state of technology report: level ......drum level control, and more. should this report not satisfy...

SPECIAL REPORT

STATE OF TECHNOLOGY REPORT:

LEVEL INSTRUMENTATIONSimple in concept, measuring the height or quantity

of solids and liquids in tanks and vessels is amazingly

complex in practice because there is a virtually infinite

number of combinations of materials and operating

conditions under which they must be measured. Solving

the resulting problems with agglomeration, separation,

corrosion, foam, vapor and adhesion, as well as high and

low pressures and temperatures, etc., has resulted in

markets for many niche as well as broad applications for

a wide variety of instrumentation.

Every few years, advances in manufacturing and signal

processing bring a new technology, such as laser, into the

practical realm of industrial applications, but for the most

part, today’s fundamental technologies of level instruments

and switches—float/displacer, differential pressure (DP),

capacitance/admittance/conductance, vibration, magneto-

striction, radar, laser, nuclear, weight—are well established.

Our following and most recent coverage focuses on

expanding applications and solving problems with using

conventional technologies in existing applications. Read

on to see how to deal with (or eliminate) DP impulse line

problems, control oil/water interfaces, improve boiler

drum level control, and more. Should this report not

satisfy your level of interest, you can find more articles

on level instrumentation and control in the Control 2015

“State of Technology Report: Level & Flow.”

—The Editors

http://info.controlglobal.com/sot-151109-lphttp://info.controlglobal.com/sot-151109-lp

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TABLE OF CONTENTS

www.controlglobal.com

State of Technology Report: Level Instrumentation 3

Digital signals support low-maintenance approach 5 to differential pressure measurement

Level technologies get faster and more precise 8

Controlling levels of parallel separators 15

Advanced control for boiler drum level? 19

Remote tank gauging 23

Experts weigh in on distillation plant measurement problems 25

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Digital precision and stability allow accurate DP level and flow readings using two pressure transmitters

By John Rezabek

A differential pressure (DP) application had capillaries—small-bore armored tub-ing connecting the remote seal to the transmitter—in excess of 50 feet. When the weather turned cold, there was enough of a viscosity change in the fill fluid to cause a time lag in the longer leg, making an otherwise quiescent measurement extremely

noisy. If this had been “real” DP instability, it could have meant death and destruction for

the millions of dollars of precious metal catalyst in the reactor, so it caused more than a

little trepidation—until we figured out the correlation with cold weather.

Twenty years ago, a lot of end users became enamored with remote seals as an alternative to

wet-leg DP level and DP flow applications. Using DP for level has its appeal: one gains some

commonality or uniformity of spare parts with flow and pressure applications, calibration stan-

dards and procedures are similar, and service is uncomplicated compared with external-cage

methods. But wet legs are a challenge when the fluid filling the impulse lines (the tubing con-

necting the DP transmitter to the level taps) is prone to freezing, polymerization or plugging of

other kinds. And since the DP measurement is in effect “weighing” the head of the liquid above

each tap, undetected changes in density or specific gravity will cause an offset or error in the

level measurement, as will gradual vaporization of fill fluid in the wet leg.

Remote-seal DP transmitters for level address a number of the pitfalls of conventional wet-leg

applications. Only the vessel nozzle and the isolation valve to which the seal connects are

Digital signals support low-maintenance approach to differential pressure measurement



vulnerable to freezing and plugging, and they

benefit from the conducted heat of the pro-

cess itself. The fluid in the wet legs is purged

free of any vapor pockets, 100% filled with a

synthetic oil, and sealed with high-integrity

welds. This isolation also makes them ap-

pealing for high-pressure, corrosive or toxic

applications where we prefer that the instru-

ment tech isn’t exposed to the hazards. But

since such systems are sealed, they impede

everyday DP transmitter calibration and spare

parts procedures. Frequently a dedicated

spare is needed for each application. Even

though these properties caused the price to

be double a normal DP level transmitter, we

specified quite a few of them.

When the measurement is differential pres-

sure, whether direct (DP) or indirect (level),

why not just use two pressure transmitters

and take the difference? The problem is, the

difference we aim to measure is often a min-

ute fraction of the system’s static pressure. In

the case of our reactor, the static pressure is

nearly 5,000 psi, and the DP of interest had a

full scale of around 100 psi. If you happen to

find a transmitter with an upper range value

(URV) of 5,000 psig, the full scale of the DP

measurement is 2% of span. A change of 1 or

2 pounds was meaningful, which translates to

0.02% of span. As Profibus expert and author

James Powell pointed out in a November 2015

posting on the “Profinews” website, the un-

certainty of 4-20 mA analog is degraded even

further when the configured span is a fraction

of the transmitter’s capability.

