Acknowledgements

Improving Steam System Performance: A Sourcebook for Industry was developed under the BestPractices 

activity for the U. S. Department of Energy’s (DOE) Industrial Technologies Program (ITP). BestPractices

undertook this project as a series of sourcebook publications. Other topics in this series include: 

compressed air systems, pumping systems, fan systems, process heating, and motor and drive systems.

For more information about DOE’s BestPractices, see ITP and BestPractices in the Where to Find Help 

section of this publication.

ITP, Lawrence Berkeley National Laboratory, and Resource Dynamics Corporation wish to thank the staff at

the many organizations that so generously assisted in the collection of data for this Sourcebook. The

Alliance to Save Energy, the Council of Industrial Boiler Operators, the National Insulation Association,

and the North American Insulation Manufacturers Association provided valuable assistance in developing, compiling, and reviewing this publication. 

The BestPractices Steam activity appreciates the participation of the Steam Technical Subcommittee.

Special thanks are extended to its co-chairs, Dr. Anthony Wright, Oak Ridge National Laboratory, 

and Glenn Hahn, Spirax Sarco, an Allied Partner, for providing extensive technical guidance and review

throughout the preparation of this publication. The efforts of these program and committee participants are greatly appreciated.

Additionally, the contributions of the following participants are appreciated for their review of and 

suggestions for this Sourcebook:

Deborah Bloom, Nalco Company

Sean Casten, Turbosteam Corporation

Bruce Gorelick, Enercheck Systems

Robert Griffin, Enbridge Gas Distribution, Canada

Dr. Greg Harrell, Energy, Environment and Resources Center, University of Tennessee-Knoxville

Thomas Henry, Armstrong Service

Carroll Hooper, Steam Solutions, Inc.

James Kumana, Kumana and Associates

Andrew W. Larkin, Trigen Energy Corporation

Lloyd Mason, Condensate Return Specialists

Gil McCoy, EERE Information Center

Kelly Paffel, Plant Support & Evaluations, Inc.

W. Randall Rawson, American Boiler Manufacturers Association 

Douglas Riley, Millennium Chemical 

Thomas Scheetz, BASF

John Todd, Yarway Corporation

Prepared for: The United States Department of Energy

Industrial Technologies Program

Prepared by: Lawrence Berkeley National Laboratory Washington, DC

Resource Dynamics Corporation

Vienna, VA

Cover photo credit: NREL/PIX 05559. The Leathers geothermal power plant located in the Salton Sea, California. 

Photo by Warren Gretz.
Acknowledgements i

Table of Contents ii

List of Figures and Tables iii

Quick Start Guide

Section 1: Steam System Basics

Why Steam? 3

Steam System Operation 3

Generation 5

Distribution 11

End Use 15

Recovery 21

Section 2: Performance Improvement Opportunities

Overview 25

Systems Approach 25

Common Performance Improvement Opportunities 25

BestPractices Steam System Performance Tools 26

Steam System Training 28

Overview of Financing Steam System Improvements 29

Section 3: Where to Find Help

The Industrial Technologies Program and BestPractices 33

Directory of Contacts 36

Resources and Tools 37

Appendices

Appendix A: Glossary of Terms 57

Appendix B: Steam Tip Sheets 61

Appendix C: Guidelines for Comment 101

Contents

A Sourcebook for Industry ii

1

3

25

33

55
iii Improving Steam System Performance

List of Figures

Figure 1. Steam System Schematic 4

Figure 2. Firetube Boiler 5

Figure 3. Watertube Boiler 6

Figure 4. Thermostatic Steam Trap with a Bellows Element 13

Figure 5. Thermostatic Steam Trap with a Bimetallic Element 13

Figure 6. Inverted Bucket Steam Trap 14

Figure 7. Float and Thermostatic Steam Trap 14

Figure 8. Thermodynamic Disc Steam Trap 14

Figure 9. Shell and Tube Heat Exchanger 18

Figure 10. Components of a Plate and Frame Heat Exchanger 18

Figure 11. Configuration of a Jacketed Kettle Heat Exchanger 18

Figure 12. Thermocompressor Operation 20

Figure 13. Condensate Receiver Tank and Pump Combination 22

Figure 14. Flash Steam Recovery Vessel 23

List of Tables

Table 1. Key IOF Steam End-Use Equipment 16

Table 2. Common Performance Improvement Opportunities for the Generation,

Distribution, and Recovery Parts of Industrial Steam Systems 26
1

This Sourcebook is designed to provide steam

system users with a reference that describes 

the basic steam system components, outlines

opportunities for energy and performance

improvements, and discusses the benefits of 

a systems approach in identifying and implementing these improvement opportunities. 

The Sourcebook is divided into three main 

sections as outlined below.

This Sourcebook is not intended to be a comprehensive technical guide on improving steam 

systems, but rather a document that makes users

aware of potential performance improvements,

provides some practical guidelines, and directs

the user to helpful resources. A systems approach

analyzes the supply and the demand sides of the

system and how they interact, essentially shifting

the focus from individual components to total

system performance. The cost-effective operation

and maintenance of a steam system require

attention not only to the needs of individual

pieces of equipment, but also to the system as a

whole. Often, operators are so focused on the

immediate demands of the equipment, they

overlook the broader question of how system

parameters affect the equipment.

◆ Section 1: Steam System Basics

For users unfamiliar with the basics of steam 

systems, or for users seeking a refresher, a brief 

discussion of the terms, relationships, and 

important system design considerations is 

provided. Users already familiar with industrial

steam system operation may want to skip this

section. This section describes steam systems

using four basic parts: generation, distribution,

end use, and recovery.

◆ Section 2: Performance Improvement 

Opportunities

This section discusses important factors that

should be considered when industrial facilities

seek to improve steam system performance and

to lower operating costs. This section also provides

an overview of the financial considerations related to steam system improvements. Additionally, 

this section discusses several resources and tools

developed through the U. S. Department of 

Energy’s (DOE) BestPractices Steam activities to

identify and assess steam system improvement

opportunities.

◆ Section 3: Where to Find Help

This section provides a directory of associations

and other organizations involved in the steam

system marketplace. This section also provides 

a description of the BestPractices Steam activities, 

a directory of contacts, and a listing of available

resources and tools, such as publications, software,

training courses, and videos. 

◆ Appendices

The Sourcebook includes three appendices.

Appendix A is a glossary defining terms used in

steam systems. Appendix B contains a series of

steam system tip sheets. Developed through

DOE’s BestPractices Steam activities, these tip

sheets discuss common opportunities that 

industrial facilities can use to improve performance and reduce fuel use. Appendix C provides

guidelines for submitting suggested changes and

improvements to the Sourcebook.

A Sourcebook for Industry

Quick Start Guide

Quick Start Guide
2 Improving Steam System Performance
3

Why Steam?

There are three principal forms of energy used in

industrial processes: electricity, direct-fired heat,

and steam. Electricity is used in many different

ways, including mechanical drive, heating, and

electrochemical reactions. Direct-fired energy

directly transfers the heat of fuel combustion 

to a process. Steam provides process heating,

pressure control, mechanical drive, and component separation, and, is a source of water for

many process reactions. 

Steam has many performance advantages that

make it an indispensable means of delivering

energy. These advantages include low toxicity,

ease of transportability, high efficiency, high heat

capacity, and low cost with respect to the other

alternatives. Steam holds a significant amount of

energy on a unit mass basis (between 1,000 and

1,250 British thermal units per pound [Btu/lb])

that can be extracted as mechanical work

through a turbine or as heat for process use.

Since most of the heat content of steam is stored

as latent heat, large quantities of heat can be

transferred efficiently at a constant temperature,

which is a useful attribute in many process heating applications. 

Steam is also used in many direct contact applications. For example, steam is used as a source of

hydrogen in steam methane reforming, which is

an important process for many chemical and

petroleum refining applications. Steam is also

used to control the pressures and temperatures 

of many chemical processes. Other significant

applications of steam are to strip contaminants

from a process fluid, to facilitate the fractionation

of hydrocarbon components, and to dry all types

of paper products.

The many advantages that are available from

steam are reflected in the significant amount 

of energy that industry uses to generate it. For

example, in 1994, industry used about 5,676 

trillion Btu of steam energy, which represents

about 34% of the total energy used in industrial

applications for product output.1

Steam use in the Industries of the Future2 is 

especially significant. For example, in 1994, 

the pulp and paper industry used approximately

2,197 trillion Btu of energy to generate steam,

accounting for about 83% of the total energy

used by this industry. The chemicals industry

used approximately 1,855 trillion Btu of energy

to generate steam, which represents about 

57% of the total energy used in this industry.

The petroleum refining industry used about

1,373 trillion Btu of energy to generate steam,

which accounts for about 42% of this industry’s

total energy use.3

◆ Steam System Operation

This Sourcebook uses four categories to discuss

steam system components and ways to enhance

steam system performance: generation, distribution, end use, and recovery. These four areas 

follow the path of steam as it leaves the boiler

and returns via the condensate return system.

Generation

Steam is generated in a boiler or a heat recovery

steam generator by transferring the heat of 

combustion gases to water. When water absorbs

enough heat, it changes phase from liquid to

steam. In some boilers, a superheater further

increases the energy content of the steam. Under

pressure, the steam then flows from the boiler or 

steam generator and into the distribution system. 

A Sourcebook for Industry

Section 1: Steam System Basics

1 Arthur D. Little, Overview of Energy Flow for Industries in Standard Industrial Classifications 20–39, December, 2000.

2 DOE’s Industries of the Future (IOF) include: aluminum, chemicals, forest products, glass, metal casting, mining, 

petroleum refining, and steel.

3 Resource Dynamics Corporation estimates.

Steam System Basics
4

◆ Distribution

The distribution system carries steam from the

boiler or generator to the points of end use.

Many distribution systems have several take-off

lines that operate at different pressures. These

distribution lines are separated by various types

of isolation valves, pressure-regulating valves,

and, sometimes, backpressure turbines. A properly

performing distribution system delivers sufficient

quantities of high quality steam at the right pressures and temperatures to the end uses. Effective

distribution system performance requires proper

steam pressure balance, good condensate drainage, adequate insulation, and effective pressure

regulation. 

◆ End Use

There are many different end uses of steam.

Examples of steam’s diverse uses include process

heating, mechanical drive, moderation of chemical reactions, and fractionation of hydrocarbon

components. Common steam system end-use

equipment includes heat exchangers, turbines,

fractionating towers, strippers, and chemical

reaction vessels.

In a heat exchanger, the steam transfers its latent

heat to a process fluid. The steam is held in the

heat exchanger by a steam trap until it condenses,

at which point the trap passes the condensate

into the condensate return system. In a turbine,

the steam transforms its energy to mechanical

work to drive rotating machinery such as pumps,

compressors, or electric generators. In fractionating towers, steam facilitates the separation of 

various components of a process fluid. In stripping applications, the steam pulls contaminants

out of a process fluid. Steam is also used as a

source of water for certain chemical reactions. In

steam methane reforming, steam is a source of

hydrogen.

◆ Recovery

The condensate return system sends the condensate back to the boiler. The condensate is returned

to a collection tank. Sometimes the makeup

water and chemicals are added here while other

times this is done in the deaerator. From the collection tank the condensate is pumped to the

deaerator, which strips oxygen and non-condensable gases. The boiler feed pumps increase the

feedwater pressure to above boiler pressure and

inject it into the boiler to complete the cycle.

Figure 1 provides a general schematic description

of the four principal areas of a steam system. The

following sections discuss the components in

these areas in greater detail.

Improving Steam System Performance

Steam System Basics

Combustion

Gases

Condensate

Receiver

Tank

Pressure

Reducing Valve

Feed

Pump

Steam

Trap

Steam

Trap

Steam

Trap

Economizer

Combustion Air Condensate Pump

Process Heater

Process Heater

Isolation Valve

Boiler

Deaerator

Fuel

Combustion Air

Preheater

Shell and Tube

Heat Exchanger

Forced Draft

Fan

Distribution

Recovery

End Use

Figure 1. Steam System Schematic

Generation
5

Generation

The generation part of a steam system uses a

boiler to add energy to a feedwater supply to

generate steam. The energy is released from the

combustion of fossil fuels or from process waste

heat. The boiler provides a heat transfer surface

(generally a set of tubes) between the combustion

products and the water. The most important

parts of the generating system include the boiler,

the fuel supply, combustion air system, feedwater

system, and exhaust gases venting system. These

systems are related, since problems or changes in

one generally affect the performance of the others.

◆ Boilers

There are two basic types of boilers: firetube and

watertube. The fundamental difference between

these boiler types is which side of the boiler tubes

contains the combustion gases or the boiler

water/steam. 

Firetube boilers. In firetube boilers, the combustion gases pass inside boiler tubes, and heat is

transferred to water on the shell side. A representative firetube boiler is shown in Figure 2. Scotch

marine boilers are the most common type of

industrial firetube boiler. The Scotch marine 

boiler is an industry workhorse due to low initial

cost, and advantages in efficiency and durability.

Scotch marine boilers are typically cylindrical

shells with horizontal tubes configured such that

the exhaust gases pass through these tubes, transferring energy to boiler water on the shell side. 

Scotch marine boilers contain relatively large

amounts of water, which enables them to

respond to load changes with relatively little

change in pressure. However, since the boiler

typically holds a large water mass, it requires

more time to initiate steaming and more time 

to accommodate changes in steam pressure. 

Also, Scotch marine boilers generate steam on

A Sourcebook for Industry

Steam System Basics

Figure 2. Firetube Boiler4

4 Guideline for Gas and Oil Emission Factors for Industrial, Commercial, and Institutional (ICI) Boilers, American Boiler 

Manufacturer’s Association, Arlington, Virginia, 1997.
6

the shell side, which has a large surface area, 

limiting the amount of pressure they can generate.

In general, Scotch marine boilers are not used

where pressures above 300 psig are required.

Today, the biggest firetube boilers are over 

1,500 boiler horsepower (about 50,000 lbs/hr).5

Firetube boilers are often characterized by their

number of passes, referring to the number of

times the combustion (or flue) gases flow the

length of the pressure vessel as they transfer heat

to the water. Each pass sends the flue gases

through the tubes in the opposite direction. To

make another pass, the gases turn 180 degrees

and pass back through the shell. The turnaround

zones can be either dryback or water-back. In

dryback designs, the turnaround area is refractorylined. In water-back designs, this turnaround

zone is water-cooled, eliminating the need for

the refractory lining.

Watertube boilers. In watertube boilers, boiler

water passes through the tubes while the exhaust

gases remain in the shell side, passing over the

tube surfaces. A representative watertube boiler is

shown in Figure 3. Since tubes can typically

withstand higher internal pressure than the large

chamber shell in a firetube, watertube boilers are

used where high steam pressures (3,000 pounds

per square inch [psi], sometimes higher) are

required. Watertube boilers are also capable of

high efficiencies and can generate saturated or

superheated steam. In fact, the ability of watertube boilers to generate superheated steam makes

these boilers particularly attractive in applications that require dry, high-pressure, high-energy

steam, including steam turbine power generation. 

The performance characteristics of watertube 

boilers make them highly favorable in process

industries, including chemical manufacturing,

Improving Steam System Performance

Steam System Basics

5 1 boiler horsepower = 33,475 Btu/hr

6 Guideline for Gas and Oil Emission Factors for Industrial, Commercial, and Institutional (ICI) Boilers, American Boiler 

Manufacturer’s Association, Arlington, Virginia, 1997.

Figure 3. Watertube Boiler6
7

pulp and paper manufacturing, and refining.

Although firetube boilers account for the majority

of boiler sales in terms of units, water-tube boilers account for the majority of boiler capacity.7

Waste Heat Recovery Boiler (WHRB). These boilers

may be either firetube or watertube design and

use heat that would otherwise be discarded to

generate steam. Typical sources of heat for

WHRBs include exhaust gases or high temperature products from an external manufacturing

process in refineries and chemical manufacturing

facilities, or combustion of a waste fuel in the

boiler furnace. 

Heat Recovery Steam Generators (HRSGs). HRSGs

transfer energy from the exhaust of a gas turbine

to an unfired or supplementary fired heat-recovery steam generator to produce steam. Exhaust

gases leave the gas turbine at temperatures of

1000°F (538°C) or higher and can represent more

than 75% of the total fuel energy input. This

energy can be recovered by passing the gases

through a heat exchanger (steam generator) to

produce hot water or steam for process needs. If

the amount of steam needed by the process

exceeds the amount produced by simple heat

recovery, then supplementary fuel can be burned

in the ducting between the gas turbine and the

HRSG.

Superheaters. Superheaters add energy to steam,

resulting in a steam temperature that exceeds 

the saturation temperature at a specific pressure.

Superheaters can be convective or radiant. Radiative superheaters rely on the energy transferred

directly from the combustion flame to increase

the energy level of the steam, while convective

superheaters rely on the transfer of additional

energy from the flue gases to the steam. 

Economizers. In many boilers, the flue gases still

have useful amounts of energy even after they

have passed through the boiler. In many of 

these applications, economizers provide effective

methods of increasing boiler efficiency by 

transferring the heat of the flue gases to incoming feedwater. There are two principal types of

economizers: noncondensing and condensing.

Noncondensing economizers are usually air-towater heat exchangers. Since these economizers

are not designed to handle flue gas condensation,

noncondensing economizers must be operated at

temperatures that are reasonably above the dew

points of the flue gas components. The dew

point of the flue gases depends largely on the

amount of water in the gas, which, in turn, is

related to the amount of hydrogen in the fuel.

For example, to avoid condensation in the

exhaust gases produced by burning natural gas,

the exhaust gas temperature should typically be

kept above 250°F. Condensing economizers are

designed to allow condensation of the exhaust

gas components. Due to latent heat recovery,

these economizers typically extract more energy

than do noncondensing economizers. Often, 

special materials are required. 

For more information on economizers, see the

Steam Tip Sheet Number 3 titled Use Feedwater

Economizers for Waste Heat Recovery in Appendix B. 

Combustion air preheaters. Combustion air preheaters are similar to economizers in that they

transfer energy from the flue gases back into the

system. In these devices, however, the energy is

transferred to the incoming combustion air. The

efficiency benefit is roughly 1% for every 40°F

increase in the combustion air temperature.8

◆ Boiler Insulation

The walls and combustion regions of boilers are

typically lined with insulating materials to

reduce energy loss and to prevent leakage. There

are several types of boiler insulating materials,

including brick, refractory, insulation and lagging.

The selection and design of boiler insulating

materials depends largely on the age and design

of the boiler. Since the insulating lining is

exposed to high temperatures and is subject to

degradation, it should be periodically inspected

and repaired when necessary. 

◆ Boiler Control System

Boiler control systems are designed to protect the

boiler and to ensure proper boiler operation.

These systems include the combustion control

system, flame safeguard, water level control, and

fuel control. 

A Sourcebook for Industry

Steam System Basics

7 GRI, Analysis of the Industrial Boiler Population, Final Report No.-96/0200, 1996.

8 Boiler Efficiency Institute, Boiler Efficiency Improvement, 1991.
8

Combustion control system. The combustion control

system regulates the fuel air mixture to achieve

safe and efficient combustion and maintains

steam system pressure. Control systems have

varying levels of sophistication. Simple systems

use a fixed linkage between the fuel-regulating

valve and the combustion air damper. This is

called single point positioning. A change in

steam pressure makes a proportional change in

the combustion air and fuel. Advanced systems

rely on signals from transmitters to determine

independent fuel valve and air damper positions.

This is called a full monitoring system. 

For more information, see the Steam Tip Sheet

Number 4 titled Improve Your Boiler’s Combustion

Efficiency in Appendix B.

Burner flame safeguard system. A flame safeguard

system is an arrangement of flame detection 

systems, interlocks, and relays which will sense

the presence of a proper flame in a furnace and

cause fuel to be shut off if a hazardous condition

develops. Modern combustion systems are closely interlocked with flame safeguard systems and

also pressure-limit switches, low-water level cutoffs, and other safety controls that will stop the

energy input to a boiler when an unsafe condition develops. The flame safeguard system senses

the presence of a good flame or proper combustion and programs the operation of a burner 

system so that motors, blowers, ignition, and fuel

valves are energized only when they are needed

and then in proper sequence. 

Safety shutoff valve. Safety shutoff valves isolate the

fuel supply to the boiler in response to certain

conditions such as low or high gas pressure or

satisfied load demand. The type of safety shutoff

valves and the settings are often determined by

code or insurance requirements.

Water level control. The boiler water level control

system ensures a safe water level in the boiler.

Typically, the control system provides a signal to

the feedwater control valve to regulate the feed

rate. Simple water level control systems that only

sense water level are single element systems. More

complex systems incorporate additional data

such as steam flow rate (dual element system)

and feedwater flow (triple element system) and

will provide better water level control during

abrupt load changes.

Safety valve. The safety valve is the most important

valve on the boiler and keeps the boiler from

exceeding its maximum allowable working 

pressure (MAWP).

Steam pressure control. Steam pressure controls

regulate the combustion equipment to maintain

a constant pressure in the steam header. As the

pressure rises above or falls below the pressure

setting, the control adjusts the burner firing rate

to bring the pressure back to the setpoint.

Nonreturn valve. The nonreturn valve is a combination shutoff and check valve that allows steam

out of the boiler, but prevents backflow from the

steam header in the event the boiler pressure

drops below that of the header. The valve is

opened only when the pressure inside the boiler

rises slightly above the steam header pressure.

Steam flow meter. Steam flow meters are helpful 

in evaluating the performance of the system 

and can provide useful data in assessing boiler 

performance, calculating boiler efficiency, and

tracking the amount of steam required by the

system. In some systems, steam flow meters 

provide a measurement signal for the boiler 

control system. Additionally, steam flow meters

can be useful in benchmarking efforts.

There are three basic types of steam flowmeters:

differential pressure (DP), vortex, and Coriolis.

Differential pressure flowmeters rely on the

change in pressure as steam flows by an element

such as a nozzle, orifice, or venturi. This pressure

difference provides an indication of flow velocity,

which, in turn, can be used to determine the

flow rate. Vortex flowmeters rely on the principal

that flow past an element creates vortices that

have frequencies that correspond to the flow

velocity. Coriolis flowmeters rely on tubes placed

in the steam flow path that twist according to

the velocity of the flow.

◆ Boiler Feedwater System

The boiler feedwater system supplies water to the

boiler. Sources of feedwater include returning

condensate and makeup water. Feedwater is 

typically stored in a collecting tank to ensure

that a steady supply of heated water is available

to the boiler. 

Improving Steam System Performance

Steam System Basics
9

Feedwater flow control valve. A modulating feedwater flow control valve moves up or down in

response to the water level transmitter(s). On

smaller firetube boilers, it is not uncommon 

for the feedwater valve to operate in a closed 

or open position, depending on the water level

transmitter signal.

Softener. Softeners remove hardness minerals,

such as calcium, magnesium, and iron, from a

water supply. The presence of hardness in boiler

water leads to many problems, including scale

buildup and foaming, which reduce boiler 

efficiency and can cause tube failure. Softeners

reduce this problem through an ion exchange

process. As the hard water passes through a

chamber filled with resin, an exchange occurs

that removes hardness minerals from the water.

The sodium that replaces the hardness minerals

has a higher solubility in water and generally 

will not form scale. 

Pretreatment equipment. Pretreatment equipment

improves the quality of the incoming water so

that it may be used in the boiler without excessive scaling or foaming, which can reduce boiler

efficiency and cause tube failure. Pretreatment

equipment includes, but is not limited to, clarifiers,

filters, softeners, dealkalizers, decarbonators,

reverse osmosis (RO) units, and demineralizers. 

Deaerator, deaerating heater, and atmospheric deaerator. The presence of oxygen in the boiler system

can be a significant problem due to its corrosivity

at high temperatures. Deaerators and deaerating

heaters use heat, typically steam, to reduce the

oxygen content in water. Deaerators and deaerating heaters are typically pressurized tanks that

raise the water temperature to the point of saturation. They also break the incoming water into

either fine droplets or thin sheets to facilitate the

removal of oxygen and other non-condensable

gases. Depending on the design, the feedwater

oxygen content can be reduced to levels ranging

from 7 to 40 parts per billion (ppb). 

Atmospheric deaerators are typically found in

smaller, lower-pressure boiler systems. They

operate at atmospheric pressure, so the maximum

operating temperature is 212°F. Most will operate

at temperatures lower than this. Atmospheric

deaerators cannot achieve the same level of 

oxygen removal as deaerators and deaerating

heaters, typically providing water with oxygen 

levels of 0.5 to 1 parts per million (ppm).

In applications that require lower oxygen levels

than achievable with a deaerator, deaerating

heater, or open feedwater heater, a chemical

agent, known as an oxygen scavenger, can be

used to remove more oxygen. In most systems,

an oxygen scavenger is part of the system’s water

treatment program. 

For more information on these devices, see the

Steam Tip Sheet Number 18 titled Deaerators in

Industrial Steam Systems, provided in Appendix B.

Feedwater pump. Feedwater pumps transfer water

from the deaerator to the boiler. Feedwater

pumps are driven by electric motors or by steam

turbines. In a modulating feedwater system, the

feedwater pumps run constantly as opposed to

an on/off operation in relatively small boilers.

Collecting/Storage tank. The return of condensate

is often erratic due to changing steam requirements by the end uses. The condensate 

is usually returned to a condensate receiver or

directly to the deaerator if the system does not

have a receiver. Pretreated water may also be stored

in a tank prior to use. This provides the boiler 

system with additional water capacity in case 

the pretreatment equipment malfunctions. The

condensate and pretreated water, or makeup, 

are transferred from the storage tanks to the

deaerator prior to being sent to the boiler.

◆ Boiler Combustion Air System

The combustion air system supplies the oxygen

necessary for the combustion reaction. To provide enough air for the amount of fuel used in

industrial boilers, fans are typically required.

Dampers, inlet valves, or variable speed drives

typically control the amount of air allowed into

the boiler. 

Forced draft fan. A forced draft fan is located at

the inlet of a boiler and pushes ambient air into

the burner region, ensuring that adequate air is

delivered to the combustion process. These fans

either pull air directly from the boiler room or

connect to a duct system that allows outside air

to be drawn into the boiler.

A Sourcebook for Industry

Steam System Basics
10

Induced draft fan. Induced draft fans are located

on the outlet gas side of the boiler and pull flue

gases out. The induced draft fan creates a slightly

negative furnace pressure that is controlled by

outlet dampers on the boiler. In some systems

where a bag house, mechanical collector, or 

precipitator is involved, special considerations

should be given in sizing and selection of this fan. 

Damper. Dampers control the amount of air

allowed into and out of a combustion chamber.

Dampers, in combination with fuel regulating

devices, are positioned by the combustion control

system to achieve certain fuel-to-air ratios.

Dampers on the boiler outlet are used to regulate

the negative furnace draft.

◆ Boiler Fuel System

There are many different types of fuels used in

boilers, requiring several different types of fuel

handling systems. Fossil fuels such as coal, oil,

and gas are most commonly used. Waste fuels are

used in many industries, particularly the forest

products, petroleum refining, and chemical manufacturing industries where there is an available

supply of waste products such as bark, wood

chips, black liquor, and refinery gas. 

Fuel regulating valve. In gaseous and liquid fuels,

regulating valves control the fuel delivered to the

boiler. In many systems, these valves can be

quickly shut in response to an operating problem. 

Fuel. The fuel types that are commonly used in

boilers include natural gas, coal, propane, fuel

oils, and waste fuels (for example, black liquor,

bark, and refinery gas). Fuel type significantly

affects boiler operation, including efficiency, 

emissions, and operating cost. Natural gas

accounts for about 36% of the total U.S. industry

boiler capacity. Coal accounts for about 14% of

the boiler capacity. Fuel oils account for about

21%. Other fuels, which include waste fuels,

account for about 29% of the boiler capacity.9

Fuel flow meter. Fuel meters measure the amount of

fuel delivered to a boiler. Fuel meters provide

essential data in determining boiler efficiency.

Since fuel flow meters measure volume or mass of

fuel, it is important to know the energy content

of the fuel when determining boiler efficiency. 

For more information, see the Steam Tip Sheet

Number 15 titled Benchmark the Fuel Cost of

Steam Generation in Appendix B.

Burner. Burners combine the fuel and air to initiate

combustion. There are many different types of

burners due to the many different types of fuels.

Additionally, burners have different performance

characteristics and control requirements. Some

burners are on/off while others allow precise 

setting of the fuel:air mixture over a range of

conditions. Some burners can fire different types

of fuel, allowing boiler operation to continue

despite the loss of one fuel supply. 

◆ Boiler Blowdown System

The boiler blowdown system includes the valves

and the controls for the continuous blowdown

and bottom blowdown services. Continuous

blowdown removes a specific amount of boiler

water (often measured in terms of percentage of

feedwater flow) in order to maintain a desired

level of total dissolved solids in the boiler. Setting the flow for the continuous blowdown is

typically done in conjunction with the water

treatment program. Some continuous blowdown

systems rely on the input of sensors that detect

the level of dissolved solids in the boiler water.

The bottom blowdown is performed to remove

particulates and sludge from the bottom of the

boiler. Bottom blowdowns are periodic and are

typically performed a certain number of times

per shift or according to a set schedule. In some

systems, bottom blowdowns are controlled by 

an automatic timer. Bottom blowdown should

never be permitted unless it is recommended 

by the boiler manufacturer. This is because in

higher pressure boilers, especially those above

700 pounds per square inch gauge (psig), bottom 

blowdown may cause water starvation in some

portions of the boiler circuit.

Boiler blowdown heat exchangers and flash tank. 

The continuous blowdown water has the same 

temperature and pressure as the boiler water.

Before this high energy water is discharged into

the environment, it is often sent to a heat

exchanger and flash tank. Flash tanks permit the

recovery of low-pressure flash steam, which can

be used in deaeration or process heating. They

also permit the use of a smaller heat exchanger

Improving Steam System Performance

Steam System Basics

9 Derived from GRI, Analysis of the Industrial Boiler Population, Final Report No.-96/0200, 1996.
11

than would be required without the flash tank. 

Blowdown heat exchangers are most often used

to preheat boiler makeup water. 

For more information on boiler blowdowns, see

the Steam Tip Sheets Numbers 9 and 10 titled

Minimize Boiler Blowdown, and Recover Heat from

Boiler Blowdown in Appendix B.

Distribution

The distribution system transports steam from

the boiler to the various end uses. Although 

distribution systems may appear to be passive, 

in reality, these systems regulate the delivery of

steam and respond to changing temperature and

pressure requirements. Consequently, proper 

performance of the distribution system requires

careful design practices and effective maintenance.

The piping should be properly sized, supported,

insulated, and configured with adequate flexibility.

Pressure-regulating devices such as pressurereducing valves and backpressure turbines should

be configured to provide proper steam balance

among the different steam headers. Additionally,

the distribution system should be configured to

allow adequate condensate drainage, which

requires adequate drip leg capacity and proper

steam trap selection. Steam distribution systems

can be broken down into three different categories:

buried pipe, above-ground, and building sections,

and selection of distribution components (piping,

insulation, etc.) can vary depending on the 

category. 

◆ Piping

Steam piping transports steam from the boiler to

the end-use services. Important characteristics of

well-designed steam system piping are that it is

adequately sized, configured, and supported.

Installation of larger pipe diameters may be more

expensive, but can create less pressure drop for a

given flow rate. Additionally, larger pipe diameters

help to reduce the noise associated with steam

flow. As such, consideration should be given to

the type of environment in which the steam 

piping will be located when selecting the pipe

diameter. Important configuration issues are

flexibility and drainage. With respect to flexibility,

piping (especially at equipment connections),

needs to accommodate thermal reactions during

system start-ups and shutdowns. Additionally,

piping should be equipped with a sufficient

number of appropriately sized drip legs to promote

effective condensate drainage. Additionally, the

piping should be pitched properly to promote

the drainage of condensate to these drip lines.

Typically, these drainage points experience two

very different operating conditions, normal 

operation and start-up; both load conditions

should be considered in the initial design.

◆ Insulation

Thermal insulation provides important safety, 

energy savings, and performance benefits. In

terms of safety, insulation reduces the outer 

surface temperature of the steam piping, which

lessens the risk of burns. A well-insulated system

also reduces heat loss to ambient workspaces,

which can make the work environment more

comfortable. Consequently, the energy saving

benefits include reduced energy losses from 

the steam system and reduced burden on the

cooling systems that remove heat from workspaces.

