Flow Measurement - Control Global...flow measurement is the dynamics of the process itself. The majority of flow loops, especially for liquids (incompressible fluids) have very short

Flow Measurement

Spring, 2019

eHANDBOOK

TABLE OF CONTENTSHow IoT is enhancing the performance of control valves 4

Better communications improve the efficiency of operations and maintenance.

Wireless flow measurement 10

Power remains the essential challenge; here are ways to meet it.

Prevent pressure transmitter problems 13

Installation details make the difference in DP flow and level applications.

Steam isn’t simple 18

Phase changes and condensate flows complicate control of heated processes.

Flaring flows and sources 22

Why and how to use ultrasonic flowmeters for this demanding application.

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eHANDBOOK: Flow Measurement, Spring, 2019 2

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The world of Internet of Things (IoT) is

expanding rapidly. By 2025, the total global

worth of IoT technology is estimated to

reach $6.2 trillion. While by 2020, there

will be around 26 smart objects per every

human being on Earth. Contrary to the

popular belief, however, most smart devices

aren’t being use in your home or office right

now. Different industries including manufac-

turing (40.20%), healthcare (30.30%), retail

(8.30%), and security (7.70%) are the lead-

ing users of various IoT applications.

How IoT is enhancing the performance of control valvesBetter communications improve the efficiency of operations and maintenance

By Ann Neal

Source: flickr.com



In the recent years, the processing industry

has also started exploiting IoT technology.

One of the most critical and often over-

looked assets in the processing industry is

the control valves. IoT can be applied to

improve the performance and efficiency of

control valves, which in turn, will save main-

tenance costs and create a more secure

work environment.

Let’s see how IoT is enhancing the perfor-

mance of the control valves.

IMPROVED OPERATIONAL EFFICIENCYPerhaps the biggest benefit of IoT will be

improved operational efficiency of control

valves. In a typical processing plant, media

or fluids flow through processing equip-

ment. Control valves perform the critical

function of regulating process variables

such as pressure, temperature, and flow

rate. All these factors contribute to the

overall operational efficiency of the process

and the plant. Smart control valves can

improve operational efficiency in the follow-

ing ways.

Preventing Costly Valve Leaks

Most processing plants have to operate

under harsh physical conditions such as

extreme temperature and pressure expos-

ing the equipment to wear and tear. For

example, in an oil refinery, flare control

valves often end up leaking hydrogen and

hydrocarbons. Unfortunately, when exces-

sive pressure opens the valves up, there

is no way to close them completely. If

such leaks are not sealed off quickly and

effectively, they can lead to hundreds of

thousands of dollars in losses. It can also

turn into a safety hazard which may eventu-

ally bring the entire plant to a standstill.

Source: Wikimedia Commons

Source: Intel



That’s where an IoT system with smart

valves comes in. Usually, to detect

hydraulic hose or connector leakage,

wireless vibration sensors or acoustic

transmitters are embedded at the right

locations on the valve. These sensors send

notifications and data to a centralized

monitoring system. Usually, a simple trend

analysis of the recorded data is carried

out to see if a leak is likely to occur. Thus,

an IoT system can identify potential leaks,

avoiding unplanned downtime.

Troubleshooting Valve Misfires Due to

Voltage Sags

Voltage sags are the most common events

that affect the operational efficiency in

almost all processing plants. They are par-

ticularly common downstream, on long

runs. As the complexity of the equipment

used in a processing line increases, it

becomes more sensitive to voltage sags.

They can sometimes lead to valve mal-

function and cause irreversible damage

to equipment such as process controllers,

Programmable Logic Controllers (PLCs),

adjustable speed drives, and robots.

Solenoid valves, for example, can suffer

substantial damage as the reduced volt-

age at the wrong time will stop the needed

magnetic force from developing. Without

sufficient magnetic force, the spool inside

the valve will also fail to operate, resulting

in malfunction.

Voltage sags can occur due to faults on

either side of the meter. In other words,

you can’t blame your local power utility

every time a voltage sag accident occurs.

Your equipment or internal wiring may be

responsible for the accident.

However, it is almost impossible to diag-

nose the cause of voltage sag under

normal circumstances. You can use an

oscilloscope to monitor the voltage signal

at the time voltage sag occurs. However,

this isn’t a feasible solution for a process-

ing plant with hundreds of devices and

power cables.

IoT-enabled control valves can be modified

to collect and analyze voltage levels across

the processing line during specific peri-

ods of the cycle. You can alter each valve

manifold node to include a voltage sensing

device. You can record voltage levels across

the machine using a “sweeper” program for

particular time periods. This data can prove

invaluable in troubleshooting power issues

in your processing plant.

Real-Time Remote Access

As mentioned before, the primary function

of control valves is to regulate the flow

of liquids in a process. While the conven-

tional automated control valve systems

eliminated the need to switch on or off

the valves manually, one still needs to

access the main control panel to monitor



the valves. With IoT technology, however,

plant supervisors and engineers can shut

down or open valves or change their con-

trol parameters remotely.

