Acoustic transducer system for monitoring well production

Details Acoustic transducer system for monitoring well production Acoustic transducer system for monitoring well production

1999-06-17

2002-03-12

Williams, Hezron (Department: 2856)

Measuring and testing

Liquid analysis or analysis of the suspension of solids in a...

Content or effect of a constituent of a liquid mixture

C166S308400

Reexamination Certificate

active

06354146

ABSTRACT:

CROSS-REFERENCE TO RELATED APPLICATIONS
Not applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
Not applicable.
TECHNICAL FIELD OF THE INVENTION
The invention relates generally to apparatus and methods for acoustically determining various properties of a fluid flowing through a conduit. More particularly, the present invention relates to an acoustic transducer system for monitoring production fluids in completed wells. Still more particularly, the present invention comprises a tool having one or more opposed transducer pairs that are acoustically isolated from the tool body and transmit acoustic signals across the fluid stream. Applications of the present invention also include an angled transducer backing that allows transducers to be used in any annular device, including tubing and rotating logging heads. Transducers configured in accordance with the present invention can be used in either pitch-catch or pulse-echo mode.
BACKGROUND OF THE INVENTION
Description of the Related Art
Production of hydrocarbons from geologic formations in the earth is typically accomplished by drilling a well to the desired formation. Once the desired drilling objectives have been met and prior to the start of production, the well undergoes a completion process. The completion process entails cementing the annulus between the casing and the borehole wall and isolating the production zone(s) from the rest of the strata. The casing is perforated at the production zone(s) so as to allow the formation fluids to drain into the casing. To isolate the production zones from other fluids in the casing, production tubing is installed inside the casing. The formation fluids, comprising mainly gaseous or liquid hydrocarbons, flow upward through the production tubing to the surface, where they are captured for processing.
Once a well has been completed in this manner, it may produce steadily and require no further attention for many years. Nevertheless, for a variety of reasons, it may be desirable to monitor the flow of fluids through the production tubing, using sensors installed in sensor modules that are deployed as part of the production tubing string. For example, the controlling equipment that receives the fluids from the formation may need to be modified or optimized, depending on the nature of the fluids it receives. Similarly, it may be desirable to monitor each producing zone in order to detect the encroachment of water, gas, or other undesired fluid into the well. It is often necessary to maintain data on the rate at which each of the flowstream constituents is produced for one or more wells in a reservoir in order to monitor the effectiveness of a reservoir production scheme, detect faults in the production equipment for an individual well, and/or in determine royalty payments for produced hydrocarbons. Hence, the pressure, temperature, flow rate, density, chemical composition and water content are all properties of the fluid stream whose measurement would be advantageous.
Because many wells are remote and/or offshore, it is often desirable to install equipment that allows unmanned or automatic mode monitoring of the producing well. For example, it is desirable to provide a production monitoring system that can measure the desired parameters and transmit the resulting data to a remote data-receiving site.
Similarly, because the monitoring system is downhole, maintenance or replacement of the monitoring system requires a trip into the hole and a corresponding interruption in production, Hence, it is desirable to maximize the period for which a production system can operate without maintenance or replacement. An ideal production monitoring system would be able to operate for at least twenty and up to thirty or more years without interruption, so as to reduce the amount of downtime and maximize efficiency. The corrosive environment that exists downhole reduces the types of equipment that are suitable for this application.
In addition, it is further desirable to minimize the amount of flow disruption caused by the monitoring sensors or tool. This typically means that the configuration of the sensors must correspond to the inside diameter of the production tubing. Hence, it is further desired to provide an effective production monitoring tool that can fit within the dimensions of the production tubing itself.
Finally, it is important that the monitoring system be capable of assessing a wide range of fluids. Production from most oil wells takes the form of a multicomponent fluid stream. For a typical oil well this stream may include crude oil, brine, hydrocarbon gases, various inorganic gases, and minor amounts of particulate matter. The proportion of each constituent of the production flowstream varies from well to well, and in a single well can vary significantly over time.
Various systems currently exist that purport to meet these requirements. Early methods for determining the fractional representation of the various fluids, i.e. liquids, gases, and combinations thereof, within the flowstream of an oil well relied on manual sampling and analytical procedures. A representative sample of the flowstream was collected and through physical separation and chemical analysis the fractional representation of each constituent was determined. Manual analysis is still used today in many instances, particularly where accuracy is particularly important. However, manual testing is relatively expensive, especially in remote oil fields or where frequent updating is necessary. Further, collecting small volume samples that accurately represent the flowstream is difficult, especially in high pressure, high temperature production systems.
Automated flowstream analysis systems have been developed to avoid much of the expense associated with manual testing. Early automated systems relied on gravity driven physical separation of the constituents of the flowstream. Such systems are not accurate for applications where the flowstream includes an oil-water emulsion, which cannot be gravity separated. Such systems are also of limited use for heavy oil reservoirs, where the density difference between the produced oil and brine is too small to provide significant driving force for gravity separation. Gravity driven automated analysis systems also tend to be bulky, expensive, and require careful maintenance.
Many additional, alternative techniques have been proposed to measure flow characteristics of fluids contained in tubular conduits. For example, some known techniques are based on sensing and correlating local pressure fluctuations or sensing the pressure field set up by a venturi or vortex element. Other techniques use measurements of the effect of the fluid stream on various types of radiation, such as gamma rays, to determine fluid properties. These techniques have obvious disadvantages, including safety and the continuous decay of the radiation source.
Acoustic monitoring systems use ultrasonic transducers that, through known acoustic signaling and signal processing techniques, are able to derive information about the fluid stream. Specifically, the speed of sound for a fluid can be calculated using the known distance between a transmitting transducer and a receiving transducer and the measured time required for a signal to traverse that distance. The transducers are typically annular rings that are spaced apart along the axis of the tool. Acoustic signals are transmitted axially, parallel to the direction of the fluid flow. An example of such a device is described in U.S. Pat. No. 4,003,252 to Dewath. The apparatus disclosed in the Dewath patent uses transducers recessed in the acoustically damping liner of a tube.
None of the prior art devices have been entirely satisfactory, however. Many of the conventional multiphase flow metering systems do not provide an accurate indication of the flow velocity of when the fluid flow is multiphase. Other conventional systems are prohibitively difficult to install or incorporate intrusive metering arrangements requiring interruption or alteration of the flow.

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