level measurement - controlglobal.com...a servo level transmitter with no stilling well may require...

TECHNOLOGY REPORT

Level Measurement PART 2

Essentials of Tank Gauging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Radar gauge considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

D/P transmitter missteps; Venturi or flow nozzle? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Understand your accuracy requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

AD INDEXAcromag . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

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Krohne . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

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TABLE OF CONTENTS

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Level Measurement, Part 2 2

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The purpose of tank gauging is to measure the contents of tanks and vessels for

inventory control and custody transfer . Most process plants have tanks that hold

feedstock or finished products, and some may have dozens of large tanks, often 50

feet or more in height and diameter, holding millions of dollars’ worth of feedstock or prod-

uct . Monitoring and controlling the volumes of tank contents is important to ensure accu-

rate data for financial statements as well as production planning and scheduling . Inaccurate

measurements may result in suboptimal productivity, accounting errors and environmental

incidents through spills .

Monitoring tank inventory levels traditionally involves two operators, one in the field and

one in the control room . The field operator takes the reading from a tank level gauge and

tells the control room operator to start/stop the pumps . This practice is expensive, resulting

in hundreds of thousands of dollars every year . In addition, it exposes the field operator to

hazards, including falls and hazardous vapors .

To improve safety, efficiency and accuracy, many plants choose to automate tank gaug-

ing and integrate tank level information with control and business systems . Any such effort

must first gather the following information:

• Who needs tank inventory information, how frequently, and in what formats .

• Relevant regulations and standards .

Essentials of Tank Gauging





• The required level of accuracy .

• Additional functions, e .g . pump control,

overfill protection .

• Software and integration requirements .

• Available or practical networks, e .g . wired,

wireless, cellular, fiberoptic .

• The properties of the measured fluids .

• The configurations, environments and

properties of the tanks or vessels .

HYDROSTATIC PRINCIPLESFeedstocks received, internal transfers and

delivered products often are measured in

incompatible volumetric or mass-based

units . Conversions from volume to mass and

vice versa are frequent, requiring accurate

measurements of water interface, density

and temperature as well as product level .

Either mass or volume measurement tech-

niques can be used . Mass or volume can be

derived from level; mass can be measured

directly by means of pressure transmitters .

Additional information can be obtained by

ACCURACY, REPEATABILITY AND RELIABILITY

Tank gauging focuses on static quantity

measurements of liquids in bulk storage .

Measurements may be either level- or

pressure-based, and usually must be

converted to standard mass or volume

units by correcting for temperature

and/or pressure (described below) .

Accuracy requirements drive much of

the lifecycle cost of a tank gauging sys-

tem . Requirements for custody transfer,

inventory reconciliation and leak de-

tection may be an order of magnitude

tighter than for operations inventories,

where repeatability and reliability may

be more important than accuracy .

In applications involving custody transfer

or assessment of taxes, duties or royal-

ties, the gauging instruments and inven-

tory control system must be officially

approved and certified for this purpose .

Along with repeatability, a reliable tank

gauging system helps prevent overfills

and spills, and avoids shutdowns due

to feedstock shortages . A high degree

of accuracy and reliability will allow

operations to safely use the maximum

tank capacity, which can materially

increase storage capacity . Reliability

also reduces maintenance, repair and

calibration costs .



measuring vapor temperature and pres-

sure . Density measurement can also be

added, with accuracies from 0 .5% up to

0 .1% . Whichever technique is selected, it

should be compatible with the operations

of all parties using the data from the tank

gauging system .

Hydrostatic tank gauging (HTG) is the

traditional pressure-based method of

measuring tank contents . A simple HTG

system uses a single transmitter (P1) near

the tank bottom . The total mass of material

above the transmitter can be calculated by

multiplying the measured pressure by the

equivalent area of the tank .

By adding a second transmitter P2 at a

known distance (usually 1 .5-2 .5 m) above

P1, the observed density of the material can

be calculated from the pressure differential .

The level can be calculated from the density

and the P1 pressure .

