## Abstrict A measurement apparatus which utilizes the direct relationship
between the density and dielectric constant of hydrocarbon mixtures
to significantly improve upon the measurement capabilities of some
existing devices used in the petroleum industry. Included among
the applications of the apparatus are 1) a multiphase hydrocarbon
mass flow meter for usage with multiphase mixtures of oil, water,
and gas and 2) a continuously self-calibrating water cut meter for
determining the water content of liquid crude oil streams.
## Claims I claim:
1. An apparatus for measuring the mass of hydrocarbon contained
in a crude oil or natural gas production stream consisting primarily
of crude oil, water, and gas, such apparatus comprising:
means forming a measurement section including a conduit for conducting
a fluid mixture therethrough;
first measuring means mounted at said measurement section for measuring
a temperature of the mixture and for generating a first signal representing
said temperature;
second measuring means mounted at said measurement section for
measuring the dielectric constant of the mixture and for generating
a second signal representing said dielectric constant;
third measuring means mounted at said measurement section for measuring
a density of the mixture and for generating a third signal representing
said density;
means connected to said first, second, and third measuring means
for receiving said first, second, and third signals, respectively,
and, based upon said signals and upon a predetermined relation between
hydrocarbon density and dielectric constant, for generating first
output signal representing the volumetric water content of the mixture,
a second output signal representing the volumetric hydrocarbon content
in the mixture, a third output signal representing the hydrocarbon
density in the mixture, and a fourth output representing the hydrocarbon
mass in the mixture.
2. An apparatus of claim 1 further including:
a fourth measuring means mounted on the measurement section for
measuring the flow rate of the mixture and for generating a fourth
signal representing said flow rate;
wherein said receiving means includes means for generating, based
upon said first, second, third, and fourth signals, a fifth output
signal representing a mass flow rate of hydrocarbons.
3. An apparatus for measuring the water content in a liquid crude
oil or natural gas production stream, such apparatus comprising:
means forming a measurement section including a conduit for conducting
a fluid mixture therethrough;
first measuring means mounted at said measurement section for measuring
a temperature of the mixture and for generating a first signal representing
said temperature;
second measuring means mounted at said measurement section for
measuring the dielectric constant of the mixture and for generating
a second signal representing said dielectric constant;
third measuring means mounted at said measurement section for measuring
a density of the mixture and for generating a third signal representing
said density;
means connected to said first, second, and third measuring means
for receiving said first, second, and third signals, respectively,
and, based upon said signals and upon a predetermined relation between
hydrocarbon density and dielectric constant, for generating first
output signal representing the volumetric water content of the mixture
and a second output signal representing the density of the hydrocarbon
in the mixture.
4. An apparatus of claim 1 further including:
a fourth measuring means mounted on the measurement section for
measuring the flow rate of the mixture and for generating a fourth
signal representing said flow rate;
wherein said receiving means includes means for generating, based
upon said first, second, third, and fourth signals, a third output
signal representing a mass flow rate of the hydrocarbons.
## Description BACKGROUND OF THE INVENTION
This invention relates to the field of meters and particularly
to meters for continuously measuring the composition and mass flow
rate of mixtures containing hydrocarbons. Many types of measurement
apparatus have been proposed and are being used for continuously
measuring water content, density, or composition of hydrocarbon
or hydrocarbon and water mixtures. But most suffer from a number
of limitations caused by difficulties with measuring mixtures containing
liquid and gas or difficulties associated with variations in the
specific gravity of the hydrocarbon being measured. Measuring the
composition of oil, water, and gas mixtures is one example. Meters
for this purpose are typically referred to as multiphase composition
meters. See U.S. Pat. Nos. 4458524 and 4760742 and U.K. Patent
2210461.
The current practice in the oil industry for measuring the quantities
of oil, water, and gas being produced by a given well or group of
wells is to separate the components in a separator and measure the
components individually. The separators are large, expensive, maintenance
intensive, and typically provide production information only at
long intervals. With continuous multiphase meters to replace the
separators, oil producers can dramatically improve the crude oil
and natural gas production process, particularly offshore production.