Cloud storage allows plant managers to

share the data in real-time with all con-

cerned parties including plant supervisor,

resident engineers, and the original equip-

ment manufacturer (OEM). For example,

if you notice irregularities in the data

collected from a temperature-humidity

sensor, you can readily shut down the

respective valve using a smartphone

application or a laptop. Engineers don’t

need to be on the factory floor to control

the devices or the process. Most manufac-

turers have created web and mobile apps

to provide engineers with direct control

over smart devices.

LEANER MAINTENANCE TIME AND COSTSMost processing plants are looking for ways

to cut down maintenance costs and down-

time. However, the conventional approach

towards regular maintenance and repair

is time-consuming and expensive. But, IoT

technology can not only reduce the mainte-

nance costs but also decrease the resulting

downtime.

Real-Time Data Sharing with OEMs

Although large-scale plants can afford

to have skilled engineers and residents

on the factory floor round the clock,

most small and medium processing

plants can’t. They often rely on the OEM

equipment manufacturer to troubleshoot

the problem.

Manually calling the OEM, checking the

problem, and ordering the new valve is a

time-consuming and costly process. But,

with IoT, plant engineers will be able to

share the device data with OEM via cloud

storage in real-time. OEM will be noti-

fied of the problem directly. Thus, plant

owners can resolve the issue relatively

quickly, saving both money and time.

Predictive Control Valve Maintenance

Based on IoT

The conventional break-fix maintenance

approach is expensive. The next alterna-

tive is time-based maintenance in which

an entire section of the plant is shut

down for maintenance at regular inter-

vals, say once every month. However,

Source: Maxpixel.net



this approach is also costly and leads to

more downtime.

IoT offers a third alternative called pre-

dictive maintenance which is relatively

inexpensive and less time-consuming. In

this approach, the data collected from IoT

devices is used to track the efficiency, life

cycle, and potential chances of failure for

each device.

Each smart control valve comes with a

sensor that continuously monitors its phys-

ical properties. Usually, the monitoring

system compares the device data with a

pre-established baseline. If a valve starts

operating below the pre-set thresholds, the

system sends an alert to the plant supervi-

sor and engineers. Thus, you can replace a

malfunctioned valve well-in-advance, pre-

venting costly delays and product loses.

CONCLUSIONIoT technology isn’t limited to smart

homes and smart cars only. It is also

transforming the processing industry

through real-time monitoring and opti-

mization of control valves. It has lead to

efficient maintenance processes, elimi-

nation of unreliable manual intervention,

better worker safety, and reduced pro-

duction costs. Hopefully, seeing how

this technology is changing the pro-

cessing industry will encourage you to

be a part of it. Feel free to tell us more

about your IoT experience and future

plans in the comments here: https://

www.controlglobal.com/articles/2018/

how-iot-is-enhancing-the-performance-of-

control-valves/?stage=Live



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Flow measurement techniques con-

tinue to grow and evolve with

new methods such as multipath

ultrasonic, magnetic and Coriolis increas-

ing at the expense of more traditional

technologies such as orifice, weir and

other differential pressure (DP)-based

techniques. The increased use of these

new technologies is partly a result of the

increased capability of microprocessors

and sensors to enable measurements not

possible without enhancements in these

areas. Another reason for their adoption

is that, in most cases, they also provide

higher accuracy and rangeability than DP

technologies. But most of these flow mea-

surement techniques tend to require more

energy than DP flowmeters, and hence

aren’t well suited for deployment as wire-

less devices.

A colleague on one of the international

standards teams I belong to indicated at a

recent meeting, during a conversation on

wireless and batteries, that their company

has only been able to find one source for

a battery suitable for their wireless trans-

mitters to meet a 10-year service life. This

is, of course, with periodic recharging.

Other rechargeable batteries tend to have

‘memory’ and other problems resulting in

operating life of closer to five years.

A bigger concern with using wireless for

flow measurement is the dynamics of the

process itself. The majority of flow loops,

especially for liquids (incompressible fluids)

have very short process response times,

often in the order of seconds, unlike tem-

perature and level, which tend to be much

longer (arguably measureable in minutes).

Wireless flow measurementPower remains the essential challenge; here are ways to meet it.

By Ian Verhappen



Therefore, if using a wireless sensor for

flow control, you’ll need a rapid update rate

for the transmitter at a minimum, which of

course leads to short battery life, and con-

sequently make the economics for cable

look better.

Of course, it would help if it were possible

to develop the perpetual motion machine

and scavenge some energy from differ-

ent flowmeters to maintain or charge the

batteries. For example, if the frequen-

cy-shedding bar of a vortex meter, or

paddle/turbine in those forms of meters,

or pulsations in a positive-displacement

meter could drive some form of coil while

not affecting the measurement proper, this

would eliminate the energy concern for

each of these forms of meter.

One way to address the response time issue

is to increase the capability of the flow

device by adding the ability to perform as

a single-loop or self-contained flow con-

troller. Then the control loop only requires

transmission of the output to the final con-

trol element and remote HMI when such

a change is required, which isn’t likely to

be every sensing or update cycle (assum-

ing the control system can accept some

degree of dead band on the signal). If the

dead band isn’t acceptable, then having

the transmitter update the control system

for historian and measurement purposes

every cycle and the output directly to the

device “as needed” is a much more complex

situation of managing different update rates

from one device depending on data type.

