Abstract: A method of storing hydrogen gas in a subsurface formation may include compressing hydrogen gas by utilizing a compressor. This may create pressurized hydrogen gas that may be introduced into a subsurface formation through a wellhead to store as reserved hydrogen gas. The reserved hydrogen gas may be stored and maintained in the subsurface formations for a period. Another method in accordance with one or more embodiments of the present disclosure relates to recovering previously stored hydrogen gas from a subsurface storage for energy production. The method may include extracting reserved hydrogen gas from a subsurface formation. The extracted hydrogen gas may be purified by using at least a dehydrator, a pressure swing adsorption unit (PSA) and at least a temperature swing adsorption unit (TSA). The purified hydrogen gas may then be pressurized and used as a fuel for combustion in a turbine-generator unit.

Abstract: Methods and systems for producing oil from a subsurface reservoir include drilling a horizontal production well into the subsurface reservoir and drilling a horizontal injection well into the subsurface reservoir below the horizontal production well. Carbon dioxide and a second gas are mixed to form a gas mixture with a density more than a density of reservoir fluids between the horizontal production well and the horizontal injection well. The gas mixture is injected into the subsurface formation through the horizontal injection well and fluid is produced from the subsurface reservoir through the horizontal production well.

Abstract: Methods and systems for producing oil from a subsurface reservoir include drilling a horizontal production well into the subsurface reservoir and drilling a horizontal injection well into the subsurface reservoir below the horizontal production well. Carbon dioxide and a second gas are mixed to form a gas mixture with a density more than a density of reservoir fluids between the horizontal production well and the horizontal injection well. The gas mixture is injected into the subsurface formation through the horizontal injection well and fluid is produced from the subsurface reservoir through the horizontal production well.

Abstract: A illustrative process for quantifying CO2 sequestration within a reservoir includes, among other things, measuring a cumulative amount of CO2 injected into a reservoir via injection wells and at a CO2 storage plant, measuring the cumulative amount of CO2 produced via production wells and at a processing plant, estimating a cumulative amount of CO2 migrated from a reservoir based on measured CO2 via observations wells, and calculating a net amount of CO2 remaining in the reservoir based on the cumulative amount of CO2 injected, CO2 produced, and the CO2 that has migrated. An illustrative CO2 quantifying and sequestration system includes, among other things, injection wells, production wells, observation wells, measurement devices for measuring an amount of CO2 injected, observed and produced, and a measurement collection and analysis system for receiving signals from the measurement devices and for estimating an amount of CO2 sequestered within the reservoir.

Abstract: A method of storing hydrogen gas in a subsurface formation may include compressing hydrogen gas by utilizing a compressor. This may create pressurized hydrogen gas that may be introduced into a subsurface formation through a wellhead to store as reserved hydrogen gas. The reserved hydrogen gas may be stored and maintained in the subsurface formations for a period. Another method in accordance with one or more embodiments of the present disclosure relates to recovering previously stored hydrogen gas from a subsurface storage for energy production. The method may include extracting reserved hydrogen gas from a subsurface formation. The extracted hydrogen gas may be purified by using at least a dehydrator, a pressure swing adsorption unit (PSA) and at least a temperature swing adsorption unit (TSA). The purified hydrogen gas may then be pressurized and used as a fuel for combustion in a turbine-generator unit.

Abstract: The present disclosure details methods and systems for generating and recovering hydrogen from a depleted reservoir. The methods comprise several steps. Oxygen is introduced into a depleted reservoir. A fire flood is initiated, increasing temperature in the depleted reservoir and generating a gas mixture. The gas mixture is removed and transported to the surface. Energy is recovered from the gas mixture. Hydrogen is separated from the gas mixture, producing a depleted gas mixture and a hydrogen-rich gas mixture. The hydrogen-rich gas mixture is introduced into a subterranean storage formation.

Abstract: Systems and methods for reducing friction between a casing string and a bore of a subterranean well when moving the casing string within the bore of a subterranean well include a roller bearing assembly. The roller bearing assembly has a bearing body and a plurality of spherical bearings spaced around an outer diameter of the bearing body. The bearing body is secured in line with the casing string.