Most proposed multiphase composition meters are designed to continuously
measure the volume fractions of oil, water, and gas being produced.
The composition meter can be combined with a flowmeter such that
production rates for the three components can be calculated. One
variety of proposed multiphase composition meter combines a dielectric
constant measurement means with a density measurement means. See,
for example, U.S. Pat. No. 4458524. These devices take advantage
of the different dielectric constant and densities of oil, water,
and gas respectively to determine their volume fractions. Temperature
and pressure sensors are included in the metering package to facilitate
these calculations.
In order for them to function properly, they must be able to calculate
the dielectric constants and/or densities of the three individual
components at the measurement conditions. This is impossible. Several
of the lower-density hydrocarbon components (ethane, propane, butane,
and pentane among them) can exist in either a liquid or a gaseous
state at pressures between 20 and 250 atm. Therefore, the fundamental
methods and equations used by these meters to determine the composition
of the multiphase production streams are flawed. In fact, it is
not possible to accurately determine the volume fractions of oil,
water, and gas without knowing how much of each hydrocarbon constituent
is in the liquid or gaseous phase at any given time. Such information
is not available on a continuous basis.
Another important measurement problem in the oil industry is the
accurate measurement of the water content of liquid crude oil streams.
The water content directly affects the price paid for crude oil.
Many devices have been developed to continuously measure the water
content. See U.S. Pat. Nos. 3498112 and 4862060 for examples.
The most commonly used measurement device for this application is
a capacitance meter which measures the dielectric constant of the
mixture to determine its water content. Many meters besides capacitance
meters utilize dielectric measurements for measuring the water content
of crude oils, including various microwave meters. A common problem
for all of these devices is that the density and dielectric constant
of the crude oil vary over time. These variations result directly
in significant measurement error.
SUMMARY OF INVENTION
To avoid the problems associated with measuring multiphase flow
where the physical properties of the liquid and gaseous hydrocarbon
cannot be determined, it is appropriate to consider the hydrocarbon
liquids and gases as a single component with an unknown density.
A suitable multiphase composition meter would then determine the
volumetric fraction and the density of the hydrocarbon, i.e. the
mass, of the hydrocarbon material in a multiphase mixture and the
water content of the mixture. Armed with this information plus flow
rate information, the user can more correctly determine how much
oil and gas are being produced at standard conditions.
Therefore, a multiphase hydrocarbon mass meter to be used in crude
oil or natural gas multiphase production lines is considered desirable.
One embodiment of this invention combines a dielectric measurement
means, a density measurement means, and a temperature measurement
means to determine the instantaneous hydrocarbon mass flowing through
the meter. The present invention utilizes a heretofore unknown relationship
between the density of a hydrocarbon, whether liquid, gas or a combination
thereof, and its dielectric constant.
As with the multiphase hydrocarbon mass meter, an improved meter
to measure water content (i.e. a water cut meter) which consists
of a combination of a dielectric measurement means, a density measurement
means, and a temperature measurement means makes it possible to
continuously correct the water cut meter for variations in the oil's
dielectric properties. Combining this improved water cut meter with
a flow meter give the additional possibility of continuously totalizing
the production rates of the oil and water in terms of volume or
mass per unit of time and continuously measuring the crude oil quality
which is directly related to its density. This improved water cut
meter is useful with crude oils, gas condensates, and liquid natural
gases.
It is an object of the invention to provide an improved multiphase
measuring apparatus for measuring the instantaneous hydrocarbon
mass and mass flow rate in a crude oil or natural gas production
line containing primarily oil, water, and gas.
It is an object of the invention to provide an apparatus which
includes measurement means for measuring mixture dielectric constant,
density, and temperature.
It is an object of the invention to provide an apparatus for determining
the instantaneous hydrocarbon mass contained in the apparatus in
accordance with the measured dielectric constant, density, and temperature.
