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DAVID W SPITZER'S E-ZINE (July 2020)

TECHNICAL AND MARKETING SERVICES
FOR INSTRUMENTATION SUPPLIERS AND END-USERS

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 percentages of:

Span	Full span	Span in air
Rated span	Maximum span	Calibrated span
Maximum measured span		Maximum span of the sensor
Maximum measuring span		Span value

Range	Full range	Detected range
Measured range	Target range	Measuring range
Maximum range	Range distance	Maximum target range (in air)
Set measuring range	Range with no temperature gradient

Full scale

Maximum distance	Target distance	Measured distance
URL

Distance	Tank height

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.

Stated Accuracy	Meaning (after discussion with supplier)
0.25% Range	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%	0.25% of maximum sensor range
0.3%	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.

This article was excerpted from The Consumer Guide to Non-Contact Level Gauges

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.

This article originally appeared in Flow Control magazine at www.flowcontrolnetwork.com.

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

Commentary

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.

This article originally appeared in Flow Control magazine at www.flowcontrolnetwork.com.

ABOUT SPITZER AND BOYES, LLC

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.