Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
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25
Fig.
2-8.
Senior orifice fitting. (Courtesy
of
Daniel Industries, Inc.)
Fig.
2-9.
Junior
orifice fitting. (Courtesy of Daniel Industries, Inc.)
26
Fig.
2-10. Flange-type pressure taps.
(Courtesy
of
Grove Valve and Regulator Company.)
Fig. 2-11. Pipe pressure taps. (After hchards, 1947, p. 15.)
Fig. 2-12. Vena contracta taps. (After Richards, 1947,
p.
14.)
n
f
h
Fig. 2-12. Vena contracta taps. (After Richards, 1947,
p.
14.)
27
Fig. 2-13. Corner pressure taps. (After Richards, 1947,
p.
13.)
root
of
the differential pressure is proportional to the velocity, and hence, the
flow
rate (see Appendix
2.1).
Turbine meters
The turbine meter principles were described in the earlier section on liquid
flow
rate measurements. In the past, there was very little incentive for measuring gas
rates due to its low cost. With the increase in prices, however, gas flow-rate
A
stagnation zone is located between the shedding body and the sensing vane. The loca-
tion or attachment of this zone is controlled by vortex shedding.
A
significant flow around
the shedding bodx opposite the side which has the vortex, goes between the shedding
body and the sensing vane. The flow then goes through the opening in the sensing vane,
resulting in
a
torque on that body This oscillating torque is brought to the outside of the
meter body through a torque-tube assembly and is sensed externally
The
V3
flowrneter incorporates advanced fluid mechanics techniques which combine
vortex shedding with fluidics (the Coanda effect), resulting in superb operating
characteristics.
Fig.
2-14. Principles
of
vortex shedding meters. (Courtesy
of
Fischer and Porter
Co.)
28
measurement has become more important; therefore, turbine meters have been, and
are being, developed in order to give automated accurate measurement of gas flow
rates. Positive displacement meters have been used in residential locations, but have
not received widespread usage in the oilfields.
Positive displacement meters
Many positive displacement meters used to measure gas flow are
on
distribution
lines. They typically measure the cumulative volume of gas through the line and
operate on the same principle as for liquid flow. Positive displacement meters
measure a given volume for each cycle or revolution.
Vortex shedding meters
The vortex shedding principle is used primarily for gas measurements, but can
also be used for liquid flow rate measurement. It involves measuring the vortex shed
behind a body of a certain shape (shown in Fig.
2-14)
and then inferring the flow
rates from this information. These type of meters have been used more often for
gases than for liquids. Some manufacturers, however, claim the use
of
the same flow
device for both liquids and gases (see Fig.
2-15),
whereas others have separate units.
Fig.
2-15.
Vortex
flow
meter for
fluids.
(Fischer
and
Porter Series
10LV3000
vortex flowmeters.)
29
OTHER TYPES
OF
FLOW
RATE MEASUREMENT
Mass flow rate, two-phase flow rate and miscellaneous/or special flow rate
meters are covered in ths section. Mass flow rate is sometimes of greater value than
volumetric flow rate. Two-phase flow
of
liquid-liquid, gas-liquid, solid-liquid, or
solid-gas is important in the petroleum industry. Special or miscellaneous flowme-
ters utilize magnetic and ultrasonic flow measurement techniques.
Muss
flow
rate
Mass flow rate can be measured by various devices. The mass flow rate can be
obtained by direct measurement or by measuring volumetric flow rate and then
calculating the mass flow rate based on density information. Direct methods include
vibrating tubes (see Fig.
2-16)
and heat transfer (often cooling). Densities can be
Fig.
2-16.
Mass
flowmeter. (Courtesy
of
Micromotion, Inc.)
30
provided by temperature and pressure compensation, by radiation attenuation, or
by other methods.
Two-phase
systems
Although it is generally better to measure each phase separately in two-phase
flow, it is not always possible. When it is necessary
to
measure the flow rate of a
two-phase stream, most techniques only give approximate values.
Special flow meters
Although magnetic flow measurements provide obstructionless flow, the fluid has
to be electrically conductive; therefore, magnetic techniques will not work in all oil
systems, unless the oil is the dispersed phase.
Fig.
2-17.
Magnetic flowmeter. (Courtesy
of
Fischer and Porter,
81000a,
10D1475, Mini Mag.)
