Abstract: A method of the present disclosure for fracturing a subterranean formation (e.g., an unconventional formation) may include: injecting a fracturing fluid into the subterranean formation at a pressure sufficient to hydraulically fracture the subterranean formation. Said fracturing fluid may comprise an aqueous fluid and a zwitterionic surfactant at a concentration of less than or equal to a critical micelle concentration.

Abstract: A methodology using an interwell connectivity model for hydrocarbon management is disclosed. The interwell connectivity model may include interwell connectivity metrics indicative of fluid interconnectivity amongst pairs of wells and may be used as predictive or prescriptive for enhanced oil recovery (EOR). As predictive, the interwell connectivity model may be used to determine an effect of gas injection into the reservoir on one or more aspects of EOR, such as reservoir pressure or production rates. As prescriptive, the interwell connectivity model may be used to improve or optimize various stages of EOR, such as during drilling or construction of the extraction site, during primary depletion, or during one or more huff-and-puff cycles.

Abstract: A methodology using an interwell connectivity model for hydrocarbon management is disclosed. The interwell connectivity model may include interwell connectivity metrics indicative of fluid interconnectivity amongst pairs of wells and may be used as predictive or prescriptive for enhanced oil recovery (EOR). As predictive, the interwell connectivity model may be used to determine an effect of gas injection into the reservoir on one or more aspects of EOR, such as reservoir pressure or production rates. As prescriptive, the interwell connectivity model may be used to improve or optimize various stages of EOR, such as during drilling or construction of the extraction site, during primary depletion, or during one or more huff-and-puff cycles.

Abstract: A method for determining the porosity of a core sample can include: saturating a core sample with a nuclear magnetic resonance (NMR) saturation fluid, wherein the core sample has a permeability of 100 milliDarcy (mD) or less, to achieve a saturated core sample; taking a NMR measurement of fluids in the saturated core sample; determining a porosity of the core sample based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration.

Abstract: Systems and methods described herein provide for the estimation of the maximum reservoir pressure at which fluid can be injected into a reservoir before causing conductivity increase due to fracture/fault reactivation. An exemplary method includes computing the maximum reservoir pressure for the location of interest prior to fracture/fault reactivation at a given depleted reservoir pressure based on a computed probability of non-exceedance for a field or laboratory estimate of the maximum reservoir pressure prior to fracture/fault reactivation and a computed pressure distribution including a range of potential maximum reservoir pressures for the location of interest prior to fracture/fault reactivation at the given depleted reservoir pressure. The method also includes outputting the computed maximum reservoir pressure as the estimated maximum reservoir pressure for performing a fluid injection operation for the location of interest.

Abstract: A methodology for spatially identifying conductive regions using pressure transience for characterizing conductive fractures and subsurface regions is provided. Hydraulic fracturing is utilized to create fractures within a reservoir, thereby increasing fluid permeability of the reservoir and permitting hydrocarbon fluids to flow into a wellbore and subsequently to be produced from the hydrocarbon reservoirs. The geometry, dimensions, and extent of the fractures may significantly impact the production characteristics of the well. However, given that fractures are thousands of feet below the surface, measuring the properties of the fractures can be difficult. In order to characterize the fractures, including determining locations of conductive fractures in the subsurface, sensors are positioned in monitoring wells. Pressure changes are then induced in a well, with the sensors measuring the effect of the pressure changes.

Abstract: A method for determining the porosity of a core sample can include: submerging a core sample in a NMR saturation fluid, wherein the core sample has a permeability of 10 mD or less; exposing the fluid to a vacuum while the core sample is submerged the NMR saturation fluid for a sufficient period of time to saturate the core sample; removing the vacuum while maintaining the core sample submerged the NMR saturation fluid; taking a NMR measurement of fluids in the core sample; and determining a porosity of the core sample based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration.

Abstract: A method for determining a core sample property selected from the group consisting of a recoverable oil volume, an irreducible hydrocarbon volume, a recoverable water volume, an irreducible water volume, and any combination thereof can include: determining a porosity of a core sample, wherein the core sample has a permeability of 100 milliDarcy (mD) or less; saturating the core sample with a NMR saturation fluid; taking a first nuclear magnetic resonance (NMR) measurement of fluids in the core sample; hydraulically exchanging a hydrophobic fluid or a hydrophilic fluid in the core sample in a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid, respectively; taking a second NMR measurement of the fluids in the core sample after hydraulic exchange; and deriving the property of the core sample based on the porosity, a NMR signal to fluid volume calibration, and a comparison between the first and second NMR measurements.

Abstract: A method determining a volume of a pore type of a core sample can include: determining a porosity of a core sample, wherein the core sample has a permeability of 100 milliDarcy (mD) or less; saturating the core sample with a nuclear magnetic resonance (NMR) saturation fluid to achieve a saturated core sample; taking a NMR measurement of fluids in the saturated core sample; and deriving a volume for a pore type based on the porosity based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration, wherein the pore type is selected from the group consisting of a nanopore, a micropore, a macropore, and any combination thereof.

Abstract: A method for determining the porosity of a core sample can include: submerging a core sample in a NMR saturation fluid, wherein the core sample has a permeability of 10 mD or less; exposing the fluid to a vacuum while the core sample is submerged the NMR saturation fluid for a sufficient period of time to saturate the core sample; removing the vacuum while maintaining the core sample submerged the NMR saturation fluid; taking a NMR measurement of fluids in the core sample; and determining a porosity of the core sample based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration.

Abstract: A method determining a volume of a pore type of a core sample can include: determining a porosity of a core sample, wherein the core sample has a permeability of 100 milliDarcy (mD) or less; saturating the core sample with a nuclear magnetic resonance (NMR) saturation fluid to achieve a saturated core sample; taking a NMR measurement of fluids in the saturated core sample; and deriving a volume for a pore type based on the porosity based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration, wherein the pore type is selected from the group consisting of a nanopore, a micropore, a macropore, and any combination thereof

Abstract: A method for determining the porosity of a core sample can include: saturating a core sample with a nuclear magnetic resonance (NMR) saturation fluid, wherein the core sample has a permeability of 100 milliDarcy (mD) or less, to achieve a saturated core sample; taking a NMR measurement of fluids in the saturated core sample; determining a porosity of the core sample based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration.

Abstract: A method for determining a core sample property selected from the group consisting of a recoverable oil volume, an irreducible hydrocarbon volume, a recoverable water volume, an irreducible water volume, and any combination thereof can include: determining a porosity of a core sample, wherein the core sample has a permeability of 100 milliDarcy (mD) or less; saturating the core sample with a NMR saturation fluid; taking a first nuclear magnetic resonance (NMR) measurement of fluids in the core sample; hydraulically exchanging a hydrophobic fluid or a hydrophilic fluid in the core sample in a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid, respectively; taking a second NMR measurement of the fluids in the core sample after hydraulic exchange; and deriving the property of the core sample based on the porosity, a NMR signal to fluid volume calibration, and a comparison between the first and second NMR measurements.

Abstract: A structure for collecting liquid droplets from an aerosol can have a structure and properties that are selected for efficient liquid collection. In particular, the strand radius and spacing of a mesh, and a material for coating the mesh, can be selected to provide efficient collection of water droplets from fog.

Abstract: A structure for collecting liquid droplets from an aerosol can have a structure and properties that are selected for efficient liquid collection. In particular, the strand radius and spacing of a mesh, and a material for coating the mesh, can be selected to provide efficient collection of water droplets from fog.