Abstract: Processes for determining formation salinity and/or processes for identifying oil bearing and/or water bearing zones in freshwater or relatively low salinity formations. In some embodiments, the process for determining formation water salinity can include measuring resistivity of a formation fluid sample at a first temperature (T1) and at a second temperature (T2), where T1 and T2 can be separated by a temperature difference (?T). The process can also include calculating a resistivity factor value based on the resistivities measured at T1 and T2. The process can also include determining a salinity of the formation fluid sample based on the resistivity factor value and the ?T. The process can also include initiating a downhole operation using the determined salinity of the formation fluid sample.

Abstract: An assembly and a method for cooling a downhole logging tool. The assembly includes a coiled tubing assembly having a downhole logging tool and a coiled tubing pipe. The coiled tubing pipe is coupled to the downhole logging tool. The coiled tubing pipe includes a cooling fluid tube. The cooling fluid tube conducts a cooling fluid to the downhole logging tool.

Abstract: A method can include receiving Stoneley wave data acquired by a sonic tool disposed in a borehole in a formation; performing an inversion using the Stoneley wave data to generate formation and borehole information; and identifying an interval along the borehole for performance of a downhole acquisition operation by a downhole tool using a machine learning model and the formation and borehole information as input to the machine learning model.

Abstract: Systems and methods are described for correcting ambient condition capillary pressure curves. In an example, the capillary pressure curve of a porous medium can be measured in non-reservoir conditions. Samples of the porous medium can be scanned at various confining pressures, and digital models of the scans can be created by a computing device. The computing device can simulate a porous plate experiment on the digital models to create a capillary pressure curve for each model. The computing device can calculate fitting equations for each capillary pressure curve according to capillary pressure points. The fitting equations can be averaged together and applied to the capillary pressure curve of the porous medium to correct for the non-reservoir conditions.

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: A determination of a continuous oil density log for a hydrocarbon reservoir accessible via a well drilling into the formation having the reservoir. The logging operations may be conducted in the well to generate a carbon-oxygen ratio (C/O) log, a water saturation log, and a porosity log. A continuous oil density log may be determined using the C/O log, the water saturation log, the porosity log, and carbon and oxygen density values. The continuous oil density log may be used in further characterization and development of the hydrocarbon reservoir.

Abstract: Process for determining rock permeability. In some embodiments, the process can include determining a volume-based aspect ratio distribution of pores in a rock sample from a digital image of the sample, grouping the volume-based aspect ratio distribution into two or more pore types, selecting an initial pore type from the two or more pore types, obtaining mercury injection capillary pressure (MICP) data of the sample, creating a volume forward model and a frequency forward model using the MICP data, deriving an initial volume-based pore size distribution and an initial frequency-based pore size distribution for the initial pore type using the volume and the frequency forward models, respectively, selecting either the initial volume-based or the initial frequency-based distribution based on the forward models, and optimizing the selected distribution using an inversion of the MICP data with combinations of two or more pore type distributions to create an optimized distribution.

Abstract: An assembly and a method for cooling a downhole logging tool. The assembly includes a coiled tubing assembly having a downhole logging tool and a coiled tubing pipe. The coiled tubing pipe is coupled to the downhole logging tool. The coiled tubing pipe includes a cooling fluid tube. The cooling fluid tube conducts a cooling fluid to the downhole logging tool.

Abstract: A method of removing wellbore water from a production wellbore includes determining a production flow rate. The method also includes determining a target production flow rate of the production fluid and comparing the production flow rate to a flow rate threshold associated with the target production flow rate. The method also includes determining, based on a result of comparing the production flow rate to the flow rate threshold, that the production flow rate satisfies the threshold. The method also includes activating a fluid moving device fluidly coupled to a wellbore string extending from a terranean surface to the water to inject, into the water, at least one of i) a surfactant, ii) a gas, or iii) a foaming agent, allowing the water and the production fluid to emulsify together and thereby allowing a mixture of water and production fluid to flow to the terranean surface of the wellbore.

Abstract: Systems and methods for detecting a formation fluid kick in a wellbore include drilling into a subsurface formation using a drill string including a pup joint. Measuring properties of a drilling fluid inside of the drill string at the pup joint using a first sensor module and measuring properties of the drilling fluid outside of the drill string at the pup joint using a second sensor module. Analyzing the measured properties of the drilling fluid inside and outside of the drill string at the pup joint including calculating a difference between the properties of the drilling fluid inside and outside of the drill string at the pup joint. Determining an occurrence of the kick based on the difference between the properties of the drilling fluid inside and outside of the drill string at the pup joint exceeding a pre-determined threshold value.

