Energy Supply Options for Modernizing

Army Heating Systems

Michael K. Brewer, Thomas E. Durbin, Chris Dilks, Roch A. Ducey, Vicki L. Van Blaricum,

William T. Brown, William R. Taylor, Mark Imel, Vincent F. Hock, and Martin J. Savoie

Most Army central heating plants (CHPs) are

about 30 years old. Many are nearing the end of

their expected lives and experience poor combustion, low thermal efficiencies, and reliability

problems. The most common solution for faulty

CHP equipment is to replace it with the same

technology. In some cases, however, the solution

is to replace the large central system with many

smaller, distributed gas-fired boiler systems.

Although modernization of equipment can help

avoid the high cost of the air pollution control

equipment required for new energy supply facilities, the economic benefits gained from the early

modernization programs have changed the life

extension philosophy at most utilities. Utilities now

view modernization as a long-term strategy or an

ongoing policy for maintenance of and investment

in existing power plants, not simply as a way to

avoid the high cost of air pollution equipment.

This report describes a screening tool and procedures to evaluate energy supply options to modernize or decentralize CHPs. The screening tool

is to be used for a first level analysis of the suitability of central or decentralized plants using

basic economic, climate, and real property data.

If warranted, a more detailed conceptual analysis

can be conducted which would then be the basis

for initiating an energy supply implementation plan

at the site. These guidelines do not represent a

specific modernization program but rather a

process to be adapted to specific needs at the

Major Army Command and installation levels.

US Army Corps

of Engineers

Construction Engineering

Research Laboratories

USACERL Technical Report 99/23

January 1999

Approved for public release; distribution is unlimited.

Energy Cost vs Peak Energ y Density

0

20

40

60

80

100

0 0.5 1

Peak Energ y Use Density (MBTU/hr/acre land)

Energy Cost Delivered 

($/MBTU)

LTHW - Gas

STEAM - Gas

Steam - Oil

LTHW - Oil
USACERL TR 99/23 1

SF 298
2 USACERL TR 99/23

Foreword

This study was conducted for U.S. Army Corps of Engineers (USACE) under

Project 4A162784AT45, “Energy and Energy Conservation;” Work Unit UL-XC7,

"Advanced Energy Supply Technology." The technical monitor was Tim Gordon,

CEMP-ET.

The work was performed by the Utilities Division (UL-U) of the Utilities and Industrial Operations Laboratory (UL), U.S. Army Construction Engineering Research Laboratories (USACERL). The USACERL principal investigator was

Michael K. Brewer. Martin J. Savoie is Acting Chief, CECER-UL-U; Dr. John T.

Bandy is Operations Chief, CECER-UL. The USACERL technical editor was

Linda L. Wheatley, Technical Information Team.

Dr. Michael J. O'Connor is Director of USACERL.
USACERL TR 99/23 3

Contents

SF 298.................................................................................................................................................... 1

Foreword ............................................................................................................................................... 2

1 Introduction ................................................................................................................................... 7

Background .........................................................................................................................7

Objective .............................................................................................................................8

Approach.............................................................................................................................8

Mode of Technology Transfer...............................................................................................9

Units of Weight and Measure..............................................................................................9

2 Thermal and Economic Factors............................................................................................... 10

Thermal Factors ................................................................................................................10

Economic Factors..............................................................................................................11

3 Policy Factors.............................................................................................................................. 13

Regulatory Forces.............................................................................................................13

Fuel Security .....................................................................................................................14

Policy Forces.....................................................................................................................14

Base Realignment and Closure ...................................................................................................15

Energy Legislation .......................................................................................................................15

Privatization .................................................................................................................................15

Project Authorization .........................................................................................................16

4 Energy Supply Methodology.................................................................................................... 17

Overview ...........................................................................................................................17

Initiate Development of a Modernization Program .......................................................................17

Define Program Objectives ..........................................................................................................19

Establish Program Resource Requirements and Schedule .........................................................20

Evaluate Technical and Economic Feasibility of Alternatives .......................................................20

Rank and Select Alternatives.......................................................................................................20

Energy Supply Screening Tool ..........................................................................................21

Conceptual Analysis Tool ..................................................................................................22

HEATMAP .........................................................................................................................22
4 USACERL TR 99/23

5 Heating Plant Modernization and Energy Supply Optimization......................................... 28

Introduction and Objectives...............................................................................................28

Risks and Uncertainties ....................................................................................................28

Overview of the Central Heating Plant Modernization Program .......................................29

Planned Modernization Projects (FY98-FY02) .................................................................29

Energy Supply Analysis Sites in CHP MOD .....................................................................30

Fort Eustis....................................................................................................................................30

Fort Riley .....................................................................................................................................31

Fort Carson..................................................................................................................................34

Other CHP MOD sites.......................................................................................................36

Fort Drum.....................................................................................................................................36

Fort Campbell ..............................................................................................................................39

6 Future Energy Supply Issues................................................................................................... 43

Low NOx Limits .................................................................................................................43

Micro-Cogeneration...........................................................................................................43

Fuel Cell Cogeneration .....................................................................................................44

Photovoltaics.....................................................................................................................44

7 Summary...................................................................................................................................... 46

References.......................................................................................................................................... 47

Cited..................................................................................................................................47

Uncited ..............................................................................................................................48

Appendix: Advanced Energy Supply Analyses .......................................................................... 51

Fort Carson Screening......................................................................................................51

Fort Eustis Screening........................................................................................................59

Fort Riley Screening..........................................................................................................66
USACERL TR 99/23 5

List of Figures and Tables

Figures

1 Historical gas and oil prices.......................................................................................14

2 Energy supply analysis..............................................................................................18

3 Energy cost versus peak energy density. ..................................................................22

4 HEATMAP AutoCAD interface. ..................................................................................23

5 HEATMAP cunsumers interface. ...............................................................................24

6 HEATMAP production plant interface. .......................................................................25

7 HEATMAP flow analysis. ...........................................................................................25

8 HEATMAP economic analysis output. .......................................................................26

9 HEATMAP load duration curve output.......................................................................27

10 Steam flow versus daily temperature, Fort Campbell, KY.........................................40

Tables

1 Planned modernization projects (FY98-FY02) ..........................................................29

2 Fort Riley non-energy related project costs...............................................................34

3 Fort Campbell life-cycle cost summary......................................................................42

4 Federal Nitrogen Oxide limits for subpart Db steam generating units.......................43
6 USACERL TR 99/23
USACERL TR 99/23 7

1 Introduction

Background

Most Army central heating plants (CHPs) are about 30 years old; many are

nearing the end of their expected lives and experience poor combustion, low

thermal efficiencies, and reliability problems. The root cause of these problems

is frequently overlooked. Because of its age, the most common solution for faulty

equipment is to replace it with the same technology. In some cases, the solution

is to replace the CHP with smaller, distributed gas-fired boiler systems. This action is frequently taken without a thorough evaluation of the energy supply

strategy.

Private industry has been interested in optimizing its thermal energy supply

methods for many years. To compete in the global market, companies continually evaluate all facets of their operation to look for opportunities to reduce cost

and improve quality. The cost and reliability of energy for an operation must be

controlled to maintain profitability. For example, DuPont has had a formal

boiler life extension program since 1959 (Perkins 1986). This program was developed to formalize periodic inspections and repairs in greater detail than standard annual maintenance and overhauls, and was designed for boilers ranging

from small, low-pressure heating boilers for warehouses to 325,000 pounds per

hour (lb/h) pulverized coal-fired boilers and larger oil- and gas-fired boilers. Interest in modernization has also increased since the Clean Air Act (CAA) was

promulgated in 1972. Modernization can help avoid the high cost of air pollution

control equipment required for new energy supply facilities. The economic benefits gained from the early modernization programs changed the life extension

philosophy at most utilities. Utilities now view modernization as a long-term

strategy or an ongoing policy for maintenance of and investment in existing

power plants, not simply as a way to avoid the high cost of air pollution equipment (Electric Power Research Institute [EPRI] 1987).

With the increased cost of managing and operating central coal fired plants, several industries are switching to gas-fired central boilers or decentralized boilers.

A few companies have also outsourced the thermal energy supply utilities to

third party contractors to allow the organization to focus its capital on core business functions. At Dupont's Louisville plant, a coal-fired cogeneration plant with
8 USACERL TR 99/23

steam-drive chillers was decommissioned and replaced with package gas-fired

boilers and electric-motor chillers. Although DuPont engineering was reluctant

to analyze a decentralized option due to the cost of gas, after considering all

other costs such as labor, pollution prevention, and business cycle flexibility, they

concluded that the package boiler option gave the best value to the company

shareholders. It is interesting to note that, although DuPont had capital available for implementing the package boiler project, the return on investment could

not compete with other investment opportunities in the plant process. As a result, DuPont used third party financing from institutions looking for low risk,

low return (6 to 8 percent) investments (Dean 1998).

Objective

The overall objective of this project was to develop a screening tool and procedures to evaluate energy supply options to modernize or decentralize CHPs. The

guidelines do not represent a specific modernization program but rather a process to be adapted to specific needs at the Major Army Command (MACOM) and

installation levels. The screening tool is to be used for a first level analysis of the

suitability of central or decentralized plants using basic economic, climate, and

real property data. The number of data inputs should be small enough to be acquired in one or two telephone calls. The conceptual analysis guideline is a procedure to calculate the desirability of several energy supply options at a site.

The conceptual analysis results would then be the basis for initiating an energy

supply implementation plan at the site.

Approach

Historic, economic, regulatory, and market factors that have driven private industry and public utilities toward modernization and decentralization were reviewed to assess their applicability to the operating environment for Army

CHPs. A screening tool was then developed in a spreadsheet to calculate cost

curves of various central and decentralized heating systems. Next, a conceptual

analysis process was developed for more detailed economic and design evaluation

of energy supply technologies using HEATMAP* and a thermal and economic

modeling tool.

 

* See p 22 for a description of HEATMAP.
USACERL TR 99/23 9

Mode of Technology Transfer

The findings of this research effort will help focus CERL’s research efforts for the

Army’s Modernization Technologies for Central Heating Plants program. The

tools developed in this research also were used to support the Army Chief of

Staff for Installation Management (ACSIM) CHP modernization program.

It is recommended that the results be used to update Army guidance documents,

including Architect and Engineers Instructions (AEIs), Army Regulation (AR)

420-49, Heating, Energy Selection and Fuel Storage, Distribution, and Dispensing Systems and Technical Manual (TM) 5-650, Repairs and Utilities: Central

Boiler Plants.

Units of Weight and Measure

U.S. standard units of measure are used throughout this report. A table of conversion factors for Standard International (SI) units is provided below.

SI conversion factors

1 in. = 2.54 cm

1 sq ft = 0.093 m2

1 gal = 3.78 L

1 lb = 0.453 kg

1 psi = 6.89 kPa

°F =(°C x 1.8) + 32
10 USACERL TR 99/23

2 Thermal and Economic Factors

Thermal Factors

Many of the Army CHPs were constructed in the 1940s–50s. The prevailing

plant design relied on low-cost solid fuel (coal), a large well-trained labor pool,

and few pollution control systems. Additionally, dual fuel security was a top concern, especially after the national coal strike in the late 1950s. Plants needed to

have large stockpiles of fuel and the ability to switch fuels to keep the base

heated. If coal is the primary fuel, a central plant is the more efficient and

cleaner than many small hand-fired boilers. Steam generated at the plant could

be piped to the buildings for “clean, dust-free” heat. A central plant also requires

a smaller total boiler capacity because of the diversity of peak loads among a

collection of buildings. Central steam plants also make possible the production

of electricity for the base.

With the growth of the gas industry and the increase in emission control requirements, gas-fired boilers have replaced most of the coal-fired systems. Central gas-fired boilers still offer the possibility of dual-fueled systems as most of

these systems can be ordered with both oil and gas burners. However, the gasfired central plants now must compete against small unattended gas boilers, water heaters, and furnaces. Often the higher costs of uninterruptible natural gas

(30 to 40 percent price premium) can be offset by the reductions in skilled labor

and elimination of distribution system losses.

