Flow and Level Measurement

Flow and Level Measurement
www.omega.com • e-mail: [email protected]
Flow & Level Measurement
A Technical Reference Series Brought to You by Omega
VOLUME
4
TABLE OF CONTENTS
VOLUME 4—FLOW & LEVEL MEASUREMENT
Topics Covered
Section
• The Flow Pioneers
• Flow Sensor Selection
• Accuracy vs. Repeatability
04
Volume 4
Page
D
08
• Primary Element Options
• Pitot Tubes
• Variable Area Flowmeters
16
• Positive Displacement Flowmeters
• Turbine Flowmeters
• Other Rotary Flowmeters
34
• Magnetic Flowmeters
• Vortex Flowmeters
• Ultrasonic Flowmeters
46
• Coriolis Mass Flowmeters
• Thermal Mass Flowmeters
• Hot-Wire Anemometers
58
TRANSACTIONS
REFERENCE SECTIONS
Editorial 06 106 Information Resources
About OMEGA 07 110 Glossary
Section
VOLUME 4—FLOW & LEVEL MEASUREMENT
Topics Covered
• Level Sensor Selection
• Boiling & Cryogenic Fluids
• Sludge, Foam, & Molten Metals
72
• Dry & Wet Leg Designs
• Bubbler Tubes
• Floats & Displacers
76
• Theory of Operation
• Probe Designs
• Installation Considerations
TRANSACTIONS
Page
- -- -----
- ----+ ++
++
+
+ ++
++
++
+
+ ++
++
++
+
+ ++
++
+
87
• Radar & Microwave
• Ultrasonic Level Gages
• Nuclear Level Gages
93
• Thermal Switches
• Vibrating Switches
• Optical Switches
102
Volume 4
05
O
08
A Flow Measurement Orientation
ur interest in the measurement of air and water flow
is timeless. Knowledge of
the direction and velocity of air flow was essential information for all ancient navigators,
and the ability to measure water
flow was necessary for the fair
distribution of water through the
aqueducts of such early commu-
hydrodynamics, pneumatics, aerodynamics) is based on the works of
the ancient Greek scientists Aristotle
and Archimedes. In the Aristotelian
view, motion involves a medium that
rushes in behind a body to prevent a
vacuum. In the sixth century A.D., John
Philoponos suggested that a body in
motion acquired a property called
impetus, and that the body came to
nities as the Sumerian cities of
Ur, Kish, and Mari near the Tigris
and Euphrates Rivers around 5,000
B.C. Even today, the distribution of
water among the rice patties of Bali
is the sacred duty of authorities
designated the “Water Priests.”
Our understanding of the behavior of liquids and gases (including
rest when its impetus died out.
In 1687, the English mathematician
Sir Isaac Newton discovered the law
of universal gravitation. The operation of angular momentum-type
mass flowmeters is based directly
on Newton’s second law of angular
motion. In 1742, the French mathematician Rond d’Alembert proved
Volume 4
that Newton’s third law of motion
applies not only to stationary bodies,
but also to objects in motion.
The Flow Pioneers
A major milestone in the understanding of flow was reached in 1783 when
the Swiss physicist Daniel Bernoulli
published his Hydrodynamica. In it,
he introduced the concept of the
conservation of energy for fluid
flows. Bernoulli determined that an
increase in the velocity of a flowing fluid increases its kinetic energy
while decreasing its static energy. It
is for this reason that a flow restriction causes an increase in the flowing
velocity and also causes a drop in
the static pressure of the flowing
fluid.
The permanent pressure loss
through a flowmeter is expressed
either as a percentage of the total
pressure drop or in units of velocity
heads, calculated as V2/2g, where V
is the flowing velocity and g is the
gravitational acceleration (32.2 feet/
second2 or 9.8 meters/second2 at
60° latitude). For example, if the
velocity of a flowing fluid is 10 ft/s,
the velocity head is 100/64.4 = 1.55
ft. If the fluid is water, the velocity
head corresponds to 1.55 ft of water
(or 0.67 psi). If the fluid is air, then
the velocity head corresponds to the
weight of a 1.55-ft column of air.
The permanent pressure loss
through various flow elements can
be expressed as a percentage of the
total pressure drop (Figure 1-1), or it
can be expressed in terms of velocity heads. The permanent pressure
loss through an orifice is four velocity heads; through a vortex shedding
sensor, it is two; through positive
TRANSACTIONS
displacement and turbine meters,
about one; and, through flow venturis,
less than 0.5 heads. Therefore, if an
orifice plate (Figure 1-2) with a beta
where C is the constant for units
conversion.
Over the past several years, the
changed.
In 1883, the British mechanical engineer Osborne Reynolds proposed a
single, dimensionless ratio to describe
the velocity profile of flowing fluids:
Re = DVρ/μ
ratio of 0.3 (diameter of the orifice
to that of the pipe) has an unrecovered pressure loss of 100 in H2O, a
venturi flow tube could reduce that
pressure loss to about 12 in H2O for
the same measurement.
In 1831, the English scientist Michael
Faraday discovered the dynamo when
he noted that, if a copper disk is
rotated between the poles of a permanent magnet, electric current is
generated. Faraday’s law of electromagnetic induction is the basis for the
operation of the magnetic flowmeter.
As shown in Figure 1-3, when a liquid
conductor moves in a pipe having a
diameter (D) and travels with an average velocity (V) through a magnetic
field of B intensity, it will induce a
voltage (E) according to the relationship:
performance of magnetic flowmeters
has improved significantly. Among
the advances are probe and ceramic
insert designs and the use of pulsed
magnetic fields (Figure 1-4), but the
basic operating principle of Faraday’s
law of electric induction has not
Where D is the pipe diameter, V is
the fluid velocity, ρ is the fluid density, and μ is the fluid viscosity.
He noted that, at low Reynolds
numbers (below 2,000) (Figure 1-5),
flow is dominated by viscous forces
and the velocity profile is (elongated)
parabolic. At high Reynolds numbers
(above 20,000), the flow is dominated by inertial forces, resulting in
a more uniform axial velocity across
the flowing stream and a flat velocity
profile.
Until 1970 or so, it was believed
that the transition between laminar
and turbulent flows is gradual, but
increased understanding of turbulence through supercomputer modeling has shown that the onset of
turbulence is abrupt.
When flow is turbulent, the pressure drop through a restriction is
proportional to the square of the
flowrate. Therefore, flow can be
measured by taking the square root
D
E = BVDC
TRANSACTIONS
Volume 4
09
of a differential pressure cell output.
When the flow is laminar, a linear
relationship exists between flow and
pressure drop. Laminar flowmeters
are used at very low flowrates (capillary flowmeters) or when the viscos-
ity of the process fluid is high.
In the case of some flowmeter
technologies, more than a century
elapsed between the discovery of
a scientific principle and its use in
building a flowmeter. This is the case
with both the Doppler ultrasonic and
the Coriolis meter.
In 1842, the Austrian physicist
Christian Doppler discovered that, if a
sound source is approaching a receiver (such as a train moving toward a
stationary listener), the frequency of
the sound will appear higher. If the
source and the recipient are moving
away from each other, the pitch will
drop (the wavelength of the sound
will appear to decrease). Yet it was
more than a century later that the first
ultrasonic Doppler flowmeter came
on the market. It projected a 0.5-MHz
beam into a flowing stream containing
reflectors such as bubbles or particles.
The shift in the reflected frequency
was a function of the average traveling
10
Volume 4
velocity of the reflectors. This speed,
in turn, could be used to calculate a
flowrate.
The history of the Coriolis flowmeter is similar. The French civil
engineer Gaspard Coriolis discovered
in 1843 that the wind, the ocean
currents, and even airborne artillery
shells will all drift sideways because
of the earth’s rotation. In the northern
hemisphere, the deflection is to the
right of the motion; in the southern
hemisphere, it is to the left. Similarly,
a body traveling toward either pole
will veer eastward, because it retains
the greater eastward rotational
speed of the lower altitudes as it
passes over the more slowly rotating
earth surface near the poles. Again,
it was the slow evolution of sensors
and electronics that delayed creation
of the first commercial Coriolis mass
flowmeter until the 1970’s.
It was the Hungarian-American
aeronautical engineer Theodore
von Karman who, as a child growing
up in Transylvania (now Romania),
noticed that stationary rocks caused
vortices in flowing water, and that
the distances between these traveling vortices are constant, no matter
how fast or slow the water runs.
dent of wind velocity and depends
solely on the diameter of the flag
pole. This is the theory behind the
vortex flowmeter, which determines
flow velocity by counting the number of vortices passing a sensor.
Von Karman published his findings
in 1954, and because by that time
the sensors and electronics required
to count vortices were already in
existence, the first edition of the
Instrument Engineers’ Handbook in
1968 was able to report the availability of the first swirlmeter.
The computer has opened new
frontiers in all fields of engineering,
and flow measurement is no exception. It was only as long ago as 1954
that another Hungarian-American
mathematician, John Von Neumann,
built Uniac—and even more recently that yet another HungarianAmerican, Andy Grove of Intel,
developed the integrated circuit. Yet
these events are already changing
the field of flowmetering. Intelligent
differential pressure cells, for example, can automatically switch their
range between two calibrated spans
(one for 1-10%, the other for 10-100%
of D/P), extending orifice accuracy
to within 1% over a 10:1 flow range.
Flow measurement options run the gamut from simple, economical paddle wheels (shown) to
sophisticated high-accuracy devices.
Later in life, he also observed that,
when a flag flutters in the wind, the
wavelength of the flutter is indepen-
Furthermore, it is possible to include
in this accuracy statement not only
hysteresis, rangeability, and linearity
TRANSACTIONS
effects, but also drift, temperature,
humidity, vibration, over-range, and
power supply variation effects.
With the development of superchips, the design of the universal
flowmeter also has become feasible.
It is now possible to replace dyetagging or chemical-tracing meters
(which measured flow velocity by
dividing the distance between two
points by the transit time of the
trace), with traceless cross-correlation flowmeters (Figure 1-6). This
is an elegant flowmeter because it
requires no physical change in the
process—not even penetration of
the pipe. The measurement is based
on memorizing the noise pattern in
any externally detectable process
variable, and, as the fluid travels
from point A to point B, noting its
transit time.
a device because it is less expensive.
Those “inexpensive” purchases can be
the most costly installations.
The basis of good flowmeter
selection is a clear understanding of
the requirements of the particular
application. Therefore, time should
be invested in fully evaluating the
nature of the process fluid and of
the overall installation. The develop-
requiring that the following types of
data be filled in for each application:
• Fluid and flow characteristics:
In this section of the table, the
name of the fluid is given and its
pressure, temperature, allowable
pressure drop, density (or specific
gravity), conductivity, viscosity
(Newtonian or not?) and vapor
pressure at maximum operating
ment of specifications that state the
application requirements should be a
systematic, step-by-step process.
The first step in the flow sensor
selection process is to determine if
the flowrate information should be
continuous or totalized, and whether
this information is needed locally
or remotely. If remotely, should the
transmission be analog, digital, or
shared? And, if shared, what is the
required (minimum) data-update frequency? Once these questions are
answered, an evaluation of the properties and flow characteristics of the
process fluid, and of the piping that
will accommodate the flowmeter,
should take place (Table 1-I). In order
to approach this task in a systematic
manner, forms have been developed,
temperature are listed, together
with an indication of how these
properties might vary or interact.
In addition, all safety or toxicity
information should be provided,
together with detailed data on the
fluid’s composition, presence of
bubbles, solids (abrasive or soft,
size of particles, fibers), tendency to coat, and light transmission
qualities (opaque, translucent or
transparent?).
• Expected minimum and maximum
pressure and temperature values
should be given in addition to the
normal operating values. Whether
flow can reverse, whether it does
not always fill the pipe, whether
slug flow can develop (air-solidsliquid), whether aeration or pul-
Flow Sensor Selection
The purpose of this section is to
provide information to assist the
reader in making an informed selection of flowmeter for a particular
application. Selection and orientation tables are used to quickly
focus on the most likely candidates
for measurement. Tables 1-I and 1-II
have been prepared to make available a large amount of information
for this selection process.
At this point, one should consider
such intangible factors as familiarity of
plant personnel, their experience with
calibration and maintenance, spare
parts availability, mean time between
failure history, etc., at the particular
plant site. It is also recommended that
the cost of the installation be computed only after taking these steps.
One of the most common flow measurement mistakes is the reversal of
this sequence: instead of selecting a
sensor which will perform properly, an
attempt is made to justify the use of
TRANSACTIONS
Volume 4
11
sation is likely, whether sudden
temperature changes can occur,
or whether special precautions are
needed during cleaning and maintenance, these facts, too, should be
stated.
• Concerning
the piping and the
area where the flowmeter is to be
located, the following information
should be specified: For the piping, its direction (avoid downward
flow in liquid applications), size,
material, schedule, flange-pressure
rating, accessibility, up or downstream turns, valves, regulators, and
available straight-pipe run lengths.
• In connection with the area, the
specifying engineer must know if
vibration or magnetic fields are
present or possible, if electric or
pneumatic power is available, if the
area is classified for explosion haz12
Volume 4
ards, or if there are other special
requirements such as compliance
with sanitary or clean-in-place
(CIP) regulations.
The next step is to determine the
required meter range by identify-
ing minimum and maximum flows
(mass or volumetric) that will be
measured. After that, the required
flow measurement accuracy is determined. Typically accuracy is specified in percentage of actual reading (AR), in percentage of calibrated
span (CS), or in percentage of full
scale (FS) units. The accuracy requirements should be separately stated
at minimum, normal, and maximum
flowrates. Unless you know these
requirements, your meter’s performance may not be acceptable over
its full range.
Accuracy vs. Repeatability
In applications where products are
sold or purchased on the basis of a
meter reading, absolute accuracy is
critical. In other applications, repeatability may be more important than
absolute accuracy. Therefore, it is
advisable to establish separately the
accuracy and repeatability requirements of each application and to
state both in the specifications.
When a flowmeter’s accuracy is
stated in % CS or % FS units, its absolute error will rise as the measured
flow rate drops. If meter error is
stated in % AR, the error in absolute
terms stays the same at high or low
flows. Because full scale (FS) is always
a larger quantity than the calibrated
span (CS), a sensor with a % FS performance will always have a larger
error than one with the same % CS
specification. Therefore, in order to
compare all bids fairly, it is advisable
to convert all quoted error statements into the same % AR units.
It is also recommended that the
user compare installations on the
basis of the total error of the loop.
For example, the inaccuracy of an orifice plate is stated in % AR, while the
error of the associated d/p cell is in
% CS or % FS. Similarly, the inaccuracy
of a Coriolis meter is the sum of two
errors, one given in % AR, the other
as a % FS value. Total inaccuracy is
calculated by taking the root of the
sum of the squares of the component
inaccuracies at the desired flow rates.
In well-prepared flowmeter specifications, all accuracy statements are
converted into uniform % AR units and
these % AR requirements are specified
separately for minimum, normal, and
maximum flows. All flowmeter specifications and bids should clearly state
both the accuracy and the repeatability of the meter at minimum, normal,
and maximum flows.
TRANSACTIONS
Table 1 provides data on the range
of Reynolds numbers (Re or RD) within
which the various flowmeter designs
can operate. In selecting the right
flowmeter, one of the first steps is to
determine both the minimum and the
maximum Reynolds numbers for the
application. Maximum RD is obtained
TRANSACTIONS
by making the calculation when flow
and density are at their maximum and
viscosity at its minimum. Conversely,
the minimum RD is obtained by using
minimum flow and density and maximum viscosity.
If acceptable metering performance
can be obtained from two different
flowmeter categories and one has
no moving parts, select the one
without moving parts. Moving parts
are a potential source of problems,
not only for the obvious reasons
of wear, lubrication, and sensitivity
to coating, but also because moving parts require clearance spaces
Volume 4
13
that sometimes introduce “slippage”
into the flow being measured. Even
with well maintained and calibrated
meters, this unmeasured flow varies
with changes in fluid viscosity and
14
Volume 4
temperature. Changes in temperature
also change the internal dimensions of
the meter and require compensation.
Furthermore, if one can obtain
the same performance from both a
full flowmeter and a point sensor,
it is generally advisable to use the
flowmeter. Because point sensors do
not look at the full flow, they read
accurately only if they are inserted
TRANSACTIONS
to a depth where the flow velocity is the average of the velocity
profile across the pipe. Even if this
point is carefully determined at the
time of calibration, it is not likely to
remain unaltered, since velocity profiles change with flowrate, viscosity,
temperature, and other factors.
If all other considerations are the
same, but one design offers less pressure loss, it is advisable to select that
design. Part of the reason is that the
pressure loss will have to be paid
for in higher pump or compressor
operating costs over the life of the
plant. Another reason is that a pressure drop is caused by any restriction
in the flow path, and wherever a
pipe is restricted becomes a potential
site for material build-up, plugging, or
cavitation.
Before specifying a flowmeter, it is
also advisable to determine whether
the flow information will be more
useful if presented in mass or volumetric units. When measuring the
flow of compressible materials, volumetric flow is not very meaningful
unless density (and sometimes also
viscosity) is constant. When the velocity (volumetric flow) of incompressible liquids is measured, the presence of suspended bubbles will cause
error; therefore, air and gas must be
removed before the fluid reaches the
meter. In other velocity sensors, pipe
liners can cause problems (ultrasonic),
or the meter may stop functioning if
the Reynolds number is too low (in
vortex shedding meters, RD > 20,000 is
required).
In view of these considerations,
mass flowmeters, which are insensitive to density, pressure and viscosity variations and are not affected
by changes in the Reynolds number,
should be kept in mind. Also underutilized in the chemical industry are
the various flumes that can measure
TRANSACTIONS
References & Further Reading
•OMEGA
Complete Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•“Advanced Process Control for Two-Phase Mixtures,” David Day,
Christopher Reiner and Michael Pepe, Measurements & Control, June,
1997.
•Applied Fluid Flow Measurement, N.P. Cheremisinoff, Marcel Decker, 1979.
•“Characteristics and Applications of Industrial Thermal Mass Flow
Transmitters,” Jerome L. Kurz, Proceedings 47th Annual Symposium on
Instrumentation for the Process Industries, ISA, 1992.
•Developments in Thermal Flow Sensors, Jerome L. Kurz, Ph.D., Kurz
Instruments Inc., 1987.
•“Differential Flow Measurement of Meter-Conditioned Flow,” Stephen A.
Ifft and Andrew J. Zacharias, Measurements & Control, September, 1993.
•Dry Solids Flow Update, Auburn International Inc.
•Flow Measurement Engineering Handbook, R.W. Miller, McGraw-Hill, 1983.
•Flow Measurement for Engineers and Scientists, N.P. Cheremisinoff,
Marcel Dekker, 1988.
•Flow Measurement, Bela Liptak, CRC Press, 1993.
•“Flowmeter Geometry Improves Measurement Accuracy,” Stephen A.
Ifft, Measurements & Control, October, 1995.
•Flowmeters, F. Cascetta, P. Vigo, ISA, 1990.
•Fluidic Flowmeter, Bulletin 1400 MX, Moore Products Co., June, 1988.
•Fundamentals of Flow Metering, Technical Data Sheet 3031, Rosemount
Inc., 1982.
•Guide to Variable Area Flowmeters, Application No.: T-022 Issue I,
Brooks Instrument Co., 1986.
•Incompressible Flow, Donald Panton, Wiley, 1996.
•Industrial Flow Measurement, D.W. Spitzer, ISA, 1984.
•“Installation Effects on Venturi Tube Flowmeters”, G. Kochen, D.J.M.
Smith, and H. Umbach, Intech, October, 1989.
•Instrument Engineers’ Handbook, Bela Liptak, ed., CRC Press, 1995.
•“Is a Turbine Flowmeter Right for Your Application?” Michael Hammond,
Flow Control, April, 1998.
•“Mass Flowmeters,” Measurements & Control, September, 1991.
•Microprocessor-Based 2-Wire Swirlmeter, Bailey-Fischer & Porter Co., 1995.
•“Process Gas Mass Flow Controllers: An Overview,” J. G. Olin, Solid State
Technology, April, 1988.
•“Target Flowmeters,” George W. Anderson, Measurements & Control,
June, 1982.
•Thermal Approach to Flow Measurement, Joseph W. Harpster and
Robert Curry, Intek, Inc. 1991.
•“Ultrasonic Flowmeter Basics,” Gabor Vass, Sensors, October, 1997.
•“Ultrasonic Flowmeters Pick Up Speed,” Murry Magness, Control, April, 1996.
•“User Tips for Mass, Volume Flowmeters,” Donald Ginesi and Carl
Annarummo, Intech, April, 1994.
Volume 4
15
T
Differential Pressure Flowmeters
he calculation of fluid flow
rate by reading the pressure
loss across a pipe restriction
is perhaps the most commonly used flow measurement technique
in industrial applications (Figure 2-1).
The pressure drops generated by a
wide variety of geometrical restrictions have been well characterized
over the years, and, as compared
in Table 2, these primary or “head”
flow elements come in a wide variety
of configurations, each with specific
application strengths and weaknesses.
Variations on the theme of differential pressure (d/p) flow measurement
include the use of pitot tubes and
variable-area meters (rotameters), and
are discussed later in this chapter.
Primary Element Options
In the 18th century, Bernoulli first
established the relationship between
static and kinetic energy in a flowing
stream. As a fluid passes through
a restriction, it accelerates, and
the energy for this acceleration is
obtained from the fluid’s static pressure. Consequently, the line pressure
drops at the point of constriction
(Figure 2-1). Part of the pressure drop
is recovered as the flow returns to
16
Volume 4
the unrestricted pipe. The pressure
differential (h) developed by the flow
element is measured, and the velocity
(V), the volumetric flow (Q) and the
mass flow (W) can all be calculated
using the following generalized formulas:
V = k (h/D)0.5
or Q =kA(h/D)0.5
or W= kA(hD)0.5
k is the discharge coefficient of
the element (which also reflects
the units of measurement), A is the
cross-sectional area of the pipe’s
opening, and D is the density of the
flowing fluid. The discharge coefficient k is influenced by the Reynolds
number (see Figure 1-5) and by the
“beta ratio,” the ratio between the
bore diameter of the flow restriction
and the inside diameter of the pipe.
Additional parameters or correction factors can be used in the
derivation of k, depending on the
type of flow element used. These
parameters can be computed from
equations or read from graphs and
tables available from the American
National Standards Institute (ANSI),
the American Petroleum Institute
(API), the American Society of
Mechanical Engineers (ASME), and the
American Gas Association (AGA), and
are included in many of the works
listed as references at the end of this
chapter.
The discharge coefficients of primary elements are determined by laboratory tests that reproduce the geometry of the installation. Published values
generally represent the average value
for that geometry over a minimum of
30 calibration runs. The uncertainties
of these published values vary from
0.5% to 3%. By using such published
discharge coefficients, it is possible to
obtain reasonably accurate flow measurements without in-place calibration. In-place calibration is required
if testing laboratories are not available or if better accuracy is desired
than that provided by the uncertainty
range noted above. The relationship
between flow and pressure drop varies with the velocity profile, which can
be laminar or turbulent (Figure 2-1) as a
function of the Reynolds number (Re),
which for liquid flows can be calculated using the relationship:
Re = 3160(SG)(Q)/(ID)μ
where ID is the inside diameter of
the pipe in inches, Q is the volumetric liquid flow in gallons/minute, SG
is the fluid specific gravity at 60°F,
and μ is the viscosity in centipoises.
At low Reynolds numbers (generally under Re = 2,000), the flow is
laminar and the velocity profile is
parabolic. At high Reynolds numbers (well over Re = 3,000), the flow
becomes fully turbulent, and the
resulting mixing action produces a
uniform axial velocity across the
TRANSACTIONS
pipe. As shown in Figure 1-5, the
transition between laminar and turbulent flows can cover a wide range
of Reynolds numbers; the relationship with the discharge coefficient is
a function of the particular primary
element.
Today, many engineering societies
and organizations and most primary
element manufacturers offer software packages for sizing d/p flow
elements. These programs include
the required data from graphs, charts,
and tables as well as empirical equations for flow coefficients and correction factors. Some include data
on the physical properties of many
common fluids. The user can simply
TRANSACTIONS
enter the application data and automatically find the recommended
size, although these results should
be checked for reasonableness by
hand calculation.
The performance of a head-type
that, at the low end of a 10:1 flow
range (at 10% flow), corresponding
to a differential pressure range of
100:1, the flowmeter would have an
error of ±20% AR. For this reason,
differential producing flowmeters
have historically been limited to use
within a 3:1 or 4:1 range.
flowmeter installation is a function
of the precision of the flow element and of the accuracy of the
d/p cell. Flow element precision is
typically reported in percentage of
actual reading (AR) terms, whereas
d/p cell accuracy is a percentage of
calibrated span (CS). A d/p cell usually provides accuracy of ±0.2% of
the calibrated span (CS). This means
Flowmeter rangeability can be further increased without adverse effect
on accuracy by operating several d/p
flowmeters in parallel runs. Only as
many runs are opened at a time as
are needed to keep the flow in the
active ones at around 75-90% of
range. Another option is to stack
two or more transmitters in parallel
onto the same element, one for
• Accuracy & Rangeability
Volume 4
17
18
1-10%, the other for 10-100% of full
scale (FS) d/p produced. Both of
these techniques are cumbersome
and expensive. Intelligent transmitters offer a better option.
The accuracy of intelligent transmitters is usually stated as ±0.1%
CS, which includes only errors due
to hysteresis, rangeability and linearity. Potential errors due to drift,
temperature, humidity, vibration,
overrange, radio frequency interference and power supply variation
flow.
To minimize error (and the need
for density correction) when dealing
with compressible fluids, the ratio
of differential pressure (h) divided
by upstream pressure (P) should not
exceed 0.25 (measured in the same
engineering units).
Metering errors due to incorrect installation of the primary
element can be substantial (up to
10%). Causes of such errors can be
the condition of the mating pipe
are all excluded. If one includes
them, inaccuracy is about 0.2% CS.
Because intelligent d/p transmitters
can—based on their own measurements—automatically switch ranges
between two calibrated spans (one
for 1-10%, the other for 10-100% of FS
d/p), it should be possible to obtain
orifice installations with 1% AR inaccuracy over a 10:1 flow range.
In most flowmetering applications,
density is not measured directly.
Rather, it is assumed to have some
normal value. If density deviates from
this assumed value, error results.
Density error can be corrected if it
is measured directly or indirectly by
measuring pressure in gases or temperature in liquids. Flow computing
packages are also available that accept
the inputs of the d/p transmitter and
the other sensors and can simultaneously calculate mass and volumetric
sections, insufficient straight pipe
runs, and pressure tap and lead line
design errors.
Under turbulent flow conditions,
as much as 10% of the d/p signal
can be noise caused by disturbances
from valves and fittings, both upand downstream of the element, and
by the element itself. In the majority
of applications, the damping provided in d/p cells is sufficient to filter
out the noise. Severe noise can be
reduced by the use of two or more
pressure taps connected in parallel
on both sides of the d/p cell.
Pulsating flow can be caused by
reciprocating pumps or compressors.
This pulsation can be reduced by
moving the flowmeter away from
the source of the pulse, or downstream of filters or other dampening
devices. Pulsation dampening hardware can also be installed at the
Volume 4
pressure taps, or dampening software can applied to the d/p cell
output signal. One such filter is the
inverse derivative algorithm, which
blocks any rate of change occurring
more quickly than the rate at which
the process flow can change.
• Piping, Installation, & Maintenance
Installation guidelines are published
by various professional organizations (ISA, ANSI, API, ASME, AGA)
and
by manufacturers of pro-
prietary designs. These guidelines
include such recommendations as:
• When, in addition to measuring
the flow, the process temperature
or pressure is also to be measured,
the pressure transmitter should
not be installed in the process
pipe, but should be connected to
the appropriate lead line of the
flow element via a tee.
• Similarly, the thermowell used for
temperature measurement should
be installed at least 10 diameters
downstream of the flow element,
to prevent velocity profile distortions.
• Welds should be ground smooth
and gaskets trimmed so that no
protrusion can be detected by
physical inspection.
In order for the velocity profile
to fully develop (and the pressure
drop to be predictable), straight
TRANSACTIONS
pipe runs are required both up- and
downstream of the d/p element.
The amount of straight run required
depends on both the beta ratio of
the installation and on the nature
of the upstream components in the
pipeline. For example, when a single
90° elbow precedes an orifice plate,
the straight-pipe requirement ranges
from 6 to 20 pipe diameters as the
diameter ratio is increased from 0.2 to
0.8.
In order to reduce the straight
run requirement, flow straighteners
(Figure 2-2) such as tube bundles,
perforated plates, or internal tabs
can be installed upstream of the
primary element.
The size and orientation of the
pressure taps are a function of both
the pipe size and the type of process fluid. The recommended maximum diameter of pressure tap holes
through the pipe or flange is G" for
pipes under 2" in diameter, K" for 2"
and 3" pipes, H" for 4 to 8" and I" for
larger pipes. Both taps should be
of the same diameter, and, where
the hole breaks through the inside
pipe surface, it should be square
with no roughness, burrs, or wire
edges. Connections to pressure
holes should be made by nipples,
couplings, or adaptors welded to the
outside surface of the pipe.
On services where the process
fluid can plug the pressure taps
or might gel or freeze in the lead
lines, chemical seal protectors
can be used. Connection sizes are
usually larger (seal elements can
also be provided with diaphragm
extensions), and, because of the
space requirement, they are usually installed at “radius tap” or
“pipe tap” locations, as shown in
Figure 2-3. When chemical seals are
used, it is important that the two
connecting capillaries, as they are
TRANSACTIONS
routed to the d/p cell, experience
the same temperature and are kept
shielded from sunlight.
The d/p transmitter should be
located as close to the primary element as possible. Lead lines should
be as short as possible and of the
same diameter. In clean liquid service, the minimum diameter is G",
while in condensable vapor service,
the minimum diameter is 0.4". In
steam service, the horizontal lead
lines should be kept as short as possible and be tilted (with a minimum
gradient of 1 in/ft with respect to
the piping) towards the tap, so that
condensate can drain back into the
pipe. Again, both lead lines should be
height condensate legs on both sides
of the d/p cell. If for some reason
the two legs are not of equal height,
the d/p cell can be biased to zero
out the difference, as long as that
difference does not change.
If the process temperature exceeds
the maximum temperature limitation
of the d/p cell, either chemical seals
have to be used or the lead lines need
to be long enough to cool the fluid. If
a large temperature drop is required,
a coiled section of tubing (pigtail) can
be installed in the lead lines to cool
the process fluids.
The frequency of inspection or
replacement of a primary element
depends on the erosive and cor-
exposed to the same ambient conditions and be shielded from sunlight.
In clean liquid or gas service, the lead
lines can be purged through the d/p
cell vent or drain connections, and
they should be flushed for several
minutes to remove all air from the
lines. Entrapped air can offset the
zero calibration.
Seal pots are on the wet leg in d/p
cell installations with small ranges
(under 10 in H2O) in order to minimize the level variation in the legs.
In steam applications, filling tees
are recommended to ensure equal
rosive nature of the process and
on the overall accuracy required.
If there is no previous experience,
the orifice plate can be removed for
inspection during the first three, six,
and 12 months of its operation. Based
on visual inspection of the plate, a
reasonable maintenance cycle can
be extrapolated from the findings.
Orifices used for material balance
calculations should be on the same
maintenance cycle.
• Sizing the Orifice Plate
The orifice plate is commonly used
Volume 4
19
20
in clean liquid, gas, and steam service. It is available for all pipe sizes,
and if the pressure drop it requires
is free, it is very cost-effective for
measuring flows in larger pipes (over
6" diameter). The orifice plate is also
approved by many standards organizations for the custody transfer of
liquids and gases.
The orifice flow equations used
today still differ from one another,
although the various standards organizations are working to adopt a single, universally accepted orifice flow
equation. Orifice sizing programs
usually allow the user to select the
flow equation desired from among
several.
The orifice plate can be made of
any material, although stainless steel
is the most common. The thickness
of the plate used (J-H") is a function
of the line size, the process tempera-
ever the plate is removed for maintenance or inspection. In contrast, an
orifice fitting allows the orifice to be
removed from the process without
depressurizing the line and shutting
down flow. In such fittings, the universal orifice plate, a circular plate
with no tab, is used.
The concentric orifice plate
(Figure 2-4A) has a sharp (squareedged) concentric bore that provides an almost pure line contact
between the plate and the fluid, with
negligible friction drag at the boundary. The beta (or diameter) ratios of
concentric orifice plates range from
0.25 to 0.75. The maximum velocity
and minimum static pressure occurs
at some 0.35 to 0.85 pipe diameters downstream from the orifice
plate. That point is called the vena
contracta. Measuring the differential
pressure at a location close to the
under 2 inches in diameter. Corner
taps are predominant in Europe for
all sizes of pipe, and are used in the
United States for pipes under 2 inches
(Figure 2-3). With corner taps, the
relatively small clearances represent a potential maintenance problem. Vena contracta taps (which
are close to the radius taps, Figure
2-4) are located one pipe diameter upstream from the plate, and
downstream at the point of vena
contracta. This location varies (with
beta ratio and Reynolds number)
from 0.35D to 0.8D.
The vena contracta taps provide
the maximum pressure differential,
but also the most noise. Additionally,
if the plate is changed, it may require
a change in the tap location. Also,
in small pipes, the vena contracta
might lie under a flange. Therefore,
vena contracta taps normally are
ture, the pressure, and the differential pressure. The traditional orifice
is a thin circular plate (with a tab for
handling and for data), inserted into
the pipeline between the two flanges of an orifice union. This method
of installation is cost-effective, but it
calls for a process shutdown when-
orifice plate minimizes the effect of
pipe roughness, since friction has an
effect on the fluid and the pipe wall.
Flange taps are predominantly
used in the United States and are
located 1 inch from the orifice plate’s
surfaces (Figure 2-3). They are not
recommended for use on pipelines
used only in pipe sizes exceeding six
inches.
Radius taps are similar to vena
contracta taps, except the downstream tap is fixed at 0.5D from the
orifice plate (Figure 2-3). Pipe taps are
located 2.5 pipe diameters upstream
and 8 diameters downstream from
Volume 4
TRANSACTIONS
the orifice (Figure 2-3). They detect
the smallest pressure difference
and, because of the tap distance
from the orifice, the effects of pipe
roughness, dimensional inconsistencies, and, therefore, measurement
errors are the greatest.
• Orifice Types & Selection
The concentric orifice plate is recommended for clean liquids, gases,
and steam flows when Reynolds
numbers range from 20,000 to 107 in
pipes under six inches. Because the
basic orifice flow equations assume
that flow velocities are well below
sonic, a different theoretical and
computational approach is required
if sonic velocities are expected. The
minimum recommended Reynolds
number for flow through an orifice
(Figure 1-5) varies with the beta ratio
of the orifice and with the pipe size.
In larger size pipes, the minimum
Reynolds number also rises.
Because of this minimum Reynolds
number consideration, square-edged
orifices are seldom used on viscous
fluids. Quadrant-edged and conical
orifice plates (Figure 2-5) are recommended when the Reynolds number
is under 10,000. Flange taps, corner,
and radius taps can all be used with
quadrant-edged orifices, but only
corner taps should be used with a
conical orifice.
Concentric orifice plates can be
provided with drain holes to prevent buildup of entrained liquids in
gas streams, or with vent holes for
venting entrained gases from liquids
(Figure 2-4A). The unmeasured flow
passing through the vent or drain
hole is usually less than 1% of the
total flow if the hole diameter is
less than 10% of the orifice bore.
The effectiveness of vent/drain
holes is limited, however, because
they often plug up.
TRANSACTIONS
Concentric orifice plates are
not recommended for multi-phase
fluids in horizontal lines because
the secondary phase can build up
around the upstream edge of the
plate. In extreme cases, this can
clog the opening, or it can change
the flow pattern, creating measurement error. Eccentric and segmental orifice plates are better suited
for such applications. Concentric
orifices are still preferred for
multi-phase flows in vertical lines
orifice is greater than that of the
eccentric orifice, and, therefore, it is
preferred in applications with high
proportions of the secondary phase.
