Abstract: Methods and apparatus enable measuring flow of a fluid within a conduit. For example, flowmeters may measure the velocity of production fluid flowing through production pipe of an oil/gas well. The flowmeters rely on detection of pressure variations generated as a result of a backward-facing step as a basis for flow measurement calculations. Pressure sensing occurs away from the step in a direction of the flow of the fluid in an enhanced turbulence region of the flowmeter where the inner diameter remains enlarged as a result of the step.

Abstract: Methods and apparatus for detecting particles flowing in a fluid within a conduit involve analysis of acoustic pressure signals detected with an array of at least two pressure sensors. The analysis can include monitoring for attenuation in power of the acoustic disturbances within the fluid and/or a reduction in a speed of sound in the fluid. This attenuation in power or reduction in the speed of sound can be detected to provide an output or otherwise indicate that particles are present in the fluid.

Abstract: Methods and apparatus enable sensing flow of a fluid inside a conduit with an array of pressure or strain sensors. Inputs for a curve fit routine include power correlation values at one of multiple trial velocities or speeds of sound and several steps on either side utilizing data obtained from the sensors. The velocity at which a curve fit routine returns a max curvature result corresponds to an estimate value that facilitates identification of a speed of sound in the fluid and/or a velocity of the flow. Furthermore, a directional quality compensation factor may apply to outputs from the curve fit routine to additionally aid in determining the velocity of the flow.

Abstract: Methods and apparatus determine individual phase fractions for three phases within a fluid mixture. Appropriate flow algorithms can utilize this phase fraction information with a sensed total combined flow rate of the mixture to find individual flow rates for the three phases, such as oil, water and gas. For some embodiments, a multiphase flowmeter includes an array of spatially distributed pressure sensors configured to determine a speed of sound in the mixture and any type of water cut meter, oil cut meter or gas cut meter.

Abstract: Methods and apparatus determine phase fractions for phases within a fluid mixture flow under a wide range of flow conditions including wet-gas flow. Appropriate flow algorithms can utilize this phase fraction information with a total flow rate of the mixture to find individual flow rates for phases, such as oil, water, and gas or gas and liquid, which can represent a combination of oil and water phases. For some embodiments, a multiphase flowmeter includes an array of spatially distributed pressure sensors configured to determine a velocity of the mixture flow and hence the total flow rate, which is applied with information from a differential pressure meter to calculate the bulk density of the fluid mixture. Further, additional speed of sound information or a water-in-liquid ratio as may be determined by spectral analysis can enable differentiation between the oil and water phases.

Abstract: Method and apparatus enable direct measurement of at least one flow velocity for one or more phases within a multiphase fluid mixture flowing in a conduit. Some embodiments provide determination of actual individual phase flow rates for three phases (e.g., oil, water and gas) that are distinct from one another within the fluid mixture. A multiphase flowmeter according to embodiments of the invention includes at least two optical sensors spatially distributed along a length of the conduit and designed to detect light interactions with the fluid mixture unique to the phases such that detected time-varying signals can be processed via cross-correlation or an array processing algorithm to provide desired individual phase flow velocity for oil, water and/or gas phases. This flow velocity can be applied to phase fraction measurements, which can be obtained utilizing the same flowmeter or another separate device, to calculate the flow rates for the phases.

Abstract: Embodiments of the present invention generally provide methods, apparatus, and systems for determining void fractions of individual phase components of a multiphase mixture. The void fractions may be determined based on measured parameters of the mixture as a whole, such as differential pressure, bulk velocity of the mixture and speed of sound in the mixture. According to some embodiments, the mixture parameters may be measured using non-intrusive fiber optic based sensors. Various other parameters may also be derived from the void fractions, such as individual phase flow rates, liquid holdup and watercut parameters (for oil and gas mixtures).

Abstract: A method and system for monitoring the operation of downhole equipment, such as electrical submersible pumps, is disclosed. The method and system rely on the use of coiled fiber optic sensors, such as hydrophones, accelerometers, and/or flow meters. These sensors are either coupled to or placed in proximity to the equipment being monitored. As the sensor is perturbed by acoustic pressure disturbances emitted from the equipment, the length of the sensing coil changes, enabling the creation of a pressure versus time signal. This signal is converted into a frequency spectrum indicative of the acoustics emissions of the equipment, which can then be manually or automatedly monitored to see if the equipment is functioning normally or abnormally, and which allows the operator to take necessary corrective actions.

Abstract: Embodiments of the present invention generally provide methods, apparatus, and systems for determining void fractions of individual phase components of a multiphase mixture. The void fractions may be determined based on measured parameters of the mixture as a whole, such as differential pressure, bulk velocity of the mixture and speed of sound in the mixture. According to some embodiments, the mixture parameters may be measured using non-intrusive fiber optic based sensors. Various other parameters may also be derived from the void fractions, such as individual phase flow rates, liquid holdup and watercut parameters (for oil and gas mixtures).

Abstract: Embodiments of the present invention generally provide methods, apparatus, and systems for determining void fractions of individual phase components of a multiphase mixture. The void fractions may be determined based on measured parameters of the mixture as a whole, such as differential pressure, bulk velocity of the mixture and speed of sound in the mixture. According to some embodiments, the mixture parameters may be measured using non-intrusive fiber optic based sensors. Various other parameters may also be derived from the void fractions, such as individual phase flow rates, liquid holdup and watercut parameters (for oil and gas mixtures).

Abstract: A method and system for monitoring the operation of downhole equipment, such as electrical submersible pumps, is disclosed. The method and system rely on the use of coiled fiber optic sensors, such as hydrophones, accelerometers, and/or flow meters. These sensors are either coupled to or placed in proximity to the equipment being monitored. As the sensor is perturbed by acoustic pressure disturbances emitted from the equipment, the length of the sensing coil changes, enabling the creation of a pressure versus time signal. This signal is converted into a frequency spectrum indicative of the acoustics emissions of the equipment, which can then be manually or automatedly monitored to see if the equipment is functioning normally or abnormally, and which allows the operator to take necessary corrective actions.