To assess the desirability of CHPs versus decentralized heating plants, the energy use density needs to be considered. The energy supply problem is solved by

correctly balancing the losses of moving the steam and hot water through the

distribution system against the inefficiencies of oversized or cycling decentralized conversion equipment. Marketing and feasibility studies in North America

and northern Europe have shown that high peak energy use density

(MBtu/hr/acre) and high load factor are important factors for ensuring profitable

district heating plant projects (Bloomquist 1987). As cited by Bloomquist,

Wahlman reports that, in general, district heating plants are favorable at densities greater than 0.7 MBtu/hr/acre, possible at 0.28 to 0.7 MBtu/hr/acre and unfavorable or questionable at less than 0.28 MBtu/hr/acre.
USACERL TR 99/23 11

Economic Factors

CHP modernization or decentralization projects require cost analysis to determine if they make economic sense. Cost-effectiveness analyses need to be done

on a life-cycle cost basis, which, for DoD projects, requires a 25-yr project life.

For central plants, several economic issues need to be considered:

• High maintenance/low reliability—Many DoD CHP boilers are 30 years old,

or more, and are pushing performance limits. The older, less reliable boilers

have higher maintenance costs and increased potential for failure, increasing

the need to consider either construction of a new boiler unit or modernization

of the existing unit.

• High cost of capital to build new unit—Costs of complying with environmental, siting, and safety regulations add to the construction cost of new

CHP units. Modernization programs have the potential advantage of lowering capital investment since existing units are merely retrofitted and upgraded.

• Poor performance of existing CHP—System optimization tasks may need to

be undertaken. Incorporating advances in boiler system design may become

a cost-effective means to improve system performance.

• Distribution system maintenance—The steam and condensate system requires an aggressive maintenance program and a reliable water treatment

system. A steam trap life span is only 2 to 5 years depending on its type and

location in the system.

• Three-shift operations—Depending on the jurisdiction, certain boiler sizes

(usually industrial sizes) require attendants. The jurisdiction may require at

least two personnel in a boiler plant if it is considered a hazardous materials

space. A staff of 10 to 13 operating personnel may be needed just to meet the

attendance and safety regulations.

For decentralized plants, the following issues need to be considered:

• Boiler safety equipment maintenance—Every boiler will have at least one

safety valve and fuel train requiring maintenance. Maintenance on the

safety system cannot be deferred. A fixed amount of maintenance is required

on a commercial or industrial boiler regardless of its size.
12 USACERL TR 99/23

• Firm gas price fluctuations—Smaller boilers will only be fueled with gas.

Firm (uninterruptible) priced gas will cost 30 to 40 percent more than the locally available, interruptible gas supply.

• Contractor support—In most areas, a larger pool of contractors will be qualified to operate and maintain smaller commercial sized boilers than for larger

industrial-size boilers.
USACERL TR 99/23 13

3 Policy Factors

Several policy issues set the framework for energy supply in addition to the

thermal and economic factors. Regulatory, fuel security, and program funding

issues frequently impact the feasibility of modernization or decentralization.

Regulatory Forces

Regulatory forces may have two types of effects on an existing CHP: regulations

may require an upgrade of the CHP, or regulations may make decentralization

preferable to upgrading or building a new CHP. Regulations that affect CHP operation include environmental compliance regulations, siting clearances for new

units, and safety code regulations.

Environmental regulations include the amended CAA, which applies more stringent emissions limits on particulate matter, sulfur dioxide (SO2), nitrogen oxides

(NOx), carbon monoxide (CO), air toxins, and volatile organic compounds

(VOCs). Additionally, the CAA calls for the complete phaseout of chlorinated

fluorocarbons (CFCs) and certain other stratospheric ozone-depleting substances.

CHP combustion produces SO2 and NOx in amounts that vary with fuel type.

Since natural gas is the primary fuel used at most DoD installations, NOx emission is the primary pollutant.

Utilities, industry, and the military face the same regulatory forces. The differences lie in the magnitude of pollution potential and in the ease of obtaining

siting clearances. Utility fossil-fired plants tend to have higher annual fuel input than industrial or military plants, which may lead to more concern about

pollution at utility plants. New utility projects require new site clearances that

require action from several regulatory bodies. Industrial and military projects,

however, tend to be on sites under their respective control.
14 USACERL TR 99/23

Fuel Security

CHPs provide the opportunity to fire multiple fuels. If a burner conversion or

upgrade is needed, it is easier to modify a few boilers at a central plant than 100

or so small boilers throughout the system. If oil capability is needed to augment

natural gas, it is easier to manage a few centrally located oil storage tanks than

a large number of small tanks. Small decentralized boilers are almost always

gas fired, although a few electric boilers may provide point-of-use hot water or

steam. These small gas-fired boilers will need an uninterruptible gas supply

unless the site can permit the space to be unheated. As mentioned earlier, the

price premium for firm (uninterruptible) gas is 30 to 40 percent above the available interruptible gas price. Figure 1 shows the fluctuations of gas and oil

prices. The firm gas prices may vary as much as $2/MBtu over the course of a

year (EIA 1998). Base managers need to account for the price risk when analyzing the feasibility of decentralizing or modernizing a CHP.

Policy Forces

Many policies within the DoD and the Army affect energy supply planning.

These policies can be broadly categorized as base realignment and closure

(BRAC), energy legislation, privatization, and project authorization.

Figure 1. Historical gas and oil prices.
USACERL TR 99/23 15

Base Realignment and Closure

The BRAC Commission was chartered on 3 May 1988 to develop recommendations for improving the effectiveness of military installations through realignment of missions and base closures. As of March 1993, BRAC had identified over

400 military installations for realignment or closure. Realignments add or remove activities from an installation that may ultimately change the installation's energy demands.

Energy Legislation

The Energy Policy Act of 1992 (Public Law [PL] 102-486) Subtitle F, Federal

Agency Energy Management, establishes several Federal agency goals and requirements. It amends sections of the National Energy Conservation Policy Act

to reflect and supplement goals and requirements established in Executive Order

12759, Federal Energy Management. It contains provisions regarding energy

management requirements, life-cycle cost methodology, budget treatment for energy conservation measures, incentives for Federal agencies, reporting requirements, new technology demonstrations, and agency surveys of energy savings

potential. The DoD establishes guidelines for meeting Federal energy goals with

Defense Energy Program Policy Memorandums (DEPPMs) such as DEPPM 91-2,

Implementing Defense Energy Management Goals. The Army issues memorandums to support Department of Defense (DoD) goals.

Privatization

AR 420-49 has been revised and requires life-cycle cost analysis and comparison

of Army-owned heating plants and systems with private and municipal alternatives. Additionally, the Defense Reform Initiative (DRI 1997) states, “By January 1, 2000, the Department will privatize all utility systems (electric, water,

waste water and natural gas) except those needed for unique security reasons or

when privatization is uneconomical.” Although boiler plants are not listed in the

DRI, it can be inferred that, if economical and feasible, privatizing thermal utilities would support the DRI’s intent, which is to divest DoD of activities not directly related to the main function of the military services, that function being to

sustain combat operations.
16 USACERL TR 99/23

Project Authorization

Authorization policies are probably the most important because they dictate how

most energy projects will be developed. The following steps summarize the project decision sequence:

• Project originated at DoD installation.

• U.S. Army Corps of Engineers (USACE) district office does the project design.

• MACOM does a technical review of the project design, which covers project

viability, project need based on its justification, and project economics (lifecycle cost). The MACOM reviews all projects, regardless of the project cost.

They review the design at the 35, 65, and 95 percent completion stages.

• Onsite personnel and Architect and Engineer (A&E) contractors are used to

implement the projects. Onsite personnel capabilities vary from installation

to installation.
USACERL TR 99/23 17

4 Energy Supply Methodology

Overview

Because the energy supply and use, heating plant performance requirements,

and operational needs of each installation present different demands on modernization programs, the planning process guidelines presented here do not attempt to specify a single approach for modernizing all CHPs. Rather, these

guidelines are intended to be general. The guidelines were developed by reviewing the literature by industry and performing modernization studies at

Army installations. The guidelines identify a process that typically meets the

needs of most Army and DoD installations.

The process provides for two levels of analysis. The first screening analysis

quantifies thermal and economic parameters for the whole base. The second

level is a more detailed analysis of plausible energy supply scenarios. Figure 2 is

a flowchart of the energy supply analysis process.

Initiate Development of a Modernization Program

Modernization is a multidiscipline activity. It requires input and cooperation of

design engineers, plant operation and maintenance managers, construction experts, economic and financial analysts, environmental analysts, energy and fuel

purchase policymakers, research and development groups, equipment life analysts, and several levels of management.

To develop a program plan, a modernization team must develop program objectives, review and analyze certain system data, and provide resources for carrying

out program activities. In addition, formal review and analyses are required of

the Army’s present and future energy supply and demand forecasts, the Army’s

energy policy, energy market forces, and many other factors that affect the overall “business” environment within the Army.
18 USACERL TR 99/23

Energy 

Suppy 

Evaluation

Summary Real 

Property Data 

(Acres, Sq Feet)

Energy Costs, 

Climate (HDD, 

Design day

Screening Tool

(adv-ener.xls)

Are curves 

adeaquate for 

mgt?

Retain Analysis

Define 

energy 

study 

objectives

Heatmap Analysis for 

current conditions

Labor Costs, 

Contractor Costs, 

Mission 

Requirements

Real Property 

Data, AutoCAD 

map, Boiler Logs, 

Energy Bills

Boiler and Pipe 

Inspections

Do Heatmap 

results agree 

with logs?

Heatmap Analysis for 

selected scenarios

Installation Future 

Mission 

Requirements

Installation Future 

Energy 

Constraints Are selected 

Heatmap scenarios 

viable?

HEATMAP report

Modify 

scenario 

conditions 

and/or 

assumptions

N

Y

Y

N

N

Y

Figure 2. Energy supply analysis.
USACERL TR 99/23 19

Define Program Objectives

Establishing the modernization program objective at the earliest possible stage

is very important since it will guide development of the policies and tactical decisions to be made later in the program. The objective should be discussed among

team members, and all members should understand what is expected from the

modernization program. Examples of objective statements for modernization

programs include:

• The objective of this modernization program is to systematically assess the

condition of the major equipment at the Army's CHPs to ensure efficient and

reliable operation of the plants beyond their designed life. Capacity improvements or efficiency improvements are not a part of this modernization

program.

• The objective of this modernization program is to extend the lives of the

Fort’s central heating plants so they can operate safely, reliably, and cost effectively beyond their original design life.

• The objective of the modernization program is to extend the lives of central

heating plants beyond their original design life while improving reliability,

availability, efficiency, and environmental safety at installations where the

heating and cooling demand is expected to increase by over “X” percent over

the next “Y” years.

In addition, the objective statement should define the:

• desired technical and economic performance for the refurbished equipment

• desired fuel purchase policy (e.g., centralized vs distributed)

• difference between fuel cost and nonfuel operations and maintenance (O&M)

costs

• specific environmental goals that must be met

• preference between purchase of new equipment or a technically equivalent

repair option with higher expected O&M costs.

However, at this planning stage, the objective statement should not indicate how

these objectives should be met. For example, the statement should not specify
20 USACERL TR 99/23

the timing of life extension or whether the life extension should include modernization or equipment upgrade. The timing and the need for modernization or

equipment upgrade can be assessed more accurately at the installation or plant

planning levels.

Establish Program Resource Requirements and Schedule

It is important to set achievable goals for the initial planning study, to set ample

time for gathering and evaluating the required data, and to determine the required and available resources. Developing costs and schedules for installations

with one or more CHPs and several potential modernization projects could become very cumbersome and difficult to manage. It may be advisable to attempt

first to identify previously implemented life extension projects at DoD’s CHPs or

similar projects. An initial planning study would be undertaken for a selected

number of installations based on information from these projects. As cost and

scheduling information is integrated with the base and heat plant planning issues for these installations, a revised program could be developed to address the

next few installations that could logically be developed for modernization.

