Saudi Arabian Oil Company

Other

Baker Hughes Oilfield Operations LLC

King Fahd University of Petroleum and Minerals

The University of Western Australia

Mohamed Nabil Noui-Mehidi

Michael John Black

Talha Jamal Ahmad

Muhammad Arsalan

Sameeh Issa Batarseh

Ahmed Yasin Bukhamseen

Jana M Al-Jindan

Khalid Mohammed M Alruwaili

Wael O Badeghaish

Jinjiang Xiao

Brett Bouldin

Paul Louis Stanwix

Michael Leslie Johns

Einar Orn Fridjonsson

Rocco DiFoggio

Otto N Fanini

Frode Hveding

Belabbes Merzougui

Dwight W Swett

Alwaleed Abdullah Al-Gouhi

Robert Turner

Sandip Maity

Jana Mohammed Aljindan

Mohammad Qamar

Abdulrahman Abdulaziz Al Mulhem

Adeola Akeem Akinpelu

Bukola Saheed Abidemi

Jana Mohamed Aljindan

Keelan Thomas O'Neill

Abdulaziz S Al-Qasim

Yuguo Wang

Abdulrahman Abdulaziz Al-Mulhem

Fakuen Frank Chang

Abdelsalam Mohammad Al-Sarkhi

Ahmad Rizq

Khalid M Al-Ruwaili

Omer Abdelazim Salim

Masoumeh Zargar

Xiao Jinjiang

Rabea Ahyad

Fadhil N Alsayegh

Qais Mohammad Al Hennawi

Ilies Mostefai

Khalid M Ruwaili

Systems and components thereof are provided for analyzing multiphase production fluids. The system comprises a fluidic separation chamber, a fluidic separation chamber valve, fluidic piping configured to supply multiphase production fluid to the fluidic separation chamber through the fluidic separation chamber valve, a plurality of composite sensing modules vertically spaced within the fluidic separation chamber, and a fluidic supply and analysis unit. Each of the sensing modules comprising an inductive sensor comprising opposing inductive sensing elements displaced from one another across a vertically extending measurement portion of the fluidic separation chamber, and a capacitive sensor comprising opposing capacitive sensing elements displaced from one another across the vertically extending measurement portion of the fluidic separation chamber. The capacitive sensor of each of the plurality of composite sensing modules to detect a height Hof an oil phase column in the multiphase production fluid in the fluidic separation chamber.

Systems and methods for analyzing multiphase production fluids

A downhole fluid analysis system includes an optical sensor comprising, which includes a light source configured to emit light comprising a plurality of wavelengths, a light detector, and an optical tip through which at least a portion of the light travels and returns to the detector, wherein the incident angle of the light causes total internal reflection within the optical tip. The system further includes a piezoelectric helm resonator that generates a resonance response in response to an applied current, and an electromagnetic spectroscopy sensor positioned symmetrically with respect to the piezoelectric helm resonator in at least one direction. The light may be reflected in the optical tip at one or more reflection points, and each reflection point may generate an evanescent wave in a medium surrounding the optical tip. The light may be internally reflected in the optical tip at a plurality of reflection points.

Attenuated total internal reflection optical sensor for obtaining downhole fluid properties

A method includes assembling a liner system by disposing a fiber optic cable circumferentially around an inner tube liner and locating an outer tube liner around the inner tube liner. The fiber optic cable is located between the inner tube liner and the outer tube liner. The method also includes spooling out the liner system, in a lay-flat state, into a conduit of a tubular structure positioned in the well, terminating spooling out the liner system when a select length of the liner system has been deployed in the conduit of the tubular structure, and securing the select length of the liner system deployed into the tubular structure at a surface above the well. The method further includes injecting a fluid into the inner tube liner of the liner system to radially expand the liner system to conform an outer circumferential surface of the outer tube liner to an inner circumferential surface of the tubular structure, protecting the inner circumferential surface of the tubular structure using the liner system, and measuring a property of the well using the fiber optic cable.

Well conduit lining method and system

Systems for generating stable emulsions may employ one or more liquid-liquid ejectors for mixing the oil with water through motive and suction streams to produce the emulsion as a discharge stream. One or more motive tanks may be fluidly coupled to the one or more liquid-liquid ejectors; the one or more motive tanks may supply the one or more liquid-liquid ejectors with a motive fluid. One or more suction tanks may be fluidly coupled to the one or more liquid-liquid ejectors; the one or more suction tanks may supply the one or more liquid-liquid ejectors with a suction fluid. One or more discharge tanks may be fluidly coupled to the one or more liquid-liquid ejectors; the one or more discharge tanks may collect an emulsion from the one or more liquid-liquid ejectors. Additionally, a flow line coupled to the one or more discharge tanks may feed the emulsions into a formation.

Methods and systems for the generation of stable oil-in-water or water-in-oil emulsion for enhanced oil recovery

Described is a device for measuring fluid density. The device is a flow meter including a housing with one side configured to mount to a flow conduit and define an outlet flow orifice near one end of the housing. The other side defines an inlet flow orifice near another end of the housing. The housing permits fluid to be introduced into the inlet flow orifice, flow through a flow cavity, and pass from the outlet flow orifice. The flow meter also includes a sensor head near the outlet flow orifice. The sensor head vibrates at a frequency upon introduction of electrical power while in contact with a fluid, detects the vibration frequency of the sensor head, and transmits the detected vibration frequency, which is associated with a density of the fluid. A system and method for determining a fluid density of a fluid using the described device is also disclosed.

