Schlumberger Technology Corporation

Adriaan Gisolf

Youxiang Zuo

Cosan Ayan

Ryan Sangjun Lee

Oliver Clinton Mullins

Nathan Mathew Landsiedel

Kang Wang

Chetankumar Natwarlal Desai

Julian J Pop

Kai Hsu

Christopher Harrison

Beatriz E Barbosa

Matthew T Sullivan

Stephen Parks

Hadrien Dumont

Elizabeth Jennings Smythe

Christopher Albert Babin

Michael Mallari Toribio

Peter S Hegeman

Ashers Partouche

Ronald E G Van Hal

Anthony Robert Holmes Goodwin

Li Chen

Jeffrey Crank

Kenneth Moelhoff

Pierre-Yves Corre

Lei Jiang

Thomas Pfeiffer

Daniel Palmer

Yong Chang

Shu Pan

Laurent Pirolli

Juan Miguel La Rotta Marin

Miroslav Slapal

Sylvain Bedouet

Vinay K Mishra

Hua Chen

Hua Yu

Tudor Ioan Palaghita

Francois Xavier Dubost

Yi Chen

Younes Jalali

Bertrand Claude Theuveny

Anthony Smits

Kamal Kader

Vladislav Achourov

Abhishek Agarwal

Richard Jackson

Adam Cygan

Ilaria De Santo

Adame Kante

Geir Thomas Glattetre

Jan Erik Tvedten

Ankit Agarwal

George Christopher Tevis

Jonathan Leonard

Kathryn Briggs

Ryota Tonoue

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

A method includes positioning a downhole acquisition tool in a wellbore in a geological formation. The method includes operating a pump module to gather information for a fluid outside of the downhole acquisition tool that enters the downhole acquisition tool from a first flowline, a second flowline, or both while the downhole acquisition tool is within the wellbore. Operating the pump module includes controlling a valve assembly to a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline fluidly coupled to a first pump module. Operating the pump module includes controlling a valve assembly to a second valve configuration that enables the fluid to flow into the downhole tool via the second flowline fluidly coupled to a second pump module, and selectively using a turnaround module or a crossover portion disposed between the first flowline and the second flowline to permit discharging the fluid from one flowline to the other flowline by actuating a valve associated with the turnaround module when the first pump module or the second pump module is not in use.

Terminal modules for downhole formation testing tools

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 method can include flowing fluid from a formation from an inlet of a tool to an annulus; flowing spacer fluid from a conduit to the annulus; flowing the fluid and the spacer fluid in the annulus to a station; and collecting the fluid.

Geologic formation characterization via fluid separation

Embodiments of the disclosure can include systems and methods for formation fluid sampling. In one embodiment, a method can include monitoring a relationship between a first characteristic of a formation fluid extracted from a formation and a second characteristic of the formation fluid extracted from the formation, determining, based at least in part on the monitoring, that a linear trend is exhibited by the relationship between the first characteristic of the formation fluid extracted from the formation and the second characteristic of the formation fluid extracted from the formation, and determining a reservoir fluid breakthrough based at least in part on the identification of the linear trend, wherein the reservoir fluid breakthrough is indicative of virgin reservoir fluid entering a sampling tool.

Systems and methods for formation fluid sampling

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

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 and an apparatus for characterizing a fluid provide for flowing a sample fluid through a microfluidic flow line and subsequently flushing the flowline with flushing fluid alone or together with heating and/or exposure to a pulsating electromagnetic field. A tracer fluid is injected and tracked in a microfluidic line based on known properties of the tracer fluid.

Flushing microfluidic sensor systems

Disclosed are methods and apparatus pertaining to processing in-situ, real-time data associated with fluid obtained by a downhole sampling tool. The processing includes generating a population of values for &#x108;, where each value of &#x108; is an estimated value of a fluid property for native formation fluid within the obtained fluid. The obtained data is iteratively fit to a predetermined model in linear space. The model relates the fluid property to pumpout volume or time. Each iterative fitting utilizes a different one of the values for &#x108;. A value &#x108;* is identified as the one of the values &#x108; that minimizes model fit error in linear space based on the iterative fitting. Selected values &#x108; that are near &#x108;* are then assessed to determine which one has a minimum integral error of nonlinearity in logarithmic space.

Estimating contamination during focused sampling

A method includes operating a downhole acquisition tool in a wellbore in a geological formation. The wellbore or the geological formation, or both, contains a fluid that includes a native reservoir fluid of the geological formation and a contaminant. The method also includes receiving a portion of the fluid into the downhole acquisition tool, obtaining a measured resistivity, a measured conductivity, or both of the portion of the fluid using the downhole acquisition tool, and using a processor of the downhole acquisition tool to obtain a temperature-corrected resistivity, a temperature-corrected conductivity, or both based on a downhole temperature of the portion of the fluid and the measured resistivity, the measured conductivity, or both.

Downhole filtrate contamination monitoring with corrected resistivity or conductivity

Implementations of the present disclosure relate to apparatuses, systems, and methods for determining when a well cleanup process has established developed flow and then extrapolating out modeled fluid parameter values to determine parameter values for a formation fluid. The model fluid parameter values may be modeled using a power law function having a specified exponent value.

Flow regime identification with filtrate contamination monitoring

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

Growing community of inventors

Houston, TX, United States of America

Adriaan Gisolf