We thought we might have to heat trace

the capillaries. Fortunately, we had digitally

integrated (fieldbus) transmitters.

Today, the reactor DP and a dozen other DP

and level measurements have been convert-

ed from DP transmitters to “DP by differ-

ence” using two static pressure transmitters.

It works because the transmitters commu-

nicate digitally, and carry a tighter spec and

warranty for accuracy and stability right out

of the box. It costs more—you’re buying two

transmitters instead of one—but the method

has become the standard whenever preci-

sion and reliability is critical. If you’re mea-

suring several DPs across a tower or reactor,

you only need N+1 transmitters (for example,

three to measure two DPs), so the cost dif-

ference is less.

If you’re using a legacy platform, you can get

the approximate performance by using any

of the much-lauded “electronic remote seals”

offered by Emerson Process Management, or

similar products from Endress+Hauser and

Vega. Similar to our method, the difference

is computed digitally in the transmitter, but

sent to the system as 4-20 mA. You won’t

find a Profibus or Foundation fieldbus ver-

sion of these products, because the precision

required is already there.

John Rezabek is a process control

specialist for ISP Corp., Lima, Ohio.

Email him at [email protected].

mailto:jrezabek%40ashland.com?subject=

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Level technologies get faster and more preciseLevel instrumentation, peripheral technologies, networking and software are being coordinated in efforts to obtain faster, more accurate readings

By Jim Montague

“Level” measurement might be the wrong word. Changeable, dynamic or chaotic measurement might reflect reality better. This is because the contents of most tanks, silos and other process vessels are often anything but level. They’re typi-cally pouring in, mixing with other substances, reacting chemically or draining out.

Of course, most process materials have enough time to settle before they’re measured, but

users churning out increasingly complex products faster are pushing existing level devices

to their limits. As a result, engineers, integrators and suppliers are helping users implement

more sophisticated level technologies, combining existing level devices in new ways and

also adding peripheral components and software that can help.

GUIDED BY RADARTwo of the today’s most popular and frequently compared level solutions are through-air/

non-contact radar and guided-wave radar (GWR). The first sends electromagnetic microwave

pulses through the atmosphere, while GWR directs its pulses along a probe or, increasingly,

flexible cable. As usual, the trick is to have the right level technology to fit the application.

For instance, Red Arrow Products Co. produces natural smoke condensates and food flavor-

ings at its plant in Manitowoc, Wisconsin, and it stores wood oil in a 1.5-meter collection tank,

which must maintain a constant level as part of its evaporation process. The company had been



measuring the oil’s level with a capacitance

sensor, but coating problems in the tank

were causing unreliable measurements and

hampering operations. Normally, capacitance

devices work well with high-temperature,

viscous and sticky substances. The wood oil

tank was especially difficult because it oper-

ates with a vacuum, and its measurement

device has to cope with vapor, mist and a tar-

like buildup on its probe that could degrade

signals. Consequently, Red Arrow’s wood

oil tank was migrated to a Rosemount 5300

GWR transmitter with one rigid probe and

Signal Quality Metrics (SQM) software from

Emerson Process Management.

“In the past, occasional unplanned shut-

downs due to probe failures or coating

issues would upset our process, reducing

product throughput and increasing en-

ergy use,” says Barry Schardt, Red Arrow’s

equipment manager and electrical engineer.

“Since we installed Emerson’s GWR trans-

mitters a few years ago, we haven’t had

premature shutdowns during a production

run due to level probe failure.”

GWR isn’t affected by pressure and vapor-

space changes, and SQM provides diag-

nostic information that relates directly to

the coating on the probe and to changing

surface conditions. These values can be

assigned as process variables and tracked

over time. This means Red Arrow’s staff can

use their SQM data to maintain ideal operat-

ing conditions and improve product quality

over extended, continuous runs.

“We’re seeing more acceptance of radar

technologies as they mature, and GWR is

growing faster than other level technolo-

gies,” says Christoffer Widahl, senior product

manager for new level programs at Emerson.

FLY THROUGH THE AIRAs capable as GWR is in many applications,

there are others where through-air/non-con-

tact radar is indispensable for getting pulses

through and securing accurate signals.

For example, Sibelco UK ships 750,000 to

800,000 tons of red and white silica sand

STORING SANDFigure 1: Sibelco UK’s quarry uses flush-mount-ed, non-contacting Sitrans LR560 through-air radar level measurement transmitters from Siemens to avoid abrasive damage. They oper-ate at a higher frequency of 78 GHz and use a narrower 4° beam angle to make sure their level measurements are accurate.



per year from its 12-15-meter-deep quarry

in Arclid, Cheshire, U.K. The white sand is

used for making glass, and the red sand is

used for playing-field drainage, animal bed-

ding and other purposes. Once the sand is

conveyed, cleaned, conditioned, graded and

sorted, it’s stored in 20- and 49-meter silos.

