## Abstrict A flow meter obtains the individual flow rates of gas, liquid hydrocarbons,
and water in a predominantly gas-containing flowing fluid mixture.
The flow meter comprises a water content meter (7) provides a signal
representing a measure of the water content of said fluid. It also
comprises a double differential pressure generating (3) and measuring
(4) structure, denoted a DDP-unit (2), that provides two measurement
signals (6A and 6B) representing two independent values of differential
pressure (DP) in said fluid (1). In addition to the above, the meter
also comprises a signal processing unit (8) having inputs (9A-C)
for receiving the measurement signals and the water content signal,
and a calculation module (10) which calculates values representing
the volumetric flow rates of said gas, liquid hydrocarbons and water
in said fluid.
## Claims 1. Flow meter capable of measuring the individual flow rates of
gas, liquid hydrocarbons, and water in a predominantly gas-containing
flowing fluid mixture (1) comprising a water content meter (7) for
providing a signal representing a measure of the water content of
said fluid, a double differential pressure generating (3) and measuring
(4) structure, denoted a DDP-unit (2), for providing two measurement
signals (6A and 6B) representing two independent values of differential
pressure in said fluid (1), and a signal processing unit (8) having
inputs (9A-C) capable of receiving the said measurement signals
and the said water content signal, and a calculation module (10)
for calculating values representing the volumetric flow rates of
said gas, liquid hydrocarbons and water in said fluid.
2. Flow meter according to claim 1 wherein the DDP-unit (2) comprises
two topologically different differential pressure DP-generating
structures (20 21A-C), installed close to each other in a pipe
(30) such that one DP-generating structure influences the flow pattern
at the other DP-generating structure.
3. Flow meter according to claim 1 wherein the DDP-unit (2) comprises
a single flow cross section reduction device mounted in said fluid
flow such as to vary cross section of said fluid flow, and two differential
pressure measuring structures arranged to measure differential pressures
at two different positions at or near said flow cross section reduction
device.
4. Flow meter according to claim 3 wherein said flow cross section
reduction device comprises an oblong body.
5. Flow meter according to claim 3 wherein the single flow cross
section reduction device defines an inlet region, a reduced cross
section region and an outlet region, the DDP-unit (2) comprises
a first differential pressure measuring device arranged in one of
the said regions, and a second differential pressure measuring device
is arranged in another one of said regions.
6. Flow meter according to claim 3 wherein both differential pressure
measuring structures are arranged to measure accelerational pressure
drops.
7. Flow meter according to claim 3 wherein one differential pressure
measuring structure is arranged to measure accelerational pressure
drop and the other differential pressure measuring structure is
arranged to measure pressure recovery.
8. Flow meter according to claim 1 wherein the water fraction
meter comprises a dielectric permittivity measurement unit.
9. Flow meter according to claim 8 wherein the dielectric permittivity
measurement unit comprises a microwave resonator.
10. Flow meter according to claim 9 comprising a V-cone, and a
Venturi tube; said V-cbne being used in a microwave resonator.
11. Flow meter according to claim 9 comprising a body placed centrally
in the pipe and an orifice; said centre body being used in a microwave
resonator.
12. Flow meter according to claim 8 wherein the dielectric permittivity
measurement unit comprises a capacitance measuring device.
13. Flow meter according to claim 8 wherein the dielectric permittivity
measurement unit and the differential pressure generating and measuring
structures are combined in a common structure.
14. Flow meter according to claim 13 where the common structure
is a single oblong body, said oblong body being used to both to
generate two independent differential pressures and as part of a
microwave resonator.
15. Method of measuring the individual flow rates of gas, liquid
hydrocarbons, and water in a predominantly gas-containing flowing
fluid mixture (1), providing the individual flow rates of gas, liquid
hydrocarbons and water in the stream, wherein the method comprises
the steps of providing a signal (9E) representing a measure of the
water content of said fluid using a water content meter (7), providing
measurement signals (5A-D, 6A-B, 9A-B) representing at least two
independent values of differential pressure in said fluid using
a double differential pressure generating (3) and measuring (4)
structure, supplying the said measurement signals and the said water
fraction signal to a signal processing (8) unit having corresponding
input channels (9A-E) capable of receiving said signals, and calculating
values representing the volumetric flow rates of said gas, liquid
hydrocarbons and water in said fluid in a calculation unit (10)
of said signal processing unit (8).
## Description [0001] This invention relates generally to flow measurements in
a fluid flow.
[0002] In particular, this invention relates to the measurement
of the composition or flow rates of the individual components of
a fluid which is a mixture of oil, gas and water, that is, a 3-phase
flow.
BACKGROUND OF THE INVENTION
[0003] In the oil industry there is in various situations a need
to measure the composition and individual flow rates of a mixture
of gaseous hydrocarbons, liquid hydrocarbons (oil or condensate)
and water, flowing in a pipe. The conventional technique is to separate
the fluid in a separator and to measure the flow of each of the
components separately. During the last years also so-called multiphase
meters have become available, which measure the composition and
the flow rates without prior separation [1]. A special case of a
multiphase flow is the so-called wet gas flow, which means that
the fluid mixture is dominated by the gas phase containing small
amounts of liquids. The liquid phase consists of water and of light
liquid hydrocarbons (so-called condensate). Usually in a wet gas,
the GVF (Gas Volume Fraction) is higher than about 95% vol. When
measuring in a wet gas flow application using a multiphase meter,
the relative uncertainty achievable for the liquid component flow
rates is too high. This applicant has recently developed a wet gas
meter that is capable of measuring the water content of a wet gas
stream using microwave technology and the wet gas flow rate based
on a differential pressure device [23]. The amount of liquid hydrocarbons
(condensate) has in this first generation wet gas meter been calculated
rather than measured. The calculation is based on a priori knowledge
about the molecular composition of the hydrocarbon mixture (gas
and condensate), using a PVT software package (computer software
tool used to calculate thermodynamic properties like densities and
gas/liquid ratios of fluids at given temperatures and pressures).
