The overall goal of such plant assessments is to develop a comprehensive

strategy that will significantly increase

plant energy efficiency and reduce environmental emissions. In this regard, ORNL

strongly encourages industrial sites to work

closely with their resource and equipment

suppliers, engineering firms, and other

third party entities. Funding of up to

$75,000 is available for each project

selected with a required industrial cost

share of at least 50%. 

We are interested in industrial sites that

take a comprehensive, plant-wide systems

approach to increasing energy efficiency

and reducing environmental emissions.

Specifically, proposals are sought where

teams will be considering the adoption of

best available and emerging technology

using state-of-the-art tools, information,

process engineering techniques, and best

practices for operating and planned plant

support and process systems. Priority will

be given to proposals for plant assessments

from industrial sites that fall within the OIT

Industries of the Future (IOF) initiative,

including: Forest Products, Chemicals,

Petroleum, Steel, Aluminum, Metalcasting,

Glass, Mining, and Agriculture. 

It is expected that the plant assessments

will address a variety of generic and industry-specific technology areas, and a variety

of plant/process optimization methods.

Proposers should also consider demandside energy management best practices

and technology implementation in plant

steam delivery and process heating systems, electric-motor systems (including 

motors, drives, pumps, fans, blowers),

compressed air systems, and heat

exchange optimization (e.g., pinch technology), as well as, supply-side options

using cogeneration and combined heat

and power system technologies. 

The results, successes, and experiences

from these assessments will be published

to encourage other U.S. industrial companies to adopt and implement a comprehensive, plant-wide systems approach to

increasing energy efficiency and reducing

environmental emissions. In this way, it is

desired to increase the market penetration

of energy-efficient systems across U.S.

industry and to increase industrial energy

efficiency, waste reduction, productivity,

and global competitiveness. Participating

plants will be made aware of, and provided technical assistance to accessing, all

OIT emerging technology and best practices, and tools and information resources

that could assist the plants in implementing the most cost-effective state-of-the-art

technology.

Parties interested in receiving the RFP

should contact:

Mitch Olszewski

Oak Ridge National Lab

P.O. Box 2009

Building 9102-1, Mail Stop 8038

Oak Ridge, TN 37831

(423) 574-0770, phone

(423) 576-0493, fax

zmo@ornl.gov, e-mail

Your Proposal Could Lead to Substantial Cost Savings 

for Your Plant—Submit it Now!

T OF ENERGY

DEPARTMEN

U

E

NIT ED STAT S OF A ERICA

M

An Office of Industrial Technologies 

Bimonthly Publication Focusing on

Energy Efficiency Opportunities for Today

www.oit.doe.gov

www.motor.doe.gov

Formerly Turning Point • May 1999

INSERT:

Steam Challenge Supplement

Issue Focus: 

Motor, Steam, Compressed Air

Systems Management

IN THIS ISSUE

Your Proposal Could Lead to Substantial

Cost Savings for your Plant—

Submit it Now . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Boiler System Efficiency Improves with 

Effective Water Treatment. . . . . . . . . . . . . . . . 2

DOE Industrial Assessment Center Helps

Georgia Quarry . . . . . . . . . . . . . . . . . . . . . . . . 4

Data Logging a Plant Compressed 

Air System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Performance Optimization Tips . . . . . . . . . . . 6

Root Cause Failure Analysis on 

AC Induction Motors . . . . . . . . . . . . . . . . . . . . 8

Letters to the Editor . . . . . . . . . . . . . . . . . . . . 9

Coming Events . . . . . . . . . . . . . . . . . . . . . . . . 10

Oak Ridge National Laboratory (ORNL), on behalf of DOE’s Office of Industrial 

Technologies (OIT), is interested in obtaining proposals from industrial manufacturing

plant sites for plant-wide assessments that will lead to substantial improvements in 

industrial energy efficiency, waste reduction, productivity, and global competitiveness. 
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Look to upcoming issues of Energy Matters to help you:

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Take a few minutes to read through the enclosed copy of Energy Matters. The

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■

EDITORIAL BOARD

Bob Asdal, Hydraulic Institute

Floyd Barwig, Iowa Energy 

Center, representing Compressed

Air Challenge

Rob Boteler, representing

National Electrical Manufacturers

Association

Lynda Butek, representing 

Electrical Apparatus Service 

Association

Don Casada, Oak Ridge National

Laboratory

Keith Davidson, Onsite Sycom

Energy

Steve Darby, Darby Electric

Glenn Hahn, Spirax Sarco

Fred Hart, U.S. DOE, Steam 

Challenge

Kim Holshouser, U.S. Electrical

Motors

Chris Hunter, Johnson & Johnson

Roy Jones, representing

Compressed Air and Gas Institute

John Machelor, Macro 

International

Rick Payton, Rockwell 

Automation/Reliance Electric

Bill Stafford, Technical 

Association of the Pulp and Paper

Industry

Howard Snyder, Weirton Steel

Chuck Whelan, DuPont

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Contact: 

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2 Energy Matters, May 1999

By Michael Frasca, Boiler Technology 

Marketing, Nalco Chemical Company,

Naperville, IL

Minimizing energy costs while maintaining

high boiler reliability is one of the main

objectives of every utility system operator.

Optimization of boiler combustion controls, minimizing stack losses, and installation of heat recovery equipment are

obvious big-ticket items. Water treatment,

although typically a smaller payback item,

is also important. 

There are many opportunities, as discussed in this article, to improve boiler system efficiency through the use of chemical

treatment. 