In addition to its safety and energy benefits,

insulation increases the amount of steam energy

available for end uses by decreasing the amount

of heat lost from the distribution system. 

Important insulation properties include thermal

conductivity, strength, abrasion resistance, workability, and resistance to water absorption. Thermal

conductivity is the measure of heat transfer per

unit thickness. Thermal conductivity of insulation

varies with temperature; consequently, it is

important to know the right temperature range

when selecting insulation. Strength is the measure of the insulation’s ability to maintain its

integrity under mechanical loads. Abrasion resistance is the ability to withstand shearing forces.

Workability is a measure of the ease with which

the insulation is installed. Water absorption

refers to the tendency of the insulation to hold

moisture. Insulation blankets (fiberglass and 

fabric) are commonly used on steam distribution

components (valves, expansion joints, turbines,

etc.) to enable easy removal and replacement for

maintenance tasks.

Some common insulating materials used in steam

systems include calcium silicate, mineral fiber,

fiberglass, perlite, and cellular glass. The American

Society for Testing and Materials (ASTM) provides

standards for the required properties of these 

and other insulation materials. Additionally, 

the North American Insulation Manufacturers

Association (NAIMA) has developed a software

A Sourcebook for Industry

Steam System Basics
12

program titled 3E Plus that allows users to 

determine the energy losses associated with 

various types and thicknesses of insulation. 

The 3E Plus program facilitates the assessment of

various insulation systems to determine the most

cost-effective solution for a given installation.

See Section 2, page 27 for more about 3E Plus

Insulation software, which can help steam users

assess insulation opportunities. 

For more information on insulation, refer to Steam

Tip Sheets Numbers 2 and 17 titled Insulate Steam

Distribution and Condensate Return Lines and Install

Removable Insulation on Uninsulated Valves and Fittings. Both can be found in Appendix B.

◆ Valves

In steam systems, the principal functions of valves

are to isolate equipment or system branches, to

regulate steam flow, and to prevent overpressurization. The principal types of valves used in steam

systems include gate, globe, swing check, pressure

reducing, and pressure relief valves. Gate, globe,

and swing check valves typically isolate steam

from a system branch or a component. Pressure

reducing valves (PRV) typically maintain certain

downstream steam pressure conditions by controlling the amount of steam that is passed. These

reducing valves are often controlled by transmitters that monitor downstream conditions. Pressure

relief valves release steam to prevent overpressurization of a system header or equipment.

◆ Steam Separators

In some steam systems, wet steam is generated.

This wet steam contains water droplets that can

reduce the effectiveness of the steam system.

Water droplets erode turbine blades and passages,

and pressure reducing valves, thus reducing efficiency and life. Furthermore, liquid water can

significantly reduce heat transfer rates in heat

exchange components, as well as result in water

hammer. Removing water droplets before they

reach end-use equipment is necessary. 

Steam separators remove water droplets, generally

relying on controlled centrifugal flow. This action

forces the entrained moisture to the outer wall

where it is removed from the separator. The

means of moisture removal could be a steam 

trap or a drain. Some manufacturers include the

trap as an integral part of the unit. Additional

accessories include water gauge connections, 

thermometer connections, and vent connections.

Steam separators can be installed in either a horizontal or vertical line. They are capable of removing 99% of particulate entrainment 10 microns

and larger over a wide range of flows. Separators

are often designed in accordance with ASME

Code, Section VIII, Division 1 with pressures to

300 psig.

◆ Steam Accumulators

A steam accumulator is a large insulated pressure

vessel, partially filled with hot water (saturated

liquid). When steam supply exceeds demand, the

excess high-pressure steam is charged into the

accumulator through special charging nozzles.

The steam is condensed, giving up its latent 

heat, to raise the pressure, temperature, and heat

content of the water body. When the steam

demand exceeds the supply, the pressure in the

accumulator drops and the additional required

steam flashes from the water, taking back the heat

previously stored. A simple system of control

valves and check valves regulates the charging

and discharging. The excess steam is charged 

quietly and smoothly, and when steam is needed,

it is available with the speed of a control valve

operation. There is also an accumulator design

that stores hot water for use as boiler feedwater.

◆ Steam Traps

Steam traps are essential for proper distribution

system performance. During system start-ups,

traps allow air and large quantities of condensate

to escape. During system operation, the traps

allow collected condensate to pass into the 

condensate return system, while minimizing the

accompanying loss of steam. There are three 

primary types of traps: thermostatic, mechanical,

and thermodynamic.10

◆ Thermostatic Traps

Thermostatic traps use temperature differential to

distinguish between condensate and live steam.

This differential is used to open or close a valve.

Under normal operating conditions, the condensate must cool below the steam temperature

before the valve will open. Common types of thermostatic traps include bellows and bimetallic traps. 

Improving Steam System Performance

Steam System Basics

10The following discussion of steam traps is based extensively on C. B. Oland, Review of Orifice Plate Steam Traps, 

Oak Ridge National Laboratory, January 2001.
13

Bellows traps. Bellows traps include a valve 

element that expands and contracts in response

to temperature changes. Often a volatile chemical such as alcohol or water is inside the element.

Evaporation provides the necessary force to change

the position of the valve. At start-up, the bellows

trap is open due to the relative cold condition.

This operating condition allows air to escape 

and provides maximum condensate removal

when the load is the highest. Bellows traps can

fail either open or closed. The configuration of a

bellows steam trap is shown in Figure 4.

Bimetallic traps. Bimetallic traps rely on the bending of a composite strip of two dissimilar metals

to open and close a valve. Air and condensate

pass freely through the valve until the temperature of the bimetallic strip approaches the steam

temperature. After steam or relatively hot condensate heats the bimetallic strip and causes it to

close the valve, the trap remains shut until the

temperature of the condensate cools sufficiently

to allow the bimetallic strip to return to its original shape and thereby open the valve. Bimetallic

traps can fail in either the open or closed position. The configuration of a bimetallic steam trap

is shown in Figure 5.

◆ Mechanical Traps

Mechanical traps use the difference in density

between condensate and live steam to produce a

change in the position of a float or bucket. This

movement causes a valve to open or close. There

are a number of mechanical trap designs that are

based on this principle. They include ball float,

float and lever, inverted bucket, open bucket,

and float and thermostatic traps. 

Ball float traps. Ball float traps rely on the movement of a spherical ball to open and close the

outlet opening in the trap body. When no condensate is present, the ball covers the outlet

opening, thereby keeping air and steam from

escaping. As condensate accumulates inside the

trap, the ball floats and uncovers the outlet 

opening. This movement allows the condensate

to flow continuously from the trap. Unless they

are equipped with a separate air vent, ball float

traps cannot vent air on start-up.

Float and lever traps. Float and lever traps are similar in operation to ball float traps except the ball

is connected to a lever. When the ball floats

upward due to accumulation of condensate inside

the trap body, the attached lever moves and causes

a valve to open. This action allows condensate to

continuously flow from the trap. If the condensate

load decreases and steam reaches the trap, downward ball movement causes the valve to close,

thereby keeping steam from escaping. Unless they

are equipped with a separate air vent, float and

lever traps can not vent air on start-up. See the discussion on float and thermostatic traps.

Inverted bucket traps. Inverted bucket traps are

somewhat more complicated than float and lever

traps. At start-up, the inverted bucket inside the

trap is resting on the bottom of the trap body and

the valve to which the bucket is linked is wide

open. The trap is initially filled with condensate.

As steam enters the trap and is captured inside

the bucket, it causes the bucket to move upward. 

This upward movement closes the valve and keeps

steam from escaping. When the condensate 

collects and cools the steam, the bucket moves

downward. This movement causes the valve to

open, thereby allowing the condensate to escape.

Unlike closed float traps, inverted bucket traps

have intermittent discharge. These traps can be

A Sourcebook for Industry

Steam System Basics

Steam &

Condensate In

Liquid

Condensate

& Flash Out

Bellows Element

Valve

Seat

Steam and/or

Hot Condensate

Depending on

Trap

Steam &

Condensate In

Liquid

Condensate

& Flash Out

Hot or

Subcooled Liquid

Condensate

Bimetallic Elements

Valve Seat

Figure 4. Thermostatic Steam Trap with a Bellows 

Element

Figure 5. Thermostatic Steam Trap with a Bimetallic 

Element
14

Steam System Basics

Improving Steam System Performance

depleted of their condensate seal when applied

in superheated steam service. If this occurs, the

trap will continuously discharge live steam. This

trap type is not recommended for superheated

steam service, unless special installation conditions are met. The configuration of an inverted

bucket steam trap is shown in Figure 6.

Open bucket traps. Open bucket traps consist of an

upright bucket that is attached to a valve. At

start-up, the bucket rests on the bottom of the

trap body. In this position, the valve is wide

open. As condensate accumulates in the trap

body on the outside of the bucket, the bucket

floats upward, causing the valve to close. When

sufficient condensate accumulates outside the

bucket, it spills over the top and fills the inside

of the bucket. At this time, the bucket sinks, 

causing the valve to open. This trap is also prone

to failure when applied in superheated steam

service because of the loss of the condensate seal.

Like inverted bucket traps, open bucket traps

have intermittent discharge.

Float and Thermostatic (F&T) traps. Float and thermostatic (F&T) traps are similar to float and lever

traps except they include a thermostatic element

that allows air to be discharged at start-up and

during operation. The thermostatic elements

used in these traps are the same as those used in

thermostatic traps. The configuration of a float

and thermostatic steam trap is shown in Figure 7.

◆ Thermodynamic Traps

Thermodynamic traps use the difference in kinetic energy (velocity) between condensate and live

steam to operate a valve. The disc trap is the

most common type of thermodynamic trap, but

piston or impulse traps are sometimes used. 

Disc traps. Disc traps use the position of a flat disc

to control steam and condensate flow. When 

condensate flows through the trap, the disc is

raised, thereby causing the trap to open. As

steam and air pass through the trap, the disc

moves downward. The force that causes the disc

to move downward is generated by the difference

in pressure between the low-velocity steam above

the disc and the high-velocity steam that flows

through the narrow gap beneath the disc. Disc

traps commonly have an intermittent discharge

and, when they fail, they normally fail open. 

The configuration of a disc steam trap is shown

in Figure 8. Generally, the air removal capability

of this trap type is poor unless equipped with

additional components (like the float and 

thermostatic trap).

Piston traps. Piston or impulse traps utilize the

heat energy in hot condensate, and the kinetic

energy in steam, to open and close a valve. Like

disc traps, piston traps are phase detectors that

sense the difference between a liquid and gas or

vapor. They continuously discharge any air and

condensate. Their primary failure mode is open.

Vent Hole

Seat Steam Spaces

Condensate Level

Steam Bubbles

Inverted Bucket Valve

Lever

Liquid 

Condensate 

& Flash Out

Seat

Air Vent

Valve

Float Lever

Steam

Space

Condensate

Level

Liquid Condensate

& Flash Out

Steam &

Condensate In Liquid 

Condensate 

& Flash Out

Valve Disc

Outlet Port

Seating Surface Inlet Port

Bonnet Chamber

Flash Vapor Closes

Valve Disc

Steam & 

Condensate In

Steam & 

Condensate In

Figure 6. Inverted Bucket Steam Trap

Figure 7. Float and Thermostatic Steam Trap

Figure 8. Thermodynamic Disc Steam Trap
15

Lever traps. Lever traps are a variation of the 

thermodynamic piston trap. They operate on the

same principal as a piston trap but with a lever

action to pass large amounts of condensate and

air on a continuous basis. Their primary failure

mode is open. 

Orifice traps. Orifice traps are of two basic types:

orifice plate and short tube. Both trap types operate under the exact same principles. A simple 

orifice plate steam trap consists of a thin metal

plate with a small-diameter hole (orifice) drilled

through the plate. When installed, condensate

that accumulates is continuously removed as the

steam pressure forces the condensate through the

orifice. During conditions when no condensate

is present, a limited amount of steam flows

through the orifice. The report Review of Orifice

Plate Steam Traps on page 49 of the Where to

Find Help section provides information for 

making informed decisions about when orifice

plate steam traps should be considered for use 

in new or existing steam systems.

Additional information regarding steam traps is

available in the Steam Tip Sheet Number 1 titled

Inspect and Repair Steam Traps, found in Appendix B.

◆ Steam Meters

The use of flowmeters within the distribution

system can provide important data for monitoring the efficiency of a process or an end use.

Tracking the amount of steam required can be

particularly useful in benchmarking efforts. The

types of steam flowmeters are discussed in the

Generation Section. 

End Use

Steam system end-use equipment transfers steam

energy into other forms of useful energy. Common

end-use equipment includes heat exchange devices

to transfer thermal energy and turbines to recover

mechanical energy. In manufacturing industries,

steam end uses often directly support production,

making their performance and reliability essential

to plant productivity. Improvements in end-use

efficiency and effectiveness also tend to result in

better performance and increased reliability. There

is a wide range of end-use equipment, largely 

due to the advantages of steam that are discussed

in the Introduction. Some of the major end-use

components are discussed in this section. 

For the purposes of this discussion, steam end-use

equipment is grouped into three basic categories: 

■ Industries of the Future11 (IOF) key end-use 

equipment

■ Conditioning and control equipment

■ Additional equipment.

The key IOF equipment category includes the

largest uses of steam in those industries. Although

IOF facilities use steam for other services as well,

the key end uses account for the largest amount

of steam use. The conditioning equipment 

category includes equipment that facilitates the

effective use of steam. The additional equipment

category includes equipment that is used in other

industries and, though significant, does not

account for most of the steam use in IOF industries.

Industries of the Future Key End-Use Equipment

In the three IOF industries of forest products, 

petroleum refining, and chemicals, steam accounts

for the largest amount of end-use energy. In

another IOF industry, steel production, steam

represents a significant amount of end-use energy

and is used to generate most of that industry’s

on-site electric power. Table 1 provides a list of

key steam-supplied end-use equipment for IOF

industries.

◆ Condensers

In steam applications, condensers are associated

with condensing steam turbines and with multiple stage ejector systems. In steam turbine applications, condensers typically operate under a

vacuum. They remove energy from the exhaust

steam, allowing it to be recovered as condensate.

In steam ejector applications, condensers increase

the effectiveness of the ejectors by condensing

both the motive steam and condensables pulled

from the process, reducing the amount of motive

steam required. 

Condensers can be surface type or barometric.

Surface condensers are supplied with cooling

water that circulates through condenser tubes,

providing a cool surface area that causes steam

condensation. The condensate is typically 

A Sourcebook for Industry

Steam System Basics

11 Industries of the Future (IOF) include: aluminum, chemicals, forest products, glass, metal casting, mining, 

petroleum refining, and steel.
16

collected in a condensate well, and pumped into

the condensate return system. Barometric condensers rely on direct contact between the cooling water and the steam. In petroleum refining

and chemical manufacturing applications, condensers are also used to condense components

from gaseous mixtures. In these applications, 

the condensers use a cooling medium to extract

energy from the gases and collect the condensed

components.

◆ Distillation Towers

The petroleum refining and chemical manufacturing industries use large amounts of steam to

facilitate the separation of crude oil or chemical

feedstocks into various components. This separation process relies on differences in the boiling

points of these hydrocarbon components. Fractionating towers use a furnace to heat crude oil above

700°F. As the volatile components boil off and

rise up the tower, they cool and condense on trays.

Steam is injected into the bottom of these towers

to reduce the partial pressures of the hydrocarbons,

which facilitates their separation, and to reduce

coke formation on tray and tower surfaces.

◆ Dryers

Dryers reduce the water content of a solid. Dryers account for the largest end use of steam in

the pulp and paper industry.12 The chemical

Improving Steam System Performance

Steam System Basics

Equipment Process Application Industry

Condenser Steam turbine operation Aluminum, Chemical Manufacturing, Forest

Products, Glass, Metal Casting, Petroleum

Refining, and Steel

Distillation tower Distillation, fractionation Chemical Manufacturing, Petroleum Refining

Dryer Drying Forest Products

Evaporator Evaporation/concentration Chemical Manufacturing, Forest Products

Petroleum Refining

Process heat Alkylation, Process air heating, Process water Aluminum, Chemical Manufacturing, Forest

exchanger heating, Gas recovery/Light ends distillation, Products, Glass, Metal Casting, Petroleum

Isomerization, Storage tank heating Refining, and Steel

Visbreaking/Coking

Reboiler Fractionation Petroleum Refining

Reformer Hydrogen generation Chemical Manufacturing, Petroleum Refining

Separator Component separation Chemical Manufacturing, Forest Products,

Petroleum Refining

Steam ejector Condenser operation, Vacuum distillation Aluminum, Chemical Manufacturing, Forest

Products, Glass, Metal Casting, Petroleum

Refining, and Steel

Steam injector Agitation/blending, Heating Chemical Manufacturing, Forest Products,

Petroleum Refining

Steam turbine Power generation, Compressor mechanical Aluminum, Chemical Manufacturing, Forest

drive, Hydrocracking, Naphtha reforming, Products, Glass, Metal Casting, Petroleum

Pump mechanical drive, Feed pump Refining, and Steel

mechanical drive

Stripper Distillation (crude and vacuum units), Chemical Manufacturing, Petroleum Refining

Catalytic cracking, Asphalt processing,

Catalytic reforming, Component removal,

Component separation, Fractionation,

Hydrogen treatment, Lube oil processing

Thermocompressor Drying, Steam pressure amplification Forest Products

Table 1. Key IOF Steam End-Use Equipment

12 Giese & Associates, Scoping Study of the Pulp and Paper Industry, EPRI, 1988.
17

manufacturing, textiles, and food processing

industries also use large amounts of steam for

drying. Dryers can be indirect or direct. Indirect

dryers remove moisture thermally as energy is

transferred from condensing steam, flue gases, 

or high temperature process fluid to the product

being dried. Common indirect dryer types are

coil and rotating drum. Direct dryers use hot

gases that have been heated with steam or flue

gases to directly contact and dry a product. 

Dryers, like evaporators, can be arranged in multiple-stage configurations. Multiple-stage steam

dryers use a cascading set of steam pressures, allowing steam released from an upstream stage to supply steam to the next stage. In many multiple-stage

dryers, thermocompressors are used to increase

the steam pressure of downstream-effect stages.

◆ Evaporators

Evaporators reduce the water content of a liquid,

generally by heating it with steam in order to 

concentrate the product. Evaporators are used

extensively in industries such as food processing,

chemical manufacturing, steel, forest products,

and textiles. 

In most cases, evaporators are shell and tube heat

exchangers with the steam on the shell side and

the product being concentrated in the tubes.

Evaporators can be single effect or multiple effect.

A single-effect evaporator uses steam at one set of

pressure and temperature conditions to boil off the

vapor from a product. Multiple-effect evaporators

take the vapor produced from one evaporator and

use it to heat the product in a lower-pressure

evaporator. Multiple-effect evaporators are generally more efficient at concentrating a fluid than

single-effect evaporators.

◆ Heat Exchangers

Heat exchangers transfer thermal energy from one

fluid to another. In manufacturing facilities, steam

is a common source of heat for many reasons,

some of which are discussed in the Introduction.

There is a wide range of heat exchanger designs

that use steam, largely due to the wide range of

products that are heated with steam. Many process

and product considerations must be incorporated

into the selection of a heat exchanger. Some

basic heat exchanger types are discussed below,

including:

■ Tubular

■ Plate and frame

■ Jacketed

■ Coil.

Tubular heat exchanger. Tubular heat exchangers

are tube bundles that are surrounded by the

heated or heating medium. This type of heat

exchanger includes finned tube and shell and

tube designs as shown in Figure 9. Finned tube

heat exchangers are often used to heat air for

drying and space heating applications. Shell and

tube heat exchangers are often used for liquid

heating and evaporation. Since the tube side of

shell and tube heat exchangers can be designed

to withstand high pressures, sometimes exceeding 1,500 psig, heat exchangers of this type are

often used in high temperature and high-pressure

applications.

Plate and frame heat exchanger. In plate and frame

heat exchangers, the two heat exchange fluids

are separated by plates. The plates are corrugated,

or ridged, as shown in Figure 10, to increase the

surface area available for heat transfer. Plate and

frame heat exchangers are often used in lowviscosity applications, where the risk of clogging

is less severe. The plate ends are typically sealed

by gasketed covers that can be removed to allow 

disassembly and cleaning. This heat exchanger

type is used when temperatures and pressures are

moderately low, typically below 300°F and 370 psi.

Plate and frame heat exchangers also have a

common design variation that has the plates

welded or brazed together. This allows higher

temperature service but eliminates the possibility

of mechanical cleaning.

Jacketed heat exchangers. Jacketed heat exchangers use an enclosure to surround the vessel that 

contains the heated product. A common example

of a jacketed heat exchanger is the jacketed 

kettle. A representation of a jacketed heat

exchanger is shown in Figure 11. Jacketed heat

exchangers are practical for batch processes and

for product types that tend to foul or clog tube

bundles or coils.

A Sourcebook for Industry

Steam System Basics
Coil heat exchangers. Coil heat exchangers characteristically use a set of coils immersed in the

medium that is being heated. Coil heat exchangers are generally compact, offering a large heat

transfer area for the size of the heat exchanger. 

◆ Reboilers

Reboilers are typically used in distilling processes

to increase component separation. Reboilers use

heat, often provided by steam, to evaporate the

volatile components of a product that has been

drawn from a fractionating tower. These volatile

components are sent downstream for further 

processing. The residual components are sent

back into the fractionating tower or sent on to a

vacuum distillation process. There are several types

of reboilers, including jacketed kettle, kettle, internal reboiler, and thermosyphon reboiler. These

designs differ from one another in the way the

product is heated with steam. 

◆ Reformers

Steam reformers are used to

generate hydrogen, typically

from a hydrocarbon feedstock

such as methane (the largest

component of natural gas). In

turn, hydrogen is used in many

petroleum refining and chemical manufacturing processes.

Reformers use steam for both

energy and as a source of

hydrogen. Steam is injected

with the hydrocarbon feedstock to initiate the following

reaction: 

Reformers often have secondary stages that are

used to convert the carbon monoxide to carbon

dioxide and additional hydrogen. Although large

amounts of steam are used throughout the

reforming processes, steam is also generated by

the reformers and is sometimes exported for

other uses. 

◆ Steam Ejectors

Steam ejectors use steam flow through a nozzle

to create a vacuum (similar in operation to thermocompressors). They are used in several different

types of system applications and process equipment. Low-pressure conditions promote the

evaporation of liquids at reduced temperatures.

18

Steam System Basics

Improving Steam System Performance

Tube Side Fluid

Tube Bundle

Tubesheet

Shell Side Fluid

Baffles

Plates

Compression Fasteners

Frame

Kettle

Steam

Condensate

Steam

Jacket

Figure 9. Shell and Tube Heat Exchanger

Figure 10. Components of a Plate and Frame 

Heat Exchanger

Figure 10. Configuration of a Jacketed Kettle

Heat Exchanger

CH4 + H2O → CO + 3H2

Methane Steam Carbon Hydrogen

monoxide
19

Consequently, many chemical manufacturing

processes use steam ejectors to increase the 

concentration of a product. In petroleum 

refining, steam ejectors are commonly used 

in the vacuum distillation of heavy hydrocarbon products. Steam ejectors are also used 

to initiate and maintain vacuum condition

in the condensers of condensing turbines. 

◆ Steam Injectors

Steam injectors are used to inject steam directly

into a tank or a pipe containing a process fluid,

generally for heating purposes. Many injector

types use a nozzle and a diffuser to pull process

fluid into the steam before the mixture is injected

into the process fluid, to promote an even distribution of heat. Important performance characteristics of injectors include accurate control of the

amount of steam injected and effective mixing 

of the steam and process. 

◆ Steam Turbines

Steam turbines are used to drive electric generators

or other rotating machinery such as compressors,

pumps, and fans. Steam turbines are used in

many different system designs, depending on 

the relative requirements for steam, electricity, or

other mechanical loads. Steam turbines provide

an effective means of stepping down steam 

pressure while extracting mechanical work. 

Additional information regarding steam turbines

is available in Steam Tip Sheets Numbers 15 and

21 titled Benchmark the Fuel Costs of Steam Generation and Consider Steam Turbine Drives for Rotating Equipment, found in Appendix B.

Some turbines have interstage take-offs that

allow steam to be extracted at various pressures

before reaching the turbine exhaust. These

extractions provide flexibility in meeting competing requirements of both the steam system

and the mechanical load. For example, if the 

turbine is connected to an electric generator,

adjusting the amount of extracted steam can

allow more or less electric power to be generated,

while making respectively less or more steam

available to the plant.

Backpressure turbines. Backpressure turbines

exhaust steam at pressures that are higher than

atmospheric, and the exhaust steam is then used

for other services. By extracting mechanical work

from steam, backpressure turbines can provide 

an efficient means of supplying lower-pressure

steam from a high-pressure header.

Condensing turbines. Condensing turbines exhaust

steam to vacuum (sub-atmospheric) conditions.

This steam is condensed in a heat exchanger,

referred to as a condenser, and transferred to the

condensate return system. Condensing turbines

typically require a source of cooling water to 

condense the steam.

◆ Strippers

Steam strippers are used to remove contaminants

from a solution. Strippers are commonly found

in petroleum refining and chemical manufacturing applications, where process solutions contain

components that have different boiling points

and removal of one or more of the components

is necessary. Injecting steam into the process

solution lowers the partial pressure of volatile

components, allowing some of them to vaporize

and get transported away with the steam. Steam

can also raise the temperature of the mixture,

lowering the solubility of the objectionable material and causing it to strip off with the steam.

Often, the steam and the contaminants are condensed and separated, allowing recovery of the

condensate and disposal or further processing of

the contaminant.

◆ Thermocompressors

Thermocompressors combine high-pressure and

low-pressure steam to form an intermediatepressure steam supply (see Figure 12). Often the

low-pressure steam does not have enough energy

to be feasibly used; however, discharging it to the

condensate return system can be an unnecessary

energy loss. Thermocompressors use a high-pressure steam source to recover the energy from this

low-pressure source, providing an intermediate

steam supply that can be feasibly used.

◆ Conditioning and Control Equipment

Conditioning equipment is generally used to

improve the performance of, or to protect the

end-use equipment. For example, desuperheaters

are often used to control the energy of a steam

supply to end-use equipment to reduce the risk

of damage to the equipment or to effectively

improve temperature control of the process.

A Sourcebook for Industry

Steam System Basics
20

Desuperheaters. The purpose of a desuperheater 

is to remove the superheat from steam. The

majority of heating and process equipment 

performs more efficiently using saturated rather

than super-heated steam. Desuper-heaters inject

a very fine mist of high-purity water, such as

condensate, into the steam flow. The superheated

vapor gives up heat to the water mist, and by

doing so, reduces its temperature.

Vacuum breakers. Vacuum conditions can develop

in a steam system when steam flow into a component or a branch is throttled or shut off. If the

rate of downstream steam use exceeds the steam

supply, the pressure decreases and vacuum conditions can form. Vacuum conditions also result

when the load on the heat exchanger is significantly less than the heat exchanger capacity. If

the pressure in the heat exchanger drops too far,

the condensate will not drain from the trap due

to a higher pressure on the trap’s downstream

side. If uncorrected, the condensate level will 

rise in the heat exchanger, reducing the available

heat transfer area and increasing the risk of 

corrosion by condensate. Vacuum breakers are

pressure-controlled devices that essentially vent 

a heat exchanger or system branch in which a

vacuum has formed. By allowing in air when

they open, vacuum breakers restore pressure and

allow the condensate to drain.

Air vents. Before start-up, the steam system contains air that must be removed. The presence 

of air in a steam system reduces heat transfer

effectiveness and promotes condensate corrosion.

Air vents remove this air. Air vents are often 

thermostatic devices, similar to thermostatic

steam traps that rely on the temperature difference between air and steam.

When exposed to the lower

temperature air in the system

side, the vent opens. As the

higher temperature steam reaches the vent, it closes, preventing the escape of steam.

Traps. Steam traps are important

to the performance of end-use

equipment. Traps provide for

condensate removal with little

or no steam loss. If the traps do

not function properly, excess

steam will flow through the

end-use device or the condensate will back up into it. Excess

steam loss will lead to costly operation while

condensate backup will promote poor performance and may lead to water hammer. Traps can

also remove non-condensable gases that reduce

heat exchanger effectiveness. There are several

different types of steam traps, which are discussed in the Distribution section of this Sourcebook. 

◆ Insulation

End-use equipment, such as heat exchangers 

and turbines, should generally be insulated due

to the significant heat loss that the surface areas

of this equipment can provide. The various types

of insulation are discussed in the Distribution

section of this Sourcebook. Where end-use equipment requires frequent inspection or maintenance,

removable insulation should be considered.

◆ Additional Equipment

The additional equipment category refers to end

uses throughout industry, which, though still 

significant users of steam, generally account for

less steam energy than the key IOF end uses.

Absorption chillers. Absorption chillers provide

cooling using an interesting variation of the

vapor compression cycle. Instead of a compressor, which is generally used in chillers, absorption chillers exploit the ability of one substance

to absorb a refrigerant at one temperature and

then release it at another. In ammonia-based 

systems, water is the absorbent and ammonia 

is the refrigerant. In lithium bromide-based 

systems, lithium bromide is the absorbent, while

water is the refrigerant. An absorption chiller

uses a pump instead of a compressor to increase

Improving Steam System Performance

Steam System Basics

Discharge

(intermediate

pressure)

Motive Steam

(high pressure)

Suction (low pressure)

Figure 12. Thermocompressor Operation
21

refrigerant pressure. Once it is at the higher 

pressure, the absorbent/ refrigerant solution is

heated, often with steam, which releases the refrigerant. Although absorption chillers generally have

lower coefficients of performance (COP) (indicating

lower thermodynamic efficiency) than traditional

chillers, they use less electric power per ton of cooling and are well suited for use with steam systems.

Humidifiers. Humidifiers inject steam into an air

or other gas source to increase its water vapor

content. In humidification, steam is used as a

source of both water and energy. Humidification

applications are found in the chemical manufacturing industry where control of ambient

temperature and moisture content are critical 

for product quality. 

Preheat/Reheat air handling coils. Steam is often

used in space heating applications to preheat 

and reheat air. In many HVAC systems, the 

conditioned air must have both its temperature

and humidity adjusted. In preheat applications,

steam is used to heat an air supply, which is 

typically a mixture of return air and outside air.

The air is then conditioned to achieve a certain

humidity and temperature. In reheat applications, the air is cooled to a particular dew point

to remove water and achieve a desired humidity.

As a result, before the air is delivered back to the

workspaces, steam coils must reheat the process

air stream up to the proper temperature. In both

reheat and preheat applications, finned tube heat

exchangers are generally used.

Tracing. In tracing applications, steam is used to

maintain the temperature of a fluid in a pipe. 

A common application of tracing lines is to 

prevent the freezing of a process fluid in piping

that runs outside of a temperature controlled

area. Since tracing lines are exposed to freezing

conditions, proper insulation, steam flow, and

condensate drainage are essential to prevent

freezing of the tracing lines as well as the 

process piping. 

Meters. Steam meters are used to measure steam

flow, and are important for tracking the steam

use of a particular part of a steam system or a

particular end use. Discussion of different meter

types is provided in the Steam Generation 

section of this Sourcebook.

Recovery

The recovery components of a steam system 

collect and return condensate back to the generation part of the system. Condensate recovery

provides thermal and water treatment benefits.

Condensate that is not returned must be compensated for by the addition of makeup water,

which is generally much cooler than condensate.

Condensate temperature often exceeds 200°F

while makeup water temperature is typically

between 50°F and 80°F. As a result, the enthalpy

difference between condensate and makeup

water is generally over 120 Btu/lb, an amount 

of energy that is often more than 10% of the

energy in the boiler generated steam. 

Additionally, makeup water is generally treated

with chemicals that remove minerals and establish certain pH levels in the boiler water and in

the system. Reducing the amount of makeup

water added to the system reduces chemical use.

Additionally, some of the treatment chemicals

that are contained in condensate are problematic

to a plant’s wastewater treatment facility. Industrial steam plants often extend across large areas.

Recovering condensate from steam systems

requires piping, collecting tanks, pumping equipment, and, in many cases, flash steam separators,

meters, and filtration/cleanup equipment. However, the cost savings available from avoiding the

purchase, treatment, and heating of makeup

water often make investments in condensate

recovery systems highly feasible. 