An alternative to every-cycle updates that

may be acceptable is using a totalization

option for the update rate to the con-

trol system, which risks losing raw data

granularity. With all these features, the

transmitter is getting closer to the Open

Process Automation (OPA) forum’s vision

of a device control node (DCN), and closer

to a SCADA RTU field controller being

monitored and controlled (i.e., changing

setpoint) remotely from the central control

station. SCADA typically includes wireless

but again, with longer update cycles and

the need for intelligence at the field end.

As the above discourse indicates, moni-

toring versus controlling has a significant

impact on system design. The apparently

simple choice of monitor versus control

or custody transfer affects not only the

type of sensor required, but as we can see,

how that device interacts with the control

system and other devices within the con-

trol system. Though true for more than

flow measurement, the impact is more

pronounced with fast control loops such

as flow, regardless of how innovative we

try to be to overcome the basic principles

and reason for which the system is being

installed.



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G reg: You can’t control some-

thing if you’re not measuring it.

There have been great advance-

ments in measurement technology. Smart

transmitters have increased accuracy

an order of magnitude or more, and

drift is so slow that calibration intervals

can be significantly extended. However,

a measurement is only as good as its

installation. Not enough knowledge is

published or presented on how to make

sure the installation doesn’t limit per-

formance or create maintenance and

reliability issues. Here, Hunter Vegas and

I (cofounders of the ISA Mentor Pro-

gram) offer what we think is important.

The newest resource to our ISA Mentor

Program, Daniel Warren, has stepped up

to offer his personal experiences to help

guide our group. Daniel has over 35 years

of experience as a senior instrument and

electrical design specialist in oil, gas,

chemical, food, mining, utilities, water

& wastewater, and various pulp & paper

facilities, and is the owner of D.M.W

Instrumentation Consulting Services Ltd.

The most common flow and level measure-

ments often use differential pressure (DP)

transmitters with two impulse lines for

flow, and one impulse and an equalization

line for level. Pressure drops are also mea-

sured by a DP with two impulse lines. Many

pressures must also be measured and

controlled. Gauge pressure transmitters

vent the low side. Absolute pressure trans-

mitters have the low side sealed with a

full vacuum. Gauge and absolute pressure

transmitters (PT) have a single impulse

line. Consequently, a production unit can

Prevent pressure transmitter problemsInstallation details make the difference in DP flow and level applications.

By Greg McMillan



have thousands of impulse lines that are

often the weakest link.

The DP and PT installation method and

location should be designed to:

• Prevent a non-representative process

variable at the transmitter,

• Prevent extraneous effects at

the transmitter,

• Keep the fluid density, composition and

phase the same to both sides of the

DP transmitter,

• Minimize accumulation of solids

and bubbles,

• Minimize plugging, coating, corrosion,

and fouling of the impulse lines,

• Minimize time lag(s) from impulse lines

to the transmitter,

• Maximize signal-to-noise ratio, and

• Enable calibration and maintenance of

the transmitter.

The impulse and equalization lines, valves

and manifolds, as well as the transmitter,

must all have wetted surfaces, including

gaskets, O-rings and seals, constructed of

materials that can withstand the worst pro-

cess scenario. This could include corrosion,

temperature swings, sudden pressure and

vacuum swings, mechanical impact (ham-

mering), clean-out procedures, etc.

Let’s first address measurement of gases.

The goal is to ensure only gases enter the

lines, and any liquid drains back into the

process. The transmitter must be mounted

above the process connections with a uni-

form slope of at least 1 foot of elevation

change for every 10 feet of length, with

a greater slope being generally advanta-

geous. For horizontal pipelines, the process

connections should be at the top. For ver-

tical pipelines, the process connections

are on the same side as the transmitter. A

vent at the DP transmitter may be useful

for venting the accumulation of low-den-

sity gases (e.g., inerts) and for transmitter

maintenance.

Hunter: Another potential problem with

gas installations is gas condensation. If

the boiling point of the gas at maximum

operating pressures is less than ambient

temperature, the gases can condense in

the impulse line and cause intermittent

negative pressure spikes. In this case, the

process tubing must be heat-traced to

eliminate this issue. Note that steam also

can condense, but this case is handled dif-

ferently. (See steam section below.)

Daniel: I’ve seen a number of cases where

piping hasn’t been installed adequately to

ensure a sufficient slope for gravity drain-

age. I’ve also seen lines that are damaged

and twisted when other mechanical com-

ponents are installed as an afterthought.

I have “blow-down” lines installed for gas

venting when isolating and venting a trans-

mitter. This also gives me a location to tie

in a purge to blow any particulate, oils or

condensate back into the process line.



Greg: When measuring liquids or steam,

you need to ensure the lines are equal in

length, and filled with liquid that has the

same density and no phase changes. The

transmitter must be mounted below the

process connections with a uniform slope

of at least 1 foot in elevation for every 10

feet of length. Valves at the transmitter

should enable flushing and draining the

lines and transmitter.

Heat tracing must provide enough heat to

prevent freezing on the coldest day with

the coldest fluid, but doesn’t overheat the

lines and cause flashing (vaporization or

boiling) of the fluid on the hottest day with

the hottest fluid.