DESCRIPTION OF STATE OF THE ART
[0004] The flow rates of the components of a multiphase flow can
be measured with a test separator or a multiphase meter. The test
separator is expensive and bulky. Therefore, it is not practical
to have a test separator measuring the production continuously on
every well, but rather one test separator per oil field. This is
especially true at offshore installations. Each well is routed through
the test separator at regular intervals. When a well is routed through
a test separator, the conditions for the well change, which may
influence the production so that the measurement does not represent
the average production correctly. A test separator is also slow
because of the long settling time. The settling time is particularly
long in wet gas applications because of the small liquid fractions
and consequently long time required to fill up the separator.
[0005] Multiphase meters measure the composition of the flow and
the flow speed separately [1]. From these the flow rates are calculated.
Multiphase meters can be installed for the continuous, in-line measurement
at every location, where measurements are needed. An important application
is to install the meter subsea in the seabed production system,
which is mainly a skid, mounted on top of a subsea well. If each
well in a cluster of wells is equipped with a subsea multiphase
meter, one common pipeline can be used to tie the cluster of subsea
wells to a production platform, which may be located tens of kilometres
from the cluster. The space available for a multiphase meter in
a seabed production system is limited. A compact design is therefore
an advantage.
[0006] A multiphase meter measures four quantities, i.e. the flow
speed and the relative fractions of the three components (oil, water,
and gas). It usually also needs the temperature, pressure, density
of the oil and gas, and the water salinity as input parameters for
compensational purposes, but these will be ignored in the following
discussion of the main measurements. Theoretically, such a system
can be characterized by a set of four equations, of which one equation
is that the sum of the three components is 100%. Hence, a multiphase
meter must be based on the use of at least three independent measurements.
These three measurements can e.g. be a differential pressure (DP)
measurement that essentially gives the flow velocity, a dielectric
measurement that gives the water content and a nucleonic measurement
giving the individual gas/liquid fractions. The uncertainty of the
composition measurement used in the ordinary multiphase meters is
generally to high for use in a wet gas application.
[0007] Different types of multiple DP based 2-phase wet gas meters
have been suggested [4-7]. Such meters are based on the measurement
of two or more differential pressures over various flow constrictions
in a pipe section in order to deduce the gas and liquid rate individually.
One of the suggested solutions [4] is e.g. based on a comparison
of accelerational pressure drop (i.e. pressure drop caused by the
acceleration of the flow) and the permanent dissipative pressure
loss over a standard flow sensor (e.g. a Venturi). One disadvantage
of this approach, which to a certain degree applies to multiple
DP meters in general, is that it is very sensitive to the individual
fluid properties. The lack of water fraction measurement in such
units is consequently a factor that deteriorates its performance.
Another method compares the measured differential pressures over
a standard Venturi and a standard orifice [5]. The information contained
in the two DP readings of separated Venturi and orifice meters has
however often a poor degree of independence meaning that the uncertainty
of this method with respect to the liquid detection will be relatively
high. Still another solution [6] combines the DP measurements over
flow elements that are installed downstream a separate mixing device.
Since this solution requires three relatively extensive geometries
(Venturi+mixing device+second flow element) installed in series
in a pipe, the meter is quite space consuming.
[0008] Another approach to the wet gas metering has been used in
the Roxar meter [2], utilizing a single DP measurement in combination
with a microwave based dielectric measurement. This concept is capable
of discriminating between hydrocarbons and water and hence to measure
the individual flow rates of hydrocarbons and water. The split between
the liquid hydrocarbons and gas is being calculated using a PVT
software package (computer software tool used to calculate thermodynamic
properties like densities and gas/liquid ratios of fluids at given
temperatures and pressures) based on a given hydrocarbon composition.
[0009] An important drawback of the existing 2-phase multiple DP
solutions is that none of the solutions discriminate between water
and liquid hydrocarbons (condensate). In addition to the lack of
a measurement of the individual flow rates of water and liquid hydrocarbons,
this ignorance will also be associated with an increased uncertainty
of the gas and liquid flow rates. The latter effect is caused by
the fact that the 2-phase DP models depend on accurate knowledge
about fluid properties, in particular the density but also e.g.
viscosity and surface tensions. It is e.g., so that in most wet
gas applications for the petroleum industry, there is a significant
difference in the density of water and of the liquid hydrocarbons.
While water has a density of size 1000 kg/m.sup.3 the condensate
density may be of size 550-750 kg/m.sup.3. Ignorance of the water/liquid
hydrocarbon fraction will hence be associated with a significant
uncertainty of the liquid density (and of other liquid properties)
which will in its turn be reflected as an uncertainty of the liquid
and gas flow rate measurements.
[0010] A limitation of the concept using one single DP measurement
in combination with a microwave based dielectric measurement [3]
is that a measurement of the liquid hydrocarbon content of the wet
gas is missing, and hence there is a requirement for having a-priori
knowledge about the hydrocarbon composition.
[0011] It is an object of the present invention to provide a flow
meter that overcomes the above-mentioned limitations.
[0012] In particular it is an object of the present invention to
provide a true 3-phase wet gas metering concept that is capable
of measuring the individual flow rates of gas, liquid hydrocarbons
and water in a wet gas pipe flow.
[0013] The objects of the invention are obtained with a flow meter
capable of measuring the individual flow rates of gas, liquid hydrocarbons
and water in a predominantly gas-containing flowing fluid mixture.
A water content meter provides a signal representing a measure of
the water content of the fluid. A double differential pressure generating
and measuring structure, denote a DDP-unit, provides two measurement
signals representing two independent values of differential pressure
(DP) in the fluid.
[0014] A signal processing unit having inputs capable of receiving
the measurement signals and the water content signal includes a
calculation module for calculating values representing the volumetric
flow rates of said gas, liquid hydrocarbons and water in said fluid.
[0015] Preferred embodiments of the flow meter are given in dependent
claims 2-14.