Reduce Boiler Scale

Boiler scale creates a problem in boiler

operation because scale typically possesses

a low thermal conductivity (relative to a

clean metal surface). The presence of scale

is equivalent to having a thin film of insulation across the path of heat transfer from

the furnace gases to the boiler water. This

heat-insulating material retards heat transfer

and causes a loss in boiler efficiency. Stack

gas temperatures may increase as the boiler

absorbs less heat from the furnace gases.

Heat transfer may be reduced as much

as 10%-12% by the presence of scale. A

scale approximately 1/8-inch thick may

cause an overall loss in boiler efficiency of

about 2%-3% in fire tube boilers as well as

in the convective sections of water-tube

boilers. Even more important than the heat

loss is that scale can cause overheating of

the boiler tube metal and can result in subsequent tube failures. Costly repairs and

boiler outages are the result of such a condition (Figure 1). 

Scale formation in boilers can be controlled by chemical treatment in combination with the proper operation and

maintenance of all make-up and feedwater

pretreatment systems. Phosphates,

chelates, and polymers are among the

treatments in common use today to condition and/or maintain solubility of scaleforming solids within the boiler.

Optimize Boiler Blowdown Rates

Proper control of blowdown is a critical

part of boiler operation. Insufficient blowdown may lead to deposits or carryover,

while excessive blowdown will waste

water, heat, and chemicals. The American

Society of Mechanical Engineers (ASME)

has developed a consensus on operating

practices for boiler feedwater and blowdown that is related to operating pressure.

These suggestions apply for both steam

purity and deposition control. 

(continued on page 3)

Boiler System Efficiency Improves with Effective Water Treatment Tube metal temperature increase

Deposit thickness, in. (mm)

0

(0)

0.002

(0.005)

0.004

(0.010)

0.006

(0.015)

0.008

(0.020)

0.010

(0.025)

0.012

(0.030)

0

20

40

60

80

100

120

°C

40

0

80

120

160

200

240

°F

1,500 psi (105 kg/cm2)

280,000 Btu/ft2/hr (760,000 kcal/m2/hr)

Analcite (sodium aluminum silicate)

Magnesium phosphate

Calcium phosphate

Magnetic iron oxide

Figure 1. Effect of boiler scale on tube metal temperature.
Energy Matters, May 1999 3

continued from page 2

The ASME limits are a good starting

point in establishing blowdown needs.

Operating experience with a particular

boiler then determines whether or not it is

practical to deviate from these limits. A

steam purity study can help set new boiler

limits which will minimize solids carryover, while also maintaining minimum

blowdown rates.

Once specific limits for boiler water

solids have been set, a practical way is

needed to control solids level on a day-today basis. Conductivity, TDS, silica, chlorides, and/or alkalinity is often used to

control the rate of blowdown. These tests,

however, are often subject to interference

and may be difficult to measure accurately

in high-purity feedwater systems. 

An inert fluorescent tracer can be used

to accurately measure boiler cycles and

chemical feed. Typically, the increased

accuracy and confidence from using an

inert fluorescent tracer will allow boiler

cycles to be increased, resulting in significant savings. 

Reduce Iron and Copper Pick-up in the

Feedwater

Oxygen scavengers developed within

the last 20 years may be more than their

name implies. Some provide both chemical oxygen scavenging and passivation of

the pre-boiler or feedwater system. (Passivation is the formation of a very thin,

dense, protective iron oxide film, commonly magnetite, on the metal surface.

Passivation typically increases the corrosion resistance of a metal surface.) These

oxygen scavengers are used to prevent corrosion in the feedwater system. Reduced

corrosion minimizes the transport of corrosion products to the boiler and also to the

superheaters if feedwater is used for attemperation. 

Testing under laboratory conditions has

determined that carbohydrazide is the best

passivating agent at all temperatures, followed by erythorbic acid and then

hydrazine. Reduction of feedwater iron 

and copper concentrations by carbohydrazide has been confirmed in actual

boiler systems. 

Reduce Feedwater to the Boiler

The maximum achievable cycles in a

boiler is often limited by TDS or conductivity. In boiler systems using sulfite as an

oxygen scavenger, switching to a non-sulfite scavenger can reduce feedwater TDS

and improve boiler system efficiency. Sulfite is commonly fed to maintain a residual

in the boiler water (Table 1). In contrast,

the non-sulfite scavenger dosage is based

on a small feedwater residual, typically

about 1 ppm. In addition, some of the

alternative scavengers do not themselves

contribute to boiler water TDS or conductivity. For a typical boiler operating at 200

psig, 550,000 lbs/day steaming rate, and

5.5 cycles, the savings from switching to a

non-sulfite scavenger would total $23,000

in fuel costs annually.

Table 1. Recommended Boiler Water 

Sulfite Residual

Boiler Pressure, Residual Range,

Psig [Mpa] ppm

Below 300 [<2.07] 30-60

301-600 [2.08-4.14] 20-40

600-900 [4.14-6.21] 15-30

Above 900 [>6.21] Not 

recommended1

1 Original recommendations extended above 900 psi,

however, thermal breakdown of sulfite typically limits

modern day use to systems operating below 900 psi.

Steam/Condensate System

One economically attractive method of

maximizing energy efficiency and boiler

reliability is by increasing the amount of

condensate return. Returned condensate,

being condensed steam, is extremely pure

and has a high heat content. Increased

condensate return can improve boiler system economics through water and energy

conservation.