For more information on condensate recovery,

see the Steam Tip Sheet Number 8 titled Return

Condensate to the Boiler, provided in Appendix B.

◆ Condensate Return Piping

Condensate return piping transports condensate

as it drains from distribution and end-use equipment piping back to the boiler. Condensate 

piping should be adequately sized and insulated.

Although the installation of larger pipe diameters

is more expensive, larger pipes create less pressure

drop for a given flow rate; this reduces the load

on the condensate pumps. Larger pipe diameters

also reduce the noise associated with condensate

flow and are more suitable for carrying flash

steam. Insulating the condensate piping helps to

retain the thermal energy that provides much of

the benefits of a condensate recovery system.

A Sourcebook for Industry

Steam System Basics
22

◆ Insulation

Insulation provides energy savings and safety

benefits. In terms of energy savings, insulation

reduces heat loss from the condensate piping and

recovery equipment surfaces, which can make

the surrounding work environment more comfortable. Reducing this heat loss can also reduce

the burden on the cooling systems that support

surrounding workspaces. In terms of safety, 

insulation reduces the outer surface temperature

of the piping, which lessens the risk of burns.

Important insulation properties and characteristics of piping insulation are discussed in the 

Distribution section of this Sourcebook. 

◆ Condensate Receiver Tanks

Condensate receiver tanks collect and store 

condensate. These tanks are usually located

remotely around the condensate system and are

configured in conjunction with condensate

pumps, as shown in Figure 13. Condensate flows

can be highly variable due to changes in steam

demand, especially during system start-ups.

Receiver tanks minimize the effects of this flow

variability on condensate pumps by providing

storage, which maintains a minimum water level

that prevents downstream condensate pumps

from running dry. Since many condensate pumps

are centrifugal types, it is important to keep a 

certain suction pressure to prevent cavitation

damage. By maintaining a minimum condensate

level, receiver tanks provide enough static 

pressure to avoid cavitation.

Most systems also contain a large condensate

receiver tank that collects all the condensate

returned from the system. This tank may also 

be used to store pretreated water. 

◆ Condensate Pumps

Condensate pumps move condensate from receiver tanks back to the boiler room. Condensate

pumps can be driven by electric motors, steam, or

compressed air, depending on the availability of

these sources. Motor-driven condensate pumps are

usually centrifugal type pumps. In many cases,

receiver tanks and motor driven pumps are packaged together and equipped with a control system

that de-energizes the pump under low water level

conditions. Steam or compressed air powered 

condensate pumps are used where electrical

pumps would not be suitable, and are generally

pressure powered pumps. 

Condensate pumps also can be important to the

performance of end-use equipment. Effective use

of condensate pumps can eliminate condensate

back up into end-use equipment, improving

process control and reducing potential equipment

problems from condensate acidification and

water hammer.

◆ Flash Steam Vessels

Flash steam vessels allow the recovery of steam

from condensate lines, as illustrated in Figure 14.

By removing steam from the condensate system,

flash steam vessels provide an efficient source of

steam to low-pressure end uses. For example,

250°F condensate has a saturation pressure of

about 15 psig. Consequently, steam that is 

separated by flash steam vessels can be used in

low-pressure steam applications such as space

heating and preheating. 

For more information on flash steam vessels, see

the Steam Tip Sheet Number 12 titled Flash HighPressure Condensate to Regenerate Low-Pressure

Steam provided in Appendix B.

◆ Condensate Meters

Condensate meters measure the flow rate of 

condensate in the return system. Knowing the 

condensate flow rate can be helpful in monitoring the condensate system and the condition of

steam traps. Condensate meters are often inline

rotary types, relying on turbine or scroll rotation

to measure flow rate. 

◆ Filtration/Cleanup Equipment

In many systems, the flow of steam and condensate picks up rust, scale, and trace contaminants

Improving Steam System Performance

Steam System Basics

Condensate

Pump

Condensate

Receiver

Tank

Outlet

Inlet

Figure 13. Condensate Receiver Tank and Pump

Combination
23

that are either carried over from the boiler or

that form in carbon steel piping and on copper

alloy heat exchange surfaces. Although strainers

and filters are used to catch the particulate 

matter, some contaminants are dissolved in the

condensate and can cause problems if returned

to the boiler. In systems that require a high level

of cleanliness, condensate polishers are used.

Condensate polishers use ion exchange to remove

these contaminants, preventing the redeposition

of these contaminants on boiler surfaces.

A Sourcebook for Industry

Steam System Basics

Saturated 

Vapor Supply

Steam Trap

High-Pressure

Condensate

Condensate

Discharge

Level

Controller

Low-Pressure

Flash Vessel

Saturated

Vapor

Saturated

Liquid

Figure 14. Flash Steam Recovery Vessel
24 Improving Steam System Performance

Steam System Basics
Section 2: Performance Improvement Opportunities

25

Overview

This section of the Sourcebook discusses important

factors that should be considered when industrial

facilities seek to improve steam system performance and to lower operating costs. Improving

steam system performance requires assessing the

entire system, identifying opportunities, and

selecting and implementing the most feasible

projects. In turn, this requires a systems approach.

Similarly, proper selection of the best projects

requires quantifying the benefits and costs of

each project. Successful implementation of these

projects requires the participation of all system

stakeholders including production, maintenance,

and management. Generally, obtaining management participation requires communication of

the analyses in economic terms. To address these

considerations, this section of the Sourcebook

discusses:

■ The systems approach

■ Common performance improvement 

opportunities

■ Resources that can help identify and 

assess opportunities

■ The economics related to steam system 

improvements.

Systems Approach

Because of the many industrial uses for steam,

there are wide ranges of steam system sizes, configurations, end-use applications, and operating

practices. As a result, there are many different

ways to improve steam system performance and

identify improvement opportunities. In general,

performance is most effectively optimized when a

systems approach is used.

A systems approach analyzes both the supply and

demand sides of the system and how they interact, essentially shifting the focus from individual

components to total system performance. Often,

operators are so focused on the immediate

demands of the equipment that they overlook the

broader issue of how system parameters affect the

equipment. Similarly, a common engineering

approach is to break a system down into its basic

components or modules, optimize the selection or

the design of these components, and then assemble these components to form the system. An

advantage to this approach is that it simplifies

problems. However, a disadvantage is that it often

overlooks the interaction of these components. In

contrast, a systems approach evaluates the entire

system to determine how the end-use requirements

can be most effectively and efficiently served. 

A systems approach also recognizes that system

efficiency, reliability, and performance are closely

related. For example, an efficiency loss such as

heat loss across uninsulated pipe surfaces reduces

energy available to the end uses and requires

boilers to work harder to meet a given demand.

Often, energy losses create additional system

stresses that accelerate wear and that can create

loads for which the system was not originally

designed.

Common Performance

Improvement Opportunities

Several steam system improvement opportunities

are common to many industrial facilities. These

opportunities can be categorized according to the

part of the system in which they are implemented. Common performance opportunities for the 

generation, distribution, and recovery areas of a

steam system are listed in Table 2. 

◆ End-Use Improvement Opportunities

There are many ways to optimize steam use

depending on the process and the equipment.

Specific End Uses for Industries of the Future

(IOF) steam systems can be found in Table 1 of

the End Use section. In some cases, equipment

can be installed to make the process more efficient; for example, multiple-stage dryers are

often more efficient than single-stage dryers.

However, in general, optimizing the efficiency of

steam-supplied end uses requires a case-by-case

assessment.

A Sourcebook for Industry

Performance Improvement Opportunities
26

BestPractices Steam System

Performance Tools

The U. S. Department of Energy (DOE) BestPractices Steam effort has developed a suite of

resources and tools that can be used to identify

and assess steam system improvement opportunities. These resources and tools are described in

this section of the Sourcebook. Additional steam

improvement resources and tools are identified

in the Resources section of the Sourcebook.

◆ Steam System Scoping Tool

The Steam System Scoping Tool is a spreadsheet

program that can assist steam operation and

management personnel to assess their steam 

systems. The program is intended for use by

steam system energy managers and operations

personnel in industrial plants. This tool also

helps assess steam system operations against

identified best practices. 

The Steam System Scoping Tool contains seven

worksheets: 

Improving Steam System Performance

Opportunity Description

Generation

Minimize excess air Reduces the amount of heat lost up the stack, allowing more of the fuel energy

to be transferred to the steam

Clean boiler heat transfer surfaces Promotes effective heat transfer from the combustion gases to the steam

Install heat recovery equipment Recovers available heat from exhaust gases and transfers it back into the

(feedwater economizers and/or system by preheating feedwater or combustion air

combustion air preheaters)

Improve water treatment to minimize Reduces the amount of total dissolved solids in the boiler water, which allows

boiler blowdown less blowdown and therefore less energy loss

Recover energy from boiler Transfers the available energy in a blowdown stream back into the system,

blowdown thereby reducing energy loss

Add/restore boiler refractory Reduces heat loss from the boiler and restores boiler efficiency

Optimize deaerator vent rate Minimizes avoidable loss of steam

Distribution

Repair steam leaks Minimizes avoidable loss of steam

Minimize vented steam Minimizes avoidable loss of steam

Ensure that steam system piping, Reduces energy loss from piping and equipment surfaces

valves, fittings, and vessels are well

insulated

Implement an effective steam-trap Reduces passage of live steam into condensate system and promotes efficient

maintenance program operation of end-use heat transfer equipment

Isolate steam from unused lines Minimizes avoidable loss of steam and reduces energy loss from piping and

equipment surfaces

Utilize backpressure turbines instead Provides a more efficient method of reducing steam pressure for low-pressure

of PRVs services

Recovery

Optimize condensate recovery Recovers the thermal energy in the condensate and reduces the amount of 

makeup water added to the system, saving energy and chemicals teatment

Use high-pressure condensate to Exploits the available energy in the returning condensate

make low-pressure steam

Table 2. Common Performance Improvement Opportunities for the Generation, Distribution,

and Recovery Parts of Industrial Steam Systems

Performance Improvement Opportunities
Performance Improvement Opportunities

A Sourcebook for Industry

1. Introduction—provides instructions on how

to use the guide and what is indicated by the

results.

2. Basic data—prompts the user to answer general

questions such as the amount of fuel used, 

amount of steam generated, and other general

system data.

3. System profiling—assesses how the user 

tracks steam costs, benchmarks steam use,

and measures important general operating

parameters.

4. Operating practices of the total system—

queries the user regarding practices such as

trap maintenance, water treatment, insulation 

condition, leak repair, and general equipment

inspection.

5. Operating practices of the boiler plant—

queries the user on boiler efficiency, heat

recovery equipment, steam quality, and 

general boiler operation.

6. Operating practices of the distribution, enduse, and recovery portions of the steam 

system—queries the user about the use of

pressure reducing valves, condensate recovery,

and the use of condensate to generate lowpressure steam.

7. Summary sheet—provides scores based on 

user responses.

◆ Steam System Survey Guide

The Steam System Survey Guide is a reference document that is intended for use by plant energy

managers and system operations personnel. 

The Survey Guide provides a technical basis for

identifying and assessing many potential steam

system improvement opportunities. Although

several of these opportunities can be identified

directly with the survey guide, others require

more sophisticated measurements and data 

gathering methods. 

The Scoping Tool and the Survey Guide are complementary. The Scoping Tool allows a user to

determine how well the system is performing and

is also useful in tracking the effectiveness of system

improvements. The Survey Guide provides a more

quantitative description of the system operation

and how to quantify some of the potential steam

system improvement opportunities. These tools

are available from DOE’s Industrial Technologies

Program (ITP) BestPractices Web site at

www.eere.energy.gov/industry/bestpractices. 

The Web site also offers links to other resources

that can assist end users in improving the performance and efficiency of their energy-intensive

utility systems.

◆ Steam System Assessment Tool

The Steam System Assessment Tool allows users

to assess potential savings from individualized

steam system improvements. Users may input

data about the condition of their plant and the

Steam System Assessment Tool generates models

of various improvement scenarios. Results detail

the energy, cost, and emissions savings that a

variety of improvements could achieve. 

The tool contains all the key features of typical

steam systems—boilers, backpressure turbines,

condensing turbines, deaerators, letdowns, flash

vessels, and feedwater heat exchangers. The

model analyzes boiler efficiency, boiler blowdown, cogeneration, steam cost, condensate

recovery, heat recovery, vent steam, insulation

efficiency, alternative fuels, backpressure turbines, steam traps, steam quality, and steam

leaks. 

◆ 3E Plus Insulation Appraisal Software

Because insulation is used in every steam system,

its restoration, replacement, or installation are

common improvement opportunities. A lack of

awareness regarding the energy losses and the

associated costs often results in a low prioritization of restoring or properly installing insulation

on steam system surfaces. As a result, a software

program known as 3E Plus was developed by 

the North American Insulation Manufacturers

Association (NAIMA). The program increases

awareness among steam system operations and

management personnel of the benefits of insulation and assists these stakeholders in assessing

insulation opportunities.

3E Plus assists the user in assessing important 

insulation project factors such as energy savings,

installation cost, and payback period for various

insulation materials and thicknesses. Users of 

3E Plus can estimate energy losses from uninsulated surfaces as well as potential savings from

various insulation options. 

The program has general data for insulation

costs by type and can analyze insulation crosssections that use several different insulation types.

It also accounts for labor rates and productivity

27
28

by region, estimating how difficult the installation process will be based on general piping

characteristics. Users can quickly determine the

economic feasibility of various insulation thicknesses. Since the program also allows the user 

to evaluate various combinations of insulation

types, 3E Plus can help the user optimize the

material thicknesses within an insulation system.

Download 3E Plus from the BestPractices Web site

at www.eere.energy.gov/industry/bestpractices.

◆ NIA’s Insulation Energy Appraisal Program 

(IEAP)

The National Insulation Association (NIA), an

ITP Allied Partner, has developed a training 

program that offers certification to professionals

who conduct insulation appraisals or specify

insulation requirements. This program is intended

to provide credibility to insulation professionals

and to increase consistency of the message that

is presented to clients. This program has four key

components:

■ Awareness Building—an important way to

increase awareness of the potential cost savings

from insulation projects is to effectively promote

insulation appraisal as a professional service. 

■ Information Gathering—determining the parts

of the system that have the most attractive

insulation improvement opportunities usually

requires input from the plant personnel.

Improving the interview techniques of insulation professionals can increase the usefulness

of these assessments. 

■ 3E Plus—the 3E Plus program is an important 

tool for insulation professionals and specifying

engineers. Learning to effectively use this tool

can improve the quality of the assessment findings, presentation of recommendations, and

cost-effective specification of new insulation. 

■ Reporting—accurately and effectively reporting the results of an insulation assessment can

significantly increase the probability that the 

recommendations will be implemented. 

Information regarding the Insulation Energy

Appraisal Program (IEAP) can be obtained from

the NIA Web site at www.insulation.org.

◆ Steam Tip Sheets

Some improvement opportunities are available 

to many different systems. To increase industry

awareness of several fundamental improvement

opportunities, ITP has developed steam tip sheets

through its BestPractices activities. 

These steam tip sheets provide concise descriptions

of common improvement opportunities. Because

BestPractices continues to develop and identify

energy improvement programs, additional tip

sheets are expected. Steam tip sheets available by

this Sourcebook’s publication date can be found

in Appendix B. Additionally, steam tip sheets can

be found on the BestPractices Web site at

www.eere.energy.gov/industry/bestpractices/.

Steam System Training

◆ Steam End User Training 

This 1-day course covers the operation of typical

steam systems and discusses methods of system

efficiency improvement. The training is designed

for plant personnel, such as energy managers,

steam system supervisors, engineers, and equipment operators, who have steam system responsibilities in industrial and institutional plants.

The course covers three key areas of potential

system improvement:

■ Steam Generation Efficiency 

■ Resource Utililization Effectiveness 

■ Steam Distribution System Losses 

The course introduces the Steam System Scoping

Tool and the Steam System Assessment Tool,

both developed by DOE's BestPractices and uses

the Steam System Survey Guide as a technical 

reference. The training also introduces the 3E

Plus insulation appraisal software and a course 

example is presented that uses this software.

◆ Steam Tool Specialist Qualification Training

Industry professionals can earn recognition as

Qualified Specialists in the use of the BestPractices

Steam Tools. DOE offers an in-depth, two-anda-half-day training for steam system specialists,

including two days of classroom instruction and

a written exam. Participants who complete the

training and pass the written exam are recognized by DOE as Qualified Steam Tool Specialists,

and are listed on the BestPractices Web site. 

Specialists can assist industrial customers in

using the BestPractices Steam Tools to evaluate

their steam systems.

The BestPractices Steam System Specialist Qualification training is primarily designed for steam

Improving Steam System Performance

Performance Improvement Opportunities
29

specialists who are interested in becoming proficient in using the BestPractices Steam Tools. To

successfully complete the Specialist Qualification

Training course, a participant must understand the

full suite of BestPractices Steam tools including: 

■ Steam System Survey Guide

■ Steam System Scoping Tool 

– Accurate collection and input of data 

for use with the tool 

– Appropriate utilization of the software 

– Interpretation of the software results 

■ Steam System Assessment Tool 

– Accurate collection and input of data for 

use with the tool 

– Development of representative system models 

– SSAT limitations 

– Individual project identification 

– Development of practical methods to 

accomplish the appropriate projects 

■ 3E Plus 

– Accurate data gathering for basic 

insulation related evaluations 

– Development of evaluation techniques 

related to common insulation evaluations. 

Class participants will receive a Prerequisite

Test/Study Guide before attending the class. This

Study Guide provides an indicator of the skill

levels necessary to successfully complete the 

Specialist Qualification training. Completion of

this Study Guide is highly recommended, but is

not a requirement to take the training. Completion of BestPractices Steam End User training is

also recommended prior to participating in the

Specialist Qualification training class, which 

covers the majority of the Specialist Qualification

training prerequisites.

To learn more about the Steam System Specialist

Qualification training, visit the BestPractices Web

site at www.eere.energy.gov/industry/bestpractices.

Overview of Financing

Steam System Improvements

Very often, industrial facility managers must 

convince upper management that an investment 

in steam efficiency is worth the effort. The communication of this message can often be more

difficult than the actual engineering behind the

concept. The corporate audience will respond

more readily to an economic impact than to a

discussion of Btu, pounds of steam, and efficiency

ratios. By adopting a financial approach, the

facility manager relates steam efficiency to corporate goals. Collaboration with financial staff can

yield the kind of proposal that is needed to 

convince corporate officers who have the final

word about capital investments such as steam

system upgrades.

Before laying out some recommendations for

how to justify steam improvement projects, it is

useful to understand the world as the corporate

office usually sees it.

◆ Understanding Corporate Priorities

Corporate officers are held accountable to a chief

executive, a board of directors, and an owner 

(or shareholders, if the firm is publicly held). 

It is the job of these officers to create and grow 

the equity value of the firm. The corporation’s

industrial facilities do so by generating revenue

that exceeds the cost of owning and operating

the facility itself. Plant equipment—including

steam system components—is an asset that must

generate an economic return. The annual earnings attributable to the sale of goods produced by

these assets, divided by the value of the plant

assets themselves, describe the rate of return on

assets. This is a key measure by which corporate

decision-makers are held accountable. 

Financial officers seek investments that are most

certain to demonstrate a favorable return on

assets. When faced with multiple investment

opportunities, the officers will favor those options

that lead to both the largest and fastest returns.

This corporate attitude may impose (sometimes

unpleasant) priorities on the facility manager:

assure reliability in production, avoid unwanted

surprises by sticking with familiar technology

and practices, and contribute to cost control

today by cutting a few corners in maintenance

and upkeep. This may result in industrial decisionmakers concluding that steam efficiency is 

a “luxury” that cannot be afforded.

Fortunately, the story does not end here. What 

follows is a discussion of ways that industrial

steam efficiency can save money and contribute

to corporate goals while effectively reducing

A Sourcebook for Industry

Performance Improvement Opportunities
30

energy consumption and cutting noxious 

combustion emissions.

◆ Measuring the Dollar Impact of Steam Efficiency

Steam efficiency improvements can move to the

top of the list of corporate priorities if the proposals

respond to distinct corporate needs. Corporate

challenges are many and varied, which in turn

open up more opportunities to “sell” steam 

efficiency as a solution. Steam systems offer

many opportunities for improvement; the particulars are shared elsewhere in this Sourcebook.

Once the selections are made, the task is one 

of communicating the proposals in corporate

financial language.

The first step is to identify and enumerate the

total dollar impact of a steam efficiency measure.

One framework for this is known as “life-cycle cost

analysis.” These analyses capture the sum total of

expenses and benefits associated with an investment. The result—a net gain or loss on balance—

can be compared to other investment options or to

the anticipated outcome if no investment is made.

As a comprehensive accounting of an investment

option, the life-cycle cost analysis for a steam efficiency measure would include projections of: 

■ Search and selection costs for seeking an 

engineering implementation firm

■ Initial capital costs, including asset purchase, 

installation, and costs of borrowing

■ Maintenance costs

■ Supply and consumable costs

■ Energy costs over the economic life of the 

implementation

■ Depreciation and tax impacts

■ Scrap value or cost of disposal at the end of

the equipment’s economic life

■ Impacts on production such as product 

quality and downtime.

One revelation that typically emerges from this

exercise is that fuel costs may represent as much

as 96% of life-cycle costs, while the initial capital

outlay is only 3%, and maintenance a mere 1%.

These findings may be true for boilers with a 

20-year life operating at high rates of capacity

utilization. Clearly, any measure that reduces fuel

consumption (while not impacting reliability

and productivity) will certainly yield positive

financial impacts for the company.

◆ Financing Steam Efficiency Improvements

As with any corporate investment, there are

many ways to measure the financial impact of

steam efficiency investments. Some methods are

more complex than others are, and proposals

may use several analytical methods side-by-side.

The choice of analyses used will depend on the

sophistication of the presenter and the audience.

A simple and widely used measure of project 

economics is the payback period. This is defined

as the period of time required for a project to

“break even.” It is the time needed for the net

benefits of an investment to accrue to the point

where they equal the cost of the initial outlay.

For a project that returns benefits in consistent,

annual increments, the simple payback equals

the initial investment divided by the annual benefit. Simple payback does not take into account

the time value of money; in other words, it

makes no distinction between a dollar earned

today versus a dollar of future (and therefore

uncertain) earnings. Still, the measure is easy to

use and understand and many companies use

simple payback for a quick “go/no-go” decision

on a project. Five important factors to remember

when calculating a simple payback:

■ It is an approximation, not an exact 

economic analysis

■ All benefits are measured without 

considering their timing

■ All economic consequences beyond the 

payback are ignored

■ Payback calculations will not always find the

best solution (for the two reasons immediately

above) when choosing among several project

options 

■ Payback does not consider the time value of 

money or tax consequences.

More sophisticated analyses take into account 

factors such as discount rates, tax impacts, the

cost of capital, etc. One approach involves calculating the net present value of a project, which is

defined in the equation below:

Net present value = Present worth of benefits –

Present worth of costs

Another commonly used calculation for determining economic feasibility of a project is internal

rate of return, which is defined as the discount

rate that equates future net benefits (cash) to an

Improving Steam System Performance

Performance Improvement Opportunities
31

initial investment outlay. This discount rate can

be compared to the interest rate at which a 

corporation borrows capital.

Many companies set a threshold (or hurdle) rate

for projects, which is the minimum required

internal rate of return for a project to be considered viable. Future benefits are discounted at the

threshold rate, and the net present worth of the

project must be positive in order for the project

to be a “go.”

◆ Relating Steam Efficiency to Corporate Priorities

Saving money should be a strong incentive for

adopting steam efficiency. Still, that may not be

enough for some corporate observers. The facility

manager’s case can be strengthened by relating 

a positive life-cycle cost outcome to specific 

corporate needs. Some suggestions for interpreting the benefits of fuel cost savings include the 

following (finance staff can suggest which of

these approaches are best for the current corporate climate):

■ A new source of permanent capital. Reduced

fuel expenditures—the direct benefit of steam

efficiency—can be thought of as a new source

of capital for the corporation. The investment

that makes this efficiency possible will yield

annual savings each year over the economic

life of the improved steam system. Regardless

of how the steam efficiency investment is

financed—borrowing, retained earnings, or

third party financing—the annual savings will

be a permanent source of funds as long as the

steam efficiency savings are maintained on a

continuous basis.

■ Added shareholder value. Publicly held corporations usually embrace opportunities to

enhance shareholder value. Steam efficiency 

can be an effective way to capture new value.

Shareholder value is the product of two 

variables: annual earnings and the price-toearnings (P/E) ratio. The P/E ratio describes 

the corporation’s stock value as the current 

stock price divided by the most recent annual 

earnings per share. To take advantage of this 

measure, the steam efficiency proposal should

first identify annual savings (or rather, addition

to earnings) that the proposal will generate.

Multiplying that earnings increment by the

P/E ratio yields the total new shareholder

value attributable to the steam efficiency

implementation.

■ Reduced cost of environmental compliance.

Facility managers can proactively seek to limit

the corporation’s exposure to penalties related

to environmental emissions compliance. Steam

efficiency, as total-system discipline, leads to

better monitoring and control of fuel use.

Combustion emissions are directly related to

fuel consumption; they rise and fall in 

tandem. By implementing steam efficiency,

the corporation enjoys two benefits: decreased

fuel expenditures per unit of production, and

fewer incidences of emission-related penalties.

■ Improved worker comfort and safety. Steam

system optimization requires ongoing monitoring and maintenance that yields safety

and comfort benefits in addition to fuel 

savings. The routine involved in system

monitoring will usually identify operational

abnormalities before they present a danger to

plant personnel. Containing these dangers

precludes threats to life, health, and property.

■ Improved reliability and capacity utilization.

Another benefit to be derived from steam 

efficiency is more productive use of steam

assets. The efforts required to achieve and

maintain energy efficiency will largely contribute to operating efficiency. By ensuring

the integrity of steam system assets, the facility manager can promise more reliable plant

operations. The flip side, from the corporate

perspective, is a greater rate of return on

assets employed in the plant.

◆ Call to Action

A proposal for steam efficiency implementation

can be made attractive to corporate decisionmakers if the facility manager:

■ Identifies opportunities for achieving steam 

efficiency

■ Determines the life-cycle cost of attaining

each option

■ Identifies the option(s) with the greatest net 

benefits

■ Collaborates with financial staff to identify 

current corporate priorities (for example,

added shareholder value, reduction of environmental compliance costs, and improved

capacity utilization)

■ Generates a proposal that demonstrates how

the steam efficiency project’s benefits will

directly respond to current corporate needs. 

A Sourcebook for Industry

Performance Improvement Opportunities
32

◆ Summary

Increased awareness of the potential improvements in steam system efficiency and performance is an important step toward increasing the

competitive capabilities of energy-intensive

industries. Some of the useful steam resources

and tools developed by BestPractices have been

described in this section. Additional steam

resources and tools and where to obtain them

are described in the Resources and Tools section

of this Sourcebook.

Improving Steam System Performance

Performance Improvement Opportunities
33

This portion of the Sourcebook lists resources

that can help end users increase the cost-effective 

performance of steam systems. The section is

organized into three sections, described below:

◆ Programs

This section describes the U.S. Department of

Energy’s Industrial Technologies Program (ITP)

BestPractices activity, a national effort aimed at

improving the performance of industrial steam

systems. This section provides a list of associations

and other organizations involved in the steam

system marketplace.

◆ Contacts

This section provides a list of associations and

other organizations involved in the steam system

marketplace.

◆ Resources

This section provides information on books and

reports, other publications, government and commercial statistics and market forecasts, software,

training courses, and other sources of information

that can help end users make informed steam system

equipment purchase and system design decisions.

The Industrial Technologies 

Program and BestPractices

◆ Overview

Industrial manufacturing consumes 36% of all

energy used in the United States. ITP has programs

to assist industry in achieving significant energy

and process efficiencies. ITP develops and delivers

advanced energy efficiency, renewable energy, and

pollution prevention technologies and practices for

industrial applications. Through an industry-driven

initiative called Industries of the Future (IOF), ITP

works with the nation’s most energy- and resourceintensive industries to develop a vision of their

future and roadmaps on how to achieve these

visions over a 20-year timeframe. This collaborative

process aligns industry goals with federal resources

to accelerate research and development of advanced technologies identified as priorities by industry.

The advancement of energy- and process-efficient

technologies is complemented by ITP’s energy

management best practices for immediate savings

results. ITP’s BestPractices assists the eight Industries of the Future—aluminum, chemicals, forest

products, glass, metal casting, mining, petroleum,

and steel—to identify and realize their best energy

efficiency and pollution prevention options from

a system and life-cycle cost perspective. Through

activities such as plant-wide energy assessments,

implementation of emerging technologies, and

energy management of industrial systems, BestPractices delivers energy solutions for industry

that result in significant energy and cost savings,

waste reduction, pollution prevention, and

enhanced environmental performance.

◆ Plant Assessments

Depending on the industry, energy can account 

for 10% or more of total operating costs. Energy

assessments identify opportunities for implementing new technologies and system improvements.

Many recommendations from energy assessments have simple payback periods of less than 

18 months and can result in significant energy

savings.

■ Plant-wide assessments help manufacturers 

develop comprehensive plant strategies to 

increase efficiency, reduce emissions, and

boost productivity. Annual competitive 

solicitations offer a 50% cost share of up to

$100,000 in matching funds.

■ Small- to medium-sized manufacturers can 

qualify for free assessments from the universitybased Industrial Assessment Centers.

◆ Emerging Technologies

Emerging technologies are those that result from

research and development and are ready for 

full-scale demonstration in real-use applications.

ITP recognizes that companies may be reluctant 

to invest capital in these new technologies, even

though they can provide significant energy and

process improvements. However, through technology implementation solicitations, ITP helps

mitigate the risk associated with using new technologies that are supported by IOF partnerships.

A Sourcebook for Industry

Where to Find Help

Section 3: Where to Find Help
34

By sharing implementation and providing thirdparty validation and verification of performance

data, the energy, economic, and environmental

benefits can be assessed to accelerate new technology to acceptance.

◆ Energy Management

ITP encourages manufacturers to adopt a comprehensive approach to energy use that includes

assessing industrial systems and evaluating

potential improvement opportunities. Efficiency

gains in compressed air, motor, process heating,

pumping, and steam systems can be significant

and usually result in immediate energy and cost

savings. ITP offers software tools and training in

a variety of system areas to help industry become

more energy and process efficient, reduce waste,

and improve environmental performance.

◆ Allied Partnerships

Allied Partners are manufacturers, associations,

industrial service and equipment providers, 

utilities, and other organizations that voluntarily

work with ITP. Allied Partners seek to increase

energy efficiency and productivity for those

industries that participate in endorsing and 

promoting ITP programs, products, and services.

Allied Partnerships help ITP achieve industrial

energy efficiency goals by extending delivery

channels through the partners’ existing networks.

In turn, partners realize benefits, such as achieving their own corporate, institutional, or plant

goals and objectives by expanding services to

customers and suppliers. Allied Partners also gain

access to technical resources, such as software,

technical publications, and training; and they can

gain recognition as leaders in the implementation

of energy-efficient technologies and practices.

For more on Allied Partnerships, contact the

EERE Information Center at 877-337-3463.

◆ Technical Resources

ITP offers a variety of resources to help industry

achieve increased energy and process efficiency,

improved productivity, and greater competitiveness.

EERE Information Center. The EERE Information

Center fields questions on EERE products and

services including those focused on industrial

energy efficiency. They can answer questions

about industrial systems such as compressed air,

motors, process heating, and steam. The EERE

Information Center can be the first stop in finding out what’s available from EERE and ITP. Contact the EERE Information Center at 877-337-3463

or www.eere.energy.gov/informationcenter.

ITP and BestPractices Web Sites. The ITP and 

BestPractices Web sites offer a large array of 

information, products, and resources to assist 

manufacturers who are interested in increasing

the efficiency of their industrial operations. 

You can gain access to Web pages for the eight

Industries of the Future, learn about upcoming

events and solicitations and much more

through the ITP site. Visit the ITP site at

www.eere.energy.gov/industry. 

The BestPractices site offers case studies of 

companies that have successfully implemented

energy efficient technologies and practices, 

software tools, tip sheets, training events, 

and solicitations for plant assessments. 

You can see these and other resources at

www.eere.energy.gov/industry/bestpractices.