Hunter: It’s very important that the tubing

slope continuously from the process con-

nection to the transmitter. Any high point

along the way can trap vapors and cause

an improper reading. Also, the transmitter

connections usually branch off the main

impulse run. This is done so if there are

any solids in the impulse line, they’ll drop

into the line section above the blowdown

valves and not impact the pressure mea-

surement at the transmitter.

Daniel: The other thing to take into con-

sideration is the liquid itself. The process

conditions and product will make a dif-

ference in the materials and installation.

As an example, what’s used for water

may not be suitable for liquid natural gas

(LNG), diluent, chlorine, etc. Each of these

are requires certain materials for wetted

parts (tubing, diaphragms, O-rings, gas-

kets, etc.), and it’s always best to confirm

the requirements with the manufacturers’

tables. The other thing to consider is the

temperature and the specific gravity. The

rangeability as well as the materials them-

selves may put a limitation on what can be

used to accurately measure that particu-

lar process.

Greg: What more do we need to know

about steam installations?

Hunter: One might consider steam a “gas”

and mount the transmitter above the pro-

cess line with a heat-traced line to avoid

condensation. However, most transmitters

cannot handle the process temperatures

and will fail in short order. Therefore, a

typical steam installation will mount the

transmitter below the line, let the steam

condense, and thus protect the transmit-

ter from the high temperatures. As long as

both legs are equally filled, the water in the

line will not impact the DP reading, but it

will cause an offset for a pressure transmit-

ter that must be calibrated out. You also

need to freeze-protect the impulse lines,

and keep them warm enough to avoid

freezing but cold enough to ensure the

steam will condense.

Daniel: You don’t have to wait for the

steam to condense to fill the lines during



commissioning. Distilled water can be used

for this purpose. I’ve also used glycol to fill

the lines when setting up transmitters in

cold-climate locations. Seal pots are more

of an old school practice. Their primary

use is to act as a barrier between a harmful

process, such as a corrosive gas/liquid or

steam, and transmitter.

The ability to calibrate and maintain the DP

installation generally requires the vent/fill/

flush and drain valves mentioned above,

and a manifold or equivalent piping of

impulse lines that enable the same pres-

sure to be applied to both sides of the DP

for zeroing. The valves in the lines and

manifold must also allow the transmitter to

be safely removed with no exposure to the

process fluid.

Daniel: How you calibrate a transmitter

also depends on how it was installed and

the type (style) of transmitter. I’ve seen

a number of skid-mounted transmitters

(and older installations) that aren’t prop-

erly installed (isolated) to allow for a zero

and/or span adjustment. It’s also easier to

do a bench calibration as compared to a

field calibration. A field calibration can be

cumbersome, especially if you must have

an assortment of tools and test equipment

(air or nitrogen cylinders, hand pumps,

etc.). Also, testing is limited when you’re

dealing with an older style of DP as com-

pared to the smart versions.



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Greg: Steam is the most common

method of providing heat to a

process. We’re fortunate to have

Steve Huffman, vice president of market-

ing and business development for Mead

O’Brien, Inc., to give us inside knowledge

inside steam systems. Steve has been

providing incredible support for the auto-

mation profession. He was ISA president

in 2007, chairman of the Automation

Federation in 2007-08, and is current

chairman of Government Relations for the

Automation Federation. I’ve been working

with Steve in the review and expansion

of the Automation Competency Model

(ACM). Steve, why are steam systems

so pervasive?

Steve: Steam systems are the most effi-

cient means of heat transfer in industry

with more heat content per unit volume,

higher temperatures available for heat

transfer, and no need for pumping systems

to distribute steam to its intended points

of use. Unfortunately, a lot of knowledge

regarding steam systems as applied to

heat transfer is being lost due to experi-

enced practitioner retirements and failure

by newer engineers and technicians to

understand the thermodynamic properties

of steam and how they affect the system in

a heat transfer control loop.

Greg: How do we get into trouble?

Steve: Too often, steam system piping

designs tend to be like water or air sys-

tems without providing adequate drip

legs, separators and traps to remove con-

densate from heat loss in the distribution

Steam isn't simplePhase changes and condensate flows complicate control of heated processes.

By Greg McMillan



piping. Designers also fail to understand

that there are steam volumetric increases

occurring with pressure reduction and

higher pressure drops at higher flows,

which will affect the amount of steam

delivered. Once steam gets to the con-

trol valve, the wrong selection of inherent

trim characteristic will lead to other issues

when the control loop is operating at less

than full-temperature-rise conditions.

Since heat transfer surface area is sized

for the worst condition, there is more sur-

face area than needed for the throttling

condition where less temperature rise

is needed. Therefore, the normal con-

troller output tends to be low. Selection

of equal-percentage trim inherent flow

characteristic helps address the prob-

lems created by operating closer to the

closed position.

Greg: Why is valve sizing so critical?