A top transmitter (P3) can be added to

compensate for the effect of vapor pres-

sure on P1 and P2 . This approach is gen-

erally not suitable for pressurized tanks

where the tank pressure is large compared

to the hydrostatic pressures used to mea-

sure tank level .

Using highly accurate, digital smart trans-

mitters, HTG systems can measure mass

within 0 .5% or better . However, as level

instruments, HTG accuracy is typically 40-

60 mm, which may not be good enough

for custody transfer or inventory value

assessment . So many plants install a dedi-

cated level gauge .

HTG systems also measure density over a

limited range near the bottom of the tank .

If the liquid level is below P2, there is no

differential pressure measurement . And in

some applications, the fluid density near

the bottom of the tank is different from

the density at higher levels . This density

stratification has a significant effect on the

calculated values for level and volume .

The low accuracy of HTG systems for level

measurement makes them unsuitable for

overfill protection, and secondary high-level

alarms are essential .

LEVEL-BASED SYSTEMSAn alternative to HTG, level-based sys-

tems use a level gauge and combine its

reading with separate temperature and

density measurements . Temperature is

measured using a spot or average tem-

perature sensor . An accurate average

temperature measurement is essential to

achieve accurate inventory calculations,

especially when the liquid temperature is

stratified .

Density at reference temperature may be

determined by laboratory analysis of a grab

sample, or by using reference tables for

well-characterized materials .



The gross observed volume (GOV) is de-

rived from the level reading and a tank ca-

pacity (strapping) table . The gross standard

volume (GSV) is calculated by correcting

the GOV with a volume correction factor

calculated from the temperature, density

at reference temperature, and ASTM or API

tables . The total mass is then calculated

from the GSV multiplied by the density at

reference temperature .

Correction may be required for sediment

and water, using interface measurements

provided by specialized level instrumen-

tation . Modern level-based tank gauge

systems may include interface detection,

temperature instrumentation, overfill sen-

sors and the ability to program strapping

and density parameters to provide a com-

plete measurement .

TANK PARAMETERSThe installed costs of an automatic tank

gauging system consist of the instrumen-

tation costs as well as the costs of tank

modifications, cabling and conduit, and

auxiliary equipment .

Different sensor technologies operate in

different ways, which directly affects how

they are installed . Most level-based tank

gauging systems use magnetostriction, ra-

dar or mechanical servo instrumentation .

(For more about instrument technologies

and applications, see Control “Essentials

of Level Instrumentation .”) All require

stable mounting for accuracy . Most will

require some degree of tank modification,

and those costs can be significantly larger

than the cost of the level transmitter .

There are three main types of tanks:

fixed roof, internal floating roof and

external floating roof . The two main

concerns are absence or presence of a

stilling well, and the nature and size of

the process opening .



A fixed-roof tank with no stilling well

can be served by a radar system with

an antenna to focus the signal, but the

antenna may be large and require using

the manway for mounting . Alternatively,

a servo level transmitter with no stilling

well may require only a six-inch opening

in the tank, but includes bulky guide wires

to stabilize the displacer . A magnetostric-

tive level transmitter typically requires a

three-inch or greater process opening .

Whether internal or external, floating roof

tanks without a stilling well are among the

most difficult applications for automatic

tank gauging . A radar level transmitter

can be used by reflecting the radar beam

off the floating roof, but accuracy may be

reduced by measuring the floating roof

instead of the actual liquid level .

Servo or magnetostrictive transmitters

can be mounted on the fixed roof of

the internal floater, or on the geodesic

dome or bracket of the external floater,

aligned with an opening in the floating

roof to allow access to the liquid . Plates

and boots are used to seal around the

floating roof entry .

All three tank types are similar if a stilling

well is present, as the stilling well provides

easy and protected access to the liquid . In

general, radar and servo instruments re-

quire a six-inch well, and magnetostrictive

require a four-inch well .



BEYOND THE TANKAdditional installation considerations in-

clude safety, communications, and auxiliary

equipment such as heaters, displays, field

modules and software .

