Abstract: Systems and methods for monitoring a crude oil blending process use nuclear magnetic resonance (NMR) sensors which investigate properties of a plurality of crude oil streams that are mixed together to form a crude oil blend. An NMR sensor is also used to investigate the properties of the crude oil blend. The investigated properties may include viscosity. Resulting determinations may be used to control the input streams so that the output stream meets desired criteria. Additional sensors such as spectroscopy sensors, viscometers, and densitometers may be used in conjunction with the NMR sensors.

Abstract: Methods and systems are provided that combine NMR and IR spectroscopy measurements on a rock sample to determine data representing at least one property of the rock sample. In one embodiment, cuttings can be split into first and second lots. Results of an NMR measurement performed on the first lot of cuttings without cleaning can be analyzed to determine pore volume of the cuttings. Results of an IR spectroscopy measurement performed on the second lot of cuttings after solvent cleaning can be analyzed to determine matrix density of the cuttings. Porosity can be determined from the pore volume and matrix density of the cuttings. In another embodiment, combined NMR and IR spectroscopy measurements can be performed on an unprepared rock sample (without solvent cleaning) to characterize properties of kerogen in the rock sample and porosity. In another aspect, a method is provided that employs multi-nucleic NMR measurements to determine porosity.

Abstract: Methods and systems are provided that combine NMR and IR spectroscopy measurements on a rock sample to determine data representing at least one property of the rock sample. In one embodiment, cuttings can be split into first and second lots. Results of an NMR measurement performed on the first lot of cuttings without cleaning can be analyzed to determine pore volume of the cuttings. Results of an IR spectroscopy measurement performed on the second lot of cuttings after solvent cleaning can be analyzed to determine matrix density of the cuttings. Porosity can be determined from the pore volume and matrix density of the cuttings. In another embodiment, combined NMR and IR spectroscopy measurements can be performed on an unprepared rock sample (without solvent cleaning) to characterize properties of kerogen in the rock sample and porosity. In another aspect, a method is provided that employs multi-nucleic NMR measurements to determine porosity.

Abstract: Nuclear magnetic resonance (NMR) relaxation and/or diffusion measurements are used to deduce fluid compositional information such as a chain-length distribution, which may then be used to predict the true boiling points (TBP) of a sample of a complex hydrocarbon fluid mixture, such as a crude oil. The NMR measurements may be considered a fast and portable proxy measurement in estimating fluid TBP distributions in lieu of distillation methods, or the simulated distillation by gas chromatography.

Abstract: Nuclear magnetic resonance (NMR) relaxation and/or diffusion measurements are used to deduce fluid compositional information such as a chain-length distribution, which may then be used to predict the true boiling points (TBP) of a sample of a complex hydrocarbon fluid mixture, such as a crude oil. The NMR measurements may be considered a fast and portable proxy measurement in estimating fluid TBP distributions in lieu of distillation methods, or the simulated distillation by gas chromatography.

Abstract: Methods and systems are provided that combine NMR and IR spectroscopy measurements on a rock sample to determine data representing at least one property of the rock sample. In one embodiment, cuttings can be split into first and second lots. Results of an NMR measurement performed on the first lot of cuttings without cleaning can be analyzed to determine pore volume of the cuttings. Results of an IR spectroscopy measurement performed on the second lot of cuttings after solvent cleaning can be analyzed to determine matrix density of the cuttings. Porosity can be determined from the pore volume and matrix density of the cuttings. In another embodiment, combined NMR and IR spectroscopy measurements can be performed on an unprepared rock sample (without solvent cleaning) to characterize properties of kerogen in the rock sample and porosity. In another aspect, a method is provided that employs multi-nucleic NMR measurements to determine porosity.

Abstract: Systems and methods for monitoring a crude oil blending process use nuclear magnetic resonance (NMR) sensors which investigate properties of a plurality of crude oil streams that are mixed together to form a crude oil blend. An NMR sensor is also used to investigate the properties of the crude oil blend. The investigated properties may include viscosity. Resulting determinations may be used to control the input streams so that the output stream meets desired criteria. Additional sensors such as spectroscopy sensors, viscometers, and densitometers may be used in conjunction with the NMR sensors.

Abstract: In one possible implementation, a computer-readable tangible medium includes instructions that direct a processor to access one or more wellbore properties and a plurality of well fluid properties. Instructions are also present that direct the processor to access a distance between a proposed location of an inlet to a multiphase production logging tool and an emulsion generation location in a wellbore. Further instructions instruct the processor to predict a drop size distribution of emulsified water in the well fluid at the proposed location of the inlet to the multiphase production logging tool. Additional instructions instruct the processor to compute an estimated error in water holdup detected by the multiphase production logging tool based on the drop size distribution, and recommend deployment of a pulsed neutron logging tool in the wellbore when the estimated error in the water holdup is above a preset threshold.

