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Pressure Measurement eHANDBOOK
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Safe and accurate level measurement in the chemical and petrochemical industries
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The VEGABAR 39 pressure sensor with switching function makes it
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This pressure sensor uses a metallic measuring cell capable of measuring liquids and gases up
to 130°C and pressures up to 1,000 bar. It can go anywhere with multiple output options, including
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TABLE OF CONTENTSUnderstand Instrument Capabilities 6
Proper data interpretation depends upon knowledge of a device’s limits
Think Straight About Orifice Plates 9
Insufficient flow conditioning often undermines measurement accuracy
Find the Real Maximum Pressure 12
Always consider static head when assessing pressure vessels
Additional Resources 15
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 3
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Adjustment via smartphone
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The Optibar LC 1010 submersible level probe with ceramic
diaphragm is a simple and continuous hydrostatic level
measurement solution for water wells, tanks and rainwater
retaining and overflow basins. It features a stainless steel
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For safe and easy cleaning on site, the diaphragm is flush-mounted. With a diameter of 22 mm/1
in., it also can be used in small vessels. It comes with preconfigured measuring ranges from 100
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The probe carries ATEX and IECEx certification and has a corrosion-resistant TPE cable that
also is approved for use with potable water. Next to the electrical lines for the 4–20-mA output,
the TPE cable houses an air hose to be used for differential pressure level measurement with
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Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 5
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Plant testing and troubleshooting
often require data gathering to
identify specific problems. Data
gathering needs vary with the process
and the equipment. Data must reflect
fundamentals of the equipment opera-
tion. Getting usable results, of course, is
crucial — but data gathering efforts must
contend with time and money limitations
as well as safety constraints. Wonderful
high-precision instruments are available.
However, they may be too difficult to use
or too expensive for many routine tasks.
Troubleshooters must know the limits of
conventional measurement instruments
and understand what data are necessary
to come to usable conclusions. An exam-
ination of centrifugal pump performance
illustrates the need to adequately appreci-
ate instrument capabilities.
Every centrifugal pump has a performance
curve. As flow rate increases, dynamic
head across the pump drops. So, knowing
dynamic head across a centrifugal pump
can give information about flow rates. The
key question then becomes how accurate
must the required pressure readings be to
estimate dynamic head.
Figure 1 highlights the challenges posed
by pressure gauge accuracy on estimat-
ing flow rates. This particular pump was
installed in a liquid recovery system that
collected slop streams. The nominal design
Understand Instrument CapabilitiesProper data interpretation depends upon knowledge of a device’s limits
By Andrew Sloley, Contributing Editor
How accurate must pressure readings be to estimate dynamic head?
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 6
www.ChemicalProcessing.com
rate was 50 gpm but normal “expected”
operation was 35 gpm. The system did not
meter flow. One part of the troubleshoot-
ing effort required getting an accurate
estimate of the liquid rate. This pump has
a constantly rising dynamic head down
to shutoff (zero flow). One characteristic
of a pump with a constantly rising head
is that the dynamic head changes only a
small amount with flow rate as that rate
approaches zero.
The suction pressure was 15 psig. To get
a dynamic head reading, the trouble-
shooters used two pressure gauges: one
on the suction and one on the discharge.
The maximum expected discharge pres-
sure was ~90 psig based on a 0.7 specific
gravity fluid. For safety, an initial check
was done with a 0–200-psig gauge on the
discharge, then a 0–100-psig gauge was
used for the final readings. Because no
lower-pressure-range gauges were avail-
able, a 0–100-psig gauge was used for the
suction pressure as well.
If the pump were operating at the normal
rate of 35 gpm and on the pump curve,
the gauge on the discharge would give a
reading of about 82 psig. The best case
for standard commercial pressure gauges
found at most plants is an accuracy of ±2%
of the range for readings. So, the 0–100-
psig gauges used for the suction and
discharge pressure readings each should
have an error of ±2 psig. Additionally, both
PUMP CURVEFigure 1. A modest inaccuracy in pressure measurement can translate into a far greater error in flow rate.