Many tank gauging applications involve

flammable products, hazardous areas, and

exposure to lightning . Instruments may

have to be explosion-proof, and sensor

circuits intrinsically safe . Their position on

top of storage tanks makes this equipment

more vulnerable to lightning damage, re-

quiring well designed, field-proven lightning

protection methods . Proper grounding and

shielding will also help protect against dam-

age by lightning .

Cable, conduit and communications choic-

es are not the same for all level technolo-

gies, even when transmitters are specified

with the same output protocol . There may

be significant differences in pricing and

availability .

Auxiliary equipment may include heaters for

cold weather applications, protocol con-

verters for proprietary protocols, specialty

tools for service or installation, and licensed

software . A simple site survey and official

quote from the gauge manufacturer (with

line item details) are the best ways to deter-

mine additional costs and avoid surprises .

Software ranges from basic gauge manage-

ment packages to inventory management

systems integrated with the enterprise . An

inventory management system can col-

lect measurement data from multiple tank

gauges, monitor alarms and functional

parameters, and compute inventory volume

and mass in real time . Volumes and masses

should be calculated the same way as au-

thorities and surveyors . The software should

store tank table parameters, calculate

observed and standard volumes, correct for

free water and, if applicable, correct for the

floating roof immersion .

The system may control inlet and outlet

valves, start and stop pumps, display data

from other transmitters, provide shipping

documents, provide trend curves, show bar

graph displays, perform leak detection, cal-

culate flow rates, control alarm annunciation

relays, perform diagnostic tasks and more .



LIFECYCLE COSTSVirtually any level measure-

ment technology can be

used in almost any tank and

be made to meet the re-

quirements . The difference

is the lifecycle cost, which

includes the cost of instal-

lation, maintenance and

calibration . Understanding

all of the installation consid-

erations before starting will

keep a project from ex-

ceeding budgets and help

minimize headaches . Before

any work is done, answer

the following questions:

• What is the stilling well

type and how will it

impact level transmitter

choice?

• What are the process

connection type and size,

and how will they affect

including access for main-

tenance?

• How much modification

will be required to the

tank itself and what will

it cost?

• What is the total cost of

cabling, conduit and/or

wireless associated with

the project?

• What auxiliary equipment

(such as heaters, displays

and field modules) will be

needed, and what will it

cost?

Studying these areas of

installation consideration

will help with determin-

ing which level technology

best suits an existing tank .

When specifying a level

transmitter for automatic

tank gauging, talk to the

manufacturer to determine

the installation require-

ments on each tank and

make an informed deci-

sion on the installed costs

of the system, not just the

specifications of the level

transmitter .

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Q1: When vapor space condensation can occur, is a guided wave or non-contacting radar level detector the better choice? A . Rahimi

a .rahimi .aut@gmail .com

A1: I’ll start with a broader discussion of the radar (radio detection ranging) level measure-

ment topic before answering your specific question .

Guided wave radar (GWR) technology has been used for many de1cades, employed for

such purposes as finding breaks in underground cables and in-wall cable installations of

large buildings . GWR operates by launching low-amplitude, high-frequency pulses onto the

waveguide, and then sequentially sampling the reflected signal amplitude . Typically, reflect-

ed pulse amplitudes are displayed on a calibrated time scale . In this way, cable impedance

changes or, in this case, tank levels can be assessed (Figure 1) .

Changes in the dielectric constant of the vapor space does cause errors . For example, if the

temperature (and pressure) of steam in a vapor space increases, the dielectric constant also

rises . This increase in vapor space dielectric causes a delay in the GWR signal propagation

as it travels down the probe to the process medium . This signal propagation delay results

in the liquid level appearing to be lower than it actually is . This error can be minimized by

Radar gauge considerationsOur experts tackle calibration requirements, plus the influence of condensing vapors

by Béla Lipták





placing a mechanical target onto the probe

within the vapor space, which produces a

small signal reflection at that known and

fixed location .