[0016] In another aspect of the invention there is provided a method
of measuring the individual flow rates of gas, liquid hydrocarbons
and water in a predominantly gas-containing flowing fluid mixture,
capable of providing the individual flow rates of gas, liquid hydrocarbons
and water in the stream. The method comprises providing a signal
representing a measure of the water content of the fluid using a
water content meter, providing measurement signals representing
at least two independent values of differential pressure (DP) in
the fluid using a double differential pressure generating and measuring
(DDP) structure, and supplying the measurement signals and the water
content signal to a signal processing unit having corresponding
input channels capable of receiving the signals. Values are calculated
representing the volumetric flow rates of said gas, liquid hydrocarbons
and water in said fluid in a calculation unit of the signal processing
unit.
THE INVENTION
[0017] The invention will now be described in more detail with
reference to the appended drawings in which:
[0018] FIG. 1 illustrates an example of the measured venturi/V-Cone
DP ratio as function of Lochard-Martinelli parameter for gas/water
flow as measured by Roxar.
[0019] FIG. 2 illustrates a first example of a combined water content
meter and DDP-unit according to the invention using a V-Cone upstream
and venturi downstream.
[0020] FIG. 3 shows a second example of an embodiment of a DDP-unit
according to the invention using venturi upstream and V-Cone downstream.
[0021] FIG. 4 shows a third example of an embodiment of a DDP-unit
according to the invention using an orifice upstream and an ellipsoid
shaped centred body downstream.
[0022] FIG. 5 illustrates a first example of a compact double accelerational
differential pressure device according to the invention with a body
in a pipe section.
[0023] FIG. 6 shows a second example of a compact double acceleration
differential pressure device according to the invention with a body
in pipe section.
[0024] FIG. 7 shows a first example of an embodiment of the invention
with a double DP--acceleration/recovery device.
[0025] FIG. 8 shows a second example of an embodiment of the invention
with a double DP--acceleration/dissipation device.
[0026] FIG. 9 shows an third example of an embodiment of the invention
with a double DP--acceleration/dissipation device.
[0027] FIG. 10 illustrates a V-Cone with microwave antennas for
water detection (Prior art) FIG. 11 shows an example of a microwave
response of a V-Cone sensor.
[0028] FIG. 12 is a schematic diagram illustrating the steps involved
in the signal processing modules and their interaction for the 3-phase
wet gas flow meter according to the present invention, based on
a double DP and a water fraction measurement.
[0029] FIG. 13 is a schematic diagram illustrating the steps involved
in the signal processing modules and their interaction for the 3-phase
wet gas flow meter according to the present invention, based on
a double DP and a dielectric water fraction measurement.
[0030] FIG. 14 is a schematic flow diagram illustrating the iterative
computer steps used in the 3-phase wet gas flow meter according
to the present invention for calculating fluid fractions from raw
measurements and input data.
[0031] FIG. 15 shows an example of an embodiment of a 3-phase wet
gas meter according to a compact version of the invention based
on a combined double DP and a microwave sensor.
[0032] FIG. 16 shows another example of an embodiment of a 3-phase
wet gas meter according to a compact version of the invention based
on a V-Cone flow meter.
[0033] FIG. 17 shows another example of an embodiment of a 3-phase
wet gas meter according to the invention.
[0034] FIG. 18 shows another example of an embodiment of a 3-phase
wet gas meter according to the invention.
[0035] FIG. 19 shows an example of an embodiment of a 3-phase wet
gas meter according to the invention using capacitance probes for
dielectric measurements.
[0036] FIG. 20 shows an illustration of how a microwave sensor
is connected with the microwave drive electronics and the signal
processing module
DETAILED DESCRIPTION OF THE INVENTION
[0037] The invention is a measuring unit or meter for measuring
the individual flow rates of gas, liquid hydrocarbons and water
in a predominantly gas-containing flowing fluid mixture that utilizes
the combination of two differential pressure measurements in combination
with a water content meter 7 (e.g. using a microwave resonator)
to measure the individual flow rates of gas, liquid hydrocarbons
(oil or condensate) and water in a fluid pipe flow (often denoted
wet gas stream) with high resolution.
[0038] The gas content can be in the range 90-100 volume-percentage,
but will typically be about 95% (volume).
[0039] The water content meter 7 provides a signal representing
a measure of the water content, in other words the water fraction,
of said fluid flow. Two differential pressure measurements are provided
by arranging a double differential pressure generating 3 and measuring
4 structures, denoted a DDP-unit 2 for obtaining two independent
values of differential pressure (DP) in said flowing fluid 1. A
signal processing unit 8 is arranged to receive said measurement
signals and said water content signal using input units 9A-C. Input
units 9A-C are typically part of the signal processing unit 8. A
calculation module is associated with or coupled to said signal
processing unit 8 and is adapted to calculate values representing
the volumetric flow rates of said gas, liquid hydrocarbons and water
in said fluid flow or fluid stream 1.
[0040] The signal processing unit 8 will typically either be located
at or near a pipe section part or arranged at a remote location,
e.g. together with other instrumentation. However, the invention
is intended to encompass all solutions where the signal processing
unit is arranged at a location which would be considered suitable
by those skilled in the art.
[0041] The raw data, i.e. the digital or analogue signal representing
the measurement signals could be stored in a suitable storage medium,
such as a tape recorder, a CD-ROM, DVD-disc, or any other storage
medium or electronic, magnetic or optical storage unit commonly
known by those skilled in the art, in order that the signal processing
is performed at a point in time after the time of recording the
measurement signals.
[0042] This means that the signal processing could either be performed
locally or non-locally, and either in real-time or at any other
suitable later time.
[0043] In order to provide a better understanding of the theoretical
foundations for the invention, a somewhat theoretical introduction
is included in the following, in order to enable a person skilled
in the art to understand the principles behind the invention.
