Classifications

• • G—PHYSICS
  • G01—MEASURING; TESTING
  • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
  • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
  • G01F1/66—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by measuring frequency, phase shift or propagation time of electromagnetic or other waves, e.g. using ultrasonic flowmeters
  • G01F1/666—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by measuring frequency, phase shift or propagation time of electromagnetic or other waves, e.g. using ultrasonic flowmeters by detecting noise and sounds generated by the flowing fluid

Definitions

• the present invention is a method and system for monitoring fluid flow, such as fluid flow through pipelines or similar conduits for delivering natural gas, crude oil, and other similar liquid or gas energy commodities.
• the method and system relies on the measurement of acoustic waves generated by the fluid from a location external to the conduit in which the fluid is flowing, thus allowing for monitoring of the flow rate without direct access to the fluid.
• the method and system of the present invention allows for estimation of the operational dynamics of components or facilities of the production, transportation, storage, and distribution systems for the energy commodities.
• a general property of fluids (whether compressible or incompressible) flowing through pipes or similar conduits is mat they produce acoustic waves, i.e., sound or vibration.
• the sound produced by the flow of natural gas or other energy commodity can be characterized by its amplitude and frequency.
• the amplitude and frequency are generally directly related to the velocity of the fluid through the conduit, and thus the flow rate of the fluid. Therefore, a sound transducer or similar sensor can be positioned to detect the acoustic waves emanating from a particular conduit caused by fluid flow through that conduit, and by recording and analyzing the acoustic waves, the flow rate through the conduit can be estimated.
• the flow rate is commonly expressed as a volumetric flow rate, i.e., characterized as the volume of fluid passing by a designated point over a predetermined time period.
• a computational analysis is performed by a digital computer program to determine the flow rate of the fluid through the monitored pipeline.
• the output or production of the facility can be determined.
• information associated with the production or output of one or more facilities or components can then be communicated to third parties.
• This information may include not only the measured flow rates or output estimates, but also historical data, cap'acity estimates, or similar data that places the measured flow rates or output estimates in context for market participants and other interested parties. It is contemplated and preferred that such communication to third parties be through export of the data to an access-controlled Internet web site, which end users can access through a common Internet browser program.
• Figure 7 is a graph illustrating the measured signal amplitudes from a sound transducer positioned adjacent a particular conduit for a defined time period, such that a best fit equation can be developed for subsequent measurements of flow rate through this particular conduit; and
• Figure 8 is a graph illustrating the measured signal amplitudes from a sound transducer positioned adjacent another particular conduit for a defined time period, such that a best fit equation can be developed for subsequent measurements of flow rate through this particular conduit.
• the production, output, and/or other measure of the flow of an energy commodity through or relative to a component or facility may be referred to as the "operational dynamics" of that component or facility.
• operational dynamics the production, transportation, storage and distribution of liquid or gas energy commodities occurs most often through networks of pipelines.
• pipelines connect various system components, such as production wells, storage facilities of various types, and distribution networks comprised of ever-smaller pipelines.
• natural gas is located and collected by production companies from geographically dispersed wells, which are generally indicated by reference numerals 10A, 10B, and IOC in Figure 1.
• the natural gas collected from these wells is delivered through a network of pipelines (or similar conduits) 12A, 12B, 12C to a primary trunk line 14. From such a trunk line 14, the natural gas is delivered to storage facilities 16, which are typically depleted natural gas fields, salt domes, or similar underground structures; and/or to local distribution companies 18, which in turn, sell and deliver the natural gas to industrial, commercial, and residential end users for ultimate consumption.
• storage facilities 16 are typically depleted natural gas fields, salt domes, or similar underground structures; and/or to local distribution companies 18, which in turn, sell and deliver the natural gas to industrial, commercial, and residential end users for ultimate consumption.
• a general property of fluids flowing through pipes or similar conduits is that they produce acoustic waves, i.e., sound or vibration.
