Schlumberger Technology Corporation

Services Petroliers Schlumberger

Thomas Pfeiffer

Oliver Clinton Mullins

Simon Edmundson

Kai Hsu

Youxiang Zuo

Andrew Emil Pomerantz

Ashers Partouche

Hadrien Dumont

Vinay K Mishra

Vladislav Achourov

Adriaan Gisolf

German Garcia

Jerimiah Forsythe

Soraya S Betancourt Pocaterra

Kang Wang

Christopher Harrison

Cosan Ayan

Denise E Freed

Stephen Parks

Shahnawaz Hossain Molla

Nikita Chugunov

Joel Herve Le Calvez

Ram Sunder Kalyanraman

Hua Yu

Li Chen

Vassilis Varveropoulos

John Allan Nighswander

Shu Pan

Sophie Nazik Godefroy

Eric Jeanson

Yi Chen

Bertrand Claude Theuveny

Farshid Mostowfi

Anish Kumar

Morten Kristensen

Adriaan Gerard Gisolf

Armin Kauerauf

Claude Signer

Erwan Olliero

Adam Cygan

Daniel M Tetzlaff

Henri-Pierre Valero

Ke Jiang

Adame Kante

Juan Miguel La Rotta Marin

Sebastien Roche

Guillaume Borrel

Jan Erik Tvedten

John Waggoner

Jesus Alberto Canas

Geir Thomas Glattetre

Pratik Halani

Zhenning Bao

Zulfiquar Ail Reza

Shunsuke Fukagawa

Kathryn Briggs

Wiwin Yuliana

Pierre Bettinelli

Marie Lefranc

Marie Emeline Cecile Lefranc

The present disclosure relates to a system that is operable to receive an execution plan and execute a control operation on one or more equipment based operations within the execution plan. The one or more operations may include a data capturing operation associated with a resource site. In one embodiment, the system may be operable to execute at least a first operation in response to a success variable of the data capturing operation indicating a successful execution of the data capturing operation. The first operation may include a quality control operation that is executed by comparing at least one characteristic of the captured data to an expected characteristic to generate quality state data. The quality state data may have one of an acceptable status and an undesirable status. In response to the quality state data indicating an acceptable status for the quality control operation, executing at least a second operation.

Autonomous operations in oil and gas fields

Embodiments present a method for fluid type identification from a downhole fluid analysis that uses machine learning techniques that are trained and derived from a computer model using pressure, temperature and downhole optical characteristics of sampled fluid.

Fluid type identification from downhole fluid analysis using machine learning techniques

This disclosure relates to a separating a fluid having multiple phases during formation testing. For example, certain embodiments of the present disclosure relate to receiving contaminated formation fluid on a first flow line and separating a contamination (e.g., mud filtrate) from the formation fluid by diverting the relatively heavier and/or denser fluid (e.g., the mud filtrate) downward through a second flow line and diverting the relatively lighter and/or less dense fluid upward through a third flow line. In some embodiments, the third flow line is generally oriented upwards at a height that may facilitate the separation of the heavier fluid from the relatively lighter fluid based on gravity and/or pumps.

System and method for fluid separation

Methods and downhole tools for operation within in a wellbore that extends into a subterranean formation. The operation includes simultaneously causing a change in a first parameter of fluid drawn into the downhole tool from the formation and determining a change in a second parameter of the fluid relative to the change in the first parameter. A third parameter of the fluid is determined based on the first and second parameter changes.

Determining asphaltene onset

An inflatable packer assembly configured to be conveyed within a wellbore. The inflatable packer assembly includes a mandrel having a flowline, a first packer ring slidably connected with the mandrel, a second packer ring fixedly connected with the mandrel, a latching mechanism fluidly connected with the flowline, and an inflatable packer fluidly connected with the flowline. The inflatable packer may be disposed around the mandrel and sealingly connected with the first and second packer rings. The inflatable packer may be operable to expand against a sidewall of the wellbore upon receiving a fluid from the flowline. The latching mechanism may be operable to limit movement of the first packer ring with respect to the mandrel, and permit the movement of the first packer ring with respect to the mandrel upon being actuated by the fluid from the flowline.

Inflatable downhole packer tool

A method of formation fluid sampling that includes setting a dual packer tool in a wellbore. The dual packer tool is used to isolate an interval between an upper packer and a lower packer. The method also includes drawing fluid from the interval with a lower inlet, until an oil fraction increases over a base line reading, and drawing oil from by pumping at a low rate with an upper inlet.

Method of minimizing immiscible fluid sample contamination

A downhole acquisition tool having a formation testing module is provided. The formation testing module includes a fluid chamber comprising a piston and configured to store a fluid and to receive a flowback fluid from a geological formation, wherein the fluid is substantially free of solids. Additionally, the formation testing tool has a first conduit fluidly coupled to the fluid chamber and extending from a flowback conduit and a first outlet of the formation testing module, wherein the flowback conduit is configured fluidly coupled to the geological formation. and configured to receive the flowback fluid from the geological formation, and wherein the first conduit is configured to receive the flowback fluid from the flowback conduit. Further, the formation testing module has a first flow control device positioned downstream from the fluid chamber, wherein the first flow control device is configured to control a flow of the fluid exiting the fluid chamber.

System and method for controlled flowback

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

Systems and methods for identifying a likelihood that a reservoir of a geological formation received a secondary charge of hydrocarbons of relatively very different thermal maturity of composition are provided. One method includes positioning a downhole acquisition tool in a wellbore in a geological formation and testing one or more fluid properties of the formation fluid. Data processing circuitry may identify whether a relationship of the one or more fluid properties exceeds a first threshold that indicates likely asphaltene instability. When this is the case, data processing circuitry may be used to model the geological formation using a realization scenario in which multiple charges of hydrocarbons of substantially different thermal maturity or substantially different composition, or both, filled a reservoir of the geological formation over geologic time.

Systems and methods for identifying two or more charges into reservoir using downhole fluid analysis

Fluid property modeling that employs a model that characterizes asphaltene concentration gradients is integrated into a reservoir modeling and simulation framework to allow for reservoir compartmentalization (the presence or absence of flow barrier in the reservoir) to be assessed more quickly and easily. Additionally, automated integration of the fluid property modeling into the reservoir modeling and simulation framework allows the compositional gradients produced by the fluid property modeler (particularly asphaltene concentration gradients) to be combined with other data, such as geologic data and other petrophysical data, which allows for more accurate assessment of reservoir compartmentalization.

Method and systems for reservoir modeling, evaluation and simulation

Growing community of inventors

Katy, TX, United States of America

Thomas Pfeiffer