Do not hesitate, download and send feedback

1. Flow Measurements
1

2. 2

3. Definitions and Units
Flow rate corrections
Differential Pressure Flow Transmitters
Differential Pressure Methods
Orifice Plates
Venturi Tubes
Flow Nozzles
Pitot Tubes
Vortex Type Flow Elements
Target Flowmeter
Turbine Flowmeter
Positive Displacement Flowmeter
Ultrasonic Flowmeter
Coriolis Flowmeter
3

4. 4

5. It is the art and science of:
1. applying instruments
2. to sense a chemical or physical process
condition.
5

6. Measurement of a given quantity is an act or
the result of comparison between the
quantity and a predefined standard.
6

7. 7

8. In order that the results are meaningful,
there are two basic requirements:
1. The standard used for comparison
purposes must be accurately defined and
should be commonly accepted.
2. The apparatus used and the method
adopted must be proved.
8

9. The advancement of science and technology
is dependent upon a parallel progress in
measurement techniques.
9

10. There are two major functions in all
branches of engineering:
1. Design of equipment and processes.
2. Proper operation and maintenance of
equipment and processes.
Both functions require measurements.
10

11. •Direct Method: The unknown quantity is directly
compared against a standard.
•Indirect Method: Measurement by direct methods
are not always possible, feasible and practicable.
Indirect methods in most of the cases are
inaccurate because of human factors.
They are also less sensitive.
11

12. Instruments
In simple cases, an instrument consists of a
single unit which gives an output reading or
signal according to the unknown variable
applied to it.
In more complex situations, a measuring
instrument consists of several separate
elements.
12

13. These elements may consist of:
•Transducer elements which convert the
measurand to an analogous form.
•The analogous signal is then processed by
some intermediate means and then fed to
•The end devices to present the results for
the purposes of display and or control.
13

14. These elements are:
•A detector.
•An intermediate transfer device.
•An indicator.
14

15. The history of development of instruments
encompasses three phases:
•Mechanical.
•Electrical.
•Electronic.
15

16. Purpose of Process
Measurement
• Reaching corporate economic goals
• Controlling a process
• Maintaining safety
• Providing product quality
16

17. •No matter how advanced or sophisticated the
distributed control system,
•the control system is only as effective as the
process measurement instruments it is
connected to;
•therefore, successful process control is
dependent on successful instrument
application.
17

18. To correctly apply instrumentation, an
engineer must clearly understand the
operations and limitations of the instrument,
as well as understanding the chemical and
physical properties of the process.
18

19. •Fundamental to applying process
instrumentation is interpreting the instrument’s
performance envelope.
•Every field measurement device has its own
distinct envelope that constitutes the process and
environmental conditions it can perform to.
•Likewise, every application has a characteristic
envelope that represents the application's
process and environmental conditions.
19

20. 20

21. Metrology
It is the “science of measurement.”
As a science, metrology uses terminology and
definitions that the process measurement
engineer must be familiar with.
He must and have a clear understanding of,
because vendors may vary in the use of a term.
21

22. The instrument engineer must consider the
following dynamic conditions that affect
process measurement:
• Temperature Effects
• Static Pressure Effects
• Interference
• Instrumentation Response
• Noise
• Damping and Digital Filtering
22

23. These dynamic conditions cause the presence of
uncertainty in measuring systems.
No measurement, however precise or repeated,
can ever completely eliminate this uncertainty.
The uncertainty of measuring systems is
exemplified in the effects temperature variations
can have on measurements.
23

24. Temperature Effects
•Temperature influences can exhibit some of the
most severe effects on a process measurement,
both in the process media itself and the
measurement instrument.
24

25. Some obvious examples of severe temperature
influences include temperature-induced phase
transitions.
It would be hard to determine what would happen to an
orifice plate, differential pressure measurement if the
process suddenly changed from a liquid to a solid or gas.
25

26. Other temperature induce dynamic changes
include:
•Change in the dimensions of the measuring
element,
•Modification of a resistance of a circuit, or
•Temperature-induced change in the flux density
of a magnetic element.
26

27. Similar to temperature effects, pressure changes can
also trigger phase transitions, especially in gas
applications.
Pressure effects seen in differential pressure (DP)
devices are an example.
Because the differential pressure devices are used in
flow and level applications, the importance of pressure
effects should not be underestimated.
27

28. •The goal is to minimize the total error that pressure
effects can cause.
•To illustrate this, consider a differential pressure
instrument that is calibrated in a lab at zero static
pressure.
•The transmitter is re-zeroed after installation by
opening an equalizing valve in the process under
pressure to eliminate zero shifts;
•however, variations inline pressure are not accounted
for during normal operations.
28

29. Interference, in process measurement terms, refers to
either external power or electrical potential that can
interfere with the reception of a desired signal or the
disturbance of a process measurement signal.
29

30. Instrumentation Response
•The dynamic characteristic of instrumentation
response refers to how quickly a measuring instrument
reacts or responds to a measured variable.
•An ideal, perfect instrument would have an
instantaneous response, which in effect, is called zero
lag.
•In general, with modern electronic instrumentation,
the response time is adequate for most applications.
30

31. •Engineers should concern themselves with response
time performance.
•Although fast speed of response is an attribute of high
quality instrumentation,
•some applications with rapidly changing processes
would not benefit from fast responding devices and
could even result in instrument damage.
•Depending on the application, some measurement lag
is placed on the measuring device.
31

32. •Noise is often described as a signal that does
not represent actual process measurement
information.
•Noise can originate internally within the process
measuring system or externally from the process
condition.
•It makes up part of the total signal from which
the desired signal must be read.
32

33. Damping and Digital Filtering
•Damping is defined as the progressive reduction
or suppression of oscillation in a device or system.
•In more practical terms, damping describes the
instrument’s performance in the way a pointer or
indicator settles into a steady indication after a
change in the value of the measured quantity.
33

34. • A response is not damped at all, oscillation
continues.
• A response is underdamped or periodic, as is the
case when overshoot occurs.
• A response is overdamped or aperiodic, when the
response is slower than an ideal or desired
condition.
• A response is critically damped, when the
response represents an ideal or desired condition.
34

35. Measurement Terminology
Range
It is defined as the region between the limits
within which a quantity is measured, received,
or transmitted, expressed by stating the lower
and upper range values.
35

36. Upper Range Value (URV) is defined as the highest
quantity that an instrument is adjusted to measure.
Lower Range Value (LRV) is defined as the lowest
quantity that an instrument is adjusted to measure.
Upper Range Limit (URL) is defined as the maximum
acceptable value that a device can be adjusted to
measure.
Lower Range Limit (LRL) is defined as the minimum
acceptable value that a device can be adjusted to
measure.
36

37. 37

38. Rangeability is the ratio of the maximum
measurable value to the minimum measurable
value.
Turndown is defined as the ratio of the normal
maximum measured variable through the
measuring device to the minimum controllable
measured variable.
In a conventional differential pressure transmitter,
if the maximum pressure is 7.45 kPa and the
minimum pressure is 1.24 kPa, the span turndown
is 6 to 1 (6:1).
38

39. These terms are often interchanged, confused and
misunderstood.
39

40. 40

41. 41

42. Zero Elevation Range is defined as a range where
the zero value of the measured variable is greater
than the lower range value.
The zero value can be between the lower range
value and the upper range value, at the upper range
value, or above the upper range value.
42

43. Zero Suppression Range is defined as a range
where the zero value of the measured variable is
less than the lower range value.
In that case, the zero value does not appear on the
range scale.
43

44. 44

45. Response Time is defined as the time taken for the
system output to rise from 0% to the first crossover
point of 100% of the final steady state value.
45

46. Accuracy is sometimes referred to as the maximum
uncertainty or limit of uncertainty.
In practical terms, accuracy qualitatively represents the
freedom from mistake or error.
In metrological terms, accuracy represents the degree
of conformity of an indicated value to an accepted
standard value, or ideal value.
46

47. Precision is confused with accuracy.
Precision, by definition, is the reproducibility with
which repeated measurements of the same measured
variable can be made under identical conditions.
47

