Schlumberger Technology Corporation

Services Petroliers Schlumberger

Schlumberger Holdings Limited

Vinay K Mishra

Hadrien Dumont

Oliver Clinton Mullins

Youxiang Zuo

German Garcia

Li Chen

Andrew Emil Pomerantz

Christopher Albert Babin

Christopher Harrison

Cosan Ayan

Thomas Pfeiffer

Abhishek Agarwal

Matthew T Sullivan

Beatriz E Barbosa

Jerimiah Forsythe

Jesus Alberto Canas

Soraya S Betancourt Pocaterra

Adriaan Gisolf

Kang Wang

Chengli Dong

Denise E Freed

Michael O'Keefe

Shu Pan

Yi Chen

Anish Kumar

Vladislav Achourov

Armin Kauerauf

Daniel M Tetzlaff

Dariusz Strapoc

Julian Youxiang Zuo

Ivan Fornasier

Joseph Carl Fiduk

Soraya S Betancourt-Pocaterra

The disclosure provides for a method for sampling fluid from a subterranean formation that is intersected by a wellbore. The method includes performing an initial draw-down at a target interval in the wellbore to pump fluid from the subterranean formation with a 3D radial probe. The method includes isolating the target interval of the wellbore with a packer and providing a residence time within a dead volume of the packer to allow fluid therein to separate into hydrocarbon and water phases. The method includes pumping a sample of the hydrocarbon into a sample chamber while pumping a remainder of the fluid into the wellbore, and testing the sample to determine a hydrocarbon content of the sample.

Downhole segregation for wireline formation fluid sampling

Methods for obtaining in-situ, multi-temperature measurements of fluid properties, such as saturation pressure and asphaltene onset pressure include obtaining a sample of formation fluid using a downhole acquisition tool positioned in a wellbore in a geological formation. The downhole acquisition tool may be stationed at a first depth in the wellbore that has an ambient first temperature. While stationed at the first depth, the downhole acquisition tool may test a first fluid property of the sample to obtain a first measurement point at approximately the first temperature. The downhole acquisition tool may be moved to a subsequent station at a new depth with an ambient second temperature, and another measurement point obtained at approximately the second temperature. From the measurement points, a temperature-dependent relationship of the first fluid property of the first formation fluid may be determined.

Methods for in-situ multi-temperature measurements using downhole acquisition tool

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

Apparatus and methods for performing downhole testing. Example apparatus include a downhole tool string for conveying within a wellbore, the downhole tool string comprising an anchor device, a testing device, and a linear or rotary actuator. The anchor device maintains a portion of the downhole tool string in a predetermined position within the wellbore. The testing device is operable to receive a downhole sample from or test a subterranean formation surrounding the wellbore. The linear actuator is connected between the anchor device and testing device, and moves the testing device relative to the anchor device.

Downhole configurable testing apparatus and methods

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

The present disclosure relates to methods and apparatus for determining a gas-oil ratio based on downhole fluid analysis measurements and calibrated gas-oil ratio parameters. According to certain embodiments, the parameters for calculating the gas-oil ratio may be calibrated using historical data from the reservoir. For example, previously determined gas-oil ratios may be employed to calibrate the parameters to the reservoir. The calibrated parameters may then be employed during sampling operations to determine the gas-oil ratio.

Fluid analysis methods and apparatus for determining gas-oil ratio

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

Various implementations directed to analyzing a reservoir using fluid analysis are provided. In one implementation, a method may include determining mud gas logging (MGL) data based on drilling mud associated with a wellbore traversing a reservoir of interest. The method may also include determining first downhole fluid analysis (DFA) data based on a first reservoir fluid sample obtained at a first measurement station in the wellbore. The method may further include determining predicted DFA data for the wellbore based on the first DFA data. The method may additionally include determining second DFA data based on a second reservoir fluid sample obtained at a second measurement station in the wellbore. The method may further include analyzing the reservoir based on a comparison of the MGL data and a comparison of the second DFA data to the predicted DFA data.

Analyzing reservoir using fluid analysis

Various implementations described herein are directed to a method for assessing risks of compartmentalization. In one implementation, the method may include receiving seismic data for a formation of interest; identifying areas in the formation having a dip angle greater than about 30 degrees; performing a plurality of downhole fluid analysis (DFA) within a wellbore around the formation having the dip angle greater than about 30 degrees to identify areas experiencing mass density inversion; and determining the areas experiencing mass density inversion by DFA as having one or more risks of compartmentalization.

Assessing risks of compartmentalization

The present disclosure relates to systems and methods for determining an integrity of a sample chamber. In certain embodiments, formation fluid is collected from a subterranean formation within a sample chamber disposed in a downhole tool, the downhole tool is withdrawn from a wellbore, an estimated surface pressure of the collected formation fluid is determined, the estimated surface pressure of the collected formation fluid is compared with an actual surface pressure of the sample chamber, and the integrity of the sample chamber is determined based on the comparison of the estimated surface pressure and the actual surface pressure.

Systems and methods for sample characterization

Fluid analysis measurements may be performed during withdrawal of a downhole tool to the surface. Fluid may be collected within a fluid analysis system of the downhole tool and the collected fluid may be exposed to the wellbore pressure during withdrawal of the downhole tool. Measurements for the collected fluid, such as optical density, the gas oil ratio, fluid density, fluid viscosity, fluorescence, temperature, and pressure, among other, may be recorded continuously or at intervals as the downhole tool is brought to the surface. The measurements may be employed to determine properties of the collected fluid, such as the saturation pressure and the asphaltene onset pressure.

Downhole fluid analysis methods

An improved method that performs downhole fluid analysis of the fluid properties of a reservoir of interest and that characterizes the reservoir of interest based upon such downhole fluid analysis.

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Katy, TX, United States of America

Vinay K Mishra