[0044] Any non-uniform section of a pipe will result in a change
of the flow speed. Based on the theory of fluid dynamics, the inertia
forces required to accelerate a fluid element through such a non-uniform
section is associated with a certain differential pressure. This
differential pressure is related to the pipe flow rate. Consequently,
a measurement of the differential pressure caused by a non-uniform
section of the pipe can be used to derive the flow rate. The most
frequently used structures for DP measurements are the venturi and
the orifice plate. Flow measurements with such structures have been
described in the international standard ISO 5167-1 [8].
[0045] The single-phase gas rate is generally given by the following
standard formula [8], which applies for all the pipe flow accelerational
differential pressure devices (e.g. venturi, orifice, V-Cone): 1
Q g0 = D 2 4 C d y 2 P g ( - 4 - 1 ) , ( 1 )
[0046] where Q.sub.g0 is the single phase gas flow rate [m.sup.3/s],
D is the pipe inner diameter [m], .DELTA.P is the differential pressure
across the flow constriction [Pa], .rho..sub.g is the gas density
[kg/m.sup.3] 2 = A constriction A pipe ( 2 )
[0047] is the beta ratio representing the relative flow cross section
reduction, .gamma. is the gas expansibility and C.sub.d is the so-called
discharge coefficient representing a correction related to the fact
that the effective flow constriction may differ from the physical
cross section reduction.
[0048] When using DP measurements to find the mass flow in 2-phase
wet gas flow, the standard formulas should be corrected for the
appearance of liquid in the gas. This is usually done by the introduction
of so-called two-phase multipliers that are functions of the individual
fractions of gas and liquid and of the density of each of the components.
The 2-phase multiplier represents the so-called overreading of differential
pressure. The term overreading is used because the differential
pressure with liquid present in the gas is higher than it would
have been if the gas were flowing alone. The differential pressure
overreading is caused by the work performed by the gas in order
to accelerate the liquid phase through the flow constriction. The
2-phase multiplier, .PHI..sub.g [9-12]is defined as: 3 g p p g (
3 )
[0049] where .DELTA.p is the actual differential pressure while
.DELTA.p.sub.g is the differential pressure one would have if the
gas where flowing alone. According to the Lochard-Martinelli theory,
the gas rate can be written [9-12]: 4 Q g = Q g0 g ( 4 )
[0050] where Q.sub.g is the gas flow rate in a 2-phase wet gas
flow situation, Q.sub.g0 is the gas flow rate one would get from
the measured differential pressure assuming the gas flow alone according
to (1), while .PHI..sub.g is the so-called 2-phase multiplier correcting
for the appearance of liquids in the gas.
[0051] The 2-phase multiplier is a function of the individual fractions
of gas and liquid and on the density ratio. It is usually written
as a function of the Lochard-Martinelli parameter, X.sub.LM as:
5 g = g ( g , g l ) = g ( X LM ) where ( 5 ) X LM 1 - g g g l ,
( 6 )
[0052] .alpha..sub.g is the gas mass flow fraction, .rho..sub.g
is the gas density and .rho..sub.1 is the liquid density. The function
(5) is an empirical correlation function, which can e.g. for a typical
device be written in the form: [10-11]: 6 g ( X LM ) = 1 + CX LM
+ X LM 2 ( 7 ) C ( g l ) n + ( l g ) n ( 8 )
[0053] where n is a device characteristic exponent of the order
0.1-0.5.
[0054] Once the gas rate has been found according to (4), the liquid
flow rate, Q.sub.1 can be calculated as: 7 Q l = Q g 1 - g g (
9 )
[0055] To be able to measure the individual gas and liquid flow
rates in a wet gas stream using the framework in the above sections,
the individual densities of the gas and liquid (.rho..sub.g and
.rho..sub.1) as well as the individual fractions of gas (.alpha..sub.g)
and liquid (.alpha..sub.1=1-.alpha..sub.g) must be known in advance.
The densities can usually be found from pressure and temperature
measurements combined with PVT calculations, and for the best accuracy
also from an additional measurement of the water fraction, while
the individual fractions of gas and liquid may often be unknown
and varying.
[0056] One building block of the present invention combines two
DP measurements, which contain independent information (different
.PHI..sub.g functions), to determine the gas/liquid fractions. As
a result, a measure of .alpha..sub.g, .alpha..sub.1 as well as the
individual flow rates of gas and liquid can be obtained.
[0057] In constructing a double DP device for individual measurement
of gas and liquid, it is an essential design criterion that the
two DP readings are different in that they contain independent information.
The core of constructing a double DP device for the detection of
liquid content is that the two differential pressures will react
differently to the presence of liquids in the gas.
[0058] In general, one could, from Eq. (1) and Eq.(4) write the
measured differential pressure in the two differential pressure
devices as functions of the gas fraction and of the gas flow rate:
.DELTA.p.sub.1=.DELTA.p.sub.1(Q.sub.g, .alpha..sub.g)=C.sub.1Q.sub.g.sup.2-
.PHI..sub.g1.sup.2.rho..sub.g (10)
.DELTA.p.sub.2=.DELTA.p.sub.2(Q.sub.g, .alpha..sub.g)=C.sub.2Q.sub.g.sup.2-
.PHI..sub.g2.sup.2.rho..sub.g (11)
[0059] where in the simplest model, C.sub.1 and C.sub.2 are constants
characterizing each differential pressure while .PHI..sub.g1 and
.PHI..sub.g2 are respectively the two-phase multipliers of the two
differential pressures. According to the framework in the sections
above, the differential pressure ratio goes as: 8 p 1 p 2 ( g1 g2
) 2 ( 12 )
[0060] If the two flow meters have a difference in their response
with respect to the presence of liquids in the gas, their respective
two-phase multipliers will contain independent information, meaning
that the differential pressure ratio will be a function (F) of the
Lochard-Martinelli number and of the gas fraction and of the individual
densities: 9 p 2 p 1 = F ( X LM ) ( 13 ) X LM = X LM ( g , l , g
) ( 14 )
[0061] When the phase densities are known in advance, the measured
differential pressure ratio can hence be used to determine the gas
fraction, solving Eqs. (13) and (14) for the gas mass fraction.
