Abstract: Steam quality is measured by mixing the steam with a small amount of surfactant to convert the steam to a stable foam, passing the stable foam through a capillary tube to determine foam quality (volume of vapor per volume of vapor and liquid) by measuring the streaming potential coupling coefficient of the foam passing through the tube, and converting foam quality (volume per volume) to steam quality (mass of vapor per mass of vapor and liquid) based upon the fluid density of the liquid-water and water-vapor phase of the steam.

Abstract: In a hydrocarbon-producing well penetrating an unconsolidated hydrocarbon reservoir, the azimuthal direction of the maximum in-situ horizontal compressive stress within the reservoir having non-uniform horizontal tectonic stresses surrounding the well is determined. Perforations are formed in the reservoir, or in the casing if the well is cased, oriented in the azimuthal direction of the determined maximum in-situ horizontal compressive stress. Thereafter, hydrocarbon production is initiated from the well through the perforations whereby the potential for sand production along with produced hydrocarbons is minimized.

Abstract: An improved method for hydraulically fracturing a formation or reservoir where a thermo-setting gellable mixture is utilized. This thermo-setting mixture is foamed either at the surface or in situ under fracturing pressures and conditions. The mixture and carrier fluid is of a composition such that the foamed mixture has a viscosity of sufficient magnitude to cause a created fracture to grow while the foamed mixture is kept under fracturing pressure and conditions. Once a fracture of a desired size and length has been generated, the resin is ignited and thermally set thus forming a porous hardened solid within the fracture thereby holding the fracture open. Once combustion is finished, no spent fracturing fluids or load fluids remain to be recovered. This porous solid props the fracture open thereby increasing the conductivity of the formation or reservoir and fluid flow therefrom.

Abstract: An oxygenated foam is injected into a loosely consolidated, clay-containing sandstone formation surrounding a well penetrating a hydrocarbon-bearing reservoir. Combustion is initiated between the oxygenated foam and hydrocarbons within the reservoir to burn the formation and form said consolidated zone around the well that acts as a barrier to the passage of sand into the well along with produced hydrocarbons.

Abstract: An oxygenated foam is injected into a hydrocarbon-bearing reservoir within a diatomite-containing subsurface formation to hydraulically form a fracture within the reservoir. Combustion is initiated between the oxygenated foam and hydrocarbons within the reservoir to burn the formation and alter diatomite within the burned area into a hardened, more highly permeable material. The reservoir may again be fractured to shatter the hardened diatomite to further increase reservoir permeability and form a self-propped fracture within the reservoir.

Abstract: A method and apparatus is provided to determine the amount of oil and water or brine in a representative core sample of reservoir rock at an overburden stress which approximates reservoir stress conditions. The core sample is initially saturated with reservoir hydrocarbon (crude oil) and aqueous fluids (water or brine). The core sample is surrounded with an elastic jacket, or sleeve, and placed in a confining pressure vessel that simulates reservoir overburden stress on the core sample. The hydrocarbon (oil) fluids and aqueous fluids (water or brine) are than extracted from the core sample with a solvent capable of dissolving both aqueous and hydrocarbon fluids. The solvent and aqueous fluids are separated from the hydrocarbon fluids by evaporation. Thereafter the aqueous fluids are separated from the solvent by extraction. The amounts of oil and aqueous fluids from the sample may be separately determined.

Abstract: A method for time lapse electric logging in a cased hole in which electrodes are implanted in the casing or the hole is completed with a gravel packed non conductive, perforated liner that allows an open hole logging tool to be used for time-lapse logging. Thereafter, the implemented electrodes or a self-potential (SP) logging tool are used to monitor a steam-flooding EOR method by detecting two-phase flow with time lapse logging. A potential drop between the surface and zones of interest is measured with electrodes installed in a non-conductive casing or the SP logging tool.

Abstract: A porous rock is saturated with a first fluid and electrical resistivity is measured along its length. A second fluid, immiscible with the first fluid, is injected into the porous rock at a first flow rate. This injection continues until displacement of the first fluid from the porous rock ceases and the pressure drop along the porous rock becomes constant, indicating a first residual fluid saturation equilibrium. The foregoing is repeated for a plurality of increasing second fluid injection flow rates to effect electrical resistivity measurements at decreasing residual fluid saturation equilibriums. The method may then be repeated substituting the second fluid for the first and vice versa to perform an imbibition experiment.

Abstract: A coring tool is lowered to the bottom of a wellbore through a subsurface formation. A coring bit at the lower end of the coring tool draws a core sample of the subsurface formation at the bottom of the wellbore into the coring tool. A coring barrel is positioned along the coring tool above and in juxtaposition with the coring bit. The core sample is drawn into a hollow cylindrical split member within the coring barrel, such member being split into two halves in an axial direction and comprised of a material effectively transparent to nuclear radiation. A wireline raises the split member containing the core sample upward through the coring tool to the surface of the earth. The core sample is tested for a nuclear radiation characteristic through the nuclear radiation transparent material of the split member at the well site. The split member is then reused to obtain a plurality of cores from the subsurface formation.