As more condensate is returned, less

make-up is required, saving on water and

make-up water treatment costs. The high

purity allows for greater boiler cycles of

concentration, thus reducing water and

energy losses to blowdown. The high heat

content (typically in excess of 180°F) can

provide substantial energy savings. Additional savings will also be noted in reduced

water treatment chemicals, water and

sewer costs. For a typical boiler operating at

600 psig, 2,400,000 lbs/day steaming rate,

and 13 cycles, the savings from increasing

the condensate return 10% would total

$132,000 in fuel costs annually.

Corrosion in condensate systems can

limit the quality or quantity of returned

condensate because of iron and copper

corrosion products, which can deposit on

boiler heat transfer surfaces. This reduces

heat transfer efficiency and could cause

tube failure. Condensate corrosion control

is required to protect process equipment,

lines, tanks, as well as to maintain the condensate as a quality feedwater source. Corrosion of the condensate system can result

in increased maintenance and equipment

costs, energy loss through steam leaks and

loss of process heat transfer efficiency. 

To prevent condensate corrosion,

volatile neutralizing amines, such as cyclohexylamine, morpholine, and diethylaminoethanol, are typically used to

neutralize carbonic acid and raise the condensate pH. These programs are most

effective when fed to maintain a minimum

pH of 8.5, ideally 8.8 to 9.2. A blend of

several amines will assure that corrosion

protection is distributed throughout the

entire steam/condensate system. Filming

amines and a new, patented chemistry are

alternative condensate treatments. 

Summary

There are many opportunities to

improve boiler system efficiency through

the use of chemical treatments. Water

treatment is an important aspect of boiler

operation that can improve efficiency and

availability, or result in damage if

neglected.

For questions or comments, call Mike

Frasca at (630) 305-1625 or send e-mail to

mfrasca@nalco.com.
4 Energy Matters, May 1999

DOE Industrial Assessment Center Helps Georgia Quarry Reduce 

Maintenance Requirements and Energy Costs

Each year, the Energy and Environmental

Management Center (EEMC) at the Georgia

Institute of Technology (Georgia Tech) conducts 25 to 40 energy, waste and productivity assessments, partly supported by its

role as a DOE Industrial Assessment Center

(IAC). 

In February 1997, the EEMC, a Motor

Challenge Allied Partner, completed an

assessment of the Blue Circle Aggregates

quarry in Lithonia, Georgia, outside

Atlanta. The Lithonia quarry, one of 10

quarries operated by Blue Circle Aggregates in Georgia, produces 1.8 million tons

of aggregate and manufactured sand for

construction and road building each year.

Excavating, moving, screening, and processing these materials consume approximately 4 million kWh annually and create

a demand of about 500 kW. 

Based on their assessment, the EEMC

staff recommended three motor system

upgrades for the Lithonia quarry. Implementing the motor system upgrades has

reduced yearly energy consumption at the

quarry by nearly 250,000 kWh and

demand by 81 kW, resulting in cost savings

of over $21,000 per year. These energy

and demand savings are 6.2% and 16% of

their respective annual figures. 

Motor System Upgrades

The three motor system upgrades were

initiated in January 1997 after the Lithonia

Quarry Manager approached the EEMC

requesting an IAC assessment. Soon afterward, the EEMC presented the results and

their recommendations to the Quarry Manager and Blue Circle Aggregates’ Director

of Environmental Services, who reviewed

the report and set priorities for the Lithonia

quarry. They were convinced that the combined benefits of reduced maintenance

and improved energy and environmental

performance were greater than the cost of

the upgrades.

Upgrade 1: Reduce Horsepower of 

Water Pumps

The greatest energy savings resulted

from reducing the capacity of three large

water pumps. The quarry has two water

sources—a quarry pit and a stream some

distance away. The EEMC found that the

quarry pit could provide all the necessary

water for quarry operations. Therefore,

reducing the use of the main pump from

the stream and two additional circulation

pumps reduced power requirements by

140 horsepower (Table 1).

Upgrade 2: Lower Hydro-Cyclone 

Elevation

The second system upgrade reduced

pumping costs by physically lowering part

of the 10-element hydro-cyclone unit at

the quarry by 80 feet. This upgrade cost

approximately $5,100 and resulted in

annual monetary savings of $3,400— a

simple payback of 1.5 years (Table 1). 

Upgrade 3: Replace Four Motors with

Energy-Efficient Motors

The third recommended upgrade

includes replacement of four standard efficiency motors with high-efficiency models

upon burnout. The EEMC completed the

economic evaluations for this upgrade

using MotorMaster+. (Table 1)

The EEMC further recommended that

Blue Circle Aggregates change their motor

policy to specify that all motors operating

more than 3,000 hours per year be

replaced with high-efficiency motors upon

burnout. Doing so would have an average

payback of about 2.4 years.

Blue Circle Aggregates’ On-going

Upgrades

After completing the Lithonia quarry

assessment, the EEMC completed assessments at two other Blue Circle Aggregates

facilities. Since then, Blue Circle Aggregates’ own staff has completed five more

assessments of their own. “They did need

some additional assistance after we submitted the report for the Lithonia quarry,”

says John Adams, Georgia Tech EEMC

Director, “but Blue Circle Aggregates’ corporate Environmental Manager has kept

the project alive and full of vitality.” 

Blue Circle Aggregates’ current plan is

to implement at each plant upgrades similar to these three quarry upgrades. 

