A lithology-independent method of well logging to estimate the pore size within a formation containing natural gas. The method makes use of a pulsed NMR logging tool utilizing a recovery time that is greater than the relaxation time of hydrocarbon gas within the formation. In a preferred embodiment, two different NMR logs are obtained: one with a recovery time significantly shorter than the longitudinal relaxation time, T1, of the gas and one with a recovery time equal to or longer than T1. The amplitudes of the two logs are subtracted to determine a restricted diffusion coefficient of the gas. The restricted diffusion coefficient can then be used to estimate pore size and permeability of the formation by means of a relationship between measured restricted diffusion coefficient, surface to volume ratio, and estimated bulk diffusion ratio of the gas.

NMR logging of natural gas reservoirs

An in situ process for treating an oil containing formation is provided. The process may include providing heat from one or more heaters to at least a portion of the formation. The heat may be allowed to transfer from the one or more heaters to a part of the formation such that heat from the one or more heat sources pyrolyzes at least some hydrocarbons within the part. Hydrocarbons may be produced from the formation.

In situ thermal processing of an oil reservoir formation

In an embodiment, a method of treating a kerogen and liquid hydrocarbon containing formation in situ may include providing heat from one or more heat sources to at least a portion of the formation. Heat may be allowed to transfer from the one or more heat sources to a part of the formation. In some embodiments, at least a portion of liquid hydrocarbons in the part may be mobilized. At least a portion of kerogen in the part may be pyrolyzed. In certain embodiments, a pressure within at least a part of the formation may be controlled. The pressure may be controlled to be at least about 2.0 bars absolute. A mixture may be produced from the formation.

In situ recovery from a kerogen and liquid hydrocarbon containing formation

A process may include providing heat from one or more heaters to at least a portion of a subsurface formation. Heat may transfer from one or more heaters to a part of a formation. In some embodiments, heat from the one or more heat sources may pyrolyze at least some hydrocarbons in a part of a subsurface formation. Hydrocarbons and/or other products may be produced from a subsurface formation. Certain embodiments describe apparatus, methods, and/or processes used in treating a subsurface or hydrocarbon containing formation.

Thermal processes for subsurface formations

A oil shale formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H 2 , and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a pyrolysis temperature. Heat sources may be used to heat the formation. The heat sources may be positioned within the formation in a selected pattern.

In situ thermal processing of an oil shale formation using a pattern of heat sources

NMR imaging methods are provided for determining the spatial petrophysical properties of materials. These methods employ the generation of separate Mo, T1 and T2 images from which various petrophysical characteristics may be obtained, such as free fluid index, porosity, pore sizes and distributions, capillary pressure, permeability, formation factor and clay content.

NMR imaging of materials

NMR imaging methods are provided for determining spatial diffusion coefficients, formation resistivity factors, mean pore size, and permeability of a porous material. The imaging methods employ a constant magnetic field and two images are obtained for the material, one with a non-imaging gradient and one without a non-imaging gradient. These images are combined to produce diffusion coefficients.

William P. Rothwell

Papers

NMR imaging of materials

NMR imaging of materials for transport properties