48. 48

49. 49

50. Reproducibility is the same as precision.
The close agreement among repeated
measurements of the output for the same value
input that are made under the same operating
conditions over a period of time, approaching from
both directions.
If the measuring instrument is given the same
inputs on a number of occasions and the results lie
closely together, the instrument is said to be of high
precision.
50

51. Repeatability
It is same as reproducibility except that
repeatability represents the closeness of agreement
among a number of consecutive measurements of
the output for the same value of input under the
same operating conditions over a period of time
(approaching from the same direction).
51

52. Linearity is the closeness to which a curve
approximates a straight line.
Independent Linearity
Terminal Linearity
Zero-based Linearity
52

53. Hysteresis
53

54. Deadband
54

55. Drift
It represents an undesired slow change or
amount of variation in the output signal over a
period of time (days, months, or years), with a
fixed reference input.
55

56. Zero Drift represents drift with zero input signal.
In practical terms, the zero of the measuring
instrument shifts.
In a mechanical instrument, it is usually caused by a
slipping linkage. The correction is to re-zero the
instrument.
In an electronic instrument, zero shift is usually caused
by environmental changes. The correction is to re-zero
the electronic instrument.
56

57. Span Drift represents drift or gradual change in
calibration as the measurement moves up the scale
from zero.
In a mechanical instrument, it is usually caused by
changes in the spring constant of the instrument, or by
the linkage.
In a electronic instrument, span shift is usually caused
by changes in the characteristics of a component.
The correction can be to adjust the span of the display
element.
57

58. Partial Drift represents drift on only a portion of the
instrument’s span.
In a mechanical instrument, it is usually caused by an
overstressed part of the measuring instrument.
In an electronic instrument, partial shift is usually
caused by drift in an electronic component.
The correction is periodic inspection and calibration.
58

59. Reliability
•It represents a measuring device’s ability to perform a
measurement function without failure over a specified
period of time or amount of use.
•Usually reliability data is extrapolated.
•Reliability is often expressed as (MTTF) specification.
•After failure, repair must take place.
MTTF + MTTR = MTBF
59

60. Overview of Typical Design Criteria
Process measurement suppliers tend to follow several
rules when designing equipment to achieve reliability.
• Keep the design simple,
• Avoid using glass as a structural material,
• Keep electronics cool as possible,
• Provide easy serviceability.
60

61. • Housing
• Metals
• Gasket Considerations
• Seal Considerations
• Associated Hardware Options
• Process Connections Options
• Installation Orientation
• Effects of Vibration
• Environment and Hardware Materials
61

62. Environment and Hardware Materials
• Reliability
• Quality
• Accuracy
• Cost
• Repeatability
• Previous acceptance
• Availability of spares
• Compatibility with existing equipments
• Flexibility of use
• Compatibility with the environments
• Ease of maintenance
• Ease of operation
• Application suitability
62

63. Electrical design and instrument
loop wiring considerations
• Power Requirements
• Power Consumption
• Wiring Terminations
• Output Signal
• RFI Effects
• Grounding of Instruments
• Shielding Considerations
• Lightning Protection
63

64. SAFETY CONSIDERATIONS
• limiting the energy level
• keeping sparks away from flammable mixtures
• containing an explosion
• diluting the gas level
• protecting against excessive temperature
• Probability that a hazardous gas is present
• Quantity of a hazardous gas
• Nature of the gas (is it heavier or lighter than air)
• The amount of ventilation
• The consequences of an explosion
64

65. 65

66. 66

67. • Pressure values themselves are essential data
for monitoring.
• Often, the values of process variables other
than pressure are derived from (inferred from)
the values that are measured for pressure.
67

68. Properties of Matter in Relation to Pressure
Measurement
68

69. Pressure Equation
•Pressure is defined as the amount of force per unit
area.
P =F/A
where:
P = pressure
F = force =ma
A = area
69

70. Gauge, Absolute, Differential, and Vacuum
70

71. Pressure Measuring Devices
Categories of pressure measuring devices :
• Gravitational gauges
• Deformation sensors and switches
• Transducers and transmitters
71

72. Gravitational Gauges
72

73. Deformation (Elastic) Sensors and Switches
Bourdon Tube
73

74. 74

75. Advantages
• They are available in a wide variety of pressure ranges.
• They are proven and suitable for many pressure
applications.
• They have good accuracy.
Disadvantages
• Vibration and shock could be harmful to mechanical
linkage.
• They are susceptible to hysteresis as they age.
75

76. Diaphragm
Bellows
76

77. Other Types of Deformation Sensors
77

78. Pressure Transducer
•It is a device that provides an electrical output signal that is
proportional to the applied process pressure.
•The output signal is specified as either a volt, current, or
frequency output.
A pressure transducer always consists of two elements:
 A force summing element, such as a diaphragm, converts
the unknown pressure into a measurable displacement or
force.
 A sensor, such as a strain gauge, converts the displacement
or force into a usable, proportional output signal.
78

79. Strain Gauge
•The sensor changes its electrical resistance when it
stretches or compresses.
79

80. Potentiometer Element
80

81. Capacitive Sensor
81

82. Performance Advantages
• They have good rangeability and response time.
• They have very good accuracy.
Typical accuracies are about 0.1% of reading or 0.01 % of
full scale.
• Typical transducers support a very wide pressure range.
• High vacuum and low differential pressure ranges are
supported.
82

83. Inductance-Type Transducer
•Changing the spacing between two magnetic devices causes a
change in the reluctance.
•The change in reluctance then represents the change in pressure.
•One type of reluctance pressure transducer is the linear variable
differential transformer (LVDT).
83

84. Piezoelectric Gauge
•Materials that create an electrical voltage when a force is
applied.
•They measure rapidly changing pressures.
84

85. Performance Advantages
• They provide a self generated output signal.
• They have high speed of response.
• They have good accuracy, about 1% of full
scale is typical.
85

86. Design of Pressure Transmitters
86

87. Meter Body Designs
87

88. Transmitter Process Locations
88

89. 89

90. 90

91. 91

92. Purpose of Flow Measurement
•Monitor and control the flow rates.
•Develop material and energy balances.
•Sustain the efficiency and to minimize
waste.
92

93. Importance of Accurate
Measurement
• Material balances in separation processes.
• Pumps and compressor operations.
• Custody transfer operations.
93

94. Flowmeter Definition
A flowmeter is defined as “A device that
measures the rate of flow or quantity of a
moving fluid in an open or closed conduit”.
It usually consists of a primary device and a
secondary device.”
94

95. Primary Device
It is defined as “The device mounted internally
or externally to the fluid conduit that produces a
signal with a defined relationship to the fluid
flow in accordance with known physical laws
relating the interaction of the fluid to the
presence of the primary device.”
95

96. Secondary Device
It is defined as “The device that responds to the
signal from the primary device and converts it to
a display or to an output signal that can be
translated relative to flow rate or quantity. ”
96

97. 97

98. Some Drawing Symbols
98

99. General Categories
of Flow Instruments
Flow instrument categorization often varies.
1. Rate or quantity type.
2. Energy usage type.
99

100. 1a. Rate meters
•They are the most common classification of
flowmeters.
•Rate meters measure the process fluid’s
velocity.
•Because a pipe’s cross sectional area is known,
the velocity is then used to calculate the flow
rate.
100

101. A rate meter can either infer the flow rate or
measure the velocity of the flowing fluid to
determine the flow rate.
•In differential pressure flowmeter, the flow
rate is inferred from the measured
differential pressure.
•In turbine meter, the velocity of the fluid
times the area is used to determine the flow
rate.
101

102. 1b. Quantity meters
•They divide the flowing material into
predetermined volume segments.
•Quantity meters count and keep track of the
number of these volume segments.
•An example of a quantity meter is a positive
displacement meter.
102

103. Meters that directly measure mass can also
be considered either as
 a quantity meter or as
 a mass flow rate meter.
103

104. 104

105. 2. Energy Approach
A. Extractive Energy
•Flowmeters take energy from the fluid
flow.
•An orifice plate is an example of an
extractive-type.
105

106. B. Additive Energy
•Flowmeters introduce some energy into
the fluid flow.
•A magnetic flowmeter is an example of an
additive type.
106

107. Volumetric Flow Rate
•It represents the volume of fluid that passes a
measurement point over a period of time.
•The calculation is based on the formula:
Q=Axv
where
Q = volumetric flow rate
A = cross-sectional area of the pipe
v = average flow velocity (flow rate)
107