(continued on page 5)

Table 1: Motor System Upgrade Savings

Motor HP kW Savings kWh Savings $ Savings

Upgrade 1: Reduce Horsepower of Water Pumps

Water Pump #1 50 20.1 60,400 $ 5,260

Water Pump #2 75 28.0 89,900 7,320

Water Pump #3 15 9.8 29,500 2,570

Upgrade 1 Totals 140 57.8 179,800 $15,150

Upgrade 2: Lower Hydro-Cyclone Elevation

Upgrade 2 Totals N/A 13.1 39,300 $ 3,400

Upgrade 3: Replace Four Motors with Energy-Efficient Motors1

Crusher 200 2.4 7,218 $ 629

Pump #2 150 2.4 7,296 636

Pump #3 200 2.4 7,218 629

Pump #6 140 2.6 7,718 673

Upgrade 3 Totals 690 9.8 29,450 $ 2,567

Grand Totals 837 80.8 248,640 $21,117

1 Savings based on 3,000 hours of operation per year and replacement upon motor failure.

Water pump at Blue Circle Aggregates’

Lithonia quarry.
Energy Matters, May 1999 5

Data Logging a Plant Compressed Air System

By Robert E. Wilson, ConservAIR 

Technologies Co. LLP

While pressure readings at the point of generation provide important information, they

do not portray a complete and accurate

picture of the system’s overall performance.

A system can have very stable pressure in

the compressor room while experiencing

major pressure fluctuations in the production area. Fluctuations can be localized or

affect the entire distribution pressure. If

fluctuations affect production, the typical

response is to increase compressed air supply, which increases operating costs. 

A compressed air system cannot be

evaluated or controlled from the supply

side; performance must be measured on

the production floor. Evaluating air system

efficiency requires a comparative review of

both supply-side and demand-side pressure profiles.

Data logging is an excellent way to

define performance and identify problems

in an industrial compressed air system.

However, to be useful, data acquired must

by correctly interpreted. 

Define Specific Objectives

Before data logging your system, define

your objectives. Keep the objectives specific to key issues. Focus on the information desired not the actual data. Put away

preconceived notions about current performance and solutions. 

Key questions as they relate to one

point of pressure data are:

■ Is pressure too high or too low? 

■ What is too low? 

■ Is pressure consistent? 

■ How consistent should it or can it be? 

■ When pressure increases, why does it

increase? 

■ Did pressure increase because another

compressor loaded up or because an

event demand went away? 

■ If pressure decreased, what was the

cause? 

■ Is the system driven by the compressors,

are the compressors responding to

demands, or both? 

To make data meaningful, you must ask

the right questions, then compare and

evaluate with other pressure point data in a

total system analysis.

Today’s data logging equipment simplifies the review process and offers a valuable

tool for those who have some knowledge 

and experience with compressed air systems. Used properly, a data logger defines

your system’s pressure profiles and shows

how the system is operating. 

Develop Test Procedures 

After determining objectives, develop a

test procedure. Select, identify, and list

monitoring points and parameters. Also,

specify sampling rates and the duration of

the data logging.

Pressure is the easiest and most definitive measure of system performance. Other

variables such as barometric pressure, temperature, fixed volume, moisture content,

demand load profile, and leaks remain relatively constant for a specific system and

duration of data gathering. Therefore, the

conclusions derived from a comparative

evaluation are valid.

Amperage readings are relatively easy

to log. Flow and kW can then be estimated

based upon the compressor manufacturer’s

published data. Again, if the same assumptions are used before and after, the conclusions derived from the comparative

evaluation will be valid. 

At a minimum, pressure must be logged

at the generation point in the compressor

room(s), at representative points in the piping distribution system, and at critical-use

points. 

A typical data logger allows four or

more simultaneous measurements. Multiple

loggers can be used at different locations

within the air system. The key to proper

interpretation is to sample data simultaneously at representative locations in the

compressor room(s), piping header(s), and

use point(s). The sampling must accurately

represent your operation. 

Instantaneous and Trending Operating

Profiles

A pressure drop shows a change in pressure as it relates to a point in time. A trending profile shows the pressure change

across the system. 

Instantaneous profiling helps determine

dynamic peak, average, and valley

demands of the system and the amplitude

of pressure fluctuations. Trending should

be conducted over a time period representative of the production schedule being

evaluated—typically over 24-hour periods

and off-peak times. A comparison of samplings in various locations is used to determine pressure gradient across the system.

(continued on page 9)

DOE’S INDUSTRIAL ASSESSMENT

CENTERS

As one of 29 Industrial Assessment Centers

based at universities around the country, the

EEMC provides energy, waste, and productivity assessments at no charge to small and

medium-sized manufacturers, many of which

are Motor Challenge Partners. These assessments help manufacturers maximize energy

efficiency, reduce waste, and improve productivity. Average savings of greater than

10% of annual utility costs typically result

from implementing the assessment recommendations.

To be eligible for an IAC assessment, a

manufacturing plant must meet the following

criteria:

■ Primary business within Standard Industrial

Classification (SIC) codes 20-39;

■ Located within 150 miles of an IAC host

campus;

■ Gross annual sales less than $75 million;

■ Fewer than 500 employees at plant site;

■ Annual energy bills greater than $75,000

and less than $1.75 million; and

■ Employ no professional, in-house staff able

to perform the assessment.

For information about an energy audit for

your plant, please call (800) 862-2086.

continued from page 4

Georgia Tech’s Energy and Environmental

Management Center

Because of its experience with the type

of operations targeted by DOE’s Office of

Industrial Technologies, the EEMC became

a DOE Industrial Assessment Center (IAC).

