A sensor element for a cutting tool (100) has a hard portion (110) having a sensing surface (112), first and second electrodes (120, 130), first and second sets of thermocouple wires (122, 132) and an electrically insulating portion. The first and second electrodes (120, 130) are arranged to allow electric current to flow when the sensing surface (112) contacts external material in response to the cutting tool engaging the external material. A first thermocouple junction (124) is operable to indicate a temperature of the first electrode and a second thermocouple junction (134) is operable to measure temperature of the second electrode.

Aspects of the subject technology relate to a sensor for a downhole tool. The downhole tool can include a collar and a sensor. The sensor can be secured to the collar for measuring one or more operational characteristics of the downhole tool during operation of the downhole tool. The sensor can include a substrate. The sensor can also include a plurality of strain gauges disposed on the substrate. The plurality of strain gauges can be configured to measure axial strains and torsional strains on the collar for measuring the one or more operational characteristics of the downhole tool.

Aspects of the subject technology relate to a sensor for a downhole tool. The downhole tool can include a collar and a sensor. The sensor can be secured to the collar for measuring one or more operational characteristics of the downhole tool during operation of the downhole tool. The sensor can include a substrate. The sensor can also include a plurality of strain gauges disposed on the substrate. The plurality of strain gauges can be configured to measure axial strains and torsional strains on the collar for measuring the one or more operational characteristics of the downhole tool.

Systems and methods consistent with the present disclosure may position a cementing tool within a casing string of a wellbore. Such a system may include a fiber optic cable coupled to the cementing tool and may include a distributed temperature sensing (DTS) system interrogator positionable at a surface of the wellbore for transmitting an optical signal through the fiber optic cable such that a plurality of temperatures along the fiber optic cable may be identified. A reel may be used when dispensing the fiber optic cable from a first end of the fiber optic cable in response to a tension in the fiber optic cable as the cementing tool travels down the casing string behind a cement composition. A processor in communication with the DTS system may be configured to monitor the plurality of temperatures along the fiber optic cable while the cement composition cures.

Systems and methods consistent with the present disclosure may position a cementing tool within a casing string of a wellbore. Such a system may include a fiber optic cable coupled to the cementing tool and may include a distributed temperature sensing (DTS) system interrogator positionable at a surface of the wellbore for transmitting an optical signal through the fiber optic cable such that a plurality of temperatures along the fiber optic cable may be identified. A reel may be used when dispensing the fiber optic cable from a first end of the fiber optic cable in response to a tension in the fiber optic cable as the cementing tool travels down the casing string behind a cement composition. A processor in communication with the DTS system may be configured to monitor the plurality of temperatures along the fiber optic cable while the cement composition cures.

Systems, devices, and techniques for determining downhole fluid contamination are disclosed. In one or more embodiments, phase-related properties are measured for a reservoir fluid having a determined composition. An equation-of-state (EOS) is selected and/or tuned based, at least in part, on the measured phase-related properties and the tuned EOS is applied to estimate fluid property values for a reference fluid over specified ranges of at least two thermodynamic properties. Contaminant reference data are generated that correlate the estimated fluid property values for the reference fluid with respective contaminant levels. Within a wellbore, a fluid sample is analyzed to determine a fluid property value. A contaminant level is identified that corresponds within the contaminant reference data to the determined fluid property value of the fluid sample.

Systems, devices, and techniques for determining downhole fluid contamination are disclosed. In one or more embodiments, phase-related properties are measured for a reservoir fluid having a determined composition. An equation-of-state (EOS) is selected and/or tuned based, at least in part, on the measured phase-related properties and the tuned EOS is applied to estimate fluid property values for a reference fluid over specified ranges of at least two thermodynamic properties. Contaminant reference data are generated that correlate the estimated fluid property values for the reference fluid with respective contaminant levels. Within a wellbore, a fluid sample is analyzed to determine a fluid property value. A contaminant level is identified that corresponds within the contaminant reference data to the determined fluid property value of the fluid sample.

An apparatus comprises at least one processing device comprising a processor coupled to a memory. The processing device is configured to obtain time-series temperature data from respective temperature sensors arranged at respective different subsurface depths, and for each of a plurality of pairs of the temperature sensors, to compute a cross-correlation of their corresponding time-series temperature data, to compute a time derivative of the cross-correlation, and to generate an estimate of at least one reservoir property based at least in part on the time derivative of the cross-correlation. At least one automated action is performed based at least in part on the generated estimate, such as, for example, controlling an amount of fluid flow into or out of a particular subsurface region. The generated estimates illustratively comprise estimates of subsurface hydraulic diffusivity.

An apparatus comprises at least one processing device comprising a processor coupled to a memory. The processing device is configured to obtain time-series temperature data from respective temperature sensors arranged at respective different subsurface depths, and for each of a plurality of pairs of the temperature sensors, to compute a cross-correlation of their corresponding time-series temperature data, to compute a time derivative of the cross-correlation, and to generate an estimate of at least one reservoir property based at least in part on the time derivative of the cross-correlation. At least one automated action is performed based at least in part on the generated estimate, such as, for example, controlling an amount of fluid flow into or out of a particular subsurface region. The generated estimates illustratively comprise estimates of subsurface hydraulic diffusivity.

Embodiments of systems and methods for generating power in the vicinity of a drilling rig are disclosed. During a drilling operation, heat generated by drilling fluid flowing from a borehole, exhaust from an engine, and/or fluid from an engine's water (or other fluid) jacket, for example, may be utilized by corresponding heat exchangers to facilitate heat transfer to a working fluid. The heated working fluid may cause an ORC unit to generate electrical power.