Schlumberger Technology Corporation

Services Petroliers Schlumberger

Geoquest Systems B.v.

Sylvain Wlodarczyk

Florent D'Halluin

John C Rasmus

Shashi Menon

Ridvan Akkurt

Vikas Jain

David Furse Allen

John Paul Horkowitz

Valerian Guillot

Olivier Marché

Keith Pinto

Akshat Gupta

Cosan Ayan

Aria Abubakar

Francois Xavier Dubost

Vianney Bruned

Gennady Makarychev

Yannick Guyomar

Jean-Etienne Jacolin

Claire Bild

Methods and systems for augmented geological service characterization are described. An embodiment of a method includes generating a geological service characterization process in response to one or more geological service objectives and a geological service experience information set. Such a method may also include augmenting the geological service characterization process by machine learning in response to a training information set. Additionally, the method may include generating an augmented geological service characterization process in response to the determination information.

Augmented geological service characterization

A method, apparatus, and program product may evaluate a field by receiving a dataset including well measurements collected from a plurality of wells in a field, generating a synthetic dataset from the received dataset by computing a plurality of synthetic samples from the received dataset using a self-organized may (SOM), and propagating one or more models generated from the synthetic dataset to the plurality of wells.

Petrophysical field evaluation using self-organized map

A method for includes obtaining a well log comprising a sequence of measurements of a wellbore in a field, and generating change points in the well log based on the sequence of measurements. Each of the change points corresponds to a depth along the wellbore where a probability distribution of the well log changes. The method further includes generating a statistic for each of multiple intervals in the well log, where the intervals are defined by the plurality of change points, categorizing the intervals based on the statistic for each of the intervals to generate categorized intervals, and performing the operation based on the categorized intervals.

Electrofacies determination

A method for modelling saturation in a reservoir, comprising: obtaining capillary pressure data representing capillary pressure in the reservoir; obtaining permeability data representing permeability in the reservoir; determining a number of pore throats represented by the capillary pressure data; creating hyperbolic tangents based on the capillary pressure data equal in number to the number of pore throats; combining hyperbolic tangents to create a curve to fit the capillary pressure data and to define hyperbolic tangent parameters; combining at least one of the hyperbolic tangent parameters with the permeability data to define a saturation height function; modelling a saturation in the reservoir using the saturation height function; and displaying the saturation model based on the saturation height function. The determination of the number of pore throats may comprise creating an initial capillary pressure curve using a predetermined number of multiple linked hyperbolic tangents, determining a first derivative of the capillary pressure curve, and determining a number of local minima in the capillary pressure curve.

Oilfield reservoir saturation and permeability modeling

A system and method for correcting capillary pressure curves includes creating a capillary pressure curve using multiple linked hyperbolic tangents, determining a closure correction pressure cutoff of the capillary pressure curve, and correcting the capillary pressure curve. The correction may include normalizing the capillary pressure curve and extrapolating the capillary pressure curve.

Method and system for correcting a capillary pressure curve

Systems, media, and methods for determining relative geochemical data are provided. Measurement data may be received that is indicative of relative yields of a plurality of chemical components in a rock formation. First absolute yields of at least a portion of the plurality of chemical components in a presence of 100% of a first volumetric component in the rock formation may be determined. Second absolute yields of at least a portion of the plurality of chemical components in a presence of 100% of a second volumetric component in the rock formation may also be determined. A volume of the first volumetric component, a volume of the second volumetric component, and a sum of yields of the plurality of chemical components may be determined using the first and second absolute yields and the relative yields.

Systems and methods for determining relative geochemical data

Methods, systems, and computer-readable media for assessing porosity and water saturation cutoff values for hydrocarbon volume estimation are described. The techniques can include determining a plurality of water saturation and porosity value pairs for locations regularly-spaced along at least one borehole. The techniques can further include plotting the plurality of water saturation and porosity value pairs on a graph and representing a plurality of percentiles of the estimated maximal hydrocarbon volume on the graph. The techniques can also include causing the graph to be displayed to a user, such that the user can visually observe a combined sensitivity to porosity and water saturation cutoffs values. The user can take various actions based on the display.

Tool for cutoff value determination in net-pay computation workflow

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

A method having obtaining one or more porosity data of a subsurface of the Earth using a data acquisition tool; computing one or more permeability data from the porosity data using a transformation function; computing a first quantile regression function and a second quantile regression function of the one or more permeability data; producing a combined mean regression function of the one or more permeability data by summing the first quantile regression function and the second quantile regression function, wherein the first quantile regression function is multiplied by a first coefficient and the second quantile regression function is multiplied by a second coefficient; and using the combined mean regression function to predict a mean permeability of the subsurface.

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Saint Clement de Riviere, France

Sylvain Wlodarczyk