Evaluate Technical and Economic Feasibility of Alternatives

At this planning level, the main questions are: what options should be considered, which plants should receive modernization first, and what are the technical

and economic benefits and risks associated with the proposed actions? To answer these questions, three activities may have to be pursued. First, a visual

inspection of the plants may have to be performed. Second, the operators and

maintenance personnel may have to be interviewed. Third, the O&M procedures

may have to be reviewed to identify potential systems, subsystems, or equipment

that would require repair, replacement, upgrade, or refurbishment. In addition,

alternatives to modernization must be identified in accordance with the program

objective. Preliminary concept drawings must be developed when needed. Cost

estimates for new equipment must be developed. Capital and operating costs

must be estimated, and economic analyses must be performed for each alternative. The result of these analyses can then be used to rank various alternatives

based either on economic merit alone or in conjunction with other factors.

Rank and Select Alternatives

Ranking methodologies consistent with the program goals should be developed

for ranking, prioritizing, and selecting energy supply alternatives. The ranking

methodology needs to consider the accuracy and quality of available information

collected for each possible alternative so as not to bias the analysis.
USACERL TR 99/23 21

Energy Supply Screening Tool

The energy supply screening tool was developed to quickly calculate cost curves

for several energy supply options. As mentioned above, the energy use density is

a significant parameter for determining the profitability of a central or decentralized heat system. The cost curve for decentralized boilers is level for practical purposes. The cost of heat from a boiler serving a remote building is not

much different than the cost of heating an urban building. Costs may differ due

to variations in labor and material prices, but any effect due to heat transfer or

heat loss is minimal. However, there will be different costs for different sized

boilers. In general, as equipment is scaled up or down the price varies about 70

percent of the magnitude of the equipment size. Also, for a boiler or hot water

heater of any size, there will be a minimum fixed maintenance cost for the safety

components. Another price premium on small boilers is due to the oversizing of

the decentralized equipment to provide redundancy.

The cost of a central plant on a per-MBtu-delivered basis will sharply escalate as

the buildings are more dispersed in the heating district. The flow and heat

losses of the distribution system will consume the economy of scale savings from

having larger central boilers. Ideally, for the same climate and fuel cost, the cost

of a central plant in a densely built heat district will approach the cost of a very

large decentralized boiler.

Figure 3 shows the curves calculated for Fort Eustis, VA. The central plant cost

curves for low temperature hot water (LTHW) are slightly lower than the steam

cost curves, because the thermal losses for hot water systems are less. Electrical

costs will be increased, however, due to the need for more pumping power.

The cost curves were developed by analyzing the costs at eight Army CHPs.

HEATMAP studies were conducted at the sites to calculate capital and operational costs. These studies were calibrated against plant logs so the heat losses

at the site climate were realistic. Next, the eight data sets were run at three different uniform fuel costs to develop a characteristic curve as a function of fuel

price and energy density. The HEATMAP study sets were next analyzed across

five climates from the range of 2,000 to 10,000 heating degree days (HDD). More

general cost equations were developed that predict the energy cost as a function

of energy use density, climate, and fuel cost.
22 USACERL TR 99/23

0

10

20

30

40

50

60

70

80

90

0 0.2 0.4 0.6 0.8 1 1.2 Peak Energy Use Density (MBTU/hr/acre land)

Energy Cost Delivered ($/MBTU)

STEAM - Gas LTHW - Gas

Steam - Oil LTHW - Oil

Sm Gas 

Lg Gas Boiler

Med Gas Boiler

Figure 3. Energy cost versus peak energy density.

Conceptual Analysis Tool

If a more detailed study is needed, conceptual analysis using HEATMAP is conducted. HEATMAP analysis requires some basic building information such as

area, type, and function. As described in Figure 2, the evaluation team will need

to collect basic equipment condition and performance information. Monthly

boiler logs and daily logs from a few load defining days such as peak winter load,

minimum summer load, peak summer load, and holiday peak loads are usually

sufficient for analysis. Due to the lack of a gauge calibration program at some

locations, the evaluation team needs to scrutinize the logs for accuracy. Sometimes the only reliable measurement of plant load is the fuel consumption data.

HEATMAP

HEATMAP is a computerized system that provides a fast and reliable means for

modeling the operation and economics of district heating and cooling (DHC) systems. HEATMAP graphically models the thermal, hydraulic, and economic

characteristics of a DHC system. Its ease of use stems from the reliance on

many preloaded data libraries. Default data are sufficient to get an analysis

completed with only partial site data. As more detailed data are discovered, the

model can be updated quickly. Additionally, almost all of the underlying library

data is visible to the analyst if needed.
USACERL TR 99/23 23

Although primarily designed to model proposed DHC systems, HEATMAP functions equally well in modeling existing systems. HEATMAP will take information related to the study area, production plants, and distribution network, and

size the district heating and cooling system to meet thermal requirements.

HEATMAP will optimize the mechanical facilities associated with DHC (i.e., pipe

size and plant size). In addition, HEATMAP has the ability to model building

loads and to determine the environmental impact of various DHC options.

HEATMAP uses actual information, where available, and provides engineering

estimates elsewhere.

HEATMAP is a standalone program that interfaces with the proprietary software AutoCAD 13c4 or 14 and LFLOW-2F. Figure 4 shows a HEATMAP AutoCAD interface screen.

The AutoCAD program provides a means for graphically representing the DHC

system. Figures 5 through 6 show how, within an AutoCAD “map” of an installation, the user can identify and locate consumers, production plants, and existing

or proposed distribution lines. The LFLOW-2F program then models and analyzes the distribution system operation based on the map developed with the

AutoCAD program (refer to Figure 7).

Figure 4. HEATMAP AutoCAD interface.
24 USACERL TR 99/23

HEATMAP was developed by the Washington State Energy Office (WSEO) at

Washington State University (WSU) in conjunction with several public and private organizations. USACERL is a partner with WSU/WSEO in the continuing

development and enhancement of the HEATMAP program. WSU/WSEO also is

developing modules for gas, water, wastewater, and electricity. The gas module,

GASMAP will be particularly useful for conducting central versus decentral heat

system analysis. These modules will operate together as a suite called

UTILITYMAP. UTILITYMAP promises to enhance the evaluation of utility supply and delivery options by combining several analysis tools into one package.

Figure 5. HEATMAP consumer interface.
USACERL TR 99/23 25

Figure 6. HEATMAP production plant interface.

Figure 7. HEATMAP flow analysis.
26 USACERL TR 99/23

HEATMAP uses the AutoLISP program in AutoCAD to take the graphical input

to populate a Microsoft Access database in HEATMAP. Once the data is input,

AutoCAD is not necessary unless the pipe layout is changed. HEATMAP ports

the building name over to the database and creates a record for the building with

a default size of 5,000 sq ft. The user then selects a function from a pick list and

modifies the building area information. If building load information is unknown,

the user will request that HEATMAP calculate annual figures for heat peak load,

energy use, domestic hot water load, and chill water load.

The results of the study (as shown in Figures 8 and 9) can then be used by base

planners to map out an implementation plan to realize the most effective energy

supply plan for the site.

Figure 8. HEATMAP economic analysis output.
USACERL TR 99/23 27

Figure 9. HEATMAP load duration curve output.
28 USACERL TR 99/23

5 Heating Plant Modernization and Energy

Supply Optimization

Introduction and Objectives

Modernization efforts for the Army’s CHPs can be broadly described as programs

that integrate the long range planning at the Department of the Army and

MACOMs with the installation level programs for equipment condition assessment, refurbishment, monitoring, and improvement of O&M procedures. The

life of a CHP is not limited by its nominal design life. Rather, it is limited by the

cost of continuing to operate that CHP while meeting certain technical, economic, and environmental performance requirements compared to the cost of

other available options (e.g., direct purchase of power or steam from other

sources, construction of a new plant, or decentralization). Consideration of modernization includes technical and economic analyses and evaluations similar to

those used when building a new CHP or decentralizing. As with new construction, plant performance (e.g., efficiency, availability) and cost factors (e.g., capital

equipment, operation, and maintenance) must be integrated with the safety, environmental, regulatory, funding, DoD energy policy (e.g., privatization, financial

risks, increased coal use), and fuel purchasing issues to make logical modernization decisions.

Currently, ACSIM is sponsoring a program to modernize about 30 heating systems. For these installations, it is vital to develop an energy supply strategy

that reflects technological advances for meeting environmental standards, forecasts of availability of fuel, and expectations of new mission requirements.

Risks and Uncertainties

Economic analysis of typical industrial and utility projects indicate that modernization could result in cost savings or economic benefits (EPRI, March 1987;

Council of Industrial Boiler Owners [CIBO], July 1989). However, any modernization program has inherent economic risks. For example, the longer the payback period or greater the life-cycle cost, the higher the risk that the failure of

the refurbished equipment or other equipment may interfere with total cost
USACERL TR 99/23 29

recovery. Another risk for fossil fuel plants—particularly coal-fired plants—for

which modernization is being considered, is uncertainty in regulations and permits.

Overview of the Central Heating Plant Modernization Program

The Army will be implementing CHP Modernization Projects (CHP MOD) at five

to six enduring installations per year starting in FY98 and going through FY02.

The Army will invest $60 million per year in the program ($300 million program

total). The program is focusing on upgrading the thermal utilities to the most

life-cycle cost-effective technology. CHPs and the associated distribution systems

are being assessed and compared to other alternatives such as decentralized

production, LTHW distribution, and hybrid energy plants. The advanced energy

supply analysis process has been very valuable in developing and evaluating

modernization plans. The appendix shows analyses for three of the installations.

Planned Modernization Projects (FY98-FY02)

Table 1 lists the projects in the planned modernization program. Some installations have more than one project. Final project approval and funding is contingent upon the installation’s ability to execute an economically favorable project

and obligate the funding on the project in one fiscal year.

Table 1. Planned modernization projects (FY98-FY02).

FY98 FY99 FY00 FY01 FY02 Unfunded

Meade Riley Carson Redstone Gordon Picatinny

Jackson Eustis Aberdeen PG Stewart Rucker Monmouth

Lewis Campbell Redstone Gordon Lee Bragg

Aberdeen PG Benning Leonard

Wood

Carson Carlisle

Barracks

Sill

Benning Wainwright Belvoir McNair Dix Knox

Belvoir Wainwright Hood Gillem

Drum Myer
30 USACERL TR 99/23

Energy Supply Analysis Sites in CHP MOD

Fort Eustis

Background information.

The base operations at Fort Eustis are government operated. The cantonment

areas encompass approximately 440 acres of land and 18.6 million sq ft of

buildings.

All of the heating plants are relatively small and unmanned. A utility monitoring control system (UMCS) by Johnson Controls is being installed in the boiler

plants. All of the systems are dual fueled by #2 oil and natural gas. High pressure (40-100 psig) and low pressure (< 15 psig) steam systems are used to provide heating and domestic hot water (DHW) to the buildings.

Heating plant survey.

In general, most of the plants and mechanical rooms were in fair to good condition. All of the plants will need some level of mechanical repair to realize the

maximum benefit of improving the controls with a UMCS. Although the new

METASYS* UMCS system will greatly improve the centralized monitoring and

control of the boiler plants, it is important that the mechanical pressure gauges,

flow meters, and thermometers be maintained. These local indicators are valuable troubleshooting tools to a mechanic first entering an equipment room on a

trouble call.

Fuel costs.

Current fuel costs at Fort Eustis are $0.53/gal ($3.87/MBtu) for #2 oil, and

$3.60/MBtu for natural gas. However, those rates are annual averages. The gas

rates at Fort Eustis vary widely over the course of the year. Also, there are cost

differentials for those buildings on firm (uninterruptible) rates.

 

* METASYS is a trademarked product of Johnson Controls, Milwaukee, WI.
USACERL TR 99/23 31

Energy screening.

The USACERL-developed energy screening tool described in Chapter 4 was used

to develop cost curves for different heating systems based on previous DoD plant

studies, Redbook* data, and utility bills from Fort Eustis. The aggregate energy

density of the entire cantonment area is about 0.79 MBtu/hr/acre. However, the

areas near the barracks may have energy densities that are much higher than

the base average. The curves indicate central plants are favorable in areas

where the density is above 0.6 MBtu/hr/acre (Figure 1). Decentralized systems

are definitely more favorable in regions with energy densities below 0.3

MBtu/hr/acre. This preliminary screening indicates that central heating systems that are in good condition should be preserved.

Summary.

