Abstract: Formation treatment fluid compositions and methods are provided that include an aqueous base fluid, where the aqueous base fluid comprises one or more salts; and sago. The profile modification fluid may include sago in an amount in the range from 50,000 ppm to 100,000 ppm. Formation treatment fluid compositions may also include an aqueous base fluid, where the aqueous base fluid comprises one or more salts, and sago, where the formation treatment fluid may include sago in an amount in the range from 10,000 ppm to 50,000 ppm. Methods for using the formation treatment fluid may include introducing into a targeted stratum of a subterranean formation a treatment fluid. The subterranean treatment fluid may include an aqueous base fluid, where the aqueous base fluid includes one or more salts, sago, and the treatment fluid may include sago in an amount in the range from 10,000 ppm to 100,000 ppm.

Abstract: A method includes providing a gelant including a cross-linkable polymer, a crosslinking agent and an aqueous fluid, adding one or more fluorescent rare earth elements to the gelant to provide a fluorescent gelant solution in which a fluorescence emission is quenched, and initiating crosslinking of the gelant to form a gel by heating the fluorescent gelant solution. The intensity of the fluorescence emission of the fluorescent gelant solution is monitored as an indicator of gelation status and a gelation point of the gelant may be identified based on the intensity of the fluorescent emission of the fluorescent gelant solution.

Abstract: A solution for injection to a formation containing hydrocarbons includes an ionic liquid and a brine having a salinity of at least 60,000 ppm total dissolved solids (TDS). The ionic liquid is configured to lower an interfacial tension between the solution and the hydrocarbons in the formation.

Abstract: A solution for injection to a formation containing hydrocarbons includes an ionic liquid and a brine having a salinity of at least 60,000 ppm total dissolved solids (TDS). The ionic liquid is configured to lower an interfacial tension between the solution and the hydrocarbons in the formation.

Abstract: A process of constructing a micromodel for a multiple porosity system includes: drilling a well; coring the well for acquiring core plugs from the well; producing thin section images of the core plugs for acquiring a first feature of the core plugs; and transforming the thin section images to binary images.

Abstract: A method includes saturating a core sample with a hydrocarbon fluid to provide a hydrocarbon-saturated core, placing the core into a first aqueous fluid, applying an external force at increasing magnitude to the hydrocarbon-saturated core to displace a volume of the hydrocarbon fluid in the hydrocarbon-saturated core with the first aqueous fluid at each pressure magnitude, measuring a volume of displaced hydrocarbon fluid at each pressure magnitude, obtaining a first capillary pressure curve, re-saturating the core sample, placing the hydrocarbon-saturated core into a second aqueous fluid having a wettability altering agent, applying an external force at increasing magnitude to displace a volume of the hydrocarbon fluid in the core with the second aqueous fluid at each pressure magnitude, measuring a volume of displaced hydrocarbon fluid at each pressure magnitude, obtaining a second capillary pressure curve, and calculating a contact angle of the second aqueous fluid.

Abstract: A viscosity reducer composition may include one or more polycyclic compounds, one or more polymers covalently attached to one or more polyaromatic compounds, one or more rheology modifiers, one or more surfactants, and an aqueous solution.

Abstract: A method includes determining a critical micelle concentration (Ccm assumed) of a sample with an unknown concentration (Cs) of a surfactant based on an assumed surfactant concentration (Cassumed) of the sample, providing a benchmark solution with a known concentration of the surfactant, determining an actual critical micelle concentration (Ccm) of the surfactant from the benchmark solution, and calculating the unknown concentration (Cs) of the surfactant in the sample from the following equation: Cs=Ccm/(Ccm assumed/Cassumed).

Abstract: An assembly includes a bypass line having a first connection end and a second connection end, a device base positioned along the bypass line, an upstream valve positioned along the bypass line between the device base and the first connection end, and a downstream valve positioned along the bypass line between the device base and the second connection end. The device base includes a first opening to the bypass line, a second opening to the bypass line, and a support structure supporting at least one of the first and second openings.

Abstract: A method includes saturating a core sample with a hydrocarbon fluid to provide a hydrocarbon-saturated core, placing the core into a first aqueous fluid, applying an external force at increasing magnitude to the hydrocarbon-saturated core to displace a volume of the hydrocarbon fluid in the hydrocarbon-saturated core with the first aqueous fluid at each pressure magnitude, measuring a volume of displaced hydrocarbon fluid at each pressure magnitude, obtaining a first capillary pressure curve, re-saturating the core sample, placing the hydrocarbon-saturated core into a second aqueous fluid having a wettability altering agent, applying an external force at increasing magnitude to displace a volume of the hydrocarbon fluid in the core with the second aqueous fluid at each pressure magnitude, measuring a volume of displaced hydrocarbon fluid at each pressure magnitude, obtaining a second capillary pressure curve, and calculating a contact angle of the second aqueous fluid.

