Vinegar Technologies LLC

Xinglin Wang

Harold J Vinegar

Philip M Singer

George J Hirasaki

Zeliang Chen

Eva Vinegar

Yunke Liu

A method for separating liquid-like (T) from solid-like (T)H NMR transverse relaxation times in porous media uses novel pulse sequences together with aH NMR spectrometer optimized for geological core samples. The method is applied to obtain 1D Tdistributions and 2D T-Tmaps in organic-rich chalks for quantification of liquid-like signal (micropore fluids, meso-macropore fluids, fluids dissolved in organic matter, and clay-bound water) and solid-like signal (kerogen, bitumen, and clay hydroxyls). The novel pulse sequences comprise a solid-echo, which detects more solid-like signal than an FID. The method is used for fluid typing in micro/meso-macro pores, clay mineral identification, determination of kerogen content, and quantification of solvent-extracted bitumen versus bitumen expelled from kerogen due to swelling from dissolved hydrocarbons. The method is used to quantify the asphaltene, resin, aromatic, and/or saturate content of bitumen in the rock.

Method of determining solid and liquid components in sedimentary rocks using NMR relaxation

This invention is useful for determining the permeability of a geological formation usingH NMR diffusion measurements acquired in the laboratory and using downholeH NMR well logging. The current technology for obtaining formation permeability downhole using NMR is not adequate for low-permeability, unconventional source rock formations with high organic content. This new method uses laboratoryH NMR diffusion measurements for creating continuous downhole well logs of the mobile-hydrocarbon permeability of the hydrocarbon-filled pore space of downhole geological formations.

Method of estimating permeability using NMR diffusion measurements

The following invention is used for determining the relative permeability of a fluid in a rock for three different phases: water, oil, and gas, in both conventional and unconventional formations. The permeability of a phase describes how much it can flow in porous media given a pressure gradient and is useful in evaluating reservoir quality and productivity. The following invention is a method to determine the three-phase relative permeabilities in both conventional and unconventional formations using NMR restricted diffusion measurements on core with NMR-active nuclei, combined with centrifugation of the core. In addition, the tortuosity, pore size (surface-to-volume ratio), fluid-filled porosity, and permeability is determined for each of the three phases in a rock.

Determination of fluid-phase-specific petrophysical properties of geological core for oil, water and gas phases

New methods for determining the volumetric composition and saturation of methane and NGLs (natural gas liquids: ethane, propane, butane, and pentane) in a petroleum reservoir combining NMR (nuclear magnetic resonance) logging and NMR core analysis and for determining the mean pore-size and tortuosity of the light hydrocarbon-filled porosity in a petroleum reservoir using NMR core analysis.

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Houston, TX, United States of America

Xinglin Wang