The phase difference sensor (PDS) is simi-

lar to GWR, except that it operates in the

frequency domain rather than the time

domain . PDS measures the level on the

basis of changes in phase angle . It operates

by sending a high frequency signal through

parallel conductors at a fixed velocity until

it’s partially reflected by the stored mate-

rial interface where the sensor impedance

abruptly changes . The dielectric constant

remains near unity, even if dust, vapor, con-

densate or foam are present, and therefore

the signal injected into the sensor probe

travels down to the material interface and

back at a constant velocity .

In case of most media, as the temperature

increases, the dielectric constant decreases .

Therefore, this inverse relationship requires

that the level value detected be corre-

spondingly corrected . Another source of er-

rors in both GWR and PDS measurements is

coating, if the media is high dielectric (e .g .

water-based) . The worst error source is a

thick, high-dielectric coating that runs the

full length of the probe .

There are two basic types of non-contact-

ing radar level sensors: pulse type and

frequency modulated carier wave (FMCW)

type . Both detect the time of flight from

the sensor to the level in the tank . The

pulse method is similar to sonar, where

the time of the echo return is measured .

They’re similar to most ultrasonic sensors,

except that the pulse units operate be-

tween 6 and 28 GHz, and not at utrasonic

accoustic frequencies . These units are

employed mostly for liquid level measure-

ment, and can’t measure interface . Agita-

tors, thick foams, window coating, conden-

sation or splashing can cause problems .

The antennas can have parabolic reflectors

or differently shaped horns .

GUIDED-WAVE RADAR OPERATIONFigure 1: In guided-wave radar applications, the dielectric constant of the media measured must be greater than 1.4. In transition zones, (0-18 in.) from top or bottom readings can become nonlin-ear. In addition, foam or coating can cause error that gets worse with higher dielectric constant, extent and/or density of the foam or coating.

Transmit pulse

Air r = 1

Media r > 1.4

24 VDC, 4–20mALoop powered



Most pulse radar detector suppliers have

five or six models . They’re designed for

measuring liquid or solids levels, can have

different measuring ranges, and housings

with ambient or high temperature or pres-

sure ratings . They can also be waterproof or

equipped to handle hazardous or vaporous

environments . Small antenna size, minimal

or zero blank zone, and threaded process

connections down to 1 in . are available .

In the more widely used and somewhat

more expensive FMCW design, time of

flight is tracked onto a carrier wave .

The detector output is a frequency sig-

nal, which is the difference between the

“send” and the reflected return signals .

This difference is directly proportional to

the time of flight and thus to the level . In

general, radar gauges are often replacing

ultrasonic detectors, but they still have

problems in detecting foam and low-di-

electric materials .

Non-contact radar gauges can be

equipped with a polypropylene or PTFE

“drop” antenna for use with condensing

atmospheres and corrosive media . Ac-

cording to one supplier, this FMCW radar

level transmitter provides accurate read-

ings in closed tanks, open-air applications

like rivers or dams, and even in fast mov-

ing processes .

So, coming back to your specific question,

contacting gauges with a guide antenna

are used more often when condensation is

present, but non-contacting ones are also

available .

Béla Lipták

liptakbela@aol .com

Q2: I really admire your books on instrumentation, which focus on practical aspects of automation and control. Generally in my country, the facility to calibrate radar level transmitters (non- contact type) is not available. Can you suggest any alternative method (which can be used by maintenance personnel) for calibrating non-contact type radar level transmitters? Do the manufactureres of radar level transmitters give any guarantee that their units do not require periodic recalibration?K V Ratnakar

vrkavi@rediffmail .com

A1: I assume you have a non-contact radar

cone and not a wave-guide model . In that

case, measure the actual distance from the

cone to the zero level in your vessel . If it’s

a closed pressurized vessel, use the design

engineer’s internal vessel drawings or use

the dimensions of the vessel itself to de-

termine what and where 0% and 100% are

on the vessel . Calibration can be as simple

as entering these values directly as your

z/100% calibration, or you might have to



do a small calculation like maximum pos-

sible distance (tank depth) minus z mea-

sured distance equals zero distance, and

maximum possible (tank depth) distance

minus 100% measured distance equals

100% distance .