These silos previously used GWR, but the

abrasive sand was hard on the contact de-

vices, and forced technicians to adjust them

often to get accurate level readings. As a

result, Sibelco recently switched to Sitrans

LR560 through-air radar level measure-

ment transmitters from Siemens. Operating

at a higher frequency of 78 GHz and using

a narrower 4° beam angle, LR560 ensures

that level measurements are consistently

accurate. And, because the transmitters are

flush-mounted and non-contacting, Sibel-

co’s technicians don’t need to worry about

the abrasive sand affecting the instruments.

“The LR560 needs very little, if any, mainte-

nance,” says Adam Daniels, Sibelco’s opera-

tions unit manager. “We’re pleased with the

time savings we’ve gained from using these

transmitters.”

Herman Coello, level market manager at

Siemens, adds, “Ten or 12 years ago, you

had to be an expert to set up a radar level

transmitter, but today they’re super simple

and can be set up in a couple of minutes. To

avoid overspills and fines, radar solutions can

also be combined with secondary technolo-

gies such as mechanical floats, electronic

capacitance devices or point-level switch for

vessesls needing alerts and alarms.”

Similarly, Aston Martin Lagonda Ltd. in

Gaydon, Warwick, U.K., adds up to nine

coats of paint to its auto bodies during a

50-hour process.

As a result, its paint shop must be carefully

controlled. This includes its water recycling

application and 3.5 x 5 x 8-meter coagula-

FOAM FIGHTER Figure 2: The coagulation tank at Aston Martin’s paint shop uses a VegaPuls WL61 through-air radar sensor and its signal-focusing, 80-mm antenna to penetrate foam, secure millimeter level readings, maintain optimum water levels in the tank and prevent overflows.



tion tank with 140,000-liter/minute effluent

flow, where entrained solids are removed

(Figure 2). At the inlet, two transfer pumps

force the incoming stream downwards,

aerating the water to accelerate and im-

prove the separation process. The coagu-

lated solids settle at the bottom of the tank,

and the clean, aerated water at the surface

flows over a weir to be further treated and

reused. The solids at the bottom are period-

ically pumped away for drying and disposal.

Because effluent treatment problems can

quickly halt painting and production, As-

ton Martin’s engineers report it’s crucial

to maintain optimum level and prevent

overflow in the tank. However, this can

be difficult because the water’s surface

is turbulent, it foams readily and heavily,

and buildup on any contact device quickly

causes problems. In fact, after installing a

GWR and trying point level switches, they

found the heavy, unpredictable buildup and

contamination on the probes was so severe

that they caused false readings and needed

frequent cleaning.

Consequently, a couple of years ago, Aston

Martin’s engineers changed out its contact

devices and implemented a contactless Veg-

aPuls WL61 radar level sensor. It’s designed

for water/wastewater applications, features

an IP68 housing with an encapsulated an-

tenna that’s ideal for harsh, effluent-plant en-

vironments, and is suited for them because

the liquid density and substances contained

in the liquid have no bearing on measure-

ment accuracy. Most importantly, VegaPuls

WL61 can cope with all reasonable levels of

foam due to its signal sensitivity and 80-mm

antenna that focuses its signal.

“The readings we now get are to the mil-

limeter, which is extremely accurate, and

allows us to have a greater level of control,

especially as this measurement also governs

the water make-up valve, which operates to

re-level the tank as water evaporates due to

“The readings we now get are to the millimeter, which is extremely

accurate, and allows us to have a greater level of control,

especially as this measurement also governs the water make-up

valve, which operates to re-level the tank as water evaporates

due to the process,” stated Aston Martin’s engineers.



the process,” stated Aston Martin’s engi-

neers. “All of the control strategy for the co-

agulation tank water system was rewritten

after installation due to the radar level sen-

sor’s greater level of accuracy, and so far

we’ve enjoyed a 100% efficiency rate. The

safety surrounding the tank has also been

increased because we don’t have to enter

the guarded area around the tank to clean

off buildup. Being non-contact is ideal in

this application, so if the pit is cleared out,

we don’t risk any sensor damage either.”

Jeff Brand, product manager at Vega Ameri-

cas Inc., reports that it’s improving perfor-

mance of both through-air and GWR with

more powerful, less costly microprocessors.

“Better chips allow level measurement devic-

es to send and receive more pulses quicker,”

says Brand. “Those rates have doubled over

the past five years, so we have much better

resolution and signal processing, and we’re

able to resolve levels faster and more accu-

rately. The typical accuracy for our through-

air products is ±1 mm where it used to be ±8

mm, and this means better inventory control

and decision making for users.”

