Schlumberger Technology Corporation

University of Alberta

Schlumberger Canada Limited

Services Petroliers Schlumberger

Schlumberger Holdings Limited

Prad Research and Development Limited

Farshid Mostowfi

Shahnawaz Hossain Molla

Vincent Joseph Sieben

Abdel Kharrat

Abdel M Kharrat

Elizabeth Jennings Smythe

John Ratulowski

Cedric Floquet

Marc Schneider

Christopher Harrison

Matthew T Sullivan

Ronald E G Van Hal

Neil William Bostrom

Simon Ivar Andersen

Jane T Lam

Michael Mallari Toribio

Anil Singh

Philip Homewood

Kenneth Chau

Amy Du

Joseph Samuel Baddeley

Kentaro Indo

Shawn David Taylor

Shunsuke Fukagawa

John Meier

Kurt Schmidt

Alexander Stickel

Collins Obiosa-Maife

Subir Bhattacharjee

Jacob Masliyah

Jan Czarnecki

Elizeusz Lucjusz Musial

Cailan Libby

Mohammed Al-Shakhs

Rob Fisher

Heng-Joo Ng

Nejib Hamed

Younes Belahnech

Philip James Homewood

Robert Fisher

Shahnawaz Molla

Vincent Sieben

A method of determining saturate, aromatic, resin, and asphaltene (SARA) fractions of a hydrocarbon fluid sample, including: i) microfluidic mixing that forms a mixture including the hydrocarbon fluid sample and a solvent fluid that dissolves asphaltenes; ii) performing optical spectroscopy on the hydrocarbon fluid sample-solvent fluid mixture resulting from i); iii) microfluidic mixing that forms a mixture including the hydrocarbon fluid sample and a titrant fluid that precipitates asphaltenes; iv) microfluidically precipitating asphaltenes from the hydrocarbon fluid sample titrant fluid mixture resulting from iii); v) performing a microfluidic filtering operation that removes precipitated asphaltenes from the mixture resulting from iv) while outputting permeate; vi) performing optical spectroscopy on the permeate resulting from v); vii) determining an asphaltene fraction percentage of the hydrocarbon fluid sample based on the optical spectroscopy performed in ii) and vi); viii) sequentially separating saturate-, aromatic-, and resin-containing portions from the permeate from v); ix) for each separating of viii), measuring an optical property of the respective saturate-, aromatic-, and resin-containing portions over time; and x) determining fraction percentages of saturates, aromatics, and resins in the hydrocarbon fluid sample based on the measured optical properties of ix) and respective mass-to-optical correlation data.

Automated method and apparatus for measuring saturate, aromatic, resin, and asphaltene fractions using microfluidics and spectroscopy

A technique facilitates detection and analysis of constituents, e.g. chemicals, which may be found in formation fluids and/or other types of fluids. The technique comprises intermittently introducing a first fluid and a second fluid into a channel in a manner which forms slugs of the first fluid separated by the second fluid. The intermittent fluids are flowed through the channel to create a mixing action which mixes the fluid in the slugs. The mixing increases the exchange, e.g. transfer, of the chemical constituent between the second fluid and the first fluid. The exchange aids in sensing an amount of the chemical or chemicals for analysis. In many applications, the intermittent introduction, mixing, and measuring can be performed in a subterranean environment.

System and methodology for chemical constituent sensing and analysis

A method and system are provided for detecting the wax appearance temperature (WAT) of a hydrocarbon fluid sample. The hydrocarbon fluid sample is run through a microfluidic channel at controlled temperatures while sensing the pressure drop across the channel. The WAT is determined by finding a temperature at which the pressure (drop) across the microfluidic channel caused by a temperature reduction of the hydrocarbon fluid sample does not stabilize over a given time interval, thereby establishing the WAT as being at that temperature or between that temperature and a previous higher temperature where the pressure (drop) stabilized over time.

