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Level Gauge Performance (Part 3 of 3) by David W Spitzer
To review --- the performance of a level measurement system is
quantified by means of its accuracy statements. The reader must understand not
only which parameter is being described, but also the manner in which the
statement is expressed. In level measurement, parameters are commonly
described in terms of a:
absolute (fixed) distance error
percentage of the empty distance (farthest measurement in span)
percentage of the maximum sensor distance
percentage of measured distance
percentage of set span
a percentage of maximum span
Note that other terminology may be used to express these
concepts. Some variations actually used by suppliers include mm, cm and
Span in air
Maximum measured span
Maximum span of the sensor
Maximum measuring span
Maximum target range (in air)
Set measuring range
Range with no temperature gradient
An undefined parameter (for example, 0.25%)
Many of the above terms do not have clear meanings. In addition,
discussions with suppliers revealed different meanings for specifications that
otherwise seemed to be clear and well defined. Regardless of the terminology
used by the supplier, the reader is advised to confirm exactly what the meaning
of the terms used in the specification in order to understand them correctly so
as to correctly evaluate performance.
More importantly, the performance specifications may not describe
performance. Consider some examples that were actually encountered.
Meaning (after discussion with supplier)
0.25% of empty distance (farthest measurement)
1.2% of range
1.2% of maximum sensor range
0.25% of measuring range
0.25% of maximum sensor range
0.25% of span
0.25% of maximum sensor range
0.25% of maximum sensor range
0.3% of measured distance
These examples illustrate the difference between published
specifications and their actual meaning. From the above data set, it would be
conservative to assume that statements expressed as percentages are percentages
of the maximum sensor range until they are confirmed otherwise by the supplier.
Natural Gas Flow Measurement, Part 2: Composition Matters by David W Spitzer
As discussed last month, Coriolis mass, differential pressure, positive displacement, thermal, turbine and vortex shedding flowmeters are often specified for natural gas service. Insertion flowmeters using some of these technologies are also available.
Presuming that a flowmeter is calibrated for the North American Energy Standards Board (NAESB) typical natural gas, differences in natural gas composition compared to the NAESB typical natural gas composition, discussed in previous articles, can potentially introduce flow measurement errors into all of these flow measurements and corresponding energy flow calculations --- albeit in different ways.
These composition differences can affect the density, thermal properties and heat content of the natural gas flowing through the flowmeter. It is strongly suggested that the specifications for these flowmeters include the actual natural gas composition (typically available from the local gas utility). Flowmeters that are affected by composition changes include:
Differential pressure flowmeters measure approximately 1/2 percent higher (or lower) for each percent decrease (or increase) in density
Most thermal flowmeters
Flowmeters that are not affected by composition changes include:
Coriolis mass flowmeters use the properties of mass to measure the mass flow
Positive displacement flowmeters measure the actual volume
Thermal flowmeters in which the user can configure the actual natural gas composition in the field
Turbine and vortex shedding flowmeters measure flow velocity to infer volume
It is important to recognize that composition changes can affect the heat content of the natural gas, which can adversely affect the accuracy with which the calculated amount of thermal energy flowing through the flowmeter can be determined. Absent an analyzer or calorimeter, natural gas composition differences from the NAESB typical composition can affect the inferred energy flow of all flowmeter technologies with the exception of some thermal flowmeters that can calculate the heat content of the gas for the configured composition.
Impulse Tubing Installation (Steam) by David W Spitzer
Where and how should a differential pressure flow transmitter be located for steam service?
A. Above the flow element with the impulse tubes sloping upward to the transmitter
B. Above the flow element with the impulse tubes sloping upward then downward to the transmitter
C. Below the flow element with the impulse tubes sloping upward then downward to the transmitter
D. Below the flow element with the impulse tubes sloping downward to the transmitter
Accurately transmitting the differential pressure generated by the flow element to the differential pressure transmitter in steam service is somewhat complicated --- as compared to liquid or gas service --- because steam is both hot and condensable. Being hot, it is not desirable to have steam in direct contact with the transmitter. However, cooling the steam will cause the steam to condense and form liquid. Accurate steam measurement can be achieved despite these seemingly contradictory constraints by allowing steam to condense and accumulate where it does not affect the measurement and, in effect, forms a liquid seal.
Answer A is not correct because it allows live steam to directly contact the transmitter. Answer B, Answer C and Answer D provide for a liquid seal to isolate the transmitter from the steam and could be correct if implemented properly.
Additional Complicating Factors
The impulse tubing installation should ensure (1) that the liquid seals generate the same pressure under zero flow conditions at the high and low ports of the differential pressure transmitter or (2) that the transmitter calibration corrects for any difference.
In addition to over 40 years of experience as an instrument user, consultant and expert witness, David W Spitzer has written over 10 books and 450 articles about flow measurement, level measurement, instrumentation and process control. David teaches his flow measurement seminars in both English and Portuguese.
Spitzer and Boyes, LLC provides engineering, technical writing, training seminars, strategic marketing consulting and expert witness services worldwide.
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