221 ft @ 35 gpm
215 ft @ 44 gpm
228 ft @22 gpm
240
200
160
120
8
Hea
d, f
t
Flow gpm
0 40 80 120
Effi
cien
cy, %
40
30
20
10
0
HeadEfficiency
Design: 50 gpmNormal: 35 gpm
3,550 rpm7.5-in. impeller
www.ChemicalProcessing.com
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 7
gauges will be taking readings close to
the ends of their range: the 15-psig suction
pressure is in the low end of the range while
the 82-psig discharge pressure is in the high
end. Readings like these towards the end
of the range likely will have higher errors
than readings more in the middle of the
gauge’s range.
To get a number, let’s examine the effect
of a 2-psi error in the dynamic head. If the
actual pressure is 82 psi but the gauge
reads 80 psi, the height is 215 ft and the
estimated flow rate is 44 gpm. If the gauge
instead reads 84 psi, the height is 228 ft and
the estimated flow rate is 22 gpm. The flow
error range is -36% to +25% for a reason-
able error in measuring dynamic pressure.
Lower flow rates shift all readings to the
right on the curve, making likely errors
greater. Higher flow rates shift the read-
ings to the left on the curve, making flow
errors smaller.
The accuracy needed on the flow measure-
ments depends upon the problem you are
trying to solve. However, troubleshooting
rarely benefits from measurements with a
-36% to +25% error range on flow rates. At
high enough rates, pump discharge pres-
sure might give a useful indication of flow
rate but it’s never the best method.
A better option for pumps with motors is
to get an estimate of pump power from
the electric load and then calculate a flow
rate. In this case, the flow-rate error drops
to -18% to +10%. While this certainly isn’t
great, it still is a 50% improvement.
Of course, these analyses all depend upon
knowing the pump curve and assuming
the pump accurately follows it. At low
flow rates, small deviations due to wear
or other factors will significantly change
any flow rate estimate from pump or
motor data.
The case discussed is a difficult one. The
best solution here, if possible, is to directly
measure flow with an ultrasonic flow
meter. Nevertheless, the case dramatically
illustrates the importance of understand-
ing the accuracy of measurements and
how they may affect troubleshooting.
ANDREW SLOLEY is a contributing editor for CP’s
Plant Insites column. Email him at [email protected].
www.ChemicalProcessing.com
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 8
Think Straight About Orifice PlatesInsufficient flow conditioning often undermines measurement accuracy
By Andrew Sloley, Contributing Editor
Plants frequently rely on differential
pressure created by an obstruction
in a line to measure flow. Accuracy
depends upon two factors: the correctness
of the differential pressure measurement
obtained via taps upstream and down-
stream, and the calculation for turning that
measurement into a flow rate.
The obstruction placed in the line most
often is an orifice plate — a flat plate with
a machined orifice. (For more on orifice
plates, see: “Remember the Old Reliable
Orifice Plate,” https://bit.ly/3cmBvZK; for
other differential-pressure flow metering
options, see: “Look Beyond Orifice Plates,”
https://bit.ly/3pFXAIx.) Orifice plates
are cheap and reliable. Moreover, orifice
plates manufactured to specific dimensions
and tolerances generate known pressure
drops for a given flow rate. The Interna-
tional Standards Organization (ISO) has
summarized the dimensional criteria; all
reputable orifice-plate manufacturers meet
these standards.
ISO standards also cover installation
requirements. Proper installation plays
a crucial role in achieving accurate ori-
fice-plate measurements. The major criteria
include a stable flow pattern, a fluid-filled
pipe and an unobstructed flow path (no
blockages). If these criteria are met, flow
meter calculations can be based on the
Many orifice meters inside process units don’t meet ISO standards.
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 9
www.ChemicalProcessing.com
physical dimensions of the system; no
in-place measurement or calibration is
required.
Let’s look in detail at the first requirement,
a stable flow pattern. An oft-repeated rule
of thumb states that a length of straight-run
pipe equal to 10–15 piping diameters creates
a sufficiently stable flow pattern. How does
this compare to the ISO standards?
