Schlumberger Technology Corporation

Schlumberger Canada Limited

Services Petroliers Schlumberger

Schlumberger Holdings Limited

Prad Research and Development Limited

John Ratulowski

Ahmed Hammami

Farshid Mostowfi

Shahnawaz Hossain Molla

Oliver Clinton Mullins

Denis Klemin

Mark Andersen

Mohammed I Zougari

Tsutomu Yamate

Robert J Schroeder

Christopher Harrison

Kentaro Indo

Peter S Hegeman

Francois M Auzerais

Matthew T Sullivan

Stephane Vannuffelen

Andrew L Kurkjian

Chengli Dong

Denise E Freed

Toru Terabayashi

John A Kerr

Soraya Sofia Betancourt

Abdel Kharrat

Elizabeth Jennings Smythe

Jeffrey A Tarvin

Alexander Nadeev

Omer M Gurpinar

Vincent Joseph Sieben

Oleg Dinariev

Shawn David Taylor

Sergey Sergeevich Safonov

John Allan Nighswander

Scott Jacobs

Shunsuke Fukagawa

Dmitry Anatolievich Koroteev

Moin Muhammad

Geza Horvath Szabo

Evgeny Ivanov

Nikolay Vyacheslavovich Evseev

Dmitry Eskin

Anil Singh

Erwan Olliero

Laurent P Prouvost

John Meier

Terry Sopkow

Julian Youxiang Zuo

Jinglin Gao

Kunal Karan

Raymond G Kennedy

Alexander Nikolaevich Nadeev

A microfluidic apparatus includes a substrate defining a microchannel having inlet and an outlet defining a length of the microchannel. The microchannel has a main channel extending from the inlet to the outlet, and a plurality of side cavities extending from the main channel. The cavities are in fluid communication with the main channel. A method includes introducing a sample into the microchannel through the inlet to fill the entire microchannel, and then introducing a solvent into the microchannel through the inlet at a controlled flow rate and inlet pressure. A developed solvent front then moves along the main channel from the inlet to the outlet while displacing the sample in the main channel. Images of the microchannel are acquired as the front moves, and a miscibility condition is determined based on the images.

Microfluidic technique for detection of multi-contact miscibility

A method for performing a simulation of a field having a subterranean formation is described. The method includes obtaining phase behavior data of subterranean fluids of the field, generating an equation of state (EOS) model of the fluids based on the phase behavior data, generating a Helmholtz free energy model that reproduces predictions of the EOS model over a pre-determined pressure and temperature range, and performing the simulation of the field using the Helmholtz free energy model. The method may further include reducing the EOS model to a reduced EOS model having a reduced number of components to represent the EOS model over a pre-determined pressure and temperature range, generating the Helmholtz free energy model based on the reduced EOS model, and obtaining and using phase behavior data of injection fluids used. A computer system data.

Construction of digital representation of complex compositional fluids

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 method for performing simulation of a field having a subterranean formation, including: obtaining a three-dimensional (3D) porous solid image of a core sample, the core sample representing a portion of the field; generating a digital rock model from the solid image, the digital rock model describing a physical pore structure in the core sample; obtaining phase behavior data of fluids of the field; generating a digital fluid model of the fluids based on the phase behavior data, the digital fluid model describing a physical property of the fluid; performing, on a computer system and based on the digital rock model and the digital fluid model, simulations of the field by varying an input parameter for the simulations; and analyzing an output parameter generated by the simulations to determine an effect of varying the input parameter on the output parameter.

Digital core sensitivity analysis

An apparatus (and method) for characterizing interfacial tension between a non-wetting phase fluid and a wetting phase fluid of a slug flow employs a capillary structure that is configured to contain a slug of the non-wetting phase fluid of the slug flow. The slug has a leading edge meniscus and a trailing edge meniscus, and the capillary structure has a venturi-like section. A pressure sensor is configured to measure differential pressure between first and second locations of the capillary structure. The first location is disposed upstream of the leading edge meniscus of the slug with the leading edge meniscus of the slug contained within the venturi-like section. The second location is disposed downstream of the trailing edge meniscus of the slug. Data processing means is configured to derive a measure of interfacial tension based upon the differential pressure measured by the pressure sensor and, optionally, geometry of the capillary structure.

