Schlumberger Technology Corporation

Onesubsea IP UK Limited

Albert Ballard Andrews

Oliver Clinton Mullins

Christopher Harrison

Ronald E G Van Hal

Andrew Speck

Tsutomu Yamate

Li Jiang

Kentaro Indo

Bhavani Raghuraman

Stephane Vannuffelen

Rogerio Tadeu Ramos

Andrew Emil Pomerantz

Timothy Gareth John Jones

Kosta Ladavac

Toru Terabayashi

Jimmy Lawrence

Gale Hyslip Gustavson

Hideki Kinjo

Wei-Chuan Shih

Jeffrey Crank

Matthew Clayton

Yi-Qiao Song

Youxiang Zuo

Robert J Schroeder

Gary Martin Oddie

Matthew T Sullivan

Chengli Dong

Akira Kamiya

Andrew John Carnegie

Ridvan Akkurt

Michael O'Keefe

Marian Faur

Irfan Bulu

Neil Herbst

Eric Lehne

Bradley Martin

Mathieu Dauphin

Shawn David Taylor

Zied Ben Hamad

Aditi Chakrabarti

Systems and methods are described for developing a model to predict humidity (relative, absolute) values inside a closed housing with an absorbent filter. In an example, a methane sensor that includes an internal atmospheric sensor and an external atmospheric sensor can be placed at a site. A computing device can use measurements from the atmospheric sensors to calculate predicted relative and absolute humidity values inside the methane sensor. The computing device can train a gaussian process regression model to calibrate sensor data based on the external temperature and humidity. When the model predicts the ambient methane within a predetermined degree of allowance, the model can be applied to live readings from methane sensors in the field.

Calibration of humidity and methane inside gas sensor housing

Systems and methods presented herein are configured to monitor gas storage in a well and, more specifically, to invert optical measurements to predict the fractional molar composition of an unknown composition of a gas mixture comprised of hydrogen, carbon dioxide, other gases, or combinations thereof, in any underground reservoir or salt dome where hydrogen, carbon dioxide, and/or the other gases are stored or exist.

Systems and methods for monitoring gas storage in underground reservoirs

A technique utilizes spatially resolved temperature measurements to infer the temperature of a subsea infrastructure. According to an embodiment, temperature data, e.g. a temperature map, is determined for the subsea infrastructure and comprises performing remote temperature measurements of water surrounding the subsea infrastructure. Additionally, a metrological scan of the subsea structure may be obtained. Furthermore, a simulation or simulations may be run for an assumed temperature profile along a surface of the subsea infrastructure. The data obtained from the remote temperature measurements, the metrological scan, and the simulation is processed to determine a temperature profile of the subsea infrastructure. This temperature profile can then be used to facilitate a variety of subsea infrastructure management decisions.

Methodology and system for determining temperature of subsea infrastructure

Methods may include emplacing a wellbore tool in a wellbore, the wellbore tool including a gas chromatograph and a mass spectrometer, wherein the mass spectrometer is configured to operate at a pressure greater than 10Torr, measuring a sample from the wellbore using the wellbore tool, and determining a molecular weight of one or more components of the sample from the measured response of the wellbore tool. Methods may also include establishing a library of one or more chemical components, emplacing a wellbore tool in a wellbore, the wellbore tool including a gas chromatograph and a mass spectrometer, wherein the mass spectrometer is configured to operate at a pressure greater than 10Torr, measuring a sample from the wellbore using the wellbore tool, comparing the measured response from the wellbore tool for the sample with results from the library of one or more chemical components, and determining a molecular weight of one or more components of the sample.

Methods of applications for a mass spectrometer in combination with a gas chromatograph

Apparatus and method for Raman-spectrography-based measurement of the composition of gas mixture in a high-temperature borehole. The method includes any of determining molar densities of individual alkanes of the mixture, introducing refractive index corrections, utilization of reference species internally to the measurement apparatus, correction for the effect of self-absorption and cross-absorption, as well as minimizing fluorescence when a liquid fraction is present in the borehole. The apparatus is configured to detect vibrational bands of CH, OH, CC, HS, NN and CO functional groups as well as collective modes in the fingerprint spectral region.