Abstract: Methods may include emplacing an emulsion into an annular region of a Taylor-Couette (TC) device; flowing the emulsion through the annular region created by a first annular surface and a second annular surface; contacting one or more shear sensors disposed on a surface of the annular region with the flowing emulsion, wherein contact with the one or more shear sensors generates a signal that scales with shear stress exerted by the flowing emulsion, and determining one or more of wall shear stress from the signal obtained from the one or more shear sensors. Methods may also include determining the apparent viscosity of the fluid composition from the stress measured on the wall of the TC device.

Abstract: Methods may include emplacing an emulsion into an annular region of a Taylor-Couette (TC) device; flowing the emulsion through the annular region created by a first annular surface and a second annular surface; contacting one or more shear sensors disposed on a surface of the annular region with the flowing emulsion, wherein contact with the one or more shear sensors generates a signal that scales with shear stress exerted by the flowing emulsion, and determining one or more of wall shear stress from the signal obtained from the one or more shear sensors. Methods may also include determining the apparent viscosity of the fluid composition from the stress measured on the wall of the TC device.

Abstract: In one possible implementation, a computer-readable tangible medium includes instructions that direct a processor to access one or more wellbore properties and a plurality of well fluid properties. Instructions are also present that direct the processor to access a distance between a proposed location of an inlet to a multiphase production logging tool and an emulsion generation location in a wellbore. Further instructions instruct the processor to predict a drop size distribution of emulsified water in the well fluid at the proposed location of the inlet to the multiphase production logging tool. Additional instructions instruct the processor to compute an estimated error in water holdup detected by the multiphase production logging tool based on the drop size distribution, and recommend deployment of a pulsed neutron logging tool in the wellbore when the estimated error in the water holdup is above a preset threshold.

Abstract: Apparatus for heating of hydrocarbon fluid where a traveling waveguide structure is configured to confine traveling wave electromagnetic radiation within its interior chamber and to contain hydrocarbon fluid that is subject to heating by such traveling wave electromagnetic radiation. The apparatus can be configured to heat hydrocarbon fluid to a reaction temperature suitable for visbreaking of the hydrocarbon fluid. The reaction temperature can be in the range of 350° C. to 500° C., which is suitable for visbreaking of heavy oil.

Abstract: A reservoir sampling apparatus comprising at least one probe adapted to provide a fluid flow path between a formation and the inner of the apparatus with a heating projector adapted to project heat into the formation surrounding the probe and a controller to maintain the temperature in the formation below a threshold value.

Abstract: Methods of treating a subterranean formation as a portion of steam-assisted gravity drainage operation including providing a fluid containing a diverting agent, injecting the fluid into a first wellbore, allowing the diverting agent to divert fluid placement, performing steam-assisted gravity drainage, and producing formation fluids from a second wellbore.

Abstract: A reservoir sampling apparatus comprising at least one probe adapted to provide a fluid flow path between a formation and the inner of the apparatus with a heating projector adapted to project heat into the formation surrounding the probe and a controller to maintain the temperature in the formation below a threshold value.

Abstract: A reservoir sampling apparatus (20) is described having at least one probe (26) adapted to provide a fluid flow path between a formation and the inner of the apparatus with the flow path being sealed from direct flow of fluids from the borehole annulus with a heating projector (251) adapted to project heat into the formation surrounding the probe and a controller (253) to maintain the temperature in the formation below a threshold value.

Abstract: A reservoir sampling apparatus (20) is described having at least one probe (26) adapted to provide a fluid flow path between a formation and the inner of the apparatus with the flow path being sealed from direct flow of fluids from the borehole annulus with a heating projector (251) adapted to project heat into the formation surrounding the probe and a controller (253) to maintain the temperature in the formation below a threshold value.

Abstract: A method for generating and characterizing an emulsion. The method provides a Couette device having first and second cylindrical members that define an annulus between them. The second cylindrical member is rotatably driven with respect to the first cylindrical member. Two or more substances each in a non-emulsified state are injected into the annulus. The Couette device is operated in a first mode to generate an emulsion from the two or more substances. The Couette device is also operated in a second mode to measure various attributes of the emulsion.

Abstract: A method for generating and characterizing an emulsion. The method provides a Couette device having first and second cylindrical members that define an annulus between them. The second cylindrical member is rotatably driven with respect to the first cylindrical member. Two or more substances each in a non-emulsified state are injected into the annulus. The Couette device is operated in a first mode to generate an emulsion from the two or more substances. The Couette device is also operated in a second mode to measure various attributes of the emulsion.

Abstract: Described herein are methods for optimizing petroleum reservoir analysis and sampling using a real-time component wherein heterogeneities in fluid properties exist. The methods can help predict the recovery performance of oil such as, for example, heavy oil, which can be adversely impacted by fluid property gradients present in the reservoir.