The ISO standards include multiple
upstream piping configurations — from
fully open full-bore valves upstream and
downstream to multiple right-angle turns
to tee-branch connections. They also detail
for multiple values of β — the orifice diam-
eter/pipe diameter, in consistent units
— the length of straight-run piping required
(Table 1). In general, the lower the b, the
shorter the pipe run necessary. During
piping design, the final β ratio is unknown.
So, many engineering standards attempt to
reduce overall cost by specifying a maxi-
mum β of 0.55 to 0.63.
The best cases are fully open full-bore
valves with a straight run upstream of them,
and a single right-angle bend upstream.
The required piping runs for a 0.55 β are
13 diameters for the full-bore valves and 16
diameters for the single right-angle bend.
Every other configuration is worse — in
some cases, much worse. Higher β values
increase upstream requirements.
For two 90° bends in series, an orifice with
a 0.55 b requires 44 diameters of upstream
CAS
3”x4” 4”x3”
FIC
XXX
FE
XXX
FT
XXX
Upstream Configuration value
<0.32 0.45 0.55 0.63 0.70 0.77 0.84
Fully open, full-bore valve 12 12 13 16 20 27 38
Two right-angle bends in same plane, Two or three
bends at right angles with straightening vanes15 18 22 28 36 46 57
Two or three bends at right angles, Flow branch 35 38 44 52 63 76 89
Fully open globe valve 18 20 23 27 32 40 49
Single right-angle bend 10 13 16 22 29 44 56
BAD IDEAFigure 1. Installing a short section of larger diameter pipe would create flow pattern with unknown impact on meter.
ISO INSTALLATION REQUIREMENTSTable 1. Required number of pipe diameters in upstream straight run generally decreases with value.
www.ChemicalProcessing.com
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 10
piping to meet ISO standards. Even with
properly installed straightening vanes, this
layout needs 22 diameters. A β of 0.84
raises the requirement to 40+ diameters for
all types of installations.
What this all means is that if your plant
needs maximum accuracy, use lots of
pipe run upstream of orifice plates. In
some cases, 90 diameters are necessary.
Additionally, if you’re having flow meter
problems, check the installation. I’ve
observed many orifice meters inside pro-
cess units that don’t meet ISO standards.
The 10–15-diameters rule only applies
to a “best case” — i.e., everything else is
done correctly and a low-b orifice plate is
installed. Most industrial installations require
20+ diameters. Using straightening vanes
can help, but doesn’t completely solve the
problem. The toughest installations are
downstream of flow branches and where
multiple elbows in series are at right angles
to each other. To paraphrase a quote from
pump installation guidelines, the only thing
worse than one elbow upstream of a flow
orifice is two elbows.
While a plant may start with low-b orifice
plates, as hydraulics become tighter it may
put in new plates with lower pressure drops
(and higher β values). Installing a short run
of larger diameter pipe doesn’t solve the
problem (Figure 1). The upstream expansion
creates a flow pattern with unknown effect
on the orifice meter.
If the piping configuration doesn’t meet ISO
standards, accuracy will suffer. For monitor-
ing unit trends, reduced accuracy may be
an acceptable tradeoff for a cheaper meter
installation. For high and reliable accuracy,
always follow the ISO requirements.
ANDREW SLOLEY is contributing editor for CP’s Plant
Insites column. Email him at [email protected].
www.ChemicalProcessing.com
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 11
Find the Real Maximum PressureAlways consider static head when assessing pressure vessels
By Andrew Sloley, Contributing Editor
Chemical plant vessels serve many
purposes, including for storage
and surge control and as reactors,
fractionators, absorbers, strippers and
crystallizers. Pressure is a key parameter
for safe operation. Vessel operating and
design pressures may appear in piping
and instrumentation diagrams (P&IDs),
specification sheets, operating instruc-
tions and fabrication drawings.
