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
www.ControlGlobal.com
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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
eHANDBOOK: Flow Measurement, Spring, 2019 4
www.ControlGlobal.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
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eHANDBOOK: Flow Measurement, Spring, 2019 5
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
www.ControlGlobal.com
eHANDBOOK: Flow Measurement, Spring, 2019 6
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
www.ControlGlobal.com
eHANDBOOK: Flow Measurement, Spring, 2019 7
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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eHANDBOOK: Flow Measurement, Spring, 2019 8
badgermeter.com/control
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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
eHANDBOOK: Flow Measurement, Spring, 2019 10
www.ControlGlobal.com
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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eHANDBOOK: Flow Measurement, Spring, 2019 11
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MEASURED VALUE+ ADDED VALUE
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
eHANDBOOK: Flow Measurement, Spring, 2019 13
www.ControlGlobal.com
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.
www.ControlGlobal.com
eHANDBOOK: Flow Measurement, Spring, 2019 14
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
www.ControlGlobal.com
eHANDBOOK: Flow Measurement, Spring, 2019 15
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.
www.ControlGlobal.com
eHANDBOOK: Flow Measurement, Spring, 2019 16
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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
eHANDBOOK: Flow Measurement, Spring, 2019 18
www.ControlGlobal.com
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
www.ControlGlobal.com
eHANDBOOK: Flow Measurement, Spring, 2019 19
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
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eHANDBOOK: Flow Measurement, Spring, 2019 20
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.
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eHANDBOOK: Flow Measurement, Spring, 2019 21
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.
eHANDBOOK: Flow Measurement, Spring, 2019 22
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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
Differential pressure meter 31% 31% 45%
Thermal flowmeter 100-300% 100-300% 300-700%
Velocity meter (optical, ultrasonic, vortex) 0% 0% 112%
Case 3—CO2 increased
Differential pressure meter 9% 9% 8%
Thermal flowmeter 2-5% 2-5% 15-20%
Velocity meter (optical, ultrasonic, vortex) 0% 0% 15%
TABLE I: ERRORS RELATED TO USING A FIXED COMPOSITION*
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eHANDBOOK: Flow Measurement, Spring, 2019 23
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
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eHANDBOOK: Flow Measurement, Spring, 2019 24
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.
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eHANDBOOK: Flow Measurement, Spring, 2019 25
• 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.
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eHANDBOOK: Flow Measurement, Spring, 2019 26
• 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%.
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eHANDBOOK: Flow Measurement, Spring, 2019 27
• 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.
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eHANDBOOK: Flow Measurement, Spring, 2019 28
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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eHANDBOOK: Flow Measurement, Spring, 2019 29