Beyond radar, some developers and users

are implementing sonic scanners and laser-

based devices to map material surfaces in

vessels and help calculate their volumes and

contents. For instance, Anglo Gold Ashanti’s

(AGA) Moab Khotsong mine contributes

16.4% of the gold ore used by AGA’s South

African operations. The ore is stored in 10

x 22-meter silos that can hold up to 10,000

tons, but grizzly bars across an aperture at

the bottom of the silos must always be cov-

ered by enough material to avoid damage

or blockages caused by rocks and gravel

entering the silos.

As a result, AGA recently adopted Rose-

mount 5708 3D acoustic solids scanners in

its gold ore silos to provide reliable content

volume measurements. The resulting 3D

graphical output of the mapped surface al-

lows AGA’s site operations team to monitor if

there’s sufficient gold ore for production and

make sure it’s spread out enough to cover

and protect the grizzly bars. They also enable

the team to see from a safe location if bridg-

ing or buildup is happening inside the silo.

“The 3D solids scanner provides us with

accurate measurements in our large silo,

which allows us to protect our equipment,”

says Ernst Smith, C&I manager at AGA.

Similarly, ABB K-Tek recently released its

VM3D volumetric measurement, 3D laser

scanner that can form 3D maps of stockpiled

solids in vessels. “Uses can use VM3D to laser-

trace profiles of chemical, fertilizers, coal,

potash and other materials to more accurate-

ly determine their inventories,” says Charles

Richard, ABB K-Tek’s global products man-

ager for radar and magnetostrictive products.

MULTITASKING MEASUREMENTThough level methods haven’t changed



much at their roots in recent years, they

have been combining technologies for bet-

ter measurement, joining with microproces-

sors and software that make sensors and

level transmitters smarter and more capa-

ble, and using networking and data man-

agement tools that help users make better

decisions based on their analyses.

Gene Henry, senior product manager for

level at Endress+Hauser, reports that E+H

launched its Levelflex FMP55 multiparame-

ter device a couple of years ago to combine

guided radar and capacitance in one com-

ponent. This cooperation is useful in level

applications with an emulsion layer, and it’s

even more helpful when there isn’t a clear

separation between these layers.

“With a rag layer like this, the overall radar

signal can get lost sometimes, and when

this happens, our FMP55 can automatically

switch to capacitance,” explains Henry.

“Basically, the FMP55 provides two out-

puts. One is the overall guided radar, while

the other can interface with capacitance or

guided radar. Many products are separated

by density, but now users no longer need to

have two devices.”

Richard adds that ABB K-Tek’s Magwave

solution combines magnetostrictive, GWR

and local float components in one device

with one set of process connections, and

can add magnetically actuated switches

to the float. “This is a dual-chamber de-

vice,” says Richard. “The GWR measures

liquid and produces a 4-20 mA signal; the

magnetostrictive device detects the bullet

float inside and has a 4-20 mA output; and

the float and magnetic gauge have a local

indicator. Having two independent and re-

dundant transmitters and a local indicator is

getting popular because they’re safer.”

Henry agrees that more powerful, less

costly microprocessors, software and algo-

rithms are enhancing level measurement

capabilities and coordination. “The real in-

novations in level today are on the software

side because we can use more of the data

we’re getting from the same instrumenta-

tion,” says Henry. “So if we’ve got foam, and

we’re monitoring the signal strength of free-

air radar coming through it, we can now

evaluate that signal with software, quantify

how much foam is developing based on

how much the output signal strength is di-

minished, and decide when and how much

defoamer to add. Previously, defoamer was

added periodically, which meant too much

was used at too much cost.”

Jim Montague is executive editor of

Control magazine, and has served as

executive editor of Control Design

and Industrial Networking magazines.

He’s worked for Putman Media for more than 10 years,

and has covered the process control and automation

technologies and industries for almost 20 years. He

holds a B.A. in English from Carleton College and lives

in Skokie, Illinois.

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Controlling levels of parallel separatorsBy Béla Lipták

QWe have a horizontal separator that works under level control (with gas-blanket-ing on top) and feeds a set of parallel-operating pumps. The level control valve (LCV) is at the pump discharge header, and gets the control signal from the level transmitter (LT) on the separator.

To handle increased influent flow rate to the existing separator, a new separator roughly

half the design capacity of the existing one will be added to work in parallel. Two new

pumps will be added to handle the additional effluent from the new vessel.

The separators are for separating oil from water. The exact size of the new separator is un-

known for now as it is yet to be sized. Operations people want the new separator to have the

same diameter and to operate at the same normal liquid level (NLL) as the existing separator,

so the liquid level in both vessels could be controlled with one level control valve at the pump

discharge. The operators’ wish is not the designer’s of course, as the separator dimensions and

NLL are dictated by residence time considerations, and fixing it because of level control consid-

erations is perhaps not a step in the right direction.

