Optical waveguides – Optical waveguide sensor
Reexamination Certificate
2000-11-29
2004-08-24
Kim, Robert H. (Department: 2871)
Optical waveguides
Optical waveguide sensor
C385S013000, C073S170010, C073S170060, C073S170110, C073S170130, C073S170140, C073S152510, C073S861180, C073S861230
Reexamination Certificate
active
06782150
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Technical Field
This invention relates to fluid flow sensing devices that use fiber optics, and, more particularly, to those devices that measure the speed of sound, flow velocity, and other parameters of a fluid within a pipe using acoustic signals and local short duration pressure variations within the fluid.
2. Background Information
In the petroleum industry, there is considerable value in the ability to monitor the flow of petroleum products in the production pipe of a well in real time. Historically, fluid flow parameters such as the bulk velocity of a fluid have been sensed with venturi type devices directly disposed within the fluid flow. These devices have several drawbacks including the fact that they provide an undesirable flow impediment, arc subject to the hostile environment within the pipe, and typically provide undesirable potential leak paths into or out of the pipe. In addition, these devices are only able to provide information relating to the bulk fluid flow and are therefore unable to provide information specific to constituents within a multi-phase fluid flow.
Some techniques utilize the speed of sound to determine various parameters of the fluid flow within a pipe. One technique measures the amount of time it takes for sound signals to travel back and forth between ultrasonic acoustic transmitters/receivers (transceivers). This is sometimes referred to as a “sing-around” or “transit time” method. U.S. Pat. Nos. 4,080,837, 4,114,439, and 5,115,670 disclose variations of this method. A disadvantage of this type of technique is that gas bubbles and/or particulates in the fluid can interfere with the signals traveling back and forth between the transceivers. Another disadvantage of this type of technique is that it considers only the fluid disposed between transceivers during the signal transit time. Fluid within a well is typically not homogenous. In other words, the fluid often contains localized concentration variations of water or oil, often referred to as “slugs”. Localized concentration variations can affect the accuracy of the data collected.
Multiphase flow meters can be used to measure the flow rates of individual constituents within a fluid (e.g., a mixture of oil, gas, and water) without requiring separation of the constituents. Most of the multiphase flow meters that are currently available, however, are designed for use at the wellhead or platform. A problem with utilizing a flow meter at the wellhead of a multiple source well is that the fluid reaching the flow meter is a mixture of the fluids from the various sources, which are disposed at different positions within the well. So although the multiphase flow meter provides the advantage of providing information specific to individual constituents within a fluid (which is an improvement over bulk flow sensors), the information they provide is still limited because there is no way to distinguish from the various sources.
Acquiring reliable, accurate fluid flow data downhole at a particular source environment is a technical challenge for at least the following reasons. First, fluid flow within a production pipe is hostile to sensors in direct contact with the fluid flow. Fluids within the production pipe can erode, corrode, wear, and otherwise compromise sensors disposed in direct contact with the fluid flow. In addition, the hole or port through which the sensor makes direct contact, or through which a cable is run, is a potential leak site. There is great advantage in preventing fluid leakage out of the production pipe. Second, the environment within most wells is harsh, characterized by extreme temperatures, pressures, and debris. Extreme temperatures can disable and limit the life of electronic components. Sensors disposed outside of the production pipe may also be subject to environmental materials such as water (fresh or salt), steam, mud, sand, etc. Third, the well environment makes it difficult and expensive to access most sensors once they have been installed and positioned downhole.
What is needed, therefore, is a reliable, accurate, and compact apparatus for sensing fluid flow within a pipe in a non-intrusive manner that is operable in an environment characterized by extreme temperatures, pressures and the presence of debris. Further needed is a fluid sensing apparatus that can operate remotely and not likely to need replacement or recalibration once installed.
SUMMARY OF THE INVENTION
According to the present invention, an apparatus for non-intrusively sensing fluid flow within a pipe is provided. The apparatus includes a first sensing array for sensing acoustic signals traveling at the speed of sound through the fluid within the pipe, a second sensing array for sensing local pressure variations traveling with the fluid flow, and a housing attached to the pipe for enclosing the sensing arrays. The first acoustic sensing array includes a plurality of first fiber optic pressure sensors. The second flow velocity sensing array also includes a plurality of second fiber optic pressure sensors.
Optical power sent from a source connected to the apparatus travels into the first sensing array, which in turn produces a first signal relating to the acoustic signals. Likewise, optical power sent from the source travels into the second sensing array, which in turn produces a second signal relating to the local pressure variations within the fluid flow. The first and second signals are then processed and interpreted using known methods.
The function of each sensing array and the information gathered to perform that function is distinct from that of the other array. This can be clearly seen if one considers that the axial velocity of the fluid flow is small and therefore negligible compared to the speed of sound in the mixture (i.e., the speed of a compression wave traveling through the fluid within the pipe). The local pressure variations that are sensed by the second sensing array travel with the fluid flow, and are therefore at approximately the same axial velocity as the fluid flow. The local pressure variations have a small coherence length (sometimes referred to as “lengthscale”) that typically lasts on the order of one to ten (1-10) pipe diameters. The acoustic signals that are sensed by the first sensing array, in contrast, are pressure variations that travel at the speed of sound through the fluid flow. The acoustic signals have a coherence length on the order of one hundred to ten thousand (100-10,000) pipe diameter lengths, which is orders of magnitude greater than that of the local pressure variations.
An advantage of the present invention apparatus is it enables the collection of flow data downhole within a well at or near the source of the fluid flow. As a result, accurate flow data can be collected from one or more sources individually, rather than data compiled from a mixture of those sources. Fluid flow data from the different sources enables the determination of the velocity and phase fraction of fluids flowing from each source.
Another advantage of the present invention is that it provides fluid flow data in a nonintrusive manner. The sensing arrays of the present invention attach to the outer surface of the pipe and therefore do not require an opening extending into the fluid flow path. As a result, a potential leak path into or out of the fluid flow path is eliminated and the sensing arrays are protected from the fluid flow within the pipe.
The present apparatus is also protected from the environment outside of the production pipe by a compactly formed housing that can easily be placed within the well casing. The housing protects the sensing arrays from the fluid and debris that enters the annulus between the production pipe and the well casing. As a result, the present invention can use a wider variety of sensing devices than would otherwise be possible. In addition, in the embodiment where the sensing arrays are disposed within a pressure vessel, the sensing arrays are disposed within a gas environment at a substantially constant pressure. The gas
Davis Allen R.
Faustino John M.
Gysling Daniel L.
McGuinn Rebecca S.
Winston Charles R.
Kim Robert H.
Moser, Patterson & Sheridan L.L.P.
Wang George Y.
Weatherford / Lamb, Inc.
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