Raman spectroscopy for determination of composition of natural gas

A downhole tool is conveyed within a borehole extending into a subterranean formation. Fluid is drawn from the subterranean formation into the downhole tool, wherein the fluid comprises heavy oil. Fluorescence intensity of the drawn fluid is measured via a sensor of the downhole tool, and asphaltene content of the drawn fluid is estimated based on the measured fluorescence intensity.

Asphaltene content of heavy oil

Wellbore tools in accordance with the present disclosure may include a gas chromatograph; and a mass spectrometer, wherein the mass spectrometer is configured to operate at a pressure greater than 10Torr. Systems in accordance with the present disclosure may include a gas chromatograph; and a mass spectrometer, wherein the mass spectrometer is configured to operate at a pressure greater than 10Torr. Methods in accordance with the present disclosure may include emplacing a wellbore tool in a wellbore, the wellbore tool containing a gas chromatograph and a mass spectrometer, wherein the mass spectrometer is configured to operate at a pressure greater than 10Torr; drawing a sample of a fluid from the wellbore into the wellbore tool; and determining a molecular weight of one or more components of the fluid.

Gas chromatograph mass spectrometer for downhole applications

A methodology for reservoir understanding employs analysis of fluid property gradients to investigate and distinguish between non-compartmentalization of the reservoir, compartmentalization of the reservoir, and lack of thermodynamic equilibrium in the reservoir.

Methods for characterization of petroleum reservoirs employing property gradient analysis of reservoir fluids

Accurate, real-time detection of dew point of a gaseous sample can be accomplished using the systems and techniques described herein. A gaseous sampling chamber defining an interior volume includes a patterned structure having a roughened surface exposed to the gaseous sampling chamber. The patterned structure includes an open volume accessible by the roughened surface, for example, representing at least about 10% of the interior volume of the gaseous sampling chamber. An illumination source is configured to illuminate at least a portion of the patterned structure. A light detector is configured to receive at least a portion of illumination returned from the patterned structure. A condensate detector is configured to determine a presence of a condensate on the roughened surface in response to an optical property of the patterned surface as modified by the presence of dew.

Measurement of liquid fraction dropout using micropatterned surfaces

Methods and related apparatuses and mixtures are described for detecting hydrogen sulfide in a formation fluid downhole. A detection mixture is combined with the formation fluid downhole. The detection mixture includes metal ions for reacting with hydrogen sulfide forming a metal sulfide, and charged nanoparticles sized so as to inhibit significant aggregation of the metal sulfide so as to enable spectroscopic detection of the metal sulfide downhole. The combined mixture and formation fluid is then spectroscopically interrogated so as to detect the presence of the metal sulfide thereby indicating the presence of hydrogen sulfide in the formation fluid. The mixture also includes chelating ligands for sustaining thermal endurance of the mixture under downhole conditions.

Downhole spectroscopic hydrogen sulfide detection

The invention relates to a method for detecting the presence of hydrocarbons near an unmanned offshore oil platform. The method steps include monitoring reflected atmospheric and thermal radiation, detecting the presence of hydrocarbons, and generating an alert based on the presence of hydrocarbons.

Method and apparatus for oil spill detection

Some principles described herein contemplate implementation of downhole imaging for the characterization of formation fluid samples in situ, as well as during flow through production tubing, including subsea flow lines, for short term investigation, permanent, and/or long term installations. Various methods and apparatus described herein may facilitate downhole testing. For example, some embodiments facilitate multi-dimensional fluorescence spectrum measurement testing downhole and correlating the fluorescence with other oil properties.

Methods and apparatus for multi dimension fluorescence spectrum measurement and correlations downhole

Some principles described herein contemplate implementation of downhole imaging for the characterization of formation fluid samples in situ, as well as during flow through production tubing, including subsea flow lines, for short term investigation, permanent, and/or long term installations. Various methods and apparatus described herein may facilitate downhole testing. For example, some embodiments facilitate multi-dimensional fluorescence spectrum measurement testing downhole.

Methods and apparatus for multi dimension fluorescence spectrum measurement downhole

Growing community of inventors

Wilton, CT, United States of America

Albert Ballard Andrews