Abstract: Embodiments of the present disclosure generally relate to methods and formulations for enhanced oil recovery. In an embodiment, a method for treating oil-containing porous media for oil recovery includes introducing oil-containing porous media with a surfactant formulation described herein. Methods can be utilized for, e.g., wettability reversal or oil recovery. Surfactant formulations are also described.

Abstract: A method and device for pore network extraction by one or more processing units are disclosed. The method may include decomposing the global image into a set of overlapping subimages, extracting a set of subnetworks corresponding to the set of overlapping subimages, obtaining a cohesive pore network representing the porous media sample by merging the set of subnetworks, and outputting the cohesive pore network.

Abstract: A method and system for non-destructive characterization of porous media samples are disclosed. The method for porous media characterization by one or more central processing units (CPUs) includes obtaining one or more segmented images from a set of images of a porous media sample, determining one or more fluid-fluid interfaces (FFIs) within one or more segmented images for each pixel of the one or more segmented images, and based at least in part on the FFIs, extracting one or more characteristics of the porous media sample.

Abstract: Embodiments of the present disclosure generally relate to apparatus and methods for foam generation, and to apparatus and methods for evaluation of foam systems. In an embodiment, a method of analyzing foam properties includes delivering a foaming composition and a gas to a housing at a pressure of 500 psi to 6,000 psi and a temperature of 35° C. to 150° C., the housing containing an unconsolidated porous media. The method further includes flowing the foaming composition and the gas through the housing, and forming a foam by an interaction of the foaming composition, the gas, and the unconsolidated porous media. The method further includes directing the foam from the housing to a visualization chamber, the visualization chamber in fluid communication with the housing, and measuring a foam characteristic via the visualization chamber. The characteristic may include foam half-life, pressure drop through the unconsolidated media, and/or apparent viscosity of the foam.

Abstract: A method and system for predicting dynamic two-phase fluid flow in a mixed-wet porous medium by one or more central processing units (CPUs), comprising generating a set of movements of main terminal menisci (MTMs) of a two-phase fluid within a pore network model (PNM) of a porous media sample having a set of pore elements; by generating a pressure field for each of the set of movements of MTMs based on at least an inlet capillary pressure or a set of flow injection boundary conditions; identifying a set of local capillary pressures and a set of arc meniscus (AM) locations based on the pressure field; identifying a set of fluid displacement potentials based on at least the set of local capillary pressures and a set of threshold capillary pressures; and identifying a highest positive fluid displacement potential from a set of fluid displacements.

Abstract: Embodiments described herein generally relate to new methods and apparatus for characterizing porous materials, such as nanoporous materials. In an embodiment, a gravimetric method for characterizing a nanoporous material is provided. The gravimetric method includes contacting a nanoporous material with an adsorbate gas, the nanoporous material positioned inside a core holder. The gravimetric method further includes collecting adsorption data, desorption data, or combinations thereof, the adsorption data and desorption data comprising gravimetric data. The gravimetric method further includes plotting an adsorption isotherm from the adsorption data, a desorption isotherm from the desorption data, or combinations thereof. The gravimetric method further includes converting the gravimetric data from gravimetric values to volumetric values. The gravimetric method further includes selecting a pore geometry for the nanoporous material.

Abstract: Embodiments of the present disclosure generally relate to core holders and uses thereof in, for example, core-flood testing. In an embodiment is provided a core holder. The core holder includes a core tube defining an outside diameter of the core holder, the core tube formed of an X-ray transparent material. The core holder further includes an internal sleeve in the core tube, the internal sleeve formed of a flexible material, the internal sleeve comprising: an inner diameter defining an interior volume of the core holder and adapted to accommodate a core sample; and an outer diameter. The core holder further includes a first end piece and a second end piece opposite the first end piece, each of the first end piece and the second end piece: adhered to an outer diameter of the core tube; and adjacent to a confining fluid chamber.

