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 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.

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 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 and system for image processing are disclosed. A method for image processing by one or more central processing units (CPU) may include detecting an overlap pattern for a set of slice images of a porous media sample, based on the overlap pattern, determining a set of overlap distances for the set of slice images of the porous media sample, and registering, based on at least the set of overlap distances, a composite image comprising any of the set of slice images of the porous media sample.

Abstract: A method and system for pore network characterization by one or more processing units is disclosed. The method may include obtaining an input image of a porous media sample, extracting a representative pore network from the input image by storing a voxel image for one or more pore elements, based on the one or more pore elements, defining a threshold capillary pressure for each of a set of inlet elements of the one or more pore elements; invading the one or more pore elements with a fluid flow configuration, the fluid flow configuration based, as least in part, on the threshold capillary pressure.

Abstract: Embodiments of the present disclosure generally relate to systems, devices, and methods to model fluid flow in a porous medium. In an embodiment, a microfluidic device to model subterranean fluid flow is disclosed. The device includes a mold of solid material, the mold including a field of pores and throats formed in the mold for mimicking a porous rock formation, a peripheral channel formed in the mold for mimicking a fluid reservoir, and an interior channel formed in the mold for mimicking a well. The peripheral channel can trace a perimeter or circumference of the field of pores and throats and be in fluid communication with the pores and throats.

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: 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 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: The invention is directed to methods for improving the recovery of oil from subterranean geological formations, such as unconventional reservoirs. The invention is also directed to methods for evaluating the efficiency of inject-soak-produce gas injection methods for oil recovery in unconventional reservoirs. In one embodiment, a method for evaluating the efficiency of oil recovery from an unconventional reservoir rock sample includes characterizing the rock sample by imaging the rock sample using a nano-CT scanner and/or scanning electron microscopy (SEM); cleaning the rock sample by flowing solvent through it; saturating the rock sample with crude oil; and establishing initial water saturation in the rock sample.

Abstract: Novel microemulsion formulations comprising a surfactant or combination of surfactants are disclosed for improved crude oil cleanup or recovery from subsurface geological formations, especially those containing carbonate cements.

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: Novel microemulsion formulations comprising a surfactant or combination of surfactants are disclosed for improved crude oil cleanup or recovery from subsurface geological formations, especially those containing carbonate cements.

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 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 for evaluating an optimal surfactant structure for oil recovery by systematically evaluating surfactants' phase behavior, cloud point, dynamic interfacial tension, dynamic contact angle, and spontaneous and forced imbibition. In one embodiment, a method for determining an optimal surfactant structure for oil recovery includes the steps of evaluating a surfactant's phase behavior, evaluating the surfactant's solubility, evaluating the surfactant's dynamic interfacial tension in a porous rock sample, evaluating the surfactant's static and dynamic contact angles in the porous rock sample, evaluating the surfactant's spontaneous imbibition in the porous rock sample, and evaluating the surfactant's forced imbibition in the porous rock sample. In one example, the surfactant comprises a polyoxyethylenated (POE) straight-chain alcohol.

Abstract: The present invention relates to a nanocondensation apparatus comprising a mass comparator, a core holder, an environmental chamber, and a pump and to methods for studying a fluid-solid system with the nanocondensation apparatus.

Abstract: The present invention relates to methods for evaluating an optimal surfactant structure for oil recovery by systematically evaluating surfactants' phase behavior, cloud point, dynamic interfacial tension, dynamic contact angle, and spontaneous and forced imbibition.

Abstract: Methods for determining an optimal surfactant structure for oil recovery are described. These methods systematically evaluate surfactants' phase behavior at ambient and at reservoir conditions; cloud point from ambient to reservoir conditions; dynamic interfacial tension at ambient and at reservoir conditions, including crude oil bubble images and fitting drop profiles; static contact angles at ambient conditions and dynamic contact angles at reservoir conditions; spontaneous imbibition at ambient conditions; and forced imbibition at reservoir conditions.