These plates are usually used in pipe
sizes exceeding four inches in diameter, and must be carefully installed
to make sure that no portion of the
flange or gasket interferes with the
opening. Flange taps are used with
both types of plates, and are located
in the quadrant opposite the opening for the eccentric orifice, in line
because accumulation of material
is less likely and the sizing data for
these plates is more reliable.
The eccentric orifice (Figure 2-4B)
is similar to the concentric except
that the opening is offset from the
pipe’s centerline. The opening of the
segmental orifice (Figure 2-4C) is a
segment of a circle. If the secondary phase is a gas, the opening of
an eccentric orifice will be located
towards the top of the pipe. If the
secondary phase is a liquid in a gas or
a slurry in a liquid stream, the opening
should be at the bottom of the pipe.
The drainage area of the segmental
with the maximum dam height for
the segmental orifice.
For the measurement of low flow
rates, a d/p cell with an integral
orifice may be the best choice. In
this design, the total process flow
passes through the d/p cell, eliminating the need for lead lines. These
are proprietary devices with little
published data on their performance;
their flow coefficients are based on
actual laboratory calibrations. They
are recommended for clean, singlephase fluids only because even small
amounts of build-up will create significant measurement errors or will
Volume 4
21
Although it is a simple device, the
calculations, the quality of the installation, and the condition of the plate
itself determine total performance.
Installation factors include tap location and condition, condition of the
process pipe, adequacy of straight
pipe runs, gasket interference, misalignment of pipe and orifice bores,
and lead line design. Other adverse
conditions include the dulling of the
sharp edge or nicks caused by corrosion or erosion, warpage of the plate
due to waterhammer and dirt, and
grease or secondary phase deposits
on either orifice surface. Any of the
above conditions can change the ori-
orifice plate is, in principle, a precision instrument. Under ideal conditions, the inaccuracy of an orifice
plate can be in the range of 0.75-1.5%
AR. Orifice plates are, however, quite
sensitive to a variety of error-inducing conditions. Precision in the bore
fice discharge coefficient by as much
as 10%. In combination, these problems can be even more worrisome
and the net effect unpredictable.
Therefore, under average operating
conditions, a typical orifice installation can be expected to have an
clog the unit.
Restriction orifices are installed to
remove excess pressure and usually operate at sonic velocities with
very small beta ratios. The pressure
drop across a single restriction orifice
should not exceed 500 psid because
of plugging or galling. In multi-element restriction orifice installations,
the plates are placed approximately
one pipe diameter from one another
in order to prevent pressure recovery
between the plates.
• Orifice Performance
22
Volume 4
overall inaccuracy in the range of 2
to 5% AR.
The typical custody-transfer
grade orifice meter is more accurate because it can be calibrated in
a testing
laboratory and is provided with honed pipe sections, flow
straighteners, senior orifice fittings,
and temperature controlled enclosures.
• Venturi & Flowtubes
Venturi tubes are available in sizes
up to 72", and can pass 25 to 50%
more flow than an orifice with the
same pressure drop. Furthermore,
the total unrecovered head loss
rarely exceeds 10% of measured
d/p (Figure 2-6). The initial cost of
venturi tubes is high, so they are
primarily used on larger flows or on
more difficult or demanding flow
applications. Venturis are insensitive to velocity profile effects and
therefore require less straight pipe
run than an orifice. Their contoured
nature, combined with the selfscouring action of the flow through
the tube, makes the device immune
to corrosion, erosion, and internal
scale build up. In spite of its high
initial cost, the total cost of ownership can still be favorable because
of savings in installation and operating and maintenance costs.
The classical Herschel venturi has a
very long flow element characterized
by a tapered inlet and a diverging
outlet. Inlet pressure is measured at
the entrance, and static pressure in
the throat section. The pressure taps
feed into a common annular chamber,
providing an average pressure reading over the entire circumference of
the element. The classical venturi is
limited in its application to clean,
non-corrosive liquids and gases.
In the short form venturi, the
entrance angle is increased and the
TRANSACTIONS
annular chambers are replaced by
pipe taps (Figure 2-7A). The shortform venturi maintains many of the
affected by calibration. The inaccuracy of the discharge coefficient in a
universal venturi, at Reynolds num-
lines. Plunger-like devices (vent cleaners) can be installed to periodically
remove buildup from interior open-
advantages of the classical venturi,
but at a reduced initial cost, shorter
length and reduced weight. Pressure
taps are located G to H pipe diameter upstream of the inlet cone, and
in the middle of the throat section.
Piezometer rings can be used with
large venturi tubes to compensate
for velocity profile distortions. In
slurry service, the pipe taps can be
purged or replaced with chemical
seals, which can eliminate all deadended cavities.
There are several proprietary
flowtube designs which provide
even better pressure recovery than
the classical venturi. The best known
of these proprietary designs is the
universal venturi (Figure 2-7B). The
various flowtube designs vary in their
contours, tap locations, generated
d/p and in their unrecovered head
loss. They all have short lay lengths,
typically varying between 2 and 4
pipe diameters. These proprietary
flowtubes usually cost less than the
classical and short-form venturis
because of their short lay length.
However, they may also require
more straight pipe run to condition
their flow velocity profiles.
Flowtube performance is much
bers exceeding 75,000, is 0.5%. The
inaccuracy of a classical venturi at
Re > 200,000 is between 0.7 and 1.5%.
Flowtubes are often supplied with
discharge coefficient graphs because
the discharge coefficient changes
as the Reynolds number drops. The
variation in the discharge coefficient
of a venturi caused by pipe roughness is less than 1% because there
is continuous contact between the
fluid and the internal pipe surface.
The high turbulence and the lack
of cavities in which material can
accumulate make flow tubes well
ings, even while the meter is online.
Lead lines can also be replaced with
button-type seal elements hydraulically coupled to the d/p transmitter
using filled capillaries. Overall measurement accuracy can drop if the
chemical seal is small, its diaphragm
is stiff, or if the capillary system
is not temperature-compensated or
not shielded from direct sunlight.
TRANSACTIONS
suited for slurry and sludge services.
However, maintenance costs can be
high if air purging cannot prevent
plugging of the pressure taps and lead
• Flow Nozzles
The flow nozzle is dimensionally
more stable than the orifice plate,
particularly in high temperature and
high velocity services. It has often
been used to measure high flowrates of superheated steam. The
flow nozzle, like the venturi, has
Volume 4
23
a greater flow capacity than the
orifice plate and requires a lower
initial investment than a venturi
tube, but also provides less pressure recovery (Figure 2-6). A major
disadvantage of the nozzle is that it
is more difficult to replace than the
orifice unless it can be removed as
part of a spool section.
The ASME pipe tap flow nozzle
is predominant in the United States
(Figure 2-7C). The downstream end
of a nozzle is a short tube having the
same diameter as the vena contracta of an equivalent orifice plate. The
low-beta designs range in diameter
ratios from 0.2 to 0.5, while the high
beta-ratio designs vary between
0.45 and 0.8. The nozzle should
always be centered in the pipe,
and the downstream pressure tap
should be inside the nozzle exit. The
throat taper should always decrease
the diameter toward the exit. Flow
nozzles are not recommended for
slurries or dirty fluids. The most
common flow nozzle is the flange
type. Taps are commonly located
one pipe diameter upstream and H
pipe diameter downstream from
the inlet face.
Flow nozzle accuracy is typically
1% AR, with a potential for 0.25% AR
if calibrated. While discharge coef24
Volume 4
ficient data is available for Reynolds
numbers as low as 5,000, it is advisable to use flow nozzles only when
the Reynolds number exceeds 50,000.
Flow nozzles maintain their accuracy for long periods, even in difficult service. Flow nozzles can be
a highly accurate way to measure
gas flows. When the gas velocity
reaches the speed of sound in the
throat, the velocity cannot increase
any more (even if downstream pressure is reduced), and a choked flow
condition is reached. Such “critical
flow nozzles” are very accurate and
often are used in flow laboratories
as standards for calibrating other gas
flowmetering devices.
Nozzles can be installed in any
position, although horizontal orientation is preferred. Vertical downflow is preferred for wet steam,
gases, or liquids containing solids.
The straight pipe run requirements
are similar to those of orifice plates.
• Segmental Wedge Elements
The segmental wedge element (Figure
2-8A) is a proprietary device designed
for use in slurry, corrosive, erosive,
viscous, or high-temperature applications. It is relatively expensive and is
used mostly on difficult fluids, where
the dramatic savings in maintenance
can justify the initial cost. The unique
flow restriction is designed to last
the life of the installation without
deterioration.
Wedge elements are used with
3-in diameter chemical seals, eliminating both the lead lines and any
dead-ended cavities. The seals
attach to the meter body immediately upstream and downstream of
the restriction. They rarely require
cleaning, even in services like dewatered sludge, black liquor, coal slurry,
fly ash slurry, taconite, and crude
oil. The minimum Reynolds number
is only 500, and the meter requires
only five diameters of upstream
straight pipe run.
The segmental wedge has a
V-shaped restriction characterized
by the H/D ratio, where H is the
height of the opening below the
restriction and D is the diameter. The
H/D ratio can be varied to match
the flow range and to produce the
desired d/p. The oncoming flow
creates a sweeping action through
the meter. This provides a scouring
effect on both faces of the restriction, helping to keep it clean and
free of buildup. Segmental wedges
can measure flow in both directions,
but the d/p transmitter must be
calibrated for a split range, or the
flow element must be provided with
two sets of connections for two d/p
transmitters (one for forward and
one for reverse flow).
An uncalibrated wedge element
can be expected to have a 2% to 5%
AR inaccuracy over a 3:1 range. A calibrated wedge element can reduce
that to 0.5% AR if the fluid density is
constant. If slurry density is variable
and/or unmeasured, error rises.
• Venturi-Cone Element
The venturi-cone (V-cone) element
(Figure 2-8B) is another proprietary
TRANSACTIONS
an orifice. Its flow rangeability of
3:1 (some operate at 4:1) is also similar to the capability of the orifice
plate. The main difference is that,
while an orifice measures the full
flowstream, the pitot tube detects
the flow velocity at only one point
in the flowstream. An advantage of
the slender pitot tube is that it can
be inserted into existing and pressurized pipelines (called hot-tapping)
without requiring a shutdown.
• Theory of Operation
design that promises consistent performance at low Reynolds numbers and is
insensitive to velocity profile distortion or swirl effects. Again, however,
it is relatively expensive. The V-cone
restriction has a unique geometry
that minimizes accuracy degradation
due to wear, making it a good choice
for high velocity flows and erosive/
corrosive applications.
The V-cone creates a controlled
turbulence region that flattens the
incoming irregular velocity profile and induces a stable differential pressure that is sensed by a
downstream tap. The beta ratio of
a
V-cone is so defined that an
orifice and a V-cone with equal beta
ratios will have equal opening areas.
Beta ratio = (D2 - d2).05 / D
where d is the cone diameter and D
is the inside diameter of the pipe.
With this design, the beta ratio can
TRANSACTIONS
exceed 0.75. For example, a 3-in meter
with a beta ratio of 0.3 can have a 0 to
75 gpm range. Published test results on
liquid and gas flows place the system
accuracy between 0.25 and 1.2% AR.
Pitot Tubes
Pitot tubes were invented by Henri
Pitot in 1732 to measure the flowing
velocity of fluids. Basically a differential pressure (d/p) flowmeter,
a pitot tube measures two pressures: the static and the total impact
pressure. The static pressure is the
operating pressure in the pipe, duct,
or the environment, upstream to the
pitot tube. It is measured at right
angles to the flow direction, preferably in a low turbulence location
(Figure 2-9).
The total impact pressure (PT) is
the sum of the static and kinetic
Although the pitot tube is one of the
simplest flow sensors, it is used in
a wide range of flow measurement
applications such as air speed in racing cars and Air Force fighter jets. In
industrial applications, pitot tubes
are used to measure air flow in pipes,
ducts, and stacks, and liquid flow
in pipes, weirs, and open channels.
While accuracy and rangeability are
relatively low, pitot tubes are simple,
reliable, inexpensive, and suited for a
variety of environmental conditions,
including extremely high temperatures and a wide range of pressures.
The pitot tube is an inexpensive alternative to an orifice plate.
Accuracy ranges from 0.5% to 5%
FS, which is comparable to that of
Volume 4
25
pressures and is detected as the
flowing stream impacts on the pitot
opening. To measure impact pressure, most pitot tubes use a small,
sometimes L-shaped tube, with the
opening directly facing the oncoming flowstream. The point velocity
of approach (VP) can be calculated
by taking the square root of the difference between the total pressure
(PT) and the static pressure (P) and
multiplying that by the C/D ratio,
where C is a dimensional constant
and D is density:
VP = C(PT - P)H /D
When the flowrate is obtained by
multiplying the point velocity (VP)
by the cross-sectional area of the
pipe or duct, it is critical that the
velocity measurement be made at an
insertion depth which corresponds
to the average velocity. As the flow
velocity rises, the velocity profile
26
Volume 4
in the pipe changes from elongated
(laminar) to more flat (turbulent).
This changes the point of average
velocity and requires an adjustment
of the insertion depth. Pitot tubes
are recommended only for highly
turbulent flows (Reynolds Numbers >
20,000) and, under these conditions,
the velocity profile tends to be flat
enough so that the insertion depth is
not critical.
In 1797, G.B. Venturi developed a
short tube with a throat-like passage that increases flow velocity
and reduces the permanent pressure drop. Special pitot designs are
available that, instead of providing
just an impact hole for opening,
add a single or double venturi to
the impact opening of the pitot
tube. The venturi version generates
a higher differential pressure than
does a regular pitot tube.
• Static Pressure Measurement
In jacketed (dual-walled) pitottube designs, the impact pressure
port faces forward into the flow,
while static ports do not, but are,
instead, spaced around the outer
tube. Both pressure signals (PT and
P) are routed by tubing to a d/p
indicator or transmitter. In industrial
applications, the static pressure (P)
can be measured in three ways: 1)
through taps in the pipe wall; 2) by
static probes inserted in the process stream; or 3) by small openings
located on the pitot tube itself or
on a separate aerodynamic element.
Wall taps can measure static pressures at flow velocities up to 200
ft/sec. A static probe (resembling an
L-shaped pitot tube) can have four
holes of 0.04 inches in diameter,
spaced 90° apart. Aerodynamic bodies can be cylinders or wedges, with
two or more sensing ports.
Errors in detecting static pressure
arise from fluid viscosity, velocity,
and fluid compressibility. The key to
accurate static pressure detection is
Pitot tube shown with associated fittings and
pressure transmitter.
TRANSACTIONS
High
to minimize the kinetic component
in the pressure measurement.
• Single-Port Pitot Tubes
A single-port pitot tube can measure the flow velocity at only a
single point in the cross-section of
a flowing stream (Figure 2-10). The
probe must be inserted to a point in
the flowing stream where the flow
velocity is the average of the velocities across the cross-section, and its
impact port must face directly into
the fluid flow. The pitot tube can be
made less sensitive to flow direction
if the impact port has an internal
bevel of about 15°, extending about
1.5 diameters into the tube.
If the pressure differential generated by the venturi is too low
for accurate detection, the conventional pitot tube can be replaced by
a pitot venturi or a double venturi
sensor. This will produce a higher
pressure differential.
A calibrated, clean and properly
inserted single-port pitot tube can
provide ±1% of full scale flow accuracy over a flow range of 3:1; and,
with some loss of accuracy, it can
even measure over a range of 4:1. Its
advantages are low cost, no moving parts, simplicity, and the fact
that it causes very little pressure
loss in the flowing stream. Its main
limitations include the errors resulting from velocity profile changes
or from plugging of the pressure
ports. Pitot tubes are generally used
for flow measurements of secondary
importance, where cost is a major
concern, and/or when the pipe or
duct diameter is large (up to 72
inches or more).
Specially designed pitot probes
have been developed for use with
pulsating flows. One design uses a
pitot probe filled with silicone oil
to transmit the process pressures to
the d/p cell. At high frequency pulTRANSACTIONS
Pressure
sating applications,
the oil serves as
Profile
a pulsation dampening and pressureaveraging medium.
Pitot tubes also can be used in
square, rectangular or circular air
ducts. Typically, the pitot tube fits
through a 5/16-in diameter hole in
the duct. Mounting can be by a
couple, and a sampling nozzle.
A pitot tube also can be used
to measure water velocity in open
channels, at drops, chutes, or over
fall crests. At the low flow velocities typical of laminar conditions,
pitot tubes are not recommended
because it is difficult to find the
flange or gland. The tube is usually
provided with an external indicator,
so that its impact port can be accurately rotated to face directly into
the flow. In addition, the tube can
be designed for detecting the full
velocity profile by making rapid and
consistent traverses across the duct.
In some applications, such as EPAmandated stack particulate sampling,
it is necessary to traverse a pitot
sampler across a stack or duct. In
these applications, at each point
noted in Figure 2-11, a temperature
and flow measurement is made in
addition to taking a gas sample,
which data are then combined and
taken to a laboratory for analysis.
In such applications, a single probe
contains a pitot tube, a thermo-
insertion depth corresponding to
the average velocity and because
the pitot element produces such a
small pressure differential. The use
of a pitot venturi does improve on
this situation by increasing the pressure differential, but cannot help the
problem caused by the elongated
velocity profile.
• Averaging Pitot Tubes
Averaging pitot tubes been introduced to overcome the problem of
finding the average velocity point.
An averaging pitot tube is provided
with multiple impact and static pressure ports and is designed to extend
across the entire diameter of the
pipe. The pressures detected by all
the impact (and separately by all the
Volume 4
27
static) pressure ports are combined
and the square root of their difference is measured as an indication of
the average flow in the pipe (Figure
2-12). The port closer to the outlet
of the combined signal has a slightly
greater influence, than the port that
is farthest away, but, for secondary
applications where pitot tubes are
commonly used, this error is acceptable.
The number of impact ports, the
distance between ports, and the
diameter of the averaging pitot tube
all can be modified to match the
needs of a particular application.
Sensing ports in averaging pitot tubes
clean, allowing the sensor to use
smaller ports.
Averaging pitot tubes offer the
same advantages and disadvantages
as do single-port tubes. They are
slightly more expensive and a little
more accurate, especially if the flow
is not fully formed. Some averaging pitot sensors can be inserted
through the same opening (or hot
tap) which accommodates a singleport tube.
• Area Averaging
Area-averaging pitot stations are
used to measure the large flows of
low pressure air in boilers, dryers,
port. Each set of ports is connected
to its own manifold, which combines the average static and average
impact pressure signals. If plugging
is likely, the manifolds can be purged
to keep the ports clean.
Because area-averaging pitot stations generate very small pressure differentials, it may be necessary to use
low differential d/p cells with spans
as low as 0-0.01 in water column. To
improve accuracy, a hexagonal celltype flow straightener and a flow
nozzle can be installed upstream of
the area-averaging pitot flow sensor. The flow straightener removes
local turbulence, while the nozzle
amplifies the differential pressure
produced by the sensor.
• Installation
are often too large to allow the tube
to behave as a true averaging chamber. This is because the oversized
port openings are optimized not for
averaging, but to prevent plugging. In
some installations, purging with an
inert gas is used to keep the ports
28
Volume 4
or HVAC systems. These units are
available for the various standard
sizes of circular or rectangular ducts
(Figure 2-13) and for pipes. They are
so designed that each segment of
the cross-section is provided with
both an impact and a static pressure
Pitot tubes can be used as permanently
installed flow sensors or as portable
monitoring devices providing periodic
data. Permanently installed carbon
steel or stainless steel units can operate at up to 1400 PSIG pressures and
are inserted into the pipe through
flanged or screw connections. Their
installation usually occurs prior to
plant start-up, but they can be hottapped into an operating process.
In a hot-tap installation (Figure
2-14), one first welds a fitting to the
pipe. Then a drill-through valve is
attached to the fitting and a hole is
drilled through the pipe. Then, after
partially withdrawing the drill, the
valve is closed, the drill is removed
and the pitot tube is inserted. Finally,
the valve is opened and the pitot
tube is fully inserted.
The velocity profile of the flowing
stream inside the pipe is affected by
the Reynolds number of the flowing
fluid, pipe surface roughness, and
by upstream disturbances, such as
valves, elbows, and other fittings.
Pitot tubes should be used only if the
TRANSACTIONS
minimum Reynolds number exceeds
20,000 and if either a straight run of
about 25 diameters can be provided
upstream to the pitot tube or if
straightening vanes can be installed.
1-in); D = probe diameter (inches); L =
unsupported probe length in inches,
which is calculated as the sum of the
pipe I.D. plus the pipe wall thickness
plus: 1.25 in for K-in diameter probes;
1.5 in for H-in; 1.56 in for I-in; and 1.94
rotameter combination (bypass rotameter), open-channel variable gate,
tapered plug, and vane or piston
designs.
Either the force of gravity or a
spring is used to return the flow ele-
in for 1-in diameter probes.
Once the velocity limits have
been calculated, make sure that they
do not fall within the range of operating velocities. If they do, change
the probe diameter, or its mounting,
or do both, until there is no overlap.
ment to its resting position when the
flow lessens. Gravity-operated meters
(rotameters) must be installed in a
vertical position, whereas spring operated ones can be mounted in any
position. All variable area flowmeters are available with local indicators.
Most can also be provided with position sensors and transmitters (pneumatic, electronic, digital, or fiberoptic)
for connecting to remote displays or
controls.
100
90
80
70
60
50
40
30
20
10
R
Scale
• Vibration Damage
Natural frequency resonant vibrations can cause pitot tube failure. Natural frequency vibration is
caused by forces created as vortices
are shed by the pitot tube. The pitot
tube is expected to experience such
vibration if the process fluid velocity (in feet per second) is between
a lower limit (VL) and an upper limit
(VH). The values of VL and VH can be
calculated (for the products of a given
manufacturer) using the equations
below.
VL = 5253(M x Pr x D)/L2
VH = 7879(M x Pr x D)/L2
Where M = mounting factor (3.52
for single mount); Pr = probe factor
(0.185 for K-in diameter probes; 0.269
for H-in; 0.372 for I-in; and 0.552 for
TRANSACTIONS
Variable Area Flowmeters
Variable area flowmeters (Figure 2-15)
are simple and versatile devices that
operate at a relatively constant pressure drop and measure the flow of
liquids, gases, and steam. The position of their float, piston or vane
is changed as the increasing flow
rate opens a larger flow area to pass
the flowing fluid. The position of
the float, piston or vane provides a
direct visual indication of flow rate.
Design variations include the rotameter (a float in a tapered tube), orifice/
• Purge-Flow Regulators
If a needle valve is placed at the
inlet or outlet of a rotameter, and a
d/p regulator controls the pressure
difference across this combination,
the result is a purge-flow regulator. Such instrumentation packages
are used as self-contained purge
flowmeters (Figure 2-16). These are
Volume 4
29
30
among the least expensive and most
widely used flowmeters. Their main
application is to control small gas or
liquid purge streams. They are used
to protect instruments from contacting hot and corrosive fluids, to
protect pressure taps from plugging,
H2O
differential. In bubbler and
purge applications, the inlet pressure
(P1) is held constant and the outlet
pressure (P0) is variable. Figure 2-16
describes a configuration where the
outlet pressure (P0) is held constant
and the inlet pressure (P1) is variable.
to protect the cleanliness of optical
devices, and to protect electrical
devices from igniting upon contact
with combustibles.
Purge meters are quite useful in
adding nitrogen gas to the vapor
spaces of tanks and other equipment. Purging with nitrogen gas
reduces the possibility of developing
a flammable mixture because it displaces flammable gases. The purgeflow regulator is reliable, intrinsically
safe, and inexpensive.
As shown in Figure 2-16, purge
meters can operate in the constant flow mode, where P2 - P0 is
held constant at about 60 to 80 in
They can handle extremely small
flow rates from 0.01 cc/min for
liquids and from 0.5 cc/min for
gases. The most common size is a
glass tube rotameter with G-in (6
mm) connections, a range of 0.050.5 gpm (0.2-2.0 lpm) on water or
0.2-2.0 scfm (0.3-3.0 cmph) in air service. Typical accuracy is ±5% FS over
a 10:1 range, and the most common
pressure rating is 150 psig (1 MPa).
Volume 4
• Rotameters
The rotameter is the most widely used variable area flowmeter
because of its low cost, simplicity,
low pressure drop, relatively wide
rangeability, and linear output. Its
operation is simple: in order to pass
through the tapered tube, the fluid
flow raises the float. The greater the
flow, the higher the float is lifted. In
liquid service, the float rises due to a
combination of the buoyancy of the
liquid and the velocity head of the
fluid. With gases, buoyancy is negligible, and the float responds mostly
to the velocity head.
In a rotameter (Figure 2-15), the
metering tube is mounted vertically,
with the small end at the bottom. The
fluid to be measured enters at the
bottom of the tube, passes upward
around the float, and exits the top.
When no flow exists, the float rests
at the bottom. When fluid enters, the
metering float begins to rise.
The float moves up and down in
proportion to the fluid flow rate
and the annular area between the
float and the tube wall. As the float
rises, the size of the annular opening
increases. As this area increases, the
differential pressure across the float
decreases. The float reaches a stable
position when the upward force
exerted by the flowing fluid equals
the weight of the float. Every float
position corresponds to a particular
flowrate for a particular fluid’s density and viscosity. For this reason, it
is necessary to size the rotameter
for each application. When sized
correctly, the flow rate can be determined by matching the float position
to a calibrated scale on the outside
of the rotameter. Many rotameters
come with a built-in valve for adjusting flow manually.
Several shapes of float are available for various applications. One
early design had slots, which caused
the float to spin for stabilizing and
centering purposes. Because this
float rotated, the term rotameter
was coined.
TRANSACTIONS
Rotameters are typically provided
with calibration data and a direct
reading scale for air or water (or
both). To size a rotameter for other
service, one must first convert the
actual flow to a standard flow. For
liquids, this standard flow is the water
equivalent in gpm; for gases, the standard flow is the air flow equivalent in
standard cubic feet per minute (scfm).
Tables listing standard water equivalent gpm and/or air scfm values are
provided by rotameter manufacturers. Manufacturers also often provide
slide rules, nomographs, or computer
software for rotameter sizing.
• Design Variations
A wide choice of materials is available for floats, packing, O-rings, and
end fittings. Rotameter tubes for such
safe applications as air or water can
Rotameters can be specified in a wide range of
sizes and materials.
be made of glass, whereas if breakage
would create an unsafe condition,
they are provided with metal tubes.
Glass tubes are most common, being
precision formed of safety shielded
borosilicate glass. Floats typically are
machined from glass, plastic, metal,
TRANSACTIONS
or stainless steel for corrosion resistance. Other float materials include
carboloy, sapphire, and tantalum.
End fittings are available in metal or
plastic. Some fluids attack the glass
metering tube, such as wet steam
or high-pH water over 194°F (which
can soften glass); caustic soda (which
dissolves glass); and hydrofluoric acid
(which etches glass).
Floats have a sharp edge at the
point where the reading should be
observed on the tube-mounted
scale. For improved reading accuracy, a glass-tube rotameter should
be installed at eye level. The scale
can be calibrated for direct reading
of air or water, or can read percentage of range. In general, glass tube
rotameters can measure flows up to
about 60 gpm water and 200 scfh air.
A correlation rotameter has a
scale from which a reading is taken
(Figure 2-15). This reading is then
compared to a correlation table for
a given gas or liquid to get the actual
flow in engineering units. Correlation
charts are readily available for nitrogen, oxygen, hydrogen, helium,
argon, and carbon dioxide. While
not nearly as convenient as a direct
reading device, a correlation meter
is more accurate. This is because a
direct-reading device is accurate for
only one specific gas or liquid at a
particular temperature and pressure.
A correlation flowmeter can be used
with a wide variety of fluids and
gases under various conditions. In
the same tube, different flow rates
can be handled by using different
floats.
Small glass tube rotameters are suitable for working with pressures up to
500 psig, but the maximum operating
pressure of a large (2-in diameter) tube
may be as low as 100 psig. The practical temperature limit is about 400°F,
but such high-temperature operation
substantially reduces the operating
pressure of the tube. In general, there
is a linear relationship between operating temperature and pressure.
Glass-tube rotameters are often
used in applications where several
streams of gases or liquids are being
metered at the same time or mixed
in a manifold, or where a single fluid
is being exhausted through several
channels (Figure 2-17). Multiple tube
flowmeters allow up to six rotameters to be mounted in the same frame.
It also is possible to operate a
rotameter in a vacuum. If the rotameter has a valve, it must be placed
at the outlet at the top of the
meter. For applications requiring a
wide measurement range, a dual-ball
rotameter can be used. This instrument has two ball floats: a light ball
(typically black) for indicating low
flows and a heavy ball (usually white)
for indicating high flows. The black
ball is read until it goes off scale,
and then the white ball is read. One
such instrument has a black measuring
range from 235-2,350 ml/min and a
white to 5,000 ml/min.
For higher pressures and temperatures beyond the practical range of
glass, metal tube rotameters can be
used. These tubes are usually made
of stainless steel, and the position
Volume 4
31
of the float is detected by magnetic
followers with readouts outside the
metering tube.
Metal-tube rotameters can be
used for hot and strong alkalis, fluorine, hydrofluoric acid, hot water,
steam, slurries, sour gas, additives,
and molten metals. They also can
be used in applications where high
operating pressures, water hammer,
or other forces could damage glass
tubes. Metal-tube rotameters are
available in diameter sizes from K in
to 4 in, can operate at pressures up
to 750 psig, temperatures to 540°C
(1,000°F), and can measure flows up
to 4,000 gpm of water or 1,300 scfm
of air. Metal-tube rotameters are
readily available as flow transmitters for integration with remote analog or digital controls. Transmitters
usually detect the float position
through magnetic coupling and are
often provided with external indication through a rotatable magnetic
32
Volume 4
helix that moves the pointer. The
transmitter can be intrinsically safe,
microprocessor-based, and can be
provided with alarms and a pulse
output for totalization.
Plastic-tube rotameters are relatively low cost rotameters that are
ideal for applications involving corrosive fluids or deionized water. The
tube itself can be made from Teflon®
PFA, polysulfone, or polyamide. The
wetted parts can be made from stainless steel, PVDF, or Teflon® PFA, PTFE,
PCTFE, with Viton® or Kalrez® O-rings.
• Accuracy
Laboratory rotameters can be calibrated to an accuracy of 0.50% AR
over a 4:1 range, while the inaccuracy
of industrial rotameters is typically
1-2% FS over a 10:1 range. Purge and
bypass rotameter errors are in the
5% range.
Rotameters can be used to manually set flow rates by adjusting the
valve opening while observing the
scale to establish the required process flow rate. If operating conditions
remain unaltered, rotameters can be
repeatable to within 0.25% of the
actual flow rate.
Most rotameters are relatively
insensitive to viscosity variations.
The most sensitive are very small
rotameters with ball floats, while
larger rotameters are less sensitive
to viscosity effects. The limitations
of each design are published by
the manufacturer (Figure 2-18). The
float shape does affect the viscosity limit. If the viscosity limit is
exceeded, the indicated flow must
be corrected for viscosity.
Because the float is sensitive to
changes in fluid density, a rotameter
can be furnished with two floats
(one sensitive to density, the other
to velocity) and used to approximate
the mass flow rate. The more closely
the float density matches the fluid
density, the greater the effect of a
fluid density change will be on the
float position. Mass-flow rotameters
work best with low viscosity fluids
such as raw sugar juice, gasoline, jet
fuel, and light hydrocarbons.
Rotameter accuracy is not affected by the upstream piping configuration. The meter also can be installed
directly after a pipe elbow without
adverse effect on metering accuracy. Rotameters are inherently self
cleaning because, as the fluid flows
between the tube wall and the float,
it produces a scouring action that
tends to prevent the buildup of foreign matter. Nevertheless, rotameters should be used only on clean
fluids which do not coat the float or
the tube. Liquids with fibrous materials, abrasives, and large particles
should also be avoided.
• Other Variable-Area Flowmeters
TRANSACTIONS
Major disadvantages of the rotameter
are its relatively high cost in larger
sizes and the requirement that it be
installed vertically (there may not
be enough head room). The cost of
a large rotameter installation can be
reduced by using an orifice bypass
or a pitot tube in combination with
a smaller rotameter. The same-size
bypass rotameter can be used to
measure a variety of flows, with
the only difference between applications being the orifice plate and the
differential it produces.
Advantages of a bypass rotameter
include low cost; its major disadvantage is inaccuracy and sensitivity to
material build-up. Bypass rotameters
are often provided with isolation
valves so that they can be removed
for maintenance without shutting
down the process line.
Tapered plug flowmeters are variable-area flowmeters with a stationary core and a piston that moves
as the flow varies. In one design,
the piston movement mechanically
moves a pointer, while in another
it magnetically moves an external
flow rate indicator. The second
TRANSACTIONS
design has a metallic meter body
for applications up to 1,000 psig.
One gate-type variable-area
flow-meter resembles a butterfly
valve. Flow through the meter forces a spring-loaded vane to rotate,
and a mechanical connection provides local flow rate indication. The
inaccuracy of such meters is 2-5%
FS. The meter can be used on oil,
water and air, and is available in
sizes up to 4 inches. It also is used as
References & Further Reading
•OMEGA
Complete Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•“Choices Abound in Flow Measurement”, D. Ginesi, Chemical Engineering,
April 1991.
•“Developments in DP Flowmeters,” Jesse Yoder, Control, April 1998.
•Differential Producers - Orifice, Nozzle, Venturi, ANSI/ASME MFC,
December 1983.
•Flow Measurement Engineers’ Handbook, R.W. Miller, McGraw-Hill, 1996.
•Flow Measurement, D.W. Spitzer, Instrument Society of America, 1991.
•Flow of Water Through Orifices, AGA/ASME, Ohio State Univ. Bulletin
89, Vol. IV, No. 3.
•Fluid Meters, H.S. Bean , American Society of Mechanical Engineers, 1971.
•Fundamentals of Flow Measurement, J. P. DeCarlo, Instrument Society of
America, 1984.
•Instrument Engineers Handbook, 3rd edition, Bela Liptak, CRC Press, 1995.
•“Orifice Metering of Natural Gas”, AGA Report 3, 1985.
•“Primary Element Solves Difficult Flow Metering Problems at Water
Waste Treatment Plant,” D. Ginesi, L. Keefe, and P. Miller, Proceedings of
ISA 1989, Instrument Society of America, 1989.
Volume 4
33
D
34
Mechanical Flowmeters
angles to the flow, suspended in the
fluid stream on a free-running bearing. The diameter of the rotor is very
close to the inside diameter of the
metering chamber, and its speed of
rotation is proportional to the volumetric flow rate. Turbine rotation can
be detected by solid state devices or
by mechanical sensors. Other types
of rotary element flowmeters include
the propeller (impeller), shunt, and
paddlewheel designs.
iscussed in this chapter are
various types of mechanical
flowmeters that measure
flow using an arrangement
of moving parts, either by passing
isolated, known volumes of a fluid
through a series of gears or chambers
(positive displacement, or PD) or by
means of a spinning turbine or rotor.
All positive displacement flowmeters operate by isolating and counting known volumes of a fluid (gas
or liquid) while feeding it through
the meter. By counting the number
of passed isolated volumes, a flow
measurement is obtained. Each PD
design uses a different means of
isolating and counting these volumes. The frequency of the resulting pulse train is a measure of flow
rate, while the total number of pulses
gives the size of the batch. While PD
meters are operated by the kinetic
energy of the flowing fluid, metering pumps (described only briefly in
this article) determine the flow rate
Positive Displacement Flowmeters
Positive displacement meters provide
high accuracy (±0.1% of actual flow
rate in some cases) and good repeatability (as high as 0.05% of reading).
Accuracy is not affected by pulsating
flow unless it entrains air or gas in
the fluid. PD meters do not require
a power supply for their operation
and do not require straight upstream
and downstream pipe runs for their
installation. PD meters are available
in sizes from G in to 12 in and can
is reduced and metering accuracy is
therefore increased as the viscosity of
the process fluid increases.
The process fluid must be clean.
Particles greater than 100 microns in
size must be removed by filtering. PD
meters operate with small clearances between their precision-machined
parts; wear rapidly destroys their
accuracy. For this reason, PD meters
are generally not recommended for
measuring slurries or abrasive fluids.