Abstract: Fluids injected into a carbonate reservoir formation during Enhanced Oil Recovery (EOR) may include a foaming mixture that includes a zwitterionic surfactant, an omega-3-acid ethyl ester, and aqueous salt solution. The omega-3-acid ethyl ester may include eicosapentaenoic acid ethyl ester, docosahexaenoic acid ethyl ester, or combinations thereof. The foaming mixtures may be incorporated into methods for enhancing hydrocarbon recovery in a carbonate reservoir formation. The methods may include introducing the foaming mixture to the carbonate reservoir formation such that any hydrocarbon present in the carbonate reservoir formation is displaced by the foaming mixture and is recoverable from the carbonate reservoir formation.

Abstract: Certain implementations of the subject matter can be implemented as a method of screening demulsifiers for live crude oil-water emulsions. A live emulsion of a hydrocarbon sample and a water sample is flowed through a capillary viscometer. The live emulsion includes dissolved gases retrieved from a hydrocarbon-carrying reservoir. While flowing the live emulsion through the capillary viscometer, a demulsifier sample is flowed through the capillary viscometer. The demulsifier sample causes breakdown of the live emulsion. Using the capillary viscometer, change in a viscosity of the live emulsion over time resulting from the breakdown of the live emulsion due to the demulsifier sample is measured. Multiple images of the breakdown of the live emulsion over time are captured. A strength of the live emulsion is classified based, in part, on the change in the viscosity of the live emulsion over time and on the plurality of images.

Abstract: Certain implementations of the subject matter can be implemented to screen demulsifiers. A live emulsion of a live hydrocarbon sample and a water sample is flowed through a capillary viscometer. The live hydrocarbon sample includes dissolved gases retrieved from a hydrocarbon-carrying reservoir. While flowing the live emulsion through the capillary viscometer, a demulsifier sample is flowed through the capillary viscometer. The demulsifier sample is capable of causing breakdown of the live emulsion. Using the capillary viscometer, change in a viscosity of the live emulsion over time resulting from the breakdown of the live emulsion due to the demulsifier sample is measured. Multiple images of the breakdown of the live emulsion over time are captured. A strength of the live emulsion is classified based, in part, on the change in the viscosity of the live emulsion over time and on the plurality of images.

Abstract: This invention generally relates to the field of oil recovery from reservoirs. More specifically, it relates to the recovery of oil from sandstone and carbonate reservoirs using a process for preparing a dispersion of capsules for use downhole including the steps of providing capsules containing a dense liquid, each capsule having a capsule wall defining an inner area, the capsule wall having an outer side. The capsules are functionalized by adding a carbon dioxide-philic compound to the outer side of the capsule wall. A dispersion is then prepared by adding the functionalized capsules to supercritical carbon dioxide such that a stable dispersion of capsules in supercritical carbon dioxide is achieved.

Abstract: Systems and methods for reducing friction between a casing string and a bore of a subterranean well when moving the casing string within the bore of a subterranean well include a roller bearing assembly. The roller bearing assembly has a bearing body and a plurality of spherical bearings spaced around an outer diameter of the bearing body. The bearing body is secured in line with the casing string.

Abstract: A dual core flooding apparatus and process are disclosed that provide for testing of two core plugs using different orientations and multiple fluids. The dual core flooding apparatus includes at least two core holders each configured to contain a core plug. The dual core flooding apparatus includes a fluids delivery system configured to inject one or more fluids into the core holders and core plugs. The dual core flooding apparatus includes an image capture system, a density and viscosity measurement system, and at least two oil/water separators. The dual core flooding apparatus also includes at least two back pressure regulators and an automated confining pressure system. A dual core flooding process may include introducing at least one fluid into the core holders, maintaining confining pressure and back pressure, and measuring density and viscosity of existing fluids.

Abstract: In one aspect, a secondary or tertiary hydrocarbon recovery method includes flowing a complex emulsion into a subterranean zone. The complex emulsion includes an internal fluid-in-gas emulsion configured to increase a density and a viscosity of a gas in the internal fluid-in-gas emulsion emulsifying a fluid in the internal fluid-in-gas emulsion. The complex emulsion includes an external fluid emulsifying the internal fluid-in-gas emulsion, and the external fluid is configured to carry corrosion inhibitors into the subterranean zone. The complex emulsion includes hydrophobic particles encapsulating an outer surface of droplets of the fluid in the internal fluid-in-gas emulsion. A concentration of the hydrophobic particles is between about 0.1% and 0.5% by weight.

