Schlumberger Technology Corporation

Services Petroliers Schlumberger

Geoquest Systems B.v.

Joel Herve Le Calvez

Takashi Mizuno

Stewart Thomas Taylor

Colin Allan Wilson

Herve Denaclara

Nikita Chugunov

Ram Sunder Kalyanraman

William Brian Underhill

Hua Yu

Thomas Pfeiffer

Vassilis Varveropoulos

Hadrien Dumont

Hongren Gu

Lang Zhan

Eric Jeanson

Bertrand Claude Theuveny

Morten Kristensen

Simon Edmundson

Erwan Olliero

Leo Eisner

Ke Jiang

David Sobernheim

Keith Tushingham

Henri-Pierre Valero

Sebastien Roche

Claude Signer

Zhenning Bao

Guillaume Borrel

Walter Dee Grant

Wiwin Yuliana

Pierre Bettinelli

Leah Hogarth

Marie Lefranc

Changan Mike Du

Xu Zhang

Debbie Fullilove

Gorka Garcia Leiceaga

Bradley John Hay

Brian D Clark

Ali Yawar Sayed

Systems and methods may be used to process distributed acoustic sensing (DAS) data at oil and gas well sites to generate processed seismic data having metadata superimposed thereon, and then stream the combined processed seismic data and metadata to an off-site data processing center for further customized data processing. For example, a method may include receiving raw seismic data from a plurality of sensors disposed in a borehole extending into a subterranean formation from the oil and gas well site, processing the raw seismic data to generate a plurality of processed seismic data waveforms and metadata associated with the plurality of processed seismic data waveforms, combining the plurality of processed seismic data waveforms and the metadata associated with the plurality of processed seismic data waveforms to generate an output file, and streaming the output file to an off-site data processing center that is located remotely from the oil and gas well site.

Streaming of sub-titled data and processing model for fiber optics seismic operation

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

A method for optimizing a seismic survey design includes obtaining a well trajectory, determining a depth range and a measurement interval for the seismic survey, determining an optimal seismic shot position for each receiver within the depth range using an inverse function, determining one or more potential seismic shot configurations that each include a number of seismic shots, a location for each of the number of seismic shots, and a power of each of the seismic shots, determining an estimate of a data quality for each of the determined one or more potential seismic shot configurations using an objective function, and determining an optimum seismic survey design based on the determined estimated data quality for each of the determined one or more potential seismic shot configurations, wherein the estimated data quality for the optimum seismic survey design is greater than a predetermined minimum threshold.

Method of optimizing seismic acquisition

Systems and methods may be used to reconstruct particle velocity wavefields from coupling-calibrated fiber-optic data that subsequently enables physically valid construction of the particle velocity wavefields for a hybrid sensor array including both fiber-optic and particle motion sensors. These systems and methods may be used in a variety of borehole geophysical applications, such as structure and reservoir imaging, impedance inversion, attenuation tomography, micro-seismic fracture imaging, focal mechanism analysis, and so on. The systems and methods may also be used in other applications such as geothermal and COstorage monitoring.

True particle velocity wavefield processing in fiber optics - particle motion sensor hybrid array

Embodiments presented provide for a fully automated method of high-resolution interval velocity estimation for vertical seismic profile-type data.

Full automation of high-resolution interval velocity estimation for check-shot and other vertical seismic profile-type datasets

A method can include receiving seismic data responsive to stimulation of an anisotropic formation via a well disposed in the formation; receiving crosswell calibrated velocity model information that spans a depth range of the anisotropic formation; locating a microseismic event generated by the stimulation based at least in part on a portion of the received seismic data and based at least in part on the crosswell calibrated velocity model information; and rendering the located microseismic event to a display with respect to one or more dimensions of the anisotropic formation.

Crosswell microseismic system

A method for performing a fracturing operation in a subterranean formation of a field. The method includes obtaining, during the fracturing operation, distributed optical fiber data from a downhole sensor of a treatment well in the subterranean formation, and determining, based on the distributed optical fiber data, an active perforation location from a number of pre-determined perforation locations of the treatment well. The active perforation location is a location of fluid flow into the subterranean formation during the fracturing operation. The method further includes generating, based at least on the active perforation location, a fracturing model for the subterranean formation, and performing, based on the fracturing model, modeling of the fracturing operation to generate a modeling result.