The liquid fraction is found from the gas fraction, because their
sum must be equal to one:
.alpha..sub.g+.alpha..sub.1=1 (15)
[0062] The function F(X.sub.LM) is an empirical relation that must
be defined for each flow meter device through experimental test.
FIG. 1 illustrates one example of such a relation obtained by experiments
carried out by this applicant on one of the example embodiments
of this invention, in particular, in a gas/water wet gas flow in
a venturi/V-Cone combination.
[0063] An important factor in the design of a double DP gas/liquid
meter according to this invention is that the two differential pressure
variables should contain independent information, which is the case
in the experimental series illustrated in FIG. 1. If this is not
the case, the differential pressure ratio will be a constant only
and cannot be used to extract .alpha..sub.g. Three main types of
means which will obtain the intended results are suggested below
as examples of how the present invention can be realized:
[0064] Measuring the differential pressures over two topologically
different (geometries that cannot be transformed into each other
by continuous deformations) flow devices mounted immediately in
series in a pipe section.
[0065] Measuring two accelerational differential pressures at different
locations of the same flow constriction.
[0066] Measuring the accelerational differential pressure and the
differential pressure related to pressure recovery of the same DP
device.
[0067] One type of double DP realization (DDP-unit) can be constructed
by the use of two topologically different differential pressure
(DP) generating structures 20 21A-C, for example two flow constrictions
installed close to each other, for example mounted in series in
a pipe section, such that one DP-generating structure disturbs the
flow pattern at the other DP-generating structure. This solution
utilizes the fact that the DP overreading depends significantly
on the flow pattern, i.e. how the liquid phase is distributed in
the gas. The overreading is e.g. different if the liquid flows as
a thin film at the inner wall of the pipe (annular flow) compared
to a case where it flows as droplets immersed in the gas phase (mist
flow).
[0068] One DP-device can be made by a narrowing of the pipe diameter,
while the other DP-device is constructed by the insertion of a body
on the pipe. This difference in topology makes a difference in the
flow pattern downstream the devices. One DP-device will in this
case create a flow pattern immediately downstream the device with
radially outward pointing velocity components, while the other DP-device
will create velocity components pointing radially inward. Such a
difference can be utilized for creating differential pressure overreadings
containing independent information that is used to extract flow
rate and liquid content. The two DP devices should be installed
close to each other in the pipe to maximize the difference between
the two. The upstream device will then have a fully developed annular/mist
pipe flow regime as its inlet conditions, while the downstream device
will have a flow regime at its inlet that is being influenced by
the upstream DP-device.
[0069] FIG. 2 shows an example embodiment of the present invention
wherein a DDP-unit 2 comprises a double differential pressure generating
part 3 and a corresponding double differential pressure measuring
part 4. A fluid flow 1 inside flowing inside a pipe 30 is shown,
the flow having a flow direction from right to left in this example.
The fluid flow 1 first encounters an upstream element, a first differential
pressure generating device 20 in this case a V-cone structure 20
[10] for generating a first differential pressure .DELTA.P.sub.1
in the fluid flow. Two pressure taps 5A, 5B are located near the
V-cone structure 20. Coupled with the pressure taps 5A, 5B is a
corresponding differential pressure transmitter 6A of a type well
known to those skilled in the art, for transmitting differential
pressure signals to corresponding signal interfaces 9A of a signal
processing unit 8.
[0070] Downstream from the V-cone 20 is a second differential pressure
generating device 21A-C, in this example a venturi, for generating
a second differential pressure .DELTA.P.sub.2. The second differential
pressure will be independent of the first differential pressure
provided the first (upstream) differential pressure generating device
is placed immediately upstream of the second (downstream) differential
pressure generating device. A second set of pressure taps 5C, 5D
are arranged together with corresponding differential pressure transmitter
6B in order to generate and transmit a signal representing this
second differential pressure to the signal processing unit 8.
[0071] At the inlet of the first differential pressure (DP) generating
device, the flow is more annular-like where the liquid tends to
flow as a film. Immediately downstream of the first DP element,
on the other hand, there is a flow region with large turbulence,
a circulating flow and vortex shedding that tends to mix the liquid
into the gas core. When the downstream element (a venturi in the
example) is placed immediately downstream of the first device, this
situation means that the liquid is entrained more into the gas core
at the inlet of the downstream flow meter, a factor that will increase
the difference between the two differential pressure devices.
[0072] A water content meter 7 is arranged, for example directly
coupled with the pipe 30 for generating and transmitting a signal
representing the water content of the fluid flow to the signal processing
unit 8 via a suitable signal interface 9C coupled to the signal
processing unit 8.
[0073] The signal processing unit 8 comprises a calculation module
10 for performing the steps in the processing of the signals received
from the differential pressure transmitters 9A and 9B and from the
water content meter signal interface 9C.
[0074] Another realization of the double differential pressure
generating device 3 which is a part of the present invention is
shown in FIG. 3. The order of the two differential pressure generating
devices has been swapped compared with FIG. 2 now using a venturi
21A-C as the upstream element and a V-Cone 20 as the downstream
element. Still another example is sketched in FIG. 4 using an orifice
23 as the upstream element and an ellipsoid shaped body 22A installed
in the pipe centre as the downstream element.