Method and device for measuring fluid density

A downhole monitoring system for continuously measuring in real-time a fluid produced from a reservoir includes a tubing extending into a wellbore, spaced apart packers forming annular seals between the tubing and a wall of the wellbore, isolated compartments formed between the spaced apart packers, each compartment having an opening in the tubing to allow fluid communication from the reservoir to surface equipment, and an ultraviolet spectrometer installed in each compartment. The ultraviolet spectrometer includes an ultra-violet source that excites diamondoids, a photomultiplier to quantify the excited diamondoids, and an electronic circuit that digitizes a response from the photomultiplier and sends the response to the surface of the wellbore. Additionally, a method includes continuously monitoring and in real-time a fluid produced from a reservoir and determining reservoir connectivity and reservoir profiling.

Diamondoids for monitoring and surveillance

Methods, systems, and apparatus, including computer programs encoded on a computer storage medium, for monitoring slug flow in subterranean wells. In one aspect, a method includes at a time instant, transmitting an acoustic signal across a cross-section of a pipeline flowing multiphase fluid including gaseous fluid and liquid fluid, wherein a portion of the acoustic signal is carried through the cross-section of the pipeline by the multiphase fluid and determining, at the time instant, a first quantity of the gaseous fluid and a second quantity of the liquid fluid passing the cross-section of the pipeline based, in part, on an energy of the portion of the acoustic signal carried through the cross-section and at least a portion of a total energy of the transmitted acoustic signal.

Slug flow monitoring and gas measurement

Tools, processes, and systems for in-situ fluid characterization based on a thermal response of a fluid are provided. The thermal response of a downhole fluid may be measured using a downhole thermal response tool and compared with thermal responses associated with known fluids. The properties of the downhole fluid, such as heat capacity, diffusivity, and thermal conductivity, may be determined by matching the thermal response of the downhole fluid with a thermal response of a known fluid and using the properties associated with the known fluid. The composition of the downhole fluid may be determined by matching the viscosity of the downhole fluid to the viscosity of known fluid. A downhole thermal response tool for cased wellbores or wellbore sections and a downhole thermal response tool for openhole wellbores or wellbore sections are provided.

In-situ thermal response fluid characterization

A method includes wrapping a packer bag around a deployment tool, providing at least one canister in fluid communication with the packer bag, sending the packer bag around the downhole tool to a downhole location in a well, and injecting a polymer filler material from the at least one canister into the packer bag until the packer bag expands to seal the downhole location.

Methods for deployment of expandable packers through slim production tubing

A multiphase flow metering device may have a conduit through which a multiphase fluid can flow and a structured packing insert positioned in the conduit. The structured packing insert may have a water-wet packing structure zone and/or an oil-wet packing structure zone. The multiphase flow metering device may also have a Halbach pre-polarizing magnet array positioned around the conduit, an RF coil, an electromagnet, an NMR console adapted to detect NMR signals from the multiphase fluid, and a control system configured to vary a polarization of the Halbach pre-polarizing magnet array. The Halbach pre-polarizing magnet array may be positioned or positionable over one or both of the oil-wet and water-wet packing structure zones. In some embodiments, the structured packing insert may include immobilized radicals, providing for dynamic nuclear polarization of the multiphase fluid.

Liquid NMR signal boost during NMR flow metering of wet gas flow using enhanced signal relaxation and/or dynamic nuclear polarisation using immobilised radicals

Techniques for measuring fluid properties include circulating a mixed-phase fluid flow through a fluid flow circuit; circulating the mixed-phase fluid flow through a pre-polarizing magnet; polarizing at least a gas phase of the mixed-phase fluid flow to an initial polarization; measuring fluid induction decay (FID) values of the polarized gas phase with the EFNMR detector; determining a velocity of the gas phase based on the FID values of the polarized gas phase; producing a pulsed magnetic field gradient to suppress one or more signals acquired by the EFNMR detector with a first electromagnet; measuring FID values of the liquid phase of the mixed-phase fluid with the EFNMR detector simultaneously with the production of the pulsed magnetic field gradient; producing a homogeneous polarizing field to polarize the liquid phase of the mixed-phase fluid with a second electromagnet; and determining a velocity and content of the liquid phase based on the FID values of the polarized liquid phase.

Determining fluid properties

A vortex flow meter is within a flow conduit. The vortex flow meter includes a housing defining a flow passage substantially in-line with the flow conduit. An actuable buff body is within the flow passage. A sensor is downstream of the actuable buff body and is attached to the housing. The sensor is configured to detect vortex shedding. A controller is configured to send a drive signal to an oscillator to oscillate the buff body. The controller is configured to receive a vortex stream from the sensor. The vortex stream is indicative of vortexes shed by the buff body within a fluid. The controller is configured to determine a flow velocity responsive to the received vortex stream.

Reducing noise in a vortex flow meter

Techniques for measuring liquid properties include circulating a mixed oil-water liquid flow through a fluid flow circuit; polarizing the mixed oil-water liquid flow with a pre-polarizing magnet to an initial polarization; circulating the polarized mixed oil-water liquid flow to an EFNMR detector that includes a radio-frequency (RF) coil and a surrounding electromagnet; further polarizing the polarized mixed oil-water liquid flow with the surrounding electromagnet; measuring fluid induction decay (FID) values of the additionally polarized mixed oil-water liquid flow with the EFNMR detector; transforming the measured FID values to an effective adiabatic transition from the Earth's field to the polarizing field; determining a velocity of the oil in the mixed oil-water liquid flow and a velocity of the water in the mixed oil-water liquid flow based on differences in NMR signal relaxation properties of the transformed FID values; and determining an oil content and a water content of the mixed oil-water liquid flow from the transformed FID values.

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Dhahran, Saudi Arabia

Mohamed Nabil Noui-Mehidi