Process safety analyses invariably address
over-pressure protection. Such analyses
generally rely on P&IDs for plant design
information. The P&IDs usually include
vessel maximum operating and working
pressures. But what do those pressures
mean? Are the P&ID pressures the ones
we really must worry about?
For vessels stamped as complying with
the American Society of Mechanical Engi-
neers (ASME) Boiler and Pressure Vessel
Code, the ASME U-1 form summarizes the
vessel’s design temperature and pressure.
It includes the design conditions and the
specific materials used, allowable materi-
als stresses, testing conditions and other
critical mechanical details. That form (and
any attachments stemming from vessel
modifications or repairs) defines the oper-
ating limits. The vessel should be code
stamped with the same values shown on
the U-1 form. While useful and convenient,
other paperwork doesn’t override the
U-1 form.
So, it’s important to understand how
P&ID design pressures compare to those
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 12
www.ChemicalProcessing.com
on ASME U-1 forms and to know some
common errors in P&ID pressures.
Section VIII Division 1 of the ASME Code
covers rules for construction of pressure
vessels. Subsection UG-21 defines design
pressure requirements: “Each element of
a pressure vessel shall be designed for at
least the most severe condition of coinci-
dent pressure (including coincident static
head in the normal operating position) and
temperature expected in normal operation.”
The design pressure of a vessel is the max-
imum pressure that any part of the vessel
can tolerate — it includes both system and
static pressures. Design pressures may
vary with temperature and vessels may be
stamped for multiple design temperature/
pressure combinations.
Common practice during hazard and oper-
ability (HAZOP) reviews is to use pressure
ratings on P&IDs rather than referring
back to U-1 forms. As long as the values
are correct and people properly under-
stand how to interpret them, this doesn’t
cause problems.
The U-1 form design values are for any
point on the vessel and must include static
head in the pressure evaluation. Too often,
HAZOP and other safety reviews look at
operating pressure from a pressure reading
point and fail to consider the implications
of static head. All vessels not under vacuum
have a static head component of pressure.
The static head may vary from insignificant
for a horizontal vessel under vacuum to
very high for a tall liquid-filled vessel. As
an example, let’s consider a vessel that has
a seam-to-seam height of 47 ft. 8 in. and
contains a mix of hydrocarbons and a liquid
ionic catalyst (hydrogen fluoride). The
average density of the liquid is 48.8 lb/ft3
at operating conditions. The U-1 form indi-
cates the vessel is designed to handle 165
psig at 250°F.
PRESSURE RELIEF VALVE OPTIONSFigure 1. Location of the valve can markedly affect the maximum release setting.
May 2011 cheMicalprocessing.coM 42
plant insites
Find the Real Maximum PressureAlways consider static head when assessing pressure vessels
CheMiCal Plant vessels serve many purposes, including for storage and surge control and as reac-tors, fractionators, absorbers, strippers and crystal-lizers. Pressure is a key parameter for safe operation. Vessel operating and design pressures may appear in piping and instrumentation diagrams (P&IDs), specification sheets, operating instructions and fabri-cation drawings.
Process safety analyses invariably address over-pressure protection. Such analyses generally rely on P&IDs for plant design information. The P&IDs usually include vessel maximum operating and working pressures. But what do those pressures mean? Are the P&ID pressures the ones we really must worry about?
For vessels stamped as complying with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, the ASME U-1 form summarizes the vessel’s design temperature and
pressure. It includes the design conditions and the specific materials used, allowable materials stresses, testing conditions and other critical mechanical details. That form (and any attachments stemming from vessel modifications or repairs) defines the operating limits. The vessel should be code stamped with the same values shown on the U-1 form. While useful and convenient, other paperwork doesn’t over-ride the U-1 form.
So, it’s important to understand how P&ID design pressures compare to those on ASME U-1 forms and to know some common errors in P&ID pressures.
Section VIII Division 1 of the ASME Code covers rules for construction of pressure vessels. Sub-section UG-21 defines design pressure requirements: “Each element of a pressure vessel shall be designed for at least the most severe condition of coincident pressure (including coincident static head in the nor-mal operating position) and temperature expected in normal operation.”
