogger at BNL shortly prior to these experiments, 

using a quadratic relation between the meter's output voltage and the fluid flow rate, and was 

accurate to better than 1%. A temperature correction for the density of water was also 

incorporated, eliminating a possible source of a 3-5% error. The thermal power is then the 

c-4 
ELECTROCHEMI CAL CELL 

02, CO, NOx 

ANALYZER 

- 4 

TO ICE BATH, 

SAMPLE PUMP 

AND TEST METER 

4 

PARTICULATE FILTER 

(ANALYZLRI NDIH C02 EXtlAlJS'I' CiAS 

FROM ENtiINE 

4 

DI LUTI ON TUNNEL 

EXHAUST FAN DI LUTI ON TUNNEL 

INLET AIR FILTER 

Figure C-2: Emissions Measurement Apparatus. 
product of temperature difference, fluid flow and the heat capacity of water. Temperatures, flows 

and thermal power were to be recorded every minute by the Campbell datalogger. 

There is also a condensing recuperator on the exhaust pipe. In order to condense water 

. in the exhaust stream, this must operate at a substantially lower temperature than the water jacket, 

and so is only useful to preheat domestic hot water or provide some similar warming function in 

the sub-1OOoF (sub-40°C) regime. Here we monitored water temperature in and out of the water 

side with thermocouples and the flow rate by timing flow into a bucket and measuring the mass 

accumulated. Thermocouples also measured the temperature of the exhaust in and out on the gas 

side. The exhaust flow could subsequently be calculated from stochiometry so that a heat balance 

could be established. The sum of this condenser heat and the water jacket heat of the previous 

paragraph constitutes the thermal power output of the Smart-1. 

c.3 Test Results - Power and Efficiency 

The actual operation of the Smart-1 was carried out by MCC personnel, since they were 

familiar with its characteristics, while BNL personnel operated the monitoring equipment 

described above. Two sets of shakedown runs were carried out, one for two hours in the 

afternoon, after all the equipment had been set up and another the next morning. After about onehalf hour of operation in the morning, the engine boiled over and the pressure of the steam 

. ruptured the stainless steel exhaust heat exchanger. It was subsequently determined that the 

cooling fan which forced air through the radiator had not been turned on manually, as required. 

There being no possibility of making repairs in less than a few weeks, the experiment was 

disassembled. The data to be reported below were all derived from the shakedown runs and are 

therefore somewhat limited. 

During the emissions tests, the Smart-1 output was measured at 50.5 kW on the Sagamon 

meter. (The Dranetz reading was consistent, but it was not yet recording at the time). 

Simultaneously, a mass measurement indicated that 50 g of oil were consumed in 52.9 s, or 0.945 

g/s. Using standard conversions and 19.4-19.7 kBtu/lb of oil, this corresponds to 146-148 

kBtu/hr as input energy in the fuel oil. 

The MCC gas meter indicated 21.62 s/f? of LPG. The supplier's MSDS states that the 

WG is 92% propane, 5 % propylene and 3 % butane. We did not measure the temperature of the 

LPG at that time, but using STP values for the heats of combustion (2.505, 2.460 and 3.368 

kBtu/ft? respectively) gives 421 mBtu/hr of LPG. This gives a total of 568 mBtu/hr, which 

corresponds to an efficiency of 30%. This is well below the 3840% MCC had expected. One 

reason for the discrepancy is that in order to raise the power output to 85 kW, they increased the 

engine speed from around 1800 rpm to around 2300 rpm. In addition, the engine was funning 

roughly, and it was subsequently determined that a cylinder sleeve had slipped out of position. 

Since it is not clear exactly when this happened, it is not possible to be sure if it was a factor. 

C-6 
Although we did take thermal data during these shakedown runs, we have not attempted 

to process the data since the system never reached thermal steady state and was always running 

well below rated power. The six thermocouples placed in the exhaust stream from each cylinder 

gave erratic and very low temperature readings (350-500°F), which we now believe is evidence 

that the exhaust heat exchanger was already leaking, with water dripping down onto the hot 

thermocouples. 

C.4 Test Results - Emissions Measurements 

Due to the technical difficulties at MCC we were forced to reduce every bit of data that 

we had. This included some very preliminary measurements made using the ENERAC gas 

analyzer direcdy in the exhaust pipe at two different load levels as well as the one, more carefbl, 

test which included particulates in the dilution tunnel. For the preliminary tests we do not have 

fuel flow rates which, for emissions calculations, means that we had to estimate the mix of gas 

and oil actually fied in these tests. The assumptionused was that the ratio was the same as in the 

more careful, dilution tunnel test. The effect that this will have on the accuracy of the data 

reduction is small because the differences in hydrogenkarbon ratios among the fuels are not that 

great. The table below provides a summary of the results. 

