Schlumberger Technology Corporation

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Services Petroliers Schlumberger

Cosan Ayan

Adriaan Gisolf

Oliver Clinton Mullins

Youxiang Zuo

Peter S Hegeman

Ricardo Vasques

Hadrien Dumont

Raghu Ramamoorthy

Chetankumar Natwarlal Desai

Terizhandur S Ramakrishnan

Christopher Harrison

Matthew T Sullivan

Nathan Mathew Landsiedel

Fikri John Kuchuk

Elizabeth Jennings Smythe

Andrew John Carnegie

Francois Xavier Dubost

Thomas J Neville

Michael Mallari Toribio

Ryan Sangjun Lee

Vinay K Mishra

Beatriz E Barbosa

Morten Kristensen

Kenneth Moelhoff

Julian J Pop

Pierre-Yves Corre

Christopher Del Campo

Kang Wang

Andrew Emil Pomerantz

Bhavani Raghuraman

Ronald E G Van Hal

Soraya Sofia Betancourt

Anthony Goodwin

Nicolas Adur

Arne Richard Pedersen

Antonio Castilho

Gustavo Andreolli Ribeiro

Tsutomu Yamate

Lei Jiang

Wael Abdallah

Sylvain Bedouet

Anthony R H Goodwin

Chanh Cao Minh

Ashers Partouche

Nikita Chugunov

Raj Banerjee

Michael O'Keefe

Hua Chen

Omer M Gurpinar

Hua Yu

Thomas Pfeiffer

Michael Hayward Hodder

Christopher Albert Babin

Sylvain Wlodarczyk

Li Chen

Shu Pan

German Garcia

Florent D'Halluin

Younes Jalali

Moin Muhammad

Yi Chen

Ram Sunder Kalyanaraman

Kamal Kader

Anish Kumar

Vincenzo De Gennaro

Vladislav Achourov

Abhishek Agarwal

Olivier Marché

Richard Jackson

Claude Signer

Dingan Zhang

Armin Kauerauf

Ilaria De Santo

Bei Gao

Daniel M Tetzlaff

Juan Miguel La Rotta Marin

Soraya S Betancourt Pocaterra

Jerimiah Forsythe

Jesus Alberto Canas

Koksal Cig

George Christopher Tevis

David C Bradley

Andrew Charles Baker

Wicher Wichers

Peter Weinheber

Yifu Zhu

Phillip Rabbito

Ryota Tonoue

Tomas Primitivo Bustos Cruz

Yannick Guyomar

A method that includes lowering a formation testing tool into a wellbore intersecting a subterranean formation. The formation testing tool comprises an expandable member. The method also includes performing a pressuremeter test (PMT) by expanding the expandable member.

System and method for evaluating static elastic modulus of subterranean formation

Embodiments of the disclosure can include systems, methods, and devices for determining saturation pressure of an uncontaminated fluid. A technique facilitates fluid analysis in situ at a downhole location. Downhole saturation pressure measurements and downhole OBM filtrate contamination of a contaminated fluid may be obtained and a relationship may be determined between the saturation pressure measurements and OBM filtrate contamination. The relationship may be extrapolated to zero OBM filtrate contamination to determine the saturation pressure of the uncontaminated fluid. According to an embodiment, a sample of oil is obtained at the downhole location from oil in a reservoir. A downhole sampling system is used to determine whether a sample has contamination and other selected characteristics of the sample. The data obtained may be processed to provide a formation volume factor of the oil.

Methods and systems for estimation of oil formation volume factor

Embodiments of the disclosure can include systems, methods, and devices for determining saturation pressure of an uncontaminated fluid. Downhole saturation pressure measurements and downhole OBM filtrate contamination of a contaminated fluid may be obtained and a relationship may be determined between the saturation pressure measurements and OBM filtrate contamination. The relationship may be extrapolated to zero OBM filtrate contamination to determine the saturation pressure of the uncontaminated fluid. In some embodiments, OBM filtrate contamination may be determined from downhole saturation pressure measurements during pumpout of a fluid.

Methods and systems for correction of oil-based mud filtrate contamination on saturation pressure

A methodology that performs fluid sampling within a wellbore traversing a reservoir and fluid analysis on the fluid sample(s) to determine properties (including asphaltene concentration) of the fluid sample(s). At least one model is used to predict asphaltene concentration as a function of location in the reservoir. The predicted asphaltene concentrations are compared with corresponding concentrations measured by the fluid analysis to identify if the asphaltene of the fluid sample(s) corresponds to a particular asphaltene type (e.g., asphaltene clusters common in heavy oil). If so, a viscosity model is used to derive viscosity of the reservoir fluids as a function of location in the reservoir. The viscosity model allows for gradients in the viscosity of the reservoir fluids as a function of depth. The results of the viscosity model (and/or parts thereof) can be used in reservoir understanding workflows and in reservoir simulation.