Aboveground steam piping is the safest, most reliable, and least expensive system to install and maintain. However, loss of condensate is a problem at Fort

Eustis. Some of the condensate piping may need repair due to condensate

grooving. Some of the underground sections may have failed as well. Corrosion

of the condensate lines indicates that improvements may be needed to the water

treatment program. A chemical analysis of the boiler water and the condensate

should be performed to diagnose the cause of the problem and to determine the

proper remedy. If most of the buildings convert steam to LTHW for space heating, the steam pipe sizing should be checked for conversion to LTHW distribution

if the condensate systems have completely failed.

Fort Riley

Background.

The base operations at Fort Riley are government operated. The cantonment

areas encompass approximately 3,000 acres of land and 18.6 million sq ft of

buildings.

Due to the heating plant modernization program and the barracks upgrade program (BUP), Fort Riley was particularly interested in assessing the alternatives

in the 8000 area of Custer Hill. This area comprises 30 buildings including 12

 

* Redbook = Department of the Army Directorates of Public Works Annual Summary of Operations.
32 USACERL TR 99/23

barracks, company headquarters, battalion headquarters, a mess hall, gymnasium, detached day rooms, and training centers. Total building area is more

than 400,000 sq ft over an area of about 22 acres. With a peak combined building load of 13.2 MBtu/hr, the 8000 area has a peak energy density of 0.6

MBtu/hr/acre. The facilities were constructed in the mid-1970s. Part of the

BUP, design of the barracks is nearing completion and the first two barracks are

scheduled for renovation in FY99.

All heating and cooling in the area is provided by a central plant in Bldg 8073.

The plant houses two high-pressure steam, natural gas-fired boilers at 16

MBtu/hr (500 hp) each, and two single-effect steam absorption chillers at 440

tons each. This equipment is original and nearing the end of its useful life.

Maintenance of the high-pressure steam requires significant manpower.

High-pressure steam is distributed to the buildings year round for DHW production in the barracks, mess hall, and gymnasium. Winter heating is provided by

steam to hot water converters located in all buildings. Approximately half of the

8,000 linear feet of steam distribution system piping is in shallow trenches and

the remainder is direct buried. The shallow trench portion was constructed in

1990. The remaining direct buried portion is original and in poor condition.

During the summer, chilled water is distributed to all buildings. The chilled water distribution system is direct buried and in good condition.

The central heating/cooling system is in need of replacement. Eight heating and

cooling supply options were studied by USACERL in 1996 (Dilks 1996). Fort

Riley revisited the study in 1998 and developed five alternatives in lieu of a direct replacement of the existing system (Imel 1998). All of the revised options

call for replacing the absorption chillers with high efficiency electric units. The

existing chilled water distribution system will remain in use. The heating portions of the options are briefly summarized below.

Option A—This option changes the existing steam system to LTHW. All boilers

would be housed in the existing plant (Bldg 8073). Existing steam distribution

lines in shallow trench would be reused when the size was sufficient. The direct

buried portion of the system would be replaced with shallow trench. LTHW

would be provided year round and used by instantaneous hot water heaters in

the barracks, mess hall, and gymnasium. Other buildings would either have no

DHW or use small gas or electric units. The LTHW system would provide heat

in the winter.

Option B—This option is identical to Option A except that it runs gas lines to the

buildings using instantaneous DHW heaters. By replacing the instantaneous
USACERL TR 99/23 33

heaters with gas, the boiler and distribution sizes could be significantly reduced.

The LTHW system would only operate during the heating season as DHW is

produced by individual gas heaters.

Option C—This option splits the heat distribution system into two loops. An additional plant building would be constructed in the middle of the 8000 area. By

splitting the system, the existing steam lines in shallow trench would have sufficient size to be used for LTHW. The existing direct buried lines, along with any

new lines, would be placed in a shallow trench. The LTHW systems would operate year round to provide DHW.

Option D—This option eliminates the central heating system. Natural gas lines

would be installed to all buildings. Each building would have its own boiler or

furnace for heating. Buildings requiring DHW would have a gas heater. The

existing mechanical rooms in the barracks are not large enough for this equipment. However, the BUP design calls for the expansion of the mechanical room

into an existing sleeping room. This requires moving a non-load-bearing wall

and maintaining the required fire rating. The cost estimate for Option D includes the cost of the mechanical room expansion in the event the Utility Modernization Program (UMP) project precedes the BUP renovations.

Option E—This option is identical to Option A, except that storage-type DHW

systems are used in the barracks, mess hall, and gymnasium. By replacing the

existing instantaneous DHW heaters, the boiler and distribution line sizes can

be greatly reduced. The LTHW system would only operate during the heating

season.

Table 2 summarizes the non-energy costs related to each option. The construction cost estimates were developed by the A&E under contract to provide design

services. The costs do not include 6 percent SIOH* and 6 percent contingency

funds. Maintenance costs were developed after consultations with the O&M Division.

Option D has a lower life-cycle cost than the other options due to the much lower

construction costs. Fort Riley is proceeding with the design of Option D.

 

* SIOH = supervision, inspection, and overhead.
34 USACERL TR 99/23

Table 2. Fort Riley non-energy-related project costs.

Option Construction

Heating System

Construction

Cooling System

Construction

Total

Annual

Maintenance

A $4,380,124 $ 829,875 $5,209,999 $98,000/yr

B $3,833,138 $829,875 $4,663,013 $120,000/yr

C $3,816,056 $829,875 $4,645,931 $110,000/yr

D $2,129,323 $829,875 $2,959,198 $133,000/yr

E $3,175,956 $829,875 $4,005,831 $ 98,000/yr

Project status.

The FY99 Utilities Modernization Program Support Team visited Fort Riley 1-2

September 1998. The team had the opportunity to review design submittals for

the BUP as well as the heating plant modernization plans.

Fort Riley is planning on implementing a decentralized LTHW heating system in

the 8000 barracks area using an instantaneous gas system for DHW. The uninterruptible natural gas will be provided to all the buildings.

All the barracks will have expansion of their boiler rooms. The BUP contractor

can only work two barracks at a time throughout the course of the BUP.

Fort Carson

Background information.

The base operations at Fort Carson have been contractor operated for almost 10

years. The central cooling plants, CHPs, distribution systems, and building

HVAC systems are all operated and maintained by Pacific Architects and Engineers Incorporated (PAE). In FY96 PAE charged Fort Carson $68,000 for chiller

operations, $64,000 for chiller maintenance, $531,000 for heat system maintenance, and $389,000 for heat system operation. The cooling season runs from 15

June to 15 September and the heating season runs from 15 October to 15 May.

The cantonment area encompasses approximately 2,500 acres of land and 12.4

million sq ft of buildings.

High temperature hot water (HTHW) and steam are used to deliver heating and

DHW to the buildings. Four plants serve most of the buildings; one HTHW plant

(Bldg 1860), one HTHW/steam plant (Bldg 6290), and two steam plants (Bldgs
USACERL TR 99/23 35

9609 and 403). All of the plants except Building 403 are gas- and oil-fired.

Building 403 is gas-fired only.

In general, most of the plants and mechanical rooms were in good condition. The

main central chiller plant at Building 1864, however, was in urgent need of repair for the 1998 cooling season. Fort Carson was in the process of retubing one

of the chillers to meet the season’s cooling needs.

Fuel costs.

Current fuel costs at Fort Carson are $0.70/gal ($5.18/MBtu) for #2 oil, $0.99/gal

($10.42/MBtu) for propane, and $2.57/MBtu for natural gas. Fort Carson and

the U.S. Air Force Academy have combined their fuel needs to negotiate good

interruptible and firm gas rates from the City of Colorado Springs.

Data analysis.

The USACERL-developed energy screening tool discussed in Chapter 4 was used

to develop cost curves for different heating systems based on previous DoD plant

studies, Redbook data, and utility bills from Fort Carson. Although the energy

density of the entire cantonment area is about 0.31 MBtu/hr/acre, there are areas near the barracks where the density is much higher. The curves indicate

central plants are favorable in areas where the density is above 0.65

MBtu/hr/acre. Decentralized systems are definitely more favorable in regions

with energy densities below 0.3 MBtu/hr/acre. This preliminary screening indicates that central heating systems that are in good condition should be preserved. Fort Carson’s actual cost curves for the central plants may be lower as

the cost billed by the contractor to operate and maintain the heating systems

was $1.53/MBtu delivered to the building as compared to the Army average of

$3.86/MBtu delivered to the building. This cost is at the lower end of the nonfuel O&M costs reported by industry and institutional steam plants.

Summary and recommendations.

No serious problems have been observed at the heat plants at Fort Carson. The

HTHW system off of Building 1860 is a main and lateral system. Some valve

repairs may be needed. It is difficult to manage outages in some sections due to

the valve condition and piping configuration. However, PAE reports that underground sections that have been unearthed appear to be in good condition. Work

on the HTHW system would probably focus on repairs and modifications to make

the system more reliable and flexible. If the system had two mains or a loop,

major sections could be isolated, depressurized, and cooled down to allow repairs.
36 USACERL TR 99/23

Fort Carson is in the initial stages of establishing an energy savings performance contract (ESPC). The installation is concerned that CHP repairs may interfere with the bundling of energy conservation opportunities (ECOs) in the ESPC

contractor’s proposal. The importance of obtaining an accurate baseline measurement of the current cost of operation cannot be overemphasized. If the baseline is overestimated, the installation risks “overpaying” for saving. If the baseline is underestimated, the contractor may not be able to find enough ECOs to

get a fair return on its investment. USACERL can provide technical assistance

with screening for ECOs and estimating the baseline costs.

Other CHP MOD sites

Fort Drum

Background.

The proposed project originally consisted of replacing an existing direct buried

HTHW distribution system that was in poor condition. The proposed replacement design was a shallow concrete trench system with occasional short runs of

aboveground piping. However, in 1997 Fort Drum elected to proceed with a decentralized system once the cost of replacing extensive portions of the HTHW

lines became prohibitively expensive.

The existing direct-buried HTHW piping system at Fort Drum was installed in

1987. The system has failed prematurely due to leaks in both the conduit and

the carrier pipe. Failures in the conduit were evidenced by its inability to hold

pressure. Failures in the carrier pipe were evidenced by the leakage of treated

HTHW into the annulus (area between the carrier pipe and conduit).

USACERL was asked to investigate the problem and to predict the remaining

life of the existing direct-buried carrier and conduit pipes. Chemical analysis of

the piping samples and water samples were taken to quantify the current condition. Then using a tool called SCALER, USACERL calculated the remaining life

of the pipes. SCALER was developed by USACERL and FORSCOM in the late

1980s to predict the effects of corrosion on water piping based on physical information about the piping system and the chemistry of the water conveyed. Water

chemistry and pipe data were entered into SCALER and prediction reports were

generated.
USACERL TR 99/23 37

Results.

Based on SCALER predictive models for pitting corrosion of galvanized steel at

elevated temperatures, the carrier pipe (2 in. diameter x 0.218 in. wall thickness)

could fail by pitting corrosion in less than 5 years. This prediction is upheld by

the fact that Fort Drum has pressure tested the annulus between the carrier and

conduit and could not maintain the required 15 psi for 1 hr. In addition, treated

HTHW was detected in one of the water samples from the annulus at manhole

19. Since the groundwater is only slightly corrosive to steel, the most likely scenario for failure would be the following series of events:

• Groundwater enters the annulus between the conduit and carrier pipes.

There are at least three likely causes of the groundwater intrusion. The most

likely cause is seepage through the drain or vent in the end cap at the manhole. Another possible cause is conduit penetration due to soil-side pitting

corrosion. Soil-side pitting corrosion is less likely than seepage through the

drain or vent (due to the longer time required). Also, previous work done at

Fort Drum has indicated that the soil is not very corrosive. However, Fort

Drum personnel have reported that failure of the conduit did occur at the

conduit/manhole junction due to galvanic and/or concentration cell corrosion.

The third possible cause of groundwater intrusion is defective weld joints.

DPW personnel reported that they had observed water intrusion into the annulus due to a lack of complete weld joints in the conduit at the expansion

loops.

• The heated groundwater (minimum 162 °F) is chemically altered and becomes soft and very aggressive or corrosive to steel.

• The boiling groundwater causes severe pitting corrosion on the interior surface of the conduit. This allows more groundwater to intrude. Physical examination of interior surfaces of the conduit did not reveal any significant

difference in the amount of corrosion (i.e., there was uniform pitting around

the circumference of the conduit).

