Schlumberger Technology Corporation

Services Petroliers Schlumberger

Vladislav Achourov

Oliver Clinton Mullins

Thomas Pfeiffer

Youxiang Zuo

Adriaan Gisolf

Kang Wang

Andrew Emil Pomerantz

Cosan Ayan

Lalitha Venkataramanan

Ashers Partouche

Shahnawaz Hossain Molla

Hadrien Dumont

Vinay K Mishra

Shu Pan

Francois Xavier Dubost

Yi Chen

Anish Kumar

Simon Edmundson

Adriaan Gerard Gisolf

Armin Kauerauf

Daniel M Tetzlaff

Harish Baban Datir

Geir Thomas Glattetre

Pratik Halani

Jan Erik Tvedten

Soraya S Betancourt Pocaterra

Jerimiah Forsythe

Jesus Alberto Canas

Jean-Marc Donadille

Kathryn Briggs

Systems and methods presented herein generally relate to a formation testing tool configured to determine whether a formation fluid being tested is a bubble point fluid or a dew point fluid. For example, in certain embodiments, a method includes depressurizing a flowline of a formation testing tool. The flowline contains a formation fluid having a gas-to-oil ratio (GOR) within a predetermined GOR range. The method also includes determining, using a fluid analysis module of the formation testing tool, whether the formation fluid is a bubble point fluid or a dew point fluid by analyzing distribution of bubbles in the formation fluid that are caused by the depressurization of the flowline.

Systems and methods for differentiating bubble points from dew points

Methods and systems are provided for conducting formation analysis. Data from borehole logging tools is used to conduct a petrophysical analysis of the formation in order to determine (quantify) total porosity and formation matrix permittivity for an interval of the formation. Noninvaded zone water saturation and flushed zone water saturation for the interval of the formation is determined using a saturation model of the interval. The noninvaded zone water saturation is compared to the flushed zone water saturation, and the results of the comparison are used to determine that the interval of the formation contains movable hydrocarbon, immobile hydrocarbon or movable formation water.

Formation analysis incorporating identification of immovable and viscous hydrocarbons

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

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Tananger, Norway

Vladislav Achourov