As an IAC for almost 20 years, the EEMC

has provided over 650 in-depth IAC assessments at no-charge to eligible manufacturing plant sites. 

John Adams feels it was an easy progression from being a Department of

Energy IAC to becoming a Motor Challenge Allied Partner. As a Motor Challenge

Allied Partner, the EEMC conducts seminars and workshops and performs in-plant

energy audits. “We routinely demonstrate

the MotorMaster+ software then leave the

customer with a copy for their own use,”

says Adams. “We like to teach by example,” he adds. 

Contact John Adams at (404) 894-4138.
6 Energy Matters, May 1999

Performance 

Optimization Tips

Field Measurements—

Practicalities and Pitfalls in 

a Parabolic Context

By Don Casada,

Motor Challenge

Program, Oak Ridge

National Laboratory

Note: This article,

focusing on understanding the changing picture of system operations, is the

third of a series dealing with potential pitfalls in field measurements of motor systems. The first appeared in the November

1998 issue of Turning Point. 

Centrifugal loads, such as pumps, fans, and

compressors are responsible for a large

fraction of industrial electrical energy consumption (1). The opportunities for reducing energy consumption in these systems

are often significant. Any effort to do so

inherently requires three fundamental

pieces of information:

■ The big picture—clearly identified functional requirements of the system.

■ An understanding of how the picture

changes over time.

■ Actual measurements in the field.

The first two elements, which should

always precede and provide the focus for

actual measurements, were covered in previous articles that appeared in the November 1998 Turning Point and the March

1999 issue of Energy Matters. This issue will

begin covering the third, subsidiary element. 

As an employee at a national laboratory, I occasionally get involved in experimental testing and analysis. Since the goal

of the testing is to produce useful and reliable test results, a good deal of attention is

paid to instrumentation issues such as

accuracy, range, calibration, proper physical configuration, etc., as well as test protocols. If an important parameter cannot be

monitored with already installed instruments, the facility is modified to add the

needed equipment. Details are important,

since experimental accuracy is of premium value. Fortunately, professional

societies, such as the American Society of

Mechanical Engineers (ASME), the

Hydraulics Institute, and the Institute of

Electrical and Electronics Engineers (IEEE)

have written excellent testing standards (2,

3, 4, 5) that address instrumentation and

procedural issues.

In many industrial systems, little

thought is given to process monitoring

issues unless the parameter to be monitored is critical to product quality or quantity. For example, if a pumping system is

used to remove heat from another process,

little attention may be paid to instrumentation issues in the pumping system itself

either before or after the system is put in

service. This is natural, since the system

exists to support the process, not experimental testing. As a result, the process

instrumentation that does exist is frequently in undesirable locations (such as a

flow meter located two pipe diameters

downstream of a control valve), and it is

seldom, if ever, calibrated. So while the

basic principles on which the test standards are founded are certainly valid in the

real world, the supporting instrumentation

frequently is not.

If we are to even estimate potential

energy reduction opportunities in centrifugal systems, parameters such as flow rate,

pressures, and electrical power must be

known. Facility managers and operators

are uniformly unenthusiastic about cutting

or drilling holes in pipes to install meters if

the system has been meeting the process

goals. In the absence of reliable permanently installed instruments, how does one

go about measuring or estimating critical

performance parameters in these systems?

Pumping Systems Field Monitoring

The balance of this issue and subsequent

issues of this column will discuss alternative methods of either measuring or estimating important energy-related

parameters in pumping systems1 when less

than ideal instrumentation is encountered. 

From the following expression of overall pump and motor efficiency, which is

simply the ratio of the fluid power to the

electric input power, the primary parameters of importance in pumping systems are

self-evident:

ηt = H ⋅ Q ⋅ γ

Pe

where ηt is overall efficiency, H is the

head, Q is the volumetric flow rate, γ is

the fluid specific weight, and Pe is electrical input power.

From a practical standpoint, fluid temperature and rotational speed are parameters that are also important to monitor.

Starting with head in this issue, each of

these elements will be discussed in this

column. The focus will be on some practical field issues; a few potential pitfalls and

tips based on personal anecdotal experience will also be noted.

It should be noted that References 2

and 3 standards provide excellent detailed

discussions on a variety of practical issues

related to pump testing that will not be

repeated in these columns. 

Pump Head

The pump head accounts for the difference in the sums of three elements of

energy per unit mass between the pump

suction and discharge: pressure, elevation,

and velocity. References 2 and 3 as well as

many textbooks provide detailed discussions on the individual terms. Some practical aspects of the pressure element of head

are treated below. The elevation and velocity elements will be discussed in a subsequent column.

Pressure

In most industrial systems, the pressure

component is the dominant head term (the

others can’t be ignored, however, especially

in low head pump applications). Threaded

test connections are fairly common in the

field, particularly in the pump discharge

line—a point where you’re also most likely

to find a permanently installed gauge. 

(continued on page 7)
Energy Matters, May 1999 7

continued from page 6

Unfortunately, sometimes there are other 

devices between the pump and the gauge, 

such as a discharge check or control valve.

But all isn’t lost if this is the case—the head

loss across the valve can be estimated from 

manufacturer (preferred) or generic performance curves once flow rate is known (or 

estimated). It is also important to note that 

the pressure downstream of a throttled discharge valve is actually a better indication

of what the system needs than is the pressure

at the pump discharge. If pressure can be

measured upstream and downstream of the

valve, an immediate indication of potential

energy savings from eliminating throttling

losses can be established from the following expressions of fluid power:

Pfl (hp) = gpm ⋅ head loss (ft) ⋅ s.g.