Also, keep in mind that radar measures

distance, and vapor space measurement is

the opposite of level . You therefore need

to modify the local display to indicate level

in mm or percent, as well as set up your

output to be based on level, and not on

distance after the calibration . The radar will

then send out a 4mA signal when the tank

is empty and 20mA when the tank is full, or

when the level has reached the point where

you have specified 100% to be .

Dick Caro

RCaro@CMC .us

A2: Special considerations may be needed in

applications where product can build-up or

splash on the radar antenna . But in general,

with no moving parts to lose tolerance, radar

transmitters need very little maintenance . So,

calibration should not be required for a well-

designed (and properly applied) radar de-

vice, but if periodic proof-testing is desired,

frame programs like PACTware can be used

to periodically view and compare waveforms

to gain confidence in the proper operation of

installed radar instruments .

Advances in the diagnostic capability of ra-

dar devices now allow for saving reference

curves, which makes comparing a waveform

taken last year to one taken more recently

very simple . Coverage may be increased by

comparing these waveforms at two differ-

ent levels in the vessel . In addition, configu-

ration changes are typically very simple to

accomplish remotely (via HART or FOUN-

DATION fieldbus) .

All this being said, it must be stressed that

proper application and installation of radar

devices is key to minimizing issues that

could arise . I hope this helps . Please let me

know if you have any questions or need ad-

ditional information .

Bob Botwinski

senior global product manager,

Radar/Guided Wave Radar

Magnetrol International

rbotwinski@magnetrol .com

A3: Non contact radars can be calibrated

by using an arrangement similar to a stilling

well, and of a length to accommodate most

radar units . As to the issue of not requir-

ing calibration, as far as I know, every unit

should be calibrated periodically .

Alex (Alejandro) Varga

vargaalex@yahoo .com

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Q: I have the following questions concerning a conventional level detection differential pressure (D/P) transmitter which is installed above the upper pressure tap. Please see sketch of the application (Figure 1).

We have used a conventional

D/P transmitter—not one with a

diaphragm seal . The reason for

keeping the transmitter above

the top nozzle is to drain any

condensate back to the vessel/

tank . My questions follow:

D/P transmitter missteps; Venturi or flow nozzle?Our experts address differential pressure transmitters used for level applications, as well as Venturi vs . flow nozzle recommendations

by Béla Lipták



LT

0%

100%

DLM = 100

HLN = 100

HUN = 5000

DUM = 100

E = 200

Cal

ibra

tion

rang

e– +

TL

TL

PROPOSED D/P LEVEL CONFIGURATIONFigure 1: Condensate drain-back into tank by locating the level transmitter above the tank.



1 . Can we the put level transmitter above

the upper nozzle?

2 . Please help me to derive the equation

of LRV and URV to be set when conven-

tional D/P transmitter is kept above the

above nozzle . I’ve seen a majority of level

transmitters installed at lower nozzle or

below the lower nozzle for head mea-

surement . So, for this arrangement, what

is the impact on calibration range when

the transmitter is installed above the top

nozzle?

3 . Is this arrangement, which does not in-

clude diaphragm seal, seal pot or purging,

allowed per international standards such

as API best practices?

4 . When there is 10% of liquid filled up, how

will liquid create head on the transmitter

(high pressure side)?

5 . How do we ensure that liquid head will

be acting on the high-pressure leg all the

time (without any vapor pocket) when

the actual level inside the tank is 10-15%?

6 . How do we ensure that density of vapor

will be the same on impulse tubing (par-

ticularly on low pressure side), so that

the chance of measurement error will be

minimized?

Jatin Katrodiya

jatinkatrodiya@yahoo .com

A1: The operating pressure creates serious

problems . It’s my experience that every-

thing leaks; the only question is how much .

It would be very difficult to keep the high-

pressure sensing line filled only with gas .

Your scheme as shown will most likely fail

to work even at startup . If the pressure was

low enough, I would suggest a purge on

both connections . That will require a com-

pressed gas source . I would prefer to use

remote chemical seals in this service .