Abstract: A two-phase fluid, flow having a first fluid and an immiscible second fluid, is passed through a core sample. The core sample is scanned with X-rays to produce a display of fluid distribution within the core sample. Electrical resistivity is measured along the length of the core sample for those intervals having uniform first fluid distribution. The two-phase flow is continued to repetitively decrease the first fluid saturation in a plurality of drainage cycles with electrical resistivity being again measured for each drainage cycle. Thereafter, the two-phase fluid flow is continued to repetitively increase the first fluid saturation in a plurality of imbibition cycles with electrical resistivity being again measured for each imbibition cycle.

Abstract: A core sample of a porous rock having a wettability representative of a subterranean formation is saturated with a first medium. This first medium is then displaced with an immiscible second medium. Capillary pressure versus wetting phase saturation is measured during the displacement of the first medium with the second medium within the core sample. Mercury is injected into an evacuated core sample of the porous rock, mercury vapor acting as a wetting phase on the porous rock. Capillary pressure versus wetting phase saturation is measured during mercury injection on the evacuated core sample. The ratio of the two capillary pressure versus wetting phase saturation measurements is determined and taken to be an indicator of the wettability of different size pore throats in the porous rock.

Abstract: A material sample representative of a subsurface formation is tested for its dynamic interaction with a coring fluid. The material sample is subjected to a pressurized and agitating coring fluid to simulate a coring operation. Thereafter the material sample is x-ray scanned to identify the extent of coring fluid invasion during the dynamic interaction of the material sample and the coring fluid.

Abstract: A core sample from a subterranean formation is shaped to provide a plurality of parallel, planar outer surfaces. Electrical resistivity is measured in each of the azimuthal directions through the core sample which are perpendicular to each of the pairs of parallel, planar outer surfaces for each of a plurality of differing fluid saturations within the core sample. A logarithmic plot is made of measured resistivity versus water saturation for each of the azimuthal directions through the core sample for which resistivity was measured. If the same logarithmic plot is obtained for all measured azimuthal directions, the core sample is identified as being electrically isotropic. If different logarithmic plots are obtained for at least 2 azimuthal directions the core sample is identified as being electrically anisotropic.

Abstract: A core sample from a subterranean reservoir is placed in a pressure cell holder and the core pressure is measured at a plurality of pressure points along the core before and during fluid flooding. A computed tomography (CT) scanning system provides images of the density distribution within the core sample during such waterflooding. Fluid saturation, determined from these CT images, and pressure gradients, determined from the pressure measurements are used to determine the relative permeability of the subterranean reservoir.

Abstract: A sample of material is rotated within a pair of parallel, spaced-apart laser beams. Variations in the diameter of the sample are determined with azimuth from the amounts of the laser beams intercepted by the sample as it rotates about an axis perpendicular to the plane of the laser beams. The sample is translated along this axis within the path of the laser beams so that the diameter of the sample is determined for a plurality of spaced-apart planes through the sample perpendicular to the axis of rotation. The deformation of the material with stress is determined by measuring the variations in diameter of the sample as the stress on the sample is changed.

Abstract: A core sample of an earth formation is obtained by drilling with a coring bit and circulating a coring fluid through the coring bit. The coring fluid contains no mud solids for contaminating the core sample or, in the alternative, contains drilling mud mixed with a bulk material which invades the core sample and occupies the core sample pore spaces preferentially over mud solids. This bulk material is more readily removed from the core sample by cleaning than mud solids.

Abstract: Measurements of reservoir characteristics of a core sample of a subsurface formation are carried out with the core sample being subjected to pressure cycling. Pore volume changes during such pressure cycling are measured. Pore compressibility is determined from a plot of the measured pore volume change versus pressure. Scanning of the core sample with X-rays each pressure cycle identifies the pressure at which fracturing is initiated.

Abstract: Hydrocarbons are produced from a subterranean reservoir by maintaining the effective reservoir pressure below the reservoir crushing pressure during a first production period, causing the effective reservoir pressure to exceed the reservoir crushing pressure after such first production period so as to crush the reservoir and reduce the reservoir permeability, and then producing hydrocarbons from the reservoir during a second production period in which hydrocarbon production is enhanced due to better sweep efficiency as a result of the lowered permeability of the reservoir.

Abstract: A core sample invaded by drilling mud is scanned with X-rays and computed tomographic images are produced. The images are calibrated to a density scale based on the barite content of the drilling mud. The mud solid volume in the pores of the core sample are determined from the density contrast created in the computed tomographic images by the presence of barite in the core sample. This mud solid volume is used to provide a corrected porosity measurement on the core sample.

Abstract: A substantially cylindrical sample of a porous material is surrounded by an elastic jacket and placed in a confining pressure cell. Pressure is supplied to the cell to press the jacket into contact with the surface of the sample. The pressure is varied over a plurality of pressure points and is scanned at a plurality of locations with X-rays at each such pressure point. A computed tomographic image is produced for each X-ray scan. Conformance of the jacket to the sample is determined from these computed tomographic images and a range of confining pressure is determined over which parameters of the sample may be measured without being affected by improper conformance of the jacket to the surface of the sample. The sample structure is monitored with these tomographic images for fractures produced due to the increase of pressure. The fracture starting point is determined to be interior or surface related.