Industrial Energy Savers Web site. Manufacturers 

will find a number of resources on this site to

implement industrial energy efficiency projects

and see immediate savings. Access this site at

www.eere.energy.gov/consumerinfo/industry.

◆ Training 

Training sessions in industrial systems improvements using ITP software tools are offered 

periodically through Allied Partners. Visit the

BestPractices Web site for more information at

www.eere.energy.gov/industry/bestpractices.

◆ Software Tools 

ITP and its partners have developed several software tools for systems improvements to help you

make decisions about implementing efficient

practices in your manufacturing facilities. 

• AirMaster+ provides comprehensive information on assessing compressed air systems,

including modeling, existing and future 

system upgrades, and evaluating savings and

effectiveness of energy efficiency measures. 

• An energy-efficient motor selection and 

management tool, MotorMaster+ 4.0 software, includes a catalog of over 20,000 AC

motors. Version 4.0 features motor inventory

management tools, maintenance log tracking,

efficiency analysis, savings evaluation, energy

accounting, and environmental reporting

capabilities.

Improving Steam System Performance

Where to Find Help
35

• The NOx and Energy Assessment Tool

(NxEAT) helps plants in the petroleum refining

and chemical industries assess and analyze NOx

emissions and how the application of energy

efficiency improvements can reduce NOx. 

Perform "what-if" analyses to optimize and

select the most cost-effective methods for reducing NOx from systems such as fired heaters,

boilers, gas turbines, and reciprocating engines.

• The Process Heating Assessment and

Survey Tool (PHAST) provides an introduction to process heating methods and tools to

improve thermal efficiency of heating equipment. Use the tool to survey process heating

equipment that uses fuel, steam, or electricity,

and identify the most energy-intensive equipment. You can also perform an energy (heat)

balance on selected equipment (furnaces) to

identify and reduce non-productive energy

use. Compare performance of the furnace

under various operating conditions and test

"what-if" scenarios.

• The Pumping System Assessment Tool

(PSAT) helps industrial users assess the efficiency

of pumping system operations. PSAT uses achievable pump performance data from Hydraulic

Institute standards and motor performance data

from the MotorMaster+ database to calculate

potential energy and associated cost savings.

◆ Newsletters 

• The Industrial Technologies Program 

E-Bulletin is a monthly e-mail update that

spotlights technologies, significant project

developments, and program activities; new ITP

and BestPractices products; training and events;

Web updates; and solicitations. The E-Bulletin

provides readers with links to source information on the ITP, BestPractices, and IAC Web

sites. To subscribe, go to: www.eere.energy.gov/

industry/resources/itp_ebulletin.html.

• Energy Matters is a bimonthly newsletter

written by ITP that provides news, technical

tips, and case studies. Energy Matters informs

industrial end users of energy efficiency

opportunities, technical issues, new products

and services, and events related to process

heating systems and other industrial utilities

such as motor, steam, and compressed air 

systems. To subscribe, contact the EERE

Information Center (877-337-3463) or 

subscribe online at:

www.eere.energy.gov/industry/bestpractices.

A Sourcebook for Industry

Where to Find Help

Software: DOE’s Steam System Tool Suite helps you tap into

potential savings in your facility, by evaluating and identifying

steam system improvements. 

Steam System Scoping Tool—This tool is designed to help

steam system energy managers and operations personnel perform initial self-assessments of their steam systems. This tool

will profile and grade steam system operations and management, and will help you to evaluate your steam system operations

against best practices.

Steam System Assessment Tool (SSAT 2.0.0)—This tool allows

users to assess potential savings from individualized steam

system improvements. Users input data about their plant's 

conditions, and the SSAT generates results detailing the energy,

cost, and emissions savings that could be achieved through 

16 different improvements.

3E Plus Version 3.2—This program calculates the most economical thickness of industrial insulation for user input operating 

conditions. You can make calculations using the built-in thermal

performance relationships of generic insulation materials or

supply conductivity data for other materials.

Training: Steam Tool Specialist Qualification Training—Industry

professionals can earn recognition as Qualified Specialists in the

use of the BestPractices Steam Tools. DOE offers an in-depth 

2-1/2 day training for steam system specialists, including 2 days

of classroom instruction and a written exam. Participants who

complete the training and pass the written exam are recognized

by DOE as Qualified Steam Tool Specialists. Specialists can

assist industrial customers in using the BestPractices Steam Tools

to evaluate their steam systems. 

Newsletter: Steaming Ahead is a bimonthly e-mail newsletter

published by the Alliance to Save Energy that describes the

activities and information products of the BestPractices Steam

effort. BestPractices Steam outreach and promotion is 

performed by the Alliance to Save Energy. Steaming Ahead

promotes best-in-class practices and technology applications in

steam system design and management. Additional information

on Steaming Ahead can be found at: www.steamingahead.org.

Case Studies: Steam Case Studies provide practical examples

of successful steam system improvement projects. Typically,

these case studies describe how a facility assessed its steam

system, then identified opportunities to improve its operation

and/or performance and implemented one or more of these

opportunities. Discussion of successful improvement projects

can reduce the uncertainty associated with making steam system improvements. Case studies also increase awareness 

of the systems approach that is often an essential part of any

successful performance or efficiency improvement. Documented

steam case studies are available from the BestPractices Web

site at www.eere.energy.gov/industry/bestpractices.

DOE Steam-Specific Resources
36

Directory of Contacts

Information on improving the performance of

industrial energy systems is available from several

resources. To improve the profitability of U.S.

industry, ITP’s BestPractices offers many resources

for steam system management. These resources

complement Industries of the Future technology

development programs, which address other

industrial systems, such as motor, compressed air,

combined heat and power, and process heating,

in addition to efforts by the Industrial Assessment

Centers. Collectively, these efforts assist industry

in adopting near-term and long-term energyefficient practices and technologies. For assistance

in these areas, contact:

U.S. Department of Energy 

Industrial Technologies Program

BestPractices Steam

Room 5-F-065, MS EE-2F

1000 Independence Avenue, SW

Washington, DC 20525

Phone: 877-337-3463

www.eere.energy.gov/industry

For specific information regarding steam systems,

including assistance in locating steam system 

specialists and equipment vendors, BestPractices

Steam provides an excellent set of helpful resources.

Together with industrial end users, equipment

suppliers, and resource organizations, BestPractices

Steam helps industry stay competitive and promotes the comprehensive upgrade of industrial

steam systems. 

Alliance to Save Energy

1200 18th Street, NW, Suite 900

Washington, DC 20036

Phone: 202-857-0666

Fax: 202-331-9588

www.ase.org

The Alliance to Save Energy is a nonprofit coalition of prominent business, government, environmental, and consumer leaders who promote

the efficient and clean use of energy worldwide

to benefit the environment, the economy, and

national security.

American Boiler Manufacturers Association

(ABMA)

4001 North 9th Street, Suite 226

Arlington, VA 22203-1900

Phone: 703-522-7350

Fax: 703-522-2665

www.abma.com

ABMA is a trade association of manufacturers of

boilers, related fuel-burning equipment, users of

boiler and boiler-related equipment, and companies that provide products and services to the

boiler industry. 

The ABMA Bookstore is a one-stop source for

boiler industry information. Find industry 

standards, technical references, and more from

ABMA, Underwriters Laboratories, and many

other publishers.

Association of Energy Engineers (AEE)

4025 Pleasantdale Road, Suite 420

Atlanta, GA 30340

Phone: 770-447-5083

Fax: 770-446-3969

www.aeecenter.org

AEE is a membership organization of over 

8,000 professionals in the energy efficiency, 

utility deregulation, facility management, plant

engineering, and environmental compliance

fields. AEE offers a variety of outreach programs

including technical seminars, conferences, 

publications, and certification programs. 

Association for Facilities Engineering (AFE)

8160 Corporate Park Drive, Suite 125

Cincinnati, OH 45242

Phone: 513-489-2473

Fax: 513-247-7422

www.afe.org

AFE provides education, certification, technical

information, and other relevant resources for

plant and facility engineering, operations, and

maintenance professionals worldwide.

Boiler Room/Go-Steam Web sites

An online community for commercial and 

industrial boiler operators and engineers.This 

site contains boiler company profiles, a career

center for steam industry professionals, a classified section for boiler/steam equipment, and 

a discussion board. See www.boilerroom.com 

and www.gosteam.com.

Improving Steam System Performance

Where to Find Help
Council of Industrial Boiler Owners (CIBO)

6035 Burke Centre Parkway, Suite 360

Burke, VA 22015

Phone: 703-250-9042

Fax: 703-239-9042

www.cibo.org

CIBO provides information and advocacy to

achieve solutions to industrial energy, environmental, and legislative issues and policies. 

Objectives of CIBO include: 

1. Information exchange among members, 

government, and the public concerning 

policies, laws, and regulations that affect

industrial energy systems. 

2. Technically sound, equitable, cost-effective

laws and regulations. 

3. Improved reliability and cost-effectiveness 

of industrial energy systems. 

National Association of Power Engineers (NAPE)

1 Springfield Street

Chicopee, MA 01013

Phone: 413-592-6273

www.powerengineers.com

NAPE is a professional association for power

engineers. NAPE was established in 1879 and

provides education and resources on power 

and energy engineering.

National Insulation Association (NIA)

99 Canal Center Plaza, Suite 222

Alexandria, VA 22314

Phone: 703-683-6422

Fax: 703-549-4838

www.insulation.org

NIA is a service organization that promotes the

general welfare of the commercial and industrial

insulation and asbestos abatement industries and

works to improve the service to the general public performed by the commercial and industrial

insulation and asbestos abatement industries.

North American Insulation Manufacturers 

Association (NAIMA)

44 Canal Center Plaza, Suite 310

Alexandria, VA 22314

Phone: 703-684-0084

Fax: 703-684-0427

www.naima.org

NAIMA is a trade association of North American

manufacturers of fiberglass, rock wool, and slag

wool insulation products. NAIMA concentrates

its efforts on promoting energy efficiency and

environmental preservation through the use of

fiberglass, rock wool, and slag wool insulation

products, while encouraging safe production and

use of these products.

STEAM-LIST

The STEAM-LIST is a discussion forum that promotes the exchange of information, problem

solving, and discussion of steam generators, piping,

and equipment. Included among the components

and issues that are discussed are boilers, boiler

feed pumps, water treatment, corrosion and 

scaling, valves, PRVs, traps, turbines, flow metering, heating coils, condensate pumps, district

heating, and system modeling. This list is intended to promote practical discussions, rather than 

theoretical or academic discussions. 

Subscription information can be obtained by 

contacting: listproc@lists.cc.utexas.edu.

Resources and Tools

Note: The descriptions accompanying the following sources have generally been taken directly

from the publisher/author/developer. Inclusion

of these sources does not imply endorsement by

the U.S. Department of Energy.

Several other resources are available that describe

current tools, technologies, and practices that can

help improve steam system operating efficiency

and performance. Many of these resources are

intended to increase awareness of the benefits of

energy improvement projects and to identify where

the industry professional can go for more help.

Armstrong International, Inc.

816 Maple Street

Three Rivers, MI 49093 

269-273-1415

www.armintl.com

Handbook N101—Steam Conservation Guidelines for

Condensate Drainage

Description: This Handbook summarizes general

principles of installation and operation of steam

A Sourcebook for Industry 37

Where to Find Help

Books
traps. It also includes Recommendation Charts

which summarize findings on which type of trap

will give optimum performance in a given 

situation and why.

ASHRAE

1791 Tullie Circle, NE

Atlanta, GA 30329

800-527-4723

www.ashrae.org 

ASHRAE Handbook of HVAC Systems 

and Equipment, 2000

Description: Complete guide to steam systems

design and equipment.

Association for Facilities Engineering (AFE)

8160 Corporate Park Drive, Suite 125

Cincinnati, OH 45242

513-489-2473

www.afe.org

Boiler Plant and Distribution Optimization Manual

Description: Guide for boiler and plant operators

to optimize the efficiency of their boilers and 

distribution systems.

Babcock and Wilcox

20 South Van Buren Avenue

Barberton, OH 44203-0351

330-753-4511

www.babcock.com

Steam: Its Generation and Use, 40th Edition

Description: This book is intended to help design,

procure, construct, maintain, and/or operate 

equipment in a way that will provide reliable 

performance.

GE Betz

4636 Somerton Road

Trevose, PA 19053-6783

215-355-3300

www.gewater.com

Handbook of Industrial Water Conditioning, Ninth Edition

Prepared by: Betz Laboratories Inc.

Description: This handbook presents detailed

information on external treatment: boiler 

and cooling water systems, air conditioning,

refrigeration and total energy systems, chemical

treatment feeding and control, and problems

encountered in special industrial cases.

Boiler Efficiency Institute

P.O. Box 2255 

Auburn, AL 36831-2255 

800-669-6948

www.boilerinstitute.com

Steam Efficiency Improvement

Description: An introductory text for establishing

a program for reducing losses in the use of steam.

The text is divided into three areas: steam 

transmission, steam consuming processes, and

condensate return systems.

CANMET Energy Technology Centre 

1 Haanel Drive

Ottawa, Ontario

Canada K1A 1M1

613-996-8693

www.nrcan.gc.ca/es/etb/cetc/cetchome.htm

An Energy Efficiency and Environment Primer 

for Boilers and Heaters

Prepared by: Federal Industrial Boiler Program,

CANMET Energy Technology Centre 

Description: This guide is intended to provide a

basic discussion of combustion processes, their

emissions, and techniques for reducing energy

consumption and environmental emissions. 

ISBN: 0777895366

Council of Industrial Boiler Operators (CIBO)

6035 Burke Centre Parkway, Suite 360

Burke, VA 22015

703-250-9042 

www.cibo.org

Energy Efficiency Handbook

Description: The Energy Efficiency Handbook was

prepared to help owners and operators get the best

and most energy-efficient performance out of their

boiler systems. Some of the handbook chapters

include Water Treatment, Boilers, Controls, Heat

Recovery, Energy Auditing, and Steam Systems.

Energy Institute Press

3969 Lantern Drive

Wheaton, MD 20902

301-946-1196

www.energybooks.com

38 Improving Steam System Performance

Where to Find Help
A Sourcebook for Industry 39

Energy Efficiency Manual

Author: Donald R. Wulfinghoff

Description: A comprehensive treatment of energy

efficiency applications in industrial, commercial,

and residential settings. Industrial boiler operators

will be interested in Section 1, “Boiler Plant,” which

devotes 225 pages solely to steam systems. Dozens

of tips are provided, each with an assessment of

their potential for savings, rate of return, reliability, and ease of initiation. ISBN: 0965792676

The Fairmont Press

700 Indian Trail

Lilburn, GA 30047 

770-925-9388 

www.fairmontpress.com

Efficient Boiler Operations Source Book, Fourth Edition

Authors: F. William Payne and Richard E. 

Thompson 

Description: Reviews the fundamentals of boiler

combustion and the factors that affect boiler 

efficiency. This book is intended for operators and

supervisors of boiler plants. ISBN: 01353226885

Energy Management Handbook

Author: Wayne C. Turner

Description: This book discusses steam and condensate systems, waste heat recovery, co-generation,

and industrial insulation. ISBN: 013728098X

Handbook of Energy Audits, Fourth Edition

Author: Albert Thumann

Description: Contains information on boilers,

steam traps, insulation, and a chapter on computer

software for energy audits. ISBN: 0139752021

Plant Engineer’s and Manager’s Guide to Energy 

Conservation, Seventh Edition

Author: Albert Thumann

Description: Provides information on steam 

tracing, steam generation using waste heat 

recovery, steam trap maintenance, cogeneration,

the transition from energy audits to industrial

assessment, a review of industrial operations and

maintenance energy measures, and an 

integrated approach to achieving energy cost 

savings at a corporate headquarters. 

ISBN: 0130207381

Stationary Engineering Handbook

Author: K. L. Petrocelly, SMA/CPE

Description: A book that discusses steam generation and water treatment from the operating

engineer’s perspective.

The Steam Trap Handbook

Author: James F. McCauley

Description: This book is intended for engineers

and technicians to help them optimize the 

performance of their steam systems by focusing

on steam traps. This book discusses proper 

selection and sizing, application, operation, 

and maintenance of steam traps.

International District Energy Association

125 Turnpike Road, Suite 4

Westborough, MA 01581-2841

508-366-9339

www.districtenergy.org

District Heating Handbook, Fourth Edition

Description: A guide for engineers to understand

district heating and how best to use it.

John Wiley & Sons

111 River Street

Hoboken, NJ 07030-5774

201-748-6000

www.wiley.com

Handbook of Energy Systems Engineering 

Production and Utilization

Author: Leslie Wilbur (Editor) 

Description: This book covers all aspects of energy

system engineering from a user’s perspective. 

It presents a holistic approach to understanding 

these systems from fuels to end-use technologies

for mechanical and electric production and 

utilization in industry today. The extensive list 

of references provided are invaluable to anyone

interested in energy production and utilization.

Publication, 1985. 

Krieger Publishing Company 

P.O. Box 9542

Melbourne, FL 32902-9542

321-724-9542 

www.krieger_publishing.com

Handbook of Thermal Insulation Design 

Economics for Pipes and Equipment

Authors: William C. Turner and John F. Malloy

Description: This handbook discusses topics such 

as heat transfer, insulation materials properties,

selection/application/installation, and energy 

savings.

Where to Find Help
40 Improving Steam System Performance

Marcel Dekker, Inc. 

270 Madison Avenue

New York, NY 10016-0602

212-696-9000

www.dekker.com

Steam Plant Calculations Manual

Author: V. Ganapathy

Description: Provides solutions to nearly 200 practical questions related to the planning, design,

operation, and maintenance of steam plant systems.

McGraw-Hill

1221 Avenue of the Americas 

New York, NY 10020

212-512-2000

www.bookstore.mcgraw-hill.com

Marks Standard Handbook for Mechanical Engineers

Authors: Eugene Avallone and Theodore Baumeister, III (Editors)

Description: Provides descriptions of different heat

distribution systems including low-pressure steam

systems. ISBN: 0070049971

A Practical Guide to Steam Turbine Technology

Author: Heinz P. Bloch

Description: This book is written for plant, mechanical, design, and maintenance engineers, and will

assist end users with selecting, operating, and

maintaining steam-driven systems. It includes

design and manufacturing data for steam turbines

and compressors, as well as the other operational

components. ISBN: 0070059241

Shreve's Chemical Process Industries, Fifth Edition

Author: G. T. Austin

Description: The book provides an overview of 

the chemical processing of raw materials into

useful and profitable products. It provides

process descriptions and diagrams for many 

chemical processing operations.

A Working Guide to Process Equipment

Authors: Norman P. Lieberman and Elizabeth T.

Lieberman

Description: Explains the basic technical issues

that need to be known to troubleshoot process

equipment problems. Provides diagnostic tips,

worked out calculations, practical examples, and

illustrations. 

Nalco Company 

1601 West Diehl Road

Naperville, IL 60563-1198

877-813-3523

www.nalco.com

Nalco Guide to Boiler Failure Analysis

Authors: Robert D. Port and Harvey M. Herro 

Description: This book is a comprehensive field

guide to boiler system failures. It is intended to

aid in-plant detection and diagnosis. Correction

procedures can usually be specified once the

cause of system failures has been determined.

Nalco Water Handbook, Second Edition

Author: Frank N. Kemmer (Editor)

Description: This reference discusses the use of

water and steam in water treatment unit operations, the use of water and steam in a number of

major process industries, and specialized water

treatment technologies in boilers and other systems.

Pennwell Publishing 

1421 South Sheridan Road

Tulsa, OK 74112

918-835-3161

www.pennwell.com 

Petrochemicals in Nontechnical Language, Third Edition

Authors: Donald L. Burdick and William L. Leffler

Description: Provides an overview of the key

processes and operations in the petrochemicals

industry. 

Petroleum Refining in Nontechnical Language,

Third Edition

Author: William L. Leffler

Description: Provides an overview of the key 

processes and operations in the petroleum 

refining industry for professionals in finance 

and marketing. 

Prentice Hall/Pearson Education

One Lake Street

Upper Saddle River, NJ 07458

800-382-3419

www.prenhall.com

Energy Analysis of 108 Industrial Processes

Authors: Harry Brown, Bernard Hamel, and 

Bruce Hedman

Description: A reference for identifying the quantity

and quality of industrial waste energy, which can be

Where to Find Help
A Sourcebook for Industry 41

economically practical to recover. Presents detailed

heat and material balances developed from the

process flow diagrams for 108 industrial processes.

Handbook of Industrial Power & Steam Systems

Author: Paul Garay

Description: Describes the design and operation features of industrial power plants, considering such

aspects as environmental concerns, basic energy

and steam, electrical systems, heat recovery, energy

conservation, codes and standards, and information sources. Publication, 1995. ISBN: 0131474146

Spirax Sarco Application Engineering Department

1150 Northpoint Boulevard

Blythewood, SC 29016

803-714-2000

www.spirax-sarco.com

Hook-Ups—Design of Fluid Systems

Description: The Hook-Up Book is intended to serve

as a reference in the design, operation, and maintenance of steam, air, and liquid systems. The book is a

learning tool to teach engineers how to design productive steam systems efficiently and cost effectively.

Steam Utilization—Design of Fluid Systems

Description: The Steam Utilization Book is intended to serve as a reference in steam fundamentals

to the most efficient use of steam heat content.

The book describes proper steam trapping, controls,

and condensate recovery.

TAPPI Press

15 Technology Parkway South

Norcross, GA 30092

800-332-8685

www.tappi.org

Energy Cost Reduction in the Pulp and Paper Industry

Prepared by: Paprican (Canada)

Description: Provides an overview of cost reduction

opportunities available in pulp and paper plants.

TLV Company Ltd.

13901 South Lakes Drive

Charlotte, NC 28273-6790 

704-597-9070 

www.tlv.com

Condensate Drainage and Recovery

Description: This handbook provides a practical

introduction to draining condensate from 

equipment and returning it to the boiler system. 

Publication, 1997.

Efficient Use of Process Steam

Description: This handbook provides a practical

introduction to steam properties, and a basic

awareness of how steam can be successfully and

beneficially used in industry. Publication, 1996.

Steam Trapping Principles

Description: This handbook explains the technology

of steam trapping, and provides data to correctly

select and install steam traps for the benefit of

maximum plant efficiency.

Yarway Corporation/Tyco Valve & Controls

9700 West Gulf Bank Road

Houston, TX 72040

713-466-1176

www.yarway.com

Industrial Steam Trapping Handbook

Description: Focuses on good steam piping/

system/application practices. Includes extensive

information on different steam trap technologies,

condensate line sizing, and steam trap testing

techniques.

American Boiler Manufacturers Association

(ABMA)

4001 North 9th Street, Suite 226

Arlington, VA 22203-1900

703-522-7350

www.abma.com

ABMA provides a wide range of guides, manuals,

and other publications on boiler operations and

maintenance. 

American Gas Association (AGA)

400 North Capitol Street, NW, Suite 450

Washington, DC 20001

202-824-7000

www.aga.org

Boiler NOx Control Field Manual, 1994

Description: This manual provides an applications

reference and guidebook to assist gas utility marketing personnel in working with industrial customers

to address the control oxides of nitrogen.

Where to Find Help

Other Publications 

(Guides, Manuals, and Standards)
American National Standards Institute (ANSI)

Fluid Control Institute of America, ANSI

25 West 43rd Street

New York, NY 10036

212-642-4900

www.ansi.org

ANSI/Fluid Control Institute 69-1-1989 (revised 1994)

Description: Pressure ratings for steam traps.

ANSI/Fluid Control Institute 85-1-1994

Description: Standard for production testing of

steam traps.

ANSI Fluid Control Institute 87-1-1994

Description: Classifications and operating 

principles of steam traps.

Fluid Control Institute 97.1 

Description: Standard for production testing of secondary pressure drainers (condensate return pumps).

American Society of Mechanical Engineers

(ASME)

Three Park Avenue

New York, NY 10016-5990

800-843-2763 

www.asme.org 

ANSI/ASME PTC 39.1, Performance Testing 

Description: Reviews all the necessary information

to conduct performance tests on steam traps for

efficient use of plant steam. 

ASME B31.1 Power Piping Code 1995 Edition

Description: Code of standards for pressure piping.

ASME Boiler/Pressure Vessel Code

Description: Construction specifications associated

with boilers and their operation.

Consensus on Operating Practices for the Control of

Feedwater and Boiler Water Chemistry in Modern

Industrial Boilers (CRTD-Vol. 34)

Description: Guidelines aimed at minimizing 

boiler deposition.

A Practical Guide to Avoiding Steam Purity 

Problems in the Industrial Plant (CRTD-Vol. 35)

Description: Guidelines aimed at avoiding steam

purity related problems.

Armstrong International, Inc. 

816 Maple Street

Three Rivers, MI 49093 

269-273-1415

www.armintl.com

Armstrong Service Guide Bulletin–301

Description: Steam trap installation and maintenance.

Chart 1101 - A Quick Way to Find How Much Steam

You Need to Heat Water

Description: Chart showing amount of steam and

the boiler horsepower required to heat water.

Chart 1121 - How to Size Condensate Return Lines

Description: Sizing condensate return lines presents several problems that differ from those of

sizing steam or water lines. The most significant

is handling flash steam. The chart contains 

formulas to size condensate lines and return line

capacity data.

Installation and Testing of Inverted Bucket Steam 

Traps–Bulletin - 307 

Description: Steam trap testing for Inverted Bucket

traps.

Steam Trap Testing Guide for Energy Conservation

Description: Trap testing for all trap styles.

ASTM International

100 Barr Harbor Drive

West Conshohocken, PA 19428-2959

610-832-9585

www.astm.org

Annual Book of Standards 2004, Section Four, Volume

04.06, “Thermal Insulation: Environmental Acoustics”.

Description: Features specifications that establish

property requirements for various types of insulation. Also included are tests, practices, and guides

that call out procedures for the measurement of

insulation properties as well as installation.

British Standards Institution (BSI)

389 Chiswick High Road

London 

W4 4AL United Kingdom

+44 (0)20 8996 7001

www.bsi.org.uk

42 Improving Steam System Performance

Where to Find Help
A Sourcebook for Industry 43

Recommendations for Treatment of Water for 

Steam Boilers and Water Heaters (BS 2486:1997)

Description: The standard gives recommendations

for the control of waterside conditions in steam

boilers and water heaters. It also includes information on the preparation of feedwater required

for these systems.

National Board of Boiler and Pressure 

Vessel Inspectors

1055 Crupper Avenue

Columbus, OH 43229

614-888-8320

www.nationalboard.org 

National Board Inspection Code, ANSI/NB-23 National

Board of Boiler and Pressure Vessel Inspectors

Description: The purpose of the National Board

Inspection Code is to “Maintain the integrity of

pressure retaining items after they have been

placed into service by providing rules for 

inspection, repair, and alteration...”

National Insulation Association (NIA)

99 Canal Center Plaza, Suite 222

Alexandria, VA 22314

703-683-6422

www.insulation.org

National Commercial and Industrial 

Insulation Standards

Description: This is a national standard for designing, specifying, and installing thermal mechanical

insulation for commercial and industrial pipe,

equipment, vessels, and ducting systems.

Plant Support & Evaluations, Inc.

282 Shellstone Court

Naples, Florida 34119

888-615-3559

www.plantsupport.com

Steam System Specialist Level One - Training Manual

Description: The training manual covers all aspects

of the steam system. It provides the necessary basic

information on steam, heat transfer, boilers, piping, heat exchangers, insulation, and steam traps. 

Steam System Specialist Level Two - Training Manual

Description: The training manual provides more

detail on certain aspects of the steam system. 

Areas of coverage include steam generation, 

steam turbines, desuperheaters, steam accumulators, piping, expansion, heat transfer, process

control, and condensate recovery.

Process Industry Practices

3925 West Braker Lane (R4500)

Austin, TX 78759

512-232-3041

www.pip.org

Process Industry Practices (PIP) is a consortium of

process industry owners and engineering construction contractors who serve the industry. PIP publishes documents called "Practices." These Practices

reflect a combination of company engineering

standards in many engineering disciplines. Specific

Practices include design, selection and specification,

and installation information.

Spirax Sarco Application Engineering Department 

1150 Northpoint Boulevard

Blythewood, SC 29016

803-714-2000

www.spirax-sarco.com 

Spirax Sarco Products, Applications and Systems for 

the Steam and Condensate Loop “Wall Chart”

Description: Wall chart of a total steam system,

showing steam generation, distribution, end-use

and recovery guidelines.

Spirax Sarco Specification Guide and Designers Notes

Description: Guideline specification and designer

note requirements for industrial, HVAC, and

clean steam systems.

Steam Distribution. Technical Reference Guide (TR-GCM-03)

Description: This guide looks at the distribution of

dry saturated steam as a conveyor of heat energy

to the point of use, for either process heat exchange applications or space heating. It covers

the issues associated with the implementation 

of an efficient steam system.

TAPPI Press

15 Technology Parkway South

Norcross, GA 30092

800-332-8685

www.tappi.org

Paper Machine Steam and Condensate Systems

Description: Provides information to solve dryingrelated problems and gives a basic understanding

of paper machine steam and condensate systems.

Where to Find Help
United Kingdom Energy Efficiency 

Action Energy Web site

Good Practice Guides

+44 (0)08 0058 5794

www.actionenergy.co.uk

The Action Energy site provides an extensive list

of publications on industrial energy efficiency

including the following Good Practices Guides:

Guidance for Coal-Fired Boiler Operation

Description: Guidelines for boiler operation for 

boilers fueled by coal.

Guidance for Gas-Fired Boiler Operation

Description: Guidelines for boiler operation for 

boilers fueled by gas.

Guidance for Oil-Fired Boiler Operation

Description: Guidelines for boiler operation for

boilers fueled by oil.

U.S. Army Corps of Engineers 

441 G Street, NW

Washington, DC 20314-1000

202-761-0001

www.usace.army.mil

Industrial Water Treatment Procedures,

PWTB 420-49-5

Description: Guide for boiler plant operators to

properly set up, maintain, and control boiler 

system water chemistry. Applies to boiler systems

operating below 600 psi. Includes guidelines for

water treatment for other HVAC systems.

U.S. Department of Energy Information Bridge

P.O. Box 62

Oak Ridge, TN 37831 

888-293-6498

www.osti.gov/bridge 

Guide to Low-Emission Boiler and Combustion 

Equipment Selection

Description: Guide presents topics pertaining to

industrial, commercial, and institutional (ICI) 

boilers. Background information about various

types of commercially available boilers is provided, along with discussions about the fuels that

they burn and the emissions that they produce.

Use of the guide is primarily intended for those

involved in either expanding current steam or

hot water generating capacity or developing new

capacity. Document reference: ORNL/TM-2002/19.

Guide to Combined Heat and Power Systems for Boiler

Owners and Operators

Description: This guide is a resource to help industry evaluate the viability of cogeneration for new

or existing ICI boiler installations. Information in

the guide focuses on technical, economic, and 

regulatory issues that boiler owners and operators

should consider during the planning phase of any

CHP project. In addition, the guide identifies

many of the potential benefits and possible barriers to successful implementation of cogeneration

technology. The guide was developed with the

American Boiler Manufacturers Association (ABMA)

and the Council of Industrial Boiler Owners

(CIBO). Document reference: ORNL/TM-2004/144.

U.S. Environmental Protection Agency 

Ariel Rios Building

1200 Pennsylvania Avenue, NW

Washington, DC 20460

202-272-0167

www.epa.gov 

Wise Rules Tool Kit

Description: Rules and measures for estimating

potential energy, cost, and greenhouse gas 

emissions savings with information on boilers,

steam systems, furnaces, process heating, waste

heat recovery, cogeneration, compressed air 

systems, and process cooling.

Armstrong International, Inc. 

816 Maple Street

Three Rivers, MI 49093 

269-273-1415

www.armintl.com

Armstrong Coil Sizing Software

Developer: Armstrong International

Description: Coil sizing and selection instructions

for specific applications.

Armstrong Humidifier Sizing Software

Developer: Armstrong International

Description: Steam humidifier sizing and selection

instructions for specific applications.

Armstrong Preventative Maintenance APM+ Software

Developer: Armstrong International

Description: Pressure Reducing Valve (PRV) sizing

and selection instructions for specific applications.

44 Improving Steam System Performance

Where to Find Help

Software
Armstrong PRV Sizing Software

Developer: Armstrong International

Description: PRV sizing and selection instructions

for specific applications.