108. Mass Flow Rate
•It represents the amount of mass that passes a specific
point over a period of time.
•The calculation is based on the formula:
W=Qx
where
W = mass flow rate
Q = volumetric flow rate
 = density
108

109. Units of Measure
109

110. Meter Run
•It is defined as “The upstream and downstream length
of pipe containing the orifice flanges and orifice plate or
orifice plate with or without quick change fittings.”
•No other pipe connections should be made within the
normal meter tube dimensions except for pressure taps
and thermowells.
•The meter tube must create an acceptable flow pattern
(velocity profile) for the fluid when it reaches the orifice
plate.
110

111. 111

112. Flow Straighteners (conditioners)
•They help to provide accurate measurement when a
distorted flow pattern is expected.
•They are installed in the upstream section of meter tube.
•They reduce the upstream meter tube length
requirement.
112

113. 113

114. Compressible versus
Incompressible Flow
•Temperature and pressure changes cause the volume
of a fluid to change.
•The change in volume is much more extreme in gases
than in liquids.
•For accurate gas flow measurements, the
compressibility factor is included in the measurement.
z =PV/nRT
114

115. 115

116. Viscosity
116

117. •Viscosity is frequently described as a fluid’s resistance
to flow.
•It have a dramatic effect on the accuracy of flow
measurement.
•Resistance to flow occurs because of internal friction
between layers in the fluid.
•Water, for example, having low viscosity has less
resistance to flow.
117

118. •When a fluid is in motion, layers of fluid are
subject to tangential shearing forces, causing the
fluid to deform.
•Fluid’s low viscosity does not become an
influential property of the fluid upon flow
measurement.
•However, when measuring the flow rate of a
fluid with high viscosity, the viscosity does
become an influential property in flow
measurement.
118

119. Viscosity is often expressed in terms of the
following:
• Dynamic viscosity
• Kinematic viscosity
• Viscosity index
• Viscosity scales
119

120. Dynamic Viscosity (Absolute Viscosity)
•It represents a fundamental viscosity measurement of a
fluid.
•Density of fluid does not play a part in the viscosity
measurement.
•Absolute viscosity is a ratio of applied shear stress to
resulting shear velocity.
•The measurement units for dynamic (absolute) viscosity
are centipoise, Pascal-seconds, or lb/ft-second.
120

121. •One method to measure viscosity is to rotate a
disk in the fluid at a particular rotational speed.
•The rotational torque required to keep the disk
rotating divided by the speed of rotation and by
the disk contacting surface area is a measure of
absolute viscosity.
•Another viscosity measurement that can be used
for liquids and gases is the falling sphere
viscometer.
121

122. Rotational and Falling Sphere Viscometers
122

123. Kinematic Viscosity (n)
•It represents a ratio of dynamic (absolute) viscosity to the
density of the fluid and is expressed in stokes (n = m / r).
•In liquids, an increasing temperature usually results in
lowering the kinematic viscosity.
•In gases, an increasing temperature increases the
kinematic viscosity.
•The measurement units for kinematic viscosity are either
centistokes, meter2/second, or ft2/second.
123

124. 124

125. •The method for determining kinematic viscosity
involves measuring the time to drain a certain
volume of liquid by gravity out of a container
through a capillary tube or some type of restriction.
•The time it takes to drain a liquid is directly related
to viscosity.
•The flow rate of fluids by gravity, which is the force
causing the flow, depends upon the density of the
fluids.
125

126. Ostwald Capillary Viscometer
126

127. Viscosity Index
•It represents the change in viscosity with respect
to temperature.
•It is used with reference to petroleum products.
•A high viscosity index number means that the
fluid’s viscosity does not change very much for a
given temperature, and vice versa.
127

128. Viscosity Scales
•It represents viscosity measurements in time units.
•Commonly used viscosity scales include the following:
oSaybolt Furol scales
oRedwood scales
oEngler scales
•The three scales express kinematic viscosity in time
units rather than centistokes.
128

129. •For example, if the kinematic viscosity of a fluid at 122°
F is 900 centistokes, on the Saybolt Furol scale the
equivalent viscosity is expressed as 424.5 seconds
(centistokes x 0.4717).
•Flow engineering reference manuals often provide
conversion formulas between centistokes and the
respective viscosity scale.
129

130. 130

131. Basic Hydraulic Equations
131

132. 132

133. Bernoulli Equation
P = Static Pressure (pounds force per sq. ft)
r = Density (rho) (pounds mass per cubic ft)
v = Velocity (feet per second)
g = Acceleration of Gravity (feet per second2)
Z = Elevation Head Above a Reference Datum (feet)
133

134. 134

135. Continuity Equation
The Equation of Continuity states that the volumetric
flow rate can be calculated by multiplying the cross
sectional area of the pipe at a given point by the
average velocity at that point.
Q=Axv
where
Q = volume flow rate (cubic feet per minute)
A = pipe cross-sectional area (square feet)
v = average fluid velocity (feet per minute)
135

136. Reynolds Number
It is a major distinctive quality of fluid flow
as
The ratio of Inertial Forces to Viscous
Forces.
136

137. 137

138. 138

139. •Laminar flow is defined by low Reynolds
numbers with the largest flowing fluid
moving coherently without intermixing.
•Turbulent flow is defined by high Reynolds
numbers with much mixing.
139

140. •Turbulent flow is best when high heat transfer is
wanted,
•while laminar flow is best when flowing fluid is to be
delivered through a pipe with low friction losses.
•Flow is considered laminar when the Reynolds number
is below 2,000.
•Turbulent flow occurs when the Reynolds number is
above 4,000.
•Between these numbers, the flow characteristics have
not been defined.
140

141. 141

142. 142

143. Newtonian versus
non-Newtonian Fluids
In Newtonian fluids, the resistance to deformation
when subjected to shear (consistency of fluid) is
constant if temperature and pressure are fixed.
Whereas in a non-Newtonian fluid, resistance to
deformation is dependent on shear stress even
though the pressure and temperature are fixed.
143

144. Hagen-Poiseuille Law
•It defines viscosity in more practical terms.
•Newton’s definition of viscosity is the ratio of
shear stress divided by shear rate.
•Hagen-Poiseuille defines it as the ratio of shear
stress divided by shear rate at the wall of a
capillary tube.
144

145. Rheograms
•It can be used to determine the characteristics of any fluid.
•Rheograms evolved from the science of rheology, which
studies flow.
•(“Rheo,” derived from the Greek language, means “a
flowing.”)
•Rheograms are useful as an aid to interpret viscosity
measurements.
145

146. Newtonian Fluids
•It exhibits the constant ratio of shear stress to shear rate (flow
velocity) when subjected to shear and continuous deformation.
•When a fluid’s temperature is fixed, the fluid exhibits the
same viscosity through changing shear rates. Viscosity is not
affected by shear rate (flow velocity).
•The relationship is linear between the shear stress (force) and
velocity (resulting flow).
•Newtonian fluids are generally homogeneous fluids. Gasoline,
kerosene, mineral oil, water and salt solutions in water are
examples of Newtonian fluids.
146

147. Non-Newtonian Fluids
•Fluids that do not show a constant ratio of shear stress to
shear rate are defined as non-Newtonian fluids.
•Fluids exhibit different viscosity at different shear rates.
•In non-Newtonian fluids, there is a nonlinear relation between
the magnitude of applied shear stress and the rate of angular
deformation.
•Non-Newtonian fluids, which have different classifications,
tend to be liquid mixtures of suspended particles.
•Thick hydrocarbon fluids are considered non-Newtonian
fluids.
147

148. 148

149. 149

150. FLOW MEASURING DEVICE
SELECTION CRITERIA
• Application fundamentals
• Specifications
• Safety considerations
• Metallurgy
• Installation considerations
• Maintenance and calibration
• Compatibility with existing process instrumentation
• Custody transfer concerns
• Economic considerations
• Technical direction
150