Steve: Certainly, as in any process con-

trolled with valves, it’s up to the control

valve to deliver the benefits and cumu-

lative accuracy of the other control loop

components. As the final control element,

it needs to be precise (minimum backlash

and stiction) and provide a linear gain

(product of process gain and installed

flow characteristic slope that’s relatively

constant). That said, the steam system

has many other challenges that other

process loops may not have. The valve

can only work well if there is a properly

operating steam trap downstream of the

heat exchanger to stop the flow of steam

to allow transfer of latent heat BTUs from

the steam to the process, remove the

resultant condensate as it forms from the

heat exchanger, and remove non-con-

densable gases common with all steam

systems. When steam condenses in a heat

exchanger, the volumetric change from

steam to condensate is about 1,000:1 in cu

ft/lb depending on pressure. If the control

valve is throttling down steam flow as a

control response and therefore not replac-

ing the condensed steam with an equal

volume, then the system will head toward

vacuum or at the very least, leave very

little operating pressure for the steam

traps to remove condensate, as their

capacity is based on differential pressure

across the trap valve orifice. If there’s an

overhead condensate return, the static

head pressure created in the riser may

cause the trap to stall and be unable to

move the condensate to the overhead

return. In this case, it may be necessary to

add a pump, a pumping trap that can act

as both a pump and/or a trap, a combi-

nation of a mechanical pump and a trap,

or on/off control to maintain high volume

tank temperature.

Greg: What are some of the other problems

caused by condensate accumulation?

Steve: In the steam distribution system,

do not fail to include drip legs, separators



and drip steam traps to eliminate accu-

mulating condensate that can cause

differential shock water hammer. If there

is considerable unremoved condensate

sharing the distribution pipe, steam trav-

eling at a much higher velocity than the

slow-moving condensate will create a

wave action and the probability of a

dangerous slug from a condensate wave

bridging the internal diameter of the pipe.

The slug will accumulate more conden-

sate as it travels at the steam velocity. As

soon as the slug encounters equipment or

a change of direction, such as valves, tees

or elbows, serious damage may occur. If

sub-cooled condensate exists due to stall

or in a heat exchanger that is not drained

by gravity to the steam trap between

batches, sudden volumetric implosion of

condensing steam into cold condensate

may cause violent thermal shock and may

create a void that is violently filled by

the cold condensate, which may impinge

off itself to form shock waves and likely

damage equipment.

Greg: What about the effect of gases and

solids in steam?

Steve: Any type of non-condensable gas

acts as an insulator to heat transfer sur-

faces, greatly reducing thermal efficiency.

Carbon dioxide will go into solution in

cooled condensate, which creates very

corrosive carbonic acid (H2CO3). Piping

that has corroded from the inside out

likely has carbonic acid issues, likely from

not draining condensate. Oxygen speeds

up pitting corrosion from oxidation, again

by going into solution in cooled con-

densate. Particles, such as dirt and scale

carryover from a boiler, can cause fouling,

reducing the heat transfer coefficient, and

can interfere with the operation of some

types of steam traps types that aren’t able

to handle dirt well.

Greg: What do we need to know about

steam traps?

Steve: Steam traps must stop the flow

of steam into the condensate system,

remove condensate, preferably as it’s

formed when used in process duty, and

remove noncondensable gases. The trap

should be mounted at least 12 in. below

the heat exchanger as general practice

to allow for the gravity flow of conden-

sate from the heat exchanger. Since we’re

stopping the flow of steam to maintain

pressure and saturated temperature to

transfer latent heat, pressure doesn’t get

condensate to the trap. Frequently, pack-

aged equipment skids, particularly those

including plate and frame (P&F) heat

exchangers, don’t address the issue of

gravity flow to the steam trap. Trap sizing

and selection is critical. Both inverted

bucket (IB) and float & thermostatic

(F&T) traps are widely used for process

service, primarily because they’re able

to remove condensate as it forms, which



is a reason for their larger physical size.

Other attributes should be considered,

such as failure position, ability to allow

continuous flow of condensate from the

heat exchanger without backing up con-

densate, ability to handle dirt, higher end

capacity, ability to operate on low differ-

ential, air removal capability and service

life, just to name a few.

Greg: Can the right steam trap design and

installation solve all problems with conden-

sate removal?

Steve: I’d say that the right steam trap

design and installation is critical to effi-

cient condensate removal, but it doesn’t

solve all potential problems. Many plants

save on installation costs with modular-

ization of steam supply and condensate

removal equipment at some distance

and/or height away from process heat

exchangers, such as brew kettles in

breweries, cookers or process heaters in

batch process plants, steam coils in large

ducts or plenums, etc., sometimes due to

floor space restrictions, size or configu-

ration. This issue, frequently combined

with larger internal areas of heat trans-

fer equipment, makes it imperative that

supplemental devices be used to remove

these gases as quickly and as close as

possible to the area where they would

be entrapped: opposite the steam supply

connection of the exchanger.

Greg: More guidance and details on

supplemental devices is located at

www.controlglobal.com/articles/2018/

steam-isnt-simple.



Accurate flare flow metering is

important to account for production

and energy loss, closing the gaps in

the plant mass balance, and in reducing emis-

sions and protecting the environment.

Existing industry regulations and standards

provide helpful guidelines by defining the

acceptable accuracy limits for flare flow-

meters. The challenge has always been how

to reveal the flowmeter inaccuracy, and

minimize errors in flare flow measurement.