Microfluidic determination of wax appearance temperature

A microfluidic apparatus has a microchannel that includes at least one vertically oriented segment with a top section having a relatively wide opening and a bottom section having a relatively narrow opening. The top section is larger in volume relative to the bottom sections, and the middle sections taper down in at least one dimension from the top section to the bottom section. One or tens or hundreds of vertically-oriented segments may be provided, and they are fluidly coupled to each other. Each segment acts as a pressure-volume-temperature (PVT) cell, and the microchannel apparatus may be used to determine a parameter of a fluid containing hydrocarbons such as the dew point of the fluid or the liquid drop-out as a function of pressure.

Measurement of liquid parameters using a microfluidic device

A microfluidic device for evaluation of an organic/inorganic scale inhibitor is provided. The device comprises a substrate mountable to a disc for rotation about an axis. The device further comprises a proximal end and a distal end. The substrate defines a sample reservoir, a solvent reservoir, an inhibitor reservoir, and a precipitant reservoir at the proximal end and an analysis chamber at the distal end in fluid communication with the sample, solvent, inhibitor, and precipitant reservoirs. The substrate is constructed to direct one or more of fluids in the sample reservoir, solvent reservoir, inhibitor reservoir, and precipitant reservoir radially outwardly towards the analysis chamber under the influence of centrifugal force when the microfluidic device rotates.

Centrifugal platform and device for rapid analysis of oilfield fluids

A method of characterizing an oil sample includes: flowing a first sample containing an oil through a microfluidic device that has a microfluidic filter while controlling the temperature of the first sample such that it is above wax appearance temperature for the oil and measuring and analyzing pressure difference across the filter over time to detect the presence of fines in the oil. The method further includes: flowing a second sample containing the oil through the microfluidic device while controlling the temperature of the second sample such that the temperature of the second sample is lower than wax appearance temperature for the oil and measuring and analyzing pressure difference across the filter over time as the second sample is filtered to detect the presence of wax in the oil.

Microfluidic method for detection of fines, waxes, and asphaltenes in oil

A test method and apparatus employs a microfluidic device to characterize properties of a fluid. The microfluidic device has an inlet port, an outlet port, and a microchannel as part of a fluid path between the inlet port and the outlet port. While a fluid is introduced into the microchannel, the fluid temperature is maintained while the fluid pressure in the microchannel is varied to characterize the properties of the fluid in the microchannel. The properties of the fluid can relate to a scale onset condition of the fluid at the pressure of the flow through the microchannel. In one aspect, fluid pressure in the microchannel is maintained while the fluid temperature is varied to characterize the properties of the fluid. In another aspect, flow rate of the fluid through the microchannel is varied while the fluid temperature is maintained to characterize the properties of the fluid in the microchannel.

Method and apparatus for characterizing inorganic scale formation conditions employing a microfludic device

A method for determining the asphaltene content of oil includes obtaining an oil sample, determining an optical spectrum of the oil sample and removing asphaltenes from the oil sample by precipitating asphaltenes using a first alkane precipitant. The method also includes determining an optical spectrum of maltenes of the oil sample and subtracting the optical spectrum of the maltenes of the oil sample from the optical spectrum of the oil sample to yield an optical spectrum of asphaltenes of the oil sample. The method further includes using the optical spectrum of asphaltenes of the oil sample to determine asphaltene content of the oil sample using a second alkane precipitant.

Method of predicting the concentration of asphaltenes using a first precipitant and correlation back to an asphaltene concentration measurement using a second precipitant

An optical sensor and corresponding method of operation can detect a phase transition and/or related property of a hydrocarbon-based analyte. The optical sensor includes an optical element with a metallic film coupled or integral thereto, with a sample chamber holds the hydrocarbon-based analyte such that the hydrocarbon-based analyte is disposed adjacent the metallic layer. The optical sensor further includes a light source configured to direct light through the optical element such that the light is reflected by the metallic layer under conditions of surface plasmon resonance. The optical sensor analyzes the reflected light to detect a phase transition and/or related property of a hydrocarbon-based analyte.