Abstract: In one aspect, a complex emulsion includes an internal fluid-in-gas emulsion configured to increase a density and a viscosity of a gas in the internal fluid-in-gas emulsion emulsifying a fluid in the internal fluid-in-gas emulsion. The complex emulsion includes an external fluid emulsifying the internal fluid-in-gas emulsion, and the external fluid is configured to carry corrosion inhibitors into a subterranean zone. The complex emulsion includes hydrophobic particles encapsulating an outer surface of droplets of the fluid in the internal fluid-in-gas emulsion. A concentration of the hydrophobic particles is between about 0.1% and 0.5% by weight.

Abstract: Systems and methods for reducing friction between a casing string and a bore of a subterranean well when moving the casing string within the bore of a subterranean well include a roller bearing assembly. The roller bearing assembly has a bearing body and a plurality of spherical bearings spaced around an outer diameter of the bearing body. The bearing body is sized to be removably attached to an outer diameter of the casing string and to be stationary relative to the casing string.

Abstract: Fluids injected into a carbonate reservoir formation during Enhanced Oil Recovery (EOR) may include a foaming mixture that includes a zwitterionic surfactant, an omega-3-acid ethyl ester, and aqueous salt solution. The omega-3-acid ethyl ester may include eicosapentaenoic acid ethyl ester, docosahexaenoic acid ethyl ester, or combinations thereof. The foaming mixtures may be incorporated into methods for enhancing hydrocarbon recovery in a carbonate reservoir formation. The methods may include introducing the foaming mixture to the carbonate reservoir formation such that any hydrocarbon present in the carbonate reservoir formation is displaced by the foaming mixture and is recoverable from the carbonate reservoir formation.

Abstract: Fluids injected into a carbonate reservoir formation during Enhanced Oil Recovery (EOR) may include a foaming mixture that includes a zwitterionic surfactant, an omega-3-acid ethyl ester, and aqueous salt solution. The omega-3-acid ethyl ester may include eicosapentaenoic acid ethyl ester, docosahexaenoic acid ethyl ester, or combinations thereof. The foaming mixtures may be incorporated into methods for enhancing hydrocarbon recovery in a carbonate reservoir formation. The methods may include introducing the foaming mixture to the carbonate reservoir formation such that any hydrocarbon present in the carbonate reservoir formation is displaced by the foaming mixture and is recoverable from the carbonate reservoir formation.

Abstract: Fluids injected into a carbonate reservoir formation during Enhanced Oil Recovery (EOR) may include a foaming mixture that includes a zwitterionic surfactant, an omega-3-acid ethyl ester, and aqueous salt solution. The omega-3-acid ethyl ester may include eicosapentaenoic acid ethyl ester, docosahexaenoic acid ethyl ester, or combinations thereof. The foaming mixtures may be incorporated into methods for enhancing hydrocarbon recovery in a carbonate reservoir formation. The methods may include introducing the foaming mixture to the carbonate reservoir formation such that any hydrocarbon present in the carbonate reservoir formation is displaced by the foaming mixture and is recoverable from the carbonate reservoir formation.

Abstract: Certain implementations of the subject matter can be implemented as a method of screening demulsifiers for live crude oil-water emulsions. A live emulsion of a hydrocarbon sample and a water sample is flowed through a capillary viscometer. The live emulsion includes dissolved gases retrieved from a hydrocarbon-carrying reservoir. While flowing the live emulsion through the capillary viscometer, a demulsifier sample is flowed through the capillary viscometer. The demulsifier sample causes breakdown of the live emulsion. Using the capillary viscometer, change in a viscosity of the live emulsion over time resulting from the breakdown of the live emulsion due to the demulsifier sample is measured. Multiple images of the breakdown of the live emulsion over time are captured. A strength of the live emulsion is classified based, in part, on the change in the viscosity of the live emulsion over time and on the plurality of images.