31
Magnetic flowmeters are also called electromagnetic flowmeters. As indicated
earlier, they can only measure the flow rate
of
electrically conductive fluids such as
water, acids, frac fluids, and water-base and oil-in-water emulsion drilling fluids.
They will not work with some oil systems, where oil is the continuous phase. The
magnetic flowmeters have good accuracy, low pressure
loss
(low head
loss
due to
friction), good rangeability, and the capability for difficult-to-handle fluids such as
acids, slurries, and viscous liquids. Inasmuch as the meter
is
non-intrusive, it does
not disturb the flow (see Fig. 2-17). Accuracies of
f0.5%
of rate are often quoted
for typical velocities, which range from
1
ft/sec to
30
ft/sec. At lower velocities, the
accuracy is
0.005
ft/sec. Rangeabilities
of
30
:
1
are typical, with meters having
rangeability of
50
:
1
being available. Temperature ranges from
0
to
360
F
and
pressure ratings up to 740 psi are possible.
Meters range in size from
0.1
to 18 in., with flow rates ranging from less than
0.1
gpm to more than
100,000
gpm.
Continuous Ultrasonic signal is frequency (doppler)
shifted by reflections from entrained particles/bubbles
moving with the flow stream. Computed volumetric
flow rate is dependent and variable with liquid's sonic
velocity, temperature, particle size and concentration
precluding predictable and stable computation in many
applications.
@
Difference of transmission time
of
sonic pulses in
upstream vs. downstream direction is directly
proportional to flow velocity. Volumetric flow rate is
computed independent of liquidk sonic properties and
includes compensation for flow profile.
Fig.
2-18.
Comparison
of
two ultrasonic flow measurement principles. (Courtesy
of
Controlotron
Corporation.)
(a)
Doppler
shift.
(b)
Pulse time difference.
69
32
Ultrasonic meters have recently been used in oilfields due to their non-intrusive
nature. There are difficulties with these systems, however, such as effects from gas
bubbles, solids, etc. There are basically two different principles:
(1)
Doppler and (2)
transmitted energy. The Doppler technique utilizes the reflections of the energy off
particles (see Fig. 2-18.a), whereas the other transmits energy across the flow stream
from one transducer to the other (see Fig. 2-18.b).
SIMPLE EQUATIONS
FOR
MEASURING WEIGHT
FLOW
RATES
FOR
GASES AND LIQUIDS
American Gas Association (1956) proposed the following equation for measuring
flow rate of gases using orifice meter.
W,
=
1.0618
FbF,Yfi
(2-1)
where:
W,
is the weight flow rate in lb/hr,
Fb is
the basic orifice factor,
F,
=
Reynolds number factor,
Y
is
the expansion factor,
h,
is
the differential
pressure
in
inches of water, and
y,
=
specific weight of flowing gas in lb/cu
ft.
For natural gas liquids, Foxboro (1961) proposed the following simplified equa-
tion:
W,
=
68,045
Sdi\jh,SG,
where:
W,
is the weight rate of flow of liquid in lbjday,
S
is the constant based
on
the bore of the orifice and internal diameter
of
the metering tube,
di
is the inside
diameter (ID) of tube in inches,
h,
is the differential pressure in inches of water,
and
SG,
is the specific gravity of flowing liquid.
Excellent discussion of the subject together with orifice meter tables necessary for
calculations were presented by Ikoku (1984).
SAMPLE PROBLEMS AND QUESTIONS
(1)
Determine the flow rate of gas in lb/hr using 1.5-in. orifice meter at 60°F
and 14.7 psia, given the following data:
h,
=
25 in. of water,
di
=
3.438 in. (ID),
SG,
=
specific gravity of gas (with respect to air
=
1)
=
0.72,
and
Tf
=
80°F;
ps
=
(static pressure upstream)
=
40
psig (Consult Ikoku (1984) for various factors).
(2)
Define the following components of the orifice flow constant: C':
Fb,
F,,
Y,
(3)
Sketch three types of orifice plates and briefly outline the advantages of each.
(4) Briefly describe the operation of a pneumatic integrator.
(5) Describe steps in proper selection of an orifice meter.
(6) List uncertainties in flow measurements.
(7)
Air flows through a 6-in.
by
3-in.