Test Number I 

Gas sampling 

point 

Power Output kW 

NOx WhP-hrI 

co WhP-hrI 

particulates k/hP-hrl 

rable A-1: Results of Emissions Mea 

1 12 

5:50 pm 6:50 pm 5:40 pm 

exhaust dilution exhaust 

Pipe tunnel Pipe 

- -15 - I 

urements on Smart-1. 

Comparisons with typical expected emissions reported in Table 2-5 above are possible. 

NO, for typical dual fuel engines is estimated there at 6 g/hp-hr. The latest version of the EPA’s 

Ap-42 listing of expected average emssions lists the emission factor for NO, for dual fuel engines 

at 9.1 g/hp-hr. By either of these standards the Smart-1 is performing well. However, for COY 

Table 2-5 indicates that 2-3 g/bhp-hr should be expected for a dual-fuel engine with no exhaust 

controls, and measured performance was quite a bit higher. The only measurement of 

particulates, 0.15 g/bhp-hr, is the same as the expected value in Table 2-5. Given the 

c-7 
uncertainties of the engine’s operation while we were testing it, the Smart-1 appears to be fairly 

ordinary in its class with respect to emissions. 

C.5 System Assessment 

The performance of the engine appears to be typical of its class, both with respect to 

efficiency and emissions. Reliability of the engine tested was well below average, and operation 

apparently troublesome. At the conclusion of the test MCC reported that this engine was in 

storage for two years and may have suffered deterioration during that the. In part as a result of 

these events, we decided to base our assessment of modular cogeneration in the Navy on a unit 

sold by a different company, one with a larger customer base and which at 120 kW is more 

appropriately sized to the needs of Navy bases. 

. 

C-8 
APPENDIX D: Cogenerating Fuel Cells 

SERDP is funding a demonstration project to determine the applicability of this 

technology to U.S. military installations. (SERDP ID #641) Because fuel cells are potentially 

a strong competitor to reciprocating engine cogeneration, we include here a brief summary of 

the technology and its current and likely future state. 

Fuel-cell power generation units provide another option for meeting commercial and 

industrial electric energy demands as environmentally clean, efficient sources of power and 

heat.'12 All fuel cells are cogeneration machines by their inherent operation. Fuel cells rely on 

an electrochemical reaction of hydrogen and oxygen which generates both electricity and heat. 

Today, the lowest cost source of hydrogen for a fuel cell is through the conversion of natural 

gas in a catalytic reformer. In a fuel cell hydrogen and oxygen are combined in an electrolyte, 

an electrically conductive material, such as phosphoric acid. The fuel cell process is nearly 

twice as efficient as steam turbine power generation because the fuel is processed into 

electricity through chemical reactions without being combusted. Fuel cells are in a way 

similar to batteries, but they can operate continuously as long as they have a fuel source. The 

fuel cell emits carbon-dioxide, the major component, along with very small emissions of 

nitrogen oxides, carbon-monoxide, and hydrocarbons. The amount of carbon-dioxide is lower 

than with conventional fuel fired power plants when efficiency factors are taken into account. 

Fuel cell operation is very quiet and noise is not a site selection criteria problem as with most 

power generation equipment. 

The earliest fuel cell types were based on alkaline electrolytes and are historically 

linked to manned space flights in the NASA Gemini and Apollo missions. Today, only three 

basic fuel cell types are considered practical for power generation here on earth. These 

include phosphoric acid, molten carbonate, and solid oxide. 

The three major components in these systems are the fuel processing section, the power 

section which generates the heat and electrical power, and the power conditioning section. 

The fuel processor takes in ~tural gas along with steam and heat from the power section and 

outputs a hydrogen rich gas to the power section and relatively clean exhaust products. The 

power section takes in air (oxygen) and the hydrogen rich gas and by the fuel cells chemical 

reactions results in direct current electric power, water, steam and heat, and again a relatively 

clean exhaust. The power conditioner converts the direct current into an alternating current, 

controlling frequency to match the local electric utility system and sends the power onto the 

utility grid. The excess heat from the fuel cell system is then available for other uses. 