• Eventually (in less than 5 years) the very corrosive boiling groundwater in

the annulus causes failure of the exterior surface of the carrier pipe by pitting corrosion.

• This failure allows treated HTHW to enter the annulus and mix with the

groundwater, rendering it less corrosive.
38 USACERL TR 99/23

• Eventually the entire system fails (in as little as 5 years) and requires total

replacement.

Examination of the interior surface of the carrier pipe revealed little or no visible

corrosion occurring. This lack of corrosion indicates an excellent water treatment program is being used at the CHP.

It is interesting to note that the application of cathodic protection would probably not have prevented the failure of either the conduit or carrier pipes since

there was extensive groundwater intrusion from the lack of welds or missing

drain and vent plugs. This conclusion can be made because the pitting corrosion

was initiated on the inside of the annulus. If the conduit failed due to soil-side

corrosion or galvanic corrosion at the conduit/manhole junction, then cathodic

protection would be an effective corrosion prevention measure.

Summary.

Based on the water chemistry, pipe examination, and SCALER prediction models, the following conclusions can be made concerning the direct-buried HTHW

piping system at Fort Drum:

• The remaining life of the piping system could be as little as 5 years due to the

failure of the carrier pipe as a result of pitting corrosion.

• The primary failure mode of the conduit appears to be pitting corrosion induced by corrosive boiling water. The groundwater intrusion most likely occurred at the manhole or expansion loops.

• The primary failure mode of the carrier appears to be pitting corrosion of the

exterior surface due to exposure of boiling groundwater. The very slightly

corrosive groundwater is chemically altered by boiling with the insulated materials over long periods of time (greater than 90 days).

• The conduit pipe will not pass a pressure test (15 psi for 1 hr). This indicates

penetration, which allows continual intrusion of groundwater.

• There is evidence of at least one failure of the carrier pipe near manhole 19.

The water analyses revealed the presence of treated HTHW in the pipe annulus.
USACERL TR 99/23 39

Fort Campbell

Background.

Fort Campbell has submitted a utilities modernization project for funding in

FY98 as part of the Army’s UMP.

USACERL was tasked to conduct a preliminary HEATMAP analysis of the steam

distribution system at Fort Campbell to calculate accurate construction and fuel

consumption estimates. Three new scenarios were modeled, all of which included shallow trench piping and one new low-NOx boiler or hot water generator

from another project. These scenarios included:

• A new steam system using the existing boilers

• A new LTHW system using the existing boilers and cascade heaters

• A new LTHW system using three new hot water generators, two at 35

MBtu/hr and one at 15 MBtu/hr.

It was assumed that natural gas was the only fuel used for the new scenarios. It

is recommended that dual fuel capabilities, either #2 oil or a propane/air mix,

should be maintained to support an interruptible gas rate and to provide greater

system reliability.

A HEATMAP analysis was conducted on the existing system. An electronic map

of the distribution system was provided as well as building loads, boiler logs, and

O&M costs from a previous study completed by Systems Engineering Management Corporation (Systems Corp). All of these data were used to validate the

HEATMAP model for the existing system. This information was then used to

estimate distribution system costs and annual fuel consumption for new steam

and LTHW systems using shallow trench piping systems. Estimates for boiler

retrofit costs were taken from 1997 R.S. Means data and did not include costs for

the installation of a new low-NOx boiler from another project. Demolition cost

estimates were obtained from a project at Fort Dix, NJ, where they were removing similar size boilers from an existing plant.

The installation of the current heating system was completed in 1977. Boiler

Plant 3902 consists of two 50 MBtu/hr #2 oil/gas-fired boilers and one 15 MBtu/

hr #2 oil/gas-fired boiler. All the boilers are of water-tube design and were manufactured by Nebraska Boiler. The working steam pressure is 92 psig. A previous study completed by Schmidt Associates, Inc. (SAI) revealed that the existing

boilers were in good condition and operating near the design efficiency of 80 percent. At least an additional 20 years of boiler life is expected. However, the direct-buried steam supply and condensate return systems are in poor condition
40 USACERL TR 99/23

and are resulting in high energy losses. This system currently serves two barracks complexes and the Lee Family Housing Area. The family housing area will

not be included in this study since an alternate means of heating and cooling will

be installed there.

Steam is used primarily for heating and DHW production. Buildings 3603 and

4061 require steam for humidification and kitchen equipment. Of the 54 buildings on the system, 19 use steam directly in their heating system, with the rest

converting to LTHW in the mechanical room before distribution inside the

building. Retrofit costs of $1,300,000 for conversion of the 19 buildings from

steam to LTHW were pulled from the Systems Corp study. From the boiler logs,

the average hourly steam flow was plotted against the average daily temperature. The minimum load averaged just above 12,000 lb/hr for average daily temperatures above 65 °F. The average base load, which included DHW and process

loads, was calculated to be 2,000 lb/hr, indicating an average loss of 10,000 lb/hr

in the distribution system. The maximum load of 78,000 lb/hr occurred on a day

with an average temperature of 5 °F. The design day for Nashville, TN, is 14 °F.

At 14 °F the boiler log sheets show an average flow of just over 60,000 lb/hr.

Figure 10 shows the steam load versus outdoor temperature relationship.

Steam flow and fuel consumption are the most reliable energy use data available

from the logs at Fort Campbell. USACERL used the steam flow data to validate

the HEATMAP flow model for the design day and the thermal loss estimate.

Fort Campbell KY - Plant 3902

Average Hourly Steam Flow vs. Average Daily

Temperature

0

10

20

30

40

50

60

70

80

90

0 20 40 60 80 100

Figure 1. Average Daily Temperature, degrees F

Steam Flow, 1000 

lbs/hr

Figure 10. Steam flow versus daily temperature, Fort Campbell, KY.
USACERL TR 99/23 41

Both the thermal loss estimate and the annual fuel consumption were used to

estimate the annual building thermal load. The plot of the steam flow shown

below identifies large thermal losses of nearly 8,500 lb/hr or 10 MBtu/hr. The

SAI study also indicated that the boiler combustion efficiency was about 80 percent. The 10 MBtu/hr loss equates to an annual consumption of 110,000 MBtu of

natural gas. Annual fuel consumption was reported to be 231,000 MBtu. This

leaves nearly 121,000 MBtu of natural gas to provide for the actual heating load.

At 80 percent efficiency, the annual heating load was estimated to be approximately 97,000 MBtu.

The slope of the data shows a peak building heating load is about 65,000 lb/hr for

a 5 °F day. At 14 °F (the design day), the heating load is around 50,000 lb/hr. An

additional 2,500 lb/hr are added to the estimated peak heating load to account

for the process load and the peak DHW load. The total peak consumer load for

the base is estimated to be 52.5 lb/hr, which is assuming a condensate return

temperature of 190 °F. An additional 10 MBtu/hr of distribution system losses

would result in a peak plant output of 62.5 MBtu/hr.

Fuel costs.

Current fuel costs at Fort Campbell are $0.60/gal for #2 oil and $3.31/MBtu for

natural gas. The previous study (prepared by Systems Corp) used a natural gas

price of $4.71/MBtu. The new scenarios consumed only natural gas as a fuel.

Economic analyses were completed for both of the natural gas prices that were

quoted in the earlier study.

Summary.

A new shallow trench LTHW distribution system using a loop around each barracks complex would provide the lowest annual O&M costs and the lowest annual fuel consumption. The shallow trench LTHW distribution system will cost

approximately $6.5 million. The piping cost estimates used were for a HTHW

system and are most likely high enough to include the design and contingency

costs for an LTHW system. Therefore, a contingency is already built in to the

estimate for the distribution system. Table 5 compares the life-cycle costs.
42 USACERL TR 99/23

Table 3. Fort Campbell life-cycle cost summary.

(All PW values are in 1000s of 1997 $) Existing

Steam

New

Steam

LTHW

Cascade

LTHW New

Boilers

Capital Cost PW 0 5,650 7,539 8,392

O&M PW 8,657 2,587 2,424 1,286

Salvage Value PW -982 -1,308 -1,308

Fuel PW @ $3.31/MBtu 13,741 9,243 8,446 8,242

Net PW @ $3.31/MBtu 22,398 16,498 17,101 16,612

SIR @ $3.31/MBtu - 2.3 1.9 1.8

DPP @ $3.31/MBtu - 9 11 11

Fuel PW @ $4.71/MBtu 19,553 13,152 12,018 11,728

Net PW @ $4.71/MBtu 28,210 20,407 20,673 20,098

SIR @ $4.71/MBtu - 2.7 2.2 2.1

DPP @ $4.71/MBtu - 8 9 9

Even though the new steam has the highest SIR and lowest DPP, it has a higher

cost risk as, without proper maintenance, it could quickly deteriorate to a condition that would consume up to 25 percent more fuel annually, primarily due to

condensate return line and steam trap failure. Also, the total life-cycle costs are

so close (about 1 percent difference) they can be considered equivalent. LTHW

systems are at a technical advantage because they do not produce corrosive condensate and do not use steam traps; thus, they are more likely to provide thermal energy efficiently throughout the economic life of the system.
USACERL TR 99/23 43

6 Future Energy Supply Issues

Several technologies and issues will need to be considered when managing energy supplies in the next 2 to 10 years.

Low NOx Limits

Recent regulation by the U.S. Environmental Protection Agency (EPA) has reduced the nitrous oxide limits for utility and industrial steam generating units

for all fuels to that of natural gas and distillate oil (EPA, September 1998). The

old Subpart Db limits (EPA, October 1998) were fuel specific as listed in Table 4.

Table 4. Federal nitrogen oxide limits for subpart Db steam generating units.

Fuel/Use Lb/MBtu/hr Input

Gas and oil (low heat release rate) 0.10

Gas and oil (high heat release rate 0.20

Residual oil (low heat release rate) 0.30

Residual oil (high heat release rate) 0.40

Coal Spreader Stoker 0.60

The new limits will be 0.20 lb/MBtu for all fuels for industrial units classified as

Subpart Db units (100 to 250 MBtu/hr heat input). The low heat release rate

limit for gas and distillate oil of 0.10 lb/MBtu will not be changed.

Micro-Cogeneration

Advances in air and foil bearings and natural gas compressors are enabling

commercialization of microturbine generators. Several companies will be marketing units in the 17 to 100 kW range that will cost $450 to $700/kW installed

(Zuckerman 1997). Since the turbine generator is direct drive with an air-foil

bearing, reduction gear and lubricant maintenance is eliminated. Additionally,

many of the units will have heat recovery options. One of the challenges of cogeneration is the transport and management of the recovered heat. Many times

the heat recovery user is not located at the generation plant. The heat needs to
44 USACERL TR 99/23

be converted to steam or hot water and transported to the user. With smaller

micro-cogeneration units, the electrical production and heat recovery can be

moved closer to the end user reducing transportation and storage losses.

Fuel Cell Cogeneration

USACERL has successfully demonstrated the technical feasibility of phosphoric

acid fuel cells at 30 DoD sites. Although the installed cost is still high at

$3,000/kW, these units have such low emissions that they are exempt from air

quality permitting. Additionally, these units provide hot water for heating or

processes for the user.

Photovoltaics

USACERL has successfully demonstrated photovoltaic (PV) energy supply at

several DoD sites that have high electric rates, or power needs where installing

utility lines would not be economical. Typically, the electric loads being served

are relatively small, less than 5 kW. The sites are either far from the local utility

grid or in an area where extending the grid, even a short distance, would require

additional equipment and/or construction costs. These additional costs eliminate

grid extension as a viable alternative. Other conventional power supplies considered for these applications include small engine-driven generators and batteries, but the life-cycle cost for these alternatives is very high. Surveys conducted by various DoD agencies have shown that there are literally tens of

thousands of existing sites that fit this profile for telecommunications, lighting,

or other field equipment loads. Additionally, a facility may have sites where conventional electric service has been ruled out in the past, but should be reconsidered with a PV system as the power supply. The features that make PV power

an attractive option include:

• Reliable, standalone power supply—Properly designed PV systems can survive some of the harshest operating conditions and reliably provide power,

unattended, for long periods of time. They have no moving parts, so maintenance and replacement of system components is greatly reduced. A reliable

power supply increases the reliability and state of preparedness of the

equipment being served, such as a vehicle starting battery or a weather data

collection platform.