3690

or 

Pfl (kW) = 

m3/hr ⋅ head loss (m) ⋅ s.g.

367

where s.g. is specific gravity.

The actual electrical power associated

with the throttling loss is typically 1.3 to 2

times this value because of inefficiencies in

the motor and pump.

Test pressure gauges, rather than permanently installed gauges, should be used if

at all possible. It has been my observation

that a large fraction of permanently

installed gauges, particularly in the

absence of a good calibration

program, are unreliable. On

many occasions, I’ve found

gauges whose pressure indications don’t change when

removed from the process—

even when the needle exhibited

some “wiggle” (suggesting the

gauge was responding to pressure fluctuations in the system)

when connected. The gauge

shown in Figure 1 is such an

example. 

Fortunately, there is usually

an instrument isolation valve

where permanently installed

gauges are located, which makes for a

more pleasant permanent gauge removal

and test gauge installation experience (a

little dry humor there). These valves not

only simplify test gauge installation—they

can also be throttled to dampen pressure

fluctuations that often exist in pumping

systems, making the job of gauge reading a

little easier. But care is needed when doing

this—the valves are often nearly completely closed to achieve the desired

damping, and it is very easy to go to the

fully isolated condition. Should the valve

completely isolate the gauge from the

process, the gauge will continue to read

the pressure that existed at valve closure

(unless there’s leakage around the gauge

threads or the valve seat), which may or

may not represent actual system conditions. A good way to use the valves for

damping is to start with them fully closed

(such as when you’re installing the test

gauge) and with pressure relieved from the

stub between the valve and the test gauge.

Then gradually crack the valve open and

stop when you first see a change in the

indicated pressure. A small needle valve

inserted between the gauge and the test

connection is much easier to use in this

way than the gate or ball valves often used

as isolation devices in the field.

Hydraulic snubbers are also used sometimes to reduce flutter in gauge indication

(as well as to protect the gauge from pressure spikes, such as water hammer). If

used, a test snubber known to be in good

shape is recommended instead of a possibly degraded (plugged) permanent one.

My personal preference for pressure

readings is a small test transducer (such as

shown in Figure 2), which provides an

electrical output, such as 1 millivolt per

psig. The average transducer signal can be

monitored on a multimeter with minimum/maximum/averaging capability, eliminating the need for a valve or hydraulic

snubber pressure damping and/or “eyeball

averaging”. By collecting pressures in this

way, the range of pressure fluctuations can

also be noted (using the minimum and

maximum values). Significant pressure

fluctuations may indicate unstable pump

and/or system operation, information

worth noting on its own merits.

Comments/questions welcome by e-mail:

a85@ornl.gov.

1 Although tailored to pumping systems, much of what

is discussed can either be applied directly or in analogous fashion in other centrifugal load systems.

References

1) United States Industrial Electric Motor Systems Market Opportunities Assessment, U.S. DOE, December

1998.

2) ASME/ANSI Performance Test Code 8.2-1990, Centrifugal Pumps.

3) ANSI/HI 1.6-1994, Centrifugal Pump Tests.

4) ANSI/IEEE Std. 120-1989, IEEE Master Test Guide for

Electrical Measurements in Power Circuits.

5) IEEE Std. 112-1991, IEEE Standard Test Procedure for

Polyphase Induction Motors and Generators.

Figure 1. Test pressure gauge. Figure 2. Test transducer.
Energy Matters, May 1999 8

Root Cause Failure Analysis On AC Induction Motors

By John M. Machelor,

Motor/Drives Systems 

Specialist, Motor Challenge

Program, MACRO International Inc.

This is the fourth in

a series of articles by

Mr. Machelor. In the

January 1999 issue,

John concluded his

discussion of the

most common electrical failure modes

of induction motors and how to identify

their root causes. The present article shifts

the focus to mechanical motor failures. The

next article will continue our investigation

of AC induction motor bearing failures.

Mechanical-related failures of induction

motors have a most common (70% to 80%

of all failures) mode, which is bearing failures. These have many direct causes, all of

which can again be traced to a root cause.

The important thing to note is that the vast

majority of all bearing failures are easily

preventable.

We will focus our attention on antifriction bearings, the most common type

found in NEMA AC induction motors.

Specifications for the design of anti-friction

bearings are covered by the Anti-Friction

Bearing Manufacturers Association, Inc.

(AFBMA). Anti-friction bearings are called

rolling element because they all consist of

an inner and an outer ring (race) encircling

some type and number of rolling element.

The elements are either balls or various

shaped rollers. Figure 1 depicts a typical

anti-friction ball bearing. As we discuss the

damage to and modes of failure of antifriction bearings, one critical characteristic

of them will stand out—except for the

lubricating film set up by the grease or oil

in the bearing, the inner and outer races

can (and often do) come into metal-tometal contact with the rolling elements!

Bearing damage leading to ultimate failure can occur when a motor bearing is

motionless or rotating. Let’s examine one

of the most common types of damage

incurred by non-rotating bearings.

False Brinelling: (See Figure 2.) This condition can occur whenever a non-rotating

bearing is subjected to external vibration.

