An inspection device for hydraulic equipment includes a hydraulic circuit having a branch valve, an optical detection section, a pump configured to supply oil to the hydraulic circuit, and a controller. The optical detection section includes an inspection oil passage connected to the branch valve. The inspection oil passage includes a filter arranged to collect foreign matter. The controller operates the branch valve to supply oil to the inspection oil passage. The optical detection section includes first and second foreign matter detection sections arranged on upstream and downstream sides of the filter to detect foreign matter. A work vehicle includes the inspection device. An inspection system includes the inspection device. An inspection method includes supplying oil to an inspection oil passage by operating a branch valve of a hydraulic circuit, and detecting foreign matter on upstream and downstream sides of a filter arranged on the inspection oil passage.

A deterioration estimation device includes a storage device and an execution device. The storage device is configured to store mapping data defining a mapping that outputs an output variable indicating the degree of deterioration of oil when an input variable is input. The mapping includes, as the input variable, a color variable that is a variable indicating a color of the oil and a hydrogen ion variable that is a variable indicating a hydrogen ion concentration of the oil. The execution device is configured to execute an acquisition process that is a process of acquiring the input variable and a calculation process of inputting the input variable acquired through the acquisition process to the mapping to output a value of the output variable.

Devices, systems, and methods for determining gas characteristics to monitor transformer operation include extracting gas from transformer fluid for analysis.

The delivery of fuel oil through a fuel oil delivery pipe is monitored to measure the flow rate, temperature, viscosity, density and dielectric constant of the fuel oil as it moves through the delivery pipe. The digital data signals from the sensors which are a function of the measured parameters are recorded in a memory. An IR sensor detects the presence of air in the pipe and prevents the data signals from being recorded. The actual total quantity of fuel oil delivered through the pipe is calculated based upon the recorded data signals, which may be adjusted to take into account the temperature of the fuel oil being delivered. A clock circuit generates a timing signal reflecting the date and time the measurements were taken. Information as to the quantity delivered and the time of delivery may be sent to a remote location.

Disclosed are systems and methods for calibrating integrated computational elements. One method includes measuring with a spectrometer sample interacted light comprising spectral data derived from one or more calibration fluids at one or more calibration conditions, the one or more calibration fluids circulating in a measurement system, programming a virtual light source based on the spectral data, simulating the spectral data with the virtual light source and thereby generating simulated fluid spectra corresponding to the spectral data, conveying the simulated fluid spectra to the one or more ICE and thereby generating corresponding beams of optically interacted light, and calibrating the one or more ICE based on the corresponding beams of optically interacted light.

Disclosed is an experimental device and method for solubility determination of methane in oil-based drilling fluid, comprising a pressure-resistant gas chamber and an equilibrium still both arranged in a constant-temperature oil bath heating oven, a gas booster pump, and a vacuum system used for vacuuming the pressure-resistant gas chamber and the equilibrium still, and a data acquisition device for collecting temperature and pressure signals; the gas booster pump is connected to drive air source inlet, a gas check valve is arranged on the pipe between the pressure-resistant gas chamber and the gas booster pump that is also connected with a high-pressure gas cylinder, the equilibrium still is divided into a dissolution equilibrium chamber at the top and a hydraulic oil chamber at the bottom by a high-pressure dynamic seal structure, the dissolution equilibrium chamber is connected to a liquid inlet funnel through the fourth globe valve.

A method for determining CO.sub.2 mass flow rate of a multi-phase fluid flowing in a pipeline includes obtaining pressure signals from pressure sensors flush-mounted on the inner wall of the pipe that include a diaphragm for sensing pressure. The pressure signals determine a first time-of-flight of flow eddies and a second time-of-flight of sound waves. Using the first and second time-of-flight, bulk flow velocity and mixture speed of sound is determined. Static pressure sensors obtain a static pressure measurement and temperature sensors obtain a temperature measurement. The static pressure and temperature sensors are placed near the pressure sensors. A fluid composition sensor obtains fluid composition data. Based on the static pressure measurement, temperature measurement, and fluid composition data, single-phase fluid properties are determined. Based on the bulk flow velocity, mixture speed of sound, and single-phase fluid properties, CO.sub.2 mass flow rate of the multi-phase fluid is determined.

A system can flush a drilling fluid sample with a hydrocarbon blend, which includes a determined concentration of at least one chemical species to generate a flushed drilling fluid sample. The system can extract a dissolved gas from the flushed drilling fluid sample. The system can determine a concentration over time of at least one chemical species of the dissolved gas. The system can generate an area per concentration curve based on the concentration over time of the at least one chemical species. The system can determine at least one concentration value of the at least one chemical species. The system can modify the at least one concentration value based on the area per concentration curve. The system can then correct bias caused by the gas extractor and fluid sampling system.

Provided, a trace gas measurement apparatus for electrical equipment that includes at least one sample cell configured to collect an oil sample from the electrical equipment. The sample cell includes (i) an oil receiving portion for receiving an oil sample, and (ii) a head space in an upper section thereof receiving ambient air therein, an oil pump for selectively pumping oil into and out of the sample cell, and a hydrogen gas sensor within an exhaust path of the sample cell. The hydrogen gas sensor receives the air exhausted from the sample cell and measures hydrogen gas present in the exhausted air.

A method of detecting at least one of an analyte or a condition of a fluid within a subterranean formation includes operably coupling a radiation source to at least one optical fiber coupled to a sensor having optically sensitive materials including at least one of chromophores, fluorophores, metal nanoparticles, or metal oxide nanoparticles dispersed within an optically transparent permeable matrix material. The sensor is contacted within a wellbore with a fluid and the fluid is passed through at least a portion of the sensor. Electromagnetic radiation is transmitted from the radiation source through at least one optical fiber to the sensor and at least one of an absorbance spectrum, an emission spectrum, a maximum absorption intensity, or a maximum emission intensity of electromagnetic radiation passing through the sensor after contacting at least some of the optically sensitive materials with the fluid is measured. Additional methods of determining a concentration of hydrogen sulfide in a fluid within a subterranean formation and related downhole optical sensor assemblies are disclosed.