• the sound produced by the flow of natural gas or other energy commodity can be characterized by its amplitude and frequency.
• the sound transducers 34a, 34b...34n are positioned in contact with the pipeline 32 or sufficiently close to said pipeline 32 such that acoustic waves can be reliably detected.
• many commercially available transducers supply mounting magnets for direct attachment of the transducers to a pipeline or similar conduit.
• each sound transducer 34a, 34b...34n may be mounted to the pipeline 32 by attaching a substantially flat magnet to the transducer using an adhesive material, with the magnet then being used to secure the sound transducer 34a, 34b...34n to the pipeline 32.
• each sound transducer 34a, 34b...34n could be provided with a curved magnet that better matches the contour of the pipeline to which it is secured.
• each sound transducer 34a, 34b...34n may be mounted on a bracket or similar frame that maintains the position of the sound transducers 34a, 34b...34n relative to the pipeline 32 without necessarily contacting the pipeline 32.
• each sound transducer 34 detects the amplitude of the acoustic waves generated by the gas flow through the pipeline 32 and generates a signal representative of that amplitude.
• the monitoring device 30 is programmed such that it periodically or continuously collects data from the sound transducers 34a, 34b...34n, processes that data into a form suitable for transmission, and transmits the data to a remote central processing facility where various computational analyses are performed on the data to determine the flow rate of natural gas or other energy commodity through the monitored pipeline.
• the output voltage of the first sound transducer 34a is applied to a amplification and filtration circuit 40a, which has a dual function.
• One function of the amplification and filtration circuit 40a is to amplify the relatively small output voltage of the sound transducer 34a to a level that will be suitable as an input to an analog-to-digital converter.
• the secondary function of the circuit 40a is to serve as a filter, removing extraneous noise from the output voltage of each sound transducer 34a.
• the output voltage of the second sound transducer 34b is applied to another amplification and filtration circuit 40b to amplify the ⁇ > voltage and remove extraneous noise, and so on.
• the specific design of the amplification and filtration circuits 40a, 40b...40n is immaterial, and various amplification and filtration circuits could be designed to achieve the dual objectives of amplifying the voltage and removing extraneous noise by one of ordinary skill in the art.
• the output voltages are then applied to the inputs of an analog multiplexer (MUX) 42.
• MUX analog multiplexer
• sample-and-hold amplifiers are generally known in the art, and any conventional means for performing the sample-and-hold function maybe incorporated into the present invention as contemplated herein. From the MUX 42, the signals are separately passed through an analog-to-digital (A/D) I converter 44.
• A/D analog-to-digital
• a control logic associated with a microprocessor 50 determines which of the multiple signals is passed through to the analog-to-;digital converter 44 at any given time.
• the outputted signal from the microprocessor 50 is then transmitted to one or both of a radio frequency (RF) transceiver 58 with associated transmission antenna 60 (which is also shown in Figure 3) and a landline network 62 for subsequent transmission of the signal to a central processing facility.
• RF radio frequency
• the individual electronic components of the monitoring device 30 are preferably powered by a battery 70 that may be continuously recharged by a solar panel array 72 (which is also shown in Figure 3).
• Figure 5 is a functional block diagram of the communication components and the central processing facility in this exemplary implementation of the method and system of the present invention. These components are not installed in the field with the monitoring device 30, but rather are located at some remote location. Specifically, the outputted data from the microprocessor 50 depicted in Figure 3 is transmitted to the central processing facility via one or both of a radio frequency (RF) transceiver 58 with associated transmission antenna 60 and a . landline network 62.
• RF radio frequency
• a receiving antenna 100 or similar communication component which is in range of one or more monitoring devices 30 in the field, receives this data, which is representative of the acoustic measurements.
• the receiving antenna 100 is operably connected to an analog or digital communications network 102 which transmits the signal to the central processing facility 110.
• Such transmission may be carried out, for example, by a satellite link 104, a microwave link 106, and/or a fiber optic link 108, although other data transmission means may certainly be used without departing from the spirit and scope of the present invention.
• a computational analysis is performed by a digital computer program 112 to determine the flow rate of the gas (or similar fluid) through the pipeline 32.
• a simple summing of the flow rates on each pipeline the natural gas production of the facility can be determined.
