Weatherford/lamb, Inc.

Weatherford Technology Holdings, LLC

Other

John Lievois

Espen S Johansen

Babajide Adejuyigbe

Omer Haldun Unalmis

Vijay Ramakrishnan

David Atkinson

Tanner Lievois

Gregg Hurst

Ken George Booth

Near-Infrared (NIR) filter photometry is used to calculate component concentrations in multiphase flows. The disclosed methodology adapts the Beer-Lambert law for nonhomogeneous immiscible mixtures (such as oil and water) by modeling the fluid layer as a nonhomogeneous distribution of its components and deriving a mathematical relationship between measured absorbances, component path lengths, and non-homogeneity factors. The methodology is integrated into a multi-channel filter photometer to measure phase concentrations in oil-and-gas pipelines. The system is proven more accurate than current state of the art based on data from simulations, multiphase flow laboratories and field trials.

Measuring component concentrations of nonhomogeneous immiscible mixtures in multiphase flows using near-infrared (NIR) filter photometry

A low cost, low power, passive optical methane monitoring system for fixed-position installation at oil and gas production well pads and gathering centers is disclosed. The optical methane monitoring system disclosed can be a scannable field of view Near Infrared (NIR) filter photometer to detect and quantify methane concentration in a two dimensional or a three dimensional grid above and around a facility. A randomized fiber optic bundle is disclosed that can be used to direct the total optical power from a collection lens to two or more isolated optical channels. Band pass filters isolate a desired wavelength range for transmission measurements for the two or more channels. Also disclosed is an absorption algorithm which accounts for variable background spectral intensity as well as correcting for water vapor and overall scattering effects to measure methane concentration for a given field of view.

Methane monitoring and detection apparatus and methods

Multiphase flow measurement in extreme environments such as subsea or in-well is a difficult task for many reasons including reliability, survivability, and longevity issues; accessibility to the equipment; and complexity of the varying flow field as a function of position and time. Embodiments of the present invention provide techniques and apparatus for performing subsea multiphase flow measurement by combining two technologies. One is based on infrared water-cut measurement technology which is capable of measuring water and oil concentrations in multiphase flow with up to 99.5% gas volume fractions. The second technology is based on in-well fiber-optic flow measurement capable of resolving gas and total liquid flow through the measurements of flow velocity, fluid mixture speed of sound, and absolute pressure and temperature at meter location. This hybrid system represents an approach to subsea multiphase metering that may offer advantages compared to traditional systems for some applications.

Multiphase flowmeter for subsea applications

Methods and apparatus for determining phase fractions (relative concentrations) within a multiphase fluid mixture, in the presence of an injected hydrate inhibitor. Combining this phase fraction information with a hydrate inhibitor injection rate (HIIR) enables resolving oil and water flow rates for the phase fractions. The liquid flow rates and a total combined flow rate of the fluid mixture&#x2014;determined based on a differential pressure of the fluid mixture through a given area&#x2014;enable resolving a gas flow rate.

Multiphase flow meter for subsea applications using hydrate inhibitor measurement

Methods and apparatus for measuring a phase fraction of a flow stream are disclosed. An infrared phase fraction meter includes a light source for emitting into a flow stream infrared radiation that includes first and second wavelength bands. The first wavelength band substantially transmits through first and second phases of the flow stream and is substantially absorbed by a third phase. In contrast, the second wavelength band is substantially absorbed by the second phase relative to the first and third phases. One or more detectors simultaneously detect attenuation of the first and second wavelength bands upon the infrared radiation passing through at least a portion of the flow stream, and a phase fraction of the second phase is determined based on the attenuation. As an example, the first, second and third phases are gas, water and oil, respectively, produced from a well.

Multi-channel infrared optical phase fraction meter

Methods and apparatus enable monitoring a hydrocarbon well for water within a flow stream of the well. A water detector includes a light source for emitting into a flow stream infrared light that includes a water absorbent wavelength band. A detector detects attenuation of the water absorbent wavelength band upon the infrared radiation passing through at least a portion of the flow stream. The water detector outputs a presence of water and/or a phase fraction or quantification of water as determined based on the attenuation. Detecting attenuation of a substantially transmissive wavelength band with respect to water simultaneously with detection of the attenuation of the water absorbent wavelength band can enable correction for non-wavelength dependent attenuation.

Water detection and 3-phase fraction measurement systems

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.

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Houston, TX, United States of America

John Lievois