I’d be obliged if you could review the three sketches A,B and C (Figure 1) and comment on

how to best control the levels in the two vessels.

Farooq Ghilazi / [email protected]

mailto:farooq.ghilzai%40gmail.com?subject=



AOption A will work if the inlet flow distribution is guaranteed by hy-draulic design, and is the easiest to imple-

ment. Another option is described below,

which will also work, but is not necessarily

superior.

The key to good separator control is keep-

ing residence time (volume/flow) above the

required minimum for good separation. In

addition, good blanketing gas, water inter-

face level control and oil level control are

required. For the purposes of this discus-

sion, the gas pressure and the interface

controls are assumed to be properly de-

signed.

When controlling two separators in paral-

lel, distribution must also be controlled.

In Figure 2, I assumed that the distribu-

tion is 2:1 and is taken care of by hydraulic

design. If it is not the case, a flow ratio

control loop must be added. This addition

naturally not only increases the first and

maintenance costs, but also, because it

increases turbulance, increases the resi-

dence time required and therefore lowers

separation capacity.

As to oil-level control, one should equal-

ize the oil levels in the two separators by

desiging a balancing pipe that is hydrauli-

cally capable of balancing the levels, and

can also be used as the pump station’s

suction manifold. In that case, when both

separators are in operation, the level mea-

surement is obtained by averaging the

two transmitter signals. When operating

only one separator, this averaging func-

tion is bypassed.

As to the pump capacity controls, I would

not waste energy by valve throtting on the

discharge side of the pumps. Instead, my

SECOND SEPARATOR IS SMALLERFigure 1: To handle increased influent, a new separator roughly half the capacity of the exist-ing one will be added in parallel, with two addi-tional pumps. What’s the best way to control the levels in the separators?

LT

LT

A

B

C

D

E

LT

LT

AA

B

C

D

E

LT

LT

A

B

C

D

E

Solution A

Solution B

Solution C

Existing processModi�cation



preference is to have at least one variable-

speed pump in the station, so that pump-

ing capacity can be modulated without

energy waste.

For a good book on hydraulic design for

residence time determination, refer to

“Chemical Engineering Research and De-

sign.”

Béla Lipták / [email protected]

QIt seems to me that the residence time in one separator can’t be mod-eled after the time in another. It might work

if both separators are identical and cleaned

frequently. It also might work if an operator

periodically, physically checks the interface

levels in both separators. I don’t know what

he’d do to fix an imbalance—possibly stop

a pump for the low tank. Operations won’t

like that.

Maybe it would work if the inlet flows were

controlled according to the size difference.

If you tell operations that they have to add

two flow control loops to save one level

loop you would get the correct result, which

is separate level control loops. Also, throt-

tling inlet flow could further mix oil and

water, increasing the separation/residence

time, which increases the tank size for a

given flow.

Maybe it would work if one of the new

pumps had variable-speed control, which is

set by a separate level controller in the new

tank. You’d need logic to start the other

pump if the variable pump got to 80% of full

speed or so. That saves the cost of a new

valve and its installation and maintenance.

Disclaimer: I’ve designed and started up con-

trols for many things, but not separators.

Bill Hawkins, HLQ Ltd. / [email protected]

Water

Water

Flow = 100% 67%

33%

LT

Ave

LT

LC

Large-diameter balancing pipe

PAY ATTENTION TO HYDRAULICSFigure 2: When controlling two separators in parallel, distribution must also be con-trolled. Here, that is done by hydraulic design; otherwise a flow ratio control loop must be added. Equalize the oil lev-els with a balancing pipe, and use a variable-speed pump to avoid wasting energy.

http://www.sciencedirect.com/science/article/pii/S0263876204726271http://www.sciencedirect.com/science/article/pii/S0263876204726271mailto:[email protected]:[email protected]



AFigure 3 shows a simplified sketch of how you may be able to connect the two separators to a common inlet and

outlet header. The level indicating control-

ler (LIC) will control the valve in such a

way that the highest level is pumped down,

and with the High-Low selector, you can

automatically or manually select any of the

separators. This way, if the level is too low,

you can stop pumping.

This, to say the least, is a simplified sketch.

For detailed loop design, more data needs

to be analyzed.

Alex (Alejandro) Varga / [email protected]

AYou’re correct to be concerned about how the tanks are tied together. One way I can see to possibly make it work would

be to have a separate, “large enough” bal-

ance line between the tanks, but that would

require modifying the existing tank.

