Abstract: Described herein are systems and techniques for an improved method for determining and evaluating an impedance of an annulus associated with a casing of a wellbore. For example, aspects of the present disclosure relate to systems and techniques for performing two-dimensional (2D) and/or three-dimensional (3D) simulations (e.g., 2D and 3D numerical modeling) for predicting physical properties of a material or sample and determining calibration functions used to improve the efficiency and accuracy of the determined impedance results.

Abstract: A method and system for identifying scale. The method may include 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 formation fluid, as a fluid sample, through the at least one probe and through the at least one passageway, perturbing the formation fluid, and analyzing the fluid sample in the fluid sampling tool for one or more indications of scale.

Abstract: Described herein are systems and techniques for predicting sample characteristics in a wellbore. An example method can include determining a set of values of estimated characteristics of a sample in a wellbore; determining, via a proxy model, a predicted ultrasonic wave response corresponding to the set of values of the estimated characteristics of the sample; based on a comparison of the predicted ultrasonic wave response with a measured ultrasonic wave response associated with the sample, determining an error associated with the predicted ultrasonic wave response; determining whether the error associated with the predicted ultrasonic wave response is below a threshold; and determining whether to update the set of values of the estimated characteristics of the sample based on determining whether the error is below the threshold.

Abstract: Methods to identify fluid holdups during downhole fluid sampling operations includes obtaining, using a sampling tool positioned within a wellbore, one or more fluid measurements using at least one sensor having a first set of spatial resolution, obtaining one or more second fluid measurements having a second spatial resolution, calculating a first fluid ratio using the at least one sensor having the first set of spatial resolution measurements, calculating a second fluid ratio of the second fluid measurements using the at least one sensor having the second set of spatial resolution, wherein the second set of spatial resolution is lower than the first set of spatial resolution, and identifying fluid holdup within the sampling tool when the differences between the two fluid ratios are higher than a limit or a similarity of the two fluid ratios are lower than a limit.

Abstract: Wellbore equipment used in oil and gas operations can be negatively affected by corrosive fluids. Coatings can be applied to the equipment to help protect the equipment. A field test can be used at a wellsite to ensure the coating is effective. Due to the HSE risks of the corrosive fluids, a proxy fluid can be used instead. The proxy fluid can have similar chemical or physical properties and simulate the corrosive fluid that is anticipated to be present in the wellbore. The wellbore equipment that is coated can be sealed to create a containment area where an initial concentration of the proxy fluid is introduced into the containment area for a period of time. A final concentration of the proxy fluid can be measured after the period of time has elapsed. By calculating the percent change of the proxy fluid, the effectiveness of the coating can be determined.

Abstract: A device for monitoring deposition of a coating comprising a dielectric material during deposition of the coating. The device includes a parallel-plate capacitor having a first plate, and a second plate; a first lead electrically connected to the first plate; a second lead electrically connected to the second plate; and a power supply. The first plate and the second plate are parallel and separated by a spacing with a known spacing thickness. The first lead and the second lead can be electrically connected to positive and negative terminals of the power supply. The device is configured to register a capacitance when the first lead and the second lead are respectively connected to the positive and the negative terminals of the power supply and a dielectric material fills the spacing, and is configured to register no capacitance until the dielectric material fills the spacing.

Abstract: A method comprises receiving a measurement of a pressure in a subsurface formation at a number of depths in a wellbore formed in the subsurface formation across a sampling depth range of the subsurface formation to generate a number of pressure-depth measurement pairs. The method comprises partitioning the sampling depth range into a number of fluid depth ranges, wherein each of the number of fluid depth ranges comprises a range where a type of reservoir fluid is present in the subsurface formation. The method comprises determining a fluid gradient for the type of the reservoir fluid for each of the number of fluid depth ranges.

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: Surface tracking systems and methods for tracking a first wellbore relative to a non-geological target in a subterranean formation by determining characteristics of gravity anomalies related to the first wellbore and the non-geological target. The system includes a gravity sensor located at the Earth's surface and an information handling system operable to analyze the first and second gravity anomalies to determine a position and the trajectory of the first wellbore relative to the non-geological target. The systems and methods may also include the ability steer a trajectory of the first wellbore relative to the non-geological target.