Abstract: Embodiments of the present disclosure generally relate to apparatus and methods for foam generation, and to apparatus and methods for evaluation of foam systems. In an embodiment, a method of analyzing foam properties includes delivering a foaming composition and a gas to a housing at a pressure of 500 psi to 6,000 psi and a temperature of 35° C. to 150° C., the housing containing an unconsolidated porous media. The method further includes flowing the foaming composition and the gas through the housing, and forming a foam by an interaction of the foaming composition, the gas, and the unconsolidated porous media. The method further includes directing the foam from the housing to a visualization chamber, the visualization chamber in fluid communication with the housing, and measuring a foam characteristic via the visualization chamber. The characteristic may include foam half-life, pressure drop through the unconsolidated media, and/or apparent viscosity of the foam.

Abstract: Embodiments relate to methods and materials for foam production in enhanced oil recovery operations and to foaming agents, gas mobility control agents for use in porous media, compositions comprising such agents, methods for using such agents, methods for generating foams, and systems for enhanced oil recovery. In an embodiment, a method for recovery of oil from a porous rock formation includes contacting a foaming fluid and a surfactant solution with the porous rock formation, and generating a foam comprising the foaming fluid and the surfactant solution. The method further includes mobilizing oil from the porous rock formation by contacting the porous rock formation with the foam, and collecting at least a portion of the mobilized oil.

Abstract: Embodiments of the present disclosure generally relate to methods and apparatus for enhanced oil recovery. In an embodiment, a method of enhanced oil recovery from a reservoir is provided. The method includes determining a three-dimensional molecular association between simulated oil and a simulated surface using molecular dynamics, and selecting a reservoir additive from a plurality of additives. The method further includes introducing the reservoir additive to the reservoir, and recovering oil from the reservoir using the reservoir additive. Methods of testing a candidate chemical or candidate formulation for use in enhanced oil recovery, and methods of determining an effect of a candidate chemical or formulation of candidate chemicals for use in enhanced oil recovery are also described. Oil extraction apparatus are also provided.

Abstract: Methods and materials for foam production in enhanced oil recovery operations are described herein. More specifically, embodiments of the present disclosure relate to foaming agents, gas mobility control agents for use in porous media, compositions comprising such agents, methods for using such agents, methods for generating foams, and systems for enhanced oil recovery. In an embodiment, a method for recovery of oil from a porous rock formation is provided. The method includes contacting a foaming fluid and a surfactant solution described herein with the porous rock formation, and generating a foam comprising the foaming fluid and the surfactant solution. The method further includes mobilizing oil from the porous rock formation by contacting the porous rock formation with the foam; and collecting at least a portion of the mobilized oil.

Abstract: Embodiments of the present disclosure generally relate to apparatus, systems, and methods for characterizing fluid-solid systems. In an embodiment, a method includes placing a porous rock sample in a core holder, contacting the porous rock sample with a fluid to create a fluid-solid system inside the core holder, automatically adjusting a temperature and/or pressure of the fluid-solid system to a preselected value via a processor and at least one automated valve, monitoring the fluid-solid system for equilibrium, recording a value for temperature, pressure, and/or mass of the fluid-solid system, performing an action based on the recorded data, and repeating the adjusting, monitoring, recording, and performing operations to produce a thermodynamic data characteristic of the fluid-solid system. In one example, the performing operation includes analyzing a pressure signal for stationarity by performing an Augmented Dickey-Fuller (ADF) test and/or a Kwiatkowski-Phillips-Schmidt-Shin (KPSS) test.

Abstract: Embodiments of the present disclosure generally relate to methods and formulations for enhanced oil recovery. In an embodiment, a method for treating oil-containing porous media for oil recovery includes introducing oil-containing porous media with a surfactant formulation described herein. Methods can be utilized for, e.g., wettability reversal or oil recovery. Surfactant formulations are also described.