Otherwise, what the individual levels end up

being depends on the hydraulic balance on

the inlet piping and the outlet piping. You

can end up with one tank on high level or

one running empty.

Another possible solution would be to

re-arrange the piping, so you have a larger,

common suction header to the pumps. This

will mean that it can act as a sort of bal-

ance line, and then you would run the con-

trol on high-level override, with the valve

controlled by whichever level is the high-

est. I’m not sure this will work; it’s a ques-

tion for the process engineers to confirm.

But the real solution is not in the controls;

it has to be a workable hydraulic design.

Simon Lucchini, Chief Controls Specialist /

[email protected]

This series is moderated by

Béla Lipták, automation and safety

consultant and editor of the Instru-

ment and Automation Engineers’

Handbook (IAEH).

CONTROLS LEVELS AT THE PUMPFigure 3: The level indi-cating controller (LIC) controls the valve so the highest level is pumped down, and the High-Low selector allows automatic or manual selection of the separators. If the level is too low, stop the pumping.

LT

LIC

Separator 1

Separator 2

LIC

HS

LT

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Advanced control for boiler drum level?By Béla Lipták

Q I read some papers regarding boiler drum level control and almost all mention that, for better performance, we should go for fuzzy logic controllers or model-based controllers instead of traditional PID controllers. However, in those papers, the results are obtained by simulating through Matlab. So I want to know, is it possible to

implement such controls?

Swastik Bhandari / [email protected]

AThere is nothing fuzzy about boiling water. You should use a three-element feedwater control system on large boilers to arrest disturbances and to rapidly react to load changes.As shown in Figure 1, in a three-element feedwater system, the water flow loop is closed.

This way, pressure disturbances that would affect the feedwater flow are handled immedi-

ately by the fast response of the flow loop. In addition to the three primary control variables

(three elements)—drum level, steam flow, and feedwater flow—drum vapor-space pressure

can also be utilized to compensate for density changes. The pressure is passed through a

calculator (DY in Figure 1) that calculates a multiplier to apply to the raw level signal. The

multiplier is based on the density change vs. pressure for saturated steam.

In making gain adjustments on a three-element feedwater system, the first step is to deter-

mine the relative gains between level and flow loops. By observing a change in boiler load,

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one can note the particular boiler “swell”

characteristics of the particular unit. Maxi-

mum system stability is obtained when the

negative effect of swell equals the posi-

tive effect of flow. For example, if a 20% of

maximum steam flow change produces a

20% change in the steam flow transmitter

output, and this flow change also produces

a 3-inch swell, which is 10% of the 30-inch

range transmitter output, then the gain of

the level loop should be double the gain of

the flow loop.

Feedforward can further improve the system

by maintaining the steam-water balance,

thereby reducing the influence of shrink-

swell and inverse-response. This loop keeps

the feedwater and steam flows equal as long

as the level is constant and on setpoint. Flow

measurement errors and the withdrawal of

perhaps 2.5% of the water as “blowdown”

(which is not converted to steam) will pre-

vent the two flow signals from being iden-

tical. Therefore, the level controller must

readjust the setpoint of the flow-difference

controller to strike a steady-state balance.

It is also desirable to precondition the level

controller, so the control system will work

during start-up or at other times when the

feedwater is controlled manually. This can

be achieved by external feedback from a

flow-difference measurement, from which

feedback is applied to the level controller.

Otherwise, an increase in steam or blow-

down flow will immediately increase the

feedwater flow, without waiting for the level

to change. If this feedforward configura-

tion is used, the controller mode settings

are less critical and shrink, swell or inverse-

response effects are further reduced.


AUsing model predictive control (MPC) for boiler drum level control is not advised. I’m not an expert on boiler control,

but there are many books devoted to this

topic, and you should be able to get some

additional help by searching for “advanced

boiler control” on the Internet. MPC is

complex and is usually used when there are

many interacting control loops, often with

significant dead times involved. Although

THREE-ELEMENT BOILER DRUM LEVEL CONTROLFigure 1: The fast response of the flow loop handles pressure distur-bances that would affect feedwater flow, while drum vapor-space pres-sure control compensates for density changes.

mailto:[email protected]



a modern DCS can implement small MPC

loops, off-line identification is often re-

quired to build the dynamic model.

Drum level is only one control loop of a typi-

cal boiler. Feed-forward control is often used

for boilers where there is a wide range of

varying demand and where the feedwater

is returned at varying temperatures, as from

steam condensate. Feed-forward control

is designed to remove the effects of load

variables as they make their way to the boiler

to remove these loads from the feedback

control loops around the boiler. Most pro-

cess control textbooks use boiler controls to

illustrate the use of feed-forward control. For

more on three-element boiler feedwater con-

trol, read this informative article, “Cascade,

Feed Forward and Boiler Level Control.”

