Measuring and testing – Borehole or drilling – Fluid flow measuring or fluid analysis
Reexamination Certificate
1999-07-08
2001-04-17
Kwok, Helen (Department: 2856)
Measuring and testing
Borehole or drilling
Fluid flow measuring or fluid analysis
C073S861080
Reexamination Certificate
active
06216532
ABSTRACT:
FIELD OF THE INVENTION
This invention relates to gas flow rate measurement, and concerns in particular the measurement of the flow of gas in a multiphase gas and liquid environment in a nearly-horizontal ascending borehole.
BACKGROUND OF THE INVENTION
Once a well—especially an oil- or gas-well—has been drilled and is producing the sought-after fluid(s), it is desirable to monitor the rate at which each fluid (such as oil or gas, or, in a multiphase well, mixtures of these with each other and/or with water) is being delivered. It is particularly useful to know when there is a change in a fluid's output rate, for that can indicate problems with the well—for instance, that the well is coming to the end of its useful life, or that material is leaking in (or out) of the well before it gets to the surface. This monitoring is known as “production logging”—definable as the measurement of fluid flow rates as a function of depth in an oil or gas well—and has been in use for many years.
The primary motivation of production logging is to monitor production flow rates of the various fluids (oil, water and gas), and to locate depths in the well of entry of unwanted fluids. Once the entry depths are located, various steps are available to shut off the unwanted entry.
Prior to the introduction of horizontal well drilling, most wells were either vertical or only slightly deviated (from 0 to at most 60 degrees from the vertical), and so there was little need to measure flow rates in nearly-horizontal wells. However, many present-day wells have long horizontal or nearly-horizontal portions (at 80 or 90 degrees to the vertical), and, because the conditions in horizontal wells are very different from those in vertical or only-slightly-deviated wells, the techniques used to measure flow in these latter types of well are simply not applicable to horizontal wells. One example of such an inapplicable technique involves the use of a gradiomanometer; this is a device which determines the density of a fluid by measuring the pressure gradient caused by gravity in a column of fluid—but since in horizontal wells gravity acts at right angles to the line of the wellbore, this technique simply does not work in them. Another inapplicable technique involves the use of a so-called “spinner”—a small propeller/turbine driven by the passing fluid. The spinner conventionally used in production logging to measure flow rate does not give an interpretable response in horizontal wells, where it responds primarily to the liquid, and hardly at all to the gas.
The invention solves this problem by utilising—by taking advantage of—some of those very features which are peculiar to horizontal wells, such as “slug flow”.
Of course, it is not unknown in many fields—and even in the oil industry—to take measurements of multiphase flow in nearly-horizontal pipelines. However, to date most of these pipelines have been surface pipelines, such as might convey the fluid from a well head to a storage system, or from one part of a refinery to another, and these are very different from the nearly-horizontal underground boreholes involved in actually producing the fluids in the first place. Down a well the pressures are enormous—several hundreds of atmospheres—and any gas bubbles are necessarily compressed into a relatively small size. On the surface, however, there is relatively-speaking no compressive pressure, so that those gas bubbles expand to a relatively large size—and because of these large amounts of free gas the flow is often “slug flow”, with liquid-rich regions of flow alternating with gas-rich regions. This time-varying nature of the flow has been suggested for use to measure the velocity of the various flow components; for example, one proposal involves beaming gamma rays into and through the pipes from external sources, and using correlated external detectors to measure slug velocity and, by the gamma ray attenuation, the volume fraction of the flow.
As in surface pipelines, so in nearly-horizontal but ascending wells free gas flows along and up the well typically as bubbles along the upper side of the borehole (in descending wells, the gas forms a stratified layer rather than bubbles). Unfortunately, for several reasons it is difficult to use the “surface” type of measurement system actually in a borehole; taking measurements downhole is different from taking them at or near the surface in a number of significant ways. In the first place—and as mentioned above—because of the higher pressures in a borehole much of the gas downhole is dissolved in the liquid, and the size of the gas bubbles is much smaller, typically not nearly filling the pipe. Such small amounts of gas are difficult to detect with gamma attenuation devices. Also, systems which require that sources and/or detectors be placed outside the flow obviously cannot be used for borehole flow measurements, which must have all sources and/or detectors within the borehole (or within any liner, if there is one [this is discussed further below]). Additionally, there may be problems downhole that stem from the borehole having a liner—typically a “slotted” liner and the normal surface measurement techniques are unable to cope with the downhole problem of fluid flow in the annulus between the liner and the borehole surface proper. Added to this, of course, are the difficulties and dangers associated with the radioactive sources needed for the gamma ray generation; these cannot be turned off, and any apparatus which uses them can be a safety hazard.
Wells can be configured or “completed” in a number of ways. Sometimes a fairly tight-fitting steel liner—a large aperture tube—is placed within the borehole to line its sides, and cement is squeezed between the liner and the borehole wall to complete that lining. Holes are then made in the liner and cement with explosive charges (to let the production fluid out of the underground geological formation through which the borehole is passing at that point), and this combination is called a “cemented completion”. On the other hand, sometimes there is employed a “slotted liner”—a steel liner with holes or slots pre-installed. In this case, no cement is used, so the liner tube is fairly loose within the borehole, and no additional holes are necessary. Such a slotted well gives rise to particular difficulties because of the freedom of the well fluid to flow both within the liner and also in the gap—the annulus—between the liner and the borehole walls. Finally, sometimes—usually in an effort to save money—no liner at all is installed in the borehole; this is called a “barefoot completion”.
Any flow rate measurement technique to be used downhole should if possible take account not only of the several sorts of “lined” wells but also the “barefoot” ones. Accordingly, a production logging tool will preferably make accurate flow measurements in any of these types of completions. This is particularly difficult in the case of a slotted liner, where as noted there will be fluid flowing both in the liner and in the annulus therearound.
SUMMARY OF THE INVENTION
The invention seeks to satisfy this need for a technique that can be employed with all these sorts of completed well by using a modified version of the techniques employed in above-ground flow rate measurement, and utilising a pair of correlated spaced sensors that can detect “directly” the difference between gas and liquid (oil and/or water), which sensor pair is carried on a logging tool positioned within the borehole itself such that the individual sensors are disposed so as to be actually in the path of any gas bubbles likely to be in the fluid. The correlated output of the sensor pair allows a determination of the gas flow velocity, and if at the same time measurements are taken that provides an indication of the hold-up of the gas bubbles—in other words, the size of the bubbles as an area proportion of the borehole cross-sectional area—there may by calculation be determined the flow rate both of the gas and of the fluid.
In one aspect, therefore, this invention provides
Stephenson Kenneth E.
Theron Bernard
Batzer William B.
Kwok Helen
Schlumberger Technology Corporation
Wang William L.
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