Armstrong Steam Eye Software

Developer: Armstrong International

Description: Software designed to constantly 

monitor steam traps in a system.

Armstrong Trap Sizing Software

Developer: Armstrong International

Description: Steam trap sizing and selection

instructions for specific applications.

ChemicaLogic Corporation 

99 South Bedford Street, Suite 207

Burlington, MA 01803

781-425-6738

www.chemicalogic.com

SteamTab Software

Developer: ChemicaLogic Corporation 

Description: SteamTab is a tool designed for steam

property users in the scientific, engineering,

plant operation, and educational communities.

SteamTab uses fundamental equations to calculate all steam properties with interpolation or

curve fits to raw steam data. SteamTab products

support spreadsheet applications.

Conserv-It Software

13000-F York Road, #116

Charlotte, NC 28278

704-841-9550

www.conserv-it.com

SteamWorks Pro

Developer: Conserv-It Software, Inc.

Description: This software assists in tracking steam

trap maintenance efforts.

Control Dynamics, Inc.

201 Wylderose Drive

P.O. Box 509

Midlothian, VA 23113

804-858-5800

www.control-dynamics.com

Boiler Control Package Tool 

Developer: Licensed by Fisher-Rosemount 

Performance Solutions

Description: The Boiler Control Package is a preconfigured control strategy for use with control systems

for steam generators; i.e., boilers, heat recovery generators, and thermal oxidizers. Controls include the

water side for single or three-element drum level

controls, combustion controls for parallel metering

and cross-limiting of one or more fuels, with oxygen

trim. Steam header pressure controls are included, as well as a simulation for training.

EPD 

14 Hayes Street

Elmsford, NY 10523

800-892-8926

www.epdtech.com

DataTemp 2 Software

Developer: EPD

Description: DataTemp 2 Software records, stores

and graphs temperature data over time. For 

maintenance operations and process monitoring

and control, temperature trend data is critical. 

If that data is in a form you can’t use, you have 

a problem. DataTemp 2 provides a simple solution. Using an EPD PM infrared for input and

your computer as a data logger and recorder,

DataTemp 2 lets you take accurate temperature

measurements at programmable time intervals.

Field Data Specialists, Inc.

6917 Stennis Blvd.

Pascagoula, MS 39581

800-932-9543

www.trapbase.com

TrapBase97 for Windows Software

Developer: Field Data Specialists, Inc.

Description: TrapBase was designed as a field tool 

to assist in developing a systematic steam system

program. The software has features for data entry,

directed surveys, field reporting, maintenance 

work orders/history, field data analysis, and savings

results analysis. Existing data from other software

or from spreadsheets can be imported into TrapBase. A version of the software was written to be

used with the TrapTech Palm PC.

Honeywell Corporation

11 West Spring Street

Freeport, IL 61032

800-343-0228

www.iac.honeywell.com 

Turbo Economic Load Allocation

Developer: Honeywell Corporation 

Description: Calculates optimum loading for all 

boilers at all possible steam loads.

A Sourcebook for Industry 45

Where to Find Help
46 Improving Steam System Performance

Linnhoff March

Targeting House

Gadbrook Park

Northwich, Cheshire 

CW9 7U3 United Kingdom

+44 (0)1606 815100

www.linnhoffmarch.co.uk 

PROSTEAM Software

Developer: Linnhoff March 

Description: PROSTEAM is an engineering add-in

model for a Microsoft Excel spreadsheet. It provides

steam and water thermodynamic and transport

property calculations, and steam utility systems

modeling.

National Institute of Standards and Technology 

100 Bureau Drive, Stop 3460

Gaithersburg, MD 20899-3460

301-975-6478

www.nist.gov 

NIST/ASME Steam Properties

Developer: National Institute of Standards and

Technology 

Description: Database of steam and water thermodynamic properties.

Nelson & Roseme, Inc. 

P.O. Box 30024 

Walnut Creek, CA 94598 

925-280-0327

www.nelson-roseme.com

VisualMesa

Developer: Nelson & Roseme, Inc. 

Description: First principles model for complicated energy systems.

Ogontz Corporation 

2835 Terwood Road

Willow Grove, PA 19090

800-523-2478

www.ogontz.com 

Ogontz Energy Savings Potential

Developer: Ogontz Corporation 

Description: This software calculates the dollars

that can be saved using steam controls and traps

in an existing facility or new construction project.

The software provides cost savings information

for unit heaters, winterization steam tracing,

temperature control of traced process piping, and

other temperature control applications.

Plant Support & Evaluations, Inc.

282 Shellstone Court

Naples, Florida 34119

888-615-3559

www.plantsupport.com

Steam Trap Database Software

Developer: Plant Support and Evaluations, Inc.

Description: This free software was developed in

Microsoft Access and is an open environment to

enable anyone to make changes to meet their

plant requirements. 

Spirax Sarco Application Engineering Department 

1150 Northpoint Boulevard

Blythewood, SC 29016

803-714-2000

www.spirax-sarco.com

SNAP3 Steam Needs Analysis Program

Developer: Spirax Sarco

Description: Total Steam System Software Program

for sizing and selecting: piping for steam/condensate/water, steam conditioning stations, 

pressure reducing stations, temperature control

stations, steam traps (all types and applications),

condensate recovery stations; flash steam recovery

systems, clean/pure steam systems.

STMS Steam Trap Management System

Developer: Spirax Sarco

Description: Windows-based software designed for

the easy collection, storage, organization, and

sorting of steam trap data. It lets you create 

custom databases from survey sheets or a handheld Data Collector, then analyze by maintenance schedules, trap performance, trap

application or cost of steam loss, etc.

Steam Conservation Systems

300 Summit Drive

Cranston, RI 02920 

401-944-2041 

www.trapo.com

Steam $$ and the Trapo Demo

Developer: Steam Conservation Systems

Description: Calculates annual steam distribution

system costs and efficiency demonstrates costs of

energy lost through piping insulation, different

costs of managing steam traps, shows investment, costs, payback and ROIs for changing to

predictive maintenance.

Where to Find Help
A Sourcebook for Industry 47

Where to Find Help

Thermon Corporation

P.O. Box 609

San Marcus, TX 78667

800-820-4328 

www.thermon.com

SteamTrace 1.3

Developer: Thermon Corporation

Description: Steam heat tracing design software.

TLV Company, Ltd. 

13901 South Lakes Drive 

Charlotte, NC 28273-6790 

704-597-9070

www.tlv.com 

TLV SE-1 STEAM Software

Developer: TLV Company, Ltd. 

Description: Software to perform calculations for

steam system components. Modules include

Engineering Calculations, Steam Trap Selection,

Pressure Reducing Valve Selection, Air Trap Selection, Gas Trap Selection, Air Vent Selection,

Power Trap Selection, and Separator Selection.

UE Systems 

14 Hayes Street

Elmsford, NY 10523

800-223-1325 

www.uesystems.com 

Ultraprobe 9000

Developer: UE Systems 

Description: Ultrasonic inspection and information

storage system.

U.S. Army Construction Engineering Laboratory 

P.O. Box 9005

Champaign, IL 61826

800-USA-CERL 

www.cecer.army.mil 

HEATER Software

Description: A computer modeling tool that 

incorporates the HEATMAP software. HEATER

allows steam/condensate/utility systems to be 

modeled, and provides inventory and O&M 

condition indices that can be used to prioritize

repairs/ replacement. Predictive modeling can 

estimate time to failure.

U.S. Department of Energy

Industrial Technologies Program

Room 5-F-065, MS EE-2F

1000 Independence Avenue, SW

Washington, DC 20525

877-337-3463

www.eere.energy.gov/industry

3E Plus Insulation Appraisal software 

Developer: North American Insulation Manufacturers Association

Description: Calculates insulation thickness to

determine economic, energy, and environmental

savings for piping and equipment. Includes 

calculations for heat gain or heat loss, surface 

temperature requirements, condensation control,

heat loss efficiencies versus bare pipe, payback

periods, and emissions reductions.

Veritech Corporation

22960 Shaw Road, Suite 620 

Sterling, VA 20166 

703-435-78810

www.veritech-energy.com

ESteam

Developer: Veritech Corporation

Description: A steam system simulation program

developed in a Microsoft Excel environment. The

model performs heat and mass balances and

allows flexibility for specifying condensate return,

flash steam blowdown and deaeration schemes, 

letdown arrangements, and desuperheating 

configurations.

Washington State University 

Cooperative Extension Energy Program

925 Plum Street, SE, Building 4

Olympia, WA 98504-3165

800-373-2139

www.wsu.edu

HEATMAP Software

Description: HEATMAP is a software program that

was specifically developed to help plan, analyze,

and operate district heating and cooling systems.

Yarway Corporation/Tyco Valve & Controls

9700 West Gulf Bank Road

Houston, TX 72040

713-466-1176

www.yarway.com
TrapMaster

Developer: Yarway Corporation

Description: Windows-based software designed for

the collection, storage, organization, and sorting

of steam trap data. It lets you create custom databases from survey sheets or a handheld Data 

Collector, then analyzes it in many different

ways. It is possible to create a historical record 

of an individual trap’s performance over many

surveys. An extensive database of steam trap

manufacturer’s models and performance data is

built in for easy access. 

ASHRAE Journal

American Society of Heating, Refrigeration, and

Air Conditioning Engineers

1791 Tullie Circle, NE

Atlanta, GA 30329

404-636-8400

www.ashrae.org

Boiler Systems Engineering

American Boiler Manufacturers Association

1300 East 9th Street

Cleveland, OH 44114

216-696-7000

www.hpac.com/BSE/

Chemical Engineering

Chemical Week Publishing

110 William Street

New York, NY 10138

212-621-4900

www.che.com

Chemical Processing

Putman Media

555 West Pierce Road, Suite 301

Itasca, IL 60143

630-467-1300

www.chemicalprocessing.com

Consulting-Specifying Engineer

Reed Business Information

360 Park Avenue South

New York, NY 10014

646-746-6400

www.cahners.com

Energy Engineering

Association of Energy Engineers

4025 Pleasantdale Road, Suite 420

Atlanta, GA 30340

770-447-5083

www.aeecenter.com

Energy User News

Business News Publishing

1428-30 Midland Avenue #8

Bronxville, NY 10708

914-776-9241

www.energyusernews.com

Heating/Piping/Air Conditioning, HPAC, Engineering

Penton Publishing

1300 East 9th Street

Cleveland, OH 44114

216-696-7000

www.penton.com

Industrial Maintenance & Plant Operation (IMPO)

Reed Business Information

360 Park Avenue South

New York, NY 10014

646-746-6400

www.cahners.com

Mechanical Engineering, American Society of 

Mechanical Engineers (ASME)

ASME International

Three Park Avenue

New York, NY 10016-5990

973-882-1167

www.asme.org

Plant Engineering

Reed Business Information

360 Park Avenue South

New York, NY 10014

646-746-6400

www.cahners.com

Plant Services

Putnam Media

555 West Pierce, Suite 301

Itasca, IL 60143

630-467-1300

www.plantservices.com

Process Heating

Business News Publishing

Manor Oak One

1910 Cochran Road, Suite 450

Pittsburgh, PA 15220

412-531-3370

www.process-heating.com

48

Where to Find Help

Periodicals
American Gas Association (AGA)

400 North Capitol Street, NW

Washington, DC 20001

202-824-7000

www.aga.org

Energy Analysis

Description: Contains information on boilers in

leading manufacturing industries as it relates to

natural gas.

Solving Boiler Efficiency Problems

Publication: Gas Technology: Natural Gas Applications in Industry, Summer 1996. 

Armstrong International, Inc. 

816 Maple Street

Three Rivers, MI 49093 

269-273-1415

www.armintl.com 

Capturing Energy Savings with Steam Traps

Authors: Richard G. Bockwinkel and Scott A. French

GTI

1700 South Mount Prospect Road 

Des Plaines, IL 60018

847-768-0500

www.gastechnology.org

Analysis of the Industrial Boiler Population 

Description: Report that identifies and characterizes

the current industrial boiler population by fuel type

and consumption, geographic location, industry,

end user, and age. Publication, June 1993.

United Kingdom Energy Efficiency 

Action Energy Web site

Good Practice Guides

+44 (0)08 0058 5794

www.actionenergy.co.uk

The Economic Thickness of Insulation for Hot Pipes

Program: Available in: Fuel Efficiency Booklet 8 1994.

Improving Boiler Efficiency through Water Treatment

Publication: Good Practice Guide 221, March 1998.

Reducing Energy Consumption Costs by Steam Metering

Publication: Good Practice Guide 18, 1991.

U.S. Department of Energy Information Bridge

P.O. Box 62

Oak Ridge, TN 37831

888-293-6498

www.osti.gov/bridge

Review of Orifice Plate Steam Traps

Description: This report describes orifice traps and

mechanical steam traps. It also provides information to help make decisions regarding applications

for which orifice traps should be considered.

U.S. Department of Energy

Industrial Technologies Program

Room 5-F-065, MS EE-2F

1000 Independence Avenue, SW

Washington, DC 20525

877-337-3463

www.eere.energy.gov/industry

Overview of Energy Flow for Industries in Standard

Industrial Classifications 20-39

Description: This report, sponsored by the Department of Energy’s Industries of the Future BestPractices activities, identifies and quantifies the

energy supply and consumption in U.S. industry

for heat and power by application.

Industrial Insulation for Systems Operating Above

Ambient Temperature

Description: This bulletin provides information

about the use of thermal insulation on piping and

flat surfaces where their temperatures are above

that of their surroundings (ORNL/M-4678, 1995).

Steam Digest

Description: This annual compendium is jointly

published by the U.S. Department of Energy and

the Alliance to Save Energy. It contains articles

authored by a variety of manufacturers, national

laboratories, and solution vendors. It covers the

technical and managerial aspects of industrial

steam facility optimization.

AESYS Technologies 

693 North Hills Road

York, PA 17402-2212 

717-755-1081

www.aesystech.com

Area(s) covered: AESYS Technologies offers courses

Training Courses 

and Technical Services

Reports and Technical Papers

A Sourcebook for Industry 49

Where to Find Help
Improving Steam System Performance

in both boiler operation and maintenance, and

facility operations and maintenance.

American Boiler Manufacturers Association

(ABMA)

4001 North 9th Street, Suite 226

Arlington, VA 22203-1900

703-522-7350

www.abma.com

ABMA members offer an extensive listing of

training courses in many aspects of boiler 

operations and maintenance. Visit

www.abma.com/training.php for details.

American Society of Mechanical Engineers (ASME)

Three Park Avenue

New York, NY 10016-5990

800-843-2763

www.asme.org

Area(s) covered: The ASME gives courses on repairs

and alterations of boilers and pressure vessels. 

Armstrong International, Inc.

816 Maple Street

Three Rivers, MI 49093 

269-273-1415

www.armintl.com

Area(s) covered: Armstrong International has training

facilities in which it sponsors Steam Energy Seminars and Education, and online steam 

training through Armstrong Steam University.

Association of Energy Engineers (AEE)

4025 Pleasantdale Road, Suite 420

Atlanta, GA 30340 

770-447-5083

www.aeecenter.org 

Area(s) covered:

• Industrial Energy Conservation 

• Strategies that Work 

• Optimizing Boiler Performance 

Babcock and Wilcox

20 South Van Buren Avenue

Barberton, OH 44203-0351

330-753-4511

www.babcock.com

Area(s) covered: Babcock & Wilcox provide

courses in:

• Boiler Condition Assessment and Monitoring 

• Boiler Performance Analysis 

• Industrial Water-Tube Boiler

• Oil/Gas-Fired Boilers 

Boiler Efficiency Institute 

P.O. Box 2255 

Auburn, AL 36831-2255 

800-669-6948

www.boilerinstitute.com

Area(s) covered:

• Steam Plant Improvement 

• Workshop Engineering Fundamentals 

CDT Micrographics

137 Water Street

Exeter, NH 03833

603-778-6140

www.cdtmicrographics.com

Area(s) covered: Hazards of Steam 

Center for Professional Advancement (CFPA)

P.O. Box 7077

44 West Ferris Street

East Brunswick, NJ 08816-7077

732-238-1600

www.cfpa.com

Area(s) covered: The CFPA offers courses in:

• Boiler and Steam System Management 

• Boiler Water Treatment 

• Piping Design, Analysis, and Fabrication 

• Pressure Vessel Design and Analysis 

• Project Management for Plant Retrofits & 

Shutdowns 

• Shell-and-Tube Heat Exchangers 

• Steam Turbines and Auxiliaries 

Eclipse Combustion, Inc.

1665 Elmwood Road

Rockford, IL 61103

815-877-3031

www.eclipsenet.com 

Area(s) covered: The Eclipse Combustion workshop is an accelerated three-day course covering

the theory, design, operation, and application of

industrial combustion equipment. 

• Combustion Fundamentals

• Combustion Equipment

50

Where to Find Help
51

• Applications

• Problem-solving and Troubleshooting

• Plant Tour and Lab Demonstrations 

Enercheck Systems, Inc.

P.O. Box 49426

Charlotte, NC 28277

704-841-9550

www.enerchecksystems.com

Area(s) covered:

• Performing a Steam Trap Survey

• Performing a Compressed Air/Inert Gas Survey

• How to Make a Steam System Efficient

Industrial Interactions, Inc./BEI

8302 Professional Hill Drive

Fairfax, VA 22031

703-573-4500

www.wetrainindustry.com

Area(s) covered: 

Training courses in:

• Boiler Operations and Maintenance

• Industrial HVAC and Chillers

• Facility Security and Emergency Guidelines

• Water Chemistry in Boilers

• Steam System Management

Technical and consulting services include:

• Walk-through energy audits 

Johnson Controls Institute

5757 North Green Bay Avenue

Milwaukee, WI 53201

414-524-1200

www.johnsoncontrols.com

Area(s) covered:

• Heat Pump Controls 

• Boiler Maintenance 

• Specifying Facility Management Systems 

National Insulation Association (NIA)

99 Canal Center Plaza, Suite 222

Alexandria, VA 22314

703-683-6422

www.insulation.org

Area(s) covered: 

• Designing, specifying, and installing insulation

• Accredited certification training in conducting 

insulation energy appraisals

New York State Energy Research 

and Development Authority (NYSERDA)

17 Columbia Circle

Albany, NY 12203-6399

518-862-1090

www.nyserda.org

Area(s) covered: NYSERDA offers a variety of

opportunities for the commercial and industrial

sectors in New York State to become more energy

efficient. For current opportunities, visit

www.nyserda.org

North American Manufacturing Company

4455 East 71st Street

Cleveland, OH 44105

216-271-6000 

www.namfg.com

Area(s) covered:

• Combustion and Kiln Control 

• Effective Combustion and Its Control 

• Optimizing Gas-Fired Industrial Heating 

Processes 

North Carolina State University Center 

for Boiler Studies

Industrial Extension Services

Campus Box 7902

Raleigh, NC 27695-7902

919-515-5438

www.ies.ncsu.edu

Area(s) covered:

• Energy Management Techniques 

• Customized On-Site Boiler Seminars 

• Measuring and Improving Boiler Efficiency 

• An Evaluation of Oil vs. Natural Gas Firing 

in Boilers 

• Improving Boiler Efficiency Through the Use 

of Natural Gas 

PGS Energy Training

Carnegie Office Park

600 North Bell Avenue

Building 2, Suite 2708

Carnegie, PA 15106 

412-279-9298 

www.pgsenergy.com

Area(s) covered: Managing Industrial Energy 

Procurement 

A Sourcebook for Industry

Where to Find Help
52

Plant Support & Evaluations, Inc. 

282 Shellstone Court 

Naples, FL 34119

888-615-3559 

www.plantsupport.com

Area(s) covered:

• Steam System Training to Four Different Levels

• Customized On-Site Boiler Training

• Customized On-Site Complete Steam System 

Training

• Steam Trap Examiner Training (two levels)

• Utility Optimization Training (steam and 

compressed air)

• Steam Start-up and Shut-down Procedure 

Training

• Defining and Resolving Waterhammer Training

• On-site Steam System Assessments

Power Specialties Company Inc. 

& Power Specialties Service

P.O. Box 9566

Raytown, MO 64133

816-353-1740

www.powerspecialties.com

Area(s) covered: Power Specialties Company Inc.

offers seminars to help optimize steam systems.

Spirax Sarco

Application Engineering Department

1150 Northpoint Boulevard

Blythewood, SC 29016

803-714-2000

www.spirax-sarco.com

Area(s) covered: Spirax Sarco offers an open university program on clean steam utilization and a 

continuing education program on steam systems. 

Steam Conservation Systems

300 Summit Drive

Cranston, RI 02920

401-944-2041

www.trapo.com

Area(s) covered: Steam Conservation Systems offers

programs for reducing the costs and hassles of

maintaining a steam distribution system.

Steam Economies Company

9325 Sutton Place

Hamilton, OH 45011 

513-874-8444

www.steameconomies.com

Area(s) covered:

• Boiler & Steam System Fundamentals 

• Understanding Your Steam Boiler System

University of Tennessee Energy, Environment 

and Resources Center

311 Conference Center Building

Knoxville, TN 37996-4134

865-974-4251

eerc.ra.utk.edu

Area(s) covered:

• Boiler & Steam System Fundamentals

• Energy Management Techniques

• Customized On-Site Boiler and Steam System 

Seminars

• Combined Heat and Power Fundamentals

• Compressed Air Systems

• On-site Assessments

University of Wisconsin-Madison/Extension

Department of Engineering Professional 

Development 

432 North Lake Street

Madison, WI 53706

800-462-0876

epdweb.engr.wisc.edu

Area(s) covered: The University of Wisconsin at

Madison offers a course in Basic Boiler Water

Treatment.

Yarway Corporation/Tyco Valve & Controls

9700 West Gulf Bank Road

Houston, TX 72040

713-466-1176

www.yarway.com

Area(s) covered: 1 or 2 1/2 day courses covering

Steam Conservation, Steam and Condensate 

Systems, Steam Trapping, Installation and 

Maintenance.

Improving Steam System Performance

Where to Find Help
A Sourcebook for Industry 53

Where to Find Help

Armstrong International, Inc. 

816 Maple Street

Three Rivers, MI 49093 

269-273-1415

www.armintl.com 

Guidelines for the Prevention of Water Hammer 

Description: Video identifies the most likely causes

of water hammer and provides solutions that can

be implemented to prevent it. (16 minutes)

Guidelines for Steam System Efficiency

Description: Video explaining basic considerations

in the design, piping, and trapping of steam 

systems. (15 minutes)

Guidelines for Steam Trap Troubleshooting and Testing

Description: Video outlining the need for establishing a preventive maintenance program and

details what to look and listen for in testing

steam traps. (18 minutes)

Let's Talk Steam Traps/Update 

Description: Video explaining the operating 

principles of the three types of steam traps:

mechanical, thermostatic, and thermodynamic.

This tape helps users understand the internal 

operation of inverted bucket, F&T, thermostatic,

and disc traps. (32 minutes)

What Is Steam? 

Description: Video explaining the basics of steam.

(15 minutes)

International District Energy Association

125 Turnpike Road, Suite 4

Westborough, MA 01581-2841

508-366-9339

www.districtenergy.org

Steam Distribution System Safety – A Video 

Training Program 

Description: The purpose of this video training

program is to present the operating features of 

a typical District Heating System with special

emphasis on hazards and safety procedures.

Spirax Sarco Application Engineering Department

1150 Northpoint Boulevard

Blythewood, SC 29016

803-714-2000

www.spirax-sarco.com

Effective Condensate Drainage from Heat Exchangers 

Description: This video highlights the operation of

steam process equipment during change in demand

to address known problems of water hammer

and temperature fluctuations. (15 minutes)

Steam Boilers: The Inside Information 

Description: The video highlights internal boiler

response to on/off demand, high steam demand,

reduced boiler pressure, and change in total 

dissolved solids (TDS). (12 1/2 minutes)

Videos
54 Improving Steam System Performance

Where to Find Help
◆ Appendix A: Glossary of Terms

This appendix contains a glossary of terms used

in steam systems.

◆ Appendix B: Tip Sheets

This appendix contains a series of steam system

tip sheets. Developed by the U.S. Department 

of Energy, these tip sheets discuss common

opportunities that industrial facilities can use 

to improve performance and reduce fuel use. 

◆ Appendix C: Guidelines for Comment

This appendix contains a form that provides a

vehicle for submitting comments for improving

the Sourcebook.

Appendices

A Sourcebook for Industry 55

Appendices

The following appendices have been included in the Sourcebook:
56 Improving Steam System Performance

Appendices
A Sourcebook for Industry 57

Absorption chilling—This is a water chilling

process in which cooling of a solution is accomplished by the evaporation of a fluid (usually

water), which is then absorbed by a different 

solution (usually lithium bromide), then evaporated under heat and pressure. The fluid is then 

condensed with the heat of condensation rejected through a cooling tower.

Air vent—A device that allows the release of

non-condensable gases from a steam system. 

Alkalinity—A measure of the concentration of 

carbonate, bicarbonate, and hydroxyl ion in

water, usually expressed in equivalent ppm (parts

per million) of calcium carbonate.

Backpressure turbine—A turbine that exhausts

steam above atmospheric pressure. The exhaust

steam is usually sent to other services. 

Biomass—Organic matter which is available on a

renewable basis, including agricultural crops and

agricultural wastes and residues, wood and wood

wastes and residues, animal wastes, municipal

wastes, and aquatic plants.

Blowdown ratio—For boilers, the ratio of water

removed by blowdown to the amount of feedwater provided to the boiler in equivalent units for

the same time period (both usually reported in

pounds per hour).

Boiler—A vessel or tank in which heat produced

from the combustion of fuels such as natural 

gas, fuel oil, wood, or coal is used to generate 

hot water or steam for applications ranging 

from building space heating to electric power

production or industrial process heat. 

Boiler blowdown—The periodic or continuous

removal of water from a boiler to remove 

concentrations of dissolved solids and/or sludge

accumulating in the boiler.

Boiler horsepower—A unit of rate of water 

evaporation equal to the evaporation per hour of

34.5 pounds of water at a temperature of 212°F

into steam at 212°F. One boiler horsepower

equals 33,475 Btu per hour.

British thermal unit (Btu)—The amount of heat

required to raise the temperature of one pound

of water one degree Fahrenheit; equal to 252

calories. It is roughly equal to the heat of one

kitchen match.

Chlorides—Chemical compounds found in boiler water consisting of metallic ions with chlorine

atoms, part of a group of compounds called salts.

The most prevalent are magnesium chloride and

sodium chloride.

Cogeneration—The simultaneous production of

electrical or mechanical work and thermal energy

from a process, thus reducing the amount of heat

or energy lost from the process. Also known as

combined heat and power (CHP).

Combined Heat and Power (CHP)—The simultaneous production of electrical or mechanical

work and thermal energy from a process, thus

reducing any waste heat or energy lost from the

process. Also known as cogeneration.

Combustion efficiency—This measure represents the amount of fuel energy extracted from

flue gases. It is a steady state measure and does

not include boiler shell losses or blowdown losses. The losses identified in this efficiency calculation are the stack losses. Stack loss is an

indication of the amount of energy remaining in

the flue gases as they exit the boiler. 

Combustion turbine—A turbine that generates

electric power from the combustion of a fuel. 

Condensate—Condensed steam.

Condensate pump—A pump that pressurizes 

condensate allowing it to flow back to a collection tank, or boiler plant.

Appendix A: Glossary of Terms

Appendix A: Glossary of Terms
58 Improving Steam System Performance

Condenser—A device that condenses steam. Surface condensers use a heat exchanger to remove

energy from the steam, and typically operate

under vacuum conditions. 

Condensing turbine—A turbine that exhausts

steam to typically sub-atmospheric conditions

where the steam is condensed. These turbines are

usually used in power generation applications.

Continuous blowdown—The process of removing

water, on a continuous basis, from a boiler to

remove high concentrations of dissolved solids,

chlorides, and other products. Water is replaced by

treated make-up water added to the condensate

return. The withdrawn blowdown water is usually

discharged to a sanitary drain.

Deaerator—A device that uses steam to strip

feedwater of oxygen and carbon dioxide. 

Desuperheater—A device used in steam systems

to control the energy level and/or temperature of

steam supplied to an end use, typically by injecting a fine mist of condensate into the steam flow.

Dew point—The temperature to which a vapor

must be cooled, in order for saturation or 

condensation to occur.

Dissolved solids—The minerals and impurities

in boiler make-up water. These increase in 

concentration as water is boiled into steam. 

Distillation column—A device that separates 

components of a compound relying on differences in boiling points.

Dryer—A device that removes moisture from 

a solid.

Duty cycle—The duration and periodicity of the

operation of a device. 

Excess air—Excess air in a combustion process is

that amount of air present in excess of the 

theoretically required air for complete combustion.

Excess air absorbs some of the heat of combustion and is carried away as waste heat with the

exhaust combusted gases.

Evaporator—A device that removes moisture

from a liquid, resulting in increased concentration of the remaining compounds.

Feedwater—Water sent into a boiler or a steam

generator. Feedwater typically meets cleanliness

criteria, contains treatment chemicals, and has

been stripped of oxygen.

Feedwater pump—A pump that sufficiently pressurizes feedwater to supply a boiler or 

generator.

Full load efficiency—The stated efficiency 

(in percent) of a process in terms of energy or

work output divided by energy input at rated

production (full load).

Greenhouse gas emissions—Those gases, such as

water vapor, carbon dioxide, tropospheric ozone,

methane, and low level ozone that are transparent to solar radiation, but opaque to long wave

radiation, and which are believed to contribute

to climate change.

Heat exchanger—A device used to transfer heat

from one medium by either direct or 

indirect contact. 

Heating, Ventilating and Air Conditioning 

(HVAC)—All the components of the appliance or

system used to condition the interior air of a

facility. 

Heat Recovery Steam Generator (HRSG)—

A device that captures the thermal energy in an

exhaust stream or a process stream and transfers

it to water to generate steam.

Kilowatt hour (kWh)—A unit of measure of 

electricity supply or consumption of 1,000 Watts

over the period of one hour; equivalent to 

3,412 Btu. 

Latent heat—The change in heat content that

occurs with a change in phase and without

change in temperature. Changes in heat content

that affect a change in temperature are called

sensible heat changes.

Life Cycle Cost (LCC)—The sum of all the costs

both recurring and nonrecurring, related 

to a product, structure, system, or service during

its life span or specified time period. 

Appendix A: Glossary of Terms
A Sourcebook for Industry 59

Make-up water—Water brought into a boiler 

system from outside to replace condensate not

returned to the boiler plant, water used in blowdown, steam lost through leaks, or water lost

through evaporation or mist. 

MMBtu—A unit of one million British thermal

units (Btu).

Payback—The amount of time required for positive cash flows to equal the total investment

costs. This is often used to describe how long it

will take for energy savings resulting from using

more energy-efficient equipment to equal the

premium paid to purchase the more energy-efficient equipment.

Potable water—Water that is suitable for drinking, as defined by local health officials. 

Pounds per square inch gauge (psig)—

A unit of pressure in pounds force in comparison

to local atmospheric pressure (as measured by a

gauge). 

Pressure Reducing Valve (PRV)—A valve that

regulates the amount of steam allowed from a

high-pressure service to a low-pressure service. 

Radiant energy—Energy (transfer of heat

through matter or space by means of electromagnetic waves) that transmits away from its source

in all directions.

Reboiler—A heat exchanger used in petroleum

refining and chemical manufacturing applications that adds heat to a process stream. 

Reformer—A device that produces hydrogen

from a hydrocarbon compound such as methane,

typically by using steam. 

Relative humidity—A measure of the percent of

moisture actually in the air compared with what

would be in it if it were fully saturated at that

temperature. When the air is fully saturated, its

relative humidity is 100 percent. 

R-Value—A measure of the capacity of a material

(or assembly of materials) to resist heat transfer,

sometimes called thermal resistance. The R-Value

is the reciprocal of the heat transfer coefficient

(U-Value). The larger the R-Value, the greater its

insulating properties. 

Silica—The concentration of silica dioxide found

in water measured in parts per million. Silica

forms a tenacious scale with low thermal conductance. Silica is soluble in steam and can carry

over into steam where it can condense on turbine blades or erode surfaces.

Sludge—A general term applied to a relatively

loose accumulation of material that has settled to

the bottom of a boiler.

Stack heat loss—Sensible and latent heat contained in combustion gases and vapor emitted to

the atmosphere. 

Stand-alone—A device that operates independent of or is not connected to other systems.