151. Application Fundamentals Flowchart
151

152. Application Fundamentals
Checklist of Selection Criteria
• Flow stream conditions:
– volume
– temperature
– pressure
– density
– viscosity
– flow velocity
• Flow measurement goals.
• Accuracy requirements.
• Range requirements.
• Acceptable pressure drops.
• Display and system requirements.
• Potential problems (i.e., vibration).
• Flow stream erosive/corrosive materials, entrained gases and solids (if any).
• Available installation space and pipe geometry.
• Economic factors (cost of ownership).
152

153. Flowmeter Applications
153

154. Flowmeter Applications (Continued)
154

155. Providing Protection to the Flowmeter
Isolation Valves
Strainers
De-aerators
155

156. •Strainers are used to protect meters from debris in a
liquid stream.
•Strainers are not intended for filtering a liquid.
•Strainers should be carefully selected to ensure that they
have a low pressure drop when used with high velocity
flowmeters.
156

157. •Deaerators are air elimination devices that protect the
meter from receiving a large slug of air.
•The air elimination device separates that air from the
liquid through the use of special baffles.
•In the case of some positive displacement meters, a large
slug of air can completely damage the meter.
•In the case of a turbine meter, air may not cause
damage, but will cause errors in readings (registrations).
157

158. •Isolation Valves are typically provided at a meter inlet to
permit meter repairability without shutting down the
process.
•Block and Bleed Valves are used in meter runs to
provide a means for calibration. These valves divert the
flow to the meter prover loop.
•Control Valves provide a means of controlling flowrate
and/or back pressure.
•For example, flowrate control is necessary to prevent a
positive displacement meter from over-speeding.
158

159. Typical Maintenance Concerns by Flowmeter Type
159

160. Accuracy Reference
•Accuracy is measured in terms of maximum positive
and negative deviation observed in testing a device
under a specified condition and specified procedure.
•The accuracy rating includes the total effect of
conformity, repeatability, dead-band, and hysteresis
errors.
•An accuracy reference of simply “2%” is incomplete.
160

161. Percent of Rate Accuracy: It applies to meters such as turbine meters, DC
magnetic meters, vortex meters, and Coriolis meters.
Percent of Full Scale Accuracy: It refers to the accuracy of primary meters such
as rotameters and AC magnetic meters.
Percent of Maximum Differential Pressure: It applies to differential pressure
flow transmitters.
161

162. Totalization
•It represents the process of counting the amount of
fluid that has passed through a flowmeter.
•Its purpose is to have periodic (daily or monthly)
readings of the material usage or production.
•The totalization data is used for billings for material
usage or production.
162

163. Multivariable Transmitters
163

164. •In measuring flow, temperature is required to
compensate for changes in density.
•A multivariable transmitter is essentially four
transmitters in one package.
•A multivariable transmitter measures differential
pressure, absolute pressure, and process temperature.
•The multivariable transmitter also calculates the
compensated flow.
•Traditionally, three separate transmitters and flow
calculation were required for this measurement.
164

165. •The multivariable transmitter incorporates
microprocessor based technology which provides the
advantages of better readability and tighter
integration.
•Additionally, the multivariable transmitter reduces
installation costs, spares inventories, and
commissioning times.
•The transmitter has the flexibility to be used in
applications such as custody transfer, energy and
material balances, and advanced control and
optimization.
165

166. 166

167. Custody Transfer
167

168. 168

169. •Flow measurement for custody transfer, where
ownership of a product transfers, is on occasion
regarded as a separate flow measurement topic.
•There are two types of custody transfer in flow
measurement:
1. Legal, which falls under weight and measure
requirements.
2. Contract, which is a mutual agreement between
seller and buyer.
169

170. In process control applications, the accuracy
requirement may be several percent,
but for custody transfer operations the accuracy
requirement may be in tenths of a percent.
170

171. Custody Transfer Concerns
• Reasons for metering hydrocarbons.
• Classifications of custody transfer
measurements.
• Meter provers required.
171

172. Reasons for Metering Hydrocarbons
In typical oil processing plants, liquid hydrocarbons are
metered at each custody transfer point and often at points
where custody does not change.
Several reasons for the metering are:
• Corporate accounting requires data.
• Billing is dependent upon accurate measurements.
• Losses are detectable.
• Business decisions are based on the measurement data.
• Assist negotiations, if necessary
• Provide auditable, historical records.
172

173. Classification of Custody Transfer Measurements
•For a custody transfer measurement of a liquid
hydrocarbon, a contract requires a volumetric measurement
at standard conditions of temperature and pressure.
•The techniques to do this are broadly categorized as “static”
and “dynamic.”
•Static measurements are accomplished through automatic
tank gauging.
•Dynamic measurements are accomplished through liquid
metering methods.
173

174. 174

175. 175

176. 176

177. Meter Provers Required
•Any flowmeter’s indication of a volume
represents an unknown volume unless the
volume can be compared to a known
volume.
The known volumes are called
“meter provers”
177

178. For a meter to be considered accurate, the
meter must be proved at the same
conditions of flowrate, temperature
pressure, and product viscosity.
178

179. 179

180. FLOW METER CALIBRATION:
IMPORTANCE AND TECHNIQUES
•Calibration is typically performed in a laboratory
setting at several different flow rates, and uses
conditions such as changing densities, pressure,
and temperatures.
•Proving differs from calibration in that it is done
in the field, typically under a single set of
conditions.
180

181. The calibration can be defined as the
comparison of a measuring instrument with
specified tolerance but an undetermined
accuracy, to a measurement standard with
known accuracy
181

182. •The use of non-calibrated instruments creates
potentially incorrect measurement and erroneous
conclusions and decisions.
•It is calibration that:
provides assurance and confidence in
measurement.
maintains product in specified ranges.
182

183. •Calibration can be a simple dimensional check to
detect measurement variables.
•Before starting calibration, a decision must be
made for the following:
Which variables should be measured.
What accuracy must be maintained.
183

184. Some element of error exists in all measurements
no matter how carefully they are conducted.
The magnitude of the error can never be easily
determined by experiments;
the possible value of the error can be calculated.
184

185. Method of Calibrations
In general the flow measurement devices are calibrated
by three methods:
• Wet calibration uses the actual fluid flow.
• Dry calibration uses flow simulation by means of an
electronic or mechanical signal.
• A measurement check of the physical dimensions and
use of empirical tables relating flow rate to these
dimensions is another form of calibration.
185

186. Wet Calibration
•It uses actual fluid flow.
•Generally it provides high accuracy for a flowmeter
and is used when accuracy is a prime concern.
•Precision flowmeters are usually wet calibrated at
the time of manufacture.
•Wet calibration for flowmeters is usually performed
with water, air, or hydrocarbon fuels.
186

187. Dry Calibration
•It is performed on a flowmeter without the
presence of a fluid medium.
•The input signal is Hz, mV, or P.
•It is much more uncertain than wet calibration.
•The overall accuracy of the flow device is
inferred because the flow transducer is bypassed.
187

188. •The input signal for a dry calibration must
be provided by a measurement standard.
•The value of the output signal requires use
of other measurement standard.
•Follow the manufacturer’s guideline and
procedures for dry calibration.
188

189. Provers
•The proving operation verifies the meter’s
performance and assurance.
•The necessity for proving depends on how accurate
the measurement must be for the product being
handled.
•Prover is considered part of the metering station’s
cost and is permanently installed at the facilities.
•For low value products, portable provers are used.
189

190. Methods of Meter Proving
•Pipe provers are one of the most common
types of provers in industry today.
•The process does not have to be shut down
when proving a meter.
•Two types of pipe provers:
Unidirectional prover,
Bidirectional prover.
190

191. Unidirectional Provers
•It displaces a known volume by means of a
displacer traveling in only one direction inside
the prover.
•The displacer’s travel is detected by detector
switches within the prover.
191

192. 192

193. Bidirectional Provers
•It requires a displacer to travel in both directions
to complete one prover run.
•After stabilizing pressure and temperature, the
displacer is put into the system.
•It will slow down flow in the system for a time
until the displacer picks up speed.
193

194. 194

195. Small Volume Provers
•They can accommodate a wide range of flow
rates.
•They are compact in size and have less volume
than conventional unidirectional and
bidirectional pipe provers.
•The time to obtain a meter factor is significantly
decreased.
195

196. Master Meter Method
•It is used when a pipe prover is unavailable.
•The master meter method uses a known reliable
meter configured in series with the meter to be
proved.
•The meter measurements are then compared.
196