[0075] A compact version of a double DP device can be constructed
by the measurement of two accelerational pressure drops at or near
the same flow constriction. The basic physics behind such a realization
is based on the difference in inertia of the two phases, due to
the difference in density. The flow constriction will typically
be a single flow cross section reducing device mounted in said stream
1 such as to vary the cross section of said stream Two differential
pressure measuring structures are arranged to measure differential
pressures at two different positions along said flow cross section
reduction device. The geometry of the DP device (which can also
be used as a microwave sensor element) consists of a centred oblong
body 24B inserted in the centre of a pipe section 30 as illustrated
in FIGS. 5 and 6. The insertion body 24B, 25B has an inlet or entrance
region where the flow cross section is reduced followed by a mid
region with a substantially constant reduced flow cross section,
and finally by an outlet or exit region where the flow cross section
again is increased to its full value. In some versions the entrance
region is followed immediately by the exit region, thus there is
no mid region. The idea is that the light gas phase, which is also
the continuous phase in a wet gas application, will be accelerated
first, in the inlet region. Drag forces from the gas will, in its
turn, accelerate the liquid phase and will happen subsequently to
the gas acceleration. This means that the differential pressure
measured at the inlet region will be dominated by the gas acceleration,
while the acceleration of the liquid phase will tend to have a larger
effect on the second DP measurement in the straight section. Expressed
in general terms, a DDP-unit 2 is arranged to have a first differential
pressure measuring device arranged in one of the said regions, and
a second differential pressure measuring device in another one of
said regions. Both of these DP-measuring structures could be arranged
in to measure accelerational pressures. In another version one DP-measuring
structure is arranged to measure accelerational pressure and the
other DP-measuring structure is arranged to measure pressure recovery.
The DP so obtained ratio .DELTA.P.sub.2/.DELTA.P.sub.1 will hence
contain information about the liquid content. At lower liquid contents
this ratio will be low, while at higher liquid contents, the ratio
will increase.
[0076] The dependence can be written in the form (10) but the exact
form must be established experimentally for each new geometry.
[0077] Still another possible solution to the double DP measurement
that can be combined with a microwave water fraction meter is to
measure and compare the accelerational differential pressure and
the pressure recovery over the same flow constriction. This embodiment
of the invention thus constitutes an improvement as compared to
the type of measurement that is utilized in the patent in Ref. [4]
where a venturi meter is utilized for 2-phase gas/liquid flow. The
principle of the present invention is however not limited to a venturi
but can also be realized using a centred body as the DP element,
in which case the flow meter may also comprise a dielectric permittivity
measuring unit, for example a microwave measuring unit including
a microwave resonator or sensor 40 microwave drive electronics
41 and associated microwave signal processing functions being a
part of the signal processing module 8 for example the version
whose geometry is illustrated in FIG. 7 and the schematic of the
measurement as illustrated in FIG. 20. Details of the operation
of a V-cone are explained in reference [3], Norwegian patent No.
315584 which is hereby incorporated by reference. The latter combinations
will be one possible solution to a 3-phase wet gas metering concept
a full 3-phase wet gas meter.
[0078] A compact version of this principle can be realized by introducing
a sudden change in flow cross section (turbulence generating geometry)
to an otherwise more smooth geometry and to measure two differential
pressures within the reduced flow cross-section. These two differential
pressures will then have a certain difference in the relative size
of the acceleration and dissipation related differential pressures.
Examples of such structures are shown in FIGS. 8-9.
[0079] FIG. 8 illustrates a DDP-generating unit similar to the
one in FIG. 6 with the addition of a turbulence generating geometry
26 at one end of the oblong body 25B inserted into the pipe section
30.
[0080] FIG. 9 illustrates an alternative embodiment of the DDP-generating
structure in which a turbulence generating structure geometry 26
is arranged as a part of the venturi 21B-C, e.g. attached to the
pipe walls at one end of the narrow section of the venturi. In FIGS.
8 and 9 the turbulence generating geometry 26 provides an abrupt
change of the diameter of the flow section.
[0081] In the following section the basics of dielectric permittivity
based composition measurements are outlined. When two material components
(A and B), (liquid, gas, or solid particles), with different permittivity
(.epsilon..sub.A and .epsilon..sub.B) are mixed, the mixture has
a permittivity .epsilon..sub.m that is dependent on the mixing ratio
.alpha. of the two components [14]. The mixing ratio is usually
expressed as the total volume of one of the components relative
to the volume of the mixture, e.g. 10 A = V A V A + V B ( 16 )
[0082] where V.sub.A is the volume of component A and V.sub.B is
the volume of component B in a sample of volume Vm=V.sub.A+V.sub.B
of the mixture. If e.g. A is water and B is gas, .alpha..sub.A is
the water content (water volume fraction) of the mixture. In the
case of the fluid produced in a wet gas well, B may be a known mixture
of gas and liquid hydrocarbons, and will therefore be generally
called the hydrocarbon component. The way .epsilon..sub.m depends
on .alpha..sub.A depends on how the components mix with each other
and is therefore specific for these components. As a model for this
dependence, a known model [14] may be used, or an empirical calibrated
model. The Bruggeman formula [14] has e.g. demonstrated to be a
good mixing model in the case of hydrocarbon-water mixtures.
[0083] The water fraction (.alpha..sub.w) in a hydrocarbon based
wet gas can e.g., by the use of the Bruggeman formula be expressed
as: 11 w = 1 - w - mix w - hc ( hc mix ) 1 / 3 ( 17 )
[0084] where .epsilon..sub.w>>1 (typically .about.80) is
the water permittivity, .epsilon..sub.hc.about.1-2 is the hydrocarbon
permittivity, and emix is the measured mixture permittivity. In
the following the basics of microwave microwave resonators are outlined.
One example of how the measurement of permittivity can be realized
is by the use of a microwave resonator. Such a sensor has a resonant
frequency that is dependent on the permittivity of the medium with
which it is filled. If f.sub.0 is the resonant frequency of the
sensor, when it is empty, and f.sub.m, when it is filled with the
mixture, the permittivity of the mixture is [17] 12 mix = ( f 0
f mix ) 2 ( 18 )
[0085] The basics of microwave resonators have been described in
e.g. [17].