In clean fluid services, however, their
precision and wide rangeability make
them ideal for custody transfer and
batch charging. They are most widely
used as household water meters.
Millions of such units are produced
annually at a unit cost of less than
$50 U.S. In industrial and petrochemical applications, PD meters are commonly used for batch charging of
both liquids and gases.
Although slippage through the PD
meter decreases (that is, accuracy
increases) as fluid viscosity increases,
while also adding kinetic energy to
the fluid.
The turbine flowmeter consists of
a multi-bladed rotor mounted at right
operate with turndowns as high as
100:1, although ranges of 15:1 or lower
are much more common. Slippage
between the flowmeter components
pressure drop through the meter
also rises. Consequently, the maximum (and minimum) flow capacity of the flowmeter is decreased
Volume 4
TRANSACTIONS
as viscosity increases. The higher
the viscosity, the less slippage and
the lower the measurable flow rate
becomes. As viscosity decreases, the
Because it must be nonmagnetic,
the meter housing is usually made of
bronze but can be made from plastic for corrosion resistance or cost
racy of these meters is required
to be
±2% of actual flow rate.
Higher viscosity can produce higher
accuracy, while lower viscosity and
low flow performance of the meter
deteriorates. The maximum allowable pressure drop across the meter
constrains the maximum operating
flow in high viscosity services.
savings. The wetted parts such as the
disc and spindle are usually bronze,
rubber, aluminum, neoprene, Buna-N,
or a fluoroelastomer such as Viton®.
Nutating disc meters are designed
for water service and the materials
of which they are made must be
checked for compatibility with other
fluids. Meters with rubber discs give
better accuracy than metal discs due
to the better sealing they provide.
Nutating disc meters are available
in L-in to 2-in sizes. They are suited
for 150-psig operating pressures with
overpressure to a maximum of 300
psig. Cold water service units are
temperature-limited to 120°F. Hot
water units are available up to 250°F.
These meters must meet American
Water Works Association (AWWA)
standards for accuracy. The accu-
wear over time will reduce accuracy.
The AWWA requires that residential
water meters be re-calibrated every
10 years. Because of the intermittent
use
patterns of residential users,
this corresponds to recalibrating L
x I in residential water meters after
they have metered 5 million gallons.
In industrial applications, however,
these meters are likely to pass this
threshold much sooner. The maximum continuous flow of a nutating
disc meter is usually about 60-80%
of the maximum flow in intermittent
service.
Rotating vane meters (Figure 3-1B)
have spring-loaded vanes that entrap
increments of liquid between the
eccentrically mounted rotor and the
casing. The rotation of the vanes
moves the flow increment from inlet
• Liquid PD Meters
Nutating disc meters are the most
common PD meters. They are used as
residential water meters around the
world. As water flows through the
metering chamber, it causes a disc
to wobble (nutate), turning a spindle,
which rotates a magnet. This magnet
is coupled to a mechanical register
or a pulse transmitter. Because the
flowmeter entraps a fixed quantity
of fluid each time the spindle is
rotated, the rate of flow is proportional to the rotational velocity of
the spindle (Figure 3-1A).
TRANSACTIONS
Volume 4
35
to outlet and discharge. Accuracy of
±0.1% of actual rate (AR) is normal,
and larger size meters on higher viscosity services can achieve accuracy
to within 0.05% of rate.
mesh or -74 micron) sand, but not
large particle size or abrasive solids.
The measurement chamber is
cylindrical with a partition plate separating its inlet port from its outlet.
used between 100 and 150 psig. Some
industrial versions are rated to 1,500
psig. They can meter flow rates from
1 gpm to 65 gpm in continuous service with intermittent excursions to
A
B
A
B
A
Rotating vane meters are regularly
used in the petroleum industry and
are capable of metering solids-laden
crude oils at flow rates as high as
17,500 gpm. Pressure and temperature limits depend on the materials
of construction and can be as high as
350°F and 1,000 psig. Viscosity limits
are 1 to 25,000 centipoise.
In the rotary displacement meter,
a fluted central rotor operates in
constant relationship with two wiper
rotors in a six-phase cycle. Its applications and features are similar to
those of the rotary vane meter.
• Piston Meters
Oscillating piston flowmeters typically are used in viscous fluid services
such as oil metering on engine test
stands where turndown is not critical
(Figure 3-2). These meters also can be
used on residential water service and
can pass limited quantities of dirt,
such as pipe scale and fine (viz,-200
36
Volume 4
The piston is also cylindrical and is
punctured by numerous openings
to allow free flow on both sides of
the piston and the post (Figure 3-2A).
The piston is guided by a control
roller within the measuring chamber, and the motion of the piston
is transferred to a follower magnet
which is external to the flowstream.
The follower magnet can be used to
drive either a transmitter, a register,
or both. The motion of the piston
is oscillatory (not rotary) since it is
constrained to move in one plane.
The rate of flow is proportional to
the rate of oscillation of the piston.
The internals of this flowmeter
can be removed without disconnection of the meter from the pipeline. Because of the close tolerances
required to seal the piston and to
reduce slippage, these meters require
regular maintenance. Oscillating piston flow meters are available in H-in
to 3-in sizes, and can generally be
100 gpm. Meters are sized so that
pressure drop is below 35 psid at
maximum flow rate. Accuracy ranges
from ±0.5 % AR for viscous fluids to
±2% AR for nonviscous applications.
Upper limit on viscosity is 10,000
centipoise.
Reciprocating piston meters are
probably the oldest PD meter designs.
They are available with multiple pistons, double-acting pistons, or rotary
pistons. As in a reciprocating piston
engine, fluid is drawn into one piston chamber as it is discharged from
the opposed piston in the meter.
Typically, either a crankshaft or a
horizontal slide is used to control the
opening and closing of the proper
orifices in the meter. These meters
are usually smaller (available in sizes
down to 1/10-in diameter) and are
used for measuring very low flows of
viscous liquids.
• Gear & Lobe Meters
TRANSACTIONS
The oval gear PD meter uses two
fine-toothed gears, one mounted
horizontally, the other vertically,
with gears meshing at the tip of the
vertical gear and the center of the
horizontal gear (Figure 3-3A). The
two rotors rotate opposite to each
other, creating an entrapment in the
crescent-shaped gap between the
housing and the gear. These meters
can be very accurate if slippage
between the housing and the gears
is kept small. If the process fluid
viscosity is greater than 10 centipoise
and the flowrate is above 20% of
rated capacity, accuracy of 0.1% AR
can be obtained. At lower flows and
at lower viscosity, slippage increases
and accuracy decreases to 0.5% AR
or less.
The lubricating characteristics of
the process fluid also affect the
turndown of an oval gear meter.
With liquids that do not lubricate
well, maximum rotor speed must be
derated to limit wear. Another way
to limit wear is to keep the pressure
drop across the meter below 15 psid.
Therefore, the pressure drop across
the meter limits the allowable maximum flow in high viscosity service.
Rotating lobe and impeller type
PD meters are variations of the oval
gear flowmeter that do not share
its precise gearing. In the rotating
lobe design, two impellers rotate in
opposite directions within the ovoid
housing (Figure 3-3B). As they rotate,
a fixed volume of liquid is entrapped
and then transported toward the
outlet. Because the lobe gears
remain in a fixed relative position,
it is only necessary to measure the
rotational velocity of one of them.
The impeller is either geared to a
register or is magnetically coupled
to a transmitter. Lobe meters can be
furnished in 2-in to 24-in line sizes.
Flow capacity is 8-10 gpm to 18,000
TRANSACTIONS
gpm in the larger sizes. They provide good repeatability (better than
0.015% AR) at high flows and can
be used at high operating pressures
(to 1,200 psig) and temperatures (to
400°F).
The lobe gear meter is available
in a wide range of materials of construction, from thermoplastics to
highly corrosion-resistant metals.
Disadvantages of this design include
a loss of accuracy at low flows. Also,
the maximum flow through this meter
is less than for the same size oscillatory piston or nutating disc meter.
In the rotating impeller meter,
very coarse gears entrap the fluid
and pass a fixed volume of fluid
with each rotation (Figure 3-3C).
These meters are accurate to 0.5%
of rate if the viscosity of the process fluid is both high and constant,
or varies only within a narrow band.
These meters can be made out of
a variety of metals, including stainless steel, and corrosion-resistant
plastics such as PVDF (Kynar). These
meters are used to meter paints
and, because they are available in 3A
or sanitary designs, also milk, juices,
and chocolate.
In these units, the passage of magnets embedded in the lobes of the
rotating impellers is sensed by proximity switches (usually Hall-effect
detectors) mounted external to the
flow chamber. The sensor transmits
a pulse train to a counter or flow
controller. These meters are available in 1/10-in to 6-in sizes and can
handle pressures to 3,000 psig and
temperatures to 400°F.
• Helix Meters
The helix meter is a positive displacement device that uses two radially pitched helical gears to continuously entrap the process fluid as it
flows. The flow forces the helical
gears to rotate in the plane of the
pipeline. Optical or magnetic sensors are used to encode a pulse
train proportional to the rotational
speed of the helical gears. The forces
required to make the helices rotate
are relatively small and therefore, in
comparison to other PD meters, the
pressure drop is relatively low. The
best attainable accuracy is about
±0.2% or rate.
As shown in Figure 3-4, measurement error rises as either the operVolume 4
37
ating flowrate or the viscosity of
the process fluid drops. Helical gear
meters can measure the flow of highly
viscous fluids (from 3 to 300,000 cP),
squeeze a plastic tubing against the
housing, which also serves to position
the tubing. This type of metering pump
is used in laboratories, in a variety of
the basis of the displacement of the
piston and the required flow rate
and discharge pressure. Check valves
(or, on critical applications, double
making them ideal for extremely
thick fluids such as glues and very
viscous polymers. Because at maximum flow the pressure drop through
the meter should not exceed 30 psid,
the maximum rated flow through the
meter is reduced as the fluid viscosity increases. If the process fluid has
good lubricating characteristics, the
meter turndown can be as high as
100:1, but lower (10:1) turndowns are
more typical.
medical applications, in the majority
of environmental sampling systems,
and also in dispensing hypochlorite
solutions. The tubing can be siliconerubber or, if a more corrosion-resistant
material is desired, PTFE tubing.
Piston pumps deliver a fixed volume of liquid with each “out” stroke
and a fixed volume enters the chamber on each “in” stroke (Figure 3-5A).
Check valves keep the fluid flow
from reversing. As with all positive
displacement pumps, piston pumps
generate a pulsating flow. To minimize the pulsation, multiple pistons
or pulsation-dampening reservoirs
are installed. Because of the close
tolerances of the piston and cylinder sleeve, a flushing mechanism
must be provided in abrasive applications. Piston pumps are sized on
check valves) are selected to protect
against backflow.
Diaphragm pumps are the most
common industrial PD pumps (Figure
3-5B). A typical configuration consists of a single diaphragm, a chamber, and suction and discharge check
valves to prevent backflow. The piston can either be directly coupled
to the diaphragm or can force a
hydraulic oil to drive the diaphragm.
Maximum output pressure is about
125 psig. Variations include bellowstype diaphragms, hydraulically actuated double diaphragms, and airoperated, reciprocating double-diaphragms.
• Metering Pumps
Metering pumps are PD meters that
also impart kinetic energy to the
process fluid. There are three basic
designs: peristaltic, piston, and diaphragm.
Peristaltic pumps operate by having fingers or a cam systematically
38
Volume 4
• Gas PD Meters
PD gas meters operate by counting
the number of entrapped volumes
TRANSACTIONS
of gas passed, similar to the way
PD meters operate on liquids. The
primary difference is that gases are
compressible.
Diaphragm gas meters most often
are used to measure the flow of
natural gas, especially in metering
consumption by households. The
meter is constructed from aluminum
castings with cloth-backed rubber
diaphragms. The meter consists of
four chambers: the two diaphragm
chambers on the inlet and outlet
sides and the inlet and outlet chambers of the meter body. The passage
of gas through the meter creates
a differential pressure between the
two diaphragm chambers by compressing the one on the inlet side
and expanding the one on the outlet
side. This action alternately empties and fills the four chambers. The
slide valves at the top of the meter
crank mechanism for the meter register.
Diaphragm meters generally are
calibrated for natural gas, which has
a specific gravity of 0.6 (relative to
air). Therefore, it is necessary to recalibrate the flow rating of the meter
when it is used to meter other gases.
The calibration for the new flow rating (QN) is obtained by multiplying
the meter’s flow rating for natural
gas (QC) by the square root of the
ratio of the specific gravities of natural gas (0.6) and the new gas (SGN):
alternate the roles of the chambers
and synchronize the action of the
diaphragms, as well as operating the
ods of time, which makes them good
choices for retail revenue metering
applications. Unless the gas is unusu-
TRANSACTIONS
QN= QC(0.6/SGN)0.5
Diaphragm meters are usually
rated in units of cubic feet per hour
and sized for a pressure drop of
0.5-2 in H2O. Accuracy is roughly ±1%
of reading over a 200:1 range. They
maintain their accuracy for long peri-
ally dirty (producer gas, or recycled
methane from composting or digesting, for example), the diaphragm
meter will operate with little or no
maintenance indefinitely.
Lobe gear meters (or lobed
impeller meters, as they are also
known), also are used for gas service.
Accuracy in gas service is ±1% of rate
over a 10:1 turndown, and typical
pressure drop is 0.1 psid. Because of
the close tolerances, upstream filtration is required for dirty lines.
Rotating vane meters measure the
flow of gas in the same ranges as do
lobe gear meters (up to 100,000 ft3/
hr) but can be used over a wider 25:1
turndown. They also incur a lower
pressure drop of 0.05 in H2O for similar accuracy, and, because the clearances are somewhat more forgiving,
upstream filtration is not as critical.
• High-Precision PD Systems
High-precision gas meters are usually
a hybrid combining a standard PD
Volume 4
39
meter and a motor drive that eliminates the pressure drop across the
meter. Equalizing the inlet and outlet
pressures eliminates slip flows, leakage, and blow-by. In high-precision
gas flowmeter installations, highsensitivity leaves are used to detect
the pressure differential, and dis-
placement transducers are used to
measure the deflection of the leaves
(Figure 3-6A). Designed to operate
at ambient temperatures and at up
to 30 psig pressures, this meter is
claimed to provide accuracy to within 0.25% of reading over a 50:1 range
and 0.5% over a 100:1 range. Flow
capacity ranges from 0.3-1,500 scfm.
For liquid service, a servomotordriven oval-gear meter equalizes
the pressure across the meter. This
increases accuracy at low flows and
under varying viscosity conditions
(Figure 3-6B). This flowmeter uses a
very sensitive piston to detect the
meter differential and drives a variable speed servomotor to keep it
near zero. This design is claimed to
provide 0.25% of rate accuracy over
a 50:1 range at operating pressures
of up to 150 psig. High precision
flowmeters are used on engine test
40
Volume 4
stands for fuel flow measurement
(gasoline, diesel, alcohol, etc.). Flow
ranges from 0.04-40 gph are typical.
Vapor separators are usually included, to prevent vapor lock.
• Testing, Calibration & Provers
All meters with moving parts require
periodic testing, recalibration and
repair, because wear increases the
clearances. Recalibration can be
done either in a laboratory or on line
using a prover.
Gas systems are recalibrated
against a bell-jar prover—a calibrated
cylindrical bell, liquid sealed in a tank.
As the bell is lowered, it discharges
a known volume of gas through the
meter being tested. The volumetric
accuracy of bell-jar provers is on the
order of 0.1% by volume, and provers
are available in discharge volumes of
2, 5, 10 ft3 and larger.
Liquid systems can be calibrated
in the laboratory against either a
calibrated secondary standard or a
gravimetric flow loop. This approach
can provide high accuracy (up to
±0.01% of rate) but requires removing the flowmeter from service.
In many operations, especially in
the petroleum industry, it is difficult
or impossible to remove a flowmeter from service for calibration.
Therefore, field-mounted and in-line
provers have been developed. This
type of prover consists of a calibrated chamber equipped with a barrier piston (Figure 3-7). Two detectors are mounted a known distance
(and therefore a known volume)
apart. As the flow passes through
the chamber, the displacer piston
is moved downstream. Dividing the
volume of the chamber by the time
it takes for the displacer to move
from one detector to the other gives
the calibrated flow rate. This rate is
then compared to the reading of the
flowmeter under test.
Provers are repeatable on the
order of 0.02%, and can operate
at up to 3,000 psig and 165°F/75°C.
Their operating flow range is from
as low as 0.001 gpm to as high as
20,000 gpm. Provers are available
for bench-top use, for mounting in
truck-beds, on trailers, or in-line.
• PD Meter Accessories
PD meter accessories include
strainers, filters, air/vapor release
assemblies, pulsation dampeners,
temperature compensation systems, and a variety of valves to
permit dribble cut-off in batching
systems. Mechanical registers can
be equipped with mechanical or
electronic ticket-printers for inventory control and point-of-use sales.
Batching flow computers are readily
available, as are analog and intelligent digital transmitters. Automatic
meter reading (AMR) devices permit
the remote retrieval of readings by
utility personnel.
Turbine Flowmeters
Invented by Reinhard Woltman in
the 18th century, the turbine flowTRANSACTIONS
meter is an accurate and reliable
flowmeter for both liquids and gases.
It consists of a multi-bladed rotor
mounted at right angles to the flow
and suspended in the fluid stream on
a free-running bearing. The diameter
of the rotor is very slightly less than
the inside diameter of the metering
chamber, and its speed of rotation is
proportional to the volumetric flow
rate. Turbine rotation can be detected by solid state devices (reluctance,
inductance, capacitive and Halleffect pick-ups) or by mechanical
sensors (gear or magnetic drives).
In the reluctance pick-up, the coil
is a permanent magnet and the turbine blades are made of a material
permanent magnet is embedded in
the rotor, or the blades of the rotor
are made of permanently magnetized
material (Figure 3-8B). As each blade
passes the coil, it generates a voltage
pulse. In some designs, only one blade
is magnetic and the pulse represents a
complete revolution of the rotor.
The outputs of reluctance and
inductive pick-up coils are continuous sine waves with the pulse train’s
frequency proportional to the flow
rate. At low flow, the output (the
height of the voltage pulse) may be
on the order of 20 mV peak-to-peak.
It is not advisable to transport such
a weak signal over long distances.
Therefore, the distance between
transistors also can be used. These
transistors change their state when
they are in the presence of a very
low strength (on the order of 25
gauss) magnetic field.
In these turbine flowmeters, very
small magnets are embedded in the
tips of the rotor blades. Rotors are typically made of a non-magnetic material, like polypropylene, Ryton, or PVDF
(Kynar). The signal output from a Halleffect sensor is a square wave pulse
train, at a frequency proportional to
the volumetric flowrate.
Because Hall-effect sensors have
no magnetic drag, they can operate
at lower flow velocities (0.2 ft/sec)
than magnetic pick-up designs (0.5-1.0
attracted to magnets. As each blade
passes the coil, a voltage is generated in the coil (Figure 3-8A). Each
pulse represents a discrete volume
of liquid. The number of pulses per
unit volume is called the meter’s
K-factor.
In the inductance pick-up, the
the pickup and associated display
electronics or preamplifier must be
short.
Capacitive sensors produce a
sine wave by generating an RF signal that is amplitude-modulated by
the movement of the rotor blades.
Instead of pick-up coils, Hall-effect
ft/sec). In addition, the Hall-effect
sensor provides a signal of high amplitude (typically a 10.8-V square wave),
permitting distances up to 3,000 ft.
between the sensor and the electronics without amplification.
In the water distribution industry,
mechanical-drive Woltman-type tur-
TRANSACTIONS
Volume 4
41
bine flowmeters continue to be the
standard. These turbine meters use a
gear train to convert the rotation of
the rotor into the rotation of a vertical shaft. The shaft passes between
the metering tube and the register
of turbine flowmeters. Class I turbine meters must register between
98-102% of actual rate at maximum
flow when tested. Class II turbine
meters must register between 98.5101.5% of actual rate. Both Class
B
section through a mechanical stuffing box, turning a geared mechanical
register assembly to indicate flow
rate and actuate a mechanical totalizer counter.
More recently, the water distribution industry has adopted a magnetic
drive as an improvement over high
maintenance mechanical-drive turbine meters. This type of meter has a
sealing disc between the measuring
chamber and the register. On the
measuring chamber side, the vertical shaft turns a magnet instead
of a gear. On the register side, an
opposing magnet is mounted to turn
the gear. This permits a completely
sealed register to be used with a
mechanical drive mechanism.
In the United States, the AWWA
sets the standards for turbine flowmeters used in water distribution
systems. Standard C701 provides for
two classes (Class I and Class II)
42
Volume 4
I and Class II meters must have
mechanical registers.
Solid state pickup designs are less
susceptible to mechanical wear than
AWWA Class I and Class II meters.
• Design & Construction Variations
Most industrial turbine flowmeters
are manufactured from austenitic
stainless steel (301, 303, 304SS),
whereas turbine meters intended for
municipal water service are bronze
or cast iron. The rotor and bearing
materials are selected to match the
process fluid and the service. Rotors
are often made from stainless steel,
and bearings of graphite, tungsten
carbide, ceramics, or in special
cases of synthetic ruby or sapphire
combined with tungsten carbide.
In all cases, bearings and shafts
are designed to provide minimum
friction and maximum resistance
to wear. Some corrosion-resistant
designs are made from plastic materials such as PVC.
Small turbine meters often are
called barstock turbines because
in sizes of I in to 3 in. they are
machined from stainless steel hexagonal barstock. The turbine is suspended by a bearing between two
hanger assemblies that also serve
to condition the flow. This design is
suited for high operating pressures
(up to 5,000 psig).
Similar to a pitot tube differential
pressure flowmeter, the insertion turbine meter is a point-velocity device.
It is designed to be inserted into
either a liquid or a gas line to a depth
This innovative turbine meter trades out a transmitted signal for local LCD indication.
TRANSACTIONS
at which the small-diameter rotor
will read the average velocity in the
line. Because they are very sensitive
to the velocity profile of the flowing stream, they must be profiled at
several points across the flow path.
Insertion turbine meters can be
designed for gas applications (small,
lightweight rotor) or for liquid (larger rotor, water-lubricated bearings).
They are often used in large diameter pipelines where it would be cost-
over a 10:1 flow range and a ±0.15%
linearity in a 6:1 range. The repeatability is from ±0.2% to ±0.02% over
the linear range.
Because there are minor inconsistencies in the manufacturing
process, all turbine flowmeters are
calibrated prior to shipment. The
resulting K-factor in pulses per volume unit will vary within the stated
linearity specification. It is possible, however, to register several
prohibitive to install a full size meter.
They can be hot-tapped into existing
pipelines (6 in or larger) through
a valving system without shutting
down the process. Typical accuracy
of an insertion turbine meter is 1%
FS, and the minimum flow velocity is
about 0.2 ft/sec.
K-factors for different portions of
the flow range and to electronically
switch from one to the other as the
measured flow changes. Naturally,
the K-factor is applicable only to
the fluid for which the meter was
calibrated.
Barstock turbine meters typically
are linear to ±0.25% AR over a 10:1
flow range. The linearity of larger
meters is ±0.5% AR over a 10:1 flow
range. Turbine meters have a typical nonlinearity (the turbine meter
hump, shown in Figure 3-9) in the
lower 25-30% of their range. Keeping
the minimum flow reading above
this region will permit linearity to
within 0.15% on small and 0.25% on
• Turbine Meter Accuracy
Figure 3-9 shows a typical turbinemeter calibration curve describing
the relationship between flow and
K-factor (pulses/gallon). The accuracy of turbine meters is typically
given in percentage of actual rate
(% AR). This particular meter has a
linearity tolerance band of ±0.25%
TRANSACTIONS
larger turbine meters. If the range
of 10:1 is insufficient, some turbine
flow- meters can provide up to 100:1
turndowns if accuracy is de-rated to
1% of full scale (FS).
• Sizing & Selection
Turbine meters should be sized so
that the expected average flow is
between 60% and 75% of the maximum capacity of the meter. If the
pipe is oversized (with flow velocity
under 1 ft/sec), one should select a
Hall-effect pick-up and use a meter
smaller than the line size. Flow velocities under 1 ft/sec can be insufficient,
while velocities in excess of 10 ft/
sec can result in excessive wear. Most
turbine meters are designed for maximum velocities of 30 ft/sec.
Turbine flowmeters should be
sized for between 3 and 5 psid pressure drop at maximum flow. Because
pressure drop increases with the
square of flow rate, reducing the
meter to the next smaller size will
raise the pressure drop considerably.
Viscosity affects the accuracy and
linearity of turbine meters. It is therefore important to calibrate the meter
Volume 4
43
for the specific fluid it is intended to
measure. Repeatability is generally not
greatly affected by changes in viscosity, and turbine meters often are
used to control the flow of viscous
fluids. Generally, turbine meters perform well if the Reynolds Number is
greater than 4,000 and less than or
equal to 20,000. Because it affects viscosity, temperature variation can also
adversely affect accuracy and must be
compensated for or controlled. The
turbine meter’s operating temperature
ranges from -200 to 450°C (-328 to
840°F).
Density changes do not greatly
affect turbine meters. On low density
fluids (SG < 0.7), the minimum flow
rate is increased due to the reduced
torque, but the meter’s accuracy
usually is not affected.
• Installation & Accessories
Turbine meters are sensitive to
upstream piping geometry that can
cause vortices and swirling flow.
Specifications call for 10-15 diameters of straight run upstream and
five diameters of straight run down44
Volume 4
stream of the meter. However, the
presence of any of the following
obstructions upstream would necessitate that there be more than 15
diameters of upstream straight-pipe
plus twice the pressure drop. Small
amounts of air entrainment (100 mg/l
or less) will make the meter read only
a bit high, while large quantities can
destroy the rotor.
runs
Turbine meters also can be damaged by solids entrained in the
fluid. If the amount of suspended
solids exceeds 100 mg/l of +75
micron size, a flushing y-strainer or
a motorized cartridge filter must be
installed at least 20 diameters of
straight run upstream of the flowmeter.
• 20
diameters for 90° elbow, tee,
filter, strainer, or thermowell;
• 25 diameters for a partially open
valve; and
• 50 or more diameters if there are
two elbows in different planes
or if the flow is spiraling or corkscrewing.
In order to reduce this straightrun requirement, straightening
vanes are installed. Tube bundles
or radial vane elements are used as
external flow straighteners located
at least 5 diameters upstream of the
meter (Figure 3-10).
Under certain conditions, the pressure drop across the turbine can cause
flashing or cavitation. The first causes
the meter to read high, the second
results in rotor damage. In order to
protect against this, the downstream
pressure must be held at a value
equaling 1.25 times the vapor pressure
• New Developments
Dual-rotor liquid turbines increase
the operating range in small line size
(under 2 in) applications. The two
rotors turn in opposite directions.
The front one acts as a conditioner,
directing the flow to the back rotor.
The rotors lock hydraulically and
continue to turn as the flow decreases
even to very low rates.
The linearity of a turbine meter is
affected by the velocity profile (often
dictated by the installation), viscosity, and temperature. It is now posTRANSACTIONS
sible to include complex linearization
functions in the preamplifier of a
turbine flowmeter to reduce these
nonlinearities. In addition, advances
in fieldbus technology make it possible to recalibrate turbine flowmeters
continuously, thereby correcting for
changes in temperature and viscosity.
Flow computers are capable of
linearization, automatic temperature
compensation, batching, calculation
of BTU content, datalogging, and
storage of multiple K-factors. The
batching controller is set with the
desired target volume and, when
its totalizer has counted down to
zero, it terminates the batch. Such
packages are equipped with dribble flow, pre-warn, or trickle-cutoff circuits. Whether functioning
through a relay contact or a ramp
function, these features serve to
minimize splashing or overfill and to
accurately terminate the batch.
• Gas Turbine & Shunt Meters
Gas meters compensate for the
lower driving torque produced by
the relatively low density of gases.
This compensation is obtained by
very large rotor hubs, very light rotor
assemblies, and larger numbers of
rotor blades. Gas turbine meters are
available from 2" to 12" and with flow
ratings up to 150,000 ft3/hr. When
operating at elevated gas pressures
(1,400 psig), a rangeability of 100:1
can be obtained in larger size meters.
Under lower pressure conditions,
typical rangeability is 20:1 with ±1%
linearity. The minimum upstream
straight pipe-run requirement is 20
pipe diameters.
Shunt flowmeters are used in gas
and steam service. They consist of
an orifice in the main line and a
rotor assembly in the bypass. These
meters are available is sizes 2 in. and
TRANSACTIONS
larger and are accurate to ±2% over
a range of 10:1.
Other Rotary Flowmeters
Other types of rotary element flowmeters include propeller (impeller),
shunt, and paddlewheel designs.
Propeller meters are commonly
used in large diameter (over 4 in)
irrigation and water distribution
systems. Their primary trade-off is
low cost and low accuracy (Figure
3-11A). AWWA Standard C-704 sets
the accuracy criterion for propeller
meters at 2% of reading. Propeller
meters have a rangeability of about
4:1 and exhibit very poor performance if the velocity drops below
1.5 ft/sec. Most propeller meters are
equipped with mechanical registers.
Mechanical wear, straightening, and
conditioning requirements are the
same as for turbine meters.
Paddlewheel flowmeters use
a rotor whose axis of rotation is
parallel to the direction of flow
(Figure 3-11B). Most paddlewheel
meters have flat-bladed rotors
and are inherently bi-directional.
Several manufacturers, however,
use crooked rotors that only rotate
in the forward direction. For smaller
pipes (H" to 3"), these meters are
available only with a fixed insertion depth, while for larger pipe
sizes (4" to 48") adjustable insertion depths are available. The use
of capacitively coupled pick-ups
or Hall-effect sensors extends the
range of paddlewheel meters into
the low-flow velocity region of 0.3
ft/sec.
Low-flow meters (usually smaller
than 1 in.) have a small jet orifice that projects the fluid onto a
Pelton wheel. Varying the diameter
and the shape of the jet orifice
matches the required flow range
and provides a flowmeter that
is accurate to 1% FS and has a
rangeability of 100:1. Higher accuracy can be achieved by calibrating
the meter and by lowering
its range. Because of the small size
of the jet orifice, these meters can
only be used on clean fluids and
they incur a pressure drop of about
20 psid. Materials of construction include polypropylene, PVDF,
TFE and PFA, brass, aluminum, and
stainless steel.
T
References & Further Reading
•OMEGA
Complete Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•Flow Measurement Engineering Handbook, Miller, McGraw-Hill, 1982.
•Flow Measurement, D. W. Spitzer, ISA, 1991.
•Flowmeters in Water Supply, Manual M33, AWWA, 1989.
•Industrial Flow Measurement, D. W. Spitzer, ISA 1984.
•Instrument Engineer’s Handbook, Bela Liptak, editor, CRC Press, 1995.
•“Turbine Flowmeter Extends Flow Range”, E. Piechota, Flow Control,
February, 1997.
•Water Meters—Selection, Installation, Testing and Maintenance, Manual
M6, AWWA, 1986.
Volume 4
45
W
Electronic Flowmeters
hile the flow measurement
technologies
discussed in this chapter—magnetic, vortex,
and ultrasonic—are neither exclusively nor exhaustively electronic in
nature, they do represent a logical
grouping of flow measurement technologies. All have no moving parts
(well, maybe vibrating), are relatively
non-intrusive, and are made possible
by today’s sophisticated electronics
technology.
Magnetic flowmeters, for example,
are the most directly electrical in
nature, deriving their first principles
of operation from Faraday’s law.
Vortex meters depend on piezoelectric sensors to detect vortices shed
from a stationary shedder bar. And
today’s ultrasonic flowmeters owe
their successful application to sophisticated digital signal processing.
Magnetic Flowmeters
The operation of magnetic flowmeters is based on Faraday’s law
of electromagnetic induction.
Magmeters can detect the flow of
conductive fluids only. Early magmeter designs required a minimum fluidic conductivity of 1-5 microsiemens
per centimeter for their operation.
The newer designs have reduced
that requirement a hundredfold to
between 0.05 and 0.1.
The magnetic flowmeter consists
of a non-magnetic pipe lined with an
insulating material. A pair of magnetic
coils is situated as shown in Figure 4-1,
and a pair of electrodes penetrates
the pipe and its lining. If a conductive
fluid flows through a pipe of diameter
(D) through a magnetic field density
(B) generated by the coils, the amount
46
Volume 4
of voltage (E) developed across the
electrodes—as predicted by Faraday’s
law—will be proportional to the
velocity (V) of the liquid. Because the
magnetic field density and the pipe
diameter are fixed values, they can be
combined into a calibration factor (K)
and the equation reduces to:
E = KV
The velocity differences at different points of the flow profile are
compensated for by a signal-weighing factor. Compensation is also provided by shaping the magnetic coils
such that the magnetic flux will be
greatest where the signal weighing
factor is lowest, and vice versa.
Manufacturers determine each
magmeter’s K factor by water calibration of each flowtube. The K value
thus obtained is valid for any other
conductive liquid and is linear over the
entire flowmeter range. For this reason, flowtubes are usually calibrated
at only one velocity. Magmeters can
measure flow in both directions, as
reversing direction will change the
polarity but not the magnitude of the
signal.
The K value obtained by water
testing might not be valid for nonNewtonian fluids (with velocitydependent viscosity) or magnetic
slurries (those containing magnetic
particles). These types of fluids can
affect the density of the magnetic
field in the tube. In-line calibration
and special compensating designs
should be considered for both of
these fluids.
• Magmeter Excitation
The voltage that develops at the
electrodes is a millivolt signal. This
signal is typically converted into a
standard current (4-20 mA) or frequency output (0-10,000 Hz) at or
near the flowtube. Intelligent magnetic transmitters with digital outputs allow direct connection to a
distributed control system. Because
the magmeter signal is a weak one,
the lead wire should be shielded and
twisted if the transmitter is remote.
The magmeter’s coils can be powered by either alternating or direct
current (Figure 4-2). When ac excitation is used, line voltage is applied
TRANSACTIONS
to the magnetic coils. As a result,
the flow signal (at constant flow)
will also look like a sine wave. The
amplitude of the wave is proportional to velocity. In addition to the
flow signal, noise voltages can be
induced in the electrode loop. Outof-phase noise is easily filtered, but
in-phase noise requires that the flow
be stopped (with the pipe full) and
the transmitter output set to zero.
The main problem with ac magmeter
designs is that noise can vary with
process conditions and frequent rezeroing is required to maintain accuracy.
In dc excitation designs, a low frequency (7-30 Hz) dc pulse is used to
excite the magnetic coils. When the
coils are pulsed on (Figure 4-2), the
transmitter reads both the flow and
noise signals. In between pulses, the
transmitter sees only the noise signal.
Therefore, the noise can be continuously eliminated after each cycle.
This provides a stable zero and
eliminates zero drift. In addition to
being more accurate and able to
measure lower flows, dc meters are
less bulky, easier to install, use less
energy, and have a lower cost of
ownership than ac meters. One new
dc design uses significantly more
power than the earlier generations
and thereby creates a stronger flowtube signal.
Another new design uses a unique
dual excitation scheme that pulses
the coils at 7 Hz for zero stability and
also at 70 Hz to obtain a stronger
signal. Magmeter transmitters can be
supplied with either ac or dc power.
A two-wire, loop-powered dc magnetic flowmeter is also available in
an intrinsically safe design, but its
performance is reduced because of
power limitations.
Pulsed ac meters have also been
introduced recently, eliminating the
TRANSACTIONS
zero stability problems of traditional
ac designs. These devices contain
circuitry that periodically disrupts
the ac power, automatically zeroing
out the effects of process noise on
the output signal.
Today, dc excitation is used in
about 85% of installations and ac
magmeters claim the other 15% when
justified by the following conditions:
air is entrained in large
quantities in the process stream;
• When the process stream is a slurry
and the solid particle sizes are not
uniform and/or the solid phase is
not homogeneously mixed within
the liquid; or
• When the flow is pulsating at a
frequency under 15 Hz.
When any of the above three
conditions exist, the output of a
pulsed dc meter is likely to be noisy.