(Note: There is another type of brinelling

called true brinelling that occurs in rotating

bearings. Damage to rotating bearings will

be discussed in a future article.) When the

bearing isn’t turning, a protective oil film

cannot form between the races and the

rotating elements. Thus, there can be metalto-metal contact between the races and

rotating elements, and the small, relative

motion between these parts causes wear

marks on both races at the location of each

rotating element. False brinelling can occur

during transportation (typically truck or

rail) and during motor storage if the storage

area is subject to vibration. False brinelling

occurs frequently with the bearings of

motors installed on “spare” or “backup” systems in the plant. A typical example of this

is parallel motor/pumps where one system is

considered to be the primary system and the

other system only a backup. The primary

system may run for weeks, months, or even

longer before the backup system is ever

energized. The problem is that even though

the backup is not running, it is actually

“piped” into the system. Vibrations associated with the running system are being constantly transmitted to the backup system.

Thus, severe false brinelling can occur on

both the backup motor and pump bearings. 

Several years ago, I encountered this

“parallel pump” situation at a chemical

plant where I was doing a system survey.

This facility had literally several hundred

primary/backup pump arrangements and

their maintenance team admitted that they

could not remember the last time some of

the backup systems had been used. With

this history in mind, I suggested a random 

energizing of ten backup systems which

maintenance assured me were “ready to

go”. Unfortunately, they were right. Of the

ten backup systems we energized, seven

failed within a day, two failed within a

week, and the remaining one managed to

last 3 weeks. In all ten cases, a bearing on

either the motor or the pump seized up

(froze). Disassembly of all ten motors and

pumps revealed that all the bearings had

severe false brinelling (in addition to corrosion, rust, and loss of lubricant, all to be

discussed later). The maintenance team

was not expecting failures at this rate, and

admitted that on occasions when the primary system failed, the backup system

never seemed to last very long. 

Tips to Avoiding False Brinnelling

The root cause of false brinnelling is lack

of knowledge that it is a problem as well as

lack of a routine maintenance program.

Root solutions thus involve becoming

knowledgeable on the subject as well as

establishing a routine maintenance program for your motors and driven equipment. To this end, here are some “tips” on

avoiding this bearing failure cause:

■ During transportation of motors (or any

type of rotating equipment which utilizes anti-friction bearings), make sure 

(continued on page 9)

Figure 1. Typical anti-friction ball bearing.

         yyyy yyyy yyyy yyyy yyyy yyyy yyyy yyyy yyyy yyyy Ball path

False brinell

marks

Figure 2. False brinelling.
9 Energy Matters, May 1999

Letters to the Editor

Energy Matters welcomes comments

from readers. Letters should be typewritten and must include the author’s full

name, address, association, and phone number. Letters should be limited to 200 words.

Address your letter to:

Michelle Mallory, 

Letters to the Editor

NREL, MS 1713

1617 Cole Blvd.

Golden, CO 80401 

or e-mail to

michelle_sosa-mallory@nrel.gov

We publish letters of interest to our readers

on related technical topics, comments, or

criticisms/corrections of a technical nature.

Preference is given to letters relating to articles that appeared in the previous two

issues. Letters may be edited for clarity,

length and style.

Motor Repair Efficiency Loss

Recently an article in Energy Matters (The

Northeast Premium Efficiency Motor Initiative, January 1999) mentioned that rewinding a motor results in a 2% efficiency loss.

This assumption of efficiency loss is frequently reported in major rewind studies and

reflected in default software calculations. 

In fact, an efficiency loss after rewind

may occur—but not when repairs are performed correctly. At Advanced Energy, the

first motor test lab in the nation to receive

accreditation by the National Voluntary

Laboratory Accreditation Program (NVLAP)

for motor efficiency testing of 1-150 hp

motors, we have conducted over 700 IEEE

112 Method B motor efficiency tests and

provided testing services to nine motor

manufacturers with a notable precision of

repeatability at ±0.2%. 

Our findings? Certain shops are capable

of maintaining or even improving motor

efficiency during repair. A motor repair

facility with a recognized quality program

in place can provide repairs with no loss of

efficiency after rewind. The current recognized motor repair quality programs

include ISO-9002, EASA-Q and Proven

Excellence Verification (PEV). 

The savings realized if post-repair efficiency loss is eliminated have been documented. According to the Department of

Energy, improved rewind practices have

potential energy savings of 4,778

GWh/year—equal to $230 million—to all

American industrial manufacturing facilities. A well-repaired motor also reduces

costly downtime and eliminates unscheduled interruptions to production lines,

which further reduce operating costs. 

Please call me at (919) 857-9013 with

questions, or e-mail me at jfarlow@

advancedenergy.org.

Jeff Farlow, Motor Test Engineer

Advanced Energy, Raleigh, NC

Data Logging

continued from page 5

The Action Plan 

Once you compile the necessary information, you can draw some conclusions

about your system’s performance and

develop an action plan to improve its overall operation. Consider these items: 

■ Use the data to determine your system’s

peak and average air demands. If you

identify a pattern of fluctuating pressure

at points of use or wide pressure variations during a production cycle, consider

using controlled compressed air storage

using intermediate flow control and

receivers.

■ The pressure gradient documents the air

distribution system’s performance.

Define techniques to reduce sustained 

gradient to the accepted level of 1.5-2.0

psid across the air distribution system. 

■ Compressor discharge pressure and

load profile data provide information

about part-load performance. Additional storage can be engineered to

improve the load/unload cycle. You

might also network compressors using a

compressor sequencer to direct partload performance.

■ Data from dynamic use points reveals

information about piping and connections. Develop a schedule for upgrades

and repairs on piping and point-of-use

tools throughout the system. Use these

results to develop standards and establish

“Best Practices” for system management.

■ The power consumption profile clearly

defines your company’s financial investment in compressed air generation.