• No fuel requirements—Using a PV power system instead of, or in combination with, an engine-driven generator reduces the use of mobility fuels. Fuel
USACERL TR 99/23 45

transportation costs are also reduced. In cases where fuel is delivered by

helicopter, or over great distances by boat or truck, the transportation cost is

sometimes higher than the cost of the fuel itself.

• Modularity—Because the PV system can be sized to closely match the load,

both for power and energy, system efficiencies are maximized. If the load

changes at a particular site, the PV system can be reconfigured fairly easily

to meet the new requirements. Engine-driven generators come in specific

sizes and are typically oversized. An underloaded generator has poor fuel efficiency and requires more frequent maintenance.

• Environmental benefits—PV systems produce no harmful pollution and meet

some of the strictest requirements of the EPA and the National Park Service.

The environmental risks of fuel handling and storage are also minimized.

For military combat considerations, PV systems emit no noise or detectable

thermal signature. Used in combination with fossil fuel generators, hybrid

PV systems increase the efficiency of the generators and, in turn, help reduce

emissions from the conventional equipment. When used to charge batteries

at off-grid sites, PV systems extend the useful life of the batteries by maintaining a higher state of charge and reducing hazardous O&M handling procedures (Ducey 1998).
46 USACERL TR 99/23

7 Summary

This research examined issues involved in energy supply optimization and developed generic guidelines for analyzing energy supply strategies. These guidelines are based on research from a variety of sources and are intentionally broad.

Energy supply modernization programs are affected by economic and regulatory

forces and by the type and amount of fuel the installation uses. Modernization

programs include certain risks. Therefore, the installation must develop an energy supply strategy that best suits its needs.

In general, many Army sites do not have the energy supply density to justify

building new, large district heating and cooling systems. Some sites will have

buildings clustered close enough to use a CHP. However, central systems lend

themselves well to cogeneration to improve cycle efficiency. This practice reduces

the amount of fuel consumed to produce a desired effect. Central systems are

also able to switch fuels to reduce reliance on one fuel supplier.

Decentralized boilers and heaters are better suited to sparse geography. Additionally, decentralized boilers can be contracted out with the building operation.

The Army can package the building operation, repair, and heating into one scope

of work for a facility operations company. However, these small boilers and hot

water heaters will still require a fixed amount of maintenance regardless of the

boiler size. Also, these units are usually fired by gas only. The price for firm

(uninterruptible) gas can be 30 to 40 percent more expensive than for interruptible gas.

Strategies should be specifically tailored to the installation to help meet longrange installation planning. The overall goal of an energy supply strategy

should be procure, convert, and transport energy to the end user in the most effective and reliable method suitable to the economic and environmental conditions at the installation.
USACERL TR 99/23 47

References

Cited

Army Regulation (AR) 420-49, Heating, Energy Selection and Fuel Storage, Distribution, and Dispensing Systems (Headquarters, Department of the Army [HQDA], 22 June 1990).

Bloomquist, R. Gordon, J.D. Nimmons, and Kevin Rafferty, District Heating Development Guide,

Legal, Institutional and Marketing Issues, Volume 1 (Washington State Energy Office, Olympia, Washington, June 1987).

Council of Industrial Boiler Owners (CIBO), Proceedings of Boiler Life Extension II (CIBO, July

1989).

Defense Energy Program Policy Memorandum (DEPPM) 91-2, Implementing Defense Energy Management Goals.

Defense Reform Initiative (DRI), November 1997

(http://www.defenselink.mil/dodreform/index.html, viewed September 1998).

Dean, J.D., A Case Study of Steam Generation Replacement at DuPont's Louisville Plant (Stoker

Efficiency Network Workshop, August 1998).

Dilks, Chris, Feasibility Study of District Heating and Cooling System Operations for the Custer

Hill Area at Fort Riley, Kansas, U.S. Army Construction Engineering Research Laboratories

(USACERL) Summary Report (September 1996).

Ducey, Roch, Technical Instructions for Photovoltaic Power Systems (Draft),

(http://www.hnd.usace.army.mil/techinfo/ei.htm), December 1998.

Electric Power Research Institute (EPRI), Strategies for Fossil Plant Life Extension, Report No.

CS-4781 (EPRI, March 1987).

Energy Information Agency (EIA) Web Site (http://www.eia.doe.gov/price.html, viewed September,

1998).
48 USACERL TR 99/23

U.S. Environmental Protection Agency (EPA), Revision of Standards of Performance of Nitrogen

Oxide Emissions From New Fossil-Fuel-Fired Steam Generating Units, Federal Register, September 16, 1998, pp 49442-49455 (http://www.epa.gov/fedrgstr/EPA-AIR/1998/September/Day16/a24733.htm.

EPA, Subpart Db, 40 CFR Part 60, (http://www.epa.gov/docs/epacfr40/chapt-I.info/subchC/40P0060/40P060Db.pdf, viewed October 1998).

Imel, Mark, Utilities Modernization Program Summary Memorandum, September 1998.

Perkins, R.P., “DuPont's Life Extension History,” First Annual Boiler Life Extension Seminar

(Council of Industrial Boiler Owners [CIBO], 1986), p 121.

Public Law (PL) 102-486, The Energy Policy Act of 1992, Subtitle F, Federal Agency Energy Management.

Technical Manual (TM) 5-650, Repairs and Utilities: Central Boiler Plants (HQDA, 13 October

1989).

Zuckerman, Laurence, “Tiny Turbine: the Next Generator?” (The New York Times, Business Day,

December 2, 1997).

Uncited

Chapman, Richard, Photovoltaics in the Department of Defense, Sandia National Laboratories

(http://www.sandia.gov/pv/hot/Pvq_197.htm#anchor520921), viewed October 1998.

CIBO, First Annual Boiler Life Extension Seminar, 1986.

CIBO, Industrial Power Plant Improvement (IPPI) Technical Conference (CIBO, May 1991).

EPRI, Generic Guidelines for the Life Extension of Fossil Fuel Power Plants, Report No. CS-4778

(EPRI, November 1986).

EPRI, Strategy for Fossil Plant Life Extension at Niagara Mohawk's Huntley - 67, Report No. CS4780 (EPRI, January 1988), pp 1-21.

HEATMAP Version 1.0 - A Computerized Tool for Analyzing District Heating and Cooling System

Feasibility, Washington State Energy Office, WSEO #91-372 (WSEO, June 1992).
USACERL TR 99/23 49

Lawrie, L.K., et al., Life Cycle Cost In Design (LCCID) Economic Analysis Computer Program

User's Manual, BLAST Support Office, Department of Mechanical and Industrial Engineering,

University of Illinois, 1988.

LiHach, N., “Extending the Lifespan of Fossil Plants,” EPRI Journal, June 1983, pp 7-15.

Magee, D.R., “Boiler Condition and Useful Life Study,” First Annual Boiler Life Extension Seminar

(CIBO, 1986), p 191.

Savoie, M.J., and R.J. Miller, “Evaluation of Boiler Tuneup vs Replacement,” Draft Report

(USACERL, 1989).

Savoie, M.J., et al., Energy Supply Alternatives for Picatinny Arsenal, NJ, Technical Report

FE-92/04/ADA256863 (USACERL, 1992).

Training and Doctrine Command (TRADOC), Strategic Utility Planning Program, Volumes 1 and 2

(Headquarters, TRADOC, December 1993).

U.S. Air Force Central Heating Plant Tuneup Workshop, Special Report E-90/03 (USACERL, 1990)

(16 volumes):

Savoie, M.J., G. Maples, and D.F. Dyer, Volume I: Introduction, ADB142803.

Maples, G., D.F. Dyer, M.J. Savoie, and R.E. Moshage, Volume II: Description of Boilers,

ADB142129.

Maples, G., D.F. Dyer, and M.J. Savoie, Volume III: Description of Burners, ADB143333.

Maples, G., D.F. Dyer, and M.J. Savoie, Volume IV: Fuel Oil Quality, ADB141113.

Biederman, R., C.F. Blazek, S. McCammon, R.E. Moshage, and M.J. Savoie, Volume V: Coal

Quality, ADB142914.

Standerfer, J.F., and M.J. Savoie, Volume VI: Coal Handling and Storage, ADB143136.

Schmidt, C.M., J.E. Davidson, S. McCammon, R.E. Moshage, and M.J. Savoie, Volume VII:

Coal Combustion Equipment, ADB141114.

Maples, G., D.F. Dyer, and M.J. Savoie, Volume VIII: Combustion Control — Oil and Gas,

ADB141115.

Maples, G., D.F. Dyer, and M.J. Savoie, Volume IX: Combustion Control — Coal, ADB143011.

Maples, G., D.F. Dyer, J.F. Standerfer, and M.J. Savoie, Volume X: Steam and Condensate Systems, ADB141454.

Maples, G., D.F. Dyer, and M.J. Savoie, Volume XI: Efficiency, ADB141661.

Maples, G., D.F. Dyer, and M.J. Savoie, Volume XII: Water Quality, ADB141116.

Maples, G., D.F. Dyer, and M.J. Savoie, Volume XIII: Operation and Maintenance, ADB141117.
50 USACERL TR 99/23

Maples, G., D.F. Dyer, and M.J. Savoie, Volume XIV: Economics, ADB141373.

Standerfer, J.F., and M.J. Savoie, Volume XV: Ash Handling, ADB143291.

Richards, J., and M.J. Savoie, Volume XVI: Air Pollution Control Systems, ADB142292.
USACERL TR 99/23 51

Appendix: Advanced Energy Supply

Analyses

Fort Carson Screening
52 USACERL TR 99/23

Advance Energy Screening Analysis Site General Data

Front Sheet

Site Name: Ft Carson

Name Phone

POC's:

MACOM POC

Notice to users:

This sheet is to assist a base or command engineer screen for the economic viability of several 

energy supply options. To select the most life-cycle cost effective option, a more detailed analysis 

will need to be conducted. Contact the Utilities Division, USACERL, Champaign, IL 61826-9005 

(800)872-2375 ext 5505 or Mechanical and Energy Division, U.S. Army Center for Public Work, Ft 

Belvoir, VA (703) 806-6067
USACERL TR 99/23 53

Energy Supply Ft Carson

Natural Gas Utility Rates:

$/MBTU

 Summer Rate $0.40 $/therm $4.01 from through

 Winter Rate $0.40 $/therm $4.01 from through

Electric Utility Rates:

 Summer Dem. $8.00 $/kW from through

 Ratchet % from Jan through Dec

 Winter Dem. $8.00 $/kW $/MBTU

 Energy $0.0420 $/kWh $12.31

Fuel rate Information: $/MBTU Heating Value Typical Values

#2 Oil ($/gal) $0.60 $4.35 137000 BTU/gal 137000

#6 Oil ($/gal) $0.50 $3.29 152000 BTU/gal 15200

Coal ($/ton) $38.00 $1.48 12800 BTU/lb 12800

Energy Ratios Coal Specifications

Proximate Analysis As Rec'd Dry

Smr. El/Gas: 3.069 % Moisture

Demand/Gas 584.705 % Ash

% Volatile

Wntr El/Gas: 3.069 % Fixed C

Demand/Gas 584.705 BTU/lb

% Sulfur

Total 0 0

Ash Fusion Temps Reducing Oxidizing

Init Def

Suggested H=W

Gas Price $0.40 $/therm H=1/2 W

#2 Oil $0.60 $/gal Fluid

#6 Oil $/gal

Coal $0.00 $/ton Bulk Dens lbs/ft3

Elect $0.0420 $/kWh Utlimate Anaysis As Rec'd Dry

Moisture

Carbon

Hydrogen

Nitrogen

Chlorine

Sulfur

Ash

Oxygen (dif)