It is an object of the invention to provide an apparatus which
includes an instantaneous hydrocarbon mass meter and a flow rate
meter.
It is an object of the invention to provide an apparatus for determining
the hydrocarbon mass flow rate in accordance with the measured instantaneous
hydrocarbon mass and its flow rate.
It is the object of the invention to provide an improved water
cut meter for continuously measuring the water content and liquid
hydrocarbon density in a crude oil or liquid natural gas production
line containing primarily liquid hydrocarbon and water.
It is an object of the invention to provide an apparatus which
includes measurement means for measuring mixture dielectric constant,
density, and temperature.
It is an object of the invention to provide an apparatus for determining
the instantaneous hydrocarbon density and water content contained
in the apparatus in accordance with the measured dielectric constant,
density, and temperature.
It is an object of the invention to provide an apparatus which
continuously calibrates itself for changes in the dielectric constant
of the liquid hydrocarbon so as to more accurately measure the water
content of the liquid hydrocarbon.
It is an object of the invention to provide an apparatus which
combines the self-calibrating water cut meter with a flow meter.
It is an object of the invention to provide an apparatus for determining
the liquid hydrocarbon and water volumetric production rates or
mass flow rates in accordance with the measured water content, liquid
hydrocarbon density, and flow rate.
BRIEF DESCRIPTION OF THE DRAWINGS
FIGS. 1 and 2 are plots of the square root of the dielectric constant
versus hydrocarbon density for liquid hydrocarbons and hydrocarbon/gas
mixtures respectively.
FIG. 3 is a block diagram of a multiphase hydrocarbon mass meter
constructed in accordance with the present invention.
FIG. 4 is a block diagram of a hydrocarbon mass flow meter constructed
in accordance with the present invention.
FIG. 5 is a block diagram of an improved water cut meter constructed
in accordance with the present invention.
FIG. 6 is a block diagram of an oil and water mass flow meter constructed
in accordance with the present invention.
DESCRIPTION OF THE INVENTION
Theory
Prior Art multiphase fraction meters which comprise a device for
measuring the dielectric constant and the density of the mixture
implement the following relations to determine the volume fractions
of oil, water, and gas:
where
`w` is the subscript for water,
`o` is the subscript for oil,
`g` is the subscript for gas,
`mix` is the subscript for the multiphase mixture,
V=Volume fraction,
.rho.=Density,
e=dielectric constant.
Equation 3 is any of a number of equations which describe the relationship
between the dielectric constant of the mixture and the dielectric
constants and volume fractions of the components. For example, one
might use the Looyenga mixing relation:
In these equations, the volume fraction V.sub.w, V.sub.o, and V.sub.g
are to be calculated from the measured mixture density .rho..sub.mix
and dielectric constant e.sub.mix. The dielectric constant and densities
of the three components vary with temperature and pressure. Therefore,
the appropriate values must be calculated at the measurement temperature
and pressure if the procedure is to work. This can be done if the
physical properties of the oil, water, or gas taken separately do
not change with temperature and pressure in an unpredictable fashion.
But, such is not the case. Several of the hydrocarbon components
can be in either the liquid or gaseous state at higher pressures;
therefore, the oil and gas densities and dielectric constants are
unknown at high pressure.
The method and apparatus of this invention differ from this standard
approach by considering the oil and gas components as a single hydrocarbon
material with an unknown density and dielectric constant. The invention
utilizes the principal that the dielectric constant and density
of hydrocarbons produced by oil wells can be directly related to
one another. This is true if the hydrocarbon is liquid, gas, or
a combination thereof.