Dick Caro / [email protected]

ABack in the 1980s, in my C&I Training room in a power plant in Hong Kong, I had a control simulator that simulated

shrink-and-swell effects using hardwired

B&W Series 4 control modules, the same

equipment being used in the plant (4 x 350

MW power plant) at the time. The trainees

used the fastest recorder available at the

time to trace the effect of drum level-based,

three-element control as the load (Boiler

Master) changes, and produced hard cop-

ies of the recorded signals (drum level, feed

flow, steam flow and steam pressure) and

the various tuning parameters of the PID

controllers as the load changed.

They were aiming at the fastest recovery

and minimum area under the curve of the

drum level signal. The tuning parameters

were used to compare with those in the real

plant under supervision by the Control Parish

Engineers in the marshalling area. The results

were, of course, different because in the real

plant there were other major parameters

to be considered and closely monitored by

Operations. These included (but were not

limited to) the drum skin temperature and

its rate of change (to be strictly followed

according to design based on size of the unit

and pressure ratings—this being 1.56 °C/min-

ute at all times, particularly at start up, when

only single element was used).

In the 1990s, in another power plant in

Canada, I remember using principal compo-

nent analysis in conjunction with other vari-

ous tools to identify the key parameters (no

greater than six out of hundreds in boiler

controls) for steam pressure (and flow). Yes,

I agree with you that PID, model-based, fuzzy

logic, etc., are just tools for computation.

Finding the right primary parameters for con-

trol and experience are necessary in pursuing

the answer to this minimum-phase control

problem for boilers of specific sizes. I’m not

sure if Matlab has all its problems solved.

Gerald Liu / [email protected]

AWhen I read papers on advanced controls, one of the first things I check is if it was actually implemented in the real

world or simply simulated on a computer.

http://www.controlguru.com/wp/p44.htmlhttp://www.controlguru.com/wp/p44.htmlmailto:RCaro%40CMC.us%20?subject=mailto:[email protected]


Many “control advances” work extraordi-

narily well in lab simulations, but seem to wilt

and stumble when faced with the messiness

of actual plant operations. As to your ques-

tion, I can say that after 30 years of plant

experience in a variety of industries including

chemical, pulp and paper, mining and oth-

ers, I have yet to see a boiler level running on

fuzzy logic. That is not say it doesn’t exist,

but it certainly isn’t commonplace.

Three-element control isn’t new or sexy, but it

works reliably and robustly in a huge number

of boilers. It is relatively easy to implement

and easy to tune, and operators understand

it. No doubt there are special applications

(very small boiler drums, very high pressures,

wildly gyrating steam and heat loads, etc.)

that may warrant something more involved

than a standard three-element control, but in

the vast majority of applications, it works very

well and is infinitely easier to set up.

If a boiler is exposed to outside disturbances

(such as wild swings in steam load on the

header), you will find that insulating the boiler

using back-pressure controllers and/or auto-

matic vents on the header will work far better

than expending a great deal of effort on

implementing complicated level controls that

probably won’t handle the upset anyway.

P. Hunter Vegas / [email protected]

This series is moderated by Béla Lipták, automation

and safety consultant and editor of the Instrument and

Automation Engineers’ Handbook (IAEH).

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Remote tank gaugingBy Béla Lipták

QRemote level monitoring? Figure 1 shows our hydrostatic tank gauging (HTG) system. Do you have a device or combination of devices that can replace the hydrostatic interface unit (HIU) and application interface module (AIM)? They are now unsupportable.

I’m open to a new communication protocol/fieldbus and possibly changing the field instru-

ments for compatibility, but my constraints are: no laying of new instrument/power/home-

run cables; field is Class I, Div. 2 hazardous location; no shutdown or tank depressurization;

and no new instrument impulse lines. Distance from field to control room is about 500 me-

ters. Note that field instruments don’t have individual cables, but are daisy-chained on one

twisted pair to the HIU.

The transmitters have isolation valves, and can be replaced without shutting down the

process. The RTDs are insert type. There are five tanks in total with four storing products at

sub-zero temperatures. The instrumentation on each tank is fully redundant, i.e. two sets of

transmitters per tank on two networks.

My thought is that there should be a HART (or some other bus) device out there that can poll the

transmitters in turn, perform the level computation, and communicate output to the host systems.

The device can even be placed in the control room. I just haven’t found any of them yet.



I have checked Honeywell’s HTG system

based on FDI 877, but it requires separate

AC power supply, and hasn’t been con-

firmed to be capable of powering three

HART transmitters in daisy chain (versus

individual wires from each instrument). I’ve

also considered battery-powered wireless

HART transmitters communicating to a

gateway, but that solution has its cons.