Venturi meter. The gage pressure is 30
Yl,
Y,,
Ym,
Fpb,
&,
Fgr
Fpv,
Fm,
4,
and
Fa.
33
lb/in.’ and the temperature is 60
F
at the base of the meter. Differential manome-
ter shows a reading of 7 in. of mercury and the barometric pressure is 14.70 psi.
Calculate the flow rate.
APPENDIX 2.1-DEVELOPMENT OF ORIFICE METERING
’
L.J.
KEMP and GEORGE V. CHILINGARIAN
History
The first record of the use of orifices for the measurement
of
fluids in a closed
conduit was left by Giovanni
B.
Venturi, an Italian physicist, who in 1797 did some
work that led to the development of the Venturi meter by Clemons Herschel in
1886. Apparently, the first orifice meter to be used in the measurement of gas was
installed near Columbus,
Ohio,
about 1890 and was designed by Professor Robinson
of
Ohio State University.
About 1903,
T.R.
Weymouth began a series
of
tests in Pennsylvania which led to
the publication of coefficients for orifice meters with flange taps. At about the same
time, E.O. Hickstein made a similar series
of
tests in Joplin, Missouri, from which
data were developed for the calculation of coefficients for orifice meters with pipe
taps. At this time, differentials were still measured as instantaneous readings
observed at regular intervals on glass tube water manometers. It was not until a
mercury manometer had been developed into a recording differential gauge, that the
orifice meter became feasible for commercial use.
A great deal of research and experimental work was conducted by the American
Gas Association and the American Society of Mechanical Engineers between 1924
and 1935 in developing
(1)
better data from whch orifice meter coefficients could
be calculated, and (2) better standards for the construction of orifice meters. The
summary of this work was published in 1935, as a joint report by the two
participating organizations (see AGA-ASME, 1935). This report is the basis for
almost all present-day orifice meter measurement. In the same year, bulletins
containing only the material pertinent to the measurement of natural gas by orifice
meters were published (AGA, 1935; CNGA, 1935).
In 1941, the California Natural Gasoline Association
’
(CNGA, 1941) published
the data necessary for the determination of the coefficient for the measurement of
natural gas by the orifice meter, and in 1947 (CNGA, 1947), the data to cover
supercompressibility for pressures in excess of
500
lb (psig).
In
1955,
further data (AGA, 1955) were made available; and in 1956 a couple of
earlier bulletins were combined and brought up to date (CNGA, 1956), and
’
This
Appendix represents Chapter
7
in
“Surface Operations in Petroleum Production” by G.V.
Chilingar and C.M. Beeson
(1968).
*
California Natural Gasoline Association’s Board officially changed the name
of
the Association
to
Western Gas Processors and Oil Refiners Association
on
June
14,
1966.
34
augmented by data on pressures ranging from 500 to 3000 lb and for meter runs up
to 30 in. in diameter. The latter were developed from tests at Refugio, Texas,
performed under the combined auspices of the American Gas Association and the
American Society of Mechanical Engineers. These tests were initiated because the
phenomenal expansion of the natural gas industry brought about the great networks
of very high-pressure and large-diameter transmission lines.
The
U.S.
Bureau of Mines has been conducting tests at Amarillo, Texas, for the
development of data for the calculation of coefficients, using eccentric and segmen-
tal orifices. These are used primarily where it is necessary to measure fluids that are
dirty or gases that are wet. The National Bureau of Standards also has conducted
extensive tests to determine appropriate installation specifications for orifice meters
in view of various pratices of measurement.
Considerable work has been done by the American Gas Association (AGA, 1962)
reverifying the validity, and extending the scope, of their former work on super-
compressibility, and developing a set
of
formulas for the calculation of correction
factors. The CNGA (1963) has published the formulas and methods for computer
application
of
large orifice meter volume calculations.
Definition
of
orifice meter
An orifice meter is a conduit and restriction to produce a pressure drop owing to
a change in velocity of the fluid. The roughest forms are probably a valve or an
elbow.
Figure 2.1-1 shows an elbow meter that is actually used for measurement. The
best and most expensive orifice meter is the Venturi meter. Between these two
extremes are many other kinds incorporating many different shapes, but the better
U
Fig.
2.1-1.
Diagrammatic
sketch
of
elbow
meter