Abstract: A method and system for performing a pressure test. The method may include inserting a formation testing tool into a wellbore to a first location within the wellbore based at least in part on a figure of merit. The formation testing tool may include at least one probe, a pump disposed within the formation testing tool and connect to the at least one probe by at least one probe channel and at least one fluid passageway, and at least one stabilizer disposed on the formation testing tool. The method may further include activating the at least one stabilizer, wherein the at least one stabilizer is activated into a surface of the wellbore and performing the pressure test and determining at least one formation property from the pressure test.

Abstract: A system and method for a fluid sampling tool. The fluid sampling tool may include a probe section. The probe section may include one or more probes, one or more stabilizers, and a housing that houses a bi directional piston pump. The method may include disposing a fluid sampling tool into a wellbore at a first depth, pressing the one or more probes into a surface of the wellbore, drawing a reservoir fluid from the wellbore through the one or more probes, placing the reservoir fluid into the housing, isolating the housing from the one or more modules of the fluid sampling tool with one or more shut in valves, depressurizing the housing with the bi directional piston pump, and measuring the asphaltene precipitation of the reservoir fluid within the housing.

Abstract: A method includes receiving first material property data for a first material in one or more second materials, detecting material sensor data from at least one sensor, and applying an inverse model and a forward model to the first material property data to provide, at least in part, synthetic sensor measurement data for the one or more second materials.

Abstract: A method and system for determining fluid contamination. The method may comprise monitoring a fluid sample, wherein the fluid sample comprises a reservoir fluid contaminated with a well fluid, and obtaining input parameters, wherein the input parameters comprise fluid properties obtained from measurement of the fluid sample and mud filtrate composition. The method may further comprise representing a mud composition as a Gaussian distribution, selecting a plurality of input data during a pumpout, determining calculated fluid properties of the reservoir fluid using an equation of state filtrate analysis, and further obtaining updated values of iterative parameters for use in a mole fraction distribution function.

Abstract: A coating system for coating, with a surface coating process, an interior surface of a housing defining an interior volume, having: a first closure and a second closure to sealingly engage with the housing; one or more first flow lines and second flow lines fluidically coupled to the first and second closure, respectively; a pressurized cell comprising a pressurized gas comprising at least one reactant and at a pressure of greater than a pressure within the housing, wherein the pressurized cell is fluidically coupled to a pressurized cell line comprising one of the first flow lines or second flow lines; and a controller in electronic communication with the pressurized cell and configured to control injection of a pulse of the pressurized gas into a flow of inert gas in the pressurized cell line, whereby the pulse is introduced into the interior volume, coating the interior surface with a coating layer.

Abstract: A coating system for coating an interior surface of a housing comprising: first and second closures engaging first and second ends, respectively, of the housing to provide an enclosed volume; first and second flow lines coupled to the first and second closures, respectively, the first flow line and/or the second flow line connected to an inert gas source; a reactant gas source(s) comprising a reactant gas and coupled to the first and/or second flow line; and a controller in electronic communication with the reactant gas and inert gas sources, and configured to control flow of inert gas into the enclosed volume, and counter current injection of reactant gas from the reactant gas source(s) into the enclosed volume whereby introduction of pulse(s) of the reactant gas into the enclosed volume are separated by introduction of inert gas into the enclosed volume, and coating layer(s) are deposited on the interior surface.

Abstract: Aspects of the subject technology relate to systems and methods for configuring links or switches that connect analog circuit elements. These analog circuit elements may be connected to a plurality of sensors that may sense different types of data. For example, these sensors may sense acoustic data, electromagnetic (EM) data, temperature, pressure, and possibly other metrics that may be located in a wellbore of an oil or gas well. These analog circuits may be configured as needed (e.g., on-the-fly) to perform optimized types of computations that may include the solving of differential equations. Examples of analog circuits that may be incorporated into a sensing system include yet are not limited to operational amplifier circuits or memcomputing devices, other components, or combinations thereof. Configured analog circuits may be coupled to digital electronics that perform other functions.

Abstract: The disclosure presents processes to determine a first formation fluid-second formation fluid boundary from one side of the boundary utilizing a formation tester tool. For example, the formation tester can be utilized in a borehole to determine an engagement point with a subterranean formation and determine one or more, or a combination of, injectable fluids to inject into the subterranean formation. Sensors coupled to the formation tester can measure the rebound pressure of the injected fluids. In some aspects, the fluid density of the collected fluid can be measured. The measured pressure changes and other collected data, can be utilized to determine a first formation fluid-second formation fluid boundary parameter. Other characteristic parameters can also be determined such as wettability parameters, porosity parameters, and capillary effects parameters. The formation tester can collect a core sample and an analyzation of the core sample can be utilized to determine the characteristic parameters.

Abstract: A method and system for identifying a fluid sample. The method may comprise disposing a fluid sampling tool into a wellbore. The fluid sampling tool may comprise at least one probe configured to fluidly connect the fluid sampling tool to a formation in the wellbore and at least one passageway that passes through the at least one probe and into the fluid sampling tool. The method may further comprise drawing a wellbore fluid as a fluid sample through the at least one probe and through the at least one passageway, obtaining a fluid measurement of the fluid sample, comparing the fluid measurement to a plurality of fingerprints that populate a database, and identifying the fluid sample based at least in part on one of the plurality of fingerprints.