Abstract: A method for retrieving heavy oil from a reservoir is provided. In the method, an injection well traversing a subsurface into a reservoir containing a heavy oil is treated via introducing a hot aqueous-based fluid into the reservoir through the injection well. The hot aqueous-based polymer solution may be heated to a temperature above the injection well prior to injecting it into the injection well. The method further includes recovery of a heavy oil mixture from a production well of the reservoir.

Abstract: A system for sidewall coring includes a sidewall coring tool lowered into a wellbore for positioning a coring bit inside a subterranean formation, an injection assembly, and an array of sensors. The coring bit is capable of collecting a core sample by rotating with respect to a housing of the sidewall coring tool. The injection assembly injects a plurality of fluids into a sidewall core and is configured to selectively inject a plurality of fluids into the core sample. The array of sensors is embedded within a sidewall cutter enclosure for recording measurements during an injection process. The array of sensors produces information relating to the core sample.

Abstract: This disclosure relates to water-soluble viscosity reducer complexes for use in reducing the viscosity of heavy oil in oil recovery operations. The viscosity reducer complexes contain a hydrophilic component of polyaromatic-hydrocarbon-based polymers and a hydrophilic component of cyclodextrin-based polymers.

Abstract: A method of forming a model of a porous structure includes three dimensionally printing a mold of the porous structure using a polycaprolactone mold material, filling the mold with a polymer mixture, and heating the filled mold at a temperature above a melting temperature of the mold material to cure the polymer mixture, where the cured polymer mixture forms the model of the porous structure.

Abstract: A method and a system to determine a gelation time of a substance in a container is disclosed. The system includes a container, a bubble generator arranged at a first end of the container, and a bubble sensor arranged at the second end of the container. The container holds a substance having a surface adjacent the second end. The bubble generator is configured to generate a bubble at the first end. The bubble sensor is configured to sense the bubble at the surface of the substance. The method includes releasing a gas into a first end of the container such that the gas bubbles rise from the first end of the container to a second end of the container, sensing the released bubbles, determining an absence of a bubble released by the bubble generator at the bubble sensor, and determining a gelation time based on a number of detected bubbles.

Abstract: A method of forming a model of a porous structure includes three dimensionally printing a mold of the porous structure using a polycaprolactone mold material, filling the mold with a polymer mixture, and heating the filled mold at a temperature above a melting temperature of the mold material to cure the polymer mixture, where the cured polymer mixture forms the model of the porous structure.

Abstract: A process of constructing a micromodel for a multiple porosity system includes: drilling a well; coring the well for acquiring core plugs from the well; producing thin section images of the core plugs for acquiring a first feature of the core plugs; and transforming the thin section images to binary images.

Abstract: A contact angle measurement system includes a housing that can hold a volume of a first fluid having a first density, an adjustable rock sample holder positioned within the housing, a fluid dropper attached to the housing, an image capturing a device, and a computer system. The holder can support a rock sample. An orientation of the holder relative to the housing is adjustable such that an outer surface of the rock sample is at a non-zero angle relative to a lower wall of the housing. When the orientation of the holder relative to the housing is such that the outer surface of the rock sample is at the non-zero angle relative to the lower wall, the fluid droplet traverses the outer surface of the rock sample. The image capturing device can capture images of the fluid droplet as the fluid droplet traverses the outer surface of the rock sample.

Abstract: Techniques for analyzing a sample include preparing a sample; circulating a gel solution through the sample to saturate the sample; scanning the saturated sample with a nuclear magnetic resonance (NMR) system to determine two or more NMR values of the saturated sample; determining a permeability of the saturated sample based, at least in part, on the two or more NMR values of the saturated sample; aging the saturated sample; scanning the aged sample with the NMR system to determine two or more NMR values of the aged sample; determining a permeability of the aged sample based, at least in part, on the two or more NMR values of the aged sample; comparing the determined permeability of the saturated sample against the determined permeability of the aged sample; and based on the compared permeabilities, determining a gel solution syneresis rate.

Abstract: Formation treatment fluid compositions and methods are provided that include an aqueous base fluid, where the aqueous base fluid comprises one or more salts; and sago. The profile modification fluid may include sago in an amount in the range from 50,000 ppm to 100,000 ppm. Formation treatment fluid compositions may also include an aqueous base fluid, where the aqueous base fluid comprises one or more salts, and sago, where the formation treatment fluid may include sago in an amount in the range from 10,000 ppm to 50,000 ppm. Methods for using the formation treatment fluid may include introducing into a targeted stratum of a subterranean formation a treatment fluid. The subterranean treatment fluid may include an aqueous base fluid, where the aqueous base fluid includes one or more salts, sago, and the treatment fluid may include sago in an amount in the range from 10,000 ppm to 100,000 ppm.