197. Weight and Volume Methods
•Static calibration
•Dynamic calibration
197

198. Static Calibration
•The flow is quickly started to begin the test, held
constant during the test, and then shut off at the
end of the test.
•The totalized flow reading from the flowmeters is
compared with the weight or volume collected and
the performance of the meter is calculated.
•The static calibration system operates best with
flowmeters that have low sensitivity to low flow
rates.
198

199. Dynamic Calibration
•The flow is kept at a constant rate before the
beginning of the test.
•The flow reading from the flow meter and initial
weight or volume are read together to start the test
and after the desired collection period to end the
test.
•The dynamic calibration systems are limited by the
meter’s speed of the response.
199

200. 200

201. 201

202. 202

203. Basic Equations
203

204. As long as the fluid speed is sufficiently subsonic
(V < mach 0.3),
the incompressible Bernoulli's equation
describes the flow reasonably well.
204

205. 205

206. •It is recommended that location 1 be positioned
one pipe diameter upstream of the orifice, and
location 2 be positioned one-half pipe diameter
downstream of the orifice.
206

207. •For flow moving from 1 to 2, the pressure at 1
will be higher than the pressure at 2;
•the pressure difference as defined will be a
positive quantity.
207

208. •From continuity, the velocities can be replaced
by cross-sectional areas of the flow and the
volumetric flowrate Q,
208

209. •Solving for the volumetric flowrate Q gives,
209

210. •For real flows (such as water or air), viscosity
and turbulence are present and act to convert
kinetic flow energy into heat.
•To account for this effect, a discharge coefficient
Cd is introduced into the above equation to
marginally reduce the flowrate Q,
210

211. •Since the actual flow profile at location 2
downstream of the orifice is quite complex,
•thereby making the effective value of A2
uncertain, the following substitution introducing
a flow coefficient Cf is made,
•where Ao is the area of the orifice.
211

212. •As a result, the volumetric flowrate Q for real
flows is given by the equation,
212

213. •The flow coefficient Cf is found from experiments
and is tabulated in reference books;
•It ranges from 0.6 to 0.9 for most orifices.
•Since it depends on the orifice and pipe diameters
(as well as the Reynolds Number), one will often
find Cf tabulated versus the ratio of orifice
diameter to inlet diameter, sometimes defined as,
213

214. Most Common P flowmeters
• Orifice plates
• Venturi
• Flow nozzles
• pitot tube / annubar
• Elbow or wedge meter
214

215. Meter Tube Assembly Example
215

216. Orifice Plate
•It is the main element within an orifice meter
tube.
•It is the simplest and most economical type of
all differential pressure flowmeters.
•It is constructed as a thin, concentric, flat metal
plate.
•The plate has an opening or “orifice.”
216

217. •An orifice plate is installed perpendicular to the
fluid flow between the two flanges of a pipe.
•As the fluid passes through the orifice, the
restriction causes an increase in fluid velocity and
a decrease in pressure.
217

218. •The potential energy (static pressure) is
converted into kinetic energy (velocity).
•As the fluid leaves the orifice, fluid velocity
decreases and pressure increases as kinetic
energy is converted back into potential energy
(static pressure).
218

219. Orifice plates always experience some energy
loss – that is, a permanent pressure loss caused
by the friction in the plate.
219

220. The Beta ratio is defined as the ratio of the
diameter of orifice bore to internal pipe
diameter.
<1
220

221. •The most common holding system for an orifice
plate is a pair of flanges, upstream and
downstream piping, and a pressure tap.
•The pressure taps are located either on orifice
flanges or upstream and downstream of the pipe
from the orifice plate.
221

222. •For precise measurement, various types of
fittings are used:
 junior fittings,
 senior fittings, and
 simplex fittings.
222

223. The fittings provide:
•easy installation of an orifice plate,
•removal of the plate for changes in flow rate
services, and
•convenient removal for inspection and
maintenance.
223

224. Senior Orifice Fitting
•It is a dual-chamber device that reigns as the
most widely used means of measurement for
natural gas.
224

225. Simplex Orifice Plate Holder
It is a single-chamber fittings that house and
accurately position an orifice plate for differential
pressure measurement.
225

226. Junior Orifice Fitting
•It is a single-chamber fitting, engineered and
manufactured to make orifice plate changing
quick and easy at installations where line
movement from flange spreading is undesirable.
226

227. 227

228. 228

229. Limitations of orifice plates include a high
irrecoverable pressure and a deterioration in
accuracy and long term repeatability because of
edge wear.
229

230. •Two types of orifice plates designs are
available:
•Paddle type and
•Universal type.
230

231. The paddle type orifice plate
•It is used with an orifice flange, has a handle for
easy installation between flanges.
•On the paddle type plate, the orifice bore,
pressure rating (flange rating), bore diameter,
Beta ratio, and nominal line size are stamped on
the upstream face of the plate.
•The outside diameter of a paddle plate varies
with the ANSI pressure rating of the flanges.
231

232. The universal orifice plate
•It is designed for use in quick change fittings.
•The universal plate is placed in a plate holder,
the outside diameter is the same for all pressure
ratings for any given size.
•When using orifice fittings, the internal
diameter of the meter tube must be specified
because the orifice plate is held in an orifice
plate sealing unit.
232

233. 233

234. Weep Hole
•Some orifice plates have a small hole in the
orifice plate besides an orifice bore either
 above the center of the plate, or
 below the center of the plate.
234

235. The purpose of the weep hole is to allow the:
passage of any condensate in a gas application
or
passage of gas in liquid service applications.
235

236. •The area of the weep hole must be considered
when sizing an orifice plate.
•An orifice plate with a weep hole should not be
used when accurate measurement is required in a
flow measurement application, such as in gas
sales service.
236

237. Concentric Orifice Plate
237

238. The orifice plate, although a relatively simple
element, is a precision measuring instrument and
should be treated accordingly.
238

239. •Critical items considered when evaluating orifice
plates are the following:
• Flatness, smoothness, and cleanliness of
the orifice plate.
• The sharpness of the upstream orifice
edge.
• The bore diameter and thickness of the
orifice plate.
239

240. Orifice Plate Dimensions
• d represents the bore of the orifice plate.
• D represents the pipe inside diameter.
• Dam height represents the difference of pipe inner diameter and diameter of bore
divided by 2.
• T represents the thickness of the plate.
• e represents the orifice plate bore thickness which is 1/2 T
•  is called orifice plate bevel angle. It is 45 °, +20 ° 0°.
240

241. •Several types of orifice bore designs are
available for orifice plates:
 Concentric,
 Segmental, and
 Eccentric orifice plates.
•The plates are used for a wide range of
applications.
241

242. Types of Orifice Plates
242

243. Concentric Plates
•The concentric orifice bore plates are used in
general flow measurement applications.
•The concentric orifice plate has an orifice bore
in the center of the plate.
•The concentric bore plate is used for clean fluid
services, as well as for applications requiring
accurate flow measurement.
243

244. •The center of bore is either
beveled or
straight.
•The beta ratio for the concentric plate is
between 0.1 to 0.75.
244

245. Eccentric Plates
•It is similar to a concentric plate, but the
eccentric plate has the bore in an offset position.
•The eccentric orifice plate is used when dirty
fluids are measured, to avoid the tendency of
hole plugging if a concentric plate were used.
•Flow coefficient data is limited for eccentric
orifices; therefore, it provides less accurate
measurement.
245

246. 246

247. •In an eccentric orifice plate, the hole is bored
tangent to the inside wall of the pipe or, more
commonly, tangent to a more concentric circle
with a diameter not smaller than 98% of the
pipe’s internal diameter.
•When lacking specific process data for the
eccentric orifice plate, the concentric orifice plate
data may be applied as long as accuracy is not a
major issue.
247

248. • Make sure that flanges or gaskets do not
interfere with the plate hole.
•The line size ranges from 4” to 14”.
•It can be made smaller than a 4” as long as the
orifice bore does not require a beveling edge.
•Beta ratio is limited between 0.3 to 0.8.
•Flange taps are recommended for eccentric
orifice plate installations.
248