The phosphoric acid fuel cell has recently been introduced into the U.S. market by 

ONSI Corporation, a subsidiary of International Fuel Cells Corp., a subsidiary of United 

Technologies COT. , which manufactures a 200 kW packaged fuel 

acid fuel cell operates at temperatures up to 400F, with a 36% - 39% electrical efficiency, and 

80 percent overall (electric and heat) efficiency. Heat rejection from the ONSI unit is 

currently at 18OF, but a large portion could be extracted at 350F as is the practice with the 

fms in Japan that are also building systems of this type. The advantages of doing so include 

The phosphoric 

D-1 
facilitating the interface with building space/water heating systems and the option of using the 

reject heat to drive heat-activated air conditioning systems such as double effect absorption and 

desiccant technology. The latter issue is the primary reason the efforts in Japanme to extract 

the heat at the highest temperature possible. In Japan four companies are commercializing 

and/or developing phosphoric acid fuel cells in the 200 kW - 1000 kW size range and in the 

U.S. Fuel Cell Corporation of America was recently formed to take over the air-cooled 

phosphoric acid fuel cell technology developed by Westinghouse Corporation over the last 

decade. These efforts are expected to result in additional product availability in the U.S. in 

the short term. Cost are currently close to $3,OOO/kW and with increased production volume 

are targeted to fall to $1,5OO/kW. Federal funding approved in the September 26, 1994 . 

Defense Appropriations Conference Report provided a total of $18,000,000 for cost sharing 

"Innovative Environmental Security Technology Systems" including phosphoric acid fuel cells. 

The Federal cost share allows for up to $1,000 per kW of capacity not to exceed one-third of 

the total cost. This would bring the immediate cost of phosphoric fuel cells down to the $2,000 

per kW for systems installed under this Federal program. 

The molten carbonate fuel cell is about five years away from market introd~ction.'*~ It

is expected to operate with a temperature of 1200F, with a 45-55 electrical efficiency, and a 

75-80 overall efficiency. One version of the molten carbonate Unit is currently being field 

tested by the Gas Research Institute. It is a 250 kW scaled down version of what will 

eventually be a 1-MX unit targeted for market introduction in the year 2000. 

Research is also ongoing in the development of solid oxide fuel cells that are projected 

to have a working temperature of 1800F with 45-47% electric efficiency and 75-80% overall 

efficiency.' Solid oxide fuel cells hold the promise of directly reforming the natural gas in the 

power section rather than using two separate major components in the system design. 

However, the solid oxide fuel cells are not expected to be available any time soon. 

The practical choice of a terrestrial fuel cell today is limited to the sole availability of 

the phosphoric acid fuel cell in the marketplace. The ONSI PC25 C phosphoric acid fuel cell 

is a self- contained 200 kW fully enclosed unit ready for installation on a poured concrete slab. 

It is available for a fixed price ($600,000 without Federal cost sharing of $200,000 currently 

available) and under wmanty. The units have an integral power conditioner to ensure 

instantaneous load-following response with tight frequency control, even under transient 

operating conditions. They also provide 700,000 Btu/hr of hot water or low pressure steam. 

Current production capacity is estimated at 200 units per year. 

The phosphoric acid fuel cell is a technology now entering the commercial marketplace 

after several years of development and extensive testing. Although its record of commercial 

success in the private sector is rather limited it has a somewhat impressive performance record 

to date. Over 70 ONSI 200 kW units have been installed in twelve countries in North 

America, Asia, and Europe. There has been over three quarters of a million operating hours 

and individual units have time exceeding 2.5 years (22,000 hours). Under commercial 

production support conditiops, the units in the United States have demonstrated overall 

D-2 
availability exceeding 96% and have unscheduled outage intervals averaging over three 

months. The average unit uses over 60% of the available heat. 

References for Appendix D: 

1. P. Teagen, "Fuel Cells for Building Cogeneration Applications - Cosflerformance 

Requirements and Markets", Draft Report for the U.S. DOE/OBT/BED, Arthur D. 

Little, January 1995. 

2. J. Kimball, "Fuel Cells - A Clean Efficient Source of Heat and Power", Gas Research 

Institute Technology Focus Sheet, June 1995. 

3. J. Kimball, "Phosphoric Acid Fuel Cells for Onsite Power Generation", Gas Research 

Institute - Tech Profile, June 1995. 

4. G. Sandelli, ONSI Corp. Technical Information Sheets and Reports describing the 

PC25 Model C Fuel Cell Power Plant. 

5. E. Cicchetti, Editor, "End Use Highlights - Molten Carbonate Fuel Cell Begins 

Operation", Gas Research Institute Digest, Summer 1995, Volume 18, Number 2. 

D-3