The design pressure of a vessel is the maximum pressure that any part of the vessel can tolerate — it includes both system and static pressures. Design pressures may vary with temperature and vessels may be stamped for multiple design temperature/pressure combinations.
Common practice during hazard and operabil-ity (HAZOP) reviews is to use pressure ratings on P&IDs rather than referring back to U-1 forms. As long as the values are correct and people properly understand how to interpret them, this doesn’t cause problems.
The U-1 form design values are for any point on the vessel and must include static head in the pres-sure evaluation. Too often, HAZOP and other safety reviews look at operating pressure from a pressure reading point and fail to consider the implications of static head. All vessels not under vacuum have a static head component of pressure.
The static head may vary from insignificant for a horizontal vessel under vacuum to very high for a tall liquid-filled vessel. As an example, let’s con-sider a vessel that has a seam-to-seam height of 47 ft. 8 in. and contains a mix of hydrocarbons and a liquid ionic catalyst (hydrogen fluoride). The average density of the liquid is 48.8 lb/ft3 at operating condi-tions. The U-1 form indicates the vessel is designed to handle 165 psig at 250°F.
Other paperwork
doesn’t override
the U-1 form.
PRVOption 1
Piping Elevation67’-4” —
Hydrocarbon Out59’-4” —
Catalyst Out20’-11” —
Feed3’-3” —
Piping Elevation— 12’-0”
PRVOption 2
PRVOption 1
Pressure Relief Valve Options
Figure 1. Location of the valve can markedly affect the maximum release setting.
CP1105_42_43_InSites.indd 42 4/26/11 2:37 PM
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Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 13
Per the ASME code, the pressure relief
device must open at or before any part
of the vessel reaches the design pressure.
Figure 1 shows the vessel layout with the
current pressure relief valve (PRV) location
as Option 1 and a new proposed location
as Option 2.
The first common misconception often
encountered is that a vessel’s rating allows
operation at the design pressure at the
pressure measurement point. This plant
mythology is false. The ASME code doesn’t
specify the location of required pressure
measurement points. The code specifies
that the system pressure plus the coinci-
dent liquid head must be below the vessel
design limit at all points on the vessel.
For our example, this limit is the lower
edge of the feed nozzle at the bottom of
the vessel.
The feed nozzle centerline is at 3 ft. 3 in.
above grade. The lower edge of the nozzle
is 9 in. lower, at 2 ft. 6 in. The PRV cur-
rently is located in a pipe rack downstream
of the vessel (Option 1). The PRV inlet is
at 12 ft. 0 in. At an operating density of
48.8 lb/ ft3 this gives 5 psi of static head
(rounded up). The maximum PRV relief set-
ting is 161 psig (165 psig design limit minus
4 psi static head).
A proposal “to take full advantage of the
vessel design pressure” would move the
PRV to the Option 2 location. This idea
stems from the thought that the vessel’s
top seam defines the design pressure. This
idea is wrong. It’s also very curious. Even
if you believe that the top seam defines
the design pressure, why move the PRV?
Just reset it to account for the correct
static head.
What must happen if the PRV moves to the
Option 2 location? The elevation of the pipe
is 67 ft. 4 in. and the PRV inlet is at 69 ft. 0
in. At an operating density of 48.8 lbs/ft3
this gives 23 psi of liquid head (rounded up
again). The maximum PRV release setting
is 142 (165 psig design limit minus 23 psi
static head).
The key point is that pressure relief devices
must protect all points of the vessel from
exceeding design pressure. Moving PRVs
doesn’t change vessel design pressures.
Always go back to the U-1 forms when you
must verify design pressure. Other docu-
mentation, while convenient and helpful,
remains secondary to the U-1 forms and
related vessel code stamps.
ANDREW SLOLEY is contributing editor for CP’s Plant
InSites column. Email him at [email protected].
Other paperwork doesn’t override the U-1 form.
www.ChemicalProcessing.com
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 14
Pressure Measurement eHANDBOOK: Take the Pressure Off Pressure Measurement 15
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