Abstract: Embodiments of the present disclosure generally relate to apparatus, systems, and methods for characterizing fluid-solid systems. In an embodiment, a method includes placing a porous rock sample in a core holder, contacting the porous rock sample with a fluid to create a fluid-solid system inside the core holder, automatically adjusting a temperature and/or pressure of the fluid-solid system to a preselected value via a processor and at least one automated valve, monitoring the fluid-solid system for equilibrium, recording a value for temperature, pressure, and/or mass of the fluid-solid system, performing an action based on the recorded data, and repeating the adjusting, monitoring, recording, and performing operations to produce a thermodynamic data characteristic of the fluid-solid system. In one example, the performing operation includes analyzing a pressure signal for stationarity by performing an Augmented Dickey-Fuller (ADF) test and/or a Kwiatkowski-Phillips-Schmidt-Shin (KPSS) test.

Abstract: A method and device for pore network extraction by one or more processing units are disclosed. The method may include decomposing the global image into a set of overlapping subimages, extracting a set of subnetworks corresponding to the set of overlapping subimages, obtaining a cohesive pore network representing the porous media sample by merging the set of subnetworks, and outputting the cohesive pore network.

Abstract: Embodiments of the present disclosure generally relate to apparatus, systems, and methods for characterizing fluid-solid systems. In an embodiment, a method includes placing a porous rock sample in a core holder, contacting the porous rock sample with a fluid to create a fluid-solid system inside the core holder, automatically adjusting a temperature and/or pressure of the fluid-solid system to a preselected value via a processor and at least one automated valve, monitoring the fluid-solid system for equilibrium, recording a value for temperature, pressure, and/or mass of the fluid-solid system, performing an action based on the recorded data, and repeating the adjusting, monitoring, recording, and performing operations to produce a thermodynamic data characteristic of the fluid-solid system. In one example, the performing operation includes analyzing a pressure signal for stationarity by performing an Augmented Dickey-Fuller (ADF) test and/or a Kwiatkowski-Phillips-Schmidt-Shin (KPSS) test.

Abstract: A method and system for predicting dynamic fluid flow in a water-wet porous medium by one or more central processing units (CPUs), comprising generating a set of possible movements of displacement fronts within a set of pore elements within a pore-network representation of a porous media or rough-walled fracture sample, based on the set of possible movements, generating pressure fields for each of the set of possible movements, based on the pressure fields, determining a highest displacement potential for the set of possible movements, and performing a displacement based on the highest displacement potential.

Abstract: A method and system for generating a heterogeneous plug for a porous media sample by one or more central processing units (CPUs), including duplicating one or more sample pore elements to fill one or more components of a heterogeneous plug, constructing a set of buffer zones between each of the one or more components, populating the set of buffer zones with one or more generated pore elements, the one or more generated pore elements based, at least in part, on the one or more sample pore elements, and connecting the one or more generated pore elements to the one or more components to generate the heterogeneous plug.

Abstract: A method for pore network construction by one or more processors is disclosed. The method may include generating one or more sample pore bodies based on a representative pore network corresponding to a porous media sample, selecting a target pore body from the one or more sample pore bodies, adding the target pore body to a generated pore network, the generated pore network associated with one or more target parameters, replicating one or more pore throat connections from the representative pore network substantially within the generated pore network, the one or more pore throat connections disposed between the target pore body and one or more duplicated neighbors of the target pore body, and processing the generated pore network to substantially align the generated pore network with the representative pore network.

Abstract: A method and system for predicting dynamic two-phase fluid flow in a mixed-wet porous medium by one or more central processing units (CPUs), comprising determining a set of possible movements of main terminal menisci (MTMs) within a pore network model (PNM) of a porous media sample having a set of pore elements, generating pressure fields for each of the set of movements of MTMs, based on at least an inlet capillary pressure or a set of flow injection boundary conditions, based on the pressure fields, determining a set of local capillary pressures and a set of arc meniscus (AM) locations, generating a set of fluid displacements potentials based on at least the set of local capillary pressures and a set of threshold capillary pressures, and determining a highest positive fluid displacement potential from the set of fluid displacements.