Method and apparatus for characterizing interfacial tension between two immiscible or partially miscible fluids

A method for determining an asphaltene onset condition of a crude oil is provided. The method includes receiving a crude oil within a downhole tool inside a well and taking a first measurement of an optical property of the received crude oil. The method also includes lowering the pressure or temperature of the crude oil after taking the first measurement of the optical property to cause aggregation of asphaltenes in the crude oil, and then separating aggregated asphaltenes from the crude oil. Further, the method includes taking a second measurement of the optical property of the crude oil within the downhole tool after separating aggregated asphaltenes from the crude oil and determining an asphaltene onset condition of the crude oil through comparison of the first and second measurements of the optical property. Additional methods, systems, and devices are also disclosed.

Method and apparatus for measuring asphaltene onset conditions and yields of crude oils

Methods and systems to characterize a fluid in a reservoir to determine if the fluid is in one of equilibrium or non-equilibrium in terms of one of gravity, solvency power, entropy effect or some combination thereof. The method includes acquiring tool data at each depth for each fluid sample of at least two fluid samples wherein each fluid sample is at a different depth and communicating the tool data to a processor. Determining formation properties of each fluid sample to obtain formation property data and determining fluid properties for each fluid sample to obtain fluid property data. Selecting a mathematical model based on one of gravity, solvency power or entropy, in view of a fluid property, using one of tool data, formation property data, fluid property data, known fluid reservoir data or some combination thereof, to predict if the fluid is in an equilibrium distribution or a non-equilibrium distribution.

Using models for equilibrium distributions of asphaltenes in the prescence of GOR gradients to determine sampling procedures

A system for determining the phase envelope of a gas condensate includes a microfluidic device defining an entrance passageway, an exit passageway, and a microchannel in fluid communication with the passageways. The system includes an input sample bottle in fluid communication with the entrance passageway and a first pump associated with the input sample bottle for urging the gas condensate, in the input sample bottle, into the entrance passageway. The system further includes an output sample bottle in fluid communication with the exit passageway and a second pump associated with the output sample bottle for pressurizing the gas condensate, in the output sample bottle, into the exit passageway in opposition to the first pump. The system includes a temperature control device for controlling the temperature of the gas condensate in the microchannel. The first pump and the second pump operate to provide a desired pressure drop across the microchannel.

System and method for determining the phase envelope of a gas condensate

The present invention contemplates implementation of transitory downhole video imaging and/or spectral imaging for the characterization of formation fluid samples in situ, as well as during flow through production tubing, including subsea flow lines, for permanent and/or long term installations. The present invention contemplates various methods and apparatus that facilitate one-time or ongoing downhole fluid characterization by video analysis in real time. The methods and systems may be particularly well suited to permanent and periodic intervention-based operations.

Spectral imaging for downhole fluid characterization

A method of assuring the collection of reliable and quality fluid sample includes the steps of acquiring a fluid sample at a point of acquisition, analyzing physical and chemical properties of the fluid sample at the point of acquisition; recording the point of acquisition sample properties in an electronic database archive, analyzing physical and chemical properties of the fluid sample at a location remote from the point of acquisition, recording the remote location sample properties in the archive, validating the fluid sample through comparison of the point of acquisition sample properties and the remote location sample properties and recording the validated sample properties in the archive.

Fluids chain-of-custody

A technique includes providing a deposition measuring device having a deposition from a fluid sample on an interior surface of the device. The technique also includes operating the device with a solvent to produce a solvent solution that contains the deposition. The solvent solution is used to quantify at least one chemical compound that is present in the deposition.

Compositional characterization and quantification of solid deposits from hydrocarbon fluids

We disclose a method of measuring an emulsion or solids deposition in a fluid sample, comprising charging the sample to a Couette device; subjecting the sample in the Couette device to a pressure, a temperature, and a shear comparable to field conditions; changing at least one of the pressure, temperature, composition, or shear of the sample; and quantifying the type and amount of solids deposited on the interior walls of the Couette device. We also disclose Couette devices which can be used in the method.

Couette device and method to study solids deposition from flowing fluids

Growing community of inventors

Edmonton, Canada

John Ratulowski