This principle is illustrated in FIGS. 1 and 2. FIG. 1 shows the
square root of the measured dielectric constant versus density for
a variety of hydrocarbon liquids at 15.degree. C. A linear curve
fit is also shown in the figure. The lowest density hydrocarbon
is pentane with a density of approximately 0.67 g/ml. The highest
density hydrocarbon is a heavy crude oil having a density of approximately
0.92 g/ml. Included among the hydrocarbons shown in FIG. 1 are crude
oils, gas condensates, and individual hydrocarbon fractions. As
FIG. 1 shows, the square root of the dielectric constant and the
density of hydrocarbon liquids are linearly related with the zero
density intercept being 1. In other words, as the density approaches
zero, the dielectric constant approaches 1 which is the dielectric
constant of vacuum which has a density of zero.
FIG. 2 shows the square root of the dielectric constant as a function
of density for a crude oil mixed with varying amounts of gas. The
volummetric fraction of gas extends from 0 to 55%. Here too, the
relationship between the square root of the dielectric constant
and the density is linear and the zero density intercept is 1. In
this case the dielectric constant of the gas is approximately equal
to 1.0005.
The linear curve fits in FIGS. 1 and 2 are virtually identical.
In practice, the slope of these curves varies slightly with temperature.
This demonstrates the important principal that the density of a
hydrocarbon, whether liquid, gas or a combination thereof, can be
related accurately to its dielectric constant. This principal is
the foundation of this invention. The principal has heretofore not
been recognized in the scientific literature (to our knowledge)
nor has it been utilized in the design of multiphase meters or water
cut meters.
The relationship between hydrocarbon dielectric constant and density
can be used to avoid the problems associated with measuring liquid
and gas hydrocarbon fractions at high pressure. Instead of measuring
oil, water, and gas fractions, the multiphase meter can instead
measure hydrocarbon and water fractions and the density of the hydrocarbon;
i.e. the multiphase hydrocarbon mass meter continuously measures
the mass of the hydrocarbon being produced. Instead of using Equations
1 to 3 the multiphase hydrocarbon mass meter would use a measurement
procedure illustrated by the following relations:
where
`hyd` is the subscript for hydrocarbon.
Equation 4 could be any of a number of equations which describe
the relationship between the dielectric constant of a mixture and
the dielectric constant and volume fractions of its components.
The following relation could be used for example:
In Equations 4-6 there are three unknowns: V.sub.hyd, .rho..sub.hyd,
and e.sub.hyd. But the dielectric constant and the density of the
hydrocarbon can be related using the principal illustrated in FIGS.
1 and 2 namely:
where
`A` is a constant which is a function of temperature. For one specific
temperature, `A` is the slope of the curves shown in FIGS. 1 and
2.
Using this relation, the component relations reduce to the following
three equations;
Thus, by measuring the mixture dielectric constant (e.sub.mix)
and mixture density (.rho..sub.mix) and calculating the dielectric
constant (e.sub.w) and density (.rho..sub.w) of the water at the
measurement temperature, it is possible to determine the hydrocarbon
fraction (V.sub.hyd) and the hydrocarbon density (.rho..sub.hyd)
in the mixture. Such is the basis for the multiphase hydrocarbon
mass meter which measures both the instantaneous mass of hydrocarbon
contained in a multiphase mixture and the water content of the mixture.
The instantaneous mass is equal to V.sub.hyd .times..rho..sub.hyd.
This meter when combined with a flow meter makes it possible to
measure the mass flow rate of the hydrocarbon and water respectively.
The principle of the self-calibrating water cut meter is much the
same. Water cut meters which are based on a measurement of the dielectric
properties of liquid hydrocarbon and water mixtures to determine
the water content are based a dielectric mixing law such as Equation
3 but simplified for two components. We have:
where
`w` is the subscript for water,
`o` is the subscript for oil,
`mix` is the subscript for the multiphase mixture,
V=Volume fraction,
e=dielectric constant.
Equation 11 could be any of a number of dielectric mixing laws
such as:
In order for the principle to be applied accurately, the dielectric
constant of the liquid hydrocarbon must remain constant over time.