Evaluate the cost effectiveness of remedial actions based upon this investment.

■ Use all data collected, summarize findings, and conduct a cost/benefit analysis of your recommendations. Data

measurement and testing can be

repeated for future evaluation of the

compressed air system. 

To find out about your system’s performance, go out on the floor where air is consumed, and measure what is happening. 

More information is available in Compressed Air Management by Tom Taranto.

Contact Bob Wilson at (800) 336-2285 for

information about the book or other questions related to this article.

False Brinelling

continued from page 8

the shaft is “blocked” to prevent axial or

radial movement. Blocking eliminates

the clearance between the races and the

rotating elements in the bearing and

thus prevents these parts from “banging”

against one another and causing wear.

■ Choose storage locations as far away as

possible from sources of external vibration. For example, locating a rotating

equipment warehouse adjacent to a ball

mill is not a good idea. In addition, turn

the shaft of all stored rotating equipment

at least once a month. Turning the shaft

moves the rolling elements of the bearing to a new position with each turn,

and also redistributes the settled lubrication grease/oil throughout the bearing.

■ In any rotating equipment plant system

that has a backup or spare system, there

is no reason to designate one system as

the “primary” and the other as the

“backup”. Each system should “share

the load” equally. Thus, establish a

schedule to run each system roughly half

the time, switching at least once a week.

Readers are welcome to send questions,

comments, or suggestions to John Machelor at:

E-mail: jmachelo@macroint.com or macrojmm@aol.com

Phone: (540) 639-4271

Fax: (540) 639-4272

See Coming Events on page 10 for upcoming workshops on the Fundametals of Compressed Air Systems.

How have you applied information from this newsletter on the job? Send us an e-mail: www.motor.doe.gov.
Coming Events 

INFORMATION

CLEARINGHOUSE

Do you have questions about 

using energy-efficient electric

motor systems? Call the OIT Challenge

Programs Information Clearinghouse 

for answers, Monday through Friday

9:00 a.m. to 8:00 p.m. (EST).

Fax: (360) 586-8303, or access our

homepage at www.motor.doe.gov

HOTLINE: (800) 862-2086

DOE Regional Support Office 

Representatives

■ Tim Eastling, Atlanta, GA, 

(404) 347-7141

■ Lili Griffin, Boston, MA, 

(617) 565-9714

■ Julie Nochumsom, Chicago, IL, 

(312) 886-8579

■ Gibson Asuquo, Denver, CO, 

(303) 275-4841

■ Julia Oliver, Seattle, WA, 

(510) 637-1952

■ Maryanne Daniel, Philadelphia, PA, 

(215) 656-6964

This document was produced for the Office 

of Energy Efficiency and Renewable Energy at

the U.S. Department of Energy (DOE) by the

National Renewable Energy Laboratory, a DOE

national laboratory.

DOE/GO-10099-589 • May 1999

T OF ENERGY

DEPARTMEN

U

E

N ITE D STAT S OFA ERICA

M

T OF ENERGY

DEPARTMEN

U

E

NI TE D ST AT S OF A ERICA

M

Printed with a renewable-source ink on paper

containing at least 50% wastepaper, including

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UNDERSTANDING PUMP SYSTEMS/PSAT WORKSHOPS

The following sessions present the fundamentals of optimizing industrial and municipal

pump systems. The workshops will present case studies and will focus on Pump System

Assessment Tool (PSAT).

■ June 6 in Milwaukee, WI

■ June 20 in Chicago, IL

■ August 29 in San Diego, CA

Call Anna Maksimova at (360) 754-1097, ext.100 for more information.

ADJUSTABLE SPEED DRIVE APPLICATION WORKSHOPS

These workshops address the fundamentals of ASDs and demonstrate the ASDMaster software.

■ June 1-2 in Reading, PA

■ June 10 in Springdale, AK

Call Anna Maksimova at (360) 754-1097, ext.100 for more information.

MOTORMASTER+ SOFTWARE DEMONSTRATION

This demonstration of MotorMaster+ software will be at the American Water Work’s Association’s Annual Conference.

■ June 20-24 in Chicago, IL

Call Anna Maksimova at (360) 754-1097, ext.100 for more information.

FUNDAMENTALS OF COMPRESSED AIR SYSTEMS

These 1-day Compressed Air Systems training seminars are targeted to plant engineers and

maintenance personnel who are responsible for ensuring optimum performance of compressed air systems. 

■ May 12 in Allentown, PA

■ May 13 in Knoxville, TN

■ May 21 in Baltimore, MD

■ May 26 in Salt Lake City, UT

■ May 28 in Dallas, TX

■ May 28 in Nashville, TN

■ June 3 in Detroit, MI

■ June 4 in Atlanta, GA

■ June 4 in Philadelphia, PA

For information or a registration form, call (800) 862-2086.

ENERGY EFFICIENCY FORUM FOR WATER/WASTEWATER FACILITIES

The goal of this forum is to help managers and operations personnel of municipal and

industrial systems find workable energy management solutions.

■ August 29-31 in San Diego, CA

Call Laura Boland at (918) 831-9179 for more information.

■ June 8 in Pittsburgh, PA

■ June 11 in San Diego, CA

■ June 11 in Greenville, SC

■ June 11 in Richmond, VA

■ June 14 in San Antonio, TX

■ June 15 in Kansas City, KS

■ June 17 in Phoenix, AZ

■ June 22 in Oklahoma City, OK

■ June 22 in Tampa, FL

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