Standby losses—In boiler systems, standby losses

are energy losses that are associated with natural

draft through a boiler in a standby operating

mode. 

Steam ejector—A device that uses a relatively

high-pressure motive steam flow through a nozzle to create a low-pressure or suction effect.

Steam injector—A device that injects steam into

a process, often used in direct steam heating 

applications. 

Steam trap—An automatic control valve that

allows for the release of condensate, air, CO2, and other non-condensable gases, yet keeps live

steam in the system.

Stripper—A device that separates components

from a compound.

Surface blowdown—Boiler blowdown taken

from the upper part of the boiler just below the

water surface to reduce the amount of dissolved

solids.

Thermal conductivity—This is a positive constant, k, that is a property of a substance and is

used in the calculation of heat transfer rates for

materials. It is the amount of heat that flows

through a specified area and thickness of a material over a specified period of time when there is

a temperature difference of one degree between

the surfaces of the material.

Appendix A: Glossary of Terms
60 Improving Steam System Performance

Thermal load factor—A term used to describe

the relative stability of use of heating in a facility

or a process. Often used in cogeneration where a

“high” factor denotes a continuous use of steady

heating. 

Thermocompressor—A device that uses high 

pressure steam to increase the pressure of a lowpressure steam supply to generate a more useful

steam service. 

Throttling—Regulating flow rate by closing a

valve in the system.

Turbine—A device that converts the enthalpy of

steam into mechanical work. See condensing 

turbine and backpressure turbine.

Vacuum breaker—A device that responds to the

formation of vacuum conditions in equipment

such as a heat exchanger by allowing in air

which promotes condensate drainage. 

Variable Frequency Drive (VFD)—A type of 

variable speed motor drive in which the motor is 

supplied with electrical power at frequencies

other than standard 60 Hertz through a converter.

Variable Air Volume (VAV)—Variable air volume

is a term for changing the quantity of air flow to

meet heating, cooling, or exhaust loads rather

than changing air temperatures.

Waste heat—Heat that is discharged from a

mechanical process, wastewater, or ventilation

exhaust system that could be reclaimed for useful

purposes.

Water hammer—A shock that results from the 

sudden collapse of a steam pocket in a two phase

line such as a condensate return line. Also the

impingement of a water slug carried by relatively

high velocity steam. 

Appendix A: Glossary of Terms
A Sourcebook for Industry 61

Appendix B: Steam Tip Sheets

Appendix B: Steam Tip Sheets

Some improvement opportunities are available to many different systems. To increase industry 

awareness of several fundamental improvement opportunities, the U.S. Department of Energy’s 

Industrial Technologies Program has developed the following tip sheets through its BestPractices 

activities. 

1. Inspect and Repair Steam Traps

2. Insulate Steam Distribution and Condensate Return Lines

3. Use Feedwater Economizers for Waste Heat Recovery

4. Improve Your Boiler's Combustion Efficiency

5. Tip Sheet Number Skipped

6. Tip Sheet Number Skipped

7. Clean Boiler Waterside Heat Transfer Surfaces

8. Return Condensate to the Boiler

9. Minimize Boiler Blowdown

10. Recover Heat from Boiler Blowdown

11. Use Vapor Recompression to Recover Low-Pressure Waste Steam

12. Flash High-Pressure Condensate to Regenerate Low-Pressure Steam

13. Use a Vent Condenser to Recover Flash Steam Energy

14. Use Low-Grade Waste Steam to Power Absorption Chillers

15. Benchmark the Fuel Costs of Steam Generation

16. Minimize Boiler Short Cycling Losses

17. Install Removable Insulation on Valves and Fittings

18. Deaerators in Industrial Steam Systems

19. Cover Heated, Open Vessels

20. Replace Pressure-Reducing Valves with Backpressure Turbogenerators

21. Consider Steam Turbine Drives for Rotating Equipment

22. Consider Installing High-Pressure Boilers with Backpressure Turbine-Generators

23. Install an Automatic Blowdown Control System

24. Upgrade Boilers with Energy-Efficient Burners

25. Consider Installing Turbulators on Two- and Three-Pass Firetube Boilers
62 Improving Steam System Performance

Appendix B: Steam Tip Sheets
Inspect and Repair Steam Traps 

In steam systems that have not been maintained for three to five years, between

15% to 30% of the installed steam traps may have failed—thus allowing live

steam to escape into the condensate return system. In systems with a regularly

scheduled maintenance program, leaking traps should account for less than 

5% of the trap population. If your steam distribution system includes more than

500 traps, a steam trap survey will probably reveal significant steam losses.

◆ Example

In a plant where the value of steam is $4.50 per thousand pounds ($/1,000 lbs),

an inspection program indicates that a trap on a 150 psig steam line is stuck

open. The trap orifice is 1/8 inch in diameter. The table shows the estimated

steam loss as 75.8 lbs/hr. By repairing the failed trap, annual savings are:

Savings = 75.8 lbs/hr x 8,760 hrs/yr x $4.50/1,000 lbs = $2,988/yr

◆ Steam Trap Testing Facts

Steam traps are tested to determine if they are functioning properly and not cold 

plugging or failing in an open position and allowing live steam to escape into

the condensate return system. There are four basic ways to test steam traps: temperature, sound, visual, and electronic.

A Sourcebook for Industry 63

Appendix B: Steam Tip Sheet Number 1

Recommended Steam Trap 

Testing Intervals

• High Pressure (150 psig and

above): Weekly to Monthly

• Medium Pressure (30 to 150

psig): Monthly to Quarterly

• Low Pressure (Below 30 psig):

Annually

◆ Suggested Actions ◆

Steam traps are tested primarily to determine whether they are functioning properly and not allowing live steam to blow through. Establish a

program for the regular systematic inspection, testing, and repair of steam traps. Include a reporting mechanism to ensure thoroughness

and to provide a means of documenting energy and dollar savings.

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102002-1503 • March 2002 • Steam Tip Sheet #1

Steam Loss (lbs/hr)

Trap Orifice Steam Pressure (psig)

Diameter (inches) 15 100 150 300

1/32 0.85 3.3 4.8 –

1/16 3.4 13.2 18.9 36.2

1/8 13.7 52.8 75.8 145

3/16 30.7 119 170 326

1/4 54.7 211 303 579

3/8 123 475 682 1,303

From the Boiler Efficiency Institute. Steam is discharging to atmospheric pressure.

Leaking Steam Trap Discharge Rate
Insulate Steam Distribution 

and Condensate Return Lines

Uninsulated steam distribution and condensate return lines are a constant source

of wasted energy. The table shows typical heat loss from uninsulated steam distribution lines. Insulation can typically reduce energy losses by 90% and help

ensure proper steam pressure at plant equipment. Any surface over 120°F should

be insulated, including boiler surfaces, steam and condensate return piping, and

fittings. 

Insulation frequently becomes damaged or is removed and never replaced during

steam system repair. Damaged or wet insulation should be repaired or immediately replaced to avoid compromising the insulating value. Eliminate sources of

moisture prior to insulation replacement. Causes of wet insulation include leaking valves, external pipe leaks, tube leaks, or leaks from adjacent equipment.

After steam lines are insulated, changes in heat flows can influence other parts of

the steam system.

◆ Example

In a plant where the value of steam is $4.50/MMBtu, a survey of the steam 

system identified 1,120 feet of bare 1-inch diameter steam line, and 175 feet of

bare 2-inch line both operating at 150 psig. An additional 250 feet of bare 4-inch

diameter line operating at 15 psig was found. From the table, the quantity of

heat lost per year is:

1-inch line: 1,120 feet x 285 MMBtu/yr per 100 ft = 3,192 MMBtu/yr

2-inch line: 175 feet x 480 MMBtu/yr per 100 ft = 840 MMBtu/yr

4-inch line: 250 feet x 415 MMBtu/yr per 100 ft = 1,037 MMBtu/yr

Total Heat Loss = 5,069 MMBtu/yr

The annual operating cost savings from installing 90% efficient

insulation is:

0.90 x $4.50/MMBtu x 5,069 MMBtu/yr = $20,530

Heat Loss per 100 feet of Uninsulated Steam Line (MMBtu/yr)

Distribution Line Steam Pressure (psig)

Diameter (inches) 15 150 300 600

1 140 285 375 495

2 235 480 630 840

4 415 850 1,120 1,500

8 740 1,540 2,030 2,725

12 1,055 2,200 2,910 3,920

Based on horizontal steel pipe, 75oF ambient air, no wind velocity, and 8,760 operating hr/yr.

64 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 2

Insulation Optimization 

Software Available

The North American Insulation

Manu-facturers Association has

developed a software package

(3EPlus) that determines the

optimum thickness for a wide

variety of insulating materials.

Outputs include the simple

payback period, surface heat

loss, and surface temperature

for each specified insulation

thickness. 3EPlus is available

at no cost through the 

EERE Information Center, 

877-337-3463.

Use Insulating Jackets

Removable insulating jackets

are available for valves, flanges,

steam traps, and other fittings.

Remember that a 6-inch gate

valve may have over 6 square

feet of surface area from which

to radiate heat.

◆ Suggested Actions ◆

Conduct a survey of your steam distribution and condensate return piping, install insulation, and start to save.

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102002-1504 • March 2002 • Steam Tip Sheet #2

Heat Loss per 100 feet of Uninsulated Steam Line
Use Feedwater Economizers 

for Waste Heat Recovery

A feedwater economizer reduces steam boiler fuel requirements by transferring

heat from the flue gas to incoming feedwater. Boiler flue gases are often rejected

to the stack at temperatures more than 100°F to 150°F higher than the temperature of the generated steam. Generally, boiler efficiency can be increased by 

1% for every 40°F reduction in flue gas temperature. By recovering waste heat, an

economizer can often reduce fuel requirements by 5% to 10% and pay for itself in

less than 2 years. The table provides examples of the potential for heat recovery.

◆ Example

A boiler generates 45,000 lb/hr of 150 psig steam by burning natural gas. Condensate is returned to the boiler and mixed with makeup water to yield 117°F

feedwater. The stack temperature is measured at 500°F. Determine the annual

energy savings that will be achieved by installing an economizer given 8,400

hours per year of boiler operation at an energy cost of $4.50/MMBtu.

From the steam tables, the following enthalpy values are available:

For 150 psig saturated steam: 1,195.50 Btu/lb

For 117°F feedwater: 84.97 Btu/lb

Boiler thermal output = 45,000 lb/hr x (1,195.5 – 84.97) Btu/lb = 50 million Btu/hr

The recoverable heat corresponding to a stack temperature of 500°F and a natural

gas-fired boiler load of 50 MMBtu/hr is read from the table (above) as 4.6 MMBtu/hr.

Annual savings = 4.6 MMBtu/hr x $4.50/MMBtu x 8,400 hr/yr = $173,880/yr

Exhaust Gas 

Temperature Limits

The lowest temperature to

which flue gases can be cooled

depends on the type of fuel

used: 250°F for natural gas,

300°F for coal and low sulphur

content fuel oils, and 350°F 

for high sulphur fuel oils.

These limits are set to prevent

condensation and possible 

corrosion of the stack.

Potential Economizer 

Applications

A feedwater economizer is

appropriate when insufficient

heat transfer surface exists

within the boiler to remove

combustion heat. Boilers 

that exceed 100 boiler hp,

operating at pressures 

exceeding 75 psig or above,

and that are significantly

loaded all year long are 

excellent candidates for an

economizer retrofit. 

◆ Suggested Actions ◆

• Determine the stack temperature after the boiler has been tuned to manufacturer’s specifications. The boiler should be operating at

close-to-optimum excess air levels with all heat transfer surfaces clean.

• Determine the minimum temperature to which stack gases can be cooled subject to criteria such as dew point, cold-end corrosion,

and economic heat transfer surface. (See sidebar: Exhaust Gas Temperature Limits.)

• Study the cost-effectiveness of installing a feedwater economizer or air preheater in your boiler.

Recoverable Heat, MMBtu/hr

Initial Stack Gas Boiler Thermal Output, MMBtu/hr

Temperature, °F 25 50 100 200

400 1.3 2.6 5.3 10.6

500 2.3 4.6 9.2 18.4

600 3.3 6.5 13.0 26.1

Based on natural gas fuel, 15% excess air, and a final stack temperature of 250°F.

A Sourcebook for Industry 65

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102002-1505 • March 2002 • Steam Tip Sheet #3

Appendix B: Steam Tip Sheet Number 3

Recoverable Heat from Boiler Flue Gases
Improve Your Boiler’s Combustion Efficiency

Combustion Efficiency

Operating your boiler with an optimum amount of excess air will minimize heat

loss up the stack and improve combustion efficiency. Combustion efficiency is a

measure of how effectively the heat content of a fuel is transferred into usable

heat. The stack temperature and flue gas oxygen (or carbon dioxide) concentrations are primary indicators of combustion efficiency. 

Given complete mixing, a precise or stoichiometric amount of air is required to

completely react with a given quantity of fuel. In practice, combustion conditions

are never ideal, and additional or “excess” air must be supplied to completely

burn the fuel.

The correct amount of excess air is determined from analyzing flue gas oxygen

or carbon dioxide concentrations. Inadequate excess air results in unburned

combustibles (fuel, soot, smoke, and carbon monoxide) while too much results

in heat lost due to the increased flue gas flow—thus lowering the overall boiler

fuel-to-steam efficiency. The table relates stack readings to boiler performance.

On well-designed natural gas-fired systems, an excess air level of 10% is attainable.

An often stated rule of thumb is that boiler efficiency can be increased by 1% for

each 15% reduction in excess air or 40°F reduction in stack gas temperature.

◆ Example

A boiler operates for 8,000 hours per year and consumes 500,000 MMBtu of natural

gas while producing 45,000 lb/hr of 150 psig steam. Stack gas measurements 

indicate an excess air level of 44.9% with a flue gas less combustion air temperature of 400°F. From the table, the boiler combustion efficiency is 78.2% (E1). 

Tuning the boiler reduces the excess air to 9.5% with a flue gas less combustion

air temperature of 300°F. The boiler combustion efficiency increases to 83.1%

(E2). Assuming a steam value of $4.50/MMBtu, the annual cost savings are:

Cost Savings = Fuel Consumption x (1 - E1/E2) x steam cost

= 29,482 MMBtu/yr x $4.50/MMBtu = $132,671 annually

Combustion Efficiency

Excess % Flue Gas Temperature Less Combustion Air Temp, °F

Air Oxygen 200 300 400 500 600

9.5 2.0 85.4 83.1 80.8 78.4 76.0

15.0 3.0 85.2 82.8 80.4 77.9 75.4

28.1 5.0 84.7 82.1 79.5 76.7 74.0

44.9 7.0 84.1 81.2 78.2 75.2 72.1

81.6 10.0 82.8 79.3 75.6 71.9 68.2

66 Improving Steam System Performance

Flue Gas Analyzers

The percentage of oxygen in

the flue gas can be measured

by inexpensive gas-absorbing

test kits. More expensive

($500-$1,000) hand-held, 

computer-based analyzers 

display percent oxygen, stack

gas temperature, and boiler

efficiency. They are a recommended investment for any

boiler system with annual fuel

costs exceeding $50,000.

Oxygen Trim Systems

When fuel composition is 

highly variable (such as refinery gas, hog fuel, or multi-fuel 

boilers), or where steam flows

are highly variable, an on-line

oxygen analyzer should be 

considered. The oxygen “trim”

system provides feedback to 

the burner controls to automatically minimize excess

combustion air and optimize

the air-to-fuel ratio.

Assumes complete combustion with no water vapor in the combustion air.

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102002-1506 • March 2002 • Steam Tip Sheet #4

◆ Suggested Actions ◆

Boilers often operate at excess air levels higher than the optimum. Periodically monitor flue gas composition and tune your boilers to

maintain excess air at optimum levels.

Appendix B: Steam Tip Sheet Number 4

Combustion Efficiency for Natural Gas
Clean Boiler Waterside Heat Transfer Surfaces

Even on small boilers, the prevention of scale formation can produce substantial

energy savings. Scale deposits occur when calcium, magnesium, and silica, commonly found in most water supplies, react to form a continuous layer of material

on the waterside of the boiler heat exchange tubes. 

Scale creates a problem because it typically possesses a thermal conductivity an

order of magnitude less than the corresponding value for bare steel. Even thin

layers of scale serve as an effective insulator and retard heat transfer. The result is

overheating of boiler tube metal, tube failures, and loss of energy efficiency. Fuel

waste due to boiler scale may be 2% for water-tube boilers and up to 5% in firetube boilers. Energy losses as a function of scale thickness and composition are

given in the table below.

◆ Example

A boiler annually uses 450,000 million Btu (MMBtu) of fuel while operating for

8,000 hours at its rated capacity of 45,000 pounds-per-hour (lbs/hr) of 150-psig

steam. If scale 1/32nd of an inch thick is allowed to form on the boiler tubes,

and the scale is of “normal” composition, the table indicates a fuel loss of 2%.

The increase in operating costs, assuming energy is priced at $3.00/MMBtu, is:

Annual Operating Cost Increase = 450,000 MMBtu/year x $3.00/MMBtu x 0.02

= $27,000

Fuel Loss, % of Total Use

Scale Thickness, Scale Type

inches “Normal” High Iron Iron Plus Silica

1/64 1.0 1.6 3.5

1/32 2.0 3.1 7.0

3/64 3.0 4.7 –

1/16 3.9 6.2 –

A Sourcebook for Industry 67

Monitor Flue Gas Temperature 

An indirect indicator of scale

or deposit formation is flue 

gas temperature. If the flue gas 

temperature rises (with boiler

load and excess air held constant), the effect is possibly

due to the presence of scale.

Perform Visual Inspections 

Visually inspect boiler tubes

when the unit is shut down

for maintenance. Scale

removal can be achieved by

mechanical means or acid

cleaning. If scale is present,

consult with your local water

treatment specialist and 

consider modifying your 

feedwater treatment or 

chemical additives schedule. 

◆ Suggested Actions ◆

Any scale in a boiler is undesirable. The best way to deal with scale is not to let it form in the first place. Scale formation is prevented by: 

• Pretreatment of boiler make-up water (using water softeners, demineralizers, and reverse osmosis to 

remove scale-forming minerals),

• Chemical injection into the boiler feedwater, and 

• Adopting proper boiler blowdown practices.

Note: “Normal” scale is usually encountered in low-pressure applications. The high iron and iron plus silica scale 

composition results from high-pressure service conditions.

*Extracted from National Institute of Standards and Technology, Handbook 115, Supplement 1.

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-10099-952 • Revised June 2001 • Steam Tip Sheet #7

Energy Loss Due to Scale Deposits*

Appendix B: Steam Tip Sheet Number 7
Return Condensate to the Boiler

When steam transfers its heat in a manufacturing process, heat exchanger, or

heating coil, it reverts to a liquid phase called condensate. An attractive method

of improving your power plant’s energy efficiency is to increase the condensate

return to the boiler.

Returning hot condensate to the boiler makes sense for several reasons. As more 

condensate is returned, less make-up water is required, saving fuel, make-up

water, and chemicals and treatment costs. Less condensate discharged into a

sewer system reduces disposal costs. Return of high purity condensate also

reduces energy losses due to boiler blowdown. Significant fuel savings occur as

most returned condensate is relatively hot (130°F to 225°F), reducing the amount

of cold make-up water (50°F to 60°F) that must be heated.

A simple calculation indicates that energy in the condensate can be more than

10% of the total steam energy content of a typical system. The graph shows the

heat remaining in the condensate at various condensate temperatures, for a

steam system operating at 100 psig, with make-up water at 55°F.

◆ Example

Consider a steam system that returns an additional 10,000 lbs/hr of condensate

at 180°F due to distribution modifications. Assume this system operates 8,000

hours annually with an average boiler efficiency of 82%, and make-up water

temperature of 55°F. The water and sewage costs for the plant are $0.002/gal, and

the water treatment cost is $0.002/gal. The fuel cost is $3.00 per Million Btu

(MMBtu). Assuming a 12% flash steam loss*, calculate the overall annual savings.

Annual Water, Sewage, and Chemicals Savings = (1 – Flash Steam Fraction) x

(Condensate Load in lbs/hr) x Annual Operating Hours x (Total Water Costs in

$/gal) ÷ (Water Density in lbs/gal)

= (1 - 0.12) x 10,000 x 8,000 x $0.004 = $33,760 8.34

* When saturated condensate is reduced to some lower pressure, some condensate flashes off to steam again. 

This amount is the flash steam loss.

Annual Fuel Savings = (1 – Flash Steam Fraction) x (Condensate Load in lbs/hr) x

Annual Operating Hours x (Makeup Water Temperature rise in °F) x (Fuel Cost in

$/Btu) ) ÷ Boiler Efficiency 

= (1 - 0.12) x 10,000 x 8,000 x (180 – 55) x $3.00 = $32,195 0.82 x 106

Total Annual Savings Due to Return of an Additional 10,000 lbs/hr of Condensate

= $33,760 + $32,195 = $65,955

68 Improving Steam System Performance

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-10099-953 • Revised June 2001 • Steam Tip Sheet #8

Condensate Recovery

Produces Savings 

A large specialty paper plant

reduced its boiler makeup

water rate from about 35% of

steam production to between

14% and 20% by returning

additional condensate. Annual

savings added up to more than

$300,000.

Suggested Actions

Reduce operating costs through

maximizing the return of hot

condensate to the boiler. Consider the following actions: 

• If a condensate return system

is absent, estimate the cost

of a condensate return and

treatment system (as necessary) and install one if economically justified. 

• Repair steam distribution

and condensate return 

system leaks.

• Insulate condensate return 

system piping to conserve

heat and protect personnel

against burns.

12 5 17 5 225 275 325

25

20

15

10

5

0

Heat Remaining in Condensate (%)

15 0 2 00 250 300 350

Condensate Temperature (°F)

Let:

hc = enthalpy of condensate at 180°F = 148 Btu/lb

hm = enthalpy of make-up water at 55°F = 23 Btu/lb

hs = enthalpy of steam at 100 psig = 1189 Btu/lb

Heat remaining in condensate (%):

= (hc – hm)/(hs – hm) x 100

= (148 – 23)/(1189 – 23) x 100 = 10.7%

Appendix B: Steam Tip Sheet Number 8
A Sourcebook for Industry 69

Minimize Boiler Blowdown 

Minimizing your blowdown rate can substantially reduce energy losses, as the

temperature of the blown-down liquid is the same as that of the steam generated

in the boiler. Minimizing blowdown will also reduce makeup water and chemical

treatment costs.

As water evaporates in the boiler steam drum, solids present in the feedwater are

left behind. The suspended solids form sludge or sediments in the boiler, which

degrades heat transfer. Dissolved solids promote foaming and carryover of boiler

water into the steam. To reduce the levels of suspended and total dissolved solids

(TDS) to acceptable limits, water is periodically discharged or blown down from

the boiler. Mud or bottom blowdown is usually a manual procedure done for a

few seconds on intervals of several hours. It is designed to remove suspended

solids that settle out of the boiler water and form a heavy sludge. Surface or

skimming blowdown is designed to remove the dissolved solids that concentrate

near the liquid surface. Surface blowdown is often a continuous process. 

Insufficient blowdown may lead to carryover of boiler water into the steam, or

the formation of deposits. Excessive blowdown will waste energy, water, and

chemicals. The optimum blowdown rate is determined by various factors including the boiler type, operating pressure, water treatment, and quality of makeup

water. Blowdown rates typically range from 4% to 8% of boiler feedwater flow

rate, but can be as high as 10% when makeup water has a high solids content. 

◆ Example

Assume that the installation of an automatic blowdown control system (see sidebar) reduces your blowdown rate from 8% to 6%. This example assumes a continuously operating natural-gas-fired, 150-psig, 100,000-pound-per-hour steam

boiler. Assume a makeup water temperature of 60°F, boiler efficiency of 82%,

with fuel valued at $3.00 per million Btu (MMBtu), and the total water, sewage

and treatment costs at $0.004 per gallon. Calculate the total annual cost savings.

Boiler Feedwater: Initial = 100,000 = 108,695 lbs/hr (1 - 0.08)

Final = 100,000 = 106,383 lbs/hr (1 - 0.06)

Makeup Water Savings = 108,695 – 106,383 = 2312 lbs/hr

Enthalpy of boiler water = 338.5 Btu/lb; for makeup water at 60°F = 28 Btu/lb

Thermal Energy Savings = 338.5 – 28 = 310.5 Btu/lb

Annual Fuel Savings = 2312 lbs/hr x 8760 hrs/yr x 310.5 Btu/lb x $3.00/MMBtu = $23,007 0.82 x 106

Annual Water and Chemical Savings = 2312 lbs/hr x 8760 hrs/yr x$0.004/gal = $9,714 8.34 lbs/gal

Annual Cost Savings = $23,007 + $9,714 = $32,721

Automatic Blowdown 

Control Systems 

These systems optimize surface

blowdown by regulating water

volume discharged in relation

to amount of dissolved solids

present. Conductivity, TDS, 

silica or chlorides concentrations, and/or alkalinity are

reliable indicators of salts and

other contaminants dissolved

in boiler water. A probe provides feedback to a controller

driving a modulating blowdown valve. An alternative is

proportional control —with

blowdown rate set proportional to makeup water flow.

Cycles of Concentration

“Cycles of concentration”

refers to the accumulation of

impurities in the boiler water.

If the boiler water contains 

ten times the level of impurities in the makeup water, it 

is said to have ten cycles of

concentration.

References and Footnotes

1. Consensus Operating Practices for

Control of Feedwater/Boiler Water

Chemistry in Modern Industrial Boilers,

published by the ASME, 1994.

2. Recommended Rules for the Care and

Operation of Heating Boilers, Section

VI of the ASME Boiler and Pressure

Vessel Code, 1995.

3. Recommended Guidelines for the Care

of Power Boilers, Section VII of the

ASME Boiler and Pressure Vessel

Code, 1995.

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-10099-954 • Revised October 2003 • Steam Tip Sheet #9

◆ Suggested Actions ◆

Review your blowdown practices to identify energy saving opportunities. Examine operating practices for boiler feedwater and blowdown

rates developed by the American Society of Mechanical Engineers (ASME). Considerations include operating pressure, steam purity, and

deposition control. Consider an automatic blowdown control system (see sidebar).

Appendix B: Steam Tip Sheet Number 9
Recover Heat from Boiler Blowdown 

Heat can be recovered from boiler blowdown by using a heat exchanger to preheat boiler makeup water. Any boiler with continuous blowdown exceeding 

5% of the steam rate is a good candidate for the introduction of blowdown waste

heat recovery. Larger energy savings occur with high-pressure boilers. The following table shows the potential for heat recovery from boiler blowdown.

◆ Example

In a plant where the fuel cost is $3.00/MMBtu, a continuous blowdown rate of

3,200 pounds per hour (lbs/hr) is maintained to avoid the buildup of high concentrations of dissolved solids. What are the annual savings if a makeup water

heat exchanger is installed that recovers 90% of the blowdown energy losses?

The 82% efficient boiler produces 50,000 lbs/hr of 150-psig steam. It operates for

8000 hours per year. The blowdown ratio is:

Blowdown Ratio = 3200 = 6.0%

3200 + 50,000

From the table, the heat recoverable corresponding to a 6% blowdown ratio with

a 150-psig boiler operating pressure is 1.8 MMBtu/hr. Since the table is based on a

steam production rate of 100,000 lbs/hour, the annual savings for this plant are:

Annual

Energy = 1.67 MMBtu/hr x (50,000 lbs/hr/100,000 lbs/hr) x 8000 hrs/yr = 8146 MMBtu

Savings 0.82

Annual Cost Savings = 8146 MMBtu/year x $3.00/MMBtu = $24,438

70 Improving Steam System Performance

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-10099-955 • Revised June 2001 • Steam Tip Sheet #10

Blowdown Energy Recovery 

Blowdown waste heat can be

recovered with a heat exchanger, a flash tank, or flash tank

in combination with a heat

exchanger. Lowering the pressure in a flash tank allows a

portion of the blowdown to 

be converted into low pressure

steam. This low pressure steam

is most typically used in deaerators. Drain water from the

flash tank is then routed

through a heat exchanger.

Cooling the blowdown has 

the additional advantage of

helping to comply with local

codes limiting the discharge of

high temperature liquids into

the sewer system.

Blowndown Heat Recovered, Million Btu per hour (MMBtu/hr)

Rate, Boiler Operating Pressure, psig

% Boiler Feedwater 50 100 150 250 300

2 0.45 0.5 0.55 0.65 0.65

4 0.9 1.0 1.1 1.3 1.3

6 1.3 1.5 1.7 1.9 2.0

8 1.7 2.0 2.2 2.6 2.7

10 2.2 2.5 2.8 3.2 3.3

20 4.4 5.0 5.6 6.4 6.6

Based on a steam production rate of 100,000 pounds per hour, 60°F makeup water, and 90% heat recovery.

◆ Suggested Actions ◆

If there is a continuous blowdown system in place, consider installing a heat recovery system. If there is a non-continuous blowdown 

system, then consider the option of converting it to a continuous blowdown system coupled with heat recovery. 

Appendix B: Steam Tip Sheet Number 10

Recoverable Heat from Boiler Blowdown
A Sourcebook for Industry 71

Use Vapor Recompression to Recover 

Low-Pressure Waste Steam

Low-pressure steam exhaust from industrial operations such as evaporators or

cookers is usually vented to the atmosphere or condensed in a cooling tower.

Simultaneously, other plant operations may require intermediate-pressure steam

at 20 to 50 pounds per square inch gauge (psig). Instead of letting down highpressure steam across a throttling valve to meet these needs, low-pressure waste

steam can be mechanically compressed or boosted to a higher pressure so that it

can be reused. 

Vapor recompression relies upon a mechanical compressor or steam jet ejector 

to increase the temperature of the latent heat in steam to render it usable for

process duties. Recompression typically requires only 5% to 10% of the energy

required to raise an equivalent amount of steam in a boiler.

◆ Example

Consider a petrochemical plant that vents 15-psig steam to the atmosphere. At

the same time, a process imposes a continuous requirement on the boiler for

5,000 lbs/hr of 40-psig steam. If 15-psig waste steam is recompressed to 40 psig

by an electrically driven compressor, the compression ratio is:

Compression Ratio = (40 + 14.7) / (15 + 14.7) = 1.84

From the table above, the compressor requires 63.5 Btu/lb of delivered steam.

Assuming that electricity is priced at $0.05/kWh, the annual cost of driving the

compressor is:

Compressor = 63.5 Btu/lb x 5,000 lbs/hr x 8,760 hrs/yr x $0.05/kWh / 3413 Btu/kWh 

Operating 

Cost = $40,745/year

If an equivalent quantity of 40-psig steam (enthalpy for saturated steam is 

1176 Btu/lb) were to be supplied by an 82% efficient natural-gas-fired boiler, 

the steam production costs with fuel priced at $4.50/MMBtu and 70°F feedwater

(enthalpy is 38 Btu/lb), are:

Steam = 5,000 lbs/year x (1176-38 Btu/lb) x 8,760 hrs/yr x $4.50/MMBtu / 0.82 

Production

Costs = $273,536/year

Annual Vapor Recompression Cost Savings = $273,536 - $40,745 = $232,791

Conduct a Pinch Analysis

Based on the actual application,

there may be other options 

to vapor recompression. The

industry best practice is to 

conduct a pinch analysis on

the steam system to reveal

cost-effective alternatives and

optimize steam use by eliminating inefficiencies. 

Vapor Recompression Limits

Vapor recompression is limited

to applications where the

compressor inlet pressure is

above atmospheric and the 

compression ratio is less than

two per stage.

System Pressure Boosting

Vapor recompression can be

used in steam distribution 

systems to boost system 

pressures that have dropped 

to unacceptably low levels.

Compressor Work, Btu/lb of Steam Produced

Inlet Compression Ratio

Pressure (psig) 1.2 1.4 1.6 1.8 2.0

0 17.8 33.2 46.8 58.8 69.6

15 18.6 34.7 48.7 61.2 72.6

Assuming adiabatic compression with a compressor efficiency of 75 percent. 80°F water is sprayed into the steam to 

eliminate superheat.

