Measuring and testing – Volume or rate of flow – Of selected fluid mixture component
Reexamination Certificate
2001-12-20
2004-06-29
Lefkowitz, Edward (Department: 2855)
Measuring and testing
Volume or rate of flow
Of selected fluid mixture component
Reexamination Certificate
active
06755086
ABSTRACT:
FIELD OF THE INVENTION
The present invention relates to the field of flow meters for multiphase mixtures. In particular, the invention relates to flow meters for oil and water mixtures in hydrocarbon wells.
BACKGROUND OF THE INVENTION
The measurement of oil and water flow rate in each producing zone of an oil well is important to the monitoring and control of fluid movement in the well and reservoir. In addition to a flow meter, each zone may have a valve to control the fluid inlet from that zone. By monitoring flow rates of oil and water from each zone and reducing flow from those zones producing the highest water cut (i.e., ratio of water flow rate to total flow rate), the water production of the entire well can be controlled. This, in addition, allows the reservoir oil to be swept more completely during the life of the well.
To evaluate the water and hydrocarbon flow rates in homogeneous flows in a well, three quantities must be estimated, namely, the mean water volume fraction H
w
, the mean water velocity v
w
, and the mean hydrocarbon velocity v
o
. The flow rates are then as follows:
q
w
=AH
w
v
w
[1]
for the water; and
q
o
=A
(1
−H
w
)
v
o
[2]
for the hydrocarbon, where A is the section of the well.
When the flow is not homogeneous, which is possible in deviated wells, flow-rate evaluations based on the above equations are invalid. It is then necessary to take account of the effective distribution of the velocities and of the volume fractions across the section of the well. In order to adopt such an approach, it is necessary that a plurality of devices are placed across a given cross-section of the well.
It is also known that the velocity of a flow in a well can be determined by measuring a magnitude that varies over time s
1
(t) and s
2
(t) at two different locations in the well separated in the direction of flow, and then by calculating a cross-correlation function:
C=<s
1
(
t
)*
s
2
(
t+T
)> [3]
In a two-phase fluid, the fluctuations in the magnitude s(t) may, for example, be due to inhomogeneous structures propagating along the pipe at the mean speed of the flow.
If T is the value of t found for which C is a maximum, the speed v of the flow is given by:
v=L/T
[4]
where L is the axial distance between the two measurement sections.
Ideally, a flow meter for making such measurement in a well should satisfy several criteria: 1) it should be extremely reliable and operate for long periods at downhole temperature and pressure; 2) it should operate in both stratified (near-horizontal) and dispersed flow regimes over a wide range of total flow rate and cut; 3) it should not require that the well completion be oriented azimuthally in any particular way during installation; 4) it should not require the use of radioactive sources: and 5) the flow meter should allow small changes in water cut and flow rate to be detected.
Typically, downhole flow meters determine the holdup (volume fraction of oil or water) and the velocity of the oil phase, the water phase, or both. The flow rate of water is then determined from the product of water holdup &agr;
w
, the pipe area A, and the velocity of water U
W
. An analogous relation holds for oil flow rate. In general, the velocities of water and oil are different. The slip velocity (difference in oil and water velocities) depends on many parameters, such as the inclination angle of the flow pipe (i.e. deviation), roughness of the pipe wall, and flow rates of the two phases. In general, one must measure the holdup and velocities of both oil and water to determine oil and water flow rate uniquely. In practice, sometimes one measures the velocity of only one phase and uses a theoretical or empirically determined slip law to obtain the other. This has a number drawbacks including inaccuracies due to differences conditions used as inputs to the model and the actual conditions downhole.
A common method to determine the velocity of a fluid is to measure the rotation rate of a spinner in the flow stream. In single phase flow, the rotational velocity of the spinner is simply related to the velocity of the flow. However, in mixed oil and water flow the response of the spinner can be so complicated as to be impossible to interpret.
Another method of velocity measurement uses tracers. A tracer is injected into the phase of choice (oil or water) and, at a known distance downstream, a sensor detects the time of passage of the tracer. The velocity is computed from the known distance and time of travel. One disadvantage of the tracer method for permanent downhole use is the need for a reservoir of tracer material and a mechanical tracer injector. The reservoir limits the number of measurements and the injector, being a mechanical device, is prone to sticking and failure.
Another method of velocity measurement uses a Venturi. In single phase flow, a Venturi generally obeys the Bernoulli equation which relates volumetric flow rate Q to fluid density &rgr; and pressure drop from the inlet to the throat of the Venturi:
Q
=
C
2
Δ
p
/
ρ
(
1
A
throat
2
-
1
A
inlet
2
)
[
5
]
where C is the discharge coefficient which is approximately unity but depends on the geometry of the Venturi, &Dgr;p is the pressure drop from Venturi inlet to throat, and A
throat
and A
inlet
are the throat and inlet cross sectional areas, respectively. The same equation can be used to determine the combined oil and water flow rate where the density in this case is the average mixture density in the throat of the Venturi. In practice, the square root in the equation makes it relatively insensitive to errors in both the density and pressure determinations.
A common method to determine the holdup in a flow of oil and water is to measure the average density of the fluid. Since oil at downhole pressure and temperature typically has a density which is smaller than that of water (around 0.7 g/cm
3
compared to 1.0 g/cm
3
), the oil and water holdups &agr;
o
and &agr;
w
can be determined proportionately from the mixture density by the relations
α
o
=
ρ
w
-
ρ
m
i
x
ρ
w
-
ρ
o
[
6
]
α
w
=
ρ
m
i
x
-
ρ
o
ρ
w
-
ρ
o
[
7
]
A common method to determine the mixture density is to measure the hydrostatic pressure of a column of fluid with a gradiomanometer. This device relies on having a component of the gravitational force vector along the axis of the flow pipe. This type of device, however, fails when the flow pipe is horizontal because the gravitational force vector is perpendicular to the pipe axis.
It is also known, e.g. from U.S. Pat. No. 5,017,879 or FR 2 780 499, that capacitive devices can be used to determine the characteristics of multi-phase flows. The dielectric constant of a mixture of fluids depends on the respective fraction of each of its components and on their individual dielectric constants. It has thus been proposed to estimate the composition of a two-phase fluid on the basis of its dielectric constant.
The dielectric constant is itself obtained by exciting the fluid by means of electrodes separated by the fluid, in particular electrodes placed on the pipe, and across which an AC voltage is applied. The measured magnitude is the resulting current. Guard electrodes have also been added to maintain the electrostatic field between the active electrodes. It is thus easier to interpret the measurements by limiting the edge effects due to the finite length of the active electrodes, or by focusing the electric field in a particular zone of the flow.
In both of the above-mentioned cases, namely when the flow is not homogeneous, or when the velocity is measured, it is thus necessary to dispose a plurality of devices, in particular capacitive devices, close together on the pipe. Contradictory requirements then have to be faced.
It is desirable to use devices that are of small size. In a non-homogeneous flow, better
Ferguson John W. J.
Fitzgerald John Barry
Goodwin Anthony Robert Holmes
Meeten Gerald H.
Pelham Sarah
Jeffery Brigitte L.
Mack Corey
Ryberg John
Schlumberger Technology Corporation
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