In some cases, one can minimize the
noise problem (hold the fluctuations
within 1% of setpoint) by filtering and
damping the output signal. If more
than 1 to 3 seconds of damping is
required to eliminate the noise, it is
always better to use an ac meter.
• When
• Flowtubes, Liners, & Probes
The face-to-face dimensions of
flanged flowtubes (lay lengths) usually meet the recommendations of
the International Organization for
Standardization (ISO). The dimensions of short-form magmeters usu-
ally meet these guidelines as well.
Magnetic flowtubes and liners are
available in many materials and are
widely used in all the process industries, including food, pharmaceutical,
mining, and metals.
Some liner materials (particularly
Teflon®) can be damaged when pry
bars are used while installing it or
removing it from process piping.
They can also be damaged by overtorquing the flange bolts. Liner protectors are available to help prevent
such damage.
Any flowtube can generally be
used with any transmitter offered by
the same manufacturer. Depending
on its construction and features, the
cost of a 2-in. magnetic flowmeter
can range from $1,500 to $5,000.
This cost has been coming down, but
is still higher than that of the least
expensive flow sensors.
Magnetic flowmeters also can be
packaged as probes and inserted into
process pipes through taps. These
probes contain both the electrodes
and magnetic coils. The flowing process fluid induces a voltage at the
electrodes, which reflects the velocity at the probe tip and not the average fluid velocity across the pipe.
These magmeters are inexpensive
and retractable. Therefore, the process does not have to be shut down
to install or remove them. Metering
accuracy is highly dependent on the
relationship between the measured
velocity and the average velocity in
the pipe.
• Electrodes
In conventional flowtubes, the electrodes are in contact with the process
fluid. They can be removable or permanent if produced by a droplet of
liquid platinum as it sinters through a
ceramic liner and fuses with the aluminum oxide to form a perfect seal.
Volume 4
47
This design is preferred due to its
low cost, its resistance to abrasion
and wear, its insensitivity to nuclear radiation, and its suitability for
sanitary applications because there
are no cavities in which bacteria
can grow. On the other hand, the
ceramic tube cannot tolerate bending, tension, or sudden cooling and
cannot handle oxidizing acids or hot
and concentrated caustic.
mately 1/10 the pipe diameter) in
order to remain covered by the fluid.
Compensation is provided for wave
action and calibration is provided for
full pipe, no flow (static level), and
partially filled pipe operation.
Another recent development is a
magnetic flowmeter with an unlined
carbon steel flowtube. In this design,
the measuring electrodes mount
externally to the unlined flowtube
It is important that the conductivity of the process fluid be uniform. If
two fluids are mixed and the conductivity of one additive is significantly
different from that of the other process fluid, it is important that they
be completely intermixed before the
blend reaches the magmeter. If the
blend is not uniform, the output
signal will be noisy. To prevent that,
pockets of varying conductivity can
In a more recent capacitivelycoupled design, non-contacting electrodes are used. These designs use
areas of metal sandwiched between
layers of liner material. They are
available in sizes under eight inches
in diameter and with ceramic liners.
Magmeters using these non-contacting electrodes can “read” fluids having 100 times less conductivity than
required to actuate conventional
flowtubes. Because the electrode is
behind the liner, these designs are
also better suited for severe coating
applications.
and the magnetic coils generate a
field 15 times stronger than in a conventional tube. This magnetic field
penetrates deep into the process
fluid (not just around the electrode
as with standard magmeter probes).
The main advantage is low initial and
replacement costs, since only the
sensors need be replaced.
be eliminated by installing a static
mixer upstream of the magmeter.
Magmeter size is determined by
capacity tables or charts published
by the manufacturer. Figure 4-3 provides a flow capacity nomograph
for line sizes from 0.1 in. to 96 in.
For most applications, flow velocities should fall between 3 ft/sec
and 15 ft/sec. For corrosive fluids,
the normal velocity range should be
3-6 ft/sec. If the flowtube is continuously operated below 3 ft/sec,
metering accuracy will deteriorate,
while continuous operation exceeding the upper limit of the normal
velocity range will shorten the life
of the meter.
The obstructionless nature of the
magmeter lowers the likelihood of
plugging and limits the unrecovered
head loss to that of an equivalent
length of straight pipe. The low
pressure drop is desirable because
• Recent Developments
When a magnetic flowmeter is provided with a capacitance level sensor embedded in the liner, it can
also measure the flow in partially
full pipes. In this design, the magmeter electrodes are located at the
bottom of the tube (at approxi48
Volume 4
• Selection & Sizing
Magnetic flowmeters can detect the
flow of clean, multi-phase, dirty, corrosive, erosive, or viscous liquids and
slurries as long as their conductivity
exceeds the minimum required for
the particular design. The expected
inaccuracy and rangeability of the
better designs are from 0.2-1% of rate,
over a range of 10:1 to 30:1, if the flow
velocity exceeds 1 ft/sec. At slower
flow velocities (even below 0.1 ft/s),
measurement error increases, but the
readings remain repeatable.
TRANSACTIONS
it lowers pumping costs and aids
gravity feed systems.
• Problem Applications
The magmeter cannot distinguish
entrained air from the process fluid;
therefore, air bubbles will cause
the magmeter to read high. If the
trapped air is not homogeneously
dispersed, but takes the form of air
slugs or large air bubbles (the size
of the electrode), this will make the
output signal noisy or even disrupt
it. Therefore, in applications where
air entrainment is likely, the meter
should be sized so that the flow
velocity under normal flow conditions is 6-12 ft/sec.
Coating of the electrodes is another common magmeter problem.
Material build-up on the inner surfaces of the meter can electrically isolate the electrodes from the process
fluid. This can cause a loss of signal or
a measurement error, either by changing the diameter of the flowtube
or by causing span and zero shifts.
Naturally, the best solution is prevention. One preventive step is to size
the meter such that, under normal
flow conditions, the flowing velocity
will be relatively high: at least 6-12 ft/
sec, or as high as practical considering
the possibility of erosion and corrosion.
Another method of prevention is
to use electrodes that protrude into
the flow stream to take advantage of
the turbulence and washing effect.
In more severe service, a mechanical
cleaning system can be installed and
used intermittently or continuously
to eliminate coating and build-ups.
• Installation
The magnetic flowmeter must
always be full of liquid. Therefore,
the preferred location for magmeters is in vertical upward flow
TRANSACTIONS
lines. Installation in horizontal lines
is acceptable if the pipe section is
at a low point and if the electrodes
are not at the top of the pipe.
This prevents air from coming into
contact with the electrodes. When
the process fluid is a slurry and the
magmeter is installed at a low point,
it should be removed during long
periods of shutdown, so that solids
will not settle and coat the internals.
If it is essential to drain the magmeter periodically, it should be
provided with an empty tube zero
option. When this option is activated, the output of the transmitter will
be clamped to zero. Detection of
empty tube conditions is by circuitry
connected to extra sets of electrodes in the flowtube. The empty
tube zero feature can also be activated by an external contact, such as
liner wear. Liner protectors are available to protect the leading edge of
the liners from the abrasive effects
of process fluids. If the magmeter is
installed in a horizontal pipe exceeding 30 ft in length, the pipe should be
supported on both sides of the meter.
The magnetic flowmeter must be
electrically grounded to the process
liquid. This is because the magmeter
is part of the path for any stray current traveling down the pipeline or
through the process liquid. Bonding,
by grounding the meter at both ends
to the process fluid, provides a short
circuit for stray currents, routing
them around the flowtube instead
of through it. If the system is not
properly grounded, these currents
can create a zero shift in the magnetic flowmeter output.
Electrical bonding to the pro-
a pump status contact.
Magmeters require five diameters
of straight pipe upstream and two
diameters downstream in order to
maintain their accuracy and minimize
cess fluid can be achieved by metal
ground straps. These straps connect
each end of the flowtube to the
adjacent pipeline flanges, which, in
turn, are in contact with the proVolume 4
49
cess liquid. Straps are used when
the piping is electrically conductive.
When the pipe is non-conductive or
lined, grounding rings are used. The
grounding ring is like an orifice plate
with a bore equal to the nominal size
(inside diameter) of the flowtube. It is
installed between the flanges of the
flowtube and adjacent process piping on the upstream and downstream
sides. The flowtube is bonded to the
process fluid by being connected to
the metallic grounding rings, and is
grounded by being wired to a good
conductor, such as a cold water pipe.
In larger sizes and in exotic materials, grounding rings can become
expensive; grounding electrodes (a
Theodor von Karman discovered
that, when a non-streamlined object
(also called a bluff body) is placed in
the path of a fast-flowing stream, the
fluid will alternately separate from
the object on its two downstream
sides, and, as the boundary layer
becomes detached and curls back on
itself, the fluid forms vortices (also
called whirlpools or eddies). He also
noted that the distance between the
vortices was constant and depended
solely on the size of the rock that
formed it.
On the side of the bluff body
where the vortex is being formed, the
fluid velocity is higher and the pressure is lower. As the vortex moves
third electrode placed in the flowtube
for bonding with the process fluid) can
be used instead. Another cost-saving
option is to use a plastic grounding
ring with a metal electrode insert.
downstream, it grows in strength
and size, and eventually detaches
or sheds itself. This is followed by a
vortex's being formed on the other
side of the bluff body (Figure 4-4).
The alternating vortices are spaced
at equal distances.
The vortex-shedding phenomenon can be observed as wind is
Vortex Flowmeters
As a young person fishing in the mountain streams of the Transylvanian Alps,
50
Volume 4
shed from a flagpole (which acts as
a bluff body); this is what causes the
regular rippling one sees in a flag.
Vortices are also shed from bridge
piers, pilings, offshore drilling platform supports, and tall buildings. The
forces caused by the vortex-shedding phenomenon must be taken
into account when designing these
structures. In a closed piping system,
the vortex effect is dissipated within
a few pipe diameters downstream of
the bluff body and causes no harm.
• Vortex Meter Design
A vortex flowmeter is typically made of 316 stainless steel or
Hastelloy and includes a bluff body,
a vortex sensor assembly and the
transmitter electronics, although
the latter can also be mounted
remotely (Figure 4-5). They are typically available in flange sizes from
H in. to 12 in. The installed cost
of vortex meters is competitive
with that of orifice meters in sizes
under six inches. Wafer body meters
(flangeless) have the lowest cost,
while flanged meters are preferred
if the process fluid is hazardous or
is at a high temperature.
Bluff body shapes (square, rectangular, t-shaped, trapezoidal) and
dimensions have been experimented
with to achieve the desired characteristics. Testing has shown that
linearity, low Reynolds number limitation, and sensitivity to velocity
profile distortion vary only slightly
with bluff body shape. In size, the
bluff body must have a width that
is a large enough fraction of the
pipe diameter that the entire flow
participates in the shedding. Second,
the bluff body must have protruding
edges on the upstream face to fix
the lines of flow separation, regardless of the flow rate. Third, the bluff
body length in the direction of the
TRANSACTIONS
flow must be a certain multiple of
the bluff body width.
Today, the majority of vortex
meters use piezoelectric or capacitance-type sensors to detect
the pressure oscillation around
the bluff body. These detectors
respond to the pressure oscillation with a low voltage output signal which has the same frequency
as the oscillation. Such sensors are
modular, inexpensive, easily replaced,
and can operate over a wide range
of temperature ranges—from cryogenic liquids to superheated steam.
Sensors can be located inside the
meter body or outside. Wetted sensors are stressed directly by the
vortex pressure fluctuations and are
enclosed in hardened cases to withstand corrosion and erosion effects.
External sensors, typically piezoelectric strain gages, sense the vortex
shedding indirectly through the force
exerted on the shedder bar. External
sensors are preferred on highly erosive/corrosive applications to reduce
maintenance costs, while internal
sensors provide better rangeability
(better low flow sensitivity). They are
also less sensitive to pipe vibrations.
The electronics housing usually is
rated explosion- and weatherproof,
and contains the electronic transmitter module, termination connections,
and optionally a flow-rate indicator
and/or totalizer.
• Sizing & Rangeability
Vortex shedding frequency is directly
proportional to the velocity of the
fluid in the pipe, and therefore to
volumetric flow rate. The shedding
frequency is independent of fluid
properties such as density, viscosity,
conductivity, etc., except that the
flow must be turbulent for vortex
shedding to occur. The relationship
between vortex frequency and fluid
TRANSACTIONS
Q = AV = (A f d B)/St
velocity is:
St = f(d/V)
Where St is the Strouhal number,
f is the vortex shedding frequency,
d is the width of the bluff body,
and V is the average fluid velocity.
The value of the Strouhal number
is determined experimentally, and is
generally found to be constant over
a wide range of Reynolds numbers.
The Strouhal number represents the
ratio of the interval between vortex
shedding (l) and bluff body width (d),
which is about six (Figure 4-4). The
Strouhal number is a dimensionless
calibration factor used to characterize various bluff bodies. If their
Strouhal number is the same, then
two different bluff bodies will perform and behave similarly.
Because the volumetric flowrate
Q is the product of the average fluid
velocity and of the cross-sectional
area available for flow (A):
where B is the blockage factor,
defined as the open area left by the
bluff body divided by the full bore
area of the pipe. This equation, in
turn, can be rewritten as:
Q=fK
where K is the meter coefficient,
equal to the product (A f d B). As
with turbine and other frequencyproducing flowmeters, the K factor
can be defined as pulses per unit
volume (pulses per gallon, pulses per
cubic foot, etc.). Therefore, one can
determine flowrate by counting the
pulses per unit time. Vortex frequencies range from one to thousands of
pulses per second, depending upon
the flow velocity, the character of
the process fluid, and the size of the
meter. In gas service, frequencies are
about 10 times higher than in liquid
applications.
The K factor is determined by the
Volume 4
51
52
manufacturer, usually by water calibration in a flow lab. Because the K
factor is the same for liquid, gas and
vapor applications, the value determined from a water calibration is valid
for any other fluid. The calibration
factor (K) at moderate Reynolds numbers is not sensitive to edge sharpness
In order to minimize measurement noise, it is important to select
a meter that will adequately handle
both the minimum and maximum
process flows that will be measured.
It is recommended that the minimum
flow rate to be measured be at least
twice the minimum flow rate detect-
to give some indication at near zero
flows, the vortex meter is provided
with a cut-off point. Below this level,
the meter output is automatically
clamped at zero (4 mA for analog
transmitters). This cut-off point corresponds to a Reynolds number at or
below 10,000. If the minimum flow
or other dimensional changes that
affect square-edged orifice meters.
Although vortex meter equations
are relatively simple compared to
those for orifice plates, there are
many rules and considerations to
keep in mind. Manufacturers offer
free computer software for sizing,
wherewith the user enters the fluid's
properties (density, viscosity, and
desired flow range) and the program
automatically sizes the meter.
The force generated by the vortex
pressure pulse is a function of fluid
density multiplied by the square
of fluid velocity. The requirement
that there be turbulent flow and
force sufficient to actuate the sensor
determines the meter’s rangeability.
This force has to be high enough to
be distinguishable from noise. For
example, a typical 2-in. vortex meter
has a water flow range of 12 to 230
gpm. If the density or viscosity of the
fluid differs from that of water, the
meter range will change.
able by the meter. The maximum
capacity of the meter should be at
least five times the anticipated maximum flowrate.
that one needs to measure is at least
twice the cut-off flow, this does not
pose a problem. On the other hand,
it can still be a drawback if low flowrate information is desired during
start-up, shutdown, or other upset
conditions.
Volume 4
• Accuracy & Rangeability
Because the Reynolds number drops
as viscosity rises, vortex flowmeter
rangeability suffers as the viscosity
rises. The maximum viscosity limit,
as a function of allowable accuracy
and rangeability, is between 8 and
30 centipoises. One can expect a
better than 20:1 rangeability for gas
and steam service and over 10:1 for
low-viscosity liquid applications if
the vortex meter has been sized
properly for the application.
The inaccuracy of most vortex
meters is 0.5-1% of rate for Reynolds
numbers over 30,000. As the
Reynolds number drops, metering
error increases. At Reynolds numbers
less than 10,000, error can reach 10%
of actual flow.
While most flowmeters continue
• Recent Developments
Smart vortex meters provide a digital output signal containing more
information than just flow rate. The
microprocessor in the flowmeter
can automatically correct for insufficient straight pipe conditions,
for differences between the bore
diameter and that of the mating
pipe, for thermal expansion of the
bluff body, and for K-factor changes
when the Reynolds number drops
below 10,000.
Intelligent transmitters are also
provided with diagnostic subroutines
to signal component or other failures. Smart transmitters can initiate
testing routines to identify problems
TRANSACTIONS
with both the meter and with the
application. These on-demand tests
can also assist in ISO 9000 verification.
Some recently introduced vortex
flowmeters can detect mass flow.
One such design measures both the
vortex frequency and the vortex
pulse strength simultaneously. From
these readings, the density of the
process fluid can be determined and
the mass flow calculated to within
2% of span.
Another newer design is provided
with multiple sensors to detect not
only the vortex frequency, but also
the temperature and pressure of the
process fluid. Based on that data, it
determines both the density and the
mass flow rate. This meter offers a
1.25% of rate accuracy when measuring the mass flow of liquids and a
2% of rate accuracy for gases and
steam. If knowledge of process pressure and temperature is of value for
other reasons, this meter provides a
convenient, less costly alternative to
installing separate transmitters.
normal flow, the vortex flowmeter
can still be considered.
If the process fluid tends to coat
or build-up on the bluff body, as
in sludge and slurry service, this
will eventually change the meter’s
K factor. Vortex-shedding flowmeters are not recommended for such
applications. If, however, a dirty
fluid has only moderate amounts of
non-coating solids, the application
is likely to be acceptable. This was
demonstrated by a 2-year test on a
limestone slurry. At the end of the
test, the K factor was found to have
changed only 0.3% from the original factory calibration, although the
bluff body and flowtube were badly
scarred and pitted.
When measuring multi-phase flow
(solid particles in gas or liquid; gas
bubbles in liquid; liquid droplets in
gas), vortex meter accuracy will drop
because of the meter’s inability to
differentiate between the phases.
Wet, low-quality steam is one such
kept open at the bottom. This can
be achieved by installing the bluff
body horizontally. Measurement
inaccuracy in such applications is
about 5% of actual flow, but with
good repeatability.
The permanent pressure loss
through a vortex meter is about
half that of an orifice plate, roughly
two velocity heads. (A velocity head
is defined as V2/g, where V is the
flow velocity and g is the gravitational constant in consistent units.)
If the pipe and meter are properly
sized and of the same size, the pressure drop is likely to be only a few
psi. However, downsizing (installing a smaller-than-line-size meter)
in order to increase the Reynolds
can increase the head loss to more
than 10 psi. One should also make
sure that the vena contracta pressure
does not drop below the vapor pressure of the process fluid, because that
would cause cavitation. Naturally, if
the back-pressure on the meter is
application: the liquid phase should
be homogeneously dispersed within
the steam, and vertical flow lines
should be avoided to prevent slugging. When the pipe is horizontal, the
liquid phase is likely to travel on the
bottom of the pipe, and therefore
the inner area of the pipe should be
below the vapor pressure, the process
fluid will flash and the meter reading
will not be meaningful.
The main advantages of vortex
meters are their low sensitivity to
variations in process conditions and
low wear relative to orifices or turbine meters. Also, initial and mainte-
• Applications & Limitations
Vortex meters are not usually recommended for batching or other
intermittent flow applications. This
is because the dribble flow-rate
setting of the batching station can
fall below the meter’s minimum
Reynolds number limit. The smaller
the total batch, the more significant
the resulting error is likely to be.
Low pressure (low density) gases
do not produce a strong enough
pressure pulse, especially if fluid
velocities are low. Therefore, it
is likely that in such services the
rangeability of the meter will be
poor and low flows will not be
measurable. On the other hand, if
reduced rangeability is acceptable
and the meter is correctly sized for
TRANSACTIONS
Volume 4
53
When installing a vortex flowmeter
in an existing process where the flow
range is not known, it is recommended to first make some approximate
measurements (using portable pitot
or clamp-on ultrasonic devices).
down” of oversized process piping
by concentric reducers and expanders. Even if flow straighteners are
installed, some straight (relaxation)
piping will still be required.
Vortex meters can be installed
vertically, horizontally, or at any
angle, as long as they are kept flooded. The meter can be kept flooded
by installing it in a vertical upward
flow line (Figure 4-6B). When install-
be carefully aligned to eliminate any
obstructions or steps.
Excessive pipe vibration can be
eliminated by supporting the piping on both sides of the meter, or
by rotating the meter so that the
sensor is moved out of the plane
of the vibration. Process noise due
to valve chattering, steam traps, or
pumps can result in high readings or
non-zero readings under zero-flow
Otherwise, there is no guarantee that
a line-size vortex meter will work at
all.
The vortex meter requires a welldeveloped and symmetrical flow
velocity profile, free from any distortions or swirls. This necessitates the
use of straight up- and downstream
piping to condition the flow. The
straight length of pipe must be the
same size as the meter (Figure 4-6) and
its length should be about the same
as required for an orifice installation
with a beta ratio of 0.7 (see Chapter
2). Most vortex flowmeter manufacturers recommend a minimum of 30
pipe diameters downstream of control valves, and 3 to 4 pipe diameters
between the meter and downstream
pressure taps. Temperature elements
should be small and located 5 to 6
diameters downstream.
About half of all vortex meter
installations require the “necking
ing the flowmeter in a downward
(Figure 4-6C) or horizontal (Figure
4-6D) flow, the downstream piping should be kept elevated. Check
valves can be used to keep the piping
full of liquid when there is no flow.
Block and bypass valves are required
if the replacement of the sensor in
the particular design requires the
stopping of the flow and the opening up of the process.
Mating flanges (on the schedule
40 or schedule 80 mating piping)
must have the same diameter and
smooth bore as the flowmeter.
Weld neck flanges are preferred, and
reducing flanges should not be used.
The inner surface of the mating pipe
should be free from mill scale, pits,
holes, reaming scores and bumps for
a distance of 4 diameters upstream
and 2 diameters downstream of the
meter. The bores of the meter, the
gaskets and the adjacent piping must
conditions. Most meter electronics
allow for increasing the noise filter
settings, but increased noise reduction usually also decreases the lowflow sensitivity of the meter. One
option is to relocate the meter to a
less noisy part of the process.
nance costs are low. For these reasons, they have been gaining wider
acceptance among users.
• Installation Recommendations
54
Volume 4
Ultrasonic Flowmeters
The speed at which sound propagates in a fluid is dependent on
the fluid’s density. If the density
is constant, however, one can use
the time of ultrasonic passage (or
reflection) to determine the velocity of a flowing fluid.
Some manufacturers produce
transducer systems that operate in
the shear-mode, sending a single
pulse and receiving a single pulse
in return. Narrow-beam systems are
commonly subject to walk-away (the
signal completely missing the downstream transducer). Wide-beam
TRANSACTIONS
systems overcome beam refraction
and work better in changing liquid
density and temperature. With the
advent of digital signal processing, it
has become possible to apply digital
signal coding to the transmitted signal. This can eliminate many of the
problems associated with noise and
variations in liquid chemistry.
• The Doppler Shift
In 1842, Christian Doppler discovered that the wavelength of sound
perceived by a stationary observer
appears shorter when the source is
approaching and longer when the
source is moving away. This shift in
frequency is the basis upon which all
Doppler-shift ultrasonic flowmeters
work.
Doppler flowmeter transducers
operate at 0.640 MHz (in clamp-on
designs) and at 1.2 MHz in wetted sensor designs. The transducer
sends an ultrasonic pulse or beam
into the flowing stream. The sound
waves are reflected back by such
acoustical discontinuities as particles, entrained gas bubbles, or even
by turbulence vortices (Figure 4-7A).
For clamp-on designs, measurement
inaccuracy ranges from ±1% to ±5%
full scale (FS).
The meter detects the velocity of
the discontinuities, rather than the
velocity of the fluid, in calculating
the flow rate. The flow velocity (V)
can be determined by:
fied to:
V = (f0 - f1)K
Thus, flow velocity V (ft/sec) is
directly proportional to the change
in frequency. The flow (Q in gpm) in a
pipe having a certain inside diameter
(ID in inches) can be obtained by:
Q = 2.45V(ID)2 = 2.45[(f0 - f1)K](ID)2
The presence of acoustical discontinuities is essential for the
proper operation of the Doppler
flowmeter. The generally accepted
rule of thumb is that for proper
signal reflection there be a minimum of 80-100 mg/l of solids with
a particle size of +200 mesh (+75
micron). In the case of bubbles, 100200 mg/l with diameters between
+75 and +150 microns is desirable. If
either the size or the concentration
of the discontinuities changes, the
amplitude of the reflected signal
will shift, introducing errors.
Doppler flowmeters are often used
to measure the flow of such fluids as
slurries. If the solids concentration
is too high (in excess of 45% by
not be distinguished from the background noise in the pipe.
The reflected Doppler signal
is
shifted from the transmitted
frequency by approximately 6 Hz for
every foot per second of velocity.
Therefore, if the flow velocity is less
than 1 ft/sec, ultrasonic flowmetering is not practical. There seems to
be no upper limit to detectable flow
velocity, as successful installations at
velocities in the 40-50 ft/sec range
are well documented.
• Transit Time Measurement
In this design, the time of flight of the
ultrasonic signal is measured between
two transducers—one upstream and
one downstream (Figure 4-7B). The
difference in elapsed time going with
or against the flow determines the
fluid velocity.
When the flow is zero, the time for
the signal T1 to get to T2 is the same
as that required to get from T2 to T1.
When there is flow, the effect is to
boost the speed of the signal in the
downstream direction, while decreasing it in the upstream direction. The
flowing velocity (Vf) can be determined by the following equation:
V = (f0 - f1)Ct /2f0 cos(a)
Where Ct is the velocity of sound
inside the transducer, f0 is the transmission frequency, f1 is the reflected
frequency, and a is the angle of
the transmitter and receiver crystals with respect to the pipe axis.
Because Ct /2f0cos(a) is a constant
(K), the relationship can be simpliTRANSACTIONS
weight), or if too much air or gas is
entrained (especially if the bubbles
are very fine), these discontinuities
will attenuate the reflected Doppler
signal to the point where it can-
Vf = Kdt/TL
where K is a calibration factor for the
volume and time units used, dt is the
Volume 4
55
time differential between upstream
and downstream transit times, and TL
is the zero-flow transit time.
Theoretically, transit-time ultrasonic meters can be very accurate
(inaccuracy of ±0.1% of reading is
sometimes claimed). Yet the error
potted into the same sensor body,
which is clamped onto a single point
of the pipe surface (Figure 4-8). In
the dual-sensor version, the transmit
crystal is in one sensor body, while
the receive crystal is in another.
Clamp-on transit time meters have
in these measurements is limited by
both the ability of the signal processing electronics to determine the transit time and by the degree to which
the sonic velocity (C) is constant. The
speed of sound in the fluid is a function of both density and temperature.
Therefore, both have to be compensated for. In addition, the change in
sonic velocity can change the refraction angle (“a” in Figure 4-7B), which
in turn will affect the distance the
signal has to travel. In extreme cases,
the signal might completely miss the
downstream receiver. Again, this type
of failure is known as walk-away.
been available since the early 1970s.
Their aim is to rival the performance
of wetted spool-piece designs, but
without the need to break the pipe or
stop the process to install the meter.
This goal has not yet been reached.
Clamp-on Doppler flowmeters
are subject to interference from the
pipe wall itself, as well as from any
air space between the sensor and
the wall. If the pipe wall is made of
stainless steel, it might conduct the
transmit signal far enough so that
the returning echo will be shifted
enough to interfere with the reading. There are also built-in acoustic
discontinuities in concrete-lined,
plastic-lined, and fiberglass-reinforced pipes. These are significant
enough to either completely scatter the transmitted signal or attenuate the return signal. This dramati-
• Design Variations
Clamp-on ultrasonic meters come
in either single or dual-sensor versions. In the single-sensor version,
the transmit and receive crystals are
56
Volume 4
cally decreases flowmeter accuracy
(to within only ±20%), and, in most
cases, clamp-on meters will not work
at all if the pipe is lined.
Wetted transducer designs—both
Doppler and transit time are available—overcome many of these signal
attenuation limitations. The full-pipe
transit-time meter originally consisted
of a flanged spool section with wetted transducers mounted in the pipe
wall in transducer wells opposite to
one another but at 45-degree angles
to the flow (Figure 4-9A). Transit-time
flowmeters can be either single-path
or multiple-path designs (Figure 4-9B).
Single-path flowmeters are provided with a single pair of transducers that make a single-line velocity
measurement. They use a meter factor that is pre-determined by calibration to compensate for variations in
velocity profile and for flow section
construction irregularities.
In the design of multi-path flowmeters, several sets of transducers
are placed in different paths across
the flow section, thereby attempting to measure the velocity profile across the entire cross-section
of the pipe. Multi-path instruments
are used in large-diameter conduits,
such as utility stacks, and in other
applications where non-uniform
flow velocity profiles exist.
Transit-time meters can also be
used to measure both very hot (e.g.,
liquid sulfur) and very cold (liquid
nitrogen) fluids, and also to detect
very low flows. Wetted-transducer
designs for small pipes (down to H
in.) are called axial or co-axial designs
(Figure 4-10). These devices permit
transit-time measurement along a
path length significantly greater than
the diameter of the pipe, increasing
low-flow sensitivity.
Originally, ultrasonic flowmeters
were divided into those using the
TRANSACTIONS
Doppler-shift principle and those
using the transit-time principle. More
recently, flowmeters are capable of
measuring the flow of both clean
fluids and of slurries with entrained
solids or other acoustical discontinuities. Microprocessors have made
it possible to switch automatically
from clean fluid mode to particulate
mode based on the "correlation factor". This figure of merit dramatically
improves the accuracy of overall
performance. In some carefully engineered applications, installed accuracy to within 0.5% of reading has
been reported.
• Applications & Performance
Doppler flowmeters are not recommended for clean fluid applications. Transit-time flowmeters, on
the other hand, are often used to
measure the flow of crude oils and
simple fractions in the petroleum
industry. They also work well with
viscous liquids, provided that the
Reynolds number at minimum flow is
either less than 4,000 (laminar flow)
or above 10,000 (turbulent flow).
Serious non-linearities are present
in the transition region (Figure 4-11).
Transit-time flowmeters are the
standard for measuring cryogenic
liquids down to -300°C and are also
used in molten metal flowmetering.
Measurement of liquid argon, liquid
nitrogen, liquid helium and molten
sulfur have often been reported.
Spool-section type flowmeters are
most often used for these applications, especially the axial and coaxial designs.
Raw wastewater applications usually have too few acoustic discontinuities for Doppler flowmeters. On
the other hand, raw wastewater is not
clean enough all the time for transittime measurement. Other wastewater-related applications are equally
TRANSACTIONS
problematic, as the solids concentration can be too high for either transittime or Doppler flowmeters to work
properly. In still other wastewater
applications, the problem is that the
acoustical absorbency of the mostly
organic solids in wastewater attenuates the ultrasonic signals.
The use of multi-path flowmeters in raw wastewater and storm
water applications is common, while
Doppler or cross-correlation hybrid
designs are most often used to measure activated sludge and digested
sludge flows.
For mining slurries, Doppler flowmeters typically work well. Among
the few problem applications are
those in HDPE pipe, because the
pipe wall flexes enough to change
the diameter of the measurement
area. This affects the accuracy of
the meter. In addition, the flexure
of the pipe wall can often break the
acoustic coupling of the transducer
to the outside of the pipe, causing failure. Another problem area is
the measurement of slurries that are
acoustically absorbent, such as lime
or kaolin slurries. These applications
fail because the highly absorbent
solids attenuate the signal below
usable strength. Lower frequency
(0.45 MHz) sensors have been tried
for these applications, but success
has been limited.
Multi-path, transit-time flowmeters also measure stack gas flows in
power-plant scrubbers, even in very
large diameter stacks.
T
References & Further Reading
•OMEGA
Complete Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•“An Intelligent Vortex Flowmeter,” T. Kamano and others, ISA/92
Proceedings, Instrument Society of America, 1992.
•“Application and Installation Guidelines for Volumetric and Mass
Flowmeters,” D. Ginesi and C. Annarummo, ISA Transactions, 1994.
•“Clamp-On Leak Detectors Protect Mid-Valley Line,” S. Douglas and J.
Baumoel, Pipeline & Gas Journal, April 1993.
•“Committee Report: Transit Time Ultrasonic Flowmeters,” AWWA
Subcommittee on Ultrasonic Devices, AWWA Journal, July 1997.
•Flow Measurement Engineering Handbook, R.W. Miller, McGraw Hill, 1996.
•Flow Measurement, D.W. Spitzer, editor, Instrument Society of America,
1991.
•“Flow Sensing: The Next Generation,” D. Ginesi, Control Engineering,
November 1997.
•Flowmeters in Water Supply, Manual M33, AWWA, 1989.
•Industrial Flow Measurement, D.W. Spitzer, ISA, 1984
•Instrument Engineers’ Handbook, Bela Liptak, editor, CRC Press, 1995.
•Ultrasonic Clamp-On Flowmeters: Have They Finally Arrived?,” P. Espina,
Flow Control, January 1997.
•Water Meters - Selection, Installation, Testing and Maintenance, Manual
M6, AWWA, 1986.
Volume 4
57
M
ass flow measurement is
the basis of most recipe
formulations, material
balance determinations,
and billing and custody transfer
operations throughout industry. With
these being the most critical flow
measurements in a processing plant,
the reliability and accuracy of mass
flow detection is very important.
In the past, mass flow was often
calculated from the outputs of a
volumetric flowmeter and a densitometer. Density was either directly
measured (Figure 5-1A), or was calculated using the outputs of process
temperature and pressure transmitters. These measurements were not
very accurate, because the relationship between process pressure or
temperature and density are not
always precisely known—each sen-
Mass Flowmeters
5-1B). It had a motor-driven impeller
that imparted angular momentum
(rotary motion) by accelerating the
fluid to a constant angular velocity.
The higher the density, the more
angular momentum was required
to obtain this angular velocity.
Downstream of the driven impeller,
a spring-held stationary turbine was
exposed to this angular momentum.
The resulting torque (spring torsion)
was an indication of mass flow.
These meters all had moving parts
and complex mechanical designs.
First developed for the measurement
of aircraft fuel, some are still in use.
However, because of their complex
nature and high maintenance costs,
they are gradually being replaced by
more robust and less maintenancedemanding designs.
Mass flow also can be measured
lower one will measure the hydrostatic head over a fixed elevational
distance. This pressure differential
yields the density of the material in
the tank. Such systems have been
used to measure the total mass flow
of slurries.
Coriolis Mass Flowmeters
It was G.G. Coriolis, a French engineer, who first noted that all bodies
moving on the surface of the Earth
tend to drift sideways because of
the eastward rotation of the planet. In the Northern Hemisphere the
deflection is to the right of the
motion; in the Southern, it is to the
left. This drift plays a principal role in
both the tidal activity of the oceans
and the weather of the planet.
Because a point on the equator
traces out a larger circle per day
Y
sor adds its own separate error to
the overall measurement error, and
the speed of response of such calculations is usually not sufficient to
detect step changes in flow.
One of the early designs of selfcontained mass flowmeters operated using angular momentum (Figure
58
Volume 4
by batch weighing or by combining an accurate level sensor with a
densitometer. Another method is to
mount two d/p transmitters on the
lower part of an atmospheric tank at
different elevations. In this case, the
output of the top d/p cell will vary
with the level in the tank, while the
than a point nearer the poles, a body
traveling towards either pole will
bear eastward, because it retains its
higher (eastward) rotational speed as
it passes over the more slowly rotating surface of the earth. This drift is
defined as the Coriolis force.
The first industrial Coriolis patTRANSACTIONS
ents date back to the 1950s, and the
first Coriolis mass flowmeters were
built in the 1970s. These flowmeters
artificially introduce a Coriolis acceleration into the flowing stream and
measure mass flow by detecting the
resulting angular momentum.
When a fluid is flowing in a
pipe and it is subjected to Coriolis
acceleration through the mechani-
ar (centripetal) = w2r
at (Coriolis) = 2wv
In order to impart the Coriolis acceleration (at) to the fluid particle, a
force of at (dm) has to generated by
the tube. The fluid particle reacts to
this force with an equal and opposite
Coriolis force:
tical when building a commercial
flowmeter, but oscillating or vibrating the tube can achieve the same
effect. Coriolis flowmeters can measure flow through the tube in either
the forward or reverse directions.