Energy Required for Steam Recompression

Appendix B: Steam Tip Sheet Number 11
72 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 11 (continued)

◆ Suggested Actions ◆

A vapor recompression project analysis consists of matching recovered waste heat with the need for low-pressure steam for process or

space heating. To perform this analysis:

• Conduct a plant audit to identify sources of low-pressure waste steam 

• Estimate the heat recovery potential 

• Inventory all steam-utilizing equipment and list pressure requirements, energy consumption, and patterns of use 

• Estimate the cost-effectiveness of installing recompression equipment and connecting piping.

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102001-1274 • May 2001 • Steam Tip Sheet #11
Flash High-Pressure Condensate to 

Regenerate Low-Pressure Steam

Low-pressure process steam requirements are usually met by throttling highpressure steam, but a portion of the process requirements can be achieved at low

cost by flashing high-pressure condensate. Flashing is particularly attractive when

it is not economically feasible to return the high-pressure condensate to the boiler.

In the table below, the quantity of steam obtained per pound of condensate

flashed is given as a function of both condensate and steam pressures.

◆ Example

In a plant where the cost of steam is $4.50 per million Btu (MMBtu), saturated

steam at 150 pounds per square inch gauge (psig) is generated, and a portion of

it throttled to supply 30-psig steam. Assuming continuous operation, determine

the annual energy savings of producing low-pressure steam by flashing 5,000

pounds per hour of 150-psig condensate. The average temperature of the boiler

make-up water is 70°F.

From the table above, when 150-psig condensate is flashed at 30 psig, 

10.3% of the condensate vaporizes. 

Low-Pressure Steam Produced = 5,000 lbs/hr x 0.103 = 515 lbs/hr

From the ASME Steam Tables, the enthalpy values are:

For 30-psig saturated steam = 1171.9 Btu/lb

For 70°F makeup water = 38.0 Btu/lb

Annual savings are obtained as follows:

Annual = 515 lb/hr x (1171.9–38.0) Btu/lb x 8,760 hours/year x $4.50/MMBtu 

Savings = $23,019

High Pressure Percent of Condensate Flashed, lb Steam/lb Condensate

Condensate Low-Pressure Steam (psig)

(psig) 50 30 15 5

200 10.4 12.8 15.2 17.3

150 7.8 10.3 12.7 14.9

100 4.6 7.1 9.6 11.8

75 2.5 5.1 7.6 9.9

Proximity Is a Plus

The source of high-pressure

condensate should be relatively close to the low-pressure

steam header to minimize 

piping and insulation costs. 

Match Availability and Use

The economics of heat 

recovery projects are most

favorable when the waste

steam heat content is high 

and the flow is continuous.

Seasonal space heating is not

the most desirable end use. 

A Sourcebook for Industry 73

Appendix B: Steam Tip Sheet Number 12

◆ Suggested Actions ◆

Determine the potential for high-pressure condensate flashing by completing a plant survey that:

• Identifies all sources of high-pressure condensate 

• Determines condensate flow and duration, as well as the heat recovery potential due to flashed steam production 

• Identifies compatible uses for low-pressure steam

• Estimates the cost effectiveness of installing appropriate heat-recovery devices and interconnecting piping.

High-Pressure Condensate Flashing
74 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 12 (continued)

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102001-1275 • May 2001 • Steam Tip Sheet #12
A Sourcebook for Industry 75

Appendix B: Steam Tip Sheet Number 13

Use a Vent Condenser to Recover 

Flash Steam Energy

When the pressure of saturated condensate is reduced, a portion of the liquid

“flashes” to low-pressure steam. Depending on the pressures involved, the flash

steam contains approximately 10% to 40% of the energy content of the original

condensate. In most cases, including condensate receivers and deaerators, the

flashing steam is vented and its energy content lost. However, a heat exchanger

can be placed in the vent to recover this energy. The following table indicates

the energy content of flash steam at atmospheric pressure.

◆ Example

Consider a vent pipe with the following conditions:

Velocity of flash steam: 300 feet per minute

Diameter of vent pipe: 4 inches

Hours of operation: 8,000 hours per year

Boiler efficiency: 82%

Cost of fuel: $4.50 per million Btu (MMBtu)

A vent condenser could condense the flashed steam, transfer its thermal energy

to incoming make-up water, and then return it to the boiler. Energy is recovered

in two forms: hotter make-up water and clean, distilled condensate ready for 

productive use in your operation. 

Referring to the table above, the potential energy recovered from the flashed

steam is 555 MMBtu, based on 8,760 hours of annual operation. Correct this

value for actual operating hours and boiler efficiency:

Annual Energy = 555 MMBtu/year x 8,000 hrs/yr / 8,760 hrs/yr x 1 / 0.82 

Recovered = 618 MMBtu

Annual Potential = 618 MMBtu/yr x $4.50/MMBtu 

Fuel Cost Savings = $2,781**

** Note that the annual fuel savings are per vent. Often, there are several such vents in a

steam facility, and the total savings can be a significantly larger number. The additional

heat exchanger cost still needs to be considered, but available literature shows a quick 

payback for the measure.

Distilled Water Recovery

A useful rule of thumb is that

every 500 lbs/hr of recovered

flash steam provides 1 gallon

per minute (gpm) of distilled

water.

Materials Considerations

Depending on the specific

application, the vent condenser

materials can be either all

stainless or mild steel shell with

copper tubes. For deaerator

vent condensing, a stainless

steel heat exchanger is recommended to avoid corrosion due

to the high concentrations of

gases. Mild steel can be used for

receiver tank vent condensing.

Pipe Energy Content. MMBtu/year*

Diameter Steam Velocity, feet/min

(inches) 200 300 400 500 600

2 90 140 185 230 280

4 370 555 740 925 1,110

6 835 1,250 1,665 2,085 2,500

10 2,315 3,470 4,630 5,875 6,945

* Assumes continuous operation, 70°F make-up water, and condensed steam at 100°F.

Energy Recovery Potential of a Vent Condenser
76 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 13 (continued)

◆ Suggested Actions ◆

• Inspect vent pipes of receiver tanks and deaerators for excessive flash steam plumes

• Re-examine deaerator steam requirements 

• Eliminate remaining flash steam energy loss with a vent condenser 

• Consult manufacturers for materials specifications, as well as size and cost recommendations for the vent condenser.

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102001-1276 • May 2001 • Steam Tip Sheet #13
Use Low-Grade Waste Steam to Power

Absorption Chillers

Absorption chillers use heat, instead of mechanical energy, to provide cooling.

The mechanical vapor compressor is replaced by a thermal compressor (see figure)

that consists of an absorber, a generator, a pump, and a throttling device. The

refrigerant vapor from the evaporator is absorbed by a solution mixture in the

absorber. This solution is then pumped to the generator where the refrigerant is

revaporized using a waste steam heat source. The refrigerant-depleted solution is

then returned to the absorber via a throttling device. The two most common

refrigerant/absorbent mixtures used in absorption chillers are water/lithium 

bromide and ammonia/water.

Compared to mechanical chillers, absorption chillers have a low coefficient of 

performance (COP = chiller load/heat input). Nonetheless, they can substantially

reduce operating costs because they are energized by low-grade waste heat, while

vapor compression chillers must be motor- or engine-driven. 

Low-pressure, steam-driven absorption chillers are available in capacities ranging

from 100 to 1,500 tons. Absorption chillers come in two commercially available

designs: single-effect and double-effect. Single-effect machines provide a thermal

COP of 0.7 and require about 18 pounds of 15-psig steam per ton-hour of cooling.

Double-effect machines are about 40% more efficient, but require a higher grade

of thermal input, using about 10 pounds of 100- to 150-psig steam per ton-hour.

◆ Example

In a plant where low-pressure steam is currently being exhausted to the atmosphere, a mechanical chiller with a COP of 4.0 is used 4,000 hours per year to 

produce an average of 300 tons of refrigeration. The cost of electricity at the 

plant is $0.05 per kilowatt-hour. 

Reduce Demand Charges

Absorption chillers can reshape

facility thermal and electric

load profiles by shifting cooling from an electric to a 

thermal load. If you are served

by an electric utility with a

ratcheted demand charge, you

may be able to reduce demand

charges throughout the year

by reducing your summer

peak loads.

Utility Incentives 

Some gas utilities offer reduced

rates during the summer. In

some areas, electric utilities

provide rebates or incentives

to replace mechanical chillers

with steam absorption units.

A Sourcebook for Industry 77

Appendix B: Steam Tip Sheet Number 14

* The evaporator and the condenser, required for both systems, are not shown in the figure.

Mechanical

Vapor Compression

Thermal

Vapor Compression

Electric/

EngineDriven

Compressor

High Pressure

Low Pressure

Waste Heat from Process

or Low-Pressure Steam

Pump Throttle

Valve

Rejected Heat

Refrigerant

Vapor to

Condenser

Refrigerant

Vapor from

Evaporator

Refrigerant

Vapor to

Condenser

Refrigerant

Vapor from

Evaporator

Generator

Absorber

Comparison of Mechanical and Thermal Vapor Compression Systems*
78 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 14 (continued)

An absorption unit requiring 5,400 lbs/hr of 15-psig steam could replace the mechanical chiller, providing

annual electrical cost savings of:

Annual = 300 tons x (12,000 Btu/ton / 4.0) x 4,000 hrs/year x $0.05/kWh x kWh/3,413 Btu

Savings = $52,740

◆ Suggested Actions ◆

Determine the cost-effectiveness of displacing a portion of your cooling load with a waste steam absorption chiller by taking the following

steps: 

• Conduct a plant survey to identify sources and availability of waste steam 

• Determine cooling load requirements and the cost of meeting those requirements with existing mechanical chillers or new installations 

• Obtain installed cost quotes for a waste steam absorption chiller 

• Conduct a life cycle cost analysis to determine if the waste steam absorption chiller meets your company’s cost-effectiveness criteria.

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102001-1277 • May 2001 • Steam Tip Sheet #14
Benchmark the Fuel Cost of Steam Generation

Benchmarking the fuel cost of steam generation ($/1000 lbs of steam) is an 

effective way to assess the efficiency of your steam system. This cost is dependent upon fuel type, unit fuel cost, boiler efficiency, feedwater temperature, and

steam pressure. This calculation provides a good first approximation for the 

cost of generating steam and serves as a tracking device to allow for boiler 

performance monitoring. Table 1 shows the heat input required to produce one

pound of saturated steam at different operating pressures and varying feedwater

temperatures. Table 2 lists the typical energy content and boiler combustion 

efficiency for several common fuels.

Data from the above tables can be used to determine the cost of usable heat from

a boiler or other combustion unit. The calculations can also include operating

costs of accessories such as feedwater pumps, fans, fuel heaters, steam for fuel

atomizers and soot blowing, treatment chemicals, and environmental and 

maintenance costs.

◆ Example

A boiler, fired with natural gas costing $0.30/therm, produces 450 psig saturated

steam and is supplied with 230°F feedwater. Using values from the tables, calculate the cost of producing steam.

Steam Cost = 0.3 ($/therm) x 1000 x 1006 (Btu/lb) x 100 = $3.69/1000 lbs 100,000 (Btu/therm) 81.7

Effective Cost of Steam

The effective cost of steam

depends on the path it follows

from the boiler to the point of

use. Take a systems approach 

and consider the entire boiler

island, including effect of

blowdown, parasitic steam

consumption, deaeration, etc.

Further complications arise

due to the process steam loads

at different pressures, multiple

boilers, and waste heat recovery systems. To determine the

effective cost of steam, use a

combined heat and power

simulation model that includes

all the significant effects.

Multi-Fuel Capability

For multi-fuel capability boilers,

take advantage of volatility 

in fuel prices by periodically 

analyzing the steam generation cost and use the fuel that

provides the lowest steam 

generation cost.

Higher Versus Lower 

Heating Values

Fuel is sold based on its gross

or higher heating value

(HHV). If, at the end of the

combustion process, water

remains in the form of vapor,

the HHV must be reduced by

the latent heat of vaporization

of water. This reduced value is

known as the lower heating

value (LHV). 

Operating Feedwater Temperature, °F

Pressure, psig 50 100 150 200 250

150 1,178 1,128 1,078 1,028 977

450 1,187 1,137 1,087 1,037 986

600 1,184 1,134 1,084 1,034 984

* Calculated from steam tables based on the difference between the enthalpies of saturated steam and feedwater.

Table 1. Energy Required to Produce One Pound of Saturated Steam (Btu)*

A Sourcebook for Industry 79

Appendix B: Steam Tip Sheet Number 15

Fuel Type Energy Content Combustion

(sales unit) (Btu/sales unit) Efficiency (%)

Natural Gas (therm) 100,000 81.7

Natural Gas (cubic foot) 1,030 81.7

Distillate/No. 2 Oil (gallon) 138,700 84.6

Residual/No. 6 Oil (gallon) 149,700 86.1

Coal (ton) 27,000,000 87.6

Note: Combustion efficiency is based on boilers equipped with economizers and air preheaters and 3% oxygen in flue gas. 

Table 2. Energy Content and Combustion Efficiency of Fuels
80 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 15 (continued)

Steam Tip Sheet information is reviewed by the DOE BestPractices Steam Technical Subcommittee. For additional information 

on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102000-1115 • December 2000 • Steam Tip Sheet #15

◆ Suggested Actions ◆

• Determine your annual fuel costs based on utility bills.

• Install a steam flowmeter in your facility and calculate your steam generation cost. Compare this with the benchmark value.

• Using a systems approach, do a thermoeconomic analysis to determine the effective cost of steam. (See sidebar: Effective Cost 

of Steam)
Minimize Boiler Short Cycling Losses

Boiler "short cycling" occurs when an oversized boiler quickly satisfies process or

space heating demands, and then shuts down until heat is again required. Process

heating demands can change over time. Boilers may have been oversized for

additions or expansions that never occurred. Installing energy conservation or heat

recovery measures may also reduce the heat demand. As a result, a facility may

have multiple boilers, each rated at several times the maximum expected load. 

Boilers used for space heating loads are often oversized, with their capacity chosen to meet total building heat losses plus heating of ventilation and infiltration

air under extreme or design-basis temperature conditions. No credit is taken for

thermal contributions from lights, equipment, or people. Excess capacity is also

added to bring a facility to required settings quickly after a night setback.

◆ Cycling Losses

A boiler cycle consists of a firing interval, a post-purge, an idle period, a pre-purge,

and a return to firing. Boiler efficiency is the useful heat provided by the boiler

divided by the energy input (useful heat plus losses) over the cycle duration. 

This efficiency decreases when short cycling occurs or when multiple boilers are

operated at low-firing rates. 

This decrease in efficiency occurs, in part, because fixed losses are magnified

under lightly loaded conditions. For example, if the radiation loss from the 

boiler enclosure is 1% of the total heat input at full-load, at half-load the losses

increase to 2%, while at one-quarter load the loss is 4%. In addition to radiation

losses, pre- and post-purge losses occur. In the pre-purge, the fan operates to

force air through the boiler to flush out any combustible gas mixture that may

have accumulated. The post-purge performs a similar function. During purging,

heat is removed from the boiler as the purged air is heated. 

◆ Example

A 1,500 hp (1 hp = 33,475 Btu/hr) boiler with a cycle efficiency of 72.7% (E1) 

is replaced with a 600 hp boiler with a cycle efficiency of 78.8% (E2). Calculate

the annual cost savings.

Fractional Fuel Savings = (1 – E1/E2)

= (1 – 72.7/78.8) x 100 = 7.7%

If the original boiler used 200,000 MMBtu of fuel annually, the savings from

switching to the smaller boiler (given a fuel cost of $3.00/MMBtu) are:

Annual Savings = 200,000 MMBtu x 0.077 x $3.00/MMBtu = $46,200

Multiple Boiler Operations

The most efficient boilers should

be brought on-line as loads

increase, with less-efficient units

taken off-line first as loads drop.

Subject to emissions, operations,

or firing rate limits, shift loads

from a boiler where steam production is expensive to one

where it is less expensive.

Use automatic controllers that

determine the incremental

costs (change in steam cost/

change in load) for each boiler

in the facility, and then shift

loads accordingly. This maximizes efficiency and reduces

energy costs. If possible, schedule

loads to help optimize boiler system performance. Powerhouses

containing multiple boilers

that are simultaneously operated at low-fire conditions offer

energy-saving opportunities by

using proper boiler allocation

strategies.

Boiler Downsizing

Fuel savings can be achieved 

by adding a smaller boiler sized

to meet average loads at your

facility, or by re-engineering

the power plant to consist of

multiple small boilers. Multiple

small boilers offer reliability

and flexibility to operators to

follow load swings without

over-firing and short cycling.

Facilities with large seasonal

variations in steam use operate

small boilers when demand

drops rather than operating

their large boilers year-round.

A Sourcebook for Industry 81

Appendix B: Steam Tip Sheet Number 16

Steam Tip Sheet information is reviewed by the DOE BestPractices Steam Technical Subcommittee. For additional information 

on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102000-1116 • December 2000 • Steam Tip Sheet #16

◆ Suggested Actions ◆

• Determine the efficiency and operating cost of each of your boilers and adopt a control strategy for maximizing overall efficiency of

multiple boiler operations. (See sidebar)

• Avoid short cycling by adding small boilers to your boiler facility to provide better flexibility and high efficiency at all loads. (See 

sidebar: Boiler Downsizing)
82 Improving Steam System Performance
Install Removable Insulation on 

Valves and Fittings

During maintenance, the insulation that covers pipes, valves, and fittings is

often damaged or removed and not replaced. Pipes, valves, and fittings that are

not insulated can be safety hazards and sources of heat loss. Removable and

reusable insulating pads are available to cover almost any surface. The pads are

made of a noncombustible inside cover, insulation material, and a noncombustible outside cover that resists tears and abrasion. Material used in the pads

resists oil and water and has been designed for temperatures of up to 1600°F.

Wire laced through grommets or straps with buckles hold the pads in place.

◆ Applications

Reusable insulating pads are commonly used in industrial facilities for insulating

flanges, valves, expansion joints, heat exchangers, pumps, turbines, tanks, and

other irregular surfaces. The pads are flexible and vibration resistant and can be

used with equipment that is horizontally or vertically mounted or that is difficult

to access. Any high-temperature piping or equipment should be insulated to

reduce heat loss, reduce emissions, and improve safety. As a general rule, any 

surface that reaches temperatures greater than 120°F should be insulated to protect personnel. Insulating pads can be easily removed for periodic inspection or

maintenance, and replaced as needed. Insulating pads can also contain built-in

acoustical barriers to help control noise.

◆ Energy Savings

The table below summarizes energy savings due to the use of insulating valve

covers for a range of valve sizes and operating temperatures. These values were

calculated using a computer program that meets the requirements of ASTM C

680—Heat Loss and Surface Temperature Calculations. The energy savings is defined

as the difference in heat loss between the uninsulated valve and the insulated

valve operating at the same temperature.

◆ Example

Using the table above, calculate the annual fuel and dollar savings from 

installing a 1-inch thick insulating pad on an uninsulated 6-inch gate valve 

in a 250 pounds per square inch gauge (psig) saturated steam line (406°F). 

Assume continuous operation with natural gas at a boiler efficiency of 80% 

and a fuel price of $4.50 per million British thermal units (MMBtu). 

Availability

Insulation supply companies

are located regionally; this

expedites delivery and helps

meet site-specific job requirements. Most supply companies

can take measurements on-site

to ensure the best fit on irregular surfaces. For customized

applications, manufacturers

can provide instructions

regarding the installation and

removal of insulating pads.

Noise Control Benefits 

Specify insulating pads that 

contain built-in barriers for

noise control.

Insulation for Steam Traps 

Effectively insulate inverted 

bucket traps with removable

and reusable snap-on insulation. Thermostatic traps and

disk traps should be insulated

according to manufacturers’

specifications to ensure proper

operation. 

Before removal of all or any 

existing insulation material,

check for asbestos in accordance with OSHA regulations.

A Sourcebook for Industry 83

Appendix B: Steam Tip Sheet Number 17

Operating Valve Size (inches)

Temperature, °F 3 4 6 8 10 12

200 800 1,090 1,560 2,200 2,900 3,300

300 1,710 2,300 3,300 4,800 6,200 7,200

400 2,900 3,400 5,800 8,300 10,800 12,500

500 4,500 6,200 9,000 13,000 16,900 19,700

600 6,700 9,100 13,300 19,200 25,200 29,300

a Based on installation of a 1-inch thick insulating pad on an ANSI 150-pound class flanged valve with an ambient 

temperature of 65°F and zero wind speed.

Energy Savingsa from Installing Removable Insulated Valve Covers (Btu/hour)
84 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 17 (continued)

Results:

Annual Fuel Savings = 5,992 Btu/hr x 8,760 hours/year x 1/0.80 

= 65.6 MMBtu/year

Annual Dollar Savings = 65.6 MMBtu/year x $4.50/MMBtu 

= $295 per 6-inch gate valve

Steam Tip Sheet information is adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices

Steam Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102004-1802 • April 2004 • Steam Tip Sheet #17

◆ Suggested Actions ◆

• Conduct a survey of your steam distribution system to identify locations where removable and reusable insulation covers can be used

• Use removable insulation on components requiring periodic inspections or repair.
A Sourcebook for Industry 85

Deaerators in Industrial Steam Systems

Deaerators are mechanical devices that remove dissolved gases from boiler feedwater. Deaeration protects the steam system from the effects of corrosive gases. 

It accomplishes this by reducing the concentration of dissolved oxygen and carbon

dioxide to a level where corrosion is minimized. A dissolved oxygen level of 

5 parts per billion (ppb) or lower is needed to prevent corrosion in most high

pressure (>200 psig) boilers. While oxygen concentrations of up to 43 ppb may

be tolerated in low pressure boilers, equipment life is extended at little or no cost

by limiting the oxygen concentration to 5 ppb. Dissolved carbon dioxide is

essentially completely removed by the deaerator. 

◆ How They Work

The design of an effective deaeration system depends upon the amount of gases

to be removed and the final gas (O2) concentration desired. This in turn depends

upon the ratio of boiler feedwater makeup to returned condensate and the operating pressure of the deaerator.

Deaerators use steam to heat the water to the full saturation temperature corresponding to the steam pressure in the deaerator and to scrub out and carry away

dissolved gases. Steam flow may be parallel, cross, or counter to the water flow.

The deaerator consists of a deaeration section, a storage tank, and a vent. In the

deaeration section, steam bubbles through the water, both heating and agitating

it. Steam is cooled by incoming water and condensed at the vent condenser.

Non-condensable gases and some steam are released through the vent.

Steam provided to the deaerator provides physical stripping action and heats the

mixture of returned condensate and boiler feedwater makeup to saturation temperature. Most of the steam will condense, but a small fraction (usually 5 to

14%) must be vented to accommodate the stripping requirements. Normal

design practice is to calculate the steam required for heating, and then make sure

that the flow is sufficient for stripping as well. If the condensate return rate is

high (>80%) and the condensate pressure is high compared to the deaerator pressure, then very little steam is needed for heating, and provisions may be made

for condensing the surplus flash steam.

◆ Deaerator Steam Consumption

The deaerator steam consumption is equal to the steam required to heat incoming water to its saturation temperature, plus the amount vented with the noncondensable gases, less any flashed steam from hot condensate or steam losses

through failed traps. The heat balance calculation is made with the incoming

water at its lowest expected temperature. The vent rate is a function of deaerator

type, size (rated feedwater capacity), and the amount of makeup water. The operating vent rate is at its maximum with the introduction of cold, oxygen-rich

makeup water.

Additional Benefits

Deaerators provide the water

storage capacity and the net

positive suction head necessary at the boiler feed pump

inlet. Returned condensate is

mixed with makeup water

within the deaerator. Operating temperatures range from

215°F to over 350°F, which

reduces the thermal shock on

downstream preheating equipment and the boiler.

Insulation

The deaerator section and 

storage tank and all piping

conveying hot water or steam

should be adequately insulated

to prevent the condensation 

of steam and loss of heat.

Function Clarification

The deaerator is designed to

remove oxygen that is dissolved in the entering water,

not entrained air. Sources of

“free air” include loose piping

connections on the suction

side of pumps and improper

pump packing.

Pressure Fluctuations

Sudden increases in free or 

“flash” steam can cause a 

spike in deaerator vessel pressure, resulting in re-oxgenation

of the feedwater. A dedicated

pressure-regulating valve should

be provided to maintain the

deaerator at a constant pressure.

Steam Tip Sheet information is reviewed by the DOE BestPractices Steam Technical Subcommittee. For additional information 

on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102000-1118 • December 2000 • Steam Tip Sheet #18

◆ Suggested Actions ◆

• Deaerator steam requirements should be re-examined following the retrofit of steam distribution system, condensate return, or heat

recovery energy conservation measures.

• Install continuous dissolved oxygen monitoring devices to aid in identifying operating practices that result in poor oxygen removal.

Appendix B: Steam Tip Sheet Number 18
Cover Heated, Open Vessels

Open vessels that contain heated liquids often have a high heat loss due to surface

evaporation. Both energy and liquid losses are reduced by covering open vessels

with insulated lids. Table 1 provides an estimate of the evaporative heat loss per

square foot of uncovered vessel surface area for various water and dry ambient air

temperatures. It is assumed that the ambient air is dry with no wind currents. A

fan pulling air over the uncovered tank could more than double the heat losses.

◆ Example

A rinse tank is four feet wide and ten feet long. It is maintained at a constant 

temperature of 170° F. Determine the evaporative heat loss from the tank if the 

ambient temperature is 75° F. 

Area of Evaporating Surface = 4 ft x 10 ft = 40 ft2

Total Heat Loss for

Uncovered Liquid Surface = 1,566 Btu/hr-ft2 x 40 ft2 = 62,640 Btu/hr

◆ Cover the Tank with an Insulated Top

Assume that the rinse tank is heated during two shifts per day, five days per

week, and 50 weeks per year. What are the annual energy savings that may be

attained by covering the tank? What is the heating cost reduction in a plant

where the cost of steam is $6.50/MMBtu? Assume that covering the rinse tank

with an insulated lid effectively reduces the heat losses from the liquid surface to

a negligible value.

Annual Energy Savings = 62,640 Btu/hr x 2 shifts/day x 8 hrs/shift x 250 days/yr

= 250 MMBtu/yr

Heating Cost Reduction = 250 MMBtu/yr x $6.50/MMBtu = $ 1,625/yr

86 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 19

Heat Loss Detail

• Eliminating internal heat

gains will also result in 

electrical energy savings if

the open tanks are located

within a conditioned space. 

• Heat losses are a strong function of both wind velocity

and ambient air humidity. 

A wind velocity of 3 miles

per hour will more than

double the rate of heat loss

from a tank. 

• Radiation heat transfer is a 

secondary source of tank 

surface heat losses. Radiation

losses increase from 

90 Btu/hr-ft2 at a liquid 

temperature of 110° F to 

290 Btu/hr-ft2 at 190° F.

Steam Tip Sheet information adapted from information provided by the Industrial Energy Extension Service of Georgia Tech and is reviewed by the DOE BestPractices Steam

Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102002-1477 • January 2002 • Steam Tip Sheet #19

◆ Suggested Actions ◆

• Conduct a survey to determine the number of open vessels that contain heated liquid within your plant. For each tank, determine the

operating schedule, liquid temperature, ambient temperature, and the square feet of exposed area.

• Estimate the annual heat loss from the uncovered tanks and determine the potential annual fuel cost savings.

• Evaporation and heat losses can be reduced by lowering the liquid temperature, reducing the exposed liquid area, minimizing flow of

air over the tank, or by installing an insulated cover.

• Obtain cost quotations for insulated covers. Install covers when they are economically justified.

Note:Table 1 is extracted from “Steam Efficiency Improvement” by the Boiler Efficiency Institute at Auburn University

Liquid Ambient Air Temperature, °F

Temperature, °F 65 75 85 95 105

110 244 222 200 177 152

130 479 452 425 397 369

150 889 856 822 788 754

170 1,608 1,566 1,524 1,482 1,440

190 2,900 2,845 2,790 2,737 2,684

Table 1. Evaporative Heat Loss from Water in Open Tanks, Btu/hr-ft2
Replace Pressure-Reducing Valves 

with Backpressure Turbogenerators

Many industrial facilities produce steam at a higher pressure than is demanded

by process requirements. Steam passes through pressure-reducing valves (PRVs,

also known as letdown valves) at various locations in the steam distribution 

system to let down or reduce its pressure. A non-condensing or backpressure

steam turbine can perform the same pressure-reducing function as a PRV, while

converting steam energy into electrical energy.

In a backpressure steam turbogenerator, shaft power is produced when a nozzle

directs jets of high-pressure steam against the blades of the turbine’s rotor. The

rotor is attached to a shaft that is coupled to an electrical generator. The steam

turbine does not consume steam. It simply reduces the pressure of the steam 

that is subsequently exhausted into the process header.

◆ Cost-Effective Power Generation

In a conventional, power-only steam turbine installation, designers increase 

efficiency by maximizing the pressure drop across the turbine. Modern Rankinecycle power plants with 1,800 psig superheated steam boilers and condensing

turbines exhausting at near-vacuum pressures can generate electricity with 

efficiencies of approximately 40%.

Most steam users do not have the benefit of ultra-high-pressure boilers and cannot achieve such high levels of generation efficiency. However, by replacing a

PRV with a backpressure steam turbine, where the exhaust steam is provided to a

plant process, energy in the inlet steam can be effectively removed and converted into electricity. This means the exhaust steam has a lower temperature than it

would have if its pressure was reduced through a PRV. In order to make up for

this heat loss, steam plants with backpressure turbine installations increase their

boiler steam throughput.

Thermodynamically, the steam turbine still behaves the same way as it would in 

a conventional Rankine power cycle, achieving isentropic efficiencies of 20% to 

70%. Economically, however, the turbine generates power at the efficiency of your

steam boiler (modern steam boilers operate at approximately 80% efficiency),

which then must be replaced with an equivalent kWh of heat for downstream

purposes. The resulting power generation efficiencies are well in excess of the

average U.S. electricity grid generating efficiency of 33%. Greater efficiency means

less fuel consumption; backpressure turbines can produce power at costs that are

often less than 3 cents/kWh. Energy savings are often sufficient to completely

recover the cost of the initial capital outlay in less than 2 years.

◆ Applicability

Packaged or “off-the-shelf” backpressure turbogenerators are now available in 

ratings as low as 50 kW. Backpressure turbogenerators should be considered 

when a PRV has constant steam flows of at least 3,000 lbs/hr, and when the 

steam pressure drop is at least 100 psi. The backpressure turbine is generally

installed in parallel with the PRV. 

◆ Estimating Your Savings

To make a preliminary estimate of the cost of producing electrical energy from a

back-pressure steam turbine, divide your boiler fuel cost (in $/MMBtu) by your

boiler efficiency. Then convert the resulting number into cost per kWh, as shown

Life and Cost of Backpressure

Turbogenerators

Turbogenerators with electrical

switchgear cost about $700/kW

for a 50 kW system to less

than $200/kW for a 2,000 kW

system. Installation cost 

varies, but typically averages

75% of equipment costs.

Backpressure steam turbines

are designed for a 20-year 

minimum service life and 

are known for needing low

maintenance.

A Sourcebook for Industry 87

Appendix B: Steam Tip Sheet Number 20
88 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 20 (continued)

in the sample calculation.

Electricity cost = Fuel cost ($/MMBtu) x 0.003412 MMBtu/kWh

Boiler efficiency

Example: $5.00/MMBtu x 0.003412 MMBtu/kWh = $0.021/kWh 0.80 

To estimate the potential power output at a PRV, refer to Figure 1, which shows lines of constant power output

(expressed in kW of electrical output per 1,000 pounds per hour of steam throughput) as a function of turbine

inlet and exhaust pressures. Look up your input and output pressure on the horizontal and vertical axes, and

then use the reference lines to estimate the backpressure turbogenerator power output per Mlb-hour of steam

flow. Then estimate the total installed generating capacity (kW) by multiplying this number by your known

steam flow rate. The annual cost savings from the backpressure turbine can then be estimated as:

Power output (kW) x Steam duty (hrs/year) x (Cost of grid power – Cost of generated power, $/kWh)

◆ Suggested Actions ◆

Consider replacing PRVs with backpressure turbogenerators when purchasing new boilers or if your boiler operates at a pressure of 

150 psig or greater.

• Develop a current steam balance and actual process pressure requirements for your plant

• Develop steam flow/duration curves for each PRV station

• Determine plant electricity, fuel cost, and operating voltage

• Consider either one centralized turbogenerator, or multiple turbogenerators at PRV stations.