Cullen langford

cullenl@aol .com

A2: You certainly have a non-conforming in-

stallation . Most installations locate the lower

leg below the tank, and use diaphragm seals

on both legs . Unless the “high pressure”

(HP) leg is a filled tube with diaphragm

seals on both sides, I don’t see how the high

pressure from liquid level and vapor pres-

sure can get to the level transmitter .

If your high pressure leg is diaphragm sealed

and filled with an inert transfer fluid, it will

appear to the level transmitter as the head

(pressure) of the transfer fluid plus the head

of the liquid in the tank plus the pressure

head of the vapor space . The low pressure

(LP) side will see only the pressure of the

vapor space . When you subtract the HP pres-

sure from the LP (the reading of the transmit-

ter) you will have the liquid level in the tank

plus the head of the HP leg . Since the HP leg

is a constant, it can be removed by setting

the zero point of the level transmitter . Now

you should be able to do your math .

Dick Caro

ISA Life Fellow

RCaro@CMC .us

A3: If for some reason you don’t want



to use chemical seals or

purge both connections,

but you do want the con-

densate to drain back into

the tank, you can follow

Figure 2 and reverse the

output of the transmitter .

Naturally, you have to cor-

rect for the density differ-

ence between that of the

ambient temperature con-

densate and the density of

liquid in the tank .

Béla Lipták

liptakbela@aol .com

VENTURI VS. FLOW NOZZLE?Q. Working as an in-strument engineer in the oil and gas industry, I’ve specified a flow measuring device as an orifice meter, but while sizing with maxi-mum beta ratio, the resulting permanent pressure loss is higher than what the process department allowed as the maximum allowable pressure drop. Hence, it’s understood that orifice will not be suit-able for this measure-ment purpose, and I’m

considering some alter-natives for the process conditions and line size. As an alternative to the orifice, in order to meet the process maximum allowable pressure drop, we decided to go with either a Venturi or flow nozzle primary element.

Now, I don’t know which to

chose . Can you suggest the

factors or considerations

in which a Venturi meter is

preferred to a flow nozzle

or vice versa? What are

the basic considerations

that have to be taken into

account for selecting one

or the other, and which is

preferred and why so?

M . Ulangatham

Instrument Engineer

ulaganathan .inst@gmail .com

A1: In general, you want to

use Venturi measurement

when the range is small, say

less than 100 in . H2O, and

nozzles when you have a

larger flow range . Most Ven-

turi meters you’ll calibrate for

0-10 or 0-25 in . H2O . Flow

nozzles work basically as a

restriction orifice (RO), so

use the same basic principle .

Alex (Alejandro) Varga

vargaalex@yahoo .com

Boiling fluid

Slope

Condensingchamber

LT

LP

HP

ALTERATE D/P LEVEL SOLUTIONFigure 2: Seal-less D/P level measurement solution as often applied to boiling fluids.



A2: The flow nozzle is a prefered choice for

steam flow measurement .

Debasis Guha

debasis_guha71@yahoo .com

A3: This is a common question, so I’ll give

you a more detailed answer .

The meter coefficient of a typical orifice is

about 0 .62, while that of a Venturi or flow

nozzle is almost one (0 .99) . Therefore, at

the same P and the same ratio (diameter

of restriction divided by the pipe inside

diameter), these meters pass about 40%

more flow than an orifice .

The big difference between them is in their

cost and pressure recovery . The cost of the

Venturi is higher, say about $6,000 for an

8 in . cast iron one, while an 8 in . aluminum

nozzle is about $1,200 . At a beta ratio of 0 .5,

a standard Venturi recovers about 85% of its

differential, while at the same beta ratio, an

ASME flow nozzle only recovers about 35%

of its differential . Consequently, because of

the high pressure recovery of the Venturi, its

operating costs are much lower . As a result,

the savings in pumping costs can quickly

compensate for the initial price difference .