We’ve found practical tools to properly

select, configure, install, test and maintain

flowmeters in flare applications, and how

to determine the flaring source using the

Flaring flows and sourcesWhy and how to use ultrasonic flowmeters for this demanding application.

by Fawaz AlSahan

USING CLAMP-ON ULTRASONIC FLOWMETERS FOR FLARE

Clamp-on ultrasonic flowemeters can’t measure a low-pressure flared gas in a metallic pipe because

the flared gas has lower acoustic impedence than metallic pipes. This causes the acoustic signal to

travel in the pipe and not to the second transducer across the pipe.

To address this limitation, there are two solutions. One option is to increase the flared gas pressure,

which is difficult to accomplish. The other is to install a clamp-on flowmeter on a nonmetallic pipe.

This will lower the acoustic impedence of the pipe, and increase the possibility of acoustic signals

traveling across the pipe and measuring the flow. Using a nonmetallic pipe in the flare header is also

a challenging option, and will require a very comprehensive assessment before implementation.



built-in features provided by these flowme-

ter technologies.

Each of the different flowmeters used

for flare applications has limitations. For

example, differential pressure (DP) flowme-

ters such as orifice plates and pitot tubes

are sensitive to fouling and composition

changes, and will require frequent calibra-

tion. Conventional thermal flowmeters are

also sensitive to fouling, liquid and com-

position changes, and will require frequent

calibrabtion unless they have automatic

composition measurement and correction.

Vortex flowmeters also have limitations in

sensitivity to fouling and liquid, maximum

flow capacity and maintenance difficulties.

An experiment (Table I) was carried out

to demonstrate the possible errors in

flare flow measurement using different

types of flowmeters with different gas

compositions. Because of the accura-

cies demonstrated in Table I and the

above considerations, this article focuses

on the use of ultrasonic flowmeters for

flare applications.

FLARE FLOWMETER CHALLENGESFlare applications introduce many

* The approximate measurement error under constant flow conditions when using a fixed composition of 1% CO2, 0.9% H2S, 97% methane, 1% ethane and 0.1% propane and the flare composition changes to:Case 1: 0.53% CO2, 0.47% H2S, 51.08% methane, 0.53% ethane, 47.39% propaneCase 2: 0.4% CO2, 0.36% H2S, 38.8% methane, 0.4% ethane, 0.04% propane, 60% hydrogenCase 3: 12% CO2, 0.8% H2S, 86.22% methane, 0.89% ethane, 0.09% propaneSource: API MPMS 14.10

Actual volume Standard volume Mass

Case 1—Propane increased

Differential pressure meter 34% 34% 25%

Thermal flowmeter 2-15% 2-15% 35-45%

Velocity meter (optical, ultrasonic, vortex) 0% 0% 0%

Case 2—Hydrogen added




Case 3—CO2 increased




TABLE I: ERRORS RELATED TO USING A FIXED COMPOSITION*



challenges on flow measurement and flow-

meters, the major ones being:

• Flare can have a very low flow (0.01 m/

sec) and a low pressure drop across the

meter (typically 0.5 psig) is required.

• The flow can be non-axial and asym-

metric. Laminar-turbulent transition flow

introduces inaccuracy, and stratification

(by sun or wind) can happen and affect

the flow profile. Pulsating flow is also pos-

sible as the gas entry to the flare header

is not continuous.

• High flow may causing low signal-to-noise

ratio and probably liquid carry-over. High

CO2, H2S, N2 and H2 can cause attenuation

to the signal.

• Flare flow has a large turndown (2,000-

4,000:1) and the gas composition

is variable.

• Primary flow elements have uncertainities

due to electronics drift, metrological (pipe

diameter, alignment) and process buildup.

Secondary instruments (temperature

and pressure) have uncertainty due to

electronics drift, mounting location and

process buildup.

• The application might require a dual-path

ultrasonic flowmeter (i.e., two sets of

transducers) to either improve accuracy,

cover very low flow conditions, or reduce

the straight piping requirement.

ULTRASONIC PRINCIPLE OF OPERATIONUltrasonic flowmeters (UFM) can be either

insertion or cross-pipe. Both types are

installed as single- or dual-path. These

flowmeters (Figure 1) determine the flow

velocity and speed of sound by measuring

the difference in the travel time (tab - tba) for

a pulse moving from one transducer at one

side of the pipe to another one at the other

ULTRASONIC ESSENTIALSFigure 1: Ultrasonic flowmeters determine the flow velocity by measuring the difference in the travel time (tab - tba) for a pulse moving from one transducer at one side of the pipe to another one at the other side (tab ) and vice versa (tba ). Secondary instruments for pressure and tem-perature are required to calculate the volumetric flow at standard conditions. Source: API MPMS 14.10, ISO 17089-2

A

B

Lp V0

Tertiarydevices

Primarydevices

Secondarydevices

Secondarydevices

Not coveredin thisstandard

To flare



side (tab) and vice versa (tba). The transduc-

ers are inserted through the pipe wall, either

by hot tapping or as an inline flowmeter

(installed on a spool pipe). The flowmeter

calculates the flared gas velocity (V), vol-

umetric flow at operating conditions (Qact)

and volumetric flow at standard conditions

(Qstd).

Sound velocity (C) is also calculated by

this flowmeter. The value of sound velocity

is used to estimate the molecular weight

(MW) of the flare gas mixture. A mathemati-

cal or graphical correlation is experimentally

extracted by testing many gas mixtures

and defining their sound velocity and MW

relationship. MW measurement helps in cal-

culating the density and therefore the mass

flow. Secondary instruments for pressure

and temperature are required to calculate

the volumetric flow at standard conditions.