249. Segmental Plates
•It looks like a segment of a circle with
segmented circle hole in offset from the plate’s
center.
•The orifice hole is bored tangent to the inside
wall of the pipe or tangent to a more concentric
circle with a diameter not smaller than 98% of
the pipe internal diameter.
•Installation is similar to eccentric type.
249

250. Quadrant Edge Plate
•It is used for lower pipe Reynolds numbers
where flow coefficients for sharp-edge orifice
plates are highly variable.
•It is used for viscous clean liquid applications.
•Nominal pipe size ranges between 1” to 6”.
250

251. Orifice Plate Parameters
(1) Orifice flow rate.
(2) Pipe line size and pressure rating.
(3) Thickness of orifice plate.
(4) Orifice Bore (d).
(5)Orifice plate holders: The orifice plate holder includes
orifice flanges, orifice fittings.
(6) Beta Ratio.
(7) Differential Pressure (P).
(8) Temperature.
(9) Reynolds Number (Re).
(10) Pressure taps.
251

252. Pressure Taps
252

253. 253

254. Flange Taps
•Holes drilled into a pair of flanges.
•Flange tap holes are not recommended when
the pipe size is below 2 inches.
254

255. Pipe Taps
•Pipe taps are located at 2.5 D upstream and 8 D
downstream from the orifice plate.
• Exact location of the taps is not critical.
•However, the effect of pipe roughness and
dimensional inconsistencies can be severe.
255

256. The uncertainty of measurement is 50 % greater
with full flow taps than with taps close to the
orifice.
Pipe taps are not normally used unless it is
required to install the orifice meter on a existing
pipe, or other taps cannot be used.
256

257. Corner Taps
•Corner taps are a style of flange taps.
•The only difference between corner and flange
taps is that the pressure is measured at the
corner between the orifice plate and the pipe
wall.
•Corner taps are used when the pipe size is 2“ or
less.
257

258. Vena Contracta Taps
•When an orifice plate is inserted into the
flowline, it creates an increase in flow velocity
and a decrease in pressure.
• The location of the vena contracta point is
between 0.35 to 0.85 of pipe diameters
downstream of the plate, depending on the beta
ratio and Reynolds number.
258

259. Pressure and Flow Profile
259

260. •Vena contracta taps are located 1D upstream and at the
Vena contracta location downstream.
•Vena contracta Taps are the optimum location for
measurement accuracy.
•They are not used for pipes less than 6” in diameter.
260

261. Liquid Service
Tap Locations – The pressure tap location in liquid
service orifice meters should be located to prevent
accumulation of gas or vapor in the connection
between the pipe and the differential pressure
instrument.
The differential pressure instrument should be close
to the pressure taps or connected through downward
sloping connecting pipe of sufficient diameter to
allow gas bubbles to flow back into the line.
261

262. Transmitter Installation – The installation of
differential pressure transmitters should be
located below the pipe and sloping upwards
toward the pipe to prevent the collection of gas
bubbles in the impulse tubing.
Vent Holes are required for venting of any gas in
a liquid service.
Location of the vent hole in a liquid service is at
the top of a pipe, above the center line.
262

263. Gas Services
Tap Locations – Pressure tap locations in a gas
service must be installed in the top of the line
with upward sloping connections towards a pipe.
The differential pressure measuring instrument
may be close-coupled to the pressure taps in the
side of the lines or connected through upward
sloping connecting pipe of sufficient diameter to
prevent liquid from accumulating in the line.
263

264. Transmitter Installation – The installation of
differential pressure transmitters should be
located above the pipe with the impulse tubing
sloping downward towards the pipe so that any
condensate drains into the pipe.
Drain Holes – A drain hole is required for draining
of any liquid in a gas service.
Location of the drain hole is below the center line
of the pipe.
264

265. Steam Services
Tap Locations require the use of condensing
chambers in steam or vapor applications because
condensate can occur at ambient temperatures.
Generally, the pressure tap connection has a
downward sloping connection from the side of
the pipe to the measuring device.
265

266. Transmitter Installation – The installation of
differential pressure transmitters should be
located above the pipe with the impulse tubing
sloping downward towards the pipe so that any
condensate drains into the pipe.
Drain Holes – A drain hole is required for draining
of any condensate liquid in a steam service.
The location of a drain hole is below the center
line of the pipe.
266

267. Standard Flow
•Flow measurement of a fluid stated in volume units at base
(standard) conditions of P and T is called standard flow.
•For crude petroleum and its liquid products, the vapor pressure is
<= than atmospheric pressure at base temperature of 14.696 psia
(101.325 kPa) at a temperature of 60°F (15.56°C).
•For a hydrocarbon liquid, when vapor pressure > atmospheric
pressure at base temperature, the base pressure is called
equilibrium vapor pressure.
•The base condition for natural gases is defined as a pressure of
14.73 psia (101.56 kPa) at a temperature of 60 °F (15.56°C).
267

268. Compensated Flow
•Compensated flow represents a flow under fluid conditions that
may vary.
•The conditions are measured and used along with flowmeter
signal to compute the true flow rate from the flowmeter.
•The output signal from a flowmeter represents the true flow rate
value under specified fluid conditions.
•For a liquid service, variations in density or viscosity can change
the meter’s accuracy.
•For gas services, a change in temperature, pressure, and
molecular weight can ruin the accuracy of the meter.
268

269. 269

270. Computer Programs for Sizing Orifice Plates
•ORICALC-2,
•EA-25,
•ORSPEC,
•FLOWEL,
•INSTRUCALC,
•ORIFICE2, and
•FLOW CONSTANT
270

271. http://www.pipeflowcalculations.com/orifice/
271

272. Common primary element errors:
• Beta ratio is too large for the meter run
• Orifice plate is not flat, it is concave or convex
• Orifice does not have sharp edges
• Orifice plate is installed backwards
• Orifice plate is damaged through poor handling
• An incorrect size is used for the orifice meter tube or plate
• Orifice plate is not centered in the line
• Orifice meter tube is corroded
• Tap locations are incorrect
• Contaminants build up on orifice plate
• Contaminants build up on meter run
• Hydrates build up on meter run and orifice plate
• Flow conditioners are dislodged and move closer to plate
• Leaks occur around orifice plate
• Pressure tap or thermowell installed upstream of meter
• Welding meter supports distorts meter run
272

273. Common secondary element errors:
• Gauge lines are too small
• Gauge lines are too long
• Gauge lines leak
• Gauge lines have sags or loops that collect condensates
• Gauge line slopes are not correct
• Incorrect ranges are used on secondary instruments
• Differential pressure transmitter was not zeroed properly
• Excessive dampening is used in secondary instrument
273

274. Other Differential Pressure Flowmeters
274

275. Flow Nozzles
•The flow nozzle is another type of differential-
producing device that follows Bernoulli’s
theorem
• The permanent pressure loss produced by the
flow-nozzle device is approximately the same as
the permanent pressure loss produced by the
orifice plates.
275

276. •The flow nozzle can handle dirty and abrasive
fluids better than can an orifice plate.
•In a flow nozzle with the same line size, flow
rate, and beta ratio as an orifice meter, the
differential pressure is lower, and the permanent
pressure loss is less.
276

277. Performance and Applications
•Changing a flow nozzle is more difficult than
changing an orifice plate when there is a change
in flow rate requirements.
•Flow nozzles are used for steam, high velocity,
nonviscous, erosive fluids, fluids with some
solids, wet gases, and similar materials.
277

278. •The flow nozzles pass 60% more flow than the
orifice plate of the same diameter and
differential pressure.
•A flow nozzle’s inaccuracy of ± 1% of rate is
standard with ± 0.25% of rate flow calibrated.
278

279. Typical Nozzle Installations
279

280. Venturi Meter
•A venturi design can be described as a restriction
with a long passage with smooth entry and exit.
•Venturi tubes produce less permanent pressure
loss and more pressure recovery than the other
meters.
•It is one of the more expensive head meters.
•Low pressure drops for non-viscous fluids.
280

281. 281

282. Venturi Designs
282

283. Performance Advantages:
• The long form venturi develops up to 89%
pressure recovery for a 0.75 beta ratio and
decreases to 86% recovery for a 0.25 beta ratio.
• The short form venturi develops up to 85%
recovery at 0.75 beta ratio and decreases to 7 %
at 0.25 beta ratio.
283