In most designs, the tube is
anchored at two points and vibrated
between these anchors.
This configuration can be envisioned as vibrating a spring and mass
assembly. Once placed in motion, a
spring and mass assembly will vibrate
at its resonant frequency, which
is a function of the mass of that
assembly. This resonant frequency is
selected because the smallest driving force is needed to keep the filled
tube in constant vibration.
• Tube Designs
cal introduction of apparent rotation into the pipe, the amount
of deflecting force generated by
the Coriolis inertial effect will be
a function of the mass flow rate
of the fluid. If a pipe is rotated
around a point while liquid is flowing through it (toward or away from
the center of rotation), that fluid
will generate an inertial force (acting on the pipe) that will be at right
angles to the direction of the flow.
With reference to Figure 5-2, a
particle (dm) travels at a velocity (V)
inside a tube (T). The tube is rotating about a fixed point (P), and the
particle is at a distance of one radius
(R) from the fixed point. The particle
moves with angular velocity (w) under
two components of acceleration, a
centripetal acceleration directed
toward P and a Coriolis acceleration
acting at right angles to ar:
TRANSACTIONS
Fc = at(dm) = 2wv(dm)
Then, if the process fluid has density
D and is flowing at constant speed
inside a rotating tube of cross-sectional area A, a segment of the tube
of length x will experience a Coriolis
force of magnitude:
Fc = 2wvDAx
Because the mass flowrate is dm =
DvA, the Coriolis force Fc = 2w(dm)
x and, finally:
Mass Flow = Fc/(2wx)
This is how measurement of the
Coriolis force exerted by the flowing
fluid on the rotating tube can provide an indication of mass flowrate.
Naturally, rotating a tube is not prac-
A tube can be of a curved or straight
form, and some designs can also be
self-draining when mounted vertically (Figure 5-3). When the design
consists of two parallel tubes, flow
is divided into two streams by a
splitter near the meter’s inlet and is
recombined at the exit. In the single
continuous tube design (or in two
tubes joined in series), the flow is not
split inside the meter.
In either case, drivers vibrate the
tubes. These drivers consist of a coil
connected to one tube and a magnet
connected to the other. The transmitter applies an alternating current to
the coil, which causes the magnet to
be attracted and repelled by turns,
thereby forcing the tubes towards
and away from one another. The sensor can detect the position, velocity, or acceleration of the tubes.
If electromagnetic sensors are used,
the magnet and coil in the sensor
change their relative positions as the
tubes vibrate, causing a change in the
magnetic field of the coil. Therefore,
the sinusoidal voltage output from
Volume 4
59
60
the coil represents the motion of the
tubes.
When there is no flow in a twotube design (Figure 5-3A), the vibration caused by the coil and magnet
drive results in identical displacements at the two sensing points
(B1 and B2). When flow is present,
Coriolis forces act to produce a secondary twisting vibration, resulting in
a small phase difference in the relative motions. This is detected at the
sensing points. The deflection of the
of its geometry, materials of construction, and the mass of the tube
assembly (mass of the tube plus the
mass of the fluid inside the tube).
The mass of the tube is fixed. Since
mass of the fluid is its density (D)
multiplied by its volume (which is
also fixed), the frequency of vibration can be related to the density of
the process fluid (D). Therefore, the
density of the fluid can be determined by measuring the resonant
frequency of oscillation of the tubes.
ing, which drastically increases the
flowing velocity (from 5-10 ft/sec
to more than 25 ft/sec). Designs
with thin walls and high fluid velocities (that is, small bore tubing), may
require the use of exotic materials
because of erosion concerns. One
will obtain the longest meter life by
selecting the design with the thickest
wall and the slowest flow velocity
that can provide the required accuracy and range.
The Coriolis meter may need to be
tubes caused by the Coriolis force
only exists when both axial fluid
flow and tube vibration are present.
Vibration at zero flow, or flow without vibration, does not produce an
output from the meter.
The natural resonance frequency
of the tube structure is a function
(Note that density can be measured
at zero flow, as long as the tubes are
filled with fluid and vibrating.)
Wall thickness varies considerably
from design to design; however, even
the sturdiest tubing will be thinner
than the process piping. In addition,
some designs use small bore tub-
made out of exotic materials because
of corrosion considerations or to
prevent pitting. Carbon or stainless
steel can often be used in process
piping, because a small amount of
pitting can be tolerated. In case of
the Coriolis meter, even a small
amount of pitting cannot be toler-
Volume 4
TRANSACTIONS
ated because the walls are thin, and
pitting induces stress concentrations
within the tube structure. Therefore,
standard corrosion tables (based on
weight loss criteria) are not suitable
for selecting Coriolis tube materials,
and the stricter guidelines of the
manufacturers must be used.
Other features may require information to be pre-programmed into
the transmitter memory. In addition,
transmitters have other hardware and
software options which allow the
user to customize them to the appli-
bending forces were created at the
anchor points. This resulted in severe
vibration problems, which were alleviated by two-tube designs (Figure
5-3A).
These designs reduced external
cation.
vibration interference, decreased the
power needed to vibrate the tubes,
and minimized the vibrational energy leaving the tube structure. One
driver was used to initiate tube vibration, and two sensors were used to
detect the Coriolis deflections. While
this design greatly improved performance, the combination of reduced
bore, thin-walled tubing, and high
fluid velocities (up to 50 ft/sec) still
resulted in premature meter failure,
including potentially catastrophic
• Transmitter Designs
Transmitters can operate on either
ac or dc power and require separate
wiring for the power supply and
for their output signals. The Coriolis
flowmeter transmitter can be integrally
or remotely mounted (Figure 5-4).
The transmitter controls the operation of the driver and processes and
transmits the sensor signals. The calibration factor (K) in the transmitter’s
memory matches the transmitter to
the particular flow tube. This calibration factor defines the constant of
proportionality between the Coriolis
force and the mass flow rate for the
dynamic spring constant of the particular vibrating tubes.
The transmitter does more than
convert sensor inputs into standardized output signals. Most transmitters also offer multiple outputs,
including mass flow rate, total mass
flow, density, and temperature.
Analog and/or pulse outputs are
both available, and intelligent transmitters can generate digital outputs
for integration into DCS systems.
Transmitters are often provided
with a local displays and keypads to
allow easy access to process data.
Coriolis transmitters provide more
than just flow information and ancillary functions. Batch control functions, percent Brix or percent HFCS
monitoring, viscosity, percent solids,
PID, API gravity, and specific gravity also are available. When viscosity information is desired, the meter
pressure drop needs to be measured.
TRANSACTIONS
• Coriolis Evolution
The first generation of Coriolis
meters consisted of a single curved
and a thin-walled tube, in which
high fluid velocities were created
by reducing the tube cross-sectional
area in relation to the process pipe.
The tube distortion was measured in
reference to a fixed point or plane.
The tubes were excited in such a
way that localized high amplitude
Volume 4
61
62
spills when the meter was used on
corrosive and erosive services. In
addition, the unrecovered head losses
are as reliable and rugged as traditional volumetric flowmeters. The
new designs operate at lower fluid
for variations in tube elasticity.
Coriolis mass flowmeters usually
are calibrated on water, because the
were high (sometimes over 50 psid),
and accuracy was not high enough
to allow users to convert batch processes into continuous ones.
More recent design improvements include the introduction of a
variety of new tube shapes, including ones that do not split the flow
(Figure 5-3B) and the use of multiple
drivers (Figure 5-5A). Thick-walled
tubing (five times thicker than early
designs), the use of full bore diameters and heavy manifolds to isolate
the tube structure from stresses
induced from piping connections,
and flowtube housings that double
as secondary containment vessels
have all contributed to improved
performance.
In some designs, torsional stresses
replaced bending, in order to prevent the concentration of stresses
that can lead to tube cracking (Figure
5-5B). In other designs, the effects of
pipeline vibration have been minimized by mounting the tube structures transverse to the pipeline.
These improvements increased
the number of suppliers and contributed to the development of a new
generation of Coriolis meters that
velocities (below 10 ft/sec) and at
lower pressure drops (under 12 psid),
can be installed in any orientation,
and provide longer service life on
slurry, viscous, corrosive, or erosive
services. The tubes are vibrated well
below their endurance limits, and
typically are made of stainless steel,
Hastelloy, and titanium.
constants are valid for all other liquids. Calibration for density is usually
done by filling the tubes with two or
more (stagnant) calibration fluids of
known densities.
Volume 4
• Interferences
The effect of the Coriolis force on
the vibrating tube is small. Full-scale
flow might cause a deflection of
only 0.001 inch. To obtain a flow
rangeability of 100:1, sensors must
be able to detect deflections to
an accuracy of 0.000001 inch in
industrial environments where the
process pressure, temperature, and
fluid density are all changing, and
where pipe vibration interferes with
measurement.
The elasticity of metal tubes
changes with temperature; they
become more elastic as they get
warmer. To eliminate the corresponding measurement error, the
tube temperature is continuously
measured by an RTD element and
is used to continuously compensate
• Accuracy & Rangeability
Coriolis meters provide 0.1-2% of
rate inaccuracy over a mass flow
range of up to 100:1. In general,
curved tube designs provide wider
rangeability (100:1 to 200:1), while
straight-tube meters are limited to
30:1 to 50:1 and their accuracy is
lower. Overall meter error is the
sum of base inaccuracy and zeroshift error, the error attributable to
the irregular output signal generated
at zero flow conditions. Zero-shift
error becomes the dominant portion of total error at the lower end
of the flow range, where the error
is between 1% and 2% of rate. Some
manufacturers state the overall
accuracy as a percentage of rate for
the upper portion of the flow range
and as a percentage of span for the
lower portion, while others state it
as a percentage of rate plus a zeroshift error. There is a fair amount of
“specmanship,” and one must read
TRANSACTIONS
sales literature carefully when comparing different devices.
When used for density measurement, the typical error range of
a Coriolis measurement is 0.0020.0005 g/cc.
Errors are caused by air or gas
pockets in the process fluid. In the
case of homogeneously dispersed
small bubbles, more power is
required to vibrate the tubes, whereas, if the gas phase separates from
the liquid, a damping effect on tube
vibration (and, consequently, error)
develops. Small voids also cause
noise because of the sloshing of the
process liquid in the tubes. Larger
voids will raise the energy required
to vibrate the tubes to excessive levels and may cause complete failure.
Because the flowtube is subjected
to axial, bending, and torsional forces
during meter operation, if process
or ambient temperature and pressure
fluctuations alter these forces, performance may be affected and re-zeroing
TRANSACTIONS
of the meter may be required.
Variations in the density of the
process fluid can affect the frequency
transfer function of mechanical systems, necessitating the re-zeroing of
older designs to protect them from
degraded performance. Because of
their tube configurations, newer
designs are unaffected by density
changes over wide ranges of specific
gravity variations.
Because of the wide rangeability of
Coriolis flowmeters (30:1 to as high
as 200:1), the same flow can be measured by two or three different sized
flow tubes. By using the smallest
possible meter, one will lower the
initial cost and reduce coating build-
process fluid is clean with a low
viscosity. On corrosive, viscous, or
abrasive slurry services, downsizing is
not recommended. A list of acceptable flow tube sizes and corresponding pressure drops, inaccuracies, and
flow velocities can be obtained from
software provided by the manufacturer.
Different Coriolis meters incur different pressure drops, but in general
they require more than traditional volumetric meters, which usually operate at less than 10 psid. (The
yearly electricity cost of pumping
1 gpm across a differential of 10 psid
is about $5 U.S.). This higher head loss
is due to the reduced tubing diameter and the circuitous path of flow.
Besides pumping costs, head loss can
up, but will increase erosion/corrosion rates and head loss, increasing
pumping and operating costs.
Downsizing (using a meter that is
smaller than the pipe) is acceptable
when the pipe is oversized and the
be of concern if the meter is installed
in a low-pressure system, or if there is
a potential for cavitation or flashing,
or if the fluid viscosity is very high.
The viscosity of non-Newtonian
fluids is a function of their flowing
• Sizing & Pressure Drop
Volume 4
63
velocity. Dilettante fluids, for example, increase their apparent viscosity
(resistance to flow) as their velocity
is increased. This apparent viscosity
can be drastically higher than their
viscosity when stagnant. In order to
provide suppliers with data on the
Therefore, the amount of driving
power that can be delivered to the
flow tube is limited.
When fluid is unloaded from tank
trucks, drums, or railroad cars, slug
flow can occur, making the meter
output unpredictable. If a slug-flow
in low viscosity fluids, like milk, will
separate at concentrations as low as
1%.
The cost of an average-sized
(under 2 in.) Coriolis flowmeter is
between $4,000 and $5,000. These
mass flowmeters provide short
flowing viscosity in a particular pipe,
head loss per foot of pipe (used
in pump sizing calculations) can be
used as an approximation.
recovery feature is provided in the
transmitter, it will stop the measurement when slug flow is detected by
the excessive drive power drawn or by
the drop in process density (reduction
in sensor output amplitude).
The amount of air in the process
fluid that can be tolerated by a
meter varies with the viscosity of
the fluid. Liquids with viscosities as
high as 300,000 centipoise can be
metered with Coriolis meters. Gas
content in such highly viscous liquids can be as high as 20% with the
small bubbles still remaining homogeneously dispersed. Gas content
payback periods on applications
where measurement accuracy lowers production costs (bathing, billing) or where multiple measurements
(including density, temperature,
pressure) are needed. On the other
hand, they may not be competitive
when used in simple flow measurement applications where volumetric sensors are sufficient and where
repeatability is more important than
precision. The ability to extract data
on total mass charged, solids rate,
percent solids, and viscosity from
a single instrument does lower the
total cost of measurement, improves
• Applications & Limitations
Coriolis mass flowmeters can detect
the flow of all liquids, including
Newtonian and non-Newtonian, as
well as that of moderately dense
gases. Self-draining designs are available for sanitary applications that
meet clean-in-place requirements.
Most meters are provided with
intrinsically safe circuits between
the flow tube and the transmitter.
64
Volume 4
TRANSACTIONS
process control, and provides redundancy for other instruments.
Continuous tube designs are generally preferred for slurry and other
multi-phase fluid applications. The
total flow is divided by splitters in
split-tube designs, and the resulting
two streams do not have to be at
exactly the same mass flow rate to
maintain accuracy (they do, however, need to have the same density). Different densities in the two
parallel tubes imbalance the system and create measurement errors.
Therefore, if there is a secondary
phase in the stream, a simple flow
splitter may not evenly distribute
the flow between the two tubes.
Continuous tube designs are also
preferred for measuring fluids that
can coat and/or clog the meter.
Continuous tubes, if sized to pass the
curved-tube designs are usually
washed out using cleaning solutions
at velocities in excess of 10 ft/sec.
Straight-tube designs also are preferred for sanitary applications due
to self-draining requirements.
Long, bent tubes twist more easily than do short, straight tubes and
therefore will generate stronger signals under the same conditions. In
general, curved-tube designs provide
wider rangeability (100:1 to 200:1),
while straight-tube meters are limited to 30:1 to 50:1, with lower accuracy. Straight-tube meters are more
immune to pipeline stresses and
vibration, are easy to install, require
less pressure drop, can be mechanically cleaned, are more compact, and
require less room for installation.
They are also preferred on services
largest solid particles in the process
fluid, are less likely to clog and are
easier to clean.
Straight-tube designs can be
cleaned by mechanical means, while
where the process fluid can solidify
at ambient temperatures.
Not all meter housings are
designed to withstand and contain
the pressurized process fluid in case
TRANSACTIONS
of tube rupture, particularly if the
process fluid is likely to vaporize
under such conditions. If that is the
case, secondary containment housings can be ordered that enclose
the entire flow tube, including its
housing. Such secondary containment enclosures can be provided
with rupture disks or pressure relief
valves, and with drains or vents.
• Installation Recommendations
There are no Reynolds number
limitations associated with Coriolis
meters. They are also insensitive to
velocity profile distortion and swirl.
Therefore, there is no requirement
for straight runs of relaxation piping upstream or downstream of the
meter to condition the flow.
The meter should be installed so
that it will remain full of liquid and
so air cannot get trapped inside the
tubes. In sanitary installations, the
meter must also drain completely.
The most desirable installation is in
vertical upward flow pipes (Figure
Volume 4
65
66
5-6B), but installations in horizontal
lines (Figure 5-6A) are also acceptable. Installations where the flow is
downward in a vertical pipe are not
recommended.
In newer Coriolis designs, normal
pipe vibration should not affect the
performance of the Coriolis meter if
it is properly supported by the process piping (Figure 5-6C). No special
supports or pads are needed for the
flow tube, but standard piping supports should be located on either
side of the meter. If the installation
instructions require special hardware
or supports, the particular meter
design is likely to be sensitive to
vibration, and the pulsation dampeners, flexible connectors, and mounting/clamping attachments recommended by the manufacturer should
crosstalk between the two units.
If air bubbles are likely to be present in the process fluid, it is recommended to install an air release
upstream of the meter. System design
characteristics that can result in the
presence of air (and which can often
be eliminated at the design stage)
include:
• Common piping used for pumping
into and out of storage tanks;
• Allowing the formation of a vortex in stirred vessels under lowlevel conditions;
• Allowing air leakage through packing glands of pumps that develop
high vacuums on the suction side
(this can occur when pumping
from underground storage);
• Vaporization of stagnant process
fluid in pipes exposed to the sun;
be carefully installed.
If your application requires that
you install two Coriolis flowmeters in series or mount two Coriolis
meters near each other, the manufacturer should be consulted to prevent
• High valve pressure drops causing
Volume 4
vaporization and flashing;
• Allowing the pipe to drain for any
reason, including lack of check
valves;
• Allowing storage tanks, trucks, or
railroad cars to drain completely;
the same pipe for pumping different materials at different
times; and
• Allowing foam formation by high
turbulence in high velocity fluids.
It is recommended to install
(upstream of the meter) strainers,
filters or air/vapor eliminators as
required to remove all undesirable
secondary phases. Figure 5-7C illustrates an air eliminator installation. Its
function is to slow the velocity of
the liquid, thereby allowing time for
the entrained air to separate and be
removed by venting. The rise and fall
of the liquid level in the eliminator
due to the accumulation of free air
closes and opens the vent valve and
discharges the air (Figure 5-7A&B).
Prior to zeroing the meter, all
• Using
air should be removed. This can be
accomplished by circulating the process fluid through the meter for several minutes at a velocity of approximately 2-6 ft/sec. On batching or
other intermittent flow applications,
TRANSACTIONS
the meter should stay flooded so
that it does not need to be repurged.
All meters should be so installed so
they can be zeroed while filled with
liquid.
When zeroing the meter, any
tion) consist of comparing the output of the meter against a reference
standard of higher accuracy, such as
a dead-weight calibrated weigh tank.
Before Coriolis meters, the reference standard was expected to be
trical heating tape can be added to
the housing. Jackets or heating tapes
must be installed by the manufacturer.
When flowmetering is not required,
the Coriolis meter can be used solely
associated pumps or other equipment should be running so that their
noise can be zeroed out. This can
be achieved in most cases by locating a shut-off value downstream of
the meter and either operating the
pump with its discharge blocked,
which is acceptable with centrifugal pumps for a short period, or by
opening the pump bypass on positive displacement pumps. Valves
used in zeroing the meter should
provide tight shut-off; double-seated valves are preferred.
Meters that are expected to be
calibrated in-line must be provided
with block and bypass valves so
that the reference standard (master)
meter can be installed and disconnected without interrupting the process. The requirements for in-line
calibration (for ISO 9000 verifica-
an order of magnitude more accurate than the meter being calibrated;
however, due to the high accuracy of
Coriolis meters, this is rare.
In less critical installations (where
weigh tanks are not used), volumetric provers or master meters (typically another Coriolis or a turbine meter
calibrated at a flow laboratory) are
used. When a volumetric reference is
used in calibrating a mass flowmeter,
the fluid density must be very precisely determined.
Control valves should be installed
downstream of the meter to increase
the back-pressure on the meter and
lower the probability of cavitation
or flashing.
When the process fluid must be
held at higher temperatures, some
Coriolis meters can be supplied with
steam jackets. As an alternative, elec-
as a densitometer. In that case, to minimize cost, usually a small (H in.) meter
is installed in a by-pass line. Such a
configuration is acceptable only in
clean services that will not clog the
small bore of the meter. In addition, a
restriction must be placed in the main
piping (between the by-pass taps) to
ensure a flow through the meter.
TRANSACTIONS
Thermal Mass Flowmeters
Thermal mass flowmeters also measure the mass flowrate of gases and
liquids directly. Volumetric measurements are affected by all ambient
and process conditions that influence unit volume or indirectly affect
pressure drop, while mass flow measurement is unaffected by changes
in viscosity, density, temperature, or
pressure.
Thermal mass flowmeters are
Volume 4
67
often used in monitoring or controlling mass-related processes such
as chemical reactions that depend
on the relative masses of unreacted
ingredients. In detecting the mass
flow of compressible vapors and
gases, the measurement is unaffected
by changes in pressure and/or temperature. One of the capabilities of
thermal mass flowmeters is to accurately measure low gas flowrates or
low gas velocities (under 25 ft. per
minute)—much lower than can be
detected with any other device.
Thermal flowmeters provide high
rangeability (10:1 to 100:1) if they are
operated in constant-temperaturedifference mode. On the other hand,
if heat input is constant, the ability to
detect very small temperature differences is limited and both precision
and rangeability drop off. At normal
flows, measurement errors are usually
in the 1-2% full scale range.
This meter is available in high pressure and high temperature designs,
and in special materials including
glass, Monel, and Teflon®. Flowthrough designs are used to measure
small flows of pure substances (heat
capacity is constant if a gas is pure),
while bypass and probe-type designs
can detect large flows in ducts, flare
stacks, and dryers.
68
Volume 4
• Theory of Operation
Thermal mass flowmeters are most
often used for the regulation of low
gas flows. They operate either by
introducing a known amount of heat
into the flowing stream and measuring
an associated temperature change, or
by maintaining a probe at a constant
temperature and measuring the energy required to do so. The components
of a basic thermal mass flowmeter
include two temperature sensors and
an electric heater between them. The
heater can protrude into the fluid
stream (Figure 5-8A) or can be external
to the pipe (Figure 5-8B).
In the direct-heat version, a fixed
amount of heat (q) is added by an
electric heater. As the process fluid
flows through the pipe, resistance
temperature detectors (RTDs) measure the temperature rise, while the
(q), and the specific heat of the fluid
(Cp), as follows:
m = Kq/(Cp (T2 - T1))
• Heated-Tube Design
Heated-tube flowmeters were developed to protect the heater and sensor elements from corrosion and any
coating effects of the process. By
mounting the sensors externally to
the piping (Figure 5-8B), the sensing elements respond more slowly
and the relationship between mass
flow and temperature difference
becomes nonlinear. This nonlinearity results from the fact that the
heat introduced is distributed over
some portion of the pipe’s surface
and transferred to the process fluid
at different rates along the length of
All-in-one mass flow controller provides both measurement and control of relatively low mass flow
amount of electric heat introduced
is held constant.
The mass flow (m) is calculated on
the basis of the measured temperature difference (T2 - T1), the meter
coefficient (K), the electric heat rate
the pipe.
The pipe wall temperature is
highest near the heater (detected
as Tw in Figure 5-8B), while, some
distance away, there is no difference
between wall and fluid temperature.
TRANSACTIONS
Therefore, the temperature of the
unheated fluid (Tf) can be detected
by measuring the wall temperature
at this location further away from
the heater. This heat transfer process
is non-linear, and the corresponding
equation differs from the one above
as follows:
power), flowmeter geometry, thermal capacity, specific heat, and viscosity of the process fluid must stay
constant when using this design.
• Bypass-Type Design
This flowmeter has two operating
modes: one measures the mass flow
by keeping the electric power input
constant and detecting the temperature rise. The other mode holds the
The bypass version of the thermal
mass flowmeter was developed to
measure larger flow rates. It consists of a thin-walled capillary tube
(approximately 0.125 in diameter)
and two externally wound self-heating resistance temperature detectors
(RTDs) that both heat the tube and
measure the resulting temperature
rise (Figure 5-9A). The meter is placed
temperature difference constant and
measures the amount of electricity
needed to maintain it. This second
mode of operation provides for a
much higher meter rangeability.
Heated-tube designs are generally
used for the measurement of clean
(e.g., bottled gases) and homogeneous (no mixtures) flows at moderate temperature ranges. They are
not recommended for applications
where either the fluid composition
or its moisture content is variable,
because the specific heat (Cp) would
change. They are not affected by
changes in pressure or temperature.
Advantages include wide rangeability (the ability to measure very low
flows) and ease of maintenance. The
temperature difference (or heater
in a bypass around a restriction in the
main pipe and is sized to operate in
the laminar flow region over its full
operating range.
When there is no flow, the heaters
raise the bypass-tube temperature to
approximately 160°F above ambient
temperature. Under this condition,
a symmetrical temperature distribution exists along the length of
the tube (Figure 5-9B). When flow
is taking place, the gas molecules
carry the heat downstream and the
temperature profile is shifted in the
direction of the flow. A Wheatstone
bridge connected to the sensor terminals converts the electrical signal
into a mass flow rate proportional to
the change in temperature.
The small size of the bypass tube
m0.8 = Kq/(Cp (Tw - Tf))
TRANSACTIONS
makes it possible to minimize electric power consumption and to
increase the speed of response of
the measurement. On the other hand,
because of the small size, filters are
necessary to prevent plugging. One
serious limitation is the high pressure drop (up to 45 psi) needed to
develop laminar flow. This is typically
acceptable only for high pressure
gas applications where the pressure
needs to be reduced in any case.
This is a low accuracy (2% full
scale), low maintenance, and low
cost flowmeter. Electronic packages
within the units allow for data acqui-
sition, chart recording, and computer
interfacing. These devices are popular in the semiconductor processing
industry. Modern day units are also
available as complete control loops,
including a controller and automatic
control valve.
• Air Velocity Probes
Probe-style mass flowmeters are
used to measure air flows and are
insensitive to the presence of moderate amounts of dust. They maintain
a temperature differential between
two RTDs mounted on the sensor
tube. The upper sensor measures
the ambient temperature of the
gas (Figure 5-10A) and continuously
maintains the second RTD (near the
tip of the probe) at 60°F above ambiVolume 4
69
ent. The higher the gas velocity, the
more current is required to maintain
the temperature differential.
Another version of the velocity
probe is the venturi-type thermal
mass flowmeter, which places a
heated mass flow sensor at the minimum diameter of a venturi flow
element and a temperature compensation probe downstream (Figure
5-10B). An inlet screen mixes the flow
to make the temperature uniform.
This design is used for both gas and
liquid measurement (including slurries), with flow range a function of
the size of the venturi. Pressure drop
is relatively low and precision is
dependent upon finding the proper
probe insertion depth.
A flow switch version is also available that contains two temperature
sensors in the tip. One of the sensors
is heated and the temperature difference is a measure of velocity. The
switch can be used to detect high or
low flow within 5%.
• Uses & Limitations
Thermal mass flowmeters can have
very high rangeability and reasonable
accuracy, but they also have serious limitations. Potential problems
include the condensation of moisture
(in saturated gases) on the temperature detector. Such condensation will
cause the thermometer to read low
and can lead to corrosion. Coating or
material build-up on the sensor also
will inhibit heat transfer and cause
the meter to read low. Additional
potential sources of error include
variations in the specific heat caused
by changes in the gas’s composition.
Some common gas-flow applications for thermal mass flowmeters
include combustion air measurement
in large boilers, semiconductor process gas measurement, air sampling
in nuclear power plants, process gas
70
Volume 4
measurements in the chemical and
petrochemical industries, research
and development applications, gas
chromatography, and filter and leak
testing. While hot-wire anemometers are best suited for clean gases
at low velocities, venturi meters can
also be considered for some liquid
rate of cooling corresponds to the
mass flowrate.
The circuitry of the heated sensing element is controlled by one of
two types of solid-state electronic
circuits: constant-temperature or
constant-power. The constant-temperature sensor maintains a constant
Air velocity probe provides 1.5% accuracy for local flow rate measurement.
(including slurry) flow applications.
Thermal mass flowmeters are well
suited for high rangeability measurements of very low flows, but also
can be used in measuring large flows
such as combustion air, natural gas,
or the distribution of compressed
air.
Hot-Wire Anemometers
The term anemometer was derived
from the Greek words anemos,
“wind,” and metron, “measure.”
Mechanical anemometers were first
developed back in the 15th century
to measure wind speed.
A hot-wire anemometer consists
of an electrically heated, fine-wire
element (0.00016 inch in diameter
and 0.05 inch long) supported by
needles at its ends (Figure 5-11).
Tungsten is used as the wire material because of its strength and high
temperature coefficient of resistance. When placed in a moving
stream of gas, the wire cools; the
temperature differential between a
heated sensor and a reference sensor; the amount of power required to
maintain the differential is measured
as an indication of the mass flow rate.
Constant-temperature anemometers are popular because of their
high-frequency response, low electronic noise level, immunity from
sensor burnout when airflow suddenly drops, compatibility with hotfilm sensors, and their applicability
to liquid or gas flows.
Constant-power anemometers
do not have a feedback system.
Temperature is simply proportional
to flowrate. They are less popular
because their zero-flow reading is
not stable, temperature and velocity
response is slow, and temperature
compensation is limited.
• Air Duct Traversing
Anemometers are widely used for air
duct balancing. This is accomplished
by placing multiple anemometers in
TRANSACTIONS
a cross-section of the duct or gas pipe
and manually recording the velocity
readings at numerous points. The mass
flow rate is obtained by calculating
the mean velocity and multiplying this
by the density and by the cross-sectional area measurement of the duct.
For cylindrical ducts, the log-linear
method of traversing provides the
highest accuracy because it takes
into account the effects of friction
along the walls of the duct. Because
of the number of measurements
(Figure 5-12), air duct traversing is a
time-consuming task. Microprocessorbased anemometers are available to
automate this procedure.
Because of the small size and fragility of the wire, hot-wire anemometers are susceptible to dirt build-up
and breakage. A positive consequence
of their small mass is fast speed of
response. They are widely used in
HVAC and ventilation applications.
Larger and more rugged anemometers
are also available for more demanding industrial applications. To ensure
the proper formation of the velocity
profile, a straight duct section is usually provided upstream of the anemometer station (usually 10 diameters
long). A conditioning nozzle is used
to eliminate boundary layer effects. If
there is no room for the straight pipe
section, a honeycomb flow straightener can be incorporated into the
sensor assembly.
T
TRANSACTIONS
References & Further Reading
•OMEGA Complete
Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•“Air Elimination Techniques for Accurate Liquid Measurement,” J. R.
Chester, Mechanical Engineering, February 1983.
•“Application and Installation Guidelines for Volumetric and Mass
Flowmeters,” D. Ginesi and C. Annarummo, ISA Transactions, Instrument
Society of America, 1994.
•Automated Process Control Electronics, John Harrington, Delmar
Publishing Inc., 1989.
•“Coriolis for the Masses,” G. J. Blickley, Control Engineering, June 1995.
•“Coriolis Mass Flowmeter is Ready for the Tough Jobs,” W. Chin, I&CS,
February 1992.
•“Field Proving Coriolis Mass Flowmeter,” R. Harold and C. Strawn, ISA/91
Proceedings, Instrument Society of America, 1991.
•Flow Measurement, D.W. Spitzer (editor), Instrument Society of America,
1991.
•“Flow Sensing: The Next Generation,” D. Ginesi, Control Engineering,
November 1997.
•Instrument Engineers’ Handbook, Bela Liptak, CRC Press, 1995.
•Instrumentation for Process Measurement and Control, 3rd edition,
Norman A. Anderson, Chilton Co., 1980.
•Instruments of Science, Robert Bud and Deborah Jean Warner, Garland
Publishing Inc., 1998.
•“Metering Mass Flow,” H. van der Bent, Process Engineering, May 1993.
•“On-line Viscosity Measurement with Coriolis Mass Flowmeters,” P.
Kalotry and D. Schaffer, ISA/91 Proceedings, Instrument Society of
America, 1991.
•Process/Industrial Instruments and Controls Handbook, 4th edition,
Douglas M. Considine, McGraw-Hill, 1993.
•“Technical Application Guide to Mass Flow Measurement,” Wayne
Shannon, Magnetrol International, 1998.
•The McGraw-Hill Encyclopedia of Science and Technology, 8th edition,
John H. Zifcak, McGraw-Hill, 1997.
Volume 4
71
O
A Level Measurement Orientation
n the 28th of March, 1979,
thousands of people fled
from Three Mile Island
(near Harrisburg, PA) when
the cooling system of a nuclear reactor failed. This dangerous situation
into the tank or should it be completely external?
• Should the sensor detect the level
continuously or will a point sensor
be adequate?
• Can the sensor come in contact
developed because the level controls turned off the coolant flow
to the reactor when they detected
the presence of cooling water near
the top of the tank. Unfortunately,
the water reached the top of the
reactor vessel not because there
was too much water in the tank, but
because there was so little that it
boiled and swelled to the top. From
this example, we can see that level
measurement is more complex than
simply the determination of the
presence or absence of a fluid at a
particular elevation.
with the process fluid or must it
be located in the vapor space?
• Is direct measurement of the level
needed or is indirect detection of
hydrostatic head (which responds
to changes in both level and density) acceptable?
• Is tank depressurization or process shut-down acceptable when
sensor removal or maintenance is
required?
By evaluating the above choices,
one will substantially shorten the list
of sensors to consider. The selection
is further narrowed by considering
only those designs that can be provided in the required materials of
construction and can function at the
required accuracy, operating temperature, etc. (Table 4). When the
level to be measured is a solid, slurry,
foam, or the interface between two
Level Sensor Selection
When determining what type of
level sensor should be used for a
given application, there are a series
of questions that must be answered:
• Can the level sensor be inserted
72
Volume 4
liquid layers, it is advisable to consult
not only Table 4, but other recommendations, such as Table 5.
If it is found that a number of
level detector designs can satisfy the
requirements of the application, one
should also consider the traditions
or preferences of the particular plant
or the particular process industry,
because of user familiarity and the
availability of spare parts. For example, the oil industry generally prefers displacement-type level sensors,
while the chemical industry favors
differential pressure (d/p) cells. (The
petroleum industry will use d/p cells
when the span exceeds 60-80 in.)
If the tank is agitated, there is
often no space in which to insert
probe-type sensors. Plus, because
the liquid surface is not flat, sonic,
ultrasonic, or radar devices typically
cannot be used, either. Even with
displacer or d/p sensors, agitation
can cause the level signal to cycle.
These pulses can be filtered out by
first determining the maximum rate
PT
at which the level can change (due
to filling or discharging) and disregarding any change that occurs faster
TRANSACTIONS
than that.
The relationship between level
and tank volume is a function of the
cross-sectional shape of the tank.
With vertical tanks, this relationship
is linear, while with horizontal or
spherical vessels, it is a non-linear
relationship (Figure 6-1).
If the level in a tank is to be
inferred using hydrostatic pressure
measurement, it is necessary to use
multi-transmitter systems when it is
TRANSACTIONS
desirable to:
• Detect the true level, while either
the process temperature or density varies;
• Measure both level and density;
and
• Measure the volume and the mass
(weight) in the tank.
By measuring one temperature and
three pressures, the system shown in
Figure 6-2 is capable of simultaneously measuring volume (level), mass
(weight), and density, all with an
accuracy of 0.3% of full span.
Boiling & Cryogenic Fluids
When a d/p cell is used to measure
the level in a steam drum, a reverseacting transmitter is usually installed
(Figure 6-3). An uninsulated condensing chamber is used to connect the
high pressure (HP) side of the d/p
cell to the vapor space on the top
of the drum. The steam condenses
Volume 4
73
the level measurement. To protect
against this, the liquid filled portion
of the connecting line should be
sloped back towards the tank. The
cross-section of the line should be
large (about 1 inch in diameter) to
minimize the turbulence caused by
the simultaneous boiling and re-
Sonic Echo
Gages
Electromechanical
in this chamber and fills the wet
leg with ambient temperature water,
while the low pressure (LP) side of
the d/p cell detects the hydrostatic
head of the boiling water inside the
drum. The output of the d/p cell
reflects the amount of water in the
drum. Output rises as the mass of
water in the drum drops (because
the steaming rate and the associated
swelling increase). It is for this reason
that a reverse
acting d/p cell is
recommended for this application.