Method for characterization of hydrocarbon reservoirs

A downhole tool designed to be disposed in a borehole of a subterranean formation that includes a probe used to interface with the subterranean formation in order to sample fluid from or to inject fluid into the subterranean formation. The downhole tool also includes a sample flowline fluidly coupled to the probe and used to direct fluid through the downhole tool. The downhole tool further includes at least two volume chambers. These volume chambers each include a first side fluidly coupled to the sample flowline, a second side fluidly coupled to the guard flowline, and a piston separating the first side from the second side. The downhole tool is able to control a flow of fluid from a high pressure environment to a low pressure environment via the at least two volume chambers, the sample flowline, and the guard flowline.

System and method for controlled pumping in a downhole sampling tool

Apparatus and methods for obtaining initial settings of station-specific parameters descriptive of wellbore/formation properties specific to downhole pressure test stations, and obtaining initial settings of station-shared parameters descriptive of petrophysical properties of petrophysically unique formation zones. A pressure transient model of the zones is obtained by regression utilizing the pressure data of each station and the initial settings of the station-specific and station-shared parameters. The regression analytically determines a model value of at least one of the station-specific parameters and the station-shared parameters.

Interpretation of pressure test data

A method includes receiving first fluid property data from a first location in a hydrocarbon reservoir and receiving second fluid property data from a second location in the hydrocarbon reservoir. The method includes performing a plurality of realizations of models of the hydrocarbon reservoir according to a respective plurality of one or more plausible dynamic processes to generate one or more respective modeled fluid properties. The method includes selecting the one or more plausible dynamic processes based at least in part on a relationship between the first fluid property data, the second fluid property data, and the modeled fluid properties obtained from the realizations to identify potential disequilibrium in the hydrocarbon reservoir.

Reservoir fluid geodynamic system and method for reservoir characterization and modeling

A downhole tool designed to be disposed in a borehole of a subterranean formation is provided. The downhole tool includes a probe used to interface with the subterranean formation in order to sample fluid from or to inject fluid into the subterranean formation. The downhole tool also includes a sample flowline fluidly coupled to the probe and used to direct fluid through the downhole tool. The downhole tool further includes at least two volume chambers. These volume chambers each include a first side fluidly coupled to the sample flowline, a second side fluidly coupled to the guard flowline, and a piston separating the first side from the second side. The downhole tool is able to control a flow of fluid from a high pressure environment to a low pressure environment via the at least two volume chambers, the sample flowline, and the guard flowline.

A formation sampling method includes disposing a downhole tool comprising a packer and an expandable probe within a wellbore. The method also includes performing pressure transient testing by setting the expandable packer and the probe to engage a wall of the wellbore and measuring a pressure response at the expandable packer and the probe while withdrawing formation fluid into the downhole tool through the expandable packer. The method further includes monitoring a contamination level of the formation fluid during the pressure transient testing, and performing formation sampling with the probe in response to determining that the monitored contamination level meets a predetermined threshold.

Formation sampling methods and systems

Systems, methods, and media for processing formation pressure test data are provided. The method includes determining using a processor, a plurality of regressions for measurements of the formation pressure test data, and determining that two or more of the plurality of regressions represent a fluid code. The method also includes combining the two or more of the plurality of regressions representing the fluid code to generate a first fluid-type regression, and combining two or more other ones of the plurality of regressions representing a second fluid code to generate a second fluid-type regression. The method further includes determining that the first fluid-type regression and the second fluid-type regression are in a first hydraulic zone, and calculating a location of a boundary between the first fluid-type regression and the second fluid-type regression by extrapolating the first and second fluid-type regressions to a point of intersection therebetween.

Automatic fluid coding and hydraulic zone determination

An apparatus is operated to obtain a model predicting data associated with a theoretical sampling operation to be performed by a downhole sampling tool, including predicted water-cut and pressure data relative to time elapsed during the theoretical sampling operation. The model predicts the water-cut and pressure data based on estimated relative permeability and capillary pressure related to different constituents of fluid theoretically obtained from a subterranean formation by the downhole sampling tool during the theoretical sampling operation. An actual sampling operation is performed with the downhole sampling tool to actually obtain fluid and data associated with the actually obtained fluid, including actual water-cut and drawdown pressure data. The apparatus is then operated to update the model utilizing the actual data water-cut and drawdown pressure data, thus obtaining actual relative permeability and capillary pressure data.

Generating relative permeabilities and capillary pressures

Methods and systems for generating and utilizing a proxy model that generates a pumping parameter as a function of contamination. The pumping parameter is descriptive of a pumpout time or volume of fluid to be obtained from a formation by a downhole sampling tool positioned in a wellbore extending into the formation. The contamination is a percentage of the fluid obtained by the downhole sampling tool that is not native to the formation. The proxy model is based on a true model that utilizes true model input parameters that include the pumping parameter, formation parameters descriptive of the formation, and a filtrate parameter descriptive of a drilling fluid utilized to form the wellbore. The output of the true model is the contamination as a function of the pumping parameter. The proxy model utilizes proxy model input parameters each related to one or more of the true model input parameters.

Cleanup model parameterization, approximation, and sensitivity

A method for performing contamination monitoring through estimation wherein measured data for optical density, gas to oil ratio, mass density and composition of fluid components are used to obtain plotting data and the plotting data is extrapolated to obtain contamination levels.

Method and apparatus for consistent and robust fitting in oil based mud filtrate contamination monitoring from multiple downhole sensors

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Istanbul, Turkey

Cosan Ayan