Total 0 0

Energy Supply Information

Utility Prices
54 USACERL TR 99/23

Energy Distribution Ft Carson

Suggested

Total Area 373,421 acres 373421 acres Total Bldg ft2/acre 4,435 

Served Area 2,500 acres 12393 acres Impr Bldg ft2/10K 0.102

Total Area 1.627E+10 ft2 Energy Dens 0.264 MBTU/hr/acre

Served Area 1.089E+08 ft2 Energy Dens 0.0605 MBTU/hr/10Kft2

Favoribility MBTU/ 270 yr/acre

Favoribility 0.006 MBTU/yr/10Kft2

Perimeter ft

Area Length ft

Area Width ft

LTHW linear ft Pipe System

HTHW 172,000 linear ft Suggested

Steam linear ft 172,000 lin Feet

Chill Water linear ft Pipe System

Distribution System Geometry

Steam/Hot Water Pipe System

Chill Water Pipe System

 	
 

 

 
USACERL TR 99/23 55

Energy Use Ft Carson

Suggested

Bldg Area (tot) 11,087,000 ft2 Pk Bldg load 659 MBTU/hr 659 MBTU/hr

Annual Load 675,521 MBTU/yr 675,521 MBTU/yr

Pk/Ann Ratio 0.00098 yr/hr 11,087,000 Bldg ft (tot)

Load Fact 0.11696208

Base Electric Use MWhr

Base Peak Electric Load: 75 MW

Monthly Peak Electrical Load (% of peak)

Jan 40 Feb 40 Mar 40 Apr 50

May 60 Jun 100 Jul 100 Aug 100

Sep 90 Oct 60 Nov 40 Dec 40

HDD 6373 CDD 692

1% Design 2 Deg F 1% DB Temp 92

Coinc Wind 7 Knots % Coinc WB 59

1% WB Temp 64

Thermal End Use Characterization

Climate

Electrical End Use Characterization
56 USACERL TR 99/23

Output Summary Ft Carson

Energy Den 0.264 MBTU/hr/acre

Costs ($.MBTU) Delivered

LTHW (gas) 28.92

LTHW (oil) 29.50

Steam (gas) 31.90

Steam (oil) 32.59

Sm Gas Blr 17.36

Med Gas Blr 8.94

Lg Gas Blr 6.73

Energy Cost vs Peak Energy Density

0

10

20

30

40

50

60

70

80

90

100

0 0.2 0.4 0.6 0.8 1 1.2

Peak Energy Use Density (MBTU/hr/acre land)

Energy Cost Delivered 

($/MBTU)

LTHW - Gas

STEAM - Gas

Steam - Oil

LTHW - Oil

Sm Gas Boiler

Lg Gas Boiler

Med Gas Boiler
123456789

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K29700 BUILDING INACTIVE KSF 0 0 0.00 K31000 IMPROVED GROUNDS AC 12,393 799,687 64.53 12,393 Acres Improve ####### Bldg ft Total K32010 OTHER THAN IMPROVED GROUNDS AC 91,743 5,158 0.06 K32020 TRAINING AREAS AC 269,285 138 0.00 373,421 Acres Total K41000 0 0 0.00 K42000 RAILROADS KLF 55 77,549 1,409.98 K51010 ROADS SURFACED KSY 3,728 617,553 165.65 K51030 ROADS UNSURFACED KSY 5,305 47,300 8.92 K51500 2,028 400,000 197.24 K52100 0 0 0.00 K52200 AIRFIELDS SURFACED KSY 299 0 0.00 K52300 145 0 0.00 K53100 SIDEWALKS KSY 729 9,845 13.50 K53200 PARKING VEHICULAR KSY 3,153 165 0.05 K53300 OPEN STORAGE KSY 206 1,459 7.08 K54110 BRIDGES, ROAD BRG 6 0 0.00 K54120 10 0 0.00 K54200 BRIDGES & TRESTLES-RAILROAD BRG 5 0 0.00 K61100 WATERFRONT FACILITIES & WATER

WFAC 0 0 0.00

K61200 12 200,000 #######K63000 NON-BUILDING FACILITIES 0 87,231 0.00L10000 ALTERATION & MINOR CONSTRUCT % 0 4,151,189 0.00L20000 0 0 0.00L30000 ALTER & MINOR CONSTRUCTION HOSPITAL 0 0 0.00

L40000 ALTER & MINOR CONSTRUCTION COMMISS 0 0 0.00M11000 FIREFIGHTERS 0 2,635,345 0.00M12000 FIRE CHIEFS & INSPECTORS 0 76,663 0.00M13000 0 565,693 0.00M21300 0 0 0.00M21400 0 0 0.00M21500 10,273 201,674 19.63M21600 LANDFILL OTHER (COLLECTION THRTON 0 0 0.00

M21700 30,846 338,696 10.98M31000 PEST CONTROL, BUILDINGS KSF 940 4,633 4.93M32000 0 0 0.00M40000 CUSTODIAL SERVICE KSF 1,402 997,250 711.31M50000 ICE ALLEVIATION 0 106,498 0.00M61000 MGMT & ENGRING LESS MASTER PL% 0 6,395,179 0.00M62000 MASTER PLANNING % 0 63,590 0.00M63000 ENVIRONMENTAL PROG-ACTV INSTL 0 3,533 0.00M71000 0 0 0.00M72000 REAL ESTATE ADMIN 0 0 0.00M74000 0 7,993 0.00M81100 LEASES 0 0 0.00M81200 0 0 0.00M81300 0 0 0.00M82000 0 0 0.00M84300 EQUIPMENT-IN-PLACE, ACQUISITION/INSTA 0 1,145,491 0.00

M84400 SPECIAL ENGINEERING MAINTENANCE ACT 0 7,880 0.00M85000 FE PACKING AND CRATING ACTIVITIES 0 0 0.00M86000 0 744,757 0.00M87000 PURCHASED FACILITY ENGINEERING SERV 0 0 0.00M88100 MAINTENANCE AND REPAIR OF DPW EQUIP 0 925,523 0.00M88200 0 0 0.00M88300 0 0 0.00M99000 DEMOLITION OF REAL PROPERTY KSF 151 1,076,300 7,127.81
USACERL TR 99/23 59

Fort Eustis Screening

Advance Energy Screening Analysis Site General Data

Front Sheet

Site Name: Ft Eustis

Name Phone

POC's:

MACOM POC

Notice to users:

This sheet is to assist a base or command engineer screen for the economic viability of several 

energy supply options. To select the most life-cycle cost effective option, a more detailed analysis 

will need to be conducted. Contact the Utilities Division, USACERL, Champaign, IL 61826-9005 

(800)872-2375 ext 5505 or Mechanical and Energy Division, U.S. Army Center for Public Work, Ft 

Belvoir, VA (703) 806-6067
60 USACERL TR 99/23

Energy Supply Ft Eustis

Natural Gas Utility Rates:

$/MBTU

 Summer Rate $0.36 $/therm $3.60 from through

 Winter Rate $0.36 $/therm $3.60 from through

Electric Utility Rates:

 Summer Dem. $8.00 $/kW from through

 Ratchet % from Jan through Dec

 Winter Dem. $8.00 $/kW $/MBTU

 Energy $0.0406 $/kWh $11.90

Fuel rate Information: $/MBTU Heating Value Typical Values

#2 Oil ($/gal) $0.53 $3.87 137000 BTU/gal 137000

#6 Oil ($/gal) $0.50 $3.29 152000 BTU/gal 15200

Coal ($/ton) $38.00 $1.48 12800 BTU/lb 12800

Energy Ratios Coal Specifications

Proximate Analysis As Rec'd Dry

Smr. El/Gas: 3.305 % Moisture

Demand/Gas 651.296 % Ash

% Volatile

Wntr El/Gas: 3.305 % Fixed C

Demand/Gas 651.296 BTU/lb

% Sulfur

Total 0 0

Ash Fusion Temps Reducing Oxidizing

Init Def

Suggested H=W

Gas Price $0.36 $/therm H=1/2 W

#2 Oil $0.53 $/gal Fluid

#6 Oil $/gal

Coal $0.00 $/ton Bulk Dens lbs/ft3

Elect $0.0406 $/kWh Utlimate Anaysis As Rec'd Dry

Moisture

Carbon

Hydrogen

Nitrogen

Chlorine

Sulfur

Ash

Oxygen (dif)

Total 0 0

Energy Supply Information

Utility Prices
USACERL TR 99/23 61

Energy Distribution Ft Eustis

Suggested

Total Area 9,712 acres 9681 acres Total Bldg ft2/acre 17,414 

Served Area 428 acres 428 acres Impr Bldg ft2/10K 0.400

Total Area 4.231E+08 ft2 Energy Dens 0.786 MBTU/hr/acre

Served Area 1.864E+07 ft2 Energy Dens 0.1804 MBTU/hr/10Kft2

Favoribility 586 MBTU/yr/acre

Favoribility 0.013 MBTU/yr/10Kft2

Perimeter ft

Area Length ft

Area Width ft

LTHW linear ft Pipe System

HTHW linear ft Suggested

Steam 745,000 linear ft 745,000 lin Feet

Chill Water linear ft Pipe System

Distribution System Geometry

Steam/Hot Water Pipe System

Chill Water Pipe System

 	


	
  

62 USACERL TR 99/23

Energy Use Ft Eustis

Suggested

Bldg Area (tot) 7,453,000 ft2 Pk Bldg load 336 MBTU/hr 336 MBTU/hr

Annual Load 250,759 MBTU/yr 250,759 MBTU/yr

Pk/Ann Ratio 0.00134 yr/hr 7,453,000 Bldg ft (tot)

Load Fact 0.08509911

Base Electric Use MWhr

Base Peak Electric Load: 75 MW

Monthly Peak Electrical Load (% of peak)

Jan 40 Feb 40 Mar 40 Apr 50

May 60 Jun 100 Jul 100 Aug 100

Sep 90 Oct 60 Nov 40 Dec 40

HDD 3752 CDD 1585

1% Design 17 Deg F 1% DB Temp 92

Coinc Wind 10 Knots % Coinc WB 77

1% WB Temp 80

Thermal End Use Characterization

Climate

Electrical End Use Characterization
USACERL TR 99/23 63

Output Summary Ft Eustis

Energy Den 0.786 MBTU/hr/acre

Costs ($.MBTU) Delivered

LTHW (gas) 10.08

LTHW (oil) 10.35

Steam (gas) 8.82

Steam (oil) 8.99

Sm Gas Blr 21.94

Med Gas Blr 10.38

Lg Gas Blr 7.34

Energy Cost vs Peak Energy Density

0

10

20

30

40

50

60

70

80

90

100

0 0.2 0.4 0.6 0.8 1 1.2

Peak Energy Use Density (MBTU/hr/acre land)

Energy Cost Delivered 

($/MBTU)

LTHW - Gas

STEAM - 

Steam - Oil

LTHW - Oil

Sm Gas Boiler

Lg Gas Boiler

Med Gas Boiler
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A B C D E FGH I J K L M N O 

Ft Eustis

$51,570,855

TDAC TDAC Description UM Quantity Total Cost Unit CostJ11000 PURCHASED WATER KG 645,984 $1,427,973 $2.21J12000 FILTERED WATERJ13000 UNFILTERED WATERJ21000 PURCHASED SEWAGE DISPOSAL KG 22,764 $72,635 $3.19J22000 WASTEWATER PLANT OPERATION KG 534,375 $559,266 $1.05J22300 INDUSTRIAL WASTEWATER TREATMENT PLANTSJ23000 UNTREATED INDUSTRIAL WASTE/COOL WTRJ24000 UNTREATED INDUST WASTE/COOL 