Among the two, the Venturi is more accu-

rate, about 1% full scale (FS), while the flow

nozzle is about 2% FS . The rangeability of

both is about 4:1 . The straight run require-

ment of nozzles are longer (10-30 diam-

eters) than Venturis (5-20 diameters), but

not that much . Flow nozzles are available

in a largerr range of beta-ratio (0 .3-0 .7) .

And as far as installation goes, flow nozzles

should be installed downflow when used

on wet gases, wet steam or liquids with

suspended solids, but neither meter should

be used on slurries or dirty fluids .

With Venturi meters, cavitation can be a

problem when the downstream pressure

of a liquid drops below the fluid’s vapor

pressure . Bubbles form, and cavitation can

destroy the throat of the meter . The bot-

tom line is: because your process people

are concerned about pressure loss, a Ven-

turi should be used .

Béla Lipták

liptakbela @aol .com

https://www.massa.com/industrial/ultrasonic-sensors/?utm_source=Control&utm_medium=eBook&utm_campaign=Sensors2021&utm_content=mPulse%26FlatPack

The essential first step toward measurement success is understanding just how ac-

curate each of your plant’s instruments needs to be . That understanding, of course,

drives what type of instrument is purchased initially, but also how its performance

should be managed in order to continue to deliver that accuracy throughout its lifecycle .

To shed some light on the factors that influence accuracy requirements—and what steps are

necessary to maintain desired performance—we caught up with Robert Jennings, calibration

and repair manager for Endress+Hauser in the U .S . Now based in La Porte, TX, he’ll soon

manage the company’s calibration and repair services out of a new $38 .5 million, 112,000-

sq .ft . campus under in Pearland’s lower Kirby District near Houston .

Q: Determining how best to ensure that one’s instruments are performing as expected is not as straightforward as one might think. More frequent calibrations than necessary can waste resources and introduce downtime and risk, while too few can adversely affect safety, regulatory compliance, product quality and overall profitability. As a first step in an optimal in-strumentation management plan, how do I go about determining just how accurate the instruments in our plant need to be?

Understand your accuracy requirementsby Robert Jennings, Endress+Hauser



A: The first step is to perform a plantwide

assessment of all your instrumentation .

First, identify and make a list of all the

equipment parts and all instrument-related

systems . This list should include details such

as description, location information, operat-

ing conditions, working range and history,

and any other points that provide a better

understanding of the instrument and sys-

tem function .

Next, evaluate each instrument’s critical-

ity along three dimensions: to the end

product; to the process operations; and to

protecting workers, the environment, and

production assets .

The first category—instruments criti-

cal to the product—are those that affect

product quality, sometimes with regula-

tory compliance implications such as for

aseptic systems . We start here because

these instruments have a direct link to

company profits, whether it involves pro-

viding a consistent mix of ingredients for

a food processing application, gauging

the completion of a batch chemical reac-

tion or successfully fulfilling the terms of a

custody-transfer agreement .

The next category—instruments critical to

the process—are those that can upset or

shutdown the overall plant or other pro-

cesses . These instruments can cause inef-

ficiencies and production losses, but do

not have a direct effect on product quality

or safety .

Instruments deemed critical for their pro-

tective role have a direct impact on opera-

tor safety, the environment or integrity of

production assets . Often, they do not have

to be extremely accurate, but they have to

function properly and reliably .

Finally, non-critical instruments have no

impact on product quality, the overall pro-

cess or protective measures . These types of

instruments are often only used for local or

remote monitoring or when manual opera-

tions are performed .



After all instruments have been identified

and classified into these four categories, a

maximum permissible error (MPE) is as-

signed to each device based on the conse-

quences of its inaccuracy . A critical instru-

ment will usually have a more stringent

MPE than a non-critical one . The necessary

calibration interval, then, is all about making

sure that the instrument continues to per-

form its critical functions and maintains that

performance within the prescribed MPE .