Abstract: Improved systematic inversion methodology applied to formation testing data interpretation with spherical, radial and/or cylindrical flow models is disclosed. A method of determining a flow line parameter includes determining a diverse set of flow models and selecting at least one flow model from the diverse set of flow models representative, at least in part, of a formation tester tool, at least one formation, at least one fluid, and at least one flow of the at least one fluid. The method further includes lowering the formation testing tool into the at least one formation to intersect with the formation at least one formation and sealing a probe of the formation tester placed in fluid communication with the at least one formation. The method further includes initiating flow from the at least one formation and utilizing the at least one selected flow model to predict the flow line parameter.

Abstract: Systems and techniques are described for modeling borehole fluid flow using a dynamic pressure boundary. An example method can include calculating a radius of fluids and a radius of pressure associated with a borehole, the radius of pressure relating to a fluid flow; generating a first model, wherein a size of the first model is larger than the calculated radius of pressure; determining a dynamic pressure based on the first model; generating a second model, wherein a size of the second model is larger than the calculated radius of fluids; and modelling the borehole fluid flow based on the second model, wherein the dynamic pressure is used as a boundary condition of the second model.

Abstract: The subject disclosure relates to techniques for correcting logging depth of a well bore. A process of the disclosed technology can include receiving a first sensor measurement from a first sensor disposed in a wellbore, receiving a second sensor measurement from a second sensor disposed in the wellbore, wherein the first sensor and the second sensor are disposed on a wireline with a predetermined distance between the first sensor and the second sensor, generating a correlation function based on the first sensor measurement and the second measurement, and determining, based on the correlation function, whether the measurements indicate a perceived distance between the first sensor and the second sensor deviating from the predetermined distance.

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 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: Concepts for middleware in a web framework are presented. One example comprises defining a target object type configured to hold results of a middleware function. A first object for an application is received and a process of the middleware function is performed, using the first object, to generate a process result. Based on the process result, a second object of the target object type is generated, after which the second object is provided to the application.

Abstract: An optical element may be fabricated by applying foreign or attenuating material, for example, a copper material or a material that includes copper, to a silicon dioxide thin film to form a layer that exhibits extraordinary optical absorption in the infrared wavelength region of at or about 2500-4700 nanometers. The foreign material may comprise or include a transition metal. The optical element exhibits increased accuracy and sensitivity in the infrared wavelength region of at or about 2500-4700 nanometers. The at or about 2500-4700 nanometers absorption property of the optical element can be selectively tuned to any region within this at or about 2500-4700 nanometers wavelength region. The optical element may comprise multiple layers of varying thicknesses to further tune the optical element to one or more spectral bands. Such an optical element may be utilized in a formation fluid analysis tool or an eye protection device.

Abstract: A fluid sampling tool may include a fluid characterization device consisting of a densitometer, a viscometer, or a vibrating element, or a combination thereof and a polymer disposed in or around the fluid characterization device, wherein the polymer volume, density, or viscosity changes with an ionic stimulus. The fluid characterization device may be located within a bypass flow line of the sampling tool. A method of measuring pH and a method of monitoring at least two analytes at the same time using the fluid characterization devices are also discussed.

Abstract: A downhole fluid sampling tool may include an optical measurement tool and a viewing region disposed in the optical measurement tool. In examples, a bridge may be disposed in a transparent portion of the flow path between a light source and a light modifier and an optical detector. The bridge includes a structure comprising a substrate and a contrast agent, wherein the contrast agent is any molecule configured to interact with an analyte and alter a property of the analyte and/or contrast agent, wherein the property is detectable by the optical measurement tool.

Abstract: Systems and methods of separating multiphase flows in a flowline of a downhole fluid sampling and analysis tool, measuring target ions in the water phase, and separating between formation water and injection water are described. The system to separate the multiphase flows includes a three-dimensional barrier permeable to water and repelling oil and/or drilling mud filtrate into at least one bypass channel within the flowline of the downhole fluid sampling and analysis tool. For instance, the system to measure the targeted ions includes the system to separate the multiphase flows and an optical sensor, wherein the three-dimensional barrier has an aperture inside the three-dimensional barrier to let a light from an optical sensor go through perpendicular to the flowline.

Abstract: Fluid holdups within a downhole sampling tool are identified by comparing high- and low-resolution measurements of fluid samples.