The present invention relates to a method for diagnosing an internal fault of an oil-immersed transformer by analyzing the composition ratio of dissolved gas in oil that is caused when an internal fault of the oil-immersed transformer occurs. According to the present invention, a method for diagnosing an internal fault of an oil-immersed tranformer by extracting and analyzing dissolved gas in oil from the oil-immersed transformer for which an internal fault is to be diagnosed comprises: a first step of calculating the composition ratio of each of CH4/H2, C2H2/C2H4, C2H4, C2H4/C2H6, and C2H4/CH4 from among the extracted dissolved gas in oil; a second step of determining whether the internal fault is an electrical fault or a thermal fault using the calculated composition ratios of CH4/H2 and C2H2/C2H4; and a third step of determining, if said internal fault is determined to be an electrical fault in the second step, whether the electrical fault is a partial discharge (PD), a discharge of low energy (D1), or a discharge of high energy (D2) using the calculated composition ratios of C2H2/C2H4 and C2H4/C2H6.

System and methods for analyzing a multiphase production fluid include a fluidic supply and analysis unit configured to transition the fluidic separation chamber to a static state after a complete gaseous phase column and a complete oil phase column are formed within the fluidic separation chamber; communicate with the fluidic separation detector to measure the absolute or relative sizes of the complete gaseous phase column and the complete oil phase column; and calculate an oil/gas volume fraction as a function of the measured sizes of the gaseous phase and oil phase columns in the fluidic separation chamber.

An apparatus includes a plate and a micro-protrusion baffle. The plate defines a microfluidic channel that is configured to flow a sample of lubrication oil. The microfluidic channel has an inlet for receiving the sample of lubrication oil. The microfluidic channel has an outlet for discharging the sample of lubrication oil. The plate defines walls of the microfluidic channel. The walls extend from the inlet to the outlet. The micro-protrusion baffle is located within the microfluidic channel between the inlet and the outlet. The micro-protrusion baffle extends from any of the walls. The micro-protrusion baffle includes a cyclic olefin copolymer. Dissolution of at least a portion of the micro-protrusion baffle in response to the sample of lubrication oil flowing through the microfluidic channel indicates a presence of hydrocarbon fuel in the sample of lubrication oil.

Processes and systems for monitoring one or more gases dissolved in a liquid. In some embodiments, the process can include introducing a fluid into an inlet of a sample cell, where the fluid includes at least one gas dissolved in a liquid. The fluid can flow through the sample cell such that at least a portion of the fluid flows past an optical window such that the fluid is viewable within the sample cell through the optical window. The fluid can be recovered from an outlet of the sample cell. An electromagnetic radiation signal can be emitted into the sample cell through the optical window for at least a portion of the time the fluid is viewable through the optical window. The fluid can be contacted with the electromagnetic radiation signal within the sample cell. A scattered electromagnetic radiation signal that can include elastic scattered radiation and inelastic scattered radiation emitted from the sample cell through the optical window can be directed into a filter to remove at least a portion of the elastic scattered radiation to produce a primarily inelastic scattered radiation signal. The primarily inelastic scatted radiation signal can be directed to a detector to detect a Raman signal indicating the presence of the at least one dissolved gas in the liquid.

A method of assessing a caprock for caprock defects comprises drilling a first well into a geologic sequence, the geologic sequence comprising a first subsurface formation, the caprock positioned above the first subsurface formation, and a second subsurface formation positioned above the caprock; sampling subsurface fluids of the geologic sequence for helium concentration within the second subsurface formation, within the caprock, and within the first subsurface formation; drilling a second well into the geologic sequence a pre-determined distance away from the first well; sampling the subsurface fluids for the helium concentration within the second subsurface formation, within the caprock, and within the first subsurface formation through the second well; determining whether a deviation exists between the helium concentration at the first well and at the second well, the deviation indicating the caprock defect is present; and halting further drilling into the geologic sequence upon determining the caprock defect is present.

A method for estimating a quantity of natural hydrogen in a subterranean formation includes degassing drilling fluid obtained from a wellbore to obtain a gas sample including a quantity of hydrogen gas, measuring a concentration of hydrogen in the gas sample, and applying a correction to the measured concentration of hydrogen to estimate the quantity of natural hydrogen in the subterranean formation.

Methods and apparatus for operating a downhole tool within a wellbore adjacent a subterranean formation to pump contaminated fluid from the formation into the downhole tool while measuring first and second fluid properties of the contaminated fluid. The contaminated fluid comprises native fluid from the formation and a contaminant. The downhole tool is in communication with surface equipment located at surface. The downhole tool and/or surface equipment is operated to estimate a formation volume factor of the contaminated fluid based on at least one of the first and second fluid properties of the contaminated fluid. A linear relationship is then estimated between the first fluid property and a function that relates the first fluid property to the second fluid property and the estimated formation volume factor of the contaminated fluid. A fluid property of the contaminant is then estimated based on the estimated linear relationship.

A single element thin-film device, a method for producing a thin-film device, a single element for detecting hydrogen absorption, a hydrogen sensor, and an apparatus for detecting hydrogen and to an electro-magnetic transformer comprising such sensor. A thin-film device comprises a substrate, an active sensing layer whose optical properties change depending on hydrogen content, and a protective layer on the active sensing layer.

System and method for analyzing gas composition content of transformer oil are provided. The analysis system includes a ten-way switching valve, a sample loop, a first chromatographic column, a second chromatographic column, a thermal conductivity cell detector, a four-way switching valve, a third chromatographic column, and a carbon composition detection device. A first composition fitted peak and a second composition fitted peak are sequentially separated from a transformer oil sample by the first chromatographic column, the first composition fitted peak is a fitted peak of hydrogen, oxygen, and nitrogen; and the second composition fitted peak is a fitted peak of carbon monoxide, methane, carbon dioxide, and a C.sub.2 hydrocarbon compositions.

Provided is a downhole tool and a well system. The downhole tool, in one aspect, includes a tubular providing one or more production fluid flow paths for a production fluid. The downhole tool, according to this aspect, further includes one or more float chambers located within the tubular, and two or more floats located within the one or more float chambers. In one aspect, a first of the two or more floats has a first density (.sub.1) between a density of gas (.sub.g) and a density of oil (.sub.o), and a second of the two or more floats has a second density (.sub.2) between the density of oil (.sub.o) and a density of water (.sub.w). The downhole tool, according to this aspect, further includes two or more non-contact proximity sensors configured to sense a radial location of the two or more floats to determine a gas:oil ratio and oil:water ratio.