[0086] A microwave resonator can be realized as an electromagnetic
cavity between two reflecting discontinuities [17]. When a microwave
resonator sensor is implemented in a pipe for the purpose of measuring
the permittivity of the fluid that is flowing in the pipe, the discontinuities
must have a structure that is open enough so that the fluid can
pass through the sensor. One practical type of discontinuity is
an increase in the cut-off frequency [17]. If the resonant waveguide
has a cut-off frequency that is lower than that of the pipe, and
the resonant frequency of the used mode is the same as the cut-off
frequency, the energy cannot propagate in the pipe. No other reflecting
discontinuity is therefore needed. Microwaves can propagate along
a large variety of structures. There is no reason why the structure
should even be uniform. Therefore, the cross section of the resonant
structure inside the pipe can be different at different locations
along the structure. In the case of non uniform structures, the
wave mode is inhomogeneous and can generally neither be described
by any wave modes known from the literature nor be solved analytically.
In such cases, the resonant frequencies and field distributions
can be solved approximately by numerical methods using e.g. FEM
(finite element method) software. Any structure with a resonant
frequency that is lower than the cut-off frequency of the pipe can
in principle be used as a resonator sensor [17]. Several examples
(based on venturi tubes, orifices, V-Cones) of how to realize a
combined geometry to be used as microwave resonator and differential
pressure flow meter are described in [3]. One example is the V-Cone
geometry shown in FIG. 10. This structure will behave as a microwave
resonator. The electromagnetic behaviour of the V-Cone sensor can
be viewed as a 1 wavelength coaxial resonator where the electromagnetic
energy is confined in the microwave cavity as defined by the V-Cone
length. This structure has an advantageous electromagnetic field
distribution that makes it well suited for water fraction detection
in a wet gas stream:
[0087] In the axial direction, the field has its maximum at the
cone edge were the gas velocity is highest. The water content will
hence be measured at this location.
[0088] The field is uniformly distributed along the circumference
of the gap, making the sensor less flow regime dependent.
[0089] Computer simulations of electromagnetic fields using the
FEM method as well as measurements have shown a frequency response
with a clean and single resonance peak in the actual frequency range,
see the example curve in FIG. 11. A 3-phase wet gas meter for the
individual measurements of gas, liquid hydrocarbons and water flow
can be constructed by a combination of a double DP flow metering
device and a separate water fraction detection sensor. The water
fraction unit may e.g. be based on any type of dielectric measurement
that gives a measure of the mixture permittivity. The microwave
resonator is one practical solution to the dielectric measurement
that can be employed together with the double DP measurement to
constitute a sensitive and compact realization of a 3-phase wet
gas-metering concept. The signal processing unit 8 of the 3-phase
meter according to the invention comprises modules for performing
the computational steps illustrated in the flow diagram in FIG.
12 and FIG. 13. FIG. 12 shows the computational modules that can
be used in the case that a general water content meter is combined
with a DDP unit, while FIG. 13 shows the computational modules in
the particular case that the water content meter is based on a dielectric
measurement of the permittivity of the fluid mixture.
[0090] 1) In module 100 and the submodule 110 the individual properties
of gas, liquid hydrocarbons and water are calculated based on the
measured or given temperature and pressure and on the given molecular
composition of gas and liquid hydrocarbons. In module 100 the individual
densities (.rho.) of gas, liquid hydrocarbons, and water are calculated
based on the measured temperature and pressure using empirical models
or e.g. from a PVT software module. 13 P , T , PVT , Models g ,
c , ww
[0091] In the case of a dielectric measurement of water fraction
(FIG. 13), the individual gas, liquid hydrocarbons and water permittivities
are calculated in block 110 from the given components individual
densities, from pressure and temperature based on empirical models
14 P , T , g , c , w Models , g , c , w
[0092] 1) In module 200 the composition of the fluid flow is calculated
based on the measured differential pressure ratio and the measured
water fraction. In the case of a general water fraction meter (FIG.
12), the measured water fraction is an input to the computational
module. The 3 unknown (.alpha..sub.w,.alpha..sub.c,.alpha..sub.g)
are found solving the following set of equations 15 1 ) p 2 p 2
= F ( X LM ) = F ( g , c , w , g , c , w ) 2 ) wmeasured = w 3 )
w + c + g = 1 } g , c , w
[0093] where F(X.sub.LM) is an empirical calibration model. This
set of equations must normally be solved numerically by iterative
computer means). In the case that a dielectric water fraction detection
method (e.g. a microwave sensor) is being used for water detection
(FIG. 13) the measured mixture permittivity is the basis for the
composition measurement and the set of equations can be written:
16 1 ) p 2 p 2 = F ( X LM ) = F ( g , c , w , g , c , w ) 2 ) mix
= mix ( g , c , w , g , c , w ) 3 ) w + c + g = 1 } g , c , w
[0094] In the case that the dielectric water detection unit is
a microwave resonator, the mixture permittivity is found from the
measured resonant frequency based on Eq. (18). The output from the
module 200 is the individual volume flow fractions of gas, liquid
hydrocarbons and water.
[0095] 2) In module 300 the gas flow rate is computed from one
of the measured differential pressures and from the calculated fractions
according to the scheme in Eq. (1)-(5):
.DELTA.p.sub.1.fwdarw.Q.sub.g
[0096] 3) In module 330 the final step of computing liquid hydrocarbons
and water flow rates is performed based on calculated fractions
and gas rate:
.alpha..sub.g,.alpha..sub.c,.alpha..sub.w,Q.sub.g.fwdarw.Q.sub.c,Q.sub.w
[0097] FIG. 14 illustrates how the computation in the 3-phase wet
gas flow meter according to the present invention may comprise an
iteration procedure as part of the calculation of fluid fractions
as in block 200 of FIG. 13 from raw measurements and input data.
An initial guess of the fractions of the fluid flow is initially
supplied together with the density and dielectric permittivity of
the gas, water and liquid hydrocarbons from module 100 and 110 to
a calculation module performing the estimation of quantities of
gas, water and liquid hydrocarbons.
