Optics: measuring and testing – By light interference – Using fiber or waveguide interferometer
Reexamination Certificate
2000-11-29
2004-08-31
Glick, Edward J. (Department: 2882)
Optics: measuring and testing
By light interference
Using fiber or waveguide interferometer
C356S035500, C356S477000, C385S012000, C385S013000
Reexamination Certificate
active
06785004
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 pressure variations within the pipe.
2. Background Information
In the petroleum industry, there is considerable value associated with the ability to monitor the flow of petroleum products in the production pipe of a well in real time. Historically, 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 that they provide an undesirable flow impediment, are 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 bulk fluid flow and are unable to provide information specific to constituents within a multi-phase 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, 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 flow 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 flow within a well is often non-homogeneous, for example, it may contain localized concentration variations (“slugs”) of water or oil. The localized concentration variations may affect the accuracy of the data collected.
One prior art technique of sensing a parameter within a body is disclosed in U.S. Pat. No. 4,950,883 to Glenn wherein a broadband source is used in cooperation with a Fabry-Perot resonator sensor. The high reflectivity gratings establish a resonant signal, the wavelength of which is indicative of the parameter of interest of a fluid within the body. Among other shortcomings, this prior art method has limited usefulness in a downhole environment for several reasons, such as limited resolution and relatively slow update rates.
Multiphase flow meters can be used to measure the flow rates of individual constituents within a fluid flow (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 flow reaching the flow meter is a mixture of the fluids from the various sources disposed at different positions within the well. So although the multiphase meter provides the advantage of providing information specific to individual constituents within a fluid flow (which is an improvement over bulk flow sensors), the information they provide is still limited because there is no way to distinguish from which well the fluid originates.
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 in 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 robust apparatus for interrogating fiber optic sensors coupled to a pipe, that can determine minute sensor response to a fluid flow within a pipe that enables a high update rate, and that is operable in an environment characterized by long optical cable lengths.
SUMMARY OF THE INVENTION
It is, therefore, an object of the present invention to provide a method and apparatus for interrogating fiber optic sensors for sensing at least one parameter of the fluid flow within a pipe that is reliable and accurate, that can determine minute sensor response to a fluid flow within a pipe, that enables a high update rate, and that operates in an environment characterized by long transmission lengths and high temperatures and pressures.
According to the present invention, an apparatus for interrogating fiber optic sensors that are coupled to a pipe for non-intrusively sensing fluid flow within the pipe is provided. The apparatus includes a narrow band optical source producing a series of discrete pulses of narrow band light, a coupler to split the pulses into first and second pulses, a modulation device to impress a modulation carrier onto the first pulses, a time delay coil delaying the second pulses by a known amount of time, a coupler to recombine the pulses onto a single optical fiber, a first reflective grating positioned on one side of the sensor and a second reflective grating positioned on the opposite side of the sensor, an optical circulator to direct the pulses to a photo receiver to receive reflected pulses from the gratings, and an interrogator to compare the pulses. The present invention further includes the capability to interrogate a plurality of sensors along a single optical fiber string with each sensor positioned between a pair of reflective gratings.
The interrogator compares the phase shift between the reflected first pulses from the second grating with the reflected second pulses from the first grating to determine a change in magnitude of the measured parameter.
The narrow band light source emits pulses at a time interval between successive pulses that is short enough in duration to extract meaningful information from the sensors. At the same time, the interval between successive pulses is long enough to allow the reflected pulses to be properly distinguished. The time delay coil is advantageously sized to match the nominal length of the sensor. The reflected pulses will establish an interference pattern at the optical receiver, the intensity of which is based on the phase shift produced by the change in length of the sensor, which in turn is indicative of the magnitude of the sensed parameter.
An advantage of the present invention apparatus is that it enables long transmission lengths of optical fiber between the source and the sensors based on low loss elements and low reflectivity gratings. As a result, sensors may be placed at remote locations from instrumentation without the need for optical amplifiers.
Another advantage of the present invention is the ability to multiplex a plurality of sensors, each having a pair of gratings that reflect a single nominal wavelength. As a result, a plurality of sensors may be positioned along a single optical fiber. This enables a system that is insensitive to cross-talk, reduces optical fiber and equipment requirements, and permits installation in size-limited applications.
The foregoing and other objects, features, and advantages of the present invention will become more apparent in light of the following detailed description of exemplary embodiments thereof.
REFERENCES:
patent: 3149492 (1964-09-01), Weinberg
paten
Bailey Timothy J.
Davis Allen R.
Fernald Mark R.
Kersey Alan D.
Winston Charles R.
Glick Edward J.
Moser Patterson & Sheridan
Suchecki Krystyna
Weatherford / Lamb, Inc.
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