Failure of equipment placed downhole in an oil/gas well results in unscheduled downtime, lost production, high repair costs, and potential damage to neighboring equipment. In a typical well, downhole equipment can include electrical submersible pumps (ESP), such as that disclosed in U.S. Pat. No. 6,167,965, as well as rotating machinery, plunger valves, and other types of equipment. Common failure modes of downhole equipment include excessive wear, failure of bearings, dynamic stress, excessive fouling, and impeller damage. Unfortunately, downhole equipment is typically inaccessible during operation, and if a failure occurs there is often no indication of what component has failed. Preventive maintenance can be achieved through monitoring the downhole equipment by sensing acoustic or vibration measurements emanating therefrom. Such monitoring can be used as part of a maintenance schedule to keep equipment operating longer at the least overall cost. Additionally, equipment overhaul can be scheduled in advance with minimum disruption in operation and production.
Electrical systems have been used to monitor the operation of downhole equipment, such as are disclosed in U.S. Pat. Nos. 5,499,533, 5,539,375, and 6,167,965. Typically such systems monitor equipment health by electrically sensing vibration of the equipment, or by monitoring the current that is sent to the equipment to see if these indicia are non-optimal. However, because these systems rely on electronic components, they are susceptible to failure in the harsh downhole environment, which is characterized by extreme pressures, temperatures, and caustic chemicals. The shortcomings of using electrical equipment to monitor downhole equipment are further disclosed in U.S. Pat. No. 5,892,860, which is incorporated herein by reference in its entirety.
By contrast, downhole sensors based on fiber optic technology are highly reliable, and accordingly, have been used in several different ways to monitor various conditions downhole, such as pressures, temperatures, flow rate, phase fractions of the fluid being produced, etc.
A good example of a fiber optic based sensor useable in a downhole environment is a fiber optic based hydrophone. As is well known, a fiber optic hydrophone is a relatively simple device and generally comprises a length of fiber optic cable wound around a compliant mandrel. The length of the cable is perturbed by the force of acoustic pressure on the mandrel. Positioning of fiber Bragg gratings (FBGs) on each end of the length of cable allows the length of the cable, and hence the properties of the acoustic disturbance, to be determined by interferometric means as is well known. Alternatively, the mandrel can comprise a sensing cable wound around a compliant mandrel, and a reference cable wound around a rigid mandrel, a configuration which again allows for a determination of the change in length of the sensing cable. Examples of fiber optic based mandrels are disclosed in U.S. Pat. Nos. 5,394,377, 5,625,724, 5,625,716, and D. J. Hill et al., “A Fiber Laser Hydrophone Array,” SPIE Vol. 3860 (1999), which are hereby incorporated by reference in their entireties. Other devices similar in nature to a hydrophone, such as the fiber optic acoustic emission sensor disclosed in U.S. Pat. No. 6,289,143, which is hereby incorporated by reference in its entirety, can likewise be used to sense high frequency vibrations, and is likewise incorporated by reference herein. These prior art approaches rely on several different types of interferometric approaches (e.g., Mach Zehnder, Michaelson, Fabry Perot, ring resonators, polarimetric and two-mode fiber interferometers), and can be interrogated, for example, by the diagnostic system disclosed in U.S. Pat. No. 5,401,956, or U.S. patent application Ser. No. 09/726,059, filed Nov. 29, 2002, which are also incorporated herein by reference in their entireties.
It has been noted that fiber optic sensors, like electronic sensors, can be used to monitor the health of downhole equipment. For example, in U.S. Pat. No. 6,268,911, hereby incorporated by reference in its entirety, it is noted that fiber optic based sensors can be used to monitor the condition or health of downhole equipment, but the type of sensor to be used is not described in detail (see FIG. 11 of the '911 patent and associated text). U.S. Pat. No. 5,892,860, also incorporated herein by reference in its entirety, similarly discloses a fiber optic based sensor for monitoring downhole equipment. In this patent, a sensor structure is disclosed which can be mounted in the casing of an ESP. The disclosed sensor employs a series of three linearly-arranged FBGs serially coupled using a wavelength-division multiplexing (WDM) approach, in which one FBGs acts as a pressure sensor, another as a temperature sensor, and (as most relevant to this disclosure) another as a dynamic sensor (accelerometer) for measuring the vibrations of the ESP. However, a review of this patent reveals a rather complicated sensor structure, as various schemes and components must be used in the sensor housing to allow each of the FBGs to detect the parameter of interest.
Although the disclosure in the '911 patent is rather vague, it is reasonable to conclude that these prior art fiber optic based approaches to monitoring downhole equipment operation present complicated approaches. Additionally, the approach of the '860 patent relies on the sensitivity of a single FBG to detect dynamic variations, which is not as sensitive as the above-discussed hydrophones, which typically employ interferometric approaches capable of detecting and distributing dynamically induced pressures over a substantial length of fiber optic cable. Moreover, the '860 patent only contemplates a direct connection of the sensors to the equipment being measured, which may be unsuitable for applications in which the equipment will not lend itself to such modification. What is needed is an apparatus for detecting the operation of downhole equipment that uses the relatively simple and precise structure of a basic hydrophone or other forms of fiber optic sensors having coils as the acoustic sensing element. This disclosure presents such configurations.
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