Unfortunately, this is not usually the case. The dielectric constant
of the liquid hydrocarbon produced by individual wells varies. The
situation is even more complex when the liquid being measured is
the commingled flow of many different wells. For commingled flow
the dielectric constant of the hydrocarbon can change significantly
as the production rates of the different feeder lines vary. This
problem (among others) means that existing water cut meters do not
deliver sufficient accuracy for many of the more crucial applications
in the oil industry.
One can take advantage of the close relationship between hydrocarbon
density and dielectric constant as illustrated in FIG. 2 to alleviate
this problem. Combining a density measurement means with the dielectric
constant measurement means and temperature measurement means, one
can correct for variations in the hydrocarbon dielectric constant
by determining it density continuously. One has the following relations:
where
A is a constant which is a function of temperature.
By combining the density measurement means, the dielectric measurement
means and by using these relations, the improved water cut is able
to use the density information to adjust the dielectric constant
of the crude oil as it changes over time. In other words, by simultaneously
solving the relations for water cut and mixture density as expressed
in Equations 13 and 14 the improved water cut meter calibrates
itself for changes in the oil's dielectric properties over time.
This is what is meant by self-calibrating water cut meter.
Multiphase Hydrocarbon Mass and Mass Flow Meter
The novel relation between a hydrocarbons density and its dielectric
constant as shown in the foregoing theoretical section is used in
this embodiment of the present invention as a means of determining
hydrocarbon mass and mass flow rate. With reference to FIG. 3 the
production stream, consisting of water, crude oil, and gas, flows
through a multiphase hydrocarbon mass meter generally designated
by the numeral 10. Apparatus 10 includes a fluid flowing conduit
20 through which the mixture passes. The mixture to be measured
may be conducted through conduit 20 on a continuous basis and conduit
20 may comprise part of a mixture transmission pipeline. Temperature
measurement means 30 measures the temperature `T` of the mixture.
An optional pressure measurement means 40 measures the pressure
`P` of the mixture. Apparatus 10 includes a dielectric measurement
means 50 for measuring the dielectric properties `e` of the mixture.
Dielectric measurement means 50 may be any of a variety of devices
for measuring the dielectric properties of flowing material such
as a capacitance meter or a microwave meter. Apparatus 10 includes
a density measurement means 60 which measures the density `D` of
the mixture. Density measurement means 60 may by any device capable
of measuring the density of multiphase mixtures. One such device
would be a gamma densitometer.
Temperature measurement means 30 pressure measurement means 40
dielectric measurement means 50 and density measurement means 60
are connected to multiphase hydrocarbon mass measurement means 70
and provide signals corresponding to the measured T, P, e, D values.
Multiphase hydrocarbon mass measurement means 70 calculates the
correct density and dielectric constant for the water from the measured
temperature (and pressure). From these values and e and D, multiphase
hydrocarbon mass measurement means 70 provides an indication of
the volumetric water content, the volumetric hydrocarbon content,
and the hydrocarbon density. The product of the hydrocarbon density
and the hydrocarbon volumetric content is equal to the hydrocarbon
mass `M`.
Referring now to FIG. 4 multiphase hydrocarbon mass meter 80 is
connected to a flow rate measurement means 110 with a pipe section
100. The combined apparatus is a multiphase hydrocarbon mass flow
meter and is designated as 120. The multiphase mixture can flow
freely through the multiphase hydrocarbon mass flow meter 120. Flow
rate measurement means 100 measures the flow rate V of the mixture
as it passes and provides a corresponding flow rate signal to multiphase
hydrocarbon mass measurement means 90. Multiphase hydrocarbon mass
measurement means 90 provides an indication of the hydrocarbon mass
flow rate in accordance with the received signal V and the measured
value M.
Numerous variations and modifications can be made without departing
from the invention. For example, many types of temperature measurement
means, pressure measurement means, dielectric measurement means,
density measurement means, or flow rate measurement means could
be used as components of the multiphase hydrocarbon mass flow meter.
