Abstract: A computer-implemented method includes: accessing a first database holding information encoding a set of labels that specify a condition of at least one of: a surface pipe, or an underground enclosure that runs at a plurality of depth locations; accessing a second database holding a plurality of inspection logs that record measurement data of the surface pipe or underground enclosure; based on, at least in part, the labeling information and the plurality of inspection logs, training a deep learning model configured to classify, into the set of labels, the condition of the surface pipe or underground enclosure when presented with the inspection logs; applying the deep learning model to one or more newly received inspection logs containing measurement data of a new surface pipe or a new underground enclosure; and subsequently classifying, into the set of labels, the condition of the new surface pipe or the new underground enclosure.

Abstract: An example logging tool includes an injection system, a detection system, and an electric control and processing system. The injection system includes a gas source, and is configured to inject a first gas from the gas source into a region of a subterranean formation. The detection system includes a gas detection chamber and one or more sensors disposed in the gas detection chamber, and is configured to receive, in the gas detection chamber, a sample from the region of the subterranean formation, and generate, using the one or more sensors, sensor measurements of the sample, The electronic control and processing system includes one or more processors, and is configured to determine one or more characteristics of the subterranean formation based on the sensor measurements.

Abstract: A fluid analysis system for characterizing a multiphase fluid includes a first set of acoustic probes disposed at a first angular position about a central axis of the fluid analysis system and oriented to direct first sound waves along a first direction that is parallel to the central axis, a second set of acoustic probes disposed at a second angular position about the central axis that is opposite to the first angular position and oriented to direct second sound waves along the first direction, a third set of acoustic probes spanning the central axis and oriented to direct third sound waves along a second direction that is perpendicular to the central axis, and an analysis unit. The analysis unit is configured to determine a location of a fluid interface within the multiphase fluid based on first, second, and third parameters respectively associated with the first, second, and third sounds waves.

Abstract: Provided are techniques for saturation logging a hydrocarbon well in a hydrocarbon reservoir. The techniques including conducting a pulsed neutron (PN) logging of the well to generate a carbon/oxygen (C/O) log, conducting a nuclear magnetic resonance (NMR) logging of the well to generate a viscosity log, conducting a temperature logging of the well to generate a temperature log, determining a relationship of oil API gravity to viscosity and temperature for the reservoir, determining an oil API gravity log for the well based on the viscosity log, the temperature log, and the relationship of oil API gravity to viscosity and temperature, determining, based on the oil API gravity log, an oil density log for the well, determining, based on the oil density log, an oil-carbon density log for the well, and determining, based on the oil-carbon density log and the C/O log, a continuous oil saturation log for the well.

Abstract: Some implementations provide a tool assembly for monitoring reservoir water salinity and reservoir production performance at a borehole, the tool assembly comprising: a water salinity measuring probe that includes a pair of electrodes, wherein the water salinity measuring probe is mounted at a tip of the tool assembly and configured to measure a water conductivity between the pair of electrodes when the tool assembly is immersed inside the borehole; a spinner tool configured to measure a total flow rate at where the tool assembly is immersed inside the borehole, wherein the spinner tool is located above the water salinity measuring probe when the tool assembly is immersed inside the borehole; and a temperature probe configured to measure a temperature at where the tool assembly is immersed inside the borehole, wherein the temperature probe is located above the spinner tool when the tool assembly is immersed inside the borehole.

Abstract: A fluid analysis system for characterizing a multiphase fluid includes a first set of acoustic probes disposed at a first angular position about a central axis of the fluid analysis system and oriented to direct first sound waves along a first direction that is parallel to the central axis, a second set of acoustic probes disposed at a second angular position about the central axis that is opposite to the first angular position and oriented to direct second sound waves along the first direction, a third set of acoustic probes spanning the central axis and oriented to direct third sound waves along a second direction that is perpendicular to the central axis, and an analysis unit. The analysis unit is configured to determine a location of a fluid interface within the multiphase fluid based on first, second, and third parameters respectively associated with the first, second, and third sounds waves.

Abstract: A well cleaning tool includes a positioning device configured to control a position of the well cleaning tool within a well, a rotatable brush assembly configured to scrape a wall of the well, a capture device configured to catch debris dislodged from the wall by the rotatable brush assembly, and a fluid delivery assembly configured to deliver a cleaning fluid to the well.

Abstract: A well cleaning tool includes a positioning device configured to control a position of the well cleaning tool within a well, a rotatable brush assembly configured to scrape a wall of the well, a capture device configured to catch debris dislodged from the wall by the rotatable brush assembly, and a fluid delivery assembly configured to deliver a cleaning fluid to the well.

Abstract: A method of cleaning a well includes flowing well fluid within the well while running a cleaning tool into the well, injecting the well fluid with a fluid thickening agent through multiple nozzles of the well cleaning tool to form thickened well fluid, dislodging metallic debris and non-metallic debris accumulated along a wall of the well with multiple brushes of the cleaning tool, carrying the non-metallic debris out of the well with the thickened well fluid, and capturing the metallic debris at a capture device of the cleaning tool.

Abstract: A system includes a bottom hole assembly and a core sampling tool. The bottom hole assembly includes a housing and a drill bit coupled to the housing. The core sampling tool includes a first compartment positioned within the housing, the first compartment including a motor; a second compartment positioned within the housing and radially spaced apart from the first compartment, the second compartment including a coring bit; and a flexible drilling shaft extending between and coupled to the motor and the coring bit.

