Measuring and testing – Borehole or drilling – Fluid flow measuring or fluid analysis
Reexamination Certificate
1999-06-04
2001-07-24
Williams, Hezron (Department: 2856)
Measuring and testing
Borehole or drilling
Fluid flow measuring or fluid analysis
C324S324000
Reexamination Certificate
active
06263729
ABSTRACT:
TECHNICAL FIELD
The present invention relates to a method designed to determine the flow rate of at least one hydrocarbon phase contained in a multi-phase fluid flowing in an oil well.
More precisely, the method of the invention is designed to make use of the results of measurements taken by a data acquisition apparatus that is displaced in an oil production well, in order to monitor the parameters thereof.
STATE OF THE ART
In an oil well in production, and, in particular, in a well that is quite old, the fluid that flows out from the well is generally a fluid that is in two phases or three phases. When it is a three-phase fluid, the fluid contains liquid petroleum, gas, and water.
For the operators of an oil well, it is essential to monitor the variation(s) in the flow rate(s) of the hydrocarbon phase(s) contained in the fluid, i.e. the flow rate of the liquid petroleum and/or the flow rate of the gas.
Data acquisition apparatus provided with sensors is currently available for performing such monitoring. When a measurement is to be taken, the apparatus is lowered into the well and displaced at constant velocity therein, while the well is otherwise under normal production conditions.
In some types of apparatus, the results of the measurements are transmitted to the surface in real time, e.g. by means of a telemetry system using the cable from which the apparatus is suspended.
In other types of apparatus, the results are recorded down-hole, inside the apparatus, for subsequent use.
As disclosed, in particular, in U.S. Pat. No. 5,661,237 and in European Patent Application 0 866 213, such apparatus is equipped with a plurality of local sensors which produce signals at different levels depending on which phase of the fluid is in contact with the sensor. Such sensors may, in particular, be of the electrical, optical, or radio-frequency type, or of some other type. Some such local sensors (e.g. electrical sensors) distinguish merely between hydrocarbon (oil and gas) and water. Other sensors (e.g. optical sensors) distinguish between all three phases.
Generally, such data acquisition apparatus is also equipped with a spinner flowmeter placed on the axis of the well, and with means for measuring the flow section of the well.
Measurements taken down-hole are supplemented by measurements taken at the surface, such surface measurements including, in particular, measurement of the speed of advance of the cable from which the apparatus is suspended. They may also include measurement of the flow rate of the fluid flowing out from the well.
As indicated in particular by M. Didek et al in “
New Production Logging Tool Enables Problem Well Diagnosis: A Case Study
”, SPWLA 37th Annual Logging Symposium, Jun. 16-19, 1996, the logging signals delivered by the local sensors (electrical sensors in that case) are used to acquire two parameters. One of the two parameters is the number of hydrocarbon bubbles per second or “bubble count”. The other parameter is the fraction of water in the fluid or “water holdup”.
In the state of the art, and as also specified by M. Didek et al, the hydrocarbon flow rate is determined on the basis of the hydrocarbon bubble count per second as measured by the local sensors, with the apparatus being displaced at different velocities in the well. That technique is based on the observation that the higher the relative velocity between the hydrocarbon bubbles and the apparatus, the higher the bubble count per second, and vice versa. The bubble count per second as seen by the local sensors thus becomes zero when the apparatus is travelling at the same velocity as the hydrocarbon bubbles.
On the basis of that observation, the same data acquisition apparatus is caused to pass along the well a plurality of times at different velocities, and each time, the hydrocarbon bubble count per second is measured. For each pass of the apparatus, the point representative of the hydrocarbon bubble count per second as a function of the displacement velocity of the apparatus is plotted on an orthonormal frame of reference. The line joining the various points obtained in this way is a straight line that is extended to the value corresponding to a hydrocarbon bubble count per second that is equal to zero. The displacement velocity of the apparatus corresponding to that point is considered to be equal to the displacement velocity of the hydrocarbon bubbles. By taking account of the flow section of the well, as also measured by the apparatus, it is possible to deduce therefrom the hydrocarbon flow rate in the well.
That technique suffers from a certain number of drawbacks.
Determining the hydrocarbon flow rate accurately enough generally requires the same data acquisition apparatus to perform more than five successive logging passes. That technique is therefore time-consuming to implement because it can take several hours to perform all of the passes. The apparatus is usually inserted while the valve situated at the bottom of the well is closed at least in part so as to reduce the flow rate of the fluid. Only once the apparatus has reached the level at which the measurements are to be taken is the well fully opened again. It is then necessary to wait for the nominal fluid flow conditions to be re-established before measurement can start.
The lengthiness of the acquisition operations required by that technique makes it very costly because production from the oil well must be interrupted for the same length of time.
In addition, the duration of the data acquisition operations can be a source of errors when the hydrocarbon flow rate varies quite rapidly.
Furthermore, that technique does not make it possible to calculate the flow rates in real time, i.e. during data acquisition.
SUMMARY OF THE INVENTION
An object of the invention is to provide a method designed to determine the hydrocarbon flow rate by means of existing data acquisition apparatus, by using information delivered during a single pass of the apparatus in the well, i.e. in a time that is quite short, and optionally in real time.
According to the invention, there is provided a method of determining the hydrocarbon flow rate Qhe in a multi-phase fluid flowing in an oil well, in which method the hydrocarbon bubble count Bc per unit time, the water holdup Hw in the fluid, and the flow section A of the well are measured by displacing a data acquisition apparatus in the well at a velocity Cs which is positive when going downwards, said method comprising the step of deducing the hydrocarbon flow rate Qhe directly from the results of the measurements by using the following relationship:
Qhe
=
2
3
(
Bc
·
d
-
Cs
(
1
-
Hw
)
)
A
where
d
represents the diameter of the hydrocarbon bubbles and is calculated by applying a mathematical model representative of the variation in said diameter as a function of the water holdup Hw.
In this method, the use of a mathematical model for calculating the diameter of the bubbles makes it possible to determine the hydrocarbon flow rate directly on the basis of the measurements taken during a single pass of the data acquisition apparatus in the well. Preferably, the flow rate is then determined in real time, during the logging operation while the data is being acquired.
In a preferred embodiment of the invention, use is made of a mathematical model which is such that the bubble diameter
d
tends towards the flow diameter D of the well when the water holdup Hw tends towards zero, and is such that the bubble diameter
d
tends towards a nominal diameter
dn
when the water holdup Hw tends towards 1.
Advantageously, use is then made of a mathematical model of the following type:
Hw
&agr;
d=D (dn/D)
where &agr; is a coefficient lying in the range 0.1 to 0.5.
In which case, &agr; is advantageously given a value equal to 0.3.
To implement the method of the invention, the nominal diameter
dn
is generally given a value equal to 1.5 mm.
Optionally, when means are available for measuring the overall velocity Vt of the fluid in the well, as is generally the case, it is possible to verify by
Jeffery Brigitte L.
Politzer Jay L.
Schlumberger Technology Corporation
Williams Hezron
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