• information associated with the production or output of one or more facilities or components can then be communicated to third parties.
• This information may include not only the measured flow rates or output estimates, but also historical data, capacity estimates, or similar data that places the measured flow rates or output estimates in context for market participants and other interested parties. It is contemplated and preferred that such communication to third parties be through export of the data to an access- controlled Internet web site 114, which end users can access through a common Internet browser program 116, such as Microsoft Internet Explorer®. Of course, communication of information and data to third parties may also be accomplished through a wide variety of other known communications media without departing from the spirit and scope of the present invention.
• the communications channel from the microprocessor 50 of the local monitoring device 30 to the central processing facility 110 may be bi-directional so that the information maintained and stored in the microprocessor 50 may be sent out on a scheduled basis or may be polled. Furthermore, through bi-directional communications, the microprocessor 50 is remotely re-programmable.
• the relationship of the measured acoustic waves through a conduit to the flow rate is somewhat mathematically complex because the acoustic waves may result not only from fluid flow, but also from the interaction of the fluid with mechanical components of the pipeline, including compressors, gas flow meters, flow and pressure regulators, control valves and/or similar equipment connected to and/or external to the pipeline.
• Figure 7 is a graph illustrating the measured signal amplitudes from a sound transducer positioned adjacent a particular conduit for more than a 105-hour time period. During this time period, the actual gas flow was also monitored.
• a particular conduit can be monitored in substantially real-time.
• the necessary computational analysis is carried out, preferably by a digital computer program, to determine the flow rate of the gas (or similar fluid) through the conduit.
• the method and system of the present invention allows for estimation of the operational dynamics of components or facilities of the production, transportation, storage, and distribution systems for the energy commodities.
• storage facilities receive and store gas collected by production companies during periods of lower usage (i.e., the summer months) and then distribute stored gas to local distribution companies during periods of high usage (i.e., the winter months), as generally described above with reference to Figure 1.
• gas is transported into and out of such storage facilities through a number of pipelines.
• the net injection or withdrawal of gas for a particular storage facility can be determined. Then, as also described above, this estimate can be communicated to third parties through an access-controlled internet web site or otherwise.
• FIG. 7 illustrates such an estimate of the output of a storage facility 16 to which three pipelines 32, 132, 232 are connected.
• Each such pipeline 32, 132, 232 is monitored by a package of one or more sound transducers 34, 134, 234 and associated monitoring devices 30, 130, 230.
• Data collected and processed by each monitoring device 30, 130, 230 is transmitted via a satellite link 104 to a central processing facility 110, where, through a simple summing of the computed flow rates on each pipeline 32, 132, 232, the net injection or withdrawal of gas for the storage facility 16 can be determined.
• various techniques can be used to deduce the direction of flow.
• pipeline networks at storage facilities includes similar mechanical components and structures, with the function of these components and structures often being dependent on the direction of flow through the pipeline. Accordingly, an evaluation of the physical layout of the pipeline networks may provide some indication of the direction of flow. Furthermore, an analysis of the measured acoustic waves may provide an indication of the direction of flow in that certain mechanical components may be activated when gas flow is in a certain direction (e.g., a compressor for injection of gas into the storage facility). For another example, the knowledge of the seasonal operation of the storage facility, as mentioned above, may be used to deduce the direction of flow. Regardless of the technique used, the net injection or withdrawal of gas for a particular storage facility can thus be determined.

Landscapes

• Physics & Mathematics (AREA)
• Electromagnetism (AREA)
• Fluid Mechanics (AREA)
• General Physics & Mathematics (AREA)
• Measuring Volume Flow (AREA)
• Pipeline Systems (AREA)
• Arrangements For Transmission Of Measured Signals (AREA)
• Investigating Or Analyzing Materials By The Use Of Ultrasonic Waves (AREA)

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• 2004
  • 2004-10-18 US US10/967,737 patent/US7274996B2/en not_active Expired - Lifetime
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  • 2004-10-19 WO PCT/US2004/034584 patent/WO2005042984A2/en not_active Ceased
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• 2006
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