[0098] Based on the supplied input signals, values are calculated
400 for the differential pressure ratio .DELTA.P.sub.2'.DELTA.P.sub.1
and the permittivity of the mixture, .epsilon..sub.mix. These calculated
values are compared 500 with the measured values. In the case that
the calculated values differ from the measured values by less than
a given amount, the calculated and measured values are deemed to
be equal, and the present input values for the fractions constitute
the desired result. In the case that the calculated values and the
measured values differ by an amount larger than a given value, a
signal is given to the update fractions module in order that a new
update or a new calculation of the fractions may be computed. Typically,
a computation will be performed using a Newtons method or other
similar techniques known to those skilled in the art, based on the
measured and estimated values. The new calculated fractions will
is then the new input to the calculation and comparison. This iteration
will typically be performed a number of times until a solution is
obtained, i.e. until calculated quantities are equal to the measured
quantities within a given tolerance or a given error margin. The
various functions and modules of the signal processing module above
will typically be realized as computer program code or software
adapted to operate in a signal processing module being a part of
a general-purpose computer, microprocessor, or computing device
known to those skilled in the art or a custom made embedded microprocessor.
A 3-phase wet gas meter can e.g. be realized by a number of different
combinations of one of the double DP devices described above in
combination with one of the microwave resonators listed in Ref[3],
the full content of which is hereby incorporated by reference. A
few examples of possible realizations are shown in FIG. 15-18. FIGS.
15-18 illustrate examples of the arrangement of microwave coupling
structures 40 which can be e.g. probes, loops, irises, or combinations
of such, in order to be able to excite and measure an electromagnetic
field within the resonating structure 42 see e.g. pp. 40-43 in
[17]. The microwave resonance can be measured with various techniques
known to anyone skilled in the art, based on e.g. the measurement
of the reflection (requires one coupling device only) or transmission
(requires two coupling devices) of microwaves, as described on pp.
30-37 in [17]. Any type of suitable microwave drive electronics
known to anyone skilled in the art may be used as schematically
illustrated in FIG. 20 to provide a suitable signal interface to
the microwave coupling structures 40. Such a drive 41 unit will
typically comprise an output module to provide output signals to
the microwave coupling structures 40 for exciting a microwave field
and a signal receiving module for receiving signal from microwave
coupling structures representing a characteristic property of the
microwave field within the resonating structure 42 e.g. the amplitude
or phase of the microwave field typically characterized in terms
of the reflection or transmission coefficient of the resonator.
The drive electronics 41 may either be locked to the resonant frequency
(see e.g. pp. 125-130 in [17]), or measure the reflection or transmission
coefficient as a function of frequency, i.e. the frequency response,
from which the characteristics of the resonance can be derived as
described on pp. 30-37 in [17]. The drive unit 41 or at least the
receiving module will be coupled with the signal processing module
8 in order that the characteristics of the microwave field obtained
is transferred to and can be processed in the signal processing
module 8. It is also, as an alternative to the microwave based water
detection, possible to use a capacitance type of dielectric measurement
to determine the water content, as exemplified in FIG. 19. Capacitance
electrodes 50 are arranged in such a manner that the total capacitance
is determined by the wet gas stream 1 flowing in the pipe 30. A
capacitance measurement, such as e.g. described in the Reference
[18], can then be combined with a double DP unit to make up a 3-phase
wet gas meter. Typically the capacitance electrodes will be coupled
to the signal processing module 8 via a drive electronics module,
similarly to the microwave sensor illustrated in FIG. 20. In summary,
the invention disclosed herewith provides a 3-phase wet gas meter
concept which is capable of measuring the individual flow rates
of gas, liquid hydrocarbons and water in a wet gas stream. This
is a new way of combining a double DP and a water detection unit
(e.g. a microwave resonator). This new device and method for 3-phase
measurement concept yields a lowered uncertainty of the wet gas
flow rate measurement as compared to a 2-phase gas/liquid concept
because of the possibility to quantify the liquid (water+liquid
hydrocarbons) properties. Further, 3-phase wet gas meter according
to this invention can be made compact because the same sensor geometry
can be used for the fluid composition measurement and for the flow
rate measurement.
Abbreviations:
[0099]
1 Abbreviations: DP Differential pressure DDP Double Differential
pressure GVF Gas Volume Fraction PVT Pressure Volume Temperature
[0100]
2 Symbols A.sub.constriction Flow cross section in flow meter constriction
- minimum cross section A.sub.pipe Flow cross section in flow meter
pipe C.sub.d Flow meter discharge D Pipe inner diameter f.sub.0
Resonant frequency in vacuum f.sub.mix Resonant frequency with fluid
filled sensor f.sub.mw Microwave resonant frequency Q.sub.g Gas
volumetric flow rate Q.sub.g0 Gas volumetric flow rate - calculated
assuming single phase gas flow rate Q.sub.l Liquid volumetric flow
rate V.sub.A.vertline.B Volume of component A X.sub.LM Lochard Martinelli
number y Fluid (wet gas) expansibility .alpha..sub.A Volume fraction
of component A .alpha..sub.c Liquid hydrocarbons volume flow fraction
.alpha..sub.g Gas volume flow fraction .alpha..sub.l Liquid volume
flow fraction .alpha..sub.w Water volume flow fraction .alpha..sub.c0
Initial guess liquid hydrocarbons volume flow fraction .alpha..sub.g0
Initial guess gas volume flow fraction .alpha..sub.w0 Initial guess
water volume flow fraction .beta. Flow meter beta ratio .epsilon.
Permittivity (dielectric constant) .epsilon..sub.c Permittivity
of liquid hydrocarbons .epsilon..sub.g Permittivity of gas .epsilon..sub.hc
Permittivity of hydrocarbon phase .epsilon..sub.mix Permittivity
of fluid mixture .epsilon..sub.w Permittivity of water .DELTA.p
Differential pressure .DELTA.p.sub.g Differential pressure from
single phase gas flow .PHI..sub.g 2-phase gas multiplier .rho..sub.c
Liquid hydrocarbons density .rho..sub.g Gas density .rho..sub.l
Liquid density .rho..sub.w Water density
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