WKG

J31000 PURCHASED ELECTRIC ENERGY MWH 117,402 $4,280,153 $36.46 $0.0365 $/KwhrJ32000 ELEC GEN PLANT OPERATION MBTU $/MBTUJ40100 PURCHASED GAS KCF 465,552 $1,676,964 $3.60 465,552 $3.60 $0.36 $/thermJ40200 PURCHASED OIL BL 27,509 $607,143 $22.07 160,251 $3.79 $0.53 $/galJ40300 PURCHASED COAL TN 0 #DIV/0! Boiler Eff $0.00 $/tonJ40400 HEAT PLT OPERATION MB 252,532 $608,504 $2.41 $2.41 0.40J40500 PURCHASED STEAM & HOT WATER SMB 12,265 $85,982 $7.01 $7.01J40600 AIR CONDITIONING PLANT OPERATIOTN 230 $16,131 $70.13J40700 REFRIGERATION/COLD STORAGE/ICE MAKINGJ61000 OTHER UTILITIES CONNECTION COSTS 0 $3,817J62000 OTHER UTILITIES LESS CONNECTION COSTS 0 $95,433J63000K11100 WATER SOURCE MAINTENANCE KGD 2,628 $0 $0.00K11200 WATER STORAGE KG 1,882 $0 $0.00K11300 WATER DISTRIBUTION KLF 593 $131,653 $222.01K12100 DOMESTIC WASTEWATER PLANTS KG 1,730 $544,141 $314.53K12200 INDUSTRIAL WASTEWATER TREATM KG 271,527 $0 $0.00K12300 WASTEWATER COLLECTION SYSTEMKLF 531 $35,470 $66.80K12400K13100 ELECTRIC GENERATING PLANT KVA 1,168 $12,750 $10.92K13210 ELEC DISTRIBUTION OVERHEAD KLF 1,214 $309,737 $255.14K13220 ELEC DISTRIBUTION UNDERGROUNDKLF 230 $26,524 $115.32K13300 ELEC DISTRIBUTION TRANSFORMERKVA 78,056 $73,532 $0.94 Total Elect O&M ($/kwhr)K13400 EXTERIOR LIGHTING 0 $41,746 $0.0042K13500 SUBSTATIONS AND SWITCH STATIONPLT 4 $23,876 $5,969.00 Plant Size (MBTU/hr) Total O&M ($/MBTU) fuel usedK14010 GAS FIRED HEAT PLANT MB 539 $15,123 $28.06 539 $0.58K14020 OIL FIRED HEAT PLANT MB 217 $222,577 $1,025.70 217K14030 0K14040 0 Linear Feet Dist Total O&M ($/MBTU) sentK14510 STEAM & HOT WATER DISTRIBUTIONKLF 745 $127,822 $171.57 745,000 $1.45K14520K14530K15100 AIR CONDITIONING PLANT MAINTENATN 31,081 $181,232 $5.83K15200K16100 

K16200 HDD 3752 K16300 OTHER UTILITY COSTS 0 $573,981 Peak Btu/hr Annual MBTU/yr Heatload Ca b Btu/ft2

K21000 TRAINING BLDGS KSF 1,055 $1,025,281 $971.83 43,206,470 27,868 FAM 113.5 10.5 3K22100 MAINTENANCE BUILDINGS KSF 571 $668,013 $1,169.90 38,035,109 22,638 b1 1320.5 10.53 40K22200 PRODUCTION BUILDINGS KSF 9 $50,022 $5,558.00 599,503 357 b2 81.9 7.4 2K23000 RESEARCH, DEVELOPMENT AND TESKSF 121 $72,490 $599.09 5,576,343 3,516 b3 295.9 10.53 39

K24000 STORAGE BUILDINGS KSF 735 $527,074 $717.11 54,160,063 29,065 AT 75.7 7.02 26K25000 HOSPITAL AND MEDICAL BULDINGS KSF 196 $765,951 $3,907.91 11,603,200 8,441 D 241.9 0 K26000 ADMINISTRATIVE BUILDINGS KSF 635 $627,708 $988.52 26,005,790 16,773 MED 254.4 11.41 43K27000 UNACCOMPANIED PERSONNEL HOU KSF 990 $8,607,489 $8,694.43 42,272,085 34,975 PM 138.25 10.53 39K28100 DEPENDENT SCHOOLS KSF 0 $0 $0.00 0 0 GYM 73.7 4.39 16K28200 OTHER COMMUNITY BULDINGS KSF 865 $733,296 $847.74 27,686,920 17,239 C 147 7.02 26K29100 FAM HOUSING BLDGS KSF 1,542 $4,322,472 $2,803.16 58,141,110 60,924 W 35.7 10.53 39K29200 OTHER BUILDINGS KSF 691 $117,942 $170.68 26,054,155 27,301 REC 231.5 5.25 1K29300 WATER PLANT BUILDINGS KSF 4 $0 $0.00 162,886 119 NCO 231.5 8.75 3K29400 WASTEWATER PLANT BUILDINGS KSF 4 $0 $0.00 294,749 158K29500 ELECTRICAL PLANT BUILDINGS KSF 2 $102 $51.00 147,374 Sum 79 SumK29600 HEAT PLANT BUILDINGS KSF 33 $34,978 $1,059.94 2,431,676 336,377,433 1,305 250,759
6566676869707172737475767778798081828384858687888990919293949596979899 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 119 120 A B C D E FGH I J K L M N O 

K29700 BUILDING INACTIVE KSF K31000 IMPROVED GROUNDS AC 428 $252,389 $589.69 428 Acres Improved 7,453,000 Bldg ft Total K32010 OTHER THAN IMPROVED GROUNDS AC 4,257 $178,465 $41.92 K32020 TRAINING AREAS AC 4,996 $256,542 $51.35 9,681 Acres Total K41000 K42000 RAILROADS KLF 30 $2,678,058 $89,268.60 K51010 ROADS SURFACED KSY 737 $182,062 $247.03 K51030 ROADS UNSURFACED KSY 595 $8,920 $14.99 K51500 K52100 K52200 AIRFIELDS SURFACED KSY 237 $1,256 $5.30 K52300 K53100 SIDEWALKS KSY 232 $57 $0.25 K53200 PARKING VEHICULAR KSY 2,810 $771,873 $274.69 K53300 OPEN STORAGE KSY 490 $0 $0.00 K54110 BRIDGES, ROAD BRG 1 $1,458 $1,458.00 K54120 K54200 BRIDGES & TRESTLES-RAILROAD BRG 3 $0 $0.00 K61100 WATERFRONT FACILITIES & WATER

WFAC 37 $86,268 $2,331.57

K61200K63000 NON-BUILDING FACILITIES 0 $399,313L10000 ALTERATION & MINOR CONSTRUCT % 0 $3,781,900L20000L30000 ALTER & MINOR CONSTRUCTION HOSPITALS/M 0 $691,280L40000 ALTER & MINOR CONSTRUCTION COMMISSARI 9 $12,997 $1,444.11M11000 FIREFIGHTERS 0 $2,200,167M12000 FIRE CHIEFS & INSPECTORS 0 $72,038M13000M21300M21400M21500M21600 LANDFILL OTHER (COLLECTION THR TON 12,461 $647,691 $51.98M21700M31000 PEST CONTROL, BUILDINGS KSF 6,616 $264,638 $40.00M32000M40000 CUSTODIAL SERVICE KSF 1,039 $554,705 $533.88M50000 ICE ALLEVIATION 0 $81,791M61000 MGMT & ENGRING LESS MASTER PL % 0 $2,948,119M62000 MASTER PLANNING % 0 $35,066M63000 ENVIRONMENTAL PROG-ACTV INSTL 0 $4,565,553M71000M72000 REAL ESTATE ADMIN 0 $49,773M74000M81100 LEASES 0 $822M81200M81300M82000M84300 EQUIPMENT-IN-PLACE, ACQUISITION/INSTAL/O 0 $460,561M84400 SPECIAL ENGINEERING MAINTENANCE ACTIVIT 0 $338,520M85000 FE PACKING AND CRATING ACTIVITIES 0 $54,811M86000M87000 PURCHASED FACILITY ENGINEERING SERVICE 0 $168,013M88100 MAINTENANCE AND REPAIR OF DPW EQUIPME 0 $1,700M88200M88300M99000 DEMOLITION OF REAL PROPERTY KSF 428 $517,066 $1,208.10
66 USACERL TR 99/23

Fort Riley Screening

Advance Energy Screening Analysis Site General Data

Front Sheet

Site Name: Ft Riley

Name Phone

POC's:

MACOM POC

Notice to users:

This sheet is to assist a base or command engineer screen for the economic viability of several 

energy supply options. To select the most life-cycle cost effective option, a more detailed analysis 

will need to be conducted. Contact the Utilities Division, USACERL, Champaign, IL 61826-9005 

(800)872-2375 ext 5505 or Mechanical and Energy Division, U.S. Army Center for Public Work, Ft 

Belvoir, VA (703) 806-6067
USACERL TR 99/23 67

Energy Supply Ft Riley

Natural Gas Utility Rates:

$/MBTU

 Summer Rate $0.28 $/therm $2.84 from through

 Winter Rate $0.28 $/therm $2.84 from through

Electric Utility Rates:

 Summer Dem. $/kW from through

 Ratchet % from Jan through Dec

 Winter Dem. $/kW $/MBTU

 Energy $0.0477 $/kWh $13.97

Fuel rate Information: $/MBTU Heating Value Typical Values

#2 Oil ($/gal) $0.48 $3.50 137000 BTU/gal 137000

#6 Oil ($/gal) $0.50 $3.29 152000 BTU/gal 15200

Coal ($/ton) $38.00 $1.48 12800 BTU/lb 12800

Energy Ratios Coal Specifications

Proximate Analysis As Rec'd Dry

Smr. El/Gas: 4.919 % Moisture

Demand/Gas 0.000 % Ash

% Volatile

Wntr El/Gas: 4.919 % Fixed C

Demand/Gas 0.000 BTU/lb

% Sulfur

Total 0 0

Ash Fusion Temps Reducing Oxidizing

Init Def

Suggested from Redbook H=W

Gas Price $0.28 $/therm H=1/2 W

#2 Oil $0.00 $/gal Fluid

#6 Oil $/gal

Coal $0.00 $/ton Bulk Dens lbs/ft3

Elect $0.0477 $/kWh Utlimate Anaysis As Rec'd Dry

Moisture

Carbon

Hydrogen

Nitrogen

Chlorine

Sulfur

Ash

Oxygen (dif)

Total 0 0

Energy Supply Information

Utility Prices
68 USACERL TR 99/23

Energy Distribution Ft Riley

Suggested

Total Area 100,446 acres 100446 acres Total Bldg ft2/acre 4,566 

Served Area 3,000 acres 60449 acres Impr Bldg ft2/10K 0.105

Total Area 4.375E+09 ft2 Energy Dens 0.260 MBTU/hr/acre

Served Area 1.307E+08 ft2 Energy Dens 0.0596 MBTU/hr/10Kft2

Favoribility 233 MBTU/yr/acre

Favoribility 0.005 MBTU/yr/10Kft2

Perimeter ft

Area Length ft

Area Width ft

LTHW linear ft Pipe System

HTHW linear ft Suggested

Steam 22,000 linear ft 22,000 lin Feet

Chill Water linear ft Pipe System

Distribution System Geometry

Steam/Hot Water Pipe System

Chill Water Pipe System

 	



	
  

USACERL TR 99/23 69

Energy Use Ft Riley

Suggested

Bldg Area (tot) 13,698,000 ft2 Pk Bldg load 779 MBTU/hr 779 MBTU/hr

Annual Load 698,238 MBTU/yr 698,238 MBTU/yr

Pk/Ann Ratio 0.00112 yr/hr 13,698,000 Bldg ft (tot)

Load Fact 0.10237053

Base Electric Use MWhr

Base Peak Electric Load: 75 MW

Monthly Peak Electrical Load (% of peak)

Jan 40 Feb 40 Mar 40 Apr 50

May 60 Jun 100 Jul 100 Aug 100

Sep 90 Oct 60 Nov 40 Dec 40

HDD 5306 CDD 1503

1% Design 1 Deg F 1% DB Temp 99

Coinc Wind 8 Knots % Coinc WB 75

1% WB Temp 78

Thermal End Use Characterization

Climate

Electrical End Use Characterization
70 USACERL TR 99/23

Output Summary Ft Riley

Energy Den 0.260 MBTU/hr/acre

Costs ($.MBTU) Delivered

LTHW (gas) 26.89

LTHW (oil) 28.13

Steam (gas) 29.18

Steam (oil) 30.50

Sm Gas Blr 18.09

Med Gas Blr 8.47

Lg Gas Blr 5.95

Energy Cost vs Peak Energy Density

0

10

20

30

40

50

60

70

80

90

100

0 0.2 0.4 0.6 0.8 1 1.2

Peak Energy Use Density (MBTU/hr/acre land)

Energy Cost Delivered ($/MBTU)

LTHW - Gas

STEAM - Gas

Steam - Oil

LTHW - Oil

Sm Gas Boiler

Lg Gas Boiler

Med Gas Boiler
USACERL TR 99/23 71
72 USACERL TR 99/23