Abstract: A system for inspecting a tubular may comprise an electromagnetic (EM) logging tool and information handling system. The EM logging tool may further include a mandrel, one or more sensor pads attached to the mandrel by one or more extendable arms, and one or more partial saturation eddy current sensors disposed on each of the one or more sensor pads.

Abstract: Disclosed are methods, systems, and devices for measuring and otherwise processing core samples. In some embodiments, a method includes containing a core sample in a containment vessel including dynamically adjusting pressure within the containment vessel to maintain a phase of fluid within the core sample. Pressure is reduced within the containment vessel. During pressure or following reduction, one or more properties of the fluid in the core sample are measured.

Abstract: Layered coating applications for sensing telemetry are provided.

Abstract: A method includes receiving fluid property data of a fluid and receiving material property data for materials in the fluid. The method includes detecting material sensor data from at least one sensor and applying an inverse model and a forward model to the fluid property data and the material property data to provide at least in part synthetic spectral channel data for the materials.

Abstract: Methods and systems for implementing and utilizing radiometric characterization in combination with reference material characterization of an optical sensor to more accurately and efficiently measure material properties are disclosed. In some embodiments, a method for for optically measuring material properties includes an optical sensor being radiometrically characterized based on measured optical responses. A model is generated and includes model components of the optical sensor. A parameterized model is generated by fitting n variable parameters of the model components using the optical responses. The optical sensor is utilized to measure an optical response to a reference material and a re-parameterized model is generated by re-fitting m of the n variable parameters of the model components based, at least in part, on the measured optical response to the reference material, wherein m is less than n.

Abstract: A method comprises determining an adaptive fluid predictive model calibrated with a plurality of types of sensor data, wherein the plurality of types of sensor responses comprise a first type of sensor response associated with a synthetic parameter space and a second type of sensor response associated with a tool parameter space. The method comprises applying the adaptive fluid predictive model to one or more fluid samples from field measurements obtained from a tool deployed in a wellbore formed in a subterranean formation and determining a value of a fluid answer product prediction with the applied adaptive fluid predictive model. The method comprises facilitating a wellbore operation with the tool based on the value of the fluid answer product prediction.

Abstract: A method and a system for determining fluid contamination. The method may comprise monitoring a fluid sample, wherein the fluid sample comprises a reservoir fluid contaminated with a well fluid, and obtaining input parameters, wherein the input parameters comprise fluid properties obtained from measurement of the fluid sample and mud filtrate composition. The method may further comprise representing a mud composition as a Gaussian distribution, selecting a plurality of input data during a pumpout, determining calculated fluid properties of the reservoir fluid using an equation of state filtrate analysis, and further obtaining updated vales of iterative parameters for use in a mole fraction distribution function. The system may comprise a downhole fluid sampling tool operable to obtain fluid samples of a reservoir fluid contaminated with a well fluid while the downhole fluid sampling tool is disposed in a wellbore, and a processor.

Abstract: Encoding downhole data in nucleic acid molecules provides increased speed accuracy in the communication of downhole data to the surface. Nucleic acid molecules can be coded with downhole data using a telemetry module that comprises a microfluidic system to perform an encoding process that encodes carrier nucleic acid molecules with substitute sequences or segments at specific locations that comprise retrieved or acquired downhole data. The encoded carrier nucleic acid molecules are injected into a downhole fluid that is circulated to the surface. Once the encoded carrier nucleic acid molecules reach the surface, the information can be decoded and analyzed. Each carrier nucleic acid molecule may be preconfigured with a header. The header may comprise information that allows N for ease in coding and recombining downhole data.

Abstract: A method and system for performing a pressure test. The method may include inserting a formation testing tool into a wellbore to a first location within the wellbore based at least in part on a figure of merit. The formation testing tool may include at least one probe, a pump disposed within the formation testing tool and connect to the at least one probe by at least one probe channel and at least one fluid passageway, and at least one stabilizer disposed on the formation testing tool. The method may further include activating the at least one stabilizer, wherein the at least one stabilizer is activated into a surface of the wellbore and performing the pressure test and determining at least one formation property from the pressure test.

Abstract: A method and a system for measuring downhole fluid properties. The downhole fluid sampling tool may comprise at least one probe and at least one passageway that passes through the at least one probe and into the downhole sampling tool. The method may comprise drawing a wellbore fluid through the at least one probe and through the at least one passageway, obtaining a first channel measurement of the wellbore fluid, obtaining at least a second channel measurement, clustering channel data from a plurality of channel measurements comprising the first channel measurement and the at least second channel measurement, and measuring a phase through a plurality of channels. The method may further comprise separating a plurality of phase signals based on the phase measured through the plurality of channels, labeling the wellbore fluid, assigning the plurality of phase signals to specific phases of a multi-phase fluid, and estimating a fluid property.

Abstract: A downhole PVT tool for performing in-situ formation fluid phase behavior characterizations in a wellbore using pressure, volume, and temperature (PVT) measurements of the formation fluid while continuing to pump the formation fluids. The disclosed downhole PVT tool includes an intake mandrel and utilizes two individual pumps to split the formation fluid to perform PVT measurements during the fluid pump out. The downhole PVT tool, two-pump configuration permits a first pump to be used to pump formation fluid along a first flowpath and a second pump to be used to pump formation fluid along a second flowpath, with one or more sensors deployed along one of the flowpaths to perform fluid and/or gas phase behavior measurements to determine one or more properties of the formation fluid in-situ. The first pump may be utilized in the phase behavior analysis while the second pump simultaneously continues flow-through pumping of the formation fluid.