The setup of these secondary instruments is

shown in Figure 1 or as advised by the flow-

meter’s manufacturer.

Referring to Figure 1, the main equations

are:

• V = [L /(2cosØ)] x [1/tab-1/tba]

• C = [L/2] x [1/tab+1/tba]

• Qact = V x pipe area

• Qstd = Qact x P/Ps x Ts/T

Where:

V: flow velocity

C: sound velocity

Qact: volumetric flow at actual

flow conditions

Qstd: volumetric flow at standard

flow conditions

L: distance between transducers

tab: time for signal travel from transducer a

to transducer b (and vice versa for tba)

T, P: operating temperature, pressure

Ts, Ps: standard temperature, pressure

SPECIFICATION AND TESTINGISO 17089-2 and BS 7965 define the

required flowmeter uncertainty in flare

application to be ≤10% for the flow above

a certain minimum limit. This uncertainty

can increase by 5% due to flowmeter

installation effects. The flare flowmeter

needs to be tested at the factory or at

a third-party calibration shop. The main

testing requirements are:

• Air is usually the testing media. A Reyn-

olds number is used to account for

differences in densities (between air and

flared gas composition).

• Expansion of the flowmeter shall be con-

sidered in high velocity.

• Testing shall cover 0.03 m/s to the max-

imum design velocity. The flowmeter

shall be tested at velocities 0.03, 0.15,

0.30, 0.61, 1.5, 3.0, 6.1, 15, 30 and 15 m/s

increments up to the maximum operating

velocity.

• The flowmeter shall be tested with the

same pipe size and upstream/down-

stream straight piping.

• Pressure transmitter accuracy shall be

maximum ±0.67 kpa.



• Temperature transmitter accuracy shall

be maximum ±2 °C.

• The testing facility shall be traceable to

NIST or equivalent national or interna-

tional standard, and shall be accredited

by ISO/IEC 17025.

• The factory and testing facility shall pro-

vide all the testing data and records of

the installation, configuration and diag-

nostics data at the test bench.

• The manufacturer shall provide the

flowmeter uncertainty and the installa-

tion effects.

• Testing shall be done at a low pressure

and at ramping up and down.

INSTALLATION AND COMMISSIONINGRequirements stated in API MPMS 14.10 and

22.3, ISO 17089-2 and BS 7965 will help

users reach an accurate flare flow measure-

ment. The major points to follow are:

• Manufacturer or manufacturer-certified

entity shall be responsible to install and

commission the flare flowmeter and all

secondary instruments. This will elimi-

nate critical problems, like transducer

misalignment.

• The end user shall decide early on the

installation approach (i.e., hot tapping,

cold tapping or a complete spool piece).

Definitely, the last option is the best

option as it will eliminate all installa-

tion errors.

• Transducers shall be retractable

to allow online removal for testing

and replacement.

• Recommended piping straight run is

generally 20 diameters (20D) upstream

and 10D downstream. This requirement

can be relaxed based on the specific

flowmeter installation and manufac-

turer recommendations, which must

be verified.

• The end user shall consider accessibil-

ity for flowmeter maintenance and gas

manual or automatic sampling.

• Pressure and temperature sensor mount-

ing locations shall follow the flowmeter

manufacturer’s recommendations.

• Vibration shall be avoided by selecting

the right location for the flowmeter and

its associated panel.

• Any control valve with noise attenuation

or fittings up or downstream shall be

checked, as this can produce interference

with the transducer pulses.

• The installation shall avoid

liquid accumulation.

• Rapid pressurization or depressurization

when removing or installing transducers

shall be avoided.

• Manufacturer shall provide the accuracy

impact when replacing any part or soft-

ware of the flowmeter system.

• The hardware serial numbers, firm-

ware and testing shall be submitted by

the vendor.



• All data and software configuration in

electronics are saved as a backup. After

commissioning, management of change

(MOC) is required.

FIELD VERIFICATIONTo verify the reading of an installed ultra-

sonic flare flowmeter, there are many

techniques. The steps and tools below can

be used:

• The flowmeter manufacturer shall be

requested to provide a written procedure

for functionality testing and verification,

inspection intervals and dimensional ver-

ification. Also, uncertainties and speed of

sound calculations shall be provided.

• Wall thickness, inclination angle of trans-

ducers, length of acoustic path, the pipe

internal diameter and pipe cleanness shall

be verified.

• Installed meter specifications and current

operating conditions shall be checked

to match the flowmeter’s specification

sheets and drawings.

• The installed flowmeter configuration and

serial number shall be verified with the

manufacturer requirements.

• Straight piping and installation of the

meter, pressure and temperature trans-

mitters shall be verified.

• Wiring shall be inspected for signs of

moisture or physical damage.

• Performance of the flowmeter using the

same transducers model and the same

installation setup at a calibration shop can

be checked. This is to verify the accuracy

of the installed flowmeter, considering the

same straight piping and mounting of the

current field installation.

• The ultrasonic flowmeter reading can be

verified using a secondary device such as:

1. A second insertion flowmeter (such

as a pitot tube).