Stimulation using fiber-derived information and fracturing modeling

A method can include receiving microseismic data of microseismic events as acquired by sensors during hydraulic fracturing of a geologic region; jointly calibrating sensor orientation of the sensors and a velocity model of the geologic region via an objective function and the microseismic data; and, based at least in part on the jointly calibrating, determining one or more locations of the one or more microseismic events.

Joint sensor orientation and velocity model calibration

A seismic system that includes a seismic source configured to generate a first seismic signal and a second seismic signal in a formation adjacent the seismic source. A first downhole sensing device disposed in a first borehole configured to detect the first seismic signal and the second seismic signal in the formation; and a first surface acquisition system is in communication with the first downhole sensing device. The first surface acquisition system is configured to: determine a first reference transit time based at least in part on detection of the first seismic signal by the first downhole sensing device; a first subsequent transit time based at least in part on detection of the second seismic signal by the first downhole sensing device; and whether a synchronization variation is expected to be present based at least in part on the first reference transit time and the first subsequent transit time.

Downhole seismic sensing synchronization systems and methods

A method includes varying a temperature of a treatment fluid. The treatment fluid is pumped into the first wellbore as part of a fluid diversion process or a fluid treatment process after the temperature of the treatment fluid is varied. A first downhole measurement is obtained in the first wellbore using a cable in the first wellbore or a first sensor coupled to the cable concurrently with or after the fluid diversion process or the fluid treatment process. An additional measurement is obtained concurrently with obtaining the first downhole measurement. The first downhole measurement and the additional measurement are combined or compared. A location where the treatment fluid is flowing through perforations in the first wellbore is determined based upon the combining or comparing the first downhole measurement and the additional measurement.

Fiber optic measurements to evaluate fluid flow

A method can include receiving an estimated spatial location of a three-component receiver in a borehole; receiving a plurality of spatial locations of sources of seismic energy; receiving incident angles for the three-component receiver at the estimated spatial location for the plurality of spatial locations of the sources of seismic energy; computing orientations for the three-component receiver based at least in part on the incident angles; minimizing an error function for the orientations; and, based at least in part on the minimizing, determining one or more deviation survey parameter values that specify at least a portion of a trajectory for the borehole.

Borehole trajectory via multi-component borehole seismic receiver

A method can include, during a treatment process, receiving vibration data acquired over a length of a fiber cable sensor disposed in a well that includes perforations; filtering the vibration data as to traveling waves to generate filtered data; analyzing the filtered data to generate fluid flow information; and adjusting the treatment process based at least in part on the fluid flow information.

Treatment based on fiber cable sensor data

Methods for in-situ reservoir investigation by borehole seismic methods are provided using receiver(s) and a downhole source. The downhole source may be a microseismic event, and may be located relative to the receiver(s) in any configuration. The downhole source may also be a controlled source that is positioned in a reverse vertical seismic profile (RVSP) geometry with respect to the receiver(s). The methods may involve locating the receiver(s) in a first well (which may have any orientation, including vertical or horizontal), and locating the source in a monitoring well (which may have any orientation, including vertical or horizontal), such that the source in the monitoring well is positioned at a greater depth in the formation than the receivers in the first well.

Methods for in-situ borehole seismic surveys using downhole sources

A method for evaluating portions of a reservoir includes classifying producing reservoir portions in the reservoir into multiple classifications based on production data associated with the producing reservoir portions. Each classification corresponds to a range of the production data. The method further includes generating a correlation between the classifications of the producing reservoir portions to a petrophysical property and elastic property of the subterranean formation, generating, based on the correlation, a spatial distribution function of reservoir quality to represent predicted classifications as a function of physical locations in the reservoir, and evaluating, using the spatial distribution function, a physical location in the reservoir for reservoir quality.

Predicting three dimensional distribution of reservoir production capacity

A microseismic method of determining the position of a downhole receiver () making use of received signals from events () at least two known locations using the equivalent of a Thales circle construction from two or more pairs of events.

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Houston, TX, United States of America

Joel Herve Le Calvez