Abstract: A method of determining a permeability profile of a heavy-oil bearing formation includes pre-heating of the formation by circulation of steam in a well, creating an excessive pressure inside the well during the pre-heating stage, stopping circulation of steam in the well, measuring temperature along a well bore of the well using distributed temperature sensors, wherein the measuring is performed from a moment at which steam circulation stops until a thermally stable condition is achieved, creating a conductive heat exchange model relating a quantity of steam penetrated into the formation to a local permeability of the formation, the model being created using the temperature measurement results of the pre-heating stage for solving an inverse problem, and determining the formation permeability profile from the created model.

Abstract: Embodiments of the present invention provide for a system and method for flow assurance and pipe condition monitoring in a pipeline for flowing hydrocarbons using at least one thermal sensor probe, which at least one thermal sensor probe may be used in conjunction with one or more other sensors to manage the sensing process and for data fusion to accurately determine flow properties and/or pipeline condition. By way of example, but not by way of limitation, in an embodiment of the present invention, a network of noninvasive sensors may provide output data that may be data-fused to determine properties of the pipeline and/or flow through the pipeline.

Abstract: This disclosure relates in general to methods and systems for measuring multiphase flows in a pipeline using a combination of venturi, microwave and radiation techniques, where the pipeline is configured to transport hydrocarbons. More specifically, but not by way of limitation, certain embodiments of the present invention provide methods and systems in which low activity radiation sources may be used in combination with one or more microwave transmitter-receiver pairs and pressure differential sensors to measure the flow rates and fractions of phases in multiphase flows in a pipeline, such as may be encountered in producing hydrocarbon wells. Additionally, other embodiments of the present invention provide for the arrangement of one or more microwave transmitter-receiver pairs, one or more radiation source-detector pairs and/or one or more pressure sensor ports in the same cross-section of the throat of a venturi to measure multiphase flow in a hydrocarbon transporting pipeline.

Abstract: This useful model relates to fiber-optic fluid/gas flow rate measurement transducers and is employed in gas/fluid flow measuring systems, and can be used for water or natural gas consumption monitoring, especially in measuring systems intended for fluid/gas flow monitoring in pipelines and oil/gas wells. The transducer includes optic fiber which comprises at least one Bragg's fiber lattice, wherein the said Bragg's fiber lattice is fitted with at least one concentrator of mechanical stresses which originate in the optic fiber during its interaction with the gas/fluid flow. As a result, the transducer sensitivity increases.

Abstract: This disclosure relates in general to methods and systems for measuring multiphase flows in a pipeline using a combination of venturi, microwave and radiation techniques, where the pipeline is configured to transport hydrocarbons. More specifically, but not by way of limitation, certain embodiments of the present invention provide methods and systems in which low activity radiation sources may be used in combination with one or more microwave transmitter-receiver pairs and pressure differential sensors to measure the flow rates and fractions of phases in multiphase flows in a pipeline, such as may be encountered in producing hydrocarbon wells. Additionally, other embodiments of the present invention provide for the arrangement of one or more microwave transmitter-receiver pairs, one or more radiation source-detector pairs and/or one or more pressure sensor ports in the same cross-section of the throat of a venturi to measure multiphase flow in a hydrocarbon transporting pipeline.

Abstract: Embodiments of the present invention provide for a system and method for flow assurance and pipe condition monitoring in a pipeline for flowing hydrocarbons using at least one thermal sensor probe, which at least one thermal sensor probe may be used in conjunction with one or more other sensors to manage the sensing process and for data fusion to accurately determine flow properties and/or pipeline condition. By way of example, but not by way of limitation, in an embodiment of the present invention, a network of noninvasive sensors may provide output data that may be data-fused to determine properties of the pipeline and/or flow through the pipeline.

Abstract: There is a method of determining properties relating to an underbalanced well, comprising inducing pressure variations in a fluid within a well, measuring the pressure variations, and calculating pore pressure of at least one fluid-producing formation. The pressure variations cause a change in flow rate from formations along a length of borehole, and as such a change in the production flow rate of the well. The variations in pressure are used to calculate the pore pressure. Variations in annular bottomhole pressure are induced by altering the flow rate of drilling fluid, or the density of drilling fluid or by acoustic pulsing downhole. The pore pressure, permeability and porosity of the formations is derived as a real time profile along the length of the borehole.

Abstract: A method and system for telemetry through a compressible drilling fluid during underbalanced drilling is disclosed. A reflector (110) is positioned downstream from the gas inlet (84) and causes reflected pressure waves having the same pressure polarity as incident pressure waves. A pressure sensor (92) is positioned below the reflector to sense pressure in the compressible drilling fluid. The reflector (110) can be a fixed orifice plate or an adjustable aperture. A borehole communication system is also disclosed wherein a pair of pressure sensors are positioned on either side of a flow restriction (118) located in the gas conduit leading to the gas injector. The flow restriction can be a valve used to regulate the flow rate of the gas being supplied into the drilling fluid, or it can be separate venturi or orifice plate.

Abstract: There is a method of determining properties relating to an underbalanced well, comprising inducing pressure variations in a fluid within a well, measuring the pressure variations, and calculating pore pressure of at least one fluid-producing formation. The pressure variations cause a change in flow rate from formations along a length of borehole, and as such a change in the production flow rate of the well. The variations in pressure are used to calculate the pore pressure. Variations in annular bottomhole pressure are induced by altering the flow rate of drilling fluid, or the density of drilling fluid or by acoustic pulsing downhole. The pore pressure, permeability and porosity of the formations is derived as a real time profile along the length of the borehole.

Abstract: A method and system for telemetry through a compressible drilling fluid during underbalanced drilling is disclosed. A reflector (110) is positioned downstream from the gas inlet (84) and causes reflected pressure waves having the same pressure polarity as incident pressure waves. A pressure sensor (92) is positioned below the reflector to sense pressure in the compressible drilling fluid. The reflector (110) can be a fixed orifice plate or an adjustable aperture. A borehole communication system is also disclosed wherein a pair of pressure sensors are positioned on either side of a flow restriction (118) located in the gas conduit leading to the gas injector. The flow restriction can be a valve used to regulate the flow rate of the gas being supplied into the drilling fluid, or it can be separate venturi or orifice plate.

Abstract: Methods and apparatus are described that characterize flows within a conduit by generating acoustic waves, and receiving acoustic energy representing at least one in-wall leaky acoustic wave mode. Attenuation of acoustic energy that has entirely propagated within the wall of the conduit is measured and evaluated in order to derive parameters relating to the fluid or fluids flowing in the conduit. The wave modes described include bulk waves and lamb waves and propagate in axial and circumferential directions.