Optical sensors using surface plasmon resonance to determine at least one property relating to phase change of a hydrocarbon-based analyte

An optical sensor includes a flow cell permitting flow of a hydrocarbon-based analyte therethrough. A metallic film is disposed adjacent or within the flow cell. At least one optical element directs polychromatic light for supply to an interface of the metallic film under conditions of surface plasmon resonance (SPR) and directs polychromatic light reflected at the interface of the metallic film (which is sensitive to SPR at such interface and thus provides an SPR sensing region within the flow cell) for output to at least one spectrometer that measures spectral data of such polychromatic light. A computer processing system is configured to process the measured spectral data over time as the hydrocarbon-based analyte flows through the flow cell to determine SPR peak wavelength over time and to process the SPR peak wavelength over time to determine at least one property related to phase transition of the analyte.

Systems, methods and apparatus for analysis of reservoir fluids using surface plasmon resonance

A system for performing a flash separation of a reservoir fluid includes a sample chamber configured to hold the reservoir fluid and a flash apparatus in fluid communication with the sample chamber. The flash apparatus includes a microfluidic device configured to flash the reservoir fluid in fluid communication with the sample chamber, and a separation chamber configured to separate the flashed reservoir fluid into a liquid phase and a gaseous phase in fluid communication with the microfluidic device. The system further includes a gas receptacle configured to store the gaseous phase, A method for performing a flash separation of a reservoir fluid includes providing a reservoir fluid to a microfluidic device, urging the reservoir fluid through the microfluidic device such that the reservoir fluid is lashed within the microfluidic device, and separating a liquid phase and a gaseous phase from the flashed reservoir fluid.

Microfluidic system and method for performing a flash separation of a reservoir fluid sample

A method of evaluating an asphaltene inhibitor includes providing a centrifugal microfluidic system including: a disc mounted to rotate about an axis; a microfluidic device mounted on the disc, the device having sample, solvent, inhibitor, and precipitant reservoirs and an analysis chamber in fluid communication with the sample, solvent, inhibitor, and precipitant reservoirs; and an optical detection system coupled to the analysis chamber and configured to measure the optical transmission of fluid in the analysis chamber. The method includes filling the sample, solvent, inhibitor, and precipitant reservoirs, respectively, with a sample, solvent, inhibitor, and precipitant; rotating the disc to generate centrifugal force to cause the sample, solvent, inhibitor, and precipitant to travel radially outward to the analysis chamber; and measuring the optical transmission of a mixture of the sample, solvent, inhibitor, and precipitant in the analysis chamber as a function of radial distance of the analysis chamber.

A method and apparatus for analyzing solubility of asphaltenes of a hydrocarbon fluid sample involves a sequence of operations including: i) performing microfluidic mixing operations that form a mixture that includes the hydrocarbon fluid sample, a solvent that dissolves asphaltenes and a precipitant that precipitates asphaltenes; ii) using microfluidic processes that result in precipitation of asphaltenes from the mixture resulting from i); iii) performing microfluidic filtering operations that remove precipitated asphaltenes resulting from ii) and passes permeate; and iv) performing optical spectroscopy on the permeate resulting from iii). The operations of i)-iv) can be repeated over iterations that vary the amount of solvent relative to the precipitant in the mixture. These iterations can cause varying fractional precipitation of asphaltenes in each given iteration.

Automated method and apparatus to characterize solubility of asphaltenes of a hydrocarbon fluid sample utilizing microfluidics

A test method and test apparatus is provided that employs a microfluidic device to characterize properties of a fluid. The microfluidic device has a first inlet port, an outlet port, and a microchannel as part of a fluid path between the first inlet port and the outlet port. While generating a flow of the fluid through the microchannel of the microfluidic device, fluid pressure at the first inlet port of the microfluidic device is measured and recorded in conjunction with varying the controlled temperature of the microchannel of the microfluidic device to characterize the properties of the fluid that flows through the microchannel of the microfluidic device. The properties of the fluid can relate to the clathrate hydrate formation condition of the fluid at the pressure of the flow through the microchannel of the microfluidic device.

Method and apparatus for characterizing clathrate hydrate formation conditions employing microfluidic device

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Edmonton, Canada

Farshid Mostowfi