284. • A venturi meter has a low permanent pressure
loss and high recovery at higher beta ratios.
• A venturi meter can be used for dirty fluids and
slurries.
• Higher accuracy (better than orifice).
284

285. Performance Disadvantages:
• A venturi meter is a very expensive measuring
device to use.
• A venturi meter has limited rangeability and is
only installed when flow rate’s rangeability is less
than 3 to 1.
285

286. Pitot Tubes
•The previously discussed primary differential
pressure flow metering devices utilized the
difference in static pressure perpendicular to the
direction of flow as a basis for inferring velocity.
•The actual velocity was not measured, but was
calculated after many experimental laboratory
measurements and correlations.
286

287. •The Pitot tube measures a fluid velocity by
converting the kinetic energy of the flow into
potential energy.
•The conversion takes place at the stagnation
point, located at the Pitot tube entrance.
287

288. 288

289. •A pressure higher than the free-stream (i.e.
dynamic) pressure results from the kinematic to
potential conversion.
•This "static" pressure is measured by comparing
it to the flow's dynamic pressure with a
differential manometer
289

290. 290

291. 291

292. Performance Advantages:
• It creates very little permanent pressure drop and, as a
result, is less expensive to operate.
• A pitot tube can be installed on 4” and more.
• Performance of the pitot tube is historically proven.
• A pitot tube’s installation and operation costs are low.
• A pitot tube can be a standard differential producing
device for all pipe sizes.
292

293. Performance Disadvantages:
• Point-type pitot tubes require traversing the
flow stream for average velocity.
• Poor rangeability.
• Nonlinear square root characteristic.
• Difficulty of use in dirty flow streams.
293

294. Annubars
•The sensing points are arrayed along perpendicular
diameters with the number of points in each traverse
based upon the duct size.
294

295. 295 Annubar Design

296. Performance
• The diamond shape annubar has long term
accuracy.
• The annubar has an accuracy of ±1% of actual
flow and ±0.1 repeatability of the actual value.
• The annubar has low installation costs; a system
shutdown is not required to install the device.
296

297. • The annubar produces a repeatable signal even
when the run requirements are not met.
• The annubar flow sensor can handle a wide
range of flow conditions with two measuring
instruments.
• The annubar should not be used if the viscosity
approaches 50 centipoise.
• The annubar can be used on two phase flow
measurements.
297

298. Applications
•The annubar can be used for liquid and gas flow
measurement services.
•Generally, the annubar is used in clean liquid
services to avoid plugging.
•The annubar can be installed for low and
medium pressure applications without shutting
down the system.
298

299. Wedge Type Flowmeter
•The basic system consists of a cylindrical pressure
vessel into which a constriction "wedge" is
fabricated thereby leaving a open segment of a
known height.
299

300. •Pressure taps which receive the sensors on either side
of the "wedge" provide the differential signal to the
Flow Transmitter which is then related, by formula, to
the rate of flow occurring through the open segment.
300

301. Elbow Type Flowmeter
•A differential pressure
exists when a flowing fluid
changes direction due to a
pipe turn.
•The pressure difference
results from the centrifugal
force.
301

302. •Since pipe elbows exist in
plants, the cost for these
meters is very low.
•However, the accuracy is
very poor.
•They are only applied
when reproducibility is
sufficient and other flow
measurements would be
very costly.
302

303. 303

304. 304

305. 305

306. 306

307. 307

308. 308

309. Turbine Meters
Flowing fluid forces the turbine wheels to rotate
at a speed proportional to the velocity of the
fluid.
309

310. •For each revolution of the turbine wheel, a
pulse is generated.
•The rotational speed of shaft and frequency of
the pulse corresponds to the volumetric flow
rate through the meter.
310

311. K-factor
It is the number of pulses per unit of measurement
generated by the rotor as it turns inside the turbine.
It is usually indicted as Pulses per Gallon
311

312. 312

313. 313
Turbine Meter

314. Insertion Type Turbine Meter
314

315. Performance Advantages
• Excellent accuracy and good rangeability over the
full linear range of a meter.
• Low flow rate designs are available.
• Some versions do not require electrical power.
• Overall meter cost is not high.
• Output signal from the meter is at a high
resolution rate, which helps reduce meter proving.
315

316. Performance Disadvantages
• Sensitive to a fluids increasing viscosity.
• Two phase fluids can create usage problems.
• Straight upstream piping or straightening
vanes are required in a turbine meter installation
to eliminate the flow turbulence into the meter.
316

317. Electromagnetic
Flowmeters
317

318. Faraday’s Law states that emf is created when a
conductive fluid moves through a magnetic
field.
318

319. The axis of the conductive fluid flows at a right angle to
the magnetic field. Fluid flowing in this manner causes
a voltage that is proportional to the flow rate.
319 Magnetic Flowmeter Principles

320. •The voltage developed at the electrodes has an
extremely low level signal.
•A signal conditioner must amplify the signal.
•There are two types of magnetic flowmeters:
AC excitation, and
DC pulse excitation.
320

321. AC Excitation
•In an AC type magnetic flowmeter, line voltage (120 or 240
V AC) is applied directly to the magnetic coils.
•This generates a magnetic field in the outer body that varies
with the frequency of the applied voltage.
•An AC meter’s signal has a sine wave pattern.
•The magnitude of the sine wave is directly proportional to
the flow velocity.
•The system produces an accurate, reliable, fast responding
meter.
321

322. DC Pulse Excitation
•In a DC type magnetic flowmeter, line voltage is the
main source of power, but instead of applying it directly
to the coils, it is first applied to a magnet driver circuit.
•The magnet driver circuit sends low frequency pulses to
the coils to generate a magnetic field.
•The DC pulse system eliminates the zero shift problem
that occurs in an AC system.
322

323. 323

324. Performance Advantages
• It is non-obstructive and has no moving parts.
• Pressure drop is very little.
• DC pulse-type power can be as low as 15 to 20 watts.
• Suitable for acid, bases, water, and aqueous solutions.
• Lining materials provide good electric insulation and
corrosion resistance.
• The magnetic meter can handle extremely low flow.
• It can be used for bidirectional flow measurements.
.
324

325. Performance Disadvantages
• The meters only measure conductive fluid flows.
(Hydrocarbons, gases, and pure substances cannot be measured)
• Proper electrical installation care is required.
• Conventional meters are heavy and larger in size.
• Meters are expensive.
325

326. Installation
Proper magnetic flow meter operation is very
dependent upon the installation.
Installation considerations for a magnetic flowmeter
primarily involve the following:
• Meter orientation
• Minimum piping requirement
• Grounding
326

327. Magnetic Flowmeter Installation Practices
327

328. Applications
•It is suited for measurement of slurries and dirty fluids
because magnetic flowmeters do not have sensors that
enter the flowing stream of fluids.
•Magnetic flowmeters are not affected by viscosity or the
consistency of Newtonian or non-Newtonian fluids.
•The resulting change in flow profile caused by a change
in Reynolds number or upstream configuration piping
does not change the meter’s performance or accuracy.
328

329. Mass Flowmeters
(Coriolis Flowmeters)
•The mass of the fluid is measured as opposed to
the fluid volume or flow rate.
•A changing density or viscosity can affect the
performance of a volumetric flowmeter,
•While a mass flowmeter would not be affected
by these changes.
329

330. 330

331. 331

332. 332

333. •Coriolis meters can be used on liquid and some
gas applications.
•The direct measurement of mass is necessary
for applications where chemicals are balanced,
combustion efficiencies are calculated, or
production quantities must be consistent.
•If a measurement volume is desired, density
corrections are required to measure the fluid at
base conditions.
333

334. •A Coriolis force is caused by flowing fluid
through a tube. The Coriolis force equation is
equivalent to Newton’s Second Law of Motion,
where
334

335. •In Coriolis flowmeters, fluid typically flows
through an U-shaped tube that vibrates at its
natural frequency.
•As the fluid flows into the U-shaped tube, the
fluid is forced to conform to the vertical
momentum of the vibrating tube.
•If the U-shaped tube is moving upward during
its vibration, the fluid flowing into the U-shaped
tube resists and pushes downward.
335

