A downhole fluid properties optical analysis probe (1) to analyze at least one property of a multiphase flow mixture (100) flowing in a hydrocarbon well (51) has an elongated cylindrical body shape. It comprises an optical tip (5) at one end of the elongated cylindrical body arranged to be in contact with the multiphase flow mixture (100). It further comprises an optical link (6) adapted for a connection with an electronics module (11) at another end of the elongated cylindrical body arranged to be separated from the multiphase flow mixture (100). The optical tip (5) is coupled to the optical link (6) through a removable and watertight coupling (7). The removable and watertight coupling comprises a first portion (9a) of a protective tube (9) resistant to downhole conditions, said first portion (9a) enclosing the optical link (6) and comprising at least one first ring bulge (22) close to a coupling interface (10), and a second portion (9b) of the protective tube (9) partially enclosing the optical tip (5) such as to let a distal end of the optical tip (5) in contact with the multiphase flow mixture (100), said second portion (9b) comprising at least one second ring bulge (23) close to the coupling interface (10). It further comprises a coupling tube (24) surrounding facing ends of the first portion (9a) and the second portion (9b), said coupling tube (24) being adjusted in size to fit in between said first and second ring bulges (22, 23), and a coupling and protecting sheath (25) enclosing said first ring bulge (22), coupling tube (24) and second ring bulge (23) in a watertight manner.

A downhole sensing method includes modulating light to form a soliton that propagates through an optical fiber acting as a sensing element that measures a downhole parameter. The method further includes obtaining scattered light created as the soliton propagates through the optic-fiber. The method further includes determining a value for a downhole parameter based on the scattered light, and displaying a representation of the value.

A method of monitoring electromagnetic properties of a sub-surface formation may include: obtaining a resistivity distribution in the subsurface formation; identifying sensor positions along a borehole; determining an effective resistivity of each region around a sensor position; deriving from the effective resistivities of regions associated with each sensor position an optimum resonance frequency; tuning an array of sensors to provide each sensor with the optimum resonance frequency; deploying the sensor array in the borehole; and collecting electromagnetic field measurements. Each sensor may include: a coil antenna positioned in a subsurface formation having a resistivity, the coil antenna generating a induced voltage signal from an electromagnetic field in the subsurface formation; and a resonant modulation circuit that converts the induced voltage signal into a telemetry signal, the resonant modulation circuit having a resonance frequency optimized for said formation resistivity.

System and methods of controlling fluid diversion during stimulation treatments are provided. Real-time measurements are obtained from a plurality of fiber-optic data sources at a well site during a stimulation treatment being performed along a portion of a wellbore within a subsurface formation. Fracture growth and stress within the subsurface formation surrounding the portion of the wellbore are determined as the stimulation treatment is performed, based on the real-time measurements and a fully-coupled diversion model. An amount of diverter for a diversion phase of the stimulation treatment to be performed along the portion of the wellbore is determined, based on the fracture growth and the stress within the subsurface formation. The diversion phase of the stimulation treatment is performed by injecting the amount of diverter into the subsurface formation via at least one injection point located along the portion of the wellbore.

Flow electrification sensors and methods relating thereto may be useful in characterizing fluids, especially the in situ characterization of fluids produced during oil and gas production operations. A system may include a flow path; a flow electrification sensor at least partially contained within the flow path, the flow electrification sensor comprising a static charge accumulator and an insulator arranged such that the static charge accumulator interacts with a fluid in the flow path; a reference sensor; and a signal processor communicably coupled to the flow electrification sensor and the reference sensor.

An analytical method that establishes a thermodynamic equilibrium or known dynamic relationship between the concentrations of gases, natural gas liquids and oils or pressures of gasses in an isolated zone of a shale, or group of distinct shale gas intervals, with the concentrations of fluids or pressures of gasses in a wellbore penetrating the shale interval or intervals. An analytical method for identifying the chemical composition of gas, natural gas liquids and oils and determining their origin in an isolated zone of a shale, or group of distinct shale gas intervals with the identification of chemical composition of gas, natural gas liquids and oils in a wellbore penetrating the shale interval or intervals. A surface measurement apparatus capable of performing the measurement ex-situ. A downhole measurement apparatus capable of reliably performing the measurement in-situ and a downhole straddle-packer assembly capable of isolating part of, or an entire shale interval.

A method of detecting a flood front through a subterranean formation, comprising, measuring a distance to the flood front, processing the measured distance using a predictor-corrector filter to determine a corrected distance to the flood front, and adjusting a formation device based on the corrected distance to control a flow of the flood front.

A method of detecting a flood front through a subterranean formation, comprising, measuring a distance to the flood front, processing the measured distance using a predictor-corrector filter to determine a corrected distance to the flood front, and adjusting a formation device based on the corrected distance to control a flow of the flood front.

A method may include transmitting a narrowband signal into a formation using a transmitter located in a wellbore. The narrowband signal is modified by passage of through the formation and the formation reflects at least a portion of the narrowband signal back to the wellbore resulting in a modified narrowband signal having a first frequency. The method also includes sensing the modified narrowband signal with an optical waveguide positioned in the wellbore, transmitting a source signal along a length of the optical waveguide, and obtaining a backscattered return signal from the optical waveguide. The backscattered return signal is sampled at a second frequency that is less than the Nyquist rate of the modified narrowband signal. The method further includes processing the backscattered return signal to obtain an amplitude of the modified narrowband signal.

A method may include collecting measurement data using a first operational sensor and a second operational sensor of a downhole tool, standardizing optical responses of each operational sensor to a master sensor in a tool parameter space to obtain a standardized master sensor response, transforming the standardized master sensor response to a synthetic parameter space response of the master sensor, applying a fluid model with the synthetic parameter space response of the master sensor to predict a fluid characteristic, comparing a first prediction obtained with the fluid model from the first operational sensor with a second prediction obtained with the fluid model from the second operational sensor, determining a fluid characteristic from the first prediction and the second prediction, and optimizing a well testing and sampling operation according to the fluid characteristic.