Olusegun Komolafe / [email protected]

AIn your present installation, I consider the “fully redundant transmitter” ap-proach outdated. The cost of three trans-

mitters is usually less than the cables plus

increased maintenance of the redundant. I

prefer three because in a redundant sys-

tem, all you know is that one is wrong, but

you don’t know which one. Since you have

shutoff valves on the pressure transmitters,

installing three of them is no problem.

Once you have a voting system, you can use

wireless transmitters, because the system

will automatically report which transmitter is

the one that needs maintenance or battery

replacement. Smart, wireless transmitters can

also be useful if you want historical trend, in

and out flow, vaporization loss or other, more

sophisticated displays or calculations.


AMoore Industries makes a HART-to-Modbus converter (HCS) that might handle this application. Here is a link.

Without chasing all of the details, I don’t

know for certain that it will work, but either

this product (or a similar one) might be a

good place to start

Hunter Vegas / [email protected]




OBSOLETE INTERFACE MODULES PRESENT COMMUNICATION CONUNDRUMFigure 1: Are there HART or other bus device(s) that can replace the functions of the shaded area?

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QInstallation differential pressure transmitters on tall towers (inlet and outlet) for vapor service has been a big problem for me. I have mounted a differential pressure (DP) transmitter above the outlet line of the tower with its low-pressure side con-nected by a sloping tube to the outlet pipe, and high-pressure side connected to the tower inlet

pipe with a 14-meter-long tube. We have two pressure gauges on the inlet and outlet pipes

showing 3 PSID while the DP cell reads 600 mbar (9 PSID). What is the problem, condensation?

What is the remedy, increasing slope or insulation? A similar case has not been resolved, and I

had to use two pressure transmitters (PT) to get software differential value. When I touch the

low tapping, its temperature is colder than the other leg. Butene is the measured vapor.

Rahim Romel / [email protected]

AThe left side of Figure 1 shows my understanding of what you have now and on the right I am showing what I would do to fix your problem. In general, I do not like to use conventional DP cells to measure the pressure difference between points that are at different

elevations, because the lead lines can introduce errors due to condensation, or due to errors

caused by differences in temperature or density on the two sides of the cell. These problems

can be reduced by using capillaries or pressure repeaters, but why bother? The best solution

in my experience is to use two good pressure transmitters and measure the difference be-

tween their outputs, as shown on the right of Figure 1.


Experts weigh in on distillation plant measurement problemsBéla Lipták and his crew tell how to resolve difficulties with measuring column differential pressure and flows of flare and natural gas

By Béla Lipták

mailto:[email protected]:[email protected]



AFlowmeter engineering is intertwined with deep understanding of pro-cess, process behavior, operational ranges,

process thermodynamics, and flow system

engineering as to what is the objective, for

example, custody transfer, process control

or flow indication as the questions indicate.

Instrumentation engineering is applied sci-

ence, requiring more knowledge than just

transmitters and orifice plates.

Your transmitter leg on the high side is very

long compared to the low side, and be-

cause of this the effect of the fluid thermal

expansion/contraction in the impulse line

has a potential of giving you this error. As

you know, the coefficient of thermal expan-

sion varies by the cube of the expansion

coefficient. Insulation of the impulse tubes

may help—my suggestion would be to use

capillary-filled tubes of equal length on both

the low and high side. Make sure the capil-

lary lengths of both legs are the same, and

are exposed to the same ambient condi-

tion. One leg should not be in shade and the

other in sun, because we want to negate the

thermal effects. The capillary should elimi-

nate the effect of phase changes etc., so it

would give a more accurate measurement.

Romel S. Bhullar, senior technical director,

Fluor Corp. / [email protected]

A Since the low pressure side of the dp cell is connected to the pressure tap at the top of the column, it is recommended

that the cell itself be located above that point

so that this low side will be self draining back

into the top outlet pipe. With this configu-

ration, the high pressure side of the dp cell

will have a very lead line connecting it to the

pressure tap at the bottom of the column

inlet pipe. Depending on the thermal insula-

tion used on the lead lines and on the tem-

peratures of the process streams at the in and

outlets of the column, there might be conden-

sation in these tubes, which might introduce

some errors. Yet, this configuration is still bet-

ter than locating the dp cell down at the level

of the inlet pipe, because then the lead line to

the low side will not be self draining, but can

fill and if it does, that side will become the

high pressure side. In any case you may need

to recalibrate the transmitter.

Alex (Alejandro) Varga / project & construction

management, Devco / [email protected]




Figure 1: Tower pressure drop measurement

ΔPT

P12

P11

P1-P2 = 200 mb

ΔPT= 600 mb

ΔP

PT1

PT2

You have Replace with
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