Moreover, the design of measurement means 70 or 90 could take on
many forms. Different combinations of analog to digital converters,
digital to analog converters, comparators, look up tables, microprocessors,
etc. could be used to determine the instantaneous hydrocarbon mass
and mass flow rate from the input signals. Accordingly, it should
be clearly understood to anyone skilled in the art that the form
of the invention described above and shown in the figures is general
in nature and not intended to limit the scope of the invention to
any specific component measurement means within the scope and spirit
of the appended claims.
Self-Calibrating Water Cut Meter
The novel relation between a hydrocarbons density and its dielectric
constant at shown in the theoretical section is used in this embodiment
of the present invention as a means of determining the water cut
corrected for the changing dielectric constant of the liquid hydrocarbon.
In addition the relation makes possible the continuous determination
of the density of the hydrocarbon, corrected for the water content,
and its mass flow rate. In illustrating this embodiment, reference
will be made to FIGS. 5 and 6.
With reference to FIG. 5 the production stream, consisting of
water and liquid hydrocarbon such as crude oil, LNG, or LPG, flows
through a self-calibrating water cut meter generally designated
by the numeral 210. Apparatus 210 includes a fluid flowing conduit
220 through which the mixture passes. The mixture to be measured
may be conducted through conduit 220 on a continuous basis and conduit
220 may comprise part of a mixture transmission pipeline. Temperature
measurement means 230 measures the temperature `T` of the mixture.
An optional pressure measurement means 240 measures the pressure
`P` of the mixture. Apparatus 210 includes a dielectric measurement
means 250 for measuring the dielectric properties `e` of the mixture.
Dielectric measurement means 250 may be any of a variety of devices
for measuring the dielectric properties of flowing materials such
as a capacitance meter or a microwave meter. Apparatus 210 includes
a density measurement means 260 which measures the density `D` of
the mixture. Density measurement means 260 may be any device capable
of measuring the density of multiphase mixtures. The density measurement
means could be a gamma densitometer, a Coriolis Meter, or a vibrating
fork densitometer for example.
Temperature measurement means 230 pressure measurement means 240
dielectric measurement means 250 and density measurement means
260 are connected to water cut measurement means 270 and provide
signals corresponding to the measured T, P, e, D values. Water cut
measurement means 270 calculates the correct density and dielectric
properties for the water from the measured temperature (and pressure).
From these values and e and D, water cut measurement means 270 provides
an indication of the instantaneous water cut `W` and the hydrocarbon
density `B` in conduit 220.
Referring now to FIG. 6 water cut meter 280 is connected to a
flow rate measurement means 310 with a pipe section 300. The combined
apparatus is an oil and water mass flow meter and is designated
as 320. The water and oil mixture can flow freely through the crude
oil mass flow meter 300. Flow rate measurement means 310 measures
the flow rate V of the mixture as it passes and provides a corresponding
flow rate signal to water cut measurement means 290. Water cut measurement
means 290 provides an indication of the hydrocarbon mass flow rate
in accordance with the received signal V and the measured values
W and B. In fact the hydrocarbon mass flow rate is the product of
V.times.B.times.(1-W).
Numerous variations and modifications can be made without departing
from the invention. For example, many types of temperature measurement
means, pressure measurement means, dielectric measurement means,
density measurement means, or flow rate measurement means could
be used as components of the hydrocarbon mass flow meter. Moreover,
the design of measurement means 270 and 290 could take on many forms.
Many different combinations of analog to digital converters, digital
to analog converters, comparators, look up tables, microprocessors,
etc. could be used to determine the instantaneous hydrocarbon mass
and mass flow rate from the input signals. The basic concept of
using the density signal to correct for the changing dielectric
constant of one of the base components of a mixture could be used
for more accurately determining the composition of any mixture containing
a high dielectric constant material such as water in a low dielectric
constant material such as oil. Accordingly, it should be clearly
understood to anyone skilled in the art that the form of the invention
described above and shown in the figures is general in nature and
not intended to limit the scope of the invention to any specific
component measurement means within the scope and spirit of the appended
claims. |