336. 336

337. •The fluid has an upward momentum as it
approaches the part of the tube where it exit.
•If that portion of the tube has a downward
motion, the fluid resists the downward motion by
pushing up on the tube.
•The U-shape tube then twists. The twisting is
called the Coriolis effect.
•The amount of U-shaped tube twisting becomes
directly proportional to the mass flow rate.
337

338. 338

339. •The detector senses the amount of tube
twisting.
•The U-shaped tube can be vibrated by an
oscillating driver at its natural frequency.
•Electromagnetic devices, such as velocity
detectors, can be located on each side of the
tube and be used to measure the velocity of the
vibrating tube.
339

340. •When no fluid flows through the tube, all points
move in sequence with the oscillating driver,
forming a sine wave.
•When fluid flows in the tube, twisting occurs.
•The twisting causes a time difference to occur
between the velocity detector's signals.
•The time difference is directly related to the
mass flow rate.
340

341. 341

342. •The mass flow of a u-shaped Coriolis flow meter
is given as:
Where:
Ku is the temperature dependent stiffness of the tube,
K a shape-dependent factor,
d the width,
 the time lag,
the vibration frequency and
Iu the inertia of the tube.
As the inertia of the tube depend on its contents, knowledge of
the fluid density is needed for the calculation of an accurate mass
flow rate.
342

343. Performance Advantage
• They can handle difficult applications.
• They are suitable for a large number of fluids.
• They have Less susceptibility to damage, wear, and
maintenance.
• They can measure bidirectional flow.
• Accuracy is very good, typically ± 0.2% of rate.
• The rangeability is typically 20:1 or better.
• Their operation is independent of a fluid’s property
characteristics.
343

344. Performance Disadvantages
• Earlier versions were susceptible to external vibrations.
• A Coriolis meter is available only up to a small size.
• Special installation requirements are followed to
isolate the Coriolis meter from mechanical vibration.
• Avoid using Coriolis meters in piping or meter runs
which are prone to substantial vibration, shock, or
extreme temperature gradients.
• External meter piping must be well supported.
344

345. 345

346. Ultrasonic Flowmeters
Flowmeters that use sound waves to measure
flow rate are called ultrasonic flowmeters.
346

347. Principles
• Doppler shift (frequency shift) method
• Deflecting beam method
• Transit time method
Time difference
Frequency difference
347

348. Doppler Shift Method
•It transmits a sound wave through the flowing
fluid.
•The sound waves are reflected from the fluid to
a receiver on the ultrasonic flowmeter.
•The frequency of the sound waves sensed at the
receiver shift are affected by the Doppler effect.
348

349. •The frequency shift is used to determine flow
rate.
•Several types of meters are available:
one type requires installation of a
transducer into the flowing stream,
the other is a strap-on model where
installation of a transducer on the pipe is
noninvasive.
349

350. 350

351. Deflecting Beam Method
•The transmitter sends a sound wave that is at a
right angle to the flow.
•The liquid carries the sound wave and the sound
wave is “pushed” or deflected downstream.
•The deflection is directly related to the flow rate
and is used to determine the flow rate.
351

352. Transit Time Method
•A diagonal beam is sent across the flow path.
•The beam is sent with and against the flow.
•Sound travels slower against flow.
•Most commonly used.
•Homogeneous fluids (No entrained bubbles).
•Not for heavy slurry-type applications, because
of the high acoustic impedance.
352

353. 353

354. Transmit Time Frequency Domain Meters
•A pulse is sent in a given direction.
•The time of pulse at the other end of sonic path
is recorded.
•The same signal transmits in the opposite
direction and records the time at the arrival.
•The difference between two time
measurements provides information on motion
of the fluid in a pipe.
354

355. Frequency Domain Meters
•The frequency domain meter uses the same type of
transducers as the transit time domain meter.
•The only difference is in the processing of the signal.
•The time pulse signal is converted to a frequency
signal.
•The path in each direction of flow is used,
•the sonic path generates two frequencies.
•The difference is directly proportional to flow.
355

356. Performance Advantages
• Clamp-on versions are convenient for retrofits.
• Usually nonintrusive.
• No pressure drop.
• Accuracy is comparable to orifice plates.
• High rangeability; rangeability 40:1.
356

357. Performance Disadvantages
• Limited to clean, single-phase liquids.
• Straight piping for uniform flow profile.
• Attenuation may limit transmission path length.
• Averaging methods for large pipes are
marginally cost-effective.
357

358. Vortex Shedding Meters
•Suitable for gas, steam, or liquid services.
•Wide flow range capability,
•Minimal maintenance,
•good accuracy, and
•Long term repeatability.
358

359. 359

360. •Vortex shedding phenomenon is known as the
Von Karman effect of flow across a bluff body.
•Flow alternately sheds vortices from one side to
the other side of a bluff body.
•The frequency of the shedding is directly
proportional to fluid velocity across the body.
360

361. •The output depends on the K-factor.
•The K-factor relates the frequency of generated
vortices to the fluid velocity.
•The K-factor varies with the Reynolds number,
but is virtually constant over a broad flow range.
•The formula for fluid velocity is
Fluid velocity =Vortex frequency/K – factor
361

362. 362

363. 363

364. Positive Displacement Meters
•Positive displacement (PD) meters are used for
measurement of gas and liquid.
Rotating paddle meters,
Oscillating piston meters,
Oval gear meters,
Sliding vane meters, and
Bi-rotor meters.
•The term “displacement” refers to a discrete volume
that is flowing through the meter.
364

365. PD meters are mechanically driven meters and
have one or more moving parts.
365

366. The energy required to drive the meter’s
mechanical components is generated from the
flow.
366

367. The energy to drive the meter creates a pressure
loss between inlet and outlet of the meter.
367

368. A PD meter’s hardware can convert each unit of
volume displacement into an electrical pulse.
368

369. Positive Displacement Meters
369

370. 370

371. •Accuracy is in terms of percentage registration:
% Registration =(actual quantity/metered quantity) x 100
•At high flow rates, the increase in pressure drop
(differential pressure) increases the flow slippage rate,
reducing the meter’s accuracy.
•At low flow rates, the meter has low energy because of
the lower pressure drop, so the flow is under-counted,
again reducing the accuracy.
•Accuracy of the meter is in the range of ± 0.1 to ± 2% of
the actual flow.
371

372. •Rangeability of PD meters typically is 5:1,
although 10:1 and greater flow ranges are
possible.
•Repeatability are typically ± 0.05% or better.
•Output signals are available either in
mechanical or electrical form.
372

373. Performance Advantages
• Ideal for viscous liquids
• Upstream piping requirements are minimal
• Some versions do not require electrical power
• High rangeability in liquid and gas meter.
373

374. Performance Disadvantages
• Not ideal for liquids with suspended particles.
• Mechanical wear.
• Larger meters require extra installation care.
• Meters can be damaged by over speeding.
374

375. Typical PD Meter Installation
375

376. Variable Area Flow Meters
(Rotameter)
•The rotameter’s operation is based
upon variable area principles.
•The flow raises a float in a tapered tube,
increasing the area for passage of the
flow.
•The greater the flow, the higher the
float is raised.
376

377. 377

378. Sight Flow Indicators
•A sight flow indicator is a mechanically driven device.
•Sight flow indicators are used for visual inspection of
the process.
•Three types of sight flow indicators are available, which
are the following:
• Paddle
• Flapper
• Drip
378

379. Paddle Type
•Its design has a propeller inside its body.
•It is only used for high flow rate applications.
•A pressure drop in the paddle type indicator is higher
than the pressure in a drip or flapper type indicator.
• It can be installed for flow directions that are
horizontal or vertical upward.
•It is used when dark process fluids are present.
379

380. Flapper Type
•Bidirectional flappers are also available.
•The flapper type sight flow indicator are used for
transparent or opaque solutions and gas services.
•Flow direction can be horizontal or vertically upward.
380

381. Drip Type
•Its design is used when there is a dripping of fluid in a
vertically downward direction.
•The drip type design is used for vertically downward
flows that are intermittent.
•Assembly consists of a chamber, glass, gasket, end
covers, and bolts.
381

382. Drag Plate
•Flow produces a positive pressure on the plate.
•The force is resisted by a null-balance supporting
element at the end of the support arm.
•The signal is proportional to the square of the flowrate.
382