When the process fluid is liquid
nitrogen (or some other cryogenic
material), the tank is usually surrounded by a thermally insulated
and evacuated cold box. Here, the
low pressure (LP) side of a direct
acting d/p cell is connected to the
vapor space above the cryogenic
liquid (Figure 6-4). As the liquid
nitrogen approaches the HP side
of the d/p cell (which is at ambient temperature outside the cold
box), its temperature rises. When
the temperature reaches the boiling
point of nitrogen, it will boil and,
from that point on, the connecting line will be filled with nitrogen vapor. This can cause noise in
74
Volume 4
TRANSACTIONS
condensing occurring at the liquidvapor interface.
Sludge, Foam, & Molten Metals
Many process fluids are aggressive
or difficult to handle and it’s best to
avoid physical contact with them.
This can be accomplished by plac-
ing the level sensor outside the tank
(weighing, radiation) or locating the
sensor in the vapor space (ultrasonic,
radar, microwave) above the process
fluid. When these options are not
available or acceptable, one must aim
to minimize maintenance and physical contact with the process fluid.
When the process fluid is a sludge,
slurry, or a highly viscous polymer,
and the goal is to detect the level at
one point, the design shown in Figure
6-5A is commonly considered. The
ultrasonic or optical signal source
and receiver typically are separated
by more than six inches so that the
process fluid drains freely from the
intervening space. After a high-level
episode, an automatic washing spray
is activated.
TRANSACTIONS
When the sludge or slurry level is
detected continuously, one of the
goals is to eliminate dead-ended cavities where the sludge might settle.
In addition, all surfaces which are
exposed to the process fluid should
be covered with Teflon®. Figure 6-5B
shows such an installation, employing
Teflon®-coated extended diaphragms
to minimize material buildup.
In strippers, where the goal is to
drive off the solvent in the shortest
period of time, one aims to keep
the foam level below a maximum.
In other processes, it is desirable to
separately control both the liquid
level beneath the foam and the thickness of the foam. In the paper industry, beta radiation detectors are used
for such applications (Kraft processing), while other industries detect
the degree of foaming indirectly (by
measuring related variables, such as
heat input or vapor flow), or they
use capacitance, conductivity, tuning
fork, optical, or thermal switches, all
provided with automatic washers.
Measuring the level of molten
glass or metals is another special
application. The most expensive
(but also most accurate) technique
available is proximity capacitancebased level measurement, which
can provide a resolution of 0.1 mm
over a range of 6 in. Laser-based
systems can provide even better
resolution from distances up to
2 ft. If such high resolution is not
required and cost is a concern, one
can make a float out of refractory
material and attach a linear variable
differential transformer (LVDT), or
make a bubbler tube out of refractory material and bubble argon or
nitrogen through it.
T
References & Further Reading
•OMEGA
Complete Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•Instrument Engineer’s Handbook, Bela G. Liptak, editor, CRC Press, 1995.
•Instrumentation for Process Measurement and Control, Third Edition, N.
A. Anderson, Chilton, 1980.
•Measurement and Control of Liquid Level, C. H. Cho, Instrument Society
of America, 1982.
•Principles of Industrial Measurement for Control Applications, E. Smith,
Instrument Society of America, 1984.
Volume 4
75
O
Pressure/Density Level Instrumentation
ne of the primary principles underlying industrial
level measurement is that
different materials and different phases of the same material
have different densities. This basic
law of nature can be utilized to measure level via differential pressure
(that at the bottom of the tank relative to that in the vapor space or to
atmospheric pressure) or via a float
or displacer that depends on the
density differences between phases.
Level measurement based on pressure measurement is also referred to
as hydrostatic tank gaging (HTG). It
works on the principle that the difference between the two pressures
d/p cell can provide an indication
of level (accurate to better than 1%)
over wide ranges, as long as the density of the liquid is constant. When
a d/p cell is used, it will cancel out
the effects of barometric pressure
variations because both the liquid in
the tank and the low pressure side
of the d/p cell are exposed to the
pressure of the atmosphere (Figure
7-1B). Therefore, the d/p cell reading
will represent the tank level.
When measuring the level in pressurized tanks, the same d/p cell designs
(motion balance, force balance, or
electronic) are used as on open tanks.
tures, are very low (Figure 7-1C). A dry
leg enables the d/p cell to compensate for the pressure pushing down
on the liquid’s surface, in the same
way as the effect of barometric pressure is canceled out in open tanks.
It is important to keep this reference leg dry because accumulation
of condensate or other liquids would
cause error in the level measurement.
When the process vapors condense
at normal ambient temperatures or
are corrosive, this reference leg can
be filled to form a wet leg. If the
process condensate is corrosive,
unstable, or undesirable to use to fill
the wet leg, this reference leg can be
filled with an inert liquid.
(d/p) is equal to the height of the
liquid (h, in inches) multiplied by the
specific gravity (SG) of the fluid (see
Figure 7-1):
It is assumed that the weight of the
vapor column above the liquid is
negligible. On the other hand, the
pressure in the vapor space cannot
be neglected, but must be relayed to
the low pressure side of the d/p cell.
Such a connection to the vapor space
is called a dry leg, used when process
vapors are non-corrosive, non-plugging, and when their condensation
rates, at normal operating tempera-
In this case, two factors must be
considered. First, the specific gravity of the inert fluid (SGwl) and the
height (hwl) of the reference column
must be accurately determined, and
the d/p cell must be depressed by
the equivalent of the hydrostatic
head of that column [(SGwl)(hwl)].
Second, it is desirable to provide a
sight flow indicator at the top of the
wet leg so that the height of that ref-
d/p = h (SG)
By definition, specific gravity is the
liquid’s density divided by the density of pure water at 68° F at atmospheric pressure. A pressure gage or
76
Volume 4
Dry & Wet Leg Designs
TRANSACTIONS
erence leg can be visually checked.
Any changes in leg fill level (due to
leakage or vaporization) introduce
error into the level measurement. If
the specific gravity of the filling fluid
for the wet leg is greater than that of
the process fluid, the high pressure
side should be connected to the reference leg and the low to the tank.
If the condensate can be used to
fill the reference leg, a condensate
pot can be mounted and piped both
to the high level connection of the
tank and to the top of the vapor
space. The condensate pot must be
mounted slightly higher than the
high level connection (tap) so that it
will maintain a constant condensate
level. Excess liquid will drain back
into the tank. It is also desirable
either to install a level gage on the
condensate pot or to use a sight
flow indicator in place of the pot, so
that the level in the pot can conveniently be inspected.
Either method (wet or dry)
assures a constant reference leg
for the d/p cell, guaranteeing that
the only variable will be the level
TRANSACTIONS
in the tank. The required piping and
valving must always be provided
on both the tank and the reference
leg side of the d/p cell, so that
draining and flushing operations can
easily be performed. When a wet
reference leg is used, a low thermal
expansion filling fluid should be
selected. Otherwise, the designer
must correct for the density variations in the reference leg caused by
ambient temperature variations.
If smart transmitters are used and
if the filling fluid data is known, wetleg temperature compensation can
be provided locally. Alternatively,
the host or supervisory control system can perform the compensation
calculations.
If it is desired to keep the process
vapors in the tank, a pressure repeater
can be used. These devices repeat the
vapor pressure (or vacuum) and send
out an air signal identical to that of
the vapor space. The measurement
side of the repeater is connected to
the vapor space and its output signal
to the low pressure side of the d/p
cell. If the tank connection is sub-
ject to material build-up or plugging,
extended diaphragm Type 1:1 repeaters can be considered for the service
(Figure 7-2).
While repeaters eliminate the
errors caused by wet legs, they do
introduce their own errors as a function of the pressure repeated. For
example, at 40 psig, repeater error
is about 2 in. At 400 psig, it is 20 in.
In many applications, the former is
acceptable but the latter is not.
• d/p Cells
Because the designs of the various
d/p cells are discussed in detail in
another issue of Transactions, only a
brief overview is provided here.
The motion balance cell is well
suited for remote locations where
instrument air or electric power are
not available. If a bellows is used as
the sensing element in a motion balance d/p cell, an increase in the pressure on either side causes the corresponding bellows to contract (Figure
7-3A). The bellows is connected to
a linkage assembly that converts the
linear motion of the bellows into a
Volume 4
77
78
rotary indicator motion, which can be
calibrated to indicate the tank level.
In a force-balance type of d/p
wide as 0-1,000 psid. Some electronic d/p cells can operate at line
pressures up to 4,500 psig at 250°F.
performance of the cell. Flat and
extended diaphragm-type d/p cells,
pressure repeaters, and chemical
cell, the sensing element (often a
diaphragm) does not move. A force
bar is provided to maintain the forces acting on the diaphragm in equilibrium (Figure 7-3B). In pneumatic
d/p cells, this is often achieved
by the use of a nozzle and flapper arrangement that guarantees
that the pneumatic output signal
will always be proportional to the
differential pressure across the cell.
The output of pneumatic d/p cells
is linear and is usually ranged from 3
to 15 psig. The levels represented by
such transmitted signals (pneumatic,
electronic, fiberoptic or digital) can
be displayed on local indicators or
remote instruments. Pneumatic transmitters require a compressed air (or
nitrogen) supply.
Electronic d/p cells provide
±0.5% of span or better precision
typically conveyed via a 4-20 mA
signal. The range of these simple
and robust cells can be as narrow
as a draft range of 0-H inH2O or as
The drift and inaccuracy of some
of these units have been tested for
periods of up to 30 months, and the
errors did not exceed the ±0.5% of
span limit.
seals are available to protect d/p
cells under these conditions.
Chemical seals, or diaphragm
pressure seals, are available with
fill liquids such as water, glycol,
alcohol, and various oils. These seals
are used when plugging or corrosion can occur on both sides of
the cell. A broad range of corrosion-resistant diaphragm and lining materials is available. Teflon®
lining is often used to minimize
material build-up and coating. Level
measurement accuracy does suffer
when these seals are used. Capillary
tube lengths should be as short as
possible and the tubes should be
shielded from the sun. In addition,
either low thermal expansion filling
fluids should be used or ambient
temperature compensation should
be provided, as discussed in connection with wet legs. If the seals
leak, maintenance of these systems
is usually done
at the supplier’s
factory due to
the complex
Volume 4
• Difficult Process Fluids
When the process fluid is a sludge,
a viscous polymer or is otherwise
hard to handle, the goal is to isolate
the dirty process from the d/p cell.
A flat diaphragm can be bolted to
a block valve on the tank nozzle so
that the d/p cell can be removed
for cleaning or replacement without
taking the tank out of service. If it
is acceptable to take the tank out
of service when d/p cell removal
is needed, an extended diaphragm
design can be considered. In this
case, the diaphragm extension fills
the tank nozzle so that the diaphragm is flush with the inside surface of the tank. This eliminates
dead ends or pockets where solids can accumulate and affect the
TRANSACTIONS
Bubbler tubes provide a simple and
inexpensive but less accurate (±1-2%)
level measurement system for corrosive or slurry-type applications.
Bubblers use compressed air or an
inert gas (usually nitrogen) introduced through a dip pipe (Figure 7-4A).
Gas flow is regulated at a constant
rate (usually at about 500 cc/min). A
differential pressure regulator across
a rotameter maintains constant flow,
while the tank level determines the
back-pressure. As the level drops,
end of the dip pipe should be located
far enough above the tank bottom so
that sediment or sludge will not plug
it. Also, its tip should be notched
with a slot or “V” to ensure the formation of a uniform and continuous
flow of small bubbles. An alternative
to locating the dip pipe in the tank
is to place it in an external chamber
connected to the tank.
In pressurized tanks, two sets
of dip pipes are needed to measure the level (Figure 7-4B). The
two back-pressures on the two dip
pipes can be connected to the two
sides of a u-tube manometer, a
differential pressure gage or a d/p
at a pressure at least 10 psi greater
than the expected maximum total
pressure required (when the tank
is full and the vapor pressure is at
its maximum). An alternative to
a continuous bubbler is to use a
hand pump (similar to a bicycle
tire pump) providing purge air only
when the level is being read.
Bubblers do consume inert gases,
which can later accumulate and
blanket processing equipment. They
also require maintenance to ensure
that the purge supply is always available and that the system is properly
adjusted and calibrated. When all
factors are considered, d/p cells
the back-pressure is proportionally
reduced and is read on a pressure
gage calibrated in percent level or
on a manometer or transmitter. The
dip pipe should have a relatively large
diameter (about 2 in.) so that the pressure drop is negligible. The bottom
cell/transmitter. The pneumatic piping or tubing in a bubbler system
should be sloped toward the tank
so that condensed process vapors
will drain back into the tank if purge
pressure is lost. The purge gas supply
should be clean, dry, and available
typically are preferred to bubblers in
the majority of applications.
evacuation and backfilling procedures involved.
Bubbler Tubes
TRANSACTIONS
• Elevation & Suppression
If the d/p cell is not located at an
elevation that corresponds to 0%
level in the tank, it must be calibrated
Volume 4
79
the high pressure side of the d/p cell
should be connected to the tank if
the specific gravity of the wet leg
filling fluid is close to that of the light
layer. It should be connected to the
h2
LT
depression when the cell is located
below the lower tap. Most d/p cells
are available with elevation and suppression ranges of 600% and 500%
of calibrated span, respectively, as
long as the calibrated span does not
exceed 100% of the upper range limit
of the cell.
For example, assume that an electronic d/p cell can be calibrated for
spans between 0-10 psid (which is its
lower range limit, LRL) and 0-100 psid
(which is its upper range limit, URL).
The cell is to be used on a 45-ft tall
closed water tank, which requires a
hydrostatic range of 0-20 psid. The
cell is located about 11 feet (5 psid)
above the lower tap of the tank;
therefore, a zero elevation of 5 psid is
needed. The d/p cell can handle this
application, because the calibrated
span is 20% of the URL and the elevation is 25% of the calibrated span.
On interface level measurement
applications with a wet leg reference,
80
Volume 4
saturated liquid layer (0.76) vary
not only with drum pressure but
also with steaming rate. This causes
the swelling of bubbles when the
steaming rate rises (and SG2 drops),
as well as their collapse when the
steaming rate drops (and SG2 rises).
Therefore, to make an accurate
determination of both the level and
the mass of the water in the steam
drum, the calculation must consider
not only the d/p cell output, but
also the drum pressure and the prevailing steaming rate.
• Tank Farms
h1
to account for the difference in elevation. This calibration adjustment is
called zero elevation when the cell
is located above the lower tap, and
is called zero suppression or zero
reference leg if the wet-leg fluid’s SG
is closer to that of the heavy layer.
• Special Applications
When the process fluid is boiling,
such as in a steam drum, a wet reference leg is maintained by a condensate pot, which drains back into the
steam drum so that the level of the
wet leg is kept constant. Changes in
ambient temperature (or sun exposure) will change the water density
in the reference leg and, therefore,
temperature compensation (manual
or automatic) is needed.
Figure 7-5 describes a typical
power plant steam drum level application. The differential pressure
detected by the level d/p cell is:
d/p = h1SG1 + h2SG2 - h3SG3
d/p = 0.03h1 + 0.76h2 - 0.99h3
Note that the SG of the saturated
steam layer (0.03) and that of the
Computerized tank farm systems usually accept level signals from several
tanks through field networks. These
systems perform the level monitoring
tasks using a variety of compensation
and conversion algorithms. The algorithms provide density corrections,
volumetric or mass conversions, and
corrections to consider the shapes of
horizontal, vertical or spherical tanks.
These systems can perform safety
functions, such as shutting off feed
pumps to prevent overfilling.
Floats & Displacers
It was more than 2,200 years ago
that Archimedes first discovered
that the apparent weight of a floating object is reduced by the weight
of the liquid displaced. Some 2,000
years later, in the late 1700s, the first
industrial application of the level float
appeared, when James Brindley and
Sutton Thomas Wood in England and
I. I. Polzunov in Russia introduced
the first float-type level regulators in
boilers.
Floats are motion balance devices
that move up and down with liquid
level. Displacers are force balance
devices (restrained floats), whose
apparent weight varies in accordance with Archimedes’ principle:
TRANSACTIONS
the buoyant force acting on an object
equals the weight of the fluid displaced. As the level changes around
to 80°C (-40 to 180° F) and up to 150
psig for rubber or plastic floats, and
-40 to 260°C (-40 to 500°F) and up
than the minimum expected specific
gravity (SG) of the process fluid. For
clean liquids a 0.1 SG difference might
B)
the stationary (and constant diameter)
displacer float, the buoyant force varies in proportion and can be detected
as an indication of level. Regular and
displacer floats are available as both
continuous level transmitters and
point-sensing level switches.
In industrial applications, displacer
floats are often favored because they
do not require motion. Furthermore,
force can often be detected more
accurately than position. However,
regular floats are also used, mostly
for utilities and in other secondary
applications.
to 750 psig for stainless steel floats.
Standard float sizes are available from
1 to 5 inches in diameter. Custom
float sizes, shapes, and materials can
be ordered from most manufacturers.
The float of a side-mounted switch is
horizontal; a permanent magnet actuates the reed switch in it (Figure 7-6B).
Floats should always be lighter
suffice, while for viscous or dirty
applications, a difference of at least
0.3 SG is recommended. This provides
additional force to overcome the
resistance due to friction and material
build-up. In dirty applications, floats
should also be accessible for cleaning.
Floats can be attached to mechanical arms or levers and can actuate
• Float Level Switches
The buoyant force available to operate a float level switch (that is, its net
buoyancy) is the difference between
the weight of the displaced fluid (gross
buoyancy) and the weight of the float.
Floats are available in spherical (Figure
7-6A), cylindrical (Figure 7-6B), and a
variety of other shapes (Figure 7-6C).
They can be made out of stainless
steel, Teflon®, Hastelloy, Monel, and
various plastic materials. Typical temperature and pressure ratings are -40
TRANSACTIONS
Volume 4
81
electrical, pneumatic, or mechanical
mechanisms. The switch itself can
be mercury (Figures 7-6A and 7-6C),
dry contact (snap-action or reed type,
the cable determines the actuation
level. One, two, or three switches
can be used to operate simplex and
duplex sump-pump stations. A sim-
shown in Figure 7-6B), hermetically
sealed, or pneumatic. The switch can
be used to actuate a visual display,
annunciator, pump, or valve. The electric contacts can be rated light-duty
(10-100 volt amps, VA) or heavy-duty
(up to 15 A @ 120 Vac). If the switch
is to operate a circuit with a greater
load than the rating of the switch contacts, an interposing relay needs to be
inserted. If the switch is to be inserted
in a 4-20 mA dc circuit, gold-plated
dry contacts should be specified to
ensure the required very low contact
resistance.
plex (one pump) system will use a
single switch wired in series with
the motor leads so that the switch
directly starts and stops the pump
motor (Figure 7-7).
A duplex (two pump) application
might use three switches: one at
the tank bottom (LO) to stop both
pumps, another in the middle (HI) to
start one pump, and the last at the
top (HI-HI) to actuate the second
pump, as well as perhaps an audible
and/or visual alarm.
Figure 7-8A illustrates how a sidemounted float switch might actuate
an adjacent, sealed reed switch. The
main advantage of this design is that
the lever extension tends to amplify
the buoyant force generated by the
float. Therefore the float itself can
be rather small. The main disadvantage is that the tank must be opened
in order to perform maintenance
on the switch. If the buoyant force
of the float is used mechanically to
actuate a snap-action switch, a force
of only one ounce is needed.
In top (or bottom) mounted magnetic float switches (Figure 7-8B), the
magnet is in the cylindrical float that
travels up or down on a short vertical
guide tube containing a reed switch.
The float’s motion is restrained by
clips and can be only H in or less.
These float and guide tubes are available with multiple floats that can
detect several levels. The switch
assembly itself can be either inserted
directly into the tank or side-mounted in a separate chamber.
• Applications & Installations
In the tilt switch (Figure 7-6C), a
mercury element or relay is mounted
inside a plastic float; the float’s electrical cable is strapped to a pipe
inside the tank or sump. As the level
rises and falls, the float tilts up and
down, thus opening and closing its
electric contact. The free length of
82
Volume 4
TRANSACTIONS
A magnetic piston operated
switch also can be mounted in an
external chamber (Figure 7-8C). As
the magnet slides up and down
inside a non-magnetic tube, it operates the mercury switch outside the
tube. These switches are complete-
ly sealed and well suited for heavy
duty industrial applications up to
900 psig and 400°C (750°F), meeting ASME code requirements. These
switches can be side, top, or cage
mounted (Figure 7-9) and can serve
both alarm and control functions
on steam drums, feedwater heaters,
condensate pots, gas/oil separators, receivers, and accumulators.
Light-duty caged float switches are
also available for service ratings up
to 250 psig at 200°C (400°F) and 400
psig at 40°C (100°F)—suitable for
many boilers, condensate receivers,
flash tanks, day tanks, holding tanks,
and dump valve controls. The cages
TRANSACTIONS
can be provided with level gages.
Multiple switches are available for
multiple-switching applications such
as boiler level alarms and controls.
• Displacer Switches
Whereas a float usually follows the
liquid level, a displacer remains par-
tially or completely submerged. As
shown in Figure 7-10A, the apparent
weight of the displacer is reduced
as it becomes covered by more liquid. When the weight drops below
the spring tension, the switch is
actuated. Displacer switches are
more reliable than regular floats
on turbulent, surging, frothy, or
foamy applications. Changing their
settings is easy because displacers can be moved anywhere along
the suspension cable (up to 50 ft).
These switches are interchangeable
between tanks because differences
in process density can be accommodated
by changing the tension of
the support spring.
Testing the proper functioning of
a regular float switch may require
filling the tank to the actuation level,
while a displacer switch can be tested simply by lifting a suspension
(Figure 7-10A). Displacer switches are
available with heavy-duty cages and
flanges for applications up to 5000
psig at 150°C (300°F), suitable for use
on hydraulic accumulators, natural
gas receivers, high pressure scrubbers, and hydrocarbon flash tanks.
• Continuous Level Displacers
Displacers are popular as level
transmitters and as local level controllers, particularly in the oil and
petrochemical industries. However,
they are not suited for slurry or
sludge service because coating of
the displacer changes its volume and
therefore its buoyant force. They are
most accurate and reliable for servicVolume 4
83
es involving clean liquids of constant
density. They should be temperaturecompensated, particularly if variations in process temperature cause
significant changes in the density of
the process fluid.
torque tubes, the buoyant force can
also be detected by other force sensors, including springs and force-balance instruments. When the buoyant
force is balanced by a spring, there is
some movement, while with a force-
cesses that are operated continuously, the American Petroleum Institute
recommends (in API RP 550) that
displacers be installed in external
standpipes with level gages and isolating valves (Figure 7-11). This way it
is possible to recalibrate or maintain
the displacer without interrupting
the process.
• Interface Applications
When used as a level transmitter,
the displacer, which is always heavier
than the process fluid, is suspended
from the torque arm. Its apparent
weight causes an angular displacement of the torque tube (a torsion
spring, a frictionless pressure seal).
This angular displacement is linearly proportional to the displacer’s
weight (Figure 7-10B).
Standard displacer volume is 100
cubic inches and the most commonly
used lengths are 14, 32, 48, and 60
in. (Lengths up to 60 ft are available
in special designs.) In addition to
84
Volume 4
balance detector, the displacer stays
in one position and only the level
over the displacer varies.
Displacer units are available with
both pneumatic and electronic outputs and can also be configured
as local, self-contained controllers.
When used in water service, a 100
cubic inch displacer will generate a buoyant force of 3.6 pounds.
Therefore, standard torque tubes are
calibrated for a force range of 0-3.6
lbf and thin-walled torque tubes for
a 0-1.8 lbf range.
For oil refineries and other pro-
When measuring the interface
between a heavy liquid and a light
liquid (such as oil on water), the
top connection of the displacer
is placed into the light and the
bottom connection into the heavy
liquid layer. If the output of such a
transmitter is set to zero when the
chamber is full of the light liquid,
and to 100% when it is full with
the heavy phase, the output will
correspond to the interface level.
Naturally, when interface is being
measured, it is essential that the
two connections of the displacer
chamber be located in the two different liquid layers and that the chamber
always be flooded. Displacer diameter can be changed to match the
difference in liquid densities, and
displacer length can be set to match
the vertical range of the level interface variation.
Regular floats can also be used
for interface detection if the difference in SG between the two
process liquids is more than 0.05.
In such applications, a float density is needed that is greater than
the lighter liquid and less than the
heavier liquid. When so selected,
the float will follow the interface
level and, in clean services, provide
acceptable performance.
• Continuous Level Floats
Of the various float sensor designs
used for continuous level measureTRANSACTIONS
ment, the oldest and arguably most
accurate is the tape level gage (Figure
7-12A). In this design, a tape or cable
connects the float inside the tank to
a gage board or an indicating takeup reel mounted on the outside of
the tank. The float is guided up and
down the tank by guide wires or travels inside a stilling well. These level
indicators are used in remote, unattended, stand-alone applications, or
they can be provided with data transmission electronics for integration
into plant-wide control systems.
To install the tape gage, an opening is needed at the top of the
tank and an anchor is required at its
bottom. When properly maintained,
tape gages are accurate to ±G in. It
is important to maintain the guide
wires under tension, clean and free
of corrosion, and to make sure that
the tape never touches the protective piping in which it travels. If this
is not done, the float can get stuck
on the guide wires or the tape can
steel) pipe. The pipe is connected to
flanged nozzles on the side of the
tank. The pipe column is provided
with a visual indicator, consisting
of G-in triangular wafer elements.
These elements flip over (from
green to red, or any other color)
when the magnet in the float reaches their level (Figure 7-12B). Alarm
switches and transmitter options
are available with similar magnetic
coupling schemes (Figure 7-12C). In
a similar design, a series of reed
switches is located inside a standpipe. The change in output voltage
as the individual reed switches are
closed by the rising magnet is measured, giving an indication of level.
The operation of magnetostrictive sensors is based on the Villari
effect. In the magnetic waveguidetype continuous level detector, the
float (or floats, when detecting interface) travels concentrically up and
down outside a vertical pipe. Inside
the pipe is a concentric waveguide
pulse. The difference in the interrogation time and the return pulse time is
proportional to the
liquid level in
the tank.
This tank level sensing method
is highly accurate, to ±0.02 in, and
therefore is ideal for precision inventory management operations. The
sensor is available in lengths of 2-25
ft and can be inserted into the tank
from the top of the vessel through
flanged, screwed, or welded connections. For the simultaneous measurement of both interface and total
level, a two-float system is available
(Figure 7-12D). A resistance temperature detector (RTD) is also available
for temperature compensation. Like
all other float level instruments, this
design too is for clean liquids. Rating
is up to 150°C (300° F) and 300 psig.
The transmitter output can be 4-20
mA dc analog or fieldbus-compatible
digital.
get stuck to the pipe. (This can happen if the level does not change for
long periods or if the tank farm is
located in a humid region.)
Another continuous level indicator
is the magnetic level gage, consisting of a magnetic float that travels
up and down on the inside of a
long, non-magnetic (usually stainless
made of a magnetostrictive material.
A low current interrogation pulse is
sent down the waveguide, creating
an electromagnetic field along the
length of the waveguide. When this
field interacts with the permanent
magnet inside the float, a torsional
strain pulse (or waveguide twist) is
created and detected as a return
Float-operated control valves combine level measurement and level
control functions into a single level
regulator. While simple and inexpensive, they are limited to applications involving small flows and small
pressure drops across the valve. This
is because the force available to
throttle the valve is limited to that
TRANSACTIONS
• Float Control Valves
Volume 4
85
provided by the buoyant force acting on the float, multiplied by the
lever action of the float arm. This
does not suffice to close large valves
against high pressure differentials.
Yet, for simple and unattended
applications (like controlling the
make-up water supply into a cooling
tower basin or draining condensate
from a trap), they are acceptable. It
is important to understand that float
regulators are simple proportional
controllers: they are incapable of
holding level at a single setpoint.
What they can do is open or close a
valve as the float travels through its
control range. Therefore, instead of a
setpoint, regulators have a throttling
range. If the range is narrow (floats
usually fully stroke their valve over
a few inches of float travel), it gives
the impression of a constant level.
In fact, level will vary over the
throttling range because the only
86
Volume 4
way for the regulator to increase the
feed flow (say into a cooling tower
basin) is to first let the level drop
so that the sinking of the float will
further open the valve. The relationship between the maximum flow
through a linear valve (Qmax) and
the range in liquid level (h) is called
the proportional sensitivity of the
regulator (Kc = Qmax/h), expressed
in units of GPM/inch. The offset of
a float regulator is the distance (in
inches) between the center of the
float range and the amount of elevation of the float required to deliver
the flowrate demanded by the process.
T
References & Further Reading
•OMEGA
Complete Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•Instrument Engineer’s Handbook, Bela G. Liptak, editor, CRC Press, 1995.
•Instrumentation for Process Measurement and Control, Third Edition, N.
A. Anderson, Chilton, 1980.
•Measurement and Control of Liquid Level, C. H. Cho, Instrument Society
of America, 1982.
•Principles of Industrial Measurement for Control Applications, E. Smith,
Instrument Society of America, 1984.
TRANSACTIONS
RF/Capacitance Level Instrumentation
C
apacitance level detectors
are also referred to as radio
frequency (RF) or admittance
level sensors. They operate
in the low MHz radio frequency
range, measuring admittance of an
alternating current (ac) circuit that
varies with level. Admittance is a
is capable of storing an electric
charge. The storage capability of a
capacitor is measured in farads. As
shown in Figure 8-1, the capacitor
plates have an area (A) and are separated by a gap (D) filled with a nonconducting material (dielectric) of
dielectric constant (K). The dielectric
measure of the conductivity in an
ac circuit, and is the reciprocal of
impedance. Admittance and impedance in an ac circuit are similar to
conductance and resistance in a
direct current (dc)
circuit. In this
chapter, the term capacitance level
sensor will be used instead of RF or
admittance.
Table 6 lists some of the industries
and applications where capacitancetype level sensors are used.
constant of a vacuum is 1.0; the
dielectric constants of a variety of
materials are listed in Table 7.
The dielectric constant of a substance is proportional to its admit-
Theory of Operation
A capacitor consists of two conductors (plates) that are electrically isolated from one another by
a nonconductor (dielectric). When
the two conductors are at different potentials (voltages), the system
TRANSACTIONS
- -- -----
- -- --+ ++
++
++
++
++
++
+
tance. The lower the dielectric constant, the lower the admittance of the
material (that is, the less conductive it
is). Capacitance (C) is calculated as:
C = KA/D
If the area (A) of and the distance
(D) between the plates of a capacitor remain constant, capacitance
will vary only as a function of the
dielectric constant of the substance
filling the gap between the plates.
If a change in level causes a change
in the total dielectric of the capacitance system, because (as illustrated
in Figure 8-1B) the lower part of area
(A) is exposed to a liquid (dielectric Kl)
while the upper part is in contact with
a vapor (dielectric Kv, which is close
to 1.0), the capacitance measurement
will be proportional to level.
In the case of a horizontally
mounted level switch (Figure 8-2),
a conductive probe forms one of
the plates of the capacitor (A1), and
the vessel wall (assuming it is made
from a conductive material) forms
the other (A2). An insulator with a
low dielectric constant is used to
+ ++
++
++
++
++
++
+
Volume 4
87
isolate the conductive probe from
the housing, which is connected to
the vessel wall. The probe is con-
the sensor probe and the vessel
wall. Both of these values are fixed.
Therefore, when the probe is no lon-
one coulomb of electric energy. A
pico-farad is one trillionth of that,
and the sensitivity of an accurate
capacitance detector is 0.5 pF. This
is the minimum detectable change in
capacitance resulting from a change
in dielectric constant (K2 -K1).
In most level-sensing applications,
the reference material is air (K1 = 1.0).
Table 7 gives the K2 values of a variety
of process materials. As the dielectric
constant of the process material gets
close to that of air (K2 for plastic pellets, for example, is 1.1), the measurement becomes more difficult.
Probe Designs
nected to the level sensor via the
conductive threads of the housing.
Measurement is made by applying
an RF signal between the conductive
probe and the vessel wall.
The RF signal results in a minute
current flow through the dielectric
process material in the tank from the
probe to the vessel wall. When the
level in the tank drops and the probe
is exposed to the even less conductive vapors, the dielectric constant
drops. This causes a drop in the
capacitance reading and a minute
drop in current flow. This change
is detected by the level switch’s
internal circuitry and translated into
a change in the relay state of the
level switch. In the case of continuous level detectors (vertical probes),
the output is not a relay state, but a
scaled analog signal.
The total area is the combined
area of the level sensor probe and
the area of the conductive vessel
wall (A = A1 + A2), and the distance
(D) is the shortest distance between
88
Volume 4
The sensitivity of a capacitance
sensor is expressed in pico-farads (pF).
The most common probe design is
a stainless steel rod of G in. or H
in. diameter, suitable for most nonconductive and non-corrosive materials. The probe is insulated from
the housing and bin wall by an lowdielectric insulator, such as Nylon or
Ryton. These polymers have maximum operating temperatures of 175230°C (350-450°F). Ceramics can be
used for higher temperature applications or if abrasion resistance is
required. For applications where the
process material is conductive and
corrosive, the probe must be coated
The capacitance unit is the farad,
defined as the potential created
when a one-volt battery connected
to a capacitor causes the storage of
with Teflon® or Kynar.
Some point level sensors are
available with build-up immunity, or
coating rejection functionality. This
ger surrounded by vapors (K1), but by
the process material (K2), the resulting
capacitance change is directly related
to the difference in dielectric constant between the two media:
Change in C = (K2 - K1)(A/D)
TRANSACTIONS
is required when the process material is wet or sticky and likely to
cause permanent coating. Build-up
immunity is provided by the addition
of a second active section of probe
and a second insulator (Figure 8-3).
This second active section (the driven
7 to 16 in. These probes typically are
side-mounted (Figure 8-4A). Vertical
probes can be extended by solid rods
up to a length of 1.2 to 1.5 m (4 to 5 ft),
or a steel cable with a weight can be
used to suspend the probe up to 15 m
(50 ft) (Figure 8-4B). Most capacitance
Capacitance probes typically are coated with Teflon® (shown), Kynar, or polyethylene
shield) is driven at the same potential and frequency as the measuring
probe. Because current cannot flow
between equal potentials, the measuring probe does not sense material
build-up between the probe and vessel wall.
Typical insertion lengths of standard capacitance probes range from
TRANSACTIONS
level sensors are provided with I to
1-H in NPT mounting connectors. The
matching female coupling is usually
welded to the vessel wall and the
capacitance probe is screwed into
the mating connector. Low profile
capacitance sensors also are available
(Figure 8-4C) and are flange-mounted.
In applications where the vessel
is non-conductive and unable to
form the return path for the RF signal, a second probe placed parallel
to the active one or a conductive
strip can be installed.
• Electronics & Housings
The electronic circuitry of the probe
performs the functions of: 1) rectifying
and filtering the incoming power, 2)
generating the radio frequency signal,
3) measuring the changes in current
flow, and 4) driving and controlling
interface devices such as relays,
analog signal generators and display
meters. The circuitry is usually of
solid state design and provided with
potentiometer adjustments for setting sensitivity and time delays.
Because the level sensor will ultimately drive an external device, it
is advisable to evaluate for system
compatibility the number of relays
required, their capacities, or the
analog signals required, time delays,
and power supply requirements.
More advanced microprocessor-
Volume 4
89
based units are self-calibrating;
sensitivity and time delay adjustments are under pushbutton control. These units are often supplied
with self-test capability and built-in
excluding temperature and supply
voltage effects) is typically 0.25% of
range. Minimum span is 4 pF, and the
upper range limit (URL) is 2,500 pF.
Level switches are usually provided
SOLIDS
temperature compensation.
