Schlumberger Intellectual Property Department

Methods and systems are provided for detecting and mitigating stall of a downhole motor driven by flow of drilling fluid through the downhole motor, which employ a BHA that includes at least one first downhole sensor and at least one second downhole sensor operably disposed above the downhole motor. The methods and systems generate time-series first data representing measurements of the rotational speed of a collar disposed at the uphole end of the downhole motor or part of the BHA disposed above the downhole motor made by the at least one first downhole sensor over time as well as time-series second data representing measurements of the vibration of the BHA made by the at least one second downhole sensor over time. Stall of the downhole motor can be automatically detected by analysis of the time-series first data and the time-series second data. Upon detecting stall of the downhole motor, at least one action can be initiated to mitigate the stall of the downhole motor.

A method for determining a recalibration trigger for a downhole survey sensor includes obtaining historical calibration and recalibration data for a plurality of downhole survey sensors. The historical calibration data is evaluated to determine calibration changes for selected ones of the survey sensors. A probabilistic model is constructed from the determined calibration changes over a predetermined range of temperatures and benchmarked against at least one industry standard to estimate the recalibration trigger.

Systems and methods for direct arrival estimation for marine seismic data are provided. A computer-implemented method for estimating direct-arrival energy in seismic data acquired in a marine environment, the method including: executing, by one or more processors, operations on seismic data that contain up-going and down-going wavefields in which direct-arrival information is not properly or completely recorded, processing the seismic data using a computer-based wavefield-analysis technique to identify water-layer reverberation events within the up-going and down-going wavefields, leveraging, through computer-implemented analysis, stable relationships among water-layer reverberations, computing, by the processors, an estimated direct-arrival signal based on the identified relationships to compensate for missing or improperly recorded direct-arrival information, and producing, using the processors, a direct-arrival estimate configured for use in subsequent seismic-processing operations.

A first velocity model having a three-dimensional (3D) grid of voxels containing velocity values is processed with an eikonal solver to generate a reference travel-time model as a second 3D grid of voxels containing respective reference travel-time values. A candidate background model is initialized based on the first velocity model. A candidate travel-time model is generated from the candidate background model. The candidate travel-time model has a third 3D grid of voxels containing respective candidate travel-time values. The candidate background model is updated to minimize a measure of difference between respective candidate travel-time values of the candidate travel-time model and respective reference travel-time values of the reference travel-time model. The updated candidate model serves as a second velocity model of the subsurface region that is kinematically equivalent to the first velocity model.

A downhole tool for a drillstring that includes a mud motor (310) and a drill bit (304) can include sensor circuitry that acquires data characteristic of operation of the mud motor, wherein the mud motor is disposed on the drillstring between the downhole tool and the drill bit; and a telemetry interface for transmission of one or more of the data and data derived metrics.

A method for monitoring subsurface changes in a subsurface domain is disclosed. The method may include receiving ambient noise occurring in a subsurface domain, generating a plurality of time-space virtual shots by processing the ambient noise, modeling subsurface changes based on at least a portion of the plurality of time-space virtual shots, transforming the plurality of time-space virtual shots to a space-time representation, determining at least one difference between the transformed time-space virtual shots, and detecting the subsurface changes based on the at least one difference.

A high density carrier fluid for use in placing a gravel pack within a wellbore includes a modified starch, a magnesium oxide, and a nano-crystalline-cellulose having a median diameter of about 20 nanometers or less. The carrier fluid includes an aqueous base fluid and dissolved salts. Related methods are also disclosed.

Methods and systems for drilling a wellbore that traverses a subterranean formation employ a computational model that relates input data representing at least one drilling performance parameter (or change therein) at one or more drilling conditions to output data representing at least one petrophysical formation property. Data representing at least one drilling performance parameter (or change therein) at one or more drilling conditions while drilling is determined by sweeping wellbore pressure over a range of pressures and measuring and analyzing wellbore pressures and associated drilling performance parameters, and such data is used as input data to the computational model, which generates output data representing at least one petrophysical formation property associated with the input data. The data output by the model can be added to well log of formation properties, which can be used to set or adjust the direction of drilling.

A method including preparing a surface of a substrate, wherein the surface of the substrate includes a carbonous material, controlling, via a control system, a LIG subsystem to generate a LIG modified area of the substrate, modifying, via an electrochemical subsystem, the LIG modified area of the substrate to generate a sensing area comprising one or more types of nanoparticles, and performing, via a SERS subsystem, detection of a spectral signature of one or more PFAS compounds on the sensing area.

Thermal management systems and methods are provided for conditioning an indoor fluid being delivered to thermal zones of a building. A heat pump system circulates a heat transfer fluid between a first heat exchanger and a second heat exchanger. The first heat exchanger thermally connects the heat transfer fluid with a heat source, and the second heat exchanger is operable to condition the indoor fluid via the heat transfer fluid. A controller communicating with the heat pump system is configured to: receive, for each thermal zone, data indicative of a demand of the thermal zone for the indoor fluid; identify, based on the data, thermal zones satisfying a demand condition; calculate a demand factor of the building based on a number of the identified thermal zones satisfying the demand condition; and adjust an operating parameter of the heat pump system when the demand factor meets or exceeds a threshold value.