Abstract: Systems and methods include a computer-implemented method for predicting fluid holdups along the borehole or the pipe on surface and to perform fluid typing and fluid properties characterization. Acoustic waves are transmitted by an array of acoustic wave transducers. Each transducer is configured to transmit acoustic waves at a different frequency. The acoustic waves are received by an array of acoustic wave receivers fixed on the bow centralizer on the tool used in the borehole. Each receiver is configured to receive only the given frequency of a given transducer, forming a receiver-transducer pair for the given frequency. Acoustic speeds measured at each given frequency and analyzed. A model is generated based on the analyzing. The model is configured to predict fluid holdups across the borehole and to perform fluid typing and fluid properties characterization in one phase, two phase, and three phase applications of gas, oil, and water.

Abstract: A system includes a bottom hole assembly and a core sampling tool. The bottom hole assembly includes a housing and a drill bit coupled to the housing. The core sampling tool includes a first compartment positioned within the housing, the first compartment including a motor; a second compartment positioned within the housing and radially spaced apart from the first compartment, the second compartment including a coring bit; and a flexible drilling shaft extending between and coupled to the motor and the coring bit.

Abstract: A wellbore tool includes a body having a longitudinal axis and an outer circumferential surface. The wellbore tool includes moveable arms, housings, actuators, a temperature sensor, a pressure sensor, and a heat source, such as a microwave source. Each moveable arm is coupled to a respective actuator and a respective housing. Each actuator is configured to move the respective moveable arm. The temperature sensor is configured to measure a temperature of the subterranean formation. The pressure sensor is configured to measure a pressure of the subterranean formation. The microwave source is configured to generate microwave radiation. Methods of analyzing acquired transient temperature and transient pressure data for formation evaluation are also described.

Abstract: The disclosure provides methods of measuring an intrinsic CO ratio in a geological formation by disposing, proximate the formation, a petrophysical tool including at least one gamma-ray detector, reading a carbon gamma-ray peak for the geological formation and an oxygen gamma-ray peak for the geological formation, determining a measured CO ratio of the geological formation from the carbon gamma-ray peak and the oxygen gamma-ray peak, and correcting the measured CO ratio by applying a corrective algorithm specific for the petrophysical tool or the type of petrophysical tool to obtain an intrinsic CO ratio of the geological formation. The corrective algorithm is derived by a mathematical analysis of measured CO ratios of a sample with a known intrinsic CO ratio using the same petrophysical tool or a petrophysical tool representative of a same type of petrophysical tool. Additional methods and systems using this method are provided.

Abstract: Embodiments provide techniques for using data from a select set of wells to develop correlations between surface-measured properties, downhole coring parameters, and properties typically determined from subsurface measurements (e.g., from logging tool responses, core analysis, or other subsurface measurements). When new wells are drilled, the surface data acquired while drilling and coring parameters used downhole may be used as an input to these correlations in order to predict properties associated with subsurface measurements.

Abstract: A formation fluid sampling tool includes a housing, and at least one sampling probe proximate an external surface of the housing. The at least one sampling probe includes an opening sized and positioned to receive one or more heated formation fluids, and a plurality of heating elements arranged concentrically around the opening and configured to conductively heat a subterranean formation through an external surface of the sampling probe.

Abstract: Provided are techniques for saturation logging a hydrocarbon well in a hydrocarbon reservoir. The techniques including conducting a pulsed neutron (PN) logging of the well to generate a carbon/oxygen (C/O) log, conducting a nuclear magnetic resonance (NMR) logging of the well to generate a viscosity log, conducting a temperature logging of the well to generate a temperature log, determining a relationship of oil API gravity to viscosity and temperature for the reservoir, determining an oil API gravity log for the well based on the viscosity log, the temperature log, and the relationship of oil API gravity to viscosity and temperature, determining, based on the oil API gravity log, an oil density log for the well, determining, based on the oil density log, an oil-carbon density log for the well, and determining, based on the oil-carbon density log and the C/O log, a continuous oil saturation log for the well.

Abstract: A formation fluid sampling tool includes a housing, and at least one sampling probe proximate an external surface of the housing. The at least one sampling probe includes an opening sized and positioned to receive one or more heated formation fluids, and a plurality of heating elements arranged concentrically around the opening and configured to conductively heat a subterranean formation through an external surface of the sampling probe.

Abstract: The disclosure provides methods of measuring an intrinsic CO ratio in a geological formation by disposing, proximate the formation, a petrophysical tool including at least one gamma-ray detector, reading a carbon gamma-ray peak for the geological formation and an oxygen gamma-ray peak for the geological formation, determining a measured CO ratio of the geological formation from the carbon gamma-ray peak and the oxygen gamma-ray peak, and correcting the measured CO ratio by applying a corrective algorithm specific for the petrophysical tool or the type of petrophysical tool to obtain an intrinsic CO ratio of the geological formation. The corrective algorithm is derived by a mathematical analysis of measured CO ratios of a sample with a known intrinsic CO ratio using the same petrophysical tool or a petrophysical tool representative of a same type of petrophysical tool. Additional methods and systems using this method are provided.

Abstract: Provided here are compositions and improved methods for recovering portion of irreducible water saturation in a porous rock sample. Compositions used here contain a displacement fluid and a surfactant, and lead to an increased recovery of the irreducible water from the porous rock sample.