Steam Tip Sheet information is adapted from material provided by the TurboSteam Corporation and is reviewed by the DOE BestPractices Steam Technical Subcommittee.

For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102002-1476 • January 2002 • Steam Tip Sheet #20

Note: Assumes a 50% isentropic turbine efficiency, a 96% efficient generator, and dry saturated inlet steam

300

250

200

150

100

50

0

100 200 300 400 500 600 700 800

 10 kW/Mlb-hour

 18 kW/Mlb-hour

25 kW/Mlb-hour

Input Pressure (psig)

Exhaust Pressure (psig)

Figure 1. Backpressure Turbogenerator Generating Potential (kW/Mlb-hour)
Consider Steam Turbine Drives 

for Rotating Equipment

Steam turbines are well suited as prime movers for driving boiler feedwater pumps,

forced or induced-draft fans, blowers, air compressors, and other rotating equipment. This service generally calls for a backpressure non-condensing steam turbine. The low-pressure steam turbine exhaust is available for feedwater heating,

preheating of deaerator makeup water, and/or process requirements. 

Steam turbine drives are equipped with throttling valves or nozzle governors to 

modulate steam flow and achieve variable speed operation. The steam turbine drive

is thus capable of serving the same function as an induction motor coupled to an

inverter or adjustable speed drive. Steam turbine drives can operate over a broad

speed range and do not fail when overloaded. They also exhibit the high starting

torque required for constant torque loads such as positive displacement pumps. 

Steam turbines are inherently rugged and reliable low-maintenance devices. They

are easy to control and offer enclosed, non-sparking operation suitable for use 

in explosive atmospheres or highly corrosive environments. Steam turbines 

provide fast, reliable starting capability and are particularly adaptable for direct

connection to equipment that rotates at high speeds. Steam turbine drives may

be installed for continuous duty under severe operating conditions, or used for

load shaping (e.g. demand limiting), standby, or emergency service.

Steam turbine performance is expressed in terms of isentropic efficiency or steam

rate (the steam requirement of the turbine per unit of shaft power produced).

Steam rates are given in terms of pounds per horsepower-hour (lb/hp-hour) or

lb/kWh.

◆ Example

A 300-hp steam turbine has an isentropic efficiency of 43% and a steam rate of

26 lb/hp-hour given the introduction of 600 psig/750°F steam with a 40

psig/486°F exhaust. What steam flow is necessary to replace a fully-loaded 300-

hp feedwater pump drive motor?

Steam flow = 26 lb/hp-hr x 300 hp = 7,800 lb/hr

An examination of the ASME steam tables reveals that this steam turbine would

utilize 103 Btu/lb of steam or 0.80 MMBtu of thermal energy per hour. Given a

natural gas cost of $5.00/MMBtu and a boiler efficiency of 80%, the fuel-related

cost of steam turbine operation is (0.80 MMBtu/hr/0.80 x $5.00/MMBtu) = $5.00/hr.

In comparison, a 300-hp motor with a full-load efficiency of 95% would require:

300 hp x (0.746 kW/hp) = 235.6 kWh/hr 0.95

In this example, the steam turbine drive would provide energy cost savings when

the price of electricity exceeds: 

$5.00/hr x 100 cents/$ = 2.12 cents/kWh 235.6 kWh/hr

The total annual energy savings are strongly dependent upon the facility energy

Steam Turbine Flexibility

Equipment redundancy and

improved reliability can be

obtained by mounting a steam 

turbine drive and an electric

motor on opposite ends of 

the driven-equipment shaft.

You can then select either 

the motor or turbine as the

prime mover by increasing or

decreasing the turbine speed 

relative to the synchronous

speed of the motor.

A Sourcebook for Industry 89

Appendix B: Steam Tip Sheet Number 21
90 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 21 (continued)

cost and the hours per year of feedwater pump operation. Annual energy savings are given in Table 1 for 

various electrical rates and pump operating schedules. In addition to operating cost savings, steam turbine

maintenance costs should be compared with electric motor maintenance expenses.

◆ Suggested Actions ◆

Consider replacing electric motors with steam turbine drives if your facility:

• Contains a high-pressure boiler or a boiler designed to operate at a higher pressure than process requirements

• Has time-of-use (e.g., on/off peak, real-time, etc.) energy purchase and resale contracts with periods when electric power costs are

substantially higher than fuel costs

• Has pumps or other rotating equipment requiring variable speed operation

• Requires continued equipment operation during electrical power supply interruptions.

Steam Tip Sheet information is adapted from material provided by the TurboSteam Corporation and is reviewed by the DOE BestPractices Steam Technical Subcommittee.

For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102002-1475 • January 2002 • Steam Tip Sheet #21

1 Savings are based upon operation of a 300-hp steam turbine drive with a steam rate of 26 lbs/hp-hr. 

A natural gas cost of $5.00/MMBtu is assumed.

Electricity Feedwater Pump Annual Operating Hours

Costs, $/kWh 2,000 4,000 6,000 7,000 8,760

0.03 $4,105 $8,210 $12,310 $14,365 $17,975

0.05 $13,525 $27,050 $40,570 $47,330 $59,230

0.075 $25,305 $50,605 $75,910 $88,560 $110,830

Table 1. Annual Energy Savings When Using a Steam Turbine Feedwater Pump Drive1
A Sourcebook for Industry 91

Consider Installing High-Pressure Boilers

with Backpressure Turbine-Generators

When specifying a new boiler, consider a high-pressure boiler with a backpressure

steam turbine-generator placed between the boiler and the steam distribution

network. A turbine-generator can often produce enough electricity to justify the

capital cost of purchasing the higher-pressure boiler and the turbine-generator.

Since boiler fuel usage per unit of steam production increases with boiler pressure, facilities often install boilers that produce steam at the lowest pressure consistent with end use and distribution requirements. 

In the backpressure turbine configuration, the turbine does not consume steam.

Instead, it simply reduces the pressure and energy content of steam that is subsequently exhausted into the process header. In essence, the turbo-generator

serves the same steam function as a pressure-reducing valve (PRV)—it reduces

steam pressure—but uses the pressure drop to produce highly valued electricity

in addition to the low-pressure steam. Shaft power is produced when a nozzle

directs jets of high-pressure steam against the blades of the turbine’s rotor. The

rotor is attached to a shaft that is coupled to an electrical generator. 

◆ Cost Effective Power Generation

In a backpressure steam turbine, energy from high-pressure inlet steam is efficiently converted into electricity and low-pressure exhaust steam is provided to a

plant process. The turbine exhaust steam has a lower temperature than the

superheated steam created when pressure is reduced through a PRV. In order to

make up for this heat or enthalpy loss and meet process energy requirements,

steam plants with backpressure turbine installations must increase their boiler

steam throughput (typically by 5%-7%). Every Btu that is recovered as highvalue electricity is replaced with an equivalent Btu of heat for downstream

processes.

Thermodynamically, steam turbines achieve an isentropic efficiency of 20%-70%.

Economically, however, the turbine generates power at the efficiency of the

steam boiler. The resulting power generation efficiency (modern steam boilers

operate at approximately 80% efficiency) is well in excess of the efficiency for

state-of-the-art single or combined cycle gas turbines. High efficiency means low

electricity generating costs. Backpressure turbines can produce electrical energy

at costs that are often less than 3 cents/kWh. The electricity savings alone—not

to mention ancillary benefits from enhanced on-site electricity reliability and

reduced emissions of CO2 and criteria pollutants—are often sufficient to completely recover the cost of the initial capital outlay in less than 2 years.

◆ Estimating Your Savings

Since you have already determined that you need a boiler to satisfy your process

thermal loads, the marginal cost of power produced from the backpressure turbine-generator is:

Cost of power production = (Annual boiler fuel cost after pressure increase

– Annual boiler fuel cost before pressure increase) / Annual kWh produced by

turbine-generator

Background

The capital cost of a back-pressure turbogenerator complete

with electrical switchgear varies

from about $700/kW for a small

system (50 kW) to less than

$200/kW for a larger system

(>2,000 kW). Installation costs

vary depending upon piping

and wiring runs, but typically

average 75% of equipment

costs.

Packaged or “off-the-shelf”

backpressure turbogenerators

are now available in ratings as

low as 50 kW. Backpressure 

turbogenerators should be considered when a boiler has steam

flows of at least 3,000 lbs/hr,

and when the steam pressure

drop between the boiler and

the distribution network is at

least 100 psig. The backpressure

turbine is generally installed in

parallel with a PRV, to ensure

that periodic turbine-generator

maintenance does not interfere

with plant thermal deliveries.

Appendix B: Steam Tip Sheet Number 22
92 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 22 (continued)

The cost of boiler fuel before and after a proposed pressure increase can be calculated directly from the boiler

fuel cost, boiler efficiency, and inlet and outlet steam conditions. The annual kWh produced by the turbine

generator can be calculated from the inlet and exhaust pressures at the turbine, along with the steam flow rate

through the turbine, in thousand pounds per hour (Mlb/hour).

To estimate the potential power output of your system, refer to Figure 1, which shows lines of constant power

output, expressed in kW of electricity output per Mlb/hour of steam throughput as a function of the inlet and

exhaust pressure through the turbine. Look up your input and output pressure on the axes shown, and then

use the lines provided to estimate the power output, per Mlb/hour of steam flow rate for a backpressure turbogenerator. You can then estimate the turbine power output by multiplying this number by your known steam

flow rate.

◆ Example

A chemical company currently uses a 100-psig boiler with 78% boiler efficiency (hboiler) to produce 50,000

pounds per hour (lb/hr) of saturated steam for process loads. The plant operates two shifts per day, with the boiler operating at rated capacity for 6,000 hours/year. The boiler has reached the end of its service life and the company is considering replacing the boiler with a new 100-psig boiler or with a high-pressure 600-psig boiler and a

backpressure steam turbine-generator. Both new boiler alternatives have rated efficiencies of 80%. The company

currently pays 6 cents/kWh for electricity, and purchases boiler fuel for $5.00/MMBtu. Condensate return to the

boiler has an enthalpy of 150 Btu/lb. What are the relative financial merits of the two systems?

Step 1: Calculate the current annual boiler fuel cost = $2,000,000 per year

Current boiler fuel cost

= [fuel price] x [steam rate] x [annual operation] x [steam enthalpy gain] / [hboiler]

= $5.00/MMBtu x 50,000 lb/hr x 6,000 hrs/yr x (1,190 Btu/lb – 150 Btu/lb) /0.78 = $2,000,000 per year

Step 2: Calculate the boiler fuel cost of a new 100-psig low-pressure (LP) boiler 

= $1,950,000 per year

Resulting reductions in fuel costs are due solely to the higher efficiency of the new boiler.

New LP boiler fuel cost 

= [fuel price] x [steam rate] x [annual operation] x [steam enthalpy gain] / [hboiler]

= $5.00/MMBtu x 50,000 lb/hr x 6,000 hrs/yr x (1,190 Btu/lb – 150 Btu/lb) /0.80 

= $1,950,000 per year

Note: Assumes 50% isentropic turbine efficiency, a 96% efficient generator, and dry unsaturated inlet steam. 

10 kW per Mlb/hour

18 kW per Mlb/hour

25 kW per Mlb/hour

100 200 300 400 500 600 700 800

300

250

200

150

100

50

0

Input Pressure (psig)

Exhaust Pressure (psig)

Figure 1. Estimating Power Output Using Steam Inlet and Exhaust Pressures
A Sourcebook for Industry 93

Appendix B: Steam Tip Sheet Number 22 (continued)

Step 3: Calculate the boiler fuel cost of a new high-pressure (HP) boiler capable of producing

600-psig, 750°F superheated steam = $2,073,940 per year 

We must now take into account the additional enthalpy necessary to raise the pressure of the boiler steam to

600-psig. With a 50% isentropic turbine efficiency, the exhaust steam from the backpressure turbine is at 

100-psig and 527°F and must be desuperheated. In order to provide an equivalent amount of thermal energy

to the process loads, the boiler steam output is reduced to 45,000 lbs/hour.

New HP boiler fuel cost 

= [fuel price] x [steam rate] x [annual operation] x [steam enthalpy gain] / [hboiler]

= $5.00/MMBtu x 45,000 lb/hr x 6,000 hrs/yr x (1,379 Btu/lb – 150 Btu/lb) / 0.80 

= $2,073,940 per year

Step 4: Estimate the electricity output of the steam turbine-generator = 6,750,000 kWh/year

At 600-psig inlet pressure with 750°F superheated steam and 100-psig exhaust pressure, the system will satisfy

existing steam loads, but will also produce approximately 25 kW of electric power per Mlb/hour of steam production (Refer to Figure 1 to estimate your power output for steam at saturated conditions). Thus,

Turbine-generator power output = 45 Mlb/hour x 25 kW/Mlb/hour = 1,125 kW

Assuming a 6,000-hour operating year, the electricity output of this turbine will be:

Turbine-generator electricity output = 1,125 kW x 6,000 hours/year = 6,750,000 kWh/year

Step 5: Determine the cost of electricity produced by the turbine = $0.018/kWh

The value is derived from the difference in fuel costs between the two boiler alternatives, divided by the

power produced by the turbine:

Fuel cost of produced electricity 

= [$2,073,940/year - $1,950,000/year] / 6,750,000 kWh/year 

= $0.018/kWh

Step 6: Calculate energy savings benefits = $283,500 per year

Cost savings 

= 1,125 kW x ($0.06/kWh – $0.018/kWh) x 6,000 hours per year 

= $283,500 per year 

This level of savings is often more than adequate to justify the capital and maintenance expenditures for the

backpressure turbine-generator set and the incremental cost of purchasing and installing the higher-pressure

boiler.

◆ Suggested Actions ◆

Consider installation of a high-pressure boiler with a backpressure turbine-generator whenever undertaking a boiler upgrade. When 

evaluating this opportunity, you should:

• Determine how much steam enthalpy, pressure and temperature is required at the header downstream from your boiler. 

• Calculate the incremental fuel cost between a low-pressure boiler and a high-pressure boiler.

• Develop steam flow/duration curves for your boiler. (Remember that electrical generation will follow your steam load or process 

heating requirements).

• Obtain plant electricity and fuel cost information.

• Use the tools provided in this fact sheet to estimate your electricity generation potential and to determine savings from purchasing 

and installing a high-pressure boiler plus a backpressure turbine-generator set.

Steam Tip Sheet information is adapted from material provided by the TurboSteam Corporation and is reviewed by the DOE BestPractices Steam Technical Subcommittee.

For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102004-1710 • July 2004 • Steam Tip Sheet #22
94 Improving Steam System Performance
Install an Automatic Blowdown 

Control System

During the surface blowdown process, a controlled amount of boiler water containing high dissolved solids concentrations is discharged into the sewer. In addition to wasting water and chemicals, the blowdown process wastes heat energy,

because the blowndown liquid is at the same temperature as the steam produced—approximately 366°F for 150 pounds per square inch gauge (psig) saturated steam—and blowdown heat recovery systems, if available, are not 100%

efficient. (Waste heat may be recovered through the use of a blowdown heat

exchanger or a flash tank in conjunction with a heat recovery system. For more

information, see Steam Tip Sheet #10, Recover Heat from Boiler Blowdown). 

◆ Advantages of Automatic Control Systems

With manual control of surface blowdown, there is no way to determine the

concentration of dissolved solids in the boiler water, nor the optimal blowdown

rate. Operators do not know when to blow down the boiler, nor for how long.

Likewise, using a fixed rate of blowdown does not take into account changes in

makeup and feedwater conditions, or variations in steam demand or condensate

return.

An automatic blowdown-control system optimizes surface-blowdown rates by

regulating the volume of water discharged from the boiler in relation to the 

concentration of dissolved solids present. Automatic surface-blowdown control

systems maintain water chemistry within acceptable limits, while minimizing

blowdown and reducing energy losses. Cost savings come from the significant

reduction in consumption, disposal, treatment, and heating of water. 

◆ How it Works

With an automatic blowdown-control system, high- or low-pressure probes are

used to measure conductivity. The conductivity probes provide feedback to a

blowdown controller that compares the measured conductivity with a set-point

value, and then transmits an output signal that drives a modulating blowdown

release valve. 

Conductivity is a measure of the electrical current carried by positive and negative

ions when a voltage is applied across electrodes in a water sample. Conductivity

increases when the dissolved ion concentrations increase. The measured current

is directly proportional to the specific conductivity of the fluid. Total dissolved

solids (TDS), silica, chloride concentrations, and/or alkalinity contribute to 

conductivity measurements. These chemical species are reliable indicators of salts

and other contaminates in the boiler water.

◆ Applications

Boilers without a blowdown heat-recovery system and with high blowdown rates

offer the greatest energy-savings potential. The optimum blowdown rate is determined by a number of factors including boiler type, operating pressure, water

treatment, and makeup-water quality. Savings also depend upon the quantity of

condensate returned to the boiler. With a low percentage of condensate return,

more makeup water is required and additional blowdown must occur. Boiler 

blowdown rates often range from 1% to 8% of the feedwater flow rate, but can be

as high as 20% to maintain silica and alkalinity limits when the makeup water

has a high solids content. 

Background

To reduce the levels of suspended and total dissolved solids in

a boiler, water is periodically

discharged or blown down.

High dissolved solids concentrations can lead to foaming

and carryover of boiler water

into the steam. This could lead

to water hammer, which may

damage piping, steam traps, 

or process equipment. Surface

blowdown removes dissolved

solids that accumulate near

the boiler liquid surface, and 

is often a continuous process.

Suspended and dissolved solids

can also form sludge. Sludge

must be removed because it

reduces the heat-transfer capabilities of the boiler, resulting

in poor fuel-to-steam efficiency

and possible pressure vessel

damage. Sludge is removed by

mud or bottom blowdown.

Recommended Practices

The American Society of

Mechanical Engineers (ASME)

has developed a consensus on

operating practices for boiler

blowdown. Sections VI and 

VII of the ASME Boiler and 

Pressure Vessel Code describe 

recommended practices. The

ASME Boiler and Pressure Vessel

Code can be ordered through

the ASME website:

www.asme.org

A Sourcebook for Industry 95

Appendix B: Steam Tip Sheet Number 23
◆ Price and Performance Example

For a 100,000 pound-per-hour steam boiler, decreasing the required blowdown rate from 8% to 6% of the

feedwater flow rate will reduce makeup water requirements by approximately 2,300 pounds per hour (See

Steam Tip Sheet #9, Minimize Boiler Blowdown). Annual energy, water, and chemicals savings due to blowdown

rate reductions for a sample system are summarized in Table 1. In many cases, these savings can provide a 

1- to 3-year simple payback on the investment in an automatic blowdown control system.

Purchasing and installing an automatic blowdown-control system can cost from $2,500 to $6,000. The

complete system consists of a low- or high-pressure conductivity probe, temperature compensation and signal

conditioning equipment, and a blowdown-modulating valve. Some systems are designed to monitor both

feedwater and blowdown conductivity from multiple boilers. Continuous conductivity recording capability

might also be desired. The total cost of the automatic blowdown system is dependent upon the system

operating pressure and the design and performance options specified.

96 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 23 (continued)

Steam Tip Sheet information is reviewed by the DOE BestPractices Steam Technical Subcommittee. For additional information 

on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102004-1711 • April 2004 • Steam Tip Sheet #23

Blowdown Reduction Annual Dollar Savings ($)

(pounds/hour) Fuel Water and Chemicals Total

1,000 $14,925 $4,200 $19,125

2,000 $29,850 $8,400 $38,250

4,000 $59,695 $16,800 $76,495

Savings Through Installation of Automatic Blowdown-Control System

Note: Based on continuous operation of a 150-psig, natural gas-fired steam boiler with fuel valued at $4.50 per million British

thermal units, a makeup water temperature of 60°F, and a boiler efficiency of 82%. Water, sewage, and chemical 

treatment costs are estimated at $0.004 per gallon.

◆ Suggested Actions ◆

• Review your blowdown and makeup water treatment practices; compare them with American Society of Mechanical Engineers 

(ASME) practices. 

• If a continuous-blowdown system is in place, determine the savings an automatic blowdown-control system could attain. Install 

conductivity monitoring and automatic blowdown control equipment if the proposed project meets your cost-effectiveness criteria. 

• Determine the energy savings and cost-effectiveness from using a heat exchanger to recover energy from the blowdown and 

preheat boiler makeup water. Blowdown heat-recovery systems may be economical for boilers with blowdown rates as low as 

500 pounds/hour.
Upgrade Boilers with Energy-Efficient Burners

◆ Background

The purpose of the burner is to mix molecules of fuel with molecules of air. A

boiler will run only as well as the burner performs. A poorly designed boiler with

an efficient burner may perform better than a well designed boiler with a poor

burner. Burners are designed to maximize combustion efficiency while minimizing the release of emissions. 

A power burner mechanically mixes fuel and combustion air and injects the

mixture into the combustion chamber. All power burners essentially provide

complete combustion while maintaining flame stabilization over a range of firing rates. Different burners, however, require different amounts of excess air and

have different turndown ratios. The turndown ratio is the maximum inlet fuel or

firing rate divided by the minimum firing rate. 

An efficient natural gas burner requires only 2% to 3% excess oxygen, or 10% to

15% excess air in the flue gas, to burn fuel without forming excessive carbon

monoxide. Most gas burners exhibit turndown ratios of 10:1 or 12:1 with little

or no loss in combustion efficiency. Some burners offer turndowns of 20:1 on oil

and up to 35:1 on gas. A higher turndown ratio reduces burner starts, provides

better load control, saves wear-and-tear on the burner, reduces refractory wear,

reduces purge-air requirements, and provides fuel savings.

◆ Efficient Burner Technologies

An efficient burner provides the proper air-to-fuel mixture throughout the full

range of firing rates, without constant adjustment. Many burners with complex

linkage designs do not hold their air-to-fuel settings over time. Often, they are

adjusted to provide high excess air levels to compensate for inconsistencies in

the burner performance.

An alternative to complex linkage designs, modern burners are increasingly

using servomotors with parallel positioning to independently control the quantities of fuel and air delivered to the burner head. Controls without linkage allow

for easy tune-ups and minor adjustments, while eliminating hysteresis, or lack of

retraceability, and provide accurate point-to-point control. These controls provide consistent performance and repeatability as the burner adjusts to different

firing rates. 

Alternatives to electronic controls are burners with a single drive or jackshaft.

Avoid purchasing standard burners that make use of linkages to provide singlepoint or proportional control. Linkage joints wear and rod-set screws can loosen,

allowing slippage, the provision of sub-optimal air-to-fuel ratios, and efficiency

declines. 

◆ Applications

Consider purchasing a new energy-efficient burner if your existing burner is

cycling on and off rapidly. Rotary-cup oil burners that have been converted to

natural gas use are often inefficient. Determining the potential energy saved by

replacing your existing burner with an energy-efficient burner requires several steps.

First, complete recommended burner-maintenance requirements and tune your

boiler. Conduct combustion efficiency tests at full- and part-load firing rates. Then,

compare the measured efficiency values with the performance of the new burner.

Most manufacturers will provide guaranteed excess O2, CO, and NOx levels. 

Maintenance Requirements

Conduct burner maintenance

at regular intervals. Wear on

the firing head, diffuser, or

igniter can result in air leakage

or failure of the boiler to 

start. One burner distributor

recommends maintenance

four times per year, with the

change of seasons. A change 

in weather results in a change

in combustion. 

Fan Selection

Fan selection is also important.

Backward-curved fans provide

more reliable air control than

forward-curved fans. Radialdamper designs tend to provide

more repeatable air control at

lower firing rates than bladetype damper assemblies.

A Sourcebook for Industry 97

Appendix B: Steam Tip Sheet Number 24
98 Improving Steam System Performance

Appendix B: Steam Tip Sheet Number 24 (continued)

Steam Tip Sheet information is adapted from material provided by PBBS Equipment Corporation and Blesi-Evans Company, and is reviewed by the DOE BestPractices Steam

Technical Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-10204-1708 • April 2004 • Steam Tip Sheet #24

◆ Example

Even a small improvement in burner efficiency can provide significant savings. Consider a 50,000 pound per

hour process boiler with a combustion efficiency of 79% (E1). The boiler annually consumes 500,000 million

British thermal units (MMBtu) of natural gas. At a price of $4.50/MMBtu, the annual fuel cost is $2.25 million.

What are the savings from installing an energy efficient burner that improves combustion efficiency by 1%,

2%, or 3%?

Cost Savings = Fuel Consumption x Fuel Price x (1 – E1/E2)

If the installed cost is $50,000 for a new burner that provides an efficiency improvement of 2%, the simple

payback on investment is:

Simple Payback = $50,000 ÷ $55,550/year = 0.9 years

◆ Suggested Actions ◆

• Perform burner maintenance and tune your boiler.

• Conduct combustion-efficiency tests at full- and part-load conditions.

• If the excess O2 exceeds 3%, or combustion efficiency values are low, consider modernizing the fuel/air control system to include

solid-state sensors and controls without linkage. Also consider installing improved process controls, an oxygen trim system, or a new

energy-efficient burner.

• A new energy-efficient burner should also be considered if repair costs become excessive, reliability becomes an issue, energy savings

are guaranteed, and/or utility energy-conservation rebates are available.

• Install a smaller burner on a boiler that is oversized relative to its steam load.

Burner Combustion Efficiency Annual Energy Savings, Annual Savings

Improvement (%) (MMBtu/year) ($)

1 6,250 $28,125

2 12,345 $55,550

3 18,290 $82,305

Energy Savings Due to Installation of an Energy-Efficient Burner
A Sourcebook for Industry 99

Appendix B: Steam Tip Sheet Number 25

Consider Installing Turbulators on 

Two- and Three-Pass Firetube Boilers

In a firetube boiler, hot combustion gases pass through long, small-diameter

tubes, where heat is transferred to water through the tube walls. Firetube boilers

are categorized by their number of “passes,” or the number of times that the hot

combustion gases travel across the boiler heat-exchange surfaces. For example, a

two-pass boiler provides two opportunities for hot gases to transfer heat to the

boiler water. Hot combustion gases enter the tubes in a turbulent flow regime,

but within a few feet, laminar flow begins and a boundary layer of cooler gas

forms along the tube walls. This layer serves as a barrier, retarding heat transfer. 

Turbulators, which consist of small baffles, angular metal strips, spiral blades, or

coiled wire, are inserted into the boiler tubes to break up the laminar boundary

layer. This increases the turbulence of the hot combustion gases, and the convective heat transfer to the tube surface. The result is improved boiler efficiency.

Turbulators are usually installed on the last boiler pass. 

Turbulator installers can also balance gas flow through the tubes by installing

longer turbulators in the uppermost tubes. This practice increases the effectiveness of the available heat-transfer surface by eliminating thermal stratification

and balancing the gas flow through the firetubes.

◆ Applications

Turbulators can be a cost-effective way to reduce the stack temperature and

increase the fuel-to-steam efficiency of single-pass horizontal return tubular

(HRT) brick-set boilers and older two- and three-pass oil and natural-gas-fueled

firetube boilers. Turbulators are not recommended for four-pass boilers or coalfired units. A four-pass unit provides four opportunities for heat transfer. It has

more heat exchange surface area, a lower stack temperature, higher fuel-to-steam

efficiency, and lower annual fuel costs than a two- or three-pass boiler operating

under identical conditions. New firetube boilers perform better than older twoand three-pass designs. 

Turbulators can also be installed to compensate for efficiency losses when a fourpass boiler is being converted to a two-pass boiler because of door warpage and

loose and leaking tubes.

Turbulators are a substitute for a more costly economizer or air-preheater. They

are simple, easy to install, and low cost. Their installed cost is about $10 to $15

per boiler tube. Current turbulator designs do not cause significant increase in

pressure drops or contribute to soot formation in natural-gas-fired boilers. 

Turbulators are held in place with a spring lock and are easily removed to allow

for tube brushing.

Turbulators come in various lengths and widths and should be installed by a 

qualified installer. To avoid combustion problems, the boiler burner should be

retuned after the turbulators have been installed. The installer must also verify

that the stack temperature does not fall below the flue gas dew point.

◆ Price and Performance Example

A manufacturing facility installed 150 turbulators into their firetube boiler. Tests, 

conducted both before and after turbulator installation, indicated a reduction in

Firetube Boilers

The packaged firetube boiler 

is the most common boiler

design used to provide heating

or process steam in industrial

and heavy commercial applications. The American Boiler

Manufacturers Association

(ABMA) surveyed high-pressure

(15 to 350-psig) firetube and

small watertube boiler sales

between 1978-1994. ABMA

found that firetube boilers

comprised over 85% of the sales

of these boilers to industry. 

Although firetube boilers are

available in ratings up to 

85,000 pounds of steam per

hour, they are generally 

specified when the required

steam pressure is under 150

psig and the boiler capacity 

is less than 25,000 pounds 

per hour. Watertube boilers 

are designed for larger, highpressure, and superheated

steam applications.
Steam Tip Sheet information is adapted from material provided by Brock Turbulators and Fuel Efficiency, LLC, and is reviewed by the DOE BestPractices Steam Technical

Subcommittee. For additional information on industrial steam system efficiency, contact the EERE Information Center at 877-337-3463.

DOE/GO-102004-1709 • April 2004 • Steam Tip Sheet #25

the stack gas temperature of 130°F. More combustion heat was being transferred into the boiler water. Because

each 40°F reduction in the boiler flue gas temperature results in a 1% boiler-efficiency improvement, overall

boiler efficiency is improved by about 3.25%. Fuel costs decrease by approximately 4%.

◆ Example

Consider a two-pass firetube boiler that consumes 60,000 million British thermal units (MMBtu) of natural gas

annually, and that produces 15,000 pounds per hour of 100 pounds per square inch gauge (psig) saturated

steam. What are the annual energy and cost savings, given that the installation of turbulators improves the

boiler efficiency from 79% (E1) to 82% (E2)? Natural gas is priced at $4.50/MMBtu.

Energy Savings = Annual Fuel Consumption (MMBtu) x (1 – E1 ÷ E2)

or 60,000 MMBtu x ( 1 - 79 ÷ 82) = 2,195 MMBtu/year

Annual Cost Savings = $4.50/MMBtu x 2,195 MMBtu/year = $9,878

If the boiler has 250 tubes and the installed cost for the turbulator is $15 per tube, the simple payback on the

investment in the energy efficiency measure is:

Simple Payback = (250 tubes x $15/tube) ÷ $9,878/year = 0.38 years

◆ Suggested Action ◆

Consider installing turbulators in your two- or three-pass firetube boiler tubes if your stack gas temperature is 100°F or more above your steam or hot

water temperature. 

100
Appendix C: Guidelines for Comment

A Sourcebook for Industry 101

Appendix C: Guidelines for Comment

Comments that can correct and improve this Sourcebook are appreciated. Please photocopy this page

and provide suggestions to the address listed below.

Improving Steam System Performance, A Sourcebook for Industry Comment Form

Page Number(s)

Comments

From:

Contact: EERE Information Center

P.O. Box 43165

Olympia, WA 98504-3165

www.eere.energy.gov/informationcenter/

Phone: 877-EERE-INF (877-337-3463)

Fax: 360-236-2023
102 Improving Steam System Performance
A Sourcebook for Industry
A Strong Energy Portfolio for a Strong America

Energy efficiency and clean, renewable energy will mean a stronger economy, a cleaner environment, and greater energy independence

for America. Working with a wide array of state, community, industry, and university partners, the U.S. Department of Energy's Office of

Energy Efficiency and Renewable Energy invests in a diverse portfolio of energy technologies.

Industrial Technologies Program

U.S. Department of Energy

Energy Efficiency and Renewable Energy

Washington, D.C. 20585-0121

Improving Steam System Performance: A Sourcebook for industry

One in a series of industrial energy efficiency sourcebooks

To order additional copies of this sourcebook, please contact:

EERE Information Center

1-877-EERE-INF (1-877-337-3463)

www.eere.energy.gov

Co-sponsored by:

Council of Industrial Boiler Operators

6035 Burke Centre Parkway, Suite 360

Burke, VA 22015

National Insulation Association

99 Canal Center Plaza, Suite 222

Alexandria, VA 22314

North American Insulation Manufacturers Association

44 Canal Center Plaza, Suite 310

Alexandria, VA 22314

American Boiler Manufacturers Association

4001 North 9th Street, Suite 226

Arlington, VA 22203-1900

About the Office of Energy Efficiency and Renewable Energy

DOE/GO-102004-1868

October 2004

Council of Industrial Boiler Owners