Application-specific factors to be taken into

account include the nature of the product

being measured, the continuity of the pro-

cess (continuous use or intermittent use),

the need for clean-in-place (CIP) opera-

tions, the severity of process impacts and

how easy it is to access and remove the

instrument for calibration . In some cases, it

may only be possible to access the instru-

ment during a complete process shutdown .

If you can show an auditor or other respon-

sible entity that a non-critical instrument

has no effect on product quality, safety or

the environment, and its MPE is relatively

high, then you can claim there is little or no

need for periodic calibration . Conversely,

critical instruments should be calibrated at

intervals appropriate to maintaining criti-

cal product quality, process operations or

protective functions . Keep in mind that

those instruments deemed critical to safety

or the environment often have their cali-

bration frequency dictated by regulatory

requirements .

Q: Verification is often cited as a way to ensure the proper operation of instruments without removing them from the process for a full-blown calibration. Can you explain how verification works, and how it is different from calibration?

A: The most important distinction is that

while calibration is quantitative, verification

is qualitative . Verification should not be

confused with calibration since it doesn’t

compare the accuracy of an instrument

against a reference, nor is it used to adjust

the calibration factor of the instrument .

That being said, verification provides a

high degree of confidence that the instru-

ment is operating in accordance with its

original specifications based on testing of

key internal components .

Verification is done in-line with minimal or

no process interruption using the verifica-

tion functionality embedded within the

latest generation of instrumentation or,

in the case of older instruments with little

diagnostic coverage, using specialized tool-

ing . More recently developed instruments

include automatic checks of their own

health, providing a continuous source of

confidence that the instrument is function-

ing as intended .



In-line verification improves plant availabil-

ity because there is no need to dismantle

the instrument for calibration . This elimi-

nates the risk of damage of during re-

moval or transportation, and removes the

potential for mistakes to be made during

reinstallation . And, when performed peri-

odically, verification allows the operator to

track the instrument’s performance over

time . This can provide early notice of an

increased risk for measurement drift of the

instrument, giving additional confidence

in the current performance of the instru-

ment—or early warning of the need for an

unscheduled calibration .

For example, Endress+Hauser’s latest gen-

eration of smart instruments with Heartbeat

Technology offer significant reliability and

safety advantages, verification convenience

and enhanced opportunities for calibration

flexibility . These instruments continuously

check their own health with a best-in-class

diagnostic coverage typically exceeding

95% . Instrument failures that could cause

malfunctioning of safety systems are signifi-

cantly reduced . Consequently, the risk of an

undetected dangerous failure being present

in an instrument is extremely low .

Heartbeat Verification enables instruments

to be verified locally at the push of a but-

ton or remotely via higher-level systems

without process interruption or the need for

additional tooling . Heartbeat Verification is

certified by TüV to be a traceable verifica-

tion method according to ISO 9001 . The

automatically generated verification report

is in accordance with the IEC 61511 user

functional safety standard and consequent-

ly meets compliance requirements while

reducing documentation effort .





Q: Can instrument self-diagnostics and verification help to extend instrument calibration and maintenance intervals? What about proof-testing for safety instrumented systems?

A: Confidence from the

continuous diagnostic test

coverage, together with

easily performed peri-

odic verifications, provides

many users the flexibility to

extend the calibration and

proof-testing cycles of their

instrumentation, thereby

saving time, effort and

costs while maintaining safe

operations .

The IEC 61508 functional

safety standard refers to

the probability of failure

on demand (PFD) as the

basis for instrument reli-

ability . Together with

instrument PFDs demon-

strated to remain low for

extended periods of time,

Endress+Hauser’s Heartbeat

Technology permits many

users to extend the instru-

ment proof-testing intervals

in their safety instrumented

systems .

It bears repeating that dis-

mantling and removing an

instrument from a process

for testing or calibration

introduces additional risk

by handling the instrument .

Most often, the user already

knows that the instrument

is probably working proper-

ly and safely but is required

by internal or external regu-

lations to ensure and docu-

ment the instrument’s func-

tionality at regular intervals .

Here, in-line verification can

be of significant value, help-

ing to extend more intrusive

calibration intervals and

saving both time and effort .

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