2. Optical method (laser doppler ane-

mometer tracer), which requires a

steady velocity.

3. Tracer dilution technique: injecting

a gas (like SF6 or helium) and mea-

suring the flow rate increase using a

secondary flowmeter.

4. Radioactive tracer: introducing a gas-

eous radioactive tracer and inserting

two detectors to detect the passage

(based on transit time). BS-5857-2

can be referenced for details.

• The transducers and the electronics can

be verified using a zero flow box. This will

provide zero calibration of transducers, and

will also check speed of sound measure-

ment for air compared to the estimated

value (performed by the manufacturer soft-

ware). Also, zero testing can be done for

the electronics and cabling using dummy

transducers and checking the signals.

• Absolute speed of sound (C) comparison,

like injecting N2 and determining C.

• Verification of the ultrasonic flowmeter

can be also done by taking a sample of

the flared gas and measuring SOS, and

then comparing the measured value to

the flowmeter estimated SOS. Difference

shall be less than 0.25%.



• Another verification tool is comparing C

and the velocity reading of one path, and

comparing it to the second path. This is

only applicable for dual path measure-

ment (i.e., when two sets of transducers

are installed).

• Flaring volume could be estimated by

conducting mass balance or using pro-

cess simulation, and the result can be

compared to the flowmeter reading.

• Computational fluid dynamics (CFD). This

is a modeling and verification technique,

which is a cost-effective solution and

helps to reveal installation errors. Also,

it provides a correction for the flow pro-

file and the missing straight piping run.

The flow is modelled in 3-D coordinates

considering turbulence and wall rough-

ness. Manufacturers of flare flowmeters

or some flow calibration labs can provide

this service.

ONLINE PERFORMANCE MONITORINGUltrasonic flowmeters have the advantage

of providing online diagnostics. Diagnostics

can be used to check the health, perfor-

mance and the accuracy of the flowmeter

without the need to remove and physically

check, calibrate or replace any part. Once

the flowmeter is proven to be correctly

selected, installed and commissioned, diag-

nostic parameters can be collected and

used as a baseline for future online perfor-

mance monitoring.

The flare flowmeter manufacturer shall be

requested to provide detailed diagnostics

parameters along with their acceptable

limits. Having these diagnostics parame-

ters in the local display and also reflected

in the remote workstation (i.e. distrib-

uted control system) is crucial for online

performance monitoring. The main diag-

nostics parameters to be displayed and

monitored are:

• System diagnostics: Transducers and

electronics functionality check, flow

DETERMINING FLARING SOURCEObserving flared gas and not being able to

determine which operating flare branch it's

coming from is very frustrating for operating

facilities. In many circumstances, the source

of the flared gas is a leaking valve. However,

identifying which valve and from which oper-

ating unit is difficult and time consuming.

An ultrasonic flowmeter offers a solution

to this problem because the most valuable

advantage of the technology is the sound

velocity measurement. There's a determined

sound velocity value for every type of gas

and for every mixture of gases. Knowing the

sound velocity will determine the molecular

weight and composition of the flared gas.

Knowng the composition will help the oper-

ating facility identify the potential sources

of flaring. This is a unique feature of ultra-

sonic flowmeters.



profile. This diagnostic parameter helps

with the recalibration decision.

• Speed of sound (C): The measured C and

the actual C can be compared to check

the health of the flowmeter. Actual C is

calculated using a gas sample and the

flowmeter manufacturer software. Also,

compare the initial flowmeter C reading

and the current C.

• Signal strength/quality indicator: Sig-

nal-to-noise ratio (SNR) indicates the

quality of ultrasonic signals. Distribu-

tion of SNR among transducers might

indicate a source of a problem such

as noise.

• Automatic gain control (AGC) level: As

meter performance deteriorates, AGC

level increases and a fault happens.

• Flow profile: A change in flow profile indi-

cates viscosity changes and/or changes

to pipe wall roughness.

• Axial velocity through the flowmeter.

• Meter performance: The ratio of trans-

ducers good pulses received to rejected

pulses received. As the flow rate

increases, meter performance decreases.

Performance also decreases with a

decrease in pressure.

• Temperature: Can indicate stratification in

the gas flow.

Following the above steps will assist

end users in evaluating their installed

flare flowmeters and could also result in

modifying or even replacing existing flow-

meters to fix the system performance and

installation errors.

Fawaz AlSahan, engineering specialist and chairman

of instrumentaiton standards at Saudi Aramco, is a

Certified Engineering Consultant (SCE) and a Certified

Automation Professional (ISA) with more than 19 years

of experience. He can be reached at fawaz.sahan@

aramco.com.

References:

• APIMPMCH14.10, Metering flare application

• APIMPMCH22.3, Test protocol for flare gas metering

• BS7965, Guide to the selection, installation, operation

and calibration of diagonal path transit time ultrasonic

flowmeters for industrial gas applications (including

flare gas)

• How do you measure flare gas effectively with

clamp-on ultrasonic flowmeters? http://www.siemens.

com/

• ISO 17089-2, Measurement of fluid flow in closed con-

duits—ultrasonic meters for gas

• Saudi Aramco best practice (SABP-J-202)—flowmeter

for flare application



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