Abstract: A production logging tool includes a housing having a first end configured to connect to a well string disposed in a wellbore, a flowmeter assembly supported by the housing and including a spinner exposed to fluid in the wellbore, and a cleaning assembly connected to the housing and including a fluid nozzle directed at the spinner. The spinner rotates about a central rotational axis of the spinner, and the fluid nozzle direct a flow of cleaning fluid at the spinner. The cleaning assembly can include a fluid pump fluidly connected to the fluid nozzle to drive the flow of cleaning fluid to the fluid nozzle, and a controllable fluid valve between the fluid pump and the fluid nozzle to control the flow of cleaning fluid to the fluid nozzle.

Abstract: A fluid velocity sensor can include a thermally conductive body comprising a first temperature sensor, a second temperature sensor, and a third temperature sensor. A heating element is secured within the fluid velocity sensor to heat the thermally conductive body. The first temperature sensor, the second temperature sensor, and the third temperature sensor each reside within the thermally conductive body at different radial distances from the heating element. A flowrate of a fluid in contact with the fluid velocity sensor is determined based on a comparison between the internal temperatures measured by each of the first, second, and third temperature sensors.

Abstract: Methods and systems are provided for predicting thermal properties of a subsurface rock formation. A training dataset is derived from petrophysical properties of a plurality of formation rock samples and thermal properties of the plurality of formation rock samples. The training dataset is used to train a machine learning model that predicts label data representing the predefined set of thermal properties given input data representing the predefined set of petrophysical properties of an arbitrary formation rock sample. The machine learning model can be validated and deployed for use in predicting thermal properties of subsurface rock formations.

Abstract: A method can include receiving Stoneley wave data acquired by a sonic tool disposed in a borehole in a formation; performing an inversion using the Stoneley wave data to generate formation and borehole information; and identifying an interval along the borehole for performance of a downhole acquisition operation by a downhole tool using a machine learning model and the formation and borehole information as input to the machine learning model.

Abstract: Systems and techniques are provided for integrating laboratory generated nuclear magnetic resonance (NMR) data and NMR logging data. An example method can include obtaining NMR logging data describing one or more downhole NMR measurements captured during a drilling operation in a borehole; modifying the NMR logging data to be compatible with a temperature correction algorithm, yielding modified NMR logging data, the temperature correction algorithm having been determined based on laboratory generated NMR data; and applying the temperature correction algorithm to the modified NMR logging data, yielding temperature corrected NMR logging data.

Abstract: A production logging tool has a housing, a flowmeter assembly, a heating element, a drive, a clutch, and a controller. The housing has a first end attached to a wellbore string. The flowmeter assembly has a spinner exposed to fluid in the production string and a spinner shaft fixed to the spinner and extending from a rear surface of the spinner into the housing. The spinner shaft is rotatably attached to the housing. The heating element is attached to the spinner. The drive is disposed within the housing. The controller is operationally coupled to the drive and the heating element. The controller activates and deactivates at least one of the drive or the heating element to heat a volume around the spinner with the heating element or selectively spin the spinner with the drive.

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: Systems and methods for detecting a formation fluid kick in a wellbore include drilling into a subsurface formation using a drill string including a pup joint. Measuring properties of a drilling fluid inside of the drill string at the pup joint using a first sensor module and measuring properties of the drilling fluid outside of the drill string at the pup joint using a second sensor module. Analyzing the measured properties of the drilling fluid inside and outside of the drill string at the pup joint including calculating a difference between the properties of the drilling fluid inside and outside of the drill string at the pup joint. Determining an occurrence of the kick based on the difference between the properties of the drilling fluid inside and outside of the drill string at the pup joint exceeding a pre-determined threshold value.

Abstract: A determination of a continuous oil density log for a hydrocarbon reservoir accessible via a well drilling into the formation having the reservoir. The logging operations may be conducted in the well to generate a carbon-oxygen ratio (C/O) log, a water saturation log, and a porosity log. A continuous oil density log may be determined using the C/O log, the water saturation log, the porosity log, and carbon and oxygen density values. The continuous oil density log may be used in further characterization and development of the hydrocarbon reservoir.

Abstract: Methods and systems are provided that perform sonic measurements in a high-angle wellbore or horizontal wellbore or vertical wellbore penetrating highly dipped formation layers where the formation layers can have a high degree of dip relative to the wellbore. Sonic data can be generated from the sonic measurements and processed using multiple arrival event processing to determine formation porosity, elastic rock properties and geometric information for a tool layer and nearby shoulder bed. Such information can be integrated into a 2D or 3D layered model of the formation. The elastic rock properties of the tool layer and shoulder bed derived from the multiple arrival event processing can provide more representative elastic property values, which can account for heterogeneity along the wellbore.