The more advanced designs are
also two-wire, intrinsically safe, and
supply your choice of standard 4-20
mA or digitally enhanced output using the HART (Highway
Addressable Remote Transducer)
protocol. Accuracy (including linearity, hysteresis, and repeatability, but
90
Volume 4
with time delays for filtering out
false readings caused by material
shifts or splashing liquids. In addition,
the feature of failsafe selectability
provides a predetermined state for
the relay output in the event of a
power failure or malfunction.
Sensor housings are typically
made from cast aluminum, steel, or
synthetic materials such as glassreinforced nylon. Most housings are
suitable for outdoor installations in
dusty or wet environments.
• The Dielectric Constant
The dielectric constant of the process material is the most important
aspect of the process data. The higher
the difference between the dielectric
constants (of the process material
and the vapor space or between the
two layers in the case of an interface
measurement), the easier the measurement. If the difference is low (K2K1 < 1.0 in Figure 8-2), a high sensitivity
design (0.5 pF) must be used.
Each sensor has a capacitance
threshold, defined as the amount
of capacitance change required to
cause a change in the sensor output.
The dielectric constant of a material can change due to variations
in temperature, moisture, humidity,
material bulk density, and particle
size. If the change in dielectric constant results in a greater capacitance
change than the calibrated capacitance threshold of the sensor, a false
reading will result. This condition
can usually be corrected by reducing
the sensitivity (increasing the capacitance threshold) of the sensor.
As shown in connection with
Figure 8-3, sensitivity can be
increased by increasing the probe
length (A) or by decreasing the size
of the gap (D). Either or both changes
will minimize the effect of dielectric constant fluctuations or increase
sensitivity to low dielectrics. It is
usually more practical to specify a
longer probe than to decrease the
distance (D) from the vessel wall.
When the probe is installed from the
side (Figure 8-4A), D is fixed, whereas
if the probe is inserted from the top
of the tank, D can be changed (if other
considerations permit) by moving the
probe closer to the wall of the vessel.
TRANSACTIONS
A
B
If the same vessel will hold different materials at different times,
the capacitance sensor must be
equipped with local or remote recalibration capability.
Light density materials under 20
lb/ft3 and materials with particle
sizes exceeding H in. in diameter can
be a problem due to their very low
dielectric constants (caused by the
large amount of air space between
particles). These applications might
not be suited for capacitance-type
level measurement.
• Application Considerations
D
E
TRANSACTIONS
Materials that are conductive (waterbased liquids with a conductivity of
100 micromhos/cm or more) can
cause a short circuit between a bare
stainless steel probe and the vessel wall. As the liquid level drops,
the probe remains wetted, providing a conductive path between the
probe and the vessel wall. The faster
the level changes, the more likely
this false indication is to occur. It is
advisable to use Teflon® or Kynar
insulator coating on the conductive
probe surface when the process fluid
is conductive.
Temperature affects both the
sensor components inside the vessel (active probes and insulators)
and the electronic components and
housing outside. An active probe is
typically made from stainless steel
and, as such (unless it is coated), it is
suitable for most applications. Probe
insulators can be Teflon®, Kynar, or
ceramic, and should be selected for
the operating temperature of the
application. The housing and the
electronics are affected by both the
internal and external vessel temperatures.
Ambient temperature limits usually
are specified by the manufacturer,
but heat conduction from a highVolume 4
91
temperature process is more difficult to evaluate. Heat conduction
can be reduced by using an extended
mounting coupling or one made of a
low thermal conductivity material.
If such methods are insufficient, the
electronics may be mounted up to
20 ft away and connected via coaxial
cable. The cable’s inherent capacitance, however, reduces the overall
sensitivity of the system.
Housings must also be compatible with the requirements for
hazardous, wash-down, wet, and/
or dusty environments. Explosionproof environments may require the
housing to be certified. In addition,
the active probe might need to be
intrinsically safe.
If the process material is corrosive
to stainless steel, the probe should
be coated with Kynar or Teflon® for
protection. Ryton is a good choice
for abrasive materials, and, for food
grade or sanitary applications, stainless steel and Teflon® are a good
probe-insulator combination.
Installation Considerations
The capacitance probe should be
mounted in such a way that its
92
Volume 4
operation is unaffected by incoming or outgoing material flow
(Figure 8-5A). Material impacts can
cause false readings or damage
to the probe and insulator. When
measuring low-dielectric materials,
it's important that the entire probe
be covered, not just the tip (Figure
8-5C). When rod or cable extensions are used, allow for 8-12 in. of
active probe coverage.
Install the probe so that it does
not contact the vessel wall (Figure
8-5B) or any structural elements of
the vessel. If a cable extension is
used, allow for swinging of the cable
as the material level in the vessel
rises, so that the plumb bob on the
end of the cable does not touch the
vessel wall. The probe should not be
mounted where material can form
a bridge between the active probe
and the vessel wall. In addition, the
probe should not be mounted at an
upward angle (Figure 8-5D), to avoid
material build-up.
If more than one capacitance level
sensor is mounted in the vessel, a
minimum distance of 18 in. should be
provided between the probes (Figure
8-5E). Closer than that and their electromagnetic fields might interfere.
If a capacitance probe is installed
through the side wall of a vessel
and the weight of the process material acting on the probe is sometimes
References & Further Reading
•OMEGA
Complete Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•Instrument Engineer’s Handbook, Bela Liptak, Third Edition, CRC Press,
1995.
•Instrumentation for Process Measurement and Control, Third Edition, N.
A. Anderson, Chilton, 1980.
•Measurement and Control of Liquid Level, C. H. Cho, Instrument Society
of America, 1982.
•Principles of Industrial Measurement for Control Applications, E. Smith,
TRANSACTIONS
Radiation-Based Level Gages
A
n entire class of level instrumentation devices is based
on a material’s tendency to
reflect or absorb radiation.
For continuous level gages, the most
common types of radiation used are
radar/microwave, ultrasonic, and
nuclear. Optical electromagnetic
radiation also can be used, but this
has found its way primarily into the
point-switch applications discussed
in the next chapter.
The main advantage of a radiation-based level gage is the absence
of moving parts and the ability to
detect level without making physical contact with the process fluid.
Because they can in effect “see”
through solid tank walls, nuclear
radiation gages are perhaps the
ultimate in non-contact sensing.
Because they require a gamma
radiation source and are relatively
expensive, however, nuclear gages
are often considered the level gage
of last resort.
Radar & Microwave
In 1925, A. Hoyt Taylor and Leo Young
of the U.S. Navy used radar (RAdio
Detection And Ranging) to measure
the height of the earth’s ionosphere.
By 1934, they were developing
radar for Navy ships. In 1935, Robert
Watson-Watt of England used radar
to detect aircraft. The first radar level
sensors were introduced in 1976, but
they did not become economically
competitive until a decade later.
Both radar signals and microwaves
travel at the speed of light, but
are distinguished by their frequencies (FM radio broadcast frequency
is from 88 to 108 MHz, while microwaves range from 1-300 GHz) and by
TRANSACTIONS
their power levels (radar is around 0.01
mW/cm2, while microwaves range
from 0.1-5 mW/cm2). Because microwaves operate at a higher energy
level, they can withstand more coating than can radar-type sensors.
Radar sensors consist of a transmitter, an antenna, a receiver with
signal processor, and an operator
of the radar pulse and the reception
of the return echo. It is determined
by the radar detector, which is simultaneously exposed to both the sent
and the reflected signal. The detector output is based on the difference.
The frequency-modulated (FM) signal
varies from 0 to 200 Hz as the distance to the process fluid surface
interface. The transmitter is mounted on top of the vessel. Its solidstate oscillator sends out an electromagnetic wave (using a selected
carrier frequency and waveform)
aimed downward at the surface of
the process fluid in the tank. The
frequency used is typically 10 GHz.
The signal is radiated by a parabolic dish or horn-type antenna
(Figure 9-1A) toward the surface of
the process liquid (Figure 1B). A portion is reflected back to the antenna,
where it is collected and routed to
the receiver. Here, a microprocessor calculates the time of flight and
calculates the level. Time of flight is
the period between the transmission
varies between 0 and 200 ft. Because
this measurement takes place in the
frequency domain, it is reasonably
free of noise interference.
The depth of the vapor space (the
distance between the datum point
and the level in the tank, identified
as “d” in Figure 9-1B) is calculated
from the time of flight (t) and the
speed of light (c = 186,000 miles/
sec):
d = t/2c
The level (L in Figure 9-1B) is calculated
by figuring the difference between
the total tank height (E) and the
vapor space depth (d):
Volume 4
93
L = E-d
Knowing the signal velocity (c) and the
dielectric constant (dc) of the vapor
(that is, the relative ability of the vapor
to oppose and reflect electromagnetic
waves), the velocity of the radar wave
transmission (V) can be calculated:
V = c/(dc)0.5
pulsed radar waves or frequencymodulated continuous waves
(FMCW). In the first, short-duration
radar pulses are transmitted and the
target distance is calculated using
the transit time. The FMCW sensor sends out continuous frequencymodulated signals, usually in successive (linear) ramps. The frequency
difference caused by the time delay
between transmittal and reception
The unreflected portion travels on to
the end of the probe and provides a
zero-level reference signal. Contact
radar technology can be used on liquids and on small-grained bulk solids
with up to 20-mm grain size.
Reflection-type microwave switches measure the change in amplitude
of a reflected signal (Figure 9-3A). Air
and vapors return a small percentage of the signal because of their
indicates the distance.
Radar beams can penetrate plastic and fiberglass; therefore, noncontact radar gages can be isolated
from the process vapors by a seal.
The seal can be above the parabolic
disc (Figure 9-1A) or can totally isolate the sensor (Figure 9-2A). The
beam’s low power allows for safe
installation in both metallic and
non-metallic vessels. Radar sensors
can be used when the process materials are flammable or dirty and
when the composition or temperature of the vapor space varies.
Contact radar gages send a pulse
down a wire to the vapor-liquid interface. There, a sudden change in the
dielectric constant causes the signal
to be partially reflected. The time-offlight is then measured (Figure 9-2B).
low dielectric constants, while high
dielectric materials such as water
return almost all the signal. More sensitive switches can distinguish liquidliquid or liquid-solid interfaces having
as little as 0.1 difference in dielectric
constant. Low dielectric materials like
plastic pellets (dielectric 1.1) can be
measured if the particle diameter is
less than 0.1 in (larger than that, excessive beam scattering occurs).
The beam-breaker switch sends a
microwave beam from a transmitter
to a receiver located on the opposite side of the tank. When the beam
is blocked, the signal is weakened
(Figure 9-3B). Beam-breaker alignment is not critical, and separation
distance can be up to 100 ft.
Both reflection and beam-breaker
microwave switches are typically
• Antenna Designs and Mounting
The two commonly used antennas
are the horn and the parabolic dish
antenna. When the radar level gage
sends out its signal, the microwaves
spread out. The larger the antenna
diameter, the smaller the divergence
angle and the greater the signal
strength (Figure 9-1A). The disadvantages of smaller antennas include
higher beam spreading and the correspondingly increased possibility of
reflection from obstacles within the
tank. On the positive side, there is a
greater chance that the emitted beam
will be reflected back to the detector.
Therefore, alignment of the sensor is
not as critical.
Large antennas generate a more
focused signal, helping to eliminate
noise interference from flat and horizontal metal surfaces. On the other
hand, they are more prone to errors
caused by unwanted reflections
from turbulent or sloping surfaces.
A fully isolated antenna mounted
outside the tank (Figures 9-2 and 9-4)
provides both sealing and thermal
isolation. If the antenna is positioned
below the process seal, it is exposed
to the process vapors, but gains
the advantages of stronger signal
amplitudes and suitability for higher
operating pressures.
• Contact & Non-Contact Radar
Non-contact radar gages either use
94
Volume 4
TRANSACTIONS
used in applications where it is desirable not to penetrate the tank. These
non-intrusive sensors send electromagnetic radio waves through plastic,
ceramic or glass windows, or through
fiberglass or plastic tank walls.
sensors are affected by the composition of the vapor space. On
the other hand, ultrasonic sensors
perform better in dirty applications,
or with solids when the grain size is
larger than 20 mm.
• Advantages & Limitations
Ultrasonic Level Gages
The reflective properties of the process material affect the returned
radar signal strength. Whereas liquids
have good reflectivity characteristics,
solids do not. Radar can detect the
liquid level under a layer of light dust
or airy foam, but if the dust particle
size increases, or if the foam or dust
gets thick, it will no longer detect the
liquid level. Instead, the level of the
foam or dust will be measured.
Internal piping, deposits on the
antenna, multiple reflections, or
reflections from the wall can all
interfere with the proper operation
of a radar sensor. Other sources
of interference are rat-holing and
bridging of solids, as well as angled
process material surfaces that can
reflect the radar beam away from the
The origin of ultrasonic level instrumentation goes back to the echometers used in measuring the depth of
wells by firing a blank shell and timing the return of the echo. SONAR
detectors used in naval navigation
also predate industrial applications
of this principle.
The frequency range of audible
sound is 9-10 kHz, slightly below the
20-45 kHz range used by industrial
level gages. The velocity of an ultrasonic pulse varies with both the substance through which it travels and
with the temperature of that substance. This means that if the speed
of sound is to be used in measuring a
level (distance or position), the substance through which it travels must
be well known and its temperature
receiver.
In comparison to other radiation
reflection sensors, radar has some
advantages. For example, ultrasonic
variations must be measured and
compensated for.
At room temperature, the speed of
sound in atmospheric air is 340 m/s or
TRANSACTIONS
762 mph. At that same temperature,
an ultrasonic pulse travels through
water at 1,496 m/s or 3,353 mph. If
the air is heated to 100°C, the speed
of sound rises to 386 m/s. Indeed,
the speed of sound is proportional
to the square root of temperature.
At near ambient temperatures, the
speed rises by 0.6 m/s per each 1°C
increase, corresponding to an increase
of 0.18%/°C.
Ultrasonic level switches (point
sensors) operate by detecting either
dampening of ultrasonic oscillation or
by sensing the absorption or transmission of an ultrasonic pulse. Ultrasonic
level transmitters measure actual distance by issuing an ultrasonic pulse
and measuring the time required for
the reflected echo to be received.
• Ultrasonic Transducers
The transducer that generates the
ultrasonic pulse is usually piezoelectric, although in the past electrostatic
units also were used. An electrostatic transducer is constructed of
a thin, flexible gold-plated plastic
foil, stretched over an aluminum
back-plate and held in place by a
leaf spring. This design was used in
early Polaroid auto-focus cameras
Volume 4
95
and is still utilized in clean environments. Piezoelectric transducers
Most often, however, a single transducer is cycled on and off at regular
liquid.
If it is desired to measure the
utilize ceramic or polymer crystals
vibrated at their natural frequency.
These units are much more rugged,
can withstand wash-down pressures
of 1,200 psig and can conform to
NEMA-6P (IEC IP67) standards.
Generally, the larger the diameter
of the transducer, the longer the
range and the lower the frequency. This is because, after releasing
an ultrasonic pulse, the transducer
needs time for the vibration to settle.
The oscillation frequency is inversely
proportional to the element’s diameter, so smaller diameter transducer
elements generate higher frequencies. Standard transducers have a
beam angle of about 8°, require a
connection size between G in and 2.5
in NPT, and are suited for operating
temperatures in the range of -20 to
60°C (-30 to 140°F). Accuracy is typically within 0.25-0.5% of full range,
up to about 30 ft. Output typically is
4-20 mA with a 12-amp relay output.
intervals to listen for the reflected
echo (Figure 9-4A). When mounted
on the top of the tank, the sensor
detects the depth of the vapor space.
Accurate knowledge of the shape of
height of the liquid column directly,
the transducer can be mounted in
the bottom of the tank (Figure 9-4A).
However, this configuration exposes
the transducer to the process fluid
and limits accessibility for maintenance. Alternately, the transducer
can be mounted on the outside
of the wall of the vessel bottom,
but the ultrasonic pulse is likely to
be substantially weakened by the
absorbing and dispersing effects of
the tank wall (Figure 9-4A).
Stagnant, unagitated liquids and
solids consisting of large and hard
particles are good reflectors, and
therefore good candidates for
ultrasonic level measurement. Fluff,
foam, and loose dirt are poor reflectors, and dust, mist, or humidity
in the vapor space tend to absorb
the ultrasonic pulse. The ultrasonic
signal also is attenuated by distance.
If a 44-kHz sound wave is traveling
in dry, clean ambient air, its sound
power drops by 1-3 decibels (dB)
for each meter of distance traveled.
Therefore it is important, particularly when measuring greater depths,
that the transducers generate a
• Level Transmitter Configurations
The ultrasonic level sensor assembly
can consist of separate transmitter
and receiver elements (Figure 9-4A).
96
Volume 4
the tank’s cross-section is required in
order to determine the volume of
TRANSACTIONS
strong and well-focused ultrasonic
pulse (Figure 9-4B).
It is also desirable that the surface be both flat and perpendicular
to the sound wave. In liquid-level
applications, the aiming angle must
be within 2 degrees of the vertical.
If the surface is agitated or sloping
(as in the case of solids), the echo
is likely to be dispersed. Therefore,
the key to successful ultrasonic level
sensor installations is the careful
analysis of the reflection, propagation, and absorption characteristics
of the tank’s contents.
When detecting the interface
between two liquids, such as the
hydrocarbon/brine interface in a
salt dome storage well, the transducer is lowered down to the bottom of the well. The ultrasonic
pulse is sent up through the heavy
brine layer to the interface. The
time it takes for the echo to return
TRANSACTIONS
is an indication of the location of
the interface (Figure 9-4C).
reduce the unit costs of obtaining
level measurements.
• Special Features
• Level Switches
Most modern ultrasonic instruments include temperature compensation, filters for data processing
and response time, and some even
provide self-calibration. Figure 9-5
illustrates a fixed target assembly
that provides a point reference to
When it is sufficient to detect the presence or absence of level at a particular
elevation, dampened or absorptiontype level switches can be considered.
In the dampened design, a piezoelectric crystal vibrates the sensor face
at its resonant frequency. The vibration
automatically recalibrate the level
sensor. Multiple calibration targets
can be provided by calibration ridges
in sounding pipes. This can guarantee measurement accuracy of within
5 mm over a distance of 30 meters.
Intelligent units can perform automatic self-calibration or convert the
level in spherical, irregular, or horizontal cylindrical tanks into actual
volume. They can also be used in
multi-tank or multi-silo installations,
which, through multiplexing, can
is dampened when the probe face is
submerged in process fluid. As shown
in Figure 9-3A, these switches can be
mounted outside or inside the tank,
above or below the liquid level. The
probe can be horizontal or vertical.
These switches are limited to clean
liquid installations because coating can
dampen the vibration. Solids may not
provide sufficient dampening effects
to actuate the switch.
In the absorption-type level
switch, one piezoelectric crystal
Volume 4
97
serves as a transmitter and another as
the receiver. When the gap between
them is filled with liquid, the sonic
wave passes from one crystal to
the other. When vapors fill the gap,
however, the ultrasonic pulse does
not reach the receiver. The crystals
current outputs are also used.
The presence or absence of an
interface between clean liquids can
be measured by inserting an absorption (gap) probe at a 10° angle below
the horizontal. In this configuration,
as long as the probe is immersed in
a seemingly solid, impenetrable mass
of matter. In the passage, however,
the gamma rays lost some of their
intensity. The rays were predictably
affected by the specific gravity and
total thickness of the object, and by
the distance between the gamma ray
source and the detector.
For example, Figure 9-6 shows
that, if radiation from Cesium 137 is
passing through an 3-in thick steel
object, 92% of the radiation energy
will be absorbed and only 8% will be
transmitted. Therefore, if the observer can hold all variables except thickness constant, the amount of gamma
transmission can be used to measure the thickness of the object.
Assuming that the distance between
the source and detector does not
change, one can make accurate measurements of either thickness (level),
or, if thickness is fixed, then of the
density of a process material.
• Radiation Sources
can be mounted on opposite sides of
the tank, contained in the fingers of
a fork-shaped sensor, or located on
the two sides of one or more 0.5-in
gaps in a horizontal or vertical probe.
When the process fluid is a sludge
or slurry, it is desirable to provide a
large gap between the transmitter
and receiver in order to make sure
that sticky or coating fluids will drain
completely from the gap when the
level drops.
Typical accuracy of these switches
is H-in or better. Connection size
is I-in NPT. Operating temperature
range is 40-90°C (100 to 195°F) (with
special units capable of readings up
to 400°C/750°F) and operating pressure to 1000 psig. Standard output is
a 5 or 10 amp double-pole/doublethrow (DPDT) relay, but voltage and
98
Volume 4
the heavy or light liquid, the ultrasonic pulse will reach the receiver.
When the interface moves into the
gap, however, it is reflected away and
does not reach the receiver.
When a sludge or slurry interface
is to be detected or when the thickness of the light layer is of interest, an
ultrasonic gap sensor can be attached
to a float. As long as the absorption
characteristics of the two layers differ, the sensor will signal if the layer is
thicker or thinner than desired.
Nuclear Level Sensors
In 1898 Marie Curie discovered radium by observing that certain elements naturally emit energy. She
named these emissions gamma rays.
Gamma rays exhibited mysterious
properties—they could pass through
The development of nuclear level
sensors began when this technology
moved from the lab to the industrial
environment. This necessitated the
design and manufacture of suitable
detectors and the mass production
of radioisotopes. Both occurred in
the 1950s.
The penetrating power of nuclear
radiation is identified by its photon
energy, expressed in electron volts
(eV) and related to wavelength (Figure
9-7). The most common isotope used
for level measurement is Cesium 137,
which has a photon energy level of
0.56 MeV. Another isotope that is
occasionally used is Cobalt 60, which
has an energy level of 1.33 MeV. While
the greater penetrating power of
this higher energy radiation appears
attractive at first, the penalty is that
it also has a shorter half-life. As any
isotope decays, it loses strength—
TRANSACTIONS
the time it takes to lose half of its
strength is called its half-life.
The half-life of Cobalt 60 is 5.3
years. This means that, in 5.3 years,
the activity of a 100 millicurie (mCi)
Cobalt 60 source will be reduced to
50 mCi. (One mCi is defined as the
rate of activity of one milligram of
Radium 226.) When used for level
measurement, the continuous loss
of source strength requires not only
continuous compensation, but, eventually (in the case of Cobalt 60, in
about 5 years), the source must be
replaced. This means not only the
expense of purchasing a new source,
but also the cost of disposing of the
old one.
In contrast, the 33-year half-life of
Cesium 137 is long enough that the
source may well outlive the process.
Another likelihood is that technological advances will increase the sensitivity of the detector faster than the
rate at which the source is decaying.
This provides users the option of
replacing or upgrading the detector
while keeping the source in place for
the future.
the vapor space above the liquid, as
the level rises in the tank, the intensity
at the detector drops. When the tank
is full, radiation intensity is practically
zero.
When used as a tank level sensor,
radiation must pass through several
layers of material before reaching the
detector. At the detector, the maximum
radiation must be less than some safety
limit (such as 5 mr/hr) to avoid the need
for “posting.” Other criteria can be used,
such as keeping a yearly dosage under
5 rems (roentgen + equivalent + man).
If somebody is exposed to radiation
throughout the year, such a dosage will
result from exposure to radiation at
an intensity of 0.57 mr/hr, while if an
operator is exposed for only 40 hrs/wk,
detector output when the level changes.
This can be illustrated by an example:
5 rem/yr will correspond to what that
person would receive if exposed to 2.4
mr/hr in the work area. As it is the total
lifetime dosage of radiation exposure
that really matters (maximum of 250
rems), the acceptability of the 5 rem/yr,
or any other limit, is also a function of
age (Figure 9-8). On the other hand, the
radiation at the detector must still be
sufficient to produce a usable change in
to actuate the intended ion chamber
detector.
First the in air intensity (Da in mr/
hr) is calculated at the detector, for
the condition when there is no tank
between the source and receiver.
Assume distance (d) is 48 in:
• Source Sizing
A point source of 10 mCi Cesium 137
(source constant for Cesium 137 is
K=0.6) is installed on a high-pressure
water tank having H-in steel walls
(Figure 9-9). Usually, two criteria need
to be satisfied: First, the radiation
intensity at the detector must drop
by at least 50% as the level rises from
0-100%. The second and more important criterion is that the maximum
radiation dose at the detector (when
the tank is empty) must not exceed
the safety limit (say, 2.4 mr/hr). It must
exceed 1.0 mr/hr, however, in order
• Radiation Safety
The Nuclear Regulatory Commission
(NRC) limits radiation intensity to a
maximum of 5 milliroentgens per hour
(mr/hr) at a distance of 12 in from the
nuclear gage. If it is more, the area
requires Radiation Area posting. The
distance of 12 in is critical, because
radiation intensity decreases by the
inverse square of distance. Nuclear
level gages are sized to provide radiation intensity at the detector that
exceeds the minimum required, but is
under the 5 mr/hr maximum. For ion
chamber detectors, the minimum is 1
mr/hr. For Geiger-Mueller switches,
it is 0.5 mr/hr. And for scintillation
detectors, it is 0.1-0.2 mr/hr. Because
the nuclear gage is basically measuring
TRANSACTIONS
Da = 1000 K(mCi)/d2 =
1000(0.6)(10)/482 = 2.6 mr/hr
Volume 4
99
Because the source is shielded in all
directions except towards the tank,
the operator who is working near
the detector will receive the maximum dosage when the tank is empty.
The two H-in steel walls will reduce
Da (% transmission of 1-in steel in
Figure 1 is 49%) to 0.49 x 2.6 = 1.27
mr/hr. This is below the allowable
maximum but above the minimum
needed by the detector.
When the tank is full, the presence of 30 in of water in the radiation path will reduce this maximum
intensity to 0.045 mr/hr (0.035 x 1.9
= 0.045). This reduction in intensity
well exceeds the required 50% drop
needed for sensitive measurement.
Note that the source size could
have been cut in half if a GeigerMueller detector were used. A
scintillation detector would reduce
source size 5- to 10-fold.
The source size can also be
reduced by locating the source in
the tip of a probe inside the tank
and moving it relatively close to the
wall. When large level ranges are to
be measured, a strip source can be
used instead of a point source. The
accuracy of most nuclear level gages
is around 1% of range. If accounting
accuracy is desired, the source and
the detector can both be attached to
motor driven tapes and positioned at
the level (or at the interface level, if
the tank contains two liquids).
Fortunately, today’s computers can easily crunch the numbers
and formulas of any combination of
geometry and design criteria. The
biggest challenge is not the calculation, but the obtaining of accurate
inputs for the calculations. Therefore,
it is very important that your vessel’s
wall materials, thicknesses, other tank
components such as baffles, agitator
blades or jackets, and all distances be
1 00
Volume 4
accurately determined. In short, the
performance of a nuclear gage installation is very much a function of the
accurate knowledge of the installation
details.
The simplest and oldest type of radiation detector is the Geiger-Muller
tube. This instrument is most often
identified with the Geiger counters
that make a loud and dramatic clicking
sound when exposed to radiation. The
working component of this detector
is a metal cylinder that acts as one
are used as insulators, and a high voltage (700-1000 vdc) nearly sufficient to
cause current flow between the electrodes is applied. When the tube is
exposed to gamma radiation, the gas
ionizes and the ionized particles carry
the current from one electrode to
the other. The more gamma radiation
reaches the gas in the tube, the more
pulses are generated. The resulting
pulse rate is counted by the associated electronic circuitry, which makes
measurements in pulses per second.
This detector can be used as a
level switch if it is calibrated to
of the electrodes and is filled with an
inert gas. A thin wire down the center
acts as the other electrode. Glass caps
engage or disengage a relay when
radiation intensity indicates a high or
low level condition. The G-M tube
• Detector Options
TRANSACTIONS
detector can only be used as a single
point detection device. Its advantages include its relatively low cost,
small size, and high reliability.
The ion chamber detector is a
continuous level device. It is a 4 to
6-in diameter tube up to twenty feet
long filled with inert gas pressurized
to several atmospheres. A small bias
voltage is applied to a large electrode inserted down the center of
the ion chamber. As gamma energy
strikes the chamber, a very small
signal (measured in picoamperes) is
detected as the inert gas is ionized.
This current, which is proportional
to the amount of gamma radiation
received by the detector, is amplified and transmitted as the level
measurement signal.
In level measurement applications,
the ion chamber will receive the most
radiation and, therefore, its output
will be highest when the level is lowest. As the level rises and the greater
quantity of measurand absorbs more
gamma radiation, the output current
of the detector decreases proportionally. The system is calibrated to read
0% level when the detector current
output is its highest. 100% level is
set to match the lowest value of
the output current. Non-linearities
in between can usually be corrected
with the use of linearizing software.
This software can correct for the
effects of steam coils, agitator blades,
baffles, stiffening rings, jackets and
other components inside or outside
the tank.
Scintillation counter detectors are
five to ten times more sensitive than
ion chambers. They also cost more,
yet many users are willing to accept
the added expense because it allows
them either to use a smaller source
size or to obtain a more sensitive
gage. When gamma energy hits a
scintillator material (a phosphor), it
TRANSACTIONS
is converted into visible flashes comprised of light photons (particles of
light).
These photons increase in number
as the intensity of gamma radiation increases. The photons travel
through the clear plastic scintillator
medium to a photo multiplier tube,
which converts the light photons
into electrons. The output is directly
proportional to the gamma energy
that is striking the scintillator.
Scintillators are available in a multitude of shapes, sizes, and lengths.
One of the latest is a fiber optic cable
that allows one to increase detector
sensitivity by installing more filaments in the bundle. Another advantage of the fiber optic cable is that
it is manufactured in long lengths
flexible enough to form-fit to the
geometry of the vessel. This simplifies the measurement of levels in
spherical, conical, or other oddly
shaped vessels.
• Nuclear Applications
Radiation gages typically are considered when nothing else will work, or
when process penetrations required
by a traditional level sensor present
a risk to human life, to the environ-
ment, or could do major damage to
property. The liquids and bulk solids
measured by nuclear gages are among
the most dangerous, highly pressurized, toxic, corrosive, explosive,
and carcinogenic materials around.
Because the nuclear gage “sees”
through tank walls, it can be installed
and modified while the process is
running—without expensive down
time or chance accidental release.
Because the installation of nuclear
sensors requires a Nuclear Regulatory
Commission (NRC) license, associated procedures are designed to
guarantee that the installation will
be safe. The best way to look at the
safety aspects of radioactive gaging is to compare the well defined
and understood risk represented by
exposing the operators to radiation
against the possibly larger risk of
having an unreliable or inaccurate
level reading on a dangerous process.
As detectors become more sensitive and are aided by computers, radiation source sizes and the
resulting radiation levels continue to
drop. Therefore, the safety of these
instruments is likely to continue to
improve with time.
T
References & Further Reading
•OMEGA
Complete Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•Automated Process Control Electronics, John Harrington, Delmar
Publishing Inc., 1989.
•Fundamentals of Radar Techniques for Level Gauging, Detlef Brumbi,
Krohne Metechnik GmbH & Co. KG, 1995.
•Industrial Applications of Radar Technology for Continuous Level
Measurement, W. L. Hendrick, Instrument Society of America, 1992.
•Instrument Engineer’s Handbook, Bela Liptak, Third Edition, CRC Press, 1995.
•Process/Industrial Instruments and Controls Handbook, 4th Edition,
Douglas M. Considine, McGraw-Hill, 1993.
•Theoretical Nuclear Physics Volume I: Nuclear Structure, New York, A.
deShalit, H. Feshback,: John Wiley & Sons, 1974.
Volume 4
101
T
hermal, vibrating, and optical level switches are specialty devices developed to
solve specific level detection
problems. Typically, they are used in
applications that either cannot be
handled by the more common float
and probe-type devices, or when
ultrasonic, nuclear, radar or microwave
designs would be too sophisticated,
expensive, or otherwise unsuited for
the task.
All three types can be used to
detect liquid levels or interfaces
between liquids. The optical level
switch is also suited for detecting
high foam levels, if it is spray washed
after each event. In some specialized applications, all three of these
switches have been tuned to identify
specific materials or to determine
when a material reaches a particular
viscosity, density, opacity, or thermal
conductivity condition.
All three level switch designs are
simple, straightforward, and reliable.
Although some can detect other
process properties besides level,
their main purpose is to measure the
presence or absence of material at a
particular level in a tank.
These switches are good candidates for use in multiple purpose
processing equipment where they
must be compatible with a variety of
process materials and process conditions. They do not require recalibration between batches and can be
cleaned in place.
Vibrating probe-type sensors are
often used to detect solid materials
such as powders, bulk solids, grain,
flour, plastic granules, cement, and fly
ash. They provide excellent performance as high or low level switches
102
Volume 4
Specialty Level Switches
and can be mounted from the tops
or sides of tanks. The low thermal
conductivity of solids and the dusty
atmospheres that are likely to exist in
the vapor space of solids bins tend to
exclude the use of optical and thermal switches from most solids level
measurement applications.
When solid materials rat-hole or
bridge, few level sensors (except load
washers to remove the build-up of
coating after each high level episode.
Thermal switches can continue to
work when lightly coated, but buildup does usually add a thermally
insulating layer, ultimately slowing
response time.
Of the three level-switch designs
discussed in this chapter, only the
laser-based optical level switch is
cells or radiation devices) work well.
The performance of vibrating probe
and tuning-fork sensors is also questionable in such services, but their
vibrating nature can help to collapse
the bridges or to break up the ratholes.
Vibrating and tuning fork probes
can tolerate a fair amount of material build-up, or, if coated with
Teflon®, can be self-cleaning in some
less difficult services. Optical level
switches are available with automatic
appropriate for use in molten metal
level detection. Of the other level
sensor technologies,
refractory
floats, refractory bubbler tubes, and
proximity-type capacitance detectors
also are used in molten metal service.
Thermal Switches
Thermal level switches sense either
the difference between the temperatures of the vapor space and the liquid or, more commonly, the increase
in thermal conductivity as a probe
TRANSACTIONS
becomes submerged in the process
liquid.
One of the simplest thermal level
switch designs consists of a temperature sensor heated with a constant
amount of heat input. As long as
the probe is in the vapor space, the
probe remains at a high temperature,
because low-conductivity vapors
do not carry much heat away from
the probe. When the probe is submerged, the liquid absorbs more heat
and the probe temperature drops.
The switch is actuated when this
change in temperature occurs.
Another type of thermal sensor
uses two resistance temperature
detectors (RTDs), both mounted
at the same elevation. One probe
is heated and the other provides
an unheated reference. The outputs of both sensors are fed into
a Wheatstone bridge (Figure 10-1).
While the sensor is in the vapor
phase, the heated probe will be
warmer than the reference probe,
and the bridge circuit will be unbalanced. When both probes are submerged in the process liquid, their
temperatures will approach that of
the liquid. Their outputs will be nearly
equal and the bridge will be in balance.
This level switch is actuated when a
change in bridge balance occurs.
Since all process materials have
a characteristic heat transfer coefficient, thermal level switches can be
calibrated to detect the presence or
absence of any fluid. Therefore, these
switches can be used in difficult services, such as interfaces, slurry, and
sludge applications. They can also
detect thermally conductive foams if
spray-cleaned after each operation.
Thermal level and interface switches
have no mechanical moving parts and
are rated for pressures up to 3,000
psig and process temperatures from
-75 to 175°C (-100 to 350°F). When
TRANSACTIONS
detecting water level, response time
is typically 0.5 second and accuracy is
within 2 mm. In general, thermal level
switches work best with non-coating
liquids and with slurries having 0.4-1.2
specific gravity and 1-300 cP viscosity.
A third type of thermal switch
also uses two sensors inside the
same vertical probe. One is mounted above the other and both are
connected to a voltage source.
When both are in the vapor or both
in the liquid phase, the current flow
through the two sensors is the same.
If, on the other hand, the lower one
is in liquid and the upper in vapor,
more current will flow through the
lower sensor. A current comparator
can detect this difference and signal
that the sensor has reached the
vapor/liquid interface.
One interesting feature of this
design is that the sensor capsule can
be suspended by a cable into a tank
or well, and the sensor output can
be used to drive the cable take-up
motor. In this fashion, the level switch
can be used as a continuous detector
of the location of the vapor/liquid
interface.
