Abstract: This invention relates generally to methods for monitoring directional flood front movement during oil recovery and more specifically to methods for monitoring flood front movement of flooding agent injected into subsurface formations. The method comprises detecting physical properties of subsurface formation and injection of a flooding agent into said formation through at least one injection well thus forcing reservoir oil movement toward at least one production well. The flooding agent is a highly dispersed gas-liquid mixture having size of gas bubbles not exceeding an average diameter of the pores of said oil-bearing reservoir. The method further comprises detecting the same physical properties of the formation at the same area after flooding and monitoring the flood front profile by registrating changes in the physical properties of the formation caused by the arrival of said flood front.

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: This invention relates generally to methods for monitoring directional flood front movement during oil recovery and more specifically to methods for monitoring flood front movement of flooding agent injected into subsurface formations. The method comprises detecting physical properties of subsurface formation and injection of a flooding agent into said formation through at least one injection well thus forcing reservoir oil movement toward at least one production well. The flooding agent is a highly dispersed gas-liquid mixture having size of gas bubbles not exceeding an average diameter of the pores of said oil-bearing reservoir. The method further comprises detecting the same physical properties of the formation at the same area after flooding and monitoring the flood front profile by registrating changes in the physical properties of the formation caused by the arrival of said flood front.

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 invention relates to the oil and gas industry, more specifically, to the development of heavy oil and asphaltic bitumen deposits. The method of determining the filtration properties of rocks comprises providing contrasting temperature fluid circulation in the well; supplying the fluid is in the quantity required for partial fluid absorption in the annulus; stopping fluid circulation in the well; measuring temperature along the well bore as from circulation stoppage and until the achievement of a thermally stable condition; obtaining a temperature vs time curve along the well bore; determining the filtration properties of rocks using a data averaging model. Fluid viscosity is modified by chemical additives for non-horizontal wells.

Abstract: Method to determine the point of the gas leak from the buried pipeline located in the ditch under the soil, providing positioning at least one fiber-distributed temperature transmitter in the soil over the pipeline; the fiber-distributed temperature transmitter's readings allow to determine the leak point presence and location; the method is characterized by the fact that the fiber-distributed temperature transmitter is located above the pipeline surface; in the ground, between the pipeline and the transmitter or over the transmitter a shield is mounted which deflects the gas flow (in case of leakage) in the upper central part of the ditch adjacent to the transmitter and preventing the gas flow to the ditch peripheral areas located far away from the transmitter; the temperature is measured continuously and by the temperature drop the gas leak and its location is determined.