Thermometers also can be used
to detect level in higher temperature
processes, such as measuring the level
of molten steel in casting molds. The
thermometers do not actually touch
the molten metal; instead, they iden-
tify the place where the temperature
on the outside of the mold suddenly
increases. This is the level inside the
mold. Using multiple sensors spaced
vertically, the system can determine
the level of molten metal in the
mold to within a fraction of an inch.
Vibrating Switches
Vibrating level switches detect
the dampening that occurs when a
vibrating probe is submerged in a
process medium. The three types
of vibrating sensors—reed, probe,
and tuning fork—are distinguished
by their configurations and operating frequencies (120, 200-400, and
85 Hz, respectively). Their methods
of operation and applications are
similar. The reed switch consists of a
paddle, a driver and a pickup (Figure
10-2). The driver coil induces a 120Hz vibration in the paddle that is
damped out when the paddle gets
covered by a process material. The
switch can detect both rising and
falling levels, and only its actuation
depth (the material depth over the
paddle) increases as the density of
the process fluid drops. The variation in actuation depth is usually
less than an inch. A reed switch can
detect liquid/liquid, liquid/vapor,
and solid/vapor interfaces, and can
also signal density or viscosity variations.
When used on wet powders, the
vibrating paddle has a tendency to
create a cavity in the granular solids. If this occurs, false readings will
result, because the sensor will confuse the cavity with vapor space.
It is best to use a reed switch on
non-coating applications or to provide automatic spray washing after
each immersion in a sludge or slurry.
Probe-type vibrating sensors are less
sensitive to material build-up or coating. The vibrating probe is a round
Volume 4
103
104
stainless steel element (resembling
a thermowell) that extends into
the material. If Teflon® coated and
inserted at an angle, these devices tend to be self-cleaning. Both
the drive and the sensor are piezoelectric elements: one causes the
vibration and the other measures
Tuning-fork sensors can be constructed with components made of
PVDF, polypropylene, stainless steel,
carbon steel, and aluminum. They
are available with Teflon® coatings
or in hygienic versions for sanitary
applications.
Vibrating sensors can be used to
it. When the probe is buried under
the process material, its vibration is
dampened and this decrease triggers
the switch.
Vibrating probe sensors can be
used to monitor powders, bulk solids, and granular materials such as
grain, flour, plastic pellets, cement,
and fly ash. Their vibrating nature
tends to minimize the bridging that
occurs in solid materials. Tuning fork
sensors are vibrated at about 85 Hz
by one piezoelectric crystal, while
another piezoelectric crystal detects
the vibration. As the process fluid
rises to cover the tuning forks, the
vibration frequency changes.
Like vibrating probes, tuningfork designs can be self-cleaning if
Teflon® coated and installed at an
angle. They can also be calibrated
to detect a wide range of materials,
including lubricating oils, hydraulic
fluids, water, corrosive materials,
sand, thick and turbulent fluids, powders, light granules, and pastes.
ascertain liquid, solid, and slurry levels. Reed switches can operate at
pressures up to 3,000 psig, while
tuning forks and vibrating probes are
limited to 150 psig. Operating temperatures range from -100 to 150°C
(-150 to 300°F) and response time is
about 1 second.
Volume 4
Optical Switches
Using visible, infrared, or laser light,
optical sensors rely upon the light
transmitting, reflecting, or refracting
properties of the process material
when measuring its level. The optical
level switch can be of a contacting
or non-contacting design.
In a non-contacting, reflecting
optical sensor, a beam of light is
aimed down at the surface of the
process material. When the level of
this surface rises to the setpoint of
the switch, the reflected light beam
is detected by a photocell. Both the
LED light source and photodetector
are housed behind the same lens.
By adjusting the photocell or the
detection electronics, the sensor can
be calibrated to detect levels at distances 0.25 to 12 in below the sensor.
These reflective switches can measure
the levels of clear as well as translucent, reflective, and opaque liquids.
Some solids also can be detected. By
using multiple photocells, a sensor
can detect several levels.
Laser light also can be used when
making difficult level measurements,
such as of molten metals, molten
glass, glass plate, or any other kind
of solid or liquid material that has
a reflecting surface. If the receiver
module is motor driven, it can track
the reflected laser beam as the level
rises and falls, thereby acting as a
continuous level transmitter.
A refracting sensor relies on the
principle that infrared or visible
light changes direction (refracts)
Ultrasonic liquid level switches provide a 300:1 signal ratio from dry to wetted state.
TRANSACTIONS
when it passes through the interface between two media. When
the sensor is in the vapor phase,
most of the light from the LED is
reflected back within a prism (Figure
10-3). When the prism is submerged,
most of the light refracts into the
liquid, and the amount of reflected
light that reaches the receiver drops
substantially. Therefore, a drop in
the reflected light signal indicates
contact with the process liquid.
A refracting sensor cannot be used
with slurries or coating liquids, unless
it is spray-washed after each submersion. Even a few drops of liquid on the
prism will refract light and cause erroneous readings. Refracting sensors are
designed to be submerged in liquids;
therefore, any number of them can be
installed on a vertical pipe to detect a
number of level points.
Transmission optical sensors send
a beam of light across the tank. A
sludge level sensor of this design uses
an LED and a photocell at the end of
a probe, located at the same elevation and separated by a few inches.
To find the sludge level, a mechanism
(or an operator, manually) lowers the
probe into the tank until the sensors
TRANSACTIONS
encounter the sludge layer.
Other transmission sensors rely on
the refraction principle utilizing an
unclad, U-shaped fiber optic cable. A
light source transmits a pulsed light
beam through the fiber cable, and
the sensor measures the amount of
light that returns. If liquid covers the
cable, it will cause light to refract
away from the cable. The use of
fiber-optics makes the system impervious to electrical interference, and
some designs are also intrinsically
safe.
Optical sensors can operate
at pressures up to 500 psig and
temperatures up to 125°C (260°F).
Response time is virtually immediate, and detection accuracy of
most designs is within 1 mm. Optical
level switches are also designed
for specific or unique applications.
For example, Teflon® optical level
switches are available for sensing the level of ultra-pure fluids.
Other unique designs include a level
switch that combines an optical
with a conductivity-type level sensor to detect the presence of both
water (conductive) and hydrocarbons (nonconductive).
T
References & Further Reading
•OMEGA
Complete Flow and Level Measurement Handbook and
Encyclopedia®, Omega Press, 1995.
•Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents
Edition, Omega Press, 1995.
•Industrial Control Handbook, E.A. Parr, Butterworth-Heinemann Ltd., 1995.
•Instrument Engineer’s Handbook, Bela Liptak, Third Edition, CRC Press,
1995.
•Process/Industrial Instruments and Controls Handbook, 4th Edition,
Douglas M. Considine, McGraw-Hill, 1993.
•The McGraw-Hill Encyclopedia of Science and Technology, 8th Edition,
John H. Zifcak, McGraw-Hill, 1997.
Volume 4
105
Information Resources
ORGANIZATIONS
106
NAME/ADDRESS
American Institute of Chemical Engineers (AIChE)
345 East 47 Street, New York NY 10017-2395
PHONE
WEB ADDRESS
(212)705-7338
www.aiche.org
American Gas Association (AGA)
400 N. Capitol St., NW Washington DC 20001
(202)824-7000
www.aga.org
American National Standards Institute (ANSI)
11 West 42 Street, New York NY 10036
(212)642-4900
web.ansi.org
American Petroleum Institute (API)
1220 L Street, NW, Washington DC 20005
(202)682-8000
www.api.org
American Society of Mechanical Engineers (ASME)
345 East 47 Street, New York NY 10017
(212)705-7722
www.asme.org
American Society for Testing and Materials (ASTM)
100 Barr Harbor Drive, West Conshohocken PA 19428-2959 (610)832-9585
www.astm.org
American Water Works Association (AWWA)
6666 West Quincy Ave., Denver CO 80235
(303)794-7711
www.awwa.org
Canadian Gas Association (CGA)
243 Consumers Road, Suite 1200,
North York Canada M2J 5E3 ON
(416)498-1994
www.cga.ca
Electric Power Research Institute (EPRI)
3412 Hillview Avenue, Palo Alto CA 94303
(415)855-2000
www.epri.com
Electronic Industries Association (EIA)
2500 Wilson Boulevard, Arlington VA 22201-3834
(703/907-7500
www.eia.org
Factory Mutual
1151 Boston-Providence Turnpike, Norwood MA 02062
(781)762-4300
www.factorymutual.com
Gas Research Institute
8600 West Bryn Mawr Ave., Chicago IL 60631-3562
(773)399-8100
www.gri.org
International Electrotechnical Commission (IEC)
3, rue de Varembé, P.O. Box 131,
CH - 1211 Geneva 20, Switzerland
+41 22 919 02 11
www.iec.ch
International Organization for Standardization (ISO)
1, rue de Varembe, Case postale 56,
CH-1211 Geneve 20 Switzerland
+41 22 749 01 11
www.iso.ch
Institute of Electrical & Electronics Engineers (IEEE)
445 Hoes Lane, Piscataway NJ 08855-1331
(732)981-0060
www.ieee.org
Institute of Gas Technology (IGT)
1700 South Mount Prospect Road, Des Plaines IL 60018
(847)768-0500
www.igt.org
Volume 4
TRANSACTIONS
organizations (cont'D.)
ISA—The International Society for Measurement and Control
67 Alexander Drive, Research Triangle Park NC 27709
(919)549-8411
www.isa.org
National Electrical Manufacturers Association (NEMA)
1300 North 17th Street, Suite 1847, Rosslyn VA 22209
(703)841-3200
www.nema.org
National Fire Protection Association (NFPA)
1 Batterymarch Park, Quincy MA 02269-9101
(617)770-3000
www.nfpa.org
National Institute of Standards and Technology
Gaithersburg MD 20899-0001
(301)975-3058
www.nist.gov
Society of Automotive Engineers (SAE)
400 Commonwealth Drive, Warrendale PA 15096-0001
(724)776-4841
www.sae.org
Underwriters Laboratories
333 Pfingsten Road, Northbrook IL 60062
(847)272-8800
www.ul.com
Water Environment Federation (WEF)
601 Wythe Street, Alexandria VA 22314-1994
(703)684-2452
www.wef.org
flow and level Products
For the Latest
Information on
Flow and Level
Products:
Omega Engineering, Inc.
One Omega Drive
P.O. Box 4047
Stamford CT 06907-0047
Phone: 800-82-66342
(800-TC-OMEGA®)
Email: [email protected]
Website: www.omega.com
omega press references
The Temperature Handbook™ Voume MM™ 21st Century™ Edition,
OMEGA Press, 1999.
The OMEGA Complete Flow and Level Measurement Handbook and Encyclopedia®,
Omega Press, 1995.
The Pressure, Strain and Force Handbook™,
Omega Press, 1995.
Book of Books®: Scientific & Technical Books, Software & Videos,
Omega Press, 1998.
Omega Volume 29 Handbook & Encyclopedia, Purchasing Agents Edition,
Omega Press, 1995
21st Century™ Preview Edition,
Omega Press, 1997
TRANSACTIONS
Volume 4
107
OTHER REFERENCE BOOKS
Applied Fluid Flow Measurement,
N.P. Cheremisinoff, Marcel Decker, 1979.
Automated Process Control Electronics,
John Harrington, Delmar Publishing Inc., 1989.
Differential Producers - Orifice, Nozzle, Venturi,
ANSI/ASME MFC, December 1983.
Electrical Measurements and Measuring Instruments,
E.W. Goldin, Pitman and Sons, 1948.
Electrical Measurements,
F.K. Harris, Wiley, 1952.
Flow Measurement Engineering Handbook,
R.W. Miller, McGraw Hill, 1996.
Flow Measurement for Engineers and Scientists,
N.P. Cheremisinoff, Marcel Dekker, 1988.
Flow Measurement,
Bela Liptak, CRC Press, 1993.
Flow Measurement,
D.W. Spitzer, Instrument Society of America, 1991.
Flow of Water Through Orifices,
AGA/ASME, Ohio State Univ. Bulletin 89, Vol. IV, No.3.
Flowmeters,
F. Cascetta, P. Vigo, ISA, 1990.
Fluid Meters,
H.S. Bean, American Society of Mechanical Engineers, 1971.
Fundamentals of Flow Measurement,
J. P. DeCarlo, Instrument Society of America, 1984.
Fundamentals of Radar Techniques for Level Gauging,
Detlef Brumbi, Krohne Metechnik GmbH & Co. KG, 1995.
Incompressible Flow,
Donald Panton, Wiley, 1996.
Industrial Applications of Radar Technology for Continuous Level Measurement,
W. L. Hendrick, Instrument Society of America, 1992.
Industrial Control Handbook,
E.A. Parr, editor, Butterworth-Heinemann Ltd., 1995.
Industrial Flow Measurement,
D. W. Spitzer, ISA 1984.
Instrument Engineer’s Handbook,
Bela Liptak, Third Edition, CRC Press, 1995.
Instrumentation and Control,
C.L. Nachtigal, Wiley, 1990.
Instrumentation and Process Control,
Nicholas P. Chopey, McGraw-Hill, 1996.
108
Volume 4
TRANSACTIONS
OTHER REFERENCE BOOKS
Instrumentation for Engineering Measurements,
J. Dally, Wiley, 1993.
Instrumentation for Process Measurement and Control, 3rd ed.,
Norman A. Anderson, Chilton Co., 1980.
Instrumentation Reference Book, 2nd ed.,
B.E. Noltingk, editor, Butterworth-Heinemann, 1995.
Instruments of Science,
Robert Bud and Deborah Jean Warner, Garland Publishing Inc., 1998.
Measurement and Control Basics, 2nd ed.,
T.A. Hughes, ISA, 1995.
Measurement and Control of Liquid Level,
C. H. Cho, Instrument Society of America, 1982.
Modern Physics,
New York, P. Tipler, Worth Publishers, 1978.
National Electrical Safety Code,
IEEE, 1993.
Principles of Industrial Measurement for Control Applications,
E. Smith, Instrument Society of America, 1984.
Process /Industrial Instruments and Controls, 4th ed.,
Douglas M. Considine, McGraw-Hill, 1993.
Sensor and Analyzer Handbook,
H.N. Norton, Prentice-Hall, 1982.
Sensors and Control Systems in Manufacturing,
S. Soloman, McGraw-Hill, 1994.
The McGraw-Hill Encyclopedia of Science and Technology, 8th ed.,
John H. Zifcak, McGraw-Hill, 1997.
Theoretical Nuclear Physics Volume I: Nuclear Structure,
New York, A. deShalit, H. Feshback, John Wiley & Sons, 1974.
Van Nostrand’s Scientific Encyclopedia,
Douglas M. Considine, Van Nostrand, 1995.
Water Meters - Selection, Installation, Testing and Maintenance,
Manual M6, AWWA, 1986.
Teflon®, Viton® and Kalrez® are registered trademarks of DuPont.
TRANSACTIONS
Volume 4
109
Glossary
A
Accuracy: Degree of conformity of a measured value to
an accepted standard value; or closeness of a reading or
indication of a sensor to the actual value of the quantity
being measured.
Accuracy rating: A number that defines a limit that the
measurement errors will not exceed under some reference operating conditions. It includes the combined
effects of conformity, hysteresis, deadband and repeatability errors.
Accuracy, units: The maximum positive or negative
deviation (inaccuracy) observed in testing a device. It can
be expressed in terms of the measured variable (±1°C), or
as a percentage of the actual reading (%AR), of the full
scale (%FS), of upper range value (%URL), of the span or
of scale length.
Admittance: Admittance of an ac circuit is analogous to
conductivity of a dc circuit; it is the reciprocal of the
impedance of an ac circuit.
Air consumption: The maximum rate at which air is
consumed by an instrument while operating within its
operating range, usually expressed in units of standard
cubic feet per minute.
Alphanumeric: A character set containing both letters
and numbers.
Alternating current (ac): A flow of electric charge (electric current) that undergoes periodic reverses in direction. In North America, household current alternates at a
frequency of 60 times per second.
Ambient pressure: The atmospheric pressure of the
medium surrounding a particular sensor. When no specific information is available, it is assumed to be 14.7 psia.
Ambient temperature: The average or mean temperature
of the atmospheric air which is surrounding a sensor or
instrument. If the sensor is a heat generator, this term
refers to the temperature of the surroundings when the
sensor is in operation. The ambient temperature is usually stated under the assumption that the sensor is not
exposed to the sun or other radiant energy sources.
Ambient temperature compensation: An automatic correction which prevents the reading of a sensor or instrument from being affected by variations in ambient temperature. The compensator specifications state the temperature range within which the compensation is effective.
110
Volume 4
American National Standards Institute (ANSI): A professional organization in the United States responsible for
accepting and designating the standards developed by
other organizations as national standards.
Ampere (A or amp): The unit of electric current flow,
defined as the rate at which one coulomb of electric
charge (6.25 x 1018 electrons) is transferred in a second.
Amplifier: A device that generates an output which is
stronger than and bears some predetermined relationship (often linear) to its input. It generates the amplified
output signal while drawing power from a source other
than the signal itself.
Analog signal: A signal that continuously represents a
variable or condition.
Analog-to-digital (A/D) conversion: A generic term
referring to the conversion of an analog signal into a
digital form.
Analog-to-digital converter (ADC): An electronic device
that converts analog signals to an equivalent digital
form.
Attenuation: The reciprocal of gain; a dimensionless
ratio defining the decrease in magnitude of a signal as
it passes between two points or two frequencies. Large
values of attenuation are expressed in decibels (dB).
B
Backlash: The relative movement of interlocked mechanical parts that occurs when motion is reversed.
Baud rate: Serial communications data transmission rate
expressed in bits per second (bps).
Bipolar: A signal range that includes both positive and
negative values (i.e., -10 V to +10 V).
Bode diagram: A plot of log amplitude ratio and phase
angle values used in describing transfer functions.
Breakdown voltage: Threshold voltage at which circuit
components begin to be damaged.
Byte (B): Eight related bits of data or an eight-bit binary
number. Also denotes the amount of memory required
to store one byte of data.
C
Calibrate: To ascertain that the output of a device
properly corresponds to the information it is measuring,
receiving or transmitting. This might involve the location
of scale graduations, adjustment to bring the output
within specified tolerance or ascertaining the error by
TRANSACTIONS
comparing the output to a reference standard.
Calibration: The process of adjusting an instrument or
compiling a deviation chart so that its reading can be
correlated to the actual values being measured.
Calibration curve: A graphical representation of the
calibration report, which report can be in the form of a
table or chart.
Calibration cycle: The application of known values of a
measured variable and the recording of the corresponding output readings over the range of the instrument in
both ascending and descending directions.
Calibration traceability: The relationship of the calibration process to the calibration steps performed by a
national standardizing laboratory.
Capacitance: The capability of a device to store electric
charge. The unit is the farad, which expresses the ratio
of stored charge in coulombs to the impressed potential
difference in volts.
Capacitor: A device designed to store electric charge. It
usually consists of two conductors that are electrically isolated by a nonconductor (dielectric). The plates of a perfect capacitor are isolated by vacuum (dielectric constant
of 1.0), in which case no current flows between the plates.
Common mode rejection: The ability of a circuit to discriminate against a common mode voltage.
Common mode voltage: A voltage of the same polarity
on both sides of a differential input relative to ground.
Compensator: A device that eliminates the effect of an
unmeasured variable or condition on the measurement
of interest.
Compound detector: A detector whose measurement
range extends both above and below zero.
Conductance; Conductivity: The reciprocal of resistance
in a dc circuit is conductance. The unit is the mho. The
unit of conductivity is cm-mho or cm/ohm.
Controller: A device that operates automatically to
regulate a controlled variable.
Coulomb: The amount of electric charge transferred in
one second by a current flow of one ampere.
D
Damping: The suppression of oscillation. The viscosity of
a fluid is used in viscous damping, while the induced current in electrical conductors is used to effect magnetic
damping.
Deadband: The range through which an input can be
changed without causing an observable response.
Dead time: The interval between the initiation of
a change in the input and the start of the resulting
TRANSACTIONS
observable response.
Decibel (dB): Unit for expressing a logarithmic measure
of the ratio of two signal levels.
Dielectric: A non-conductor of dc current.
Dielectric constant: A numeral that expresses the degree
of non-conductivity of different substances, with full
vacuum defined as 1.0.
Distributed control system (DCS): Typically, a largescale process control system characterized by a distributed network of processors and I/O subsystems that
encompass the functions of control, user interface, data
collection, and system management.
Dither: A useful oscillation of small magnitude, introduced to overcome the effects of friction, hysteresis,
or clogging.
Drift: Undesired change in the input-output relationship
over a period of time.
Dynamic range: Ratio of the largest to the smallest signal
level a circuit can handle, normally expressed in dB.
E
Electromotive force: Force that causes the movement
of electricity, such as potential difference of voltage. A
measure of voltage in an electrical circuit.
Elevation: A range in which the zero value of the measured variable exceeds the lower range value.
Error: The difference between the measured signal value
or actual reading and the true (ideal) or desired value.
Error, common mode: Error caused by interference
that appears between both measuring terminals and
ground.
Error, normal mode: Error caused by interference that
appears between the two measuring terminals.
Error, random: The amount of error that remains even
after calibrating a sensor. Also called "precision," while
"repeatability" is defined as twice that: the diameter
(instead of the radius) of the circle within which the
readings fall.
Error, systematic: A repeatable error, which either
remains constant or varies according to some law, when
the sensor is measuring the same value. This type of error
can be eliminated by calibration.
F
Farad: The unit of capacitance, equivalent to one coulomb of stored charge per volt of applied potential difference. As this is a very large unit, one trillionth of it, the
picofarad (pf), is commonly used.
Fieldbus: All-digital communication network used to
connect process instrumentation and control systems.
Volume 4
111
Designed to replace systems based on 4-20 mA analog
signals with bi-directional, multivariable data communication capability.
Frequency: The number of cycles over a specified
time period during which an event occurs. Normally
expressed in cycles per second (hertz, Hz).
Frequency response: The frequency-dependent characteristic that determines the phase and amplitude relationship between sinusoidal input and output.
G
Gain (magnitude ratio): For a linear system or element,
the ratio of the magnitude (amplitude) of a steady-state
sinusoidal output relative to a causal input. In an electrical circuit, the amount of amplification used, sometime
expressed in decibels (dB).
Gain accuracy: Measure of deviation of the gain (of an
amplifier or other device) from the ideal gain.
Gain, dynamic: For a sinusoidal signal, the magnitude
ratio of the steady-state amplitude of an output signal
to the amplitude of the input.
Gain, static: The ratio of change of steady-state value
to a step change in input, provided that the output does
not saturate.
Ground: The electrical neutral line having the same
potential as the surrounding earth; the negative side of a
direct current power system; the reference point for an
electrical system.
H
Hertz (Hz): The unit of frequency, defined as one cycle
per second.
Hunting: An undesirable oscillation which continues for
some time after an external stimulus has disappeared.
Hysteresis: The property of an element or sensor, whereby output is dependent not only on the value of the
input, but on the direction of the current traverse. (That
is, the reading of the same value differs as a function of
whether the measurement is rising or falling.)
I
Impedance: Opposition to the flow of ac current; the
equivalent of resistance in dc circuits. The unit is the
ohm. The impedance of an ac circuit is one ohm if a
potential difference of one volt creates a current flow
of one ampere within it.
Inductance: The property by which an electromotive
force (emf) is induced in a conductor when the magnetic field is changing about it. This is usually caused by
changes in the current flow in the circuit or in a neighboring circuit.
112
Volume 4
Input/output (I/O): The analog or digital signals entering or leaving a DCS or other central control or computer system involving communications channels, operator
interface devices, and/or data acquisition and control
interfaces.
Integral control: A control mode which generates a corrective output signal in proportion to the time integral
of the past error. It eliminates the offset inherent in
proportional control.
Intrinsically safe: Equipment or wiring which is incapable
of releasing sufficient electrical or thermal energy to
ignite a hazardous mixture of hydrocarbon vapors and
air. In such equipment, the electrical energy is limited
so that it cannot generate a spark or otherwise ignite a
flammable mixture.
ISA: Formerly, The Instrument Society of America; now
referred to as the International Society for Measurement
& Control.
L
Laser: Narrow, intense beam of coherent light.
Linearity: The closeness to which a curve approximates a
straight line, or the deviation of an instrument’s response
from a straight line.
Linear stroke: For a transducer, the calibrated mechanical movement over which its electrical output linearity
meets its specifications.
Loop gain characteristics: Of a closed loop, the characteristic curve of the ratio of the change in the return signal
to the change in the error signal for all real frequencies.
Loop transfer function: Of a closed loop, the transfer
function obtained by taking the ratio of the Laplace
transform of the return signal to the Laplace transform
of its corresponding error signal.
Lower range limit (LRL): The lowest value of the
measured variable that a device can be adjusted to
measure.
Lower range value (LRV): The lowest value of the measured variable that a device is adjusted to measure.
M
Manipulated variable: A quantity or condition which is
varied as a function of an actuating error signal so as to
change the value of the directly controlled variable.
Measurement signal: The electrical, mechanical, pneumatic, digital or other variable applied to the input of
a device. It is the analog of the measured variable produced by the transducer.
Measurement variable: A quantity, property or condition
which is being measured, sometimes referred to as the
TRANSACTIONS
measurand.
Milliamp (mA): One thousandth of an ampere.
Millivolt (mV): One thousandth of a volt.
Multiplexer (Mux): A switching device that sequentially
connects multiple inputs or outputs in order to process
several signal channels with a single A/D or D/A converter.
N
Noise: Any undesirable electrical signal, from external
sources such as ac power lines, motors, electrical storms,
radio transmitters, as well as internal sources such as
electrical components.
Non-linearity: The deviation from the best fit straight
line that passes through zero.
Normal-mode rejection ratio: The ability of an instrument to reject electrical interference across its input
terminals, normally of line frequency (50-60 Hz).
Nyquist theorem: The law that is the basis for sampling
continuous information. It states that the frequency of
data sampling should be at least twice the maximum frequency at which the information might vary. This theorem should be observed in order to preserve patterns in
the information or data, without introducing artificial,
lower frequency patterns.
O
Ohmmeter: A device used to measure electrical resistance.
One-to-one repeater: A diaphragm-operated device
which detects process pressure and generates an air (or
nitrogen) output signal of equal pressure.
Optical isolation: Two networks or circuits in which an
LED transmitter and receiver are used to maintain electrical discontinuity between the circuits.
Output settling time: The time required for an analog output voltage to reach its final value within specified limits.
Output signal: A signal delivered by a device, element
or system.
Output slew rate: The maximum rate of change of analog output voltage from one level to another.
Overtravel: That part of a stroke which falls between the
end of the calibrated range and the travel stop.
P
Phase: A time-based relationship between a periodic
function and a reference.
Phase shift: The angle in degrees between an energizing
voltage waveform and an output signal waveform.
Polarity: In electricity, the quality of having two charged
TRANSACTIONS
poles, one positive and one negative.
Port: A communications connection on an electronic or
computer-based device.
Power supply: A separate unit or part of a system that
provides power (pneumatic, electric, etc.) to the rest of
a system.
Pressure, ambient: The pressure of the medium surrounding a device.
Pressure, design: The pressure used in the design of a
vessel or other item of equipment for the purpose of
determining the minimum permissible wall thickness
or size of parts for a given maximum working pressure
(MWP) at a given temperature.
Pressure, maximum working: The maximum permissible
operating pressure at a specified temperature. This is the
highest pressure to which the device will be subjected
during regular use.
Pressure, operating: The actual (positive or negative)
pressure at which a device operates under normal conditions.
Pressure, rupture: The burst pressure of a device (determined by testing).
Pressure, static: The steady-state pressure applied to a
device.
Pressure, supply: The pressure at which a utility (such as
air) is supplied to a device.
Pressure, surge: Operating pressure plus the increment
to which a device can be subjected for a very short time
during temporary pressure surges caused by such phenomena as pump start-up or valve shut-off.
Pretravel: That part of a stroke which falls below the
calibrated range, between zero and the travel stop.
Primary element: An element that converts a measured
variable into a force, motion or other form suitable for
measurement.
Process: Physical or chemical change of matter or conversion of energy.
Process measurement: The acquisition of information
that establishes the magnitude of process quantities.
Programmable logic controller (PLC): Computer-based
industrial monitoring and control package with applications mostly in the areas of safety, sequential or logical
operations, where control actions are based on equipment and alarm status.
Proportional control: A control mode which generates
an output correction in proportion to error (the process
variable’s deviation from setpoint).
Volume 4
113
Proportional-integral-derivative (PID): Also referred to
as a 3-mode controller, combining proportional, integral,
and derivative control actions.
psia: Pounds per square inch absolute; the unit of pressure used when the zero reference is full vacuum.
psig: Pounds per square inch gauge; the unit of pressure
used when the zero reference is the barometric pressure
of the atmosphere.
R
Radio frequency: The frequency range between ultrasonic
and infrared. AM broadcast frequencies range from 540
to 1,800 kHz, while FM broadcasts from 88 to 108 MHz.
Radio frequency interference (RFI): Noise induced upon
signal wires by ambient radio-frequency electromagnetic
radiation with the effect of obscuring an instrument signal.
Ramp: The total (transient plus steady-state) time response
resulting from a sudden increase in the rate of change from
zero to some finite value of input stimulus.
Range: The region between the limits within which a
quantity is measured, received or transmitted, expressed
by stating lower and upper range values.
Reactance: The opposition to the flow of ac current,
which is created by either inductance or capacitance. In
such a circuit, total impedance is therefore the sum of
reactance and resistance. The unit is the ohm.
Reference input: An external signal serving as a setpoint
or as a standard of comparison for a controlled variable.
Reliability: The probability that a device will perform its
objective adequately for the period of time specified,
under the operating conditions specified.
Repeatability: The maximum difference between output
readings when the same input is applied consecutively;
the closeness of agreement among consecutive measurements of an output for the same value of input under the
same operating conditions, approaching from the same
direction, usually measured as non-repeatability and
expressed as percent of span.
Reproducibility: The closeness of agreement among
repeated measurements of an output for the same value
of input made under the same operating conditions over
a period of time, approaching from both directions. It
includes hysteresis, deadband, drift and repeatability.
Resistance; Resistivity: The opposition to the flow of
current in a dc circuit. The unit is the ohm, which is
defined as the resistance that will give a one-ampere
current flow if a one-volt potential difference is applied
in a circuit Resistivity is the reciprocal of conductivity;
114
Volume 4
its unit is the ohm/cm.
Resolution: The smallest change in input which produces
a detectable change in output. This is the smallest increment of change that can be detected by a measurement
system. Resolution can be expressed in bits, in proportions, in percent of actual reading or in percent of full
scale. For example, a 12-bit system has a resolution of
one part in 4,096 or 0.0244% of full scale.
Resonance: A condition of oscillation caused when
a small amplitude of periodic input has a frequency
approaching one of the natural frequencies of the driven
system.
Response time: An output expressed as a function of
time, resulting from the application of a specified input
under specified operating conditions.
S
Sampling period: The time interval between observations.
Scale factor: The factor by which the number of scale
divisions indicated or recorded by an instrument must be
multiplied to compute the value of a measured variable.
Sensing element: The element that is directly responsive
to the value of a measured variable.
Sensitivity: The minimum change in a physical variable
to which an instrument can respond; the ratio of the
change in output magnitude to the change of the input
which causes it after the steady-state has been reached.
Sensor: An element or device that detects a variable
by receiving information in the form of one quantity
and converting it to information in the form of that or
another quantity.
Setpoint: A variable, expressed in the same units as the
measurement, which sets either the desired target for
a controller, or the condition at which alarms or safety
interlocks are to be energized.
Settling time: The time required after a stimulus for the
output to center and remain within a specified narrow
band centered on its steady-state value.
Signal: A variable that carries information about another
variable that it represents.
Signal-to-noise ratio: Ratio of signal amplitude to noise
amplitude. The ratio of overall rms signal level to rms
noise level, expressed in dB. For sinusoidal signals, amplitude may be peak or rms.
Span: The algebraic difference between the upper and
lower range values expressed in the same units as the
range.
Span shift: Any change in slope of the input-output
TRANSACTIONS
curve.
Stability: The ability of an instrument or sensor to
maintain a consistent output when a constant input is
applied.
Steady-state: A characteristic of a condition, such as
value, rate, periodicity, or amplitude, exhibiting only
negligible change over an arbitrary, long period of time.
Stiffness: The ratio of change of force (or torque) to the
resulting change in deflection of a spring-like element,
the opposite of compliance.
Strain: The ratio of the change in length to the initial
unstressed reference length of an element under stress.
Subsidence: The progressive reduction or suppression of
oscillation in a device or system.
Suppressed range: A range in which the zero value of a
measured variable is greater than the lower-range value
(LRV). The terms "elevated zero," "suppression" or "suppressed span" are also used to express the condition when
the zero of the measured variable is greater than the LRV.
Suppressed span: The span in which the zero of the measured variable is greater than the LRV.
Suppressed zero: The range in which the zero value of a
measured variable is less than the lower range value. The
terms "elevation," "elevated range" and "elevated span"
are frequently used to express the condition in which
the zero of the measured variable is less than the lower
range value.
Suppression ratio: The ration of the lower-range value to
the span. If range is 20-100 and, therefore, span is 80 and
LRV is 20, the suppression ratio is 20/80 = 0.25 or 25%.
Synchronous: An event or action that is synchronized to
a reference clock.
System noise: Measure of the amount of noise seen by
an analog circuit or an ADC when the analog inputs are
grounded.
T
Temperature coefficient: The amount of drift, in percent
of full scale output, that might result from a 1°C change
in ambient temperature.
Thermal shock: An abrupt temperature change applied
to a device.
Time constant: The value "T" in an exponential term A(-t/T).
For the output of a first-order system forced by a step or
an impulse, T is the time required to complete 63.2% of
the total rise or decay. For higher order systems, there is
a time constant for each of the first-order components
of the process.
TRANSACTIONS
Transducer: An element or device that receives information in the form of one quantity and converts it to information in the same or another quantity or form. Primary elements and transmitters are also referred to as transducers.
Transfer function: Mathematical, graphical, or tabular
statement of the influence which a system or element
has on a signal or action compared at input and at output terminals.
Transient: The behavior of a variable during transition
between two steady-states.
Transmitter: A transducer which responds to a measured
variable by means of a sensing element, and converts it
to a standardized transmission signal which is a function
only of the values of the measured variable.
U
Upper range limit (URL): The highest value of a measured
variable that a device can be adjusted to measure. (This
value corresponds to the top of the range.)
Upper range value (URV): The highest value of a measured variable that a device is adjusted to measure. (This
value corresponds to the top of the span.)
V
Vapor pressure: The pressure exerted by a vapor which is
in equilibrium with its own liquid.
Variable: Any condition that is measured, controlled
(directly or indirectly) or manipulated.
Velocity limit: A limit on the rate of change which a
particular variable may not exceed.
Vibration: The periodic motion or oscillation of an element, device, or system.
Volt (V): The electrical potential difference between two
points in a circuit. One volt is the potential needed to
move one coulomb of charge between two points while
using one joule of energy.
W
Warm-up period: The time required after energizing a
device before its rated performance characteristics start
to apply.
Z
Zero offset: The non-zero output of an instrument,
expressed in units of measure, under conditions of true
zero.
Zero suppression: For a suppressed-zero range, the
amount by which a measured variable’s zero is less than
the lower-range value; can be expressed as a percentage
of either the measured variable or of the span.
Zone, neutral: A predetermined range of input values
that do not result in a change in the previously existing
output value.
Volume 4
115
Notice of
Intellectual Property Rights
The OMEGA® Handbook Series is based upon original
intellectual property rights that were created and
developed by OMEGA. These rights are protected
under applicable copyright, trade dress, patent and
trademark laws. The distinctive, composite appearance of these Handbooks is uniquely identified with
OMEGA, including graphics, product identifying pings,
paging/section highlights, and layout style. The front,
back and inside front cover arrangement is the subject of a U. S. Patent Pending.
©2001 Putman Publishing Company and OMEGA Press LLC.
Was this manual useful for you? yes no
Thank you for your participation!

* Your assessment is very important for improving the work of artificial intelligence, which forms the content of this project

Download PDF

advertisement