Recovering heavy oil from a subterraneous formation penetrated by at least one injection well and one production well, by injecting into the injection well a mixture of steam and an alkyl alkoxylated carboxylate salt, increasing the apparent viscosity of the steam while at the same time lowering the steam mobility, and recovering oil from the subterranean formation.

Recovering heavy oil from a subterraneous formation penetrated by at least one injection well and one production well, by injecting into the injection well a mixture of steam and an alkyl alkoxylated carboxylate salt, increasing the apparent viscosity of the steam while at the same time lowering the steam mobility, and recovering oil from the subterranean formation.

A method for producing hydrocarbons within a reservoir includes (a) injecting an aqueous solution into the reservoir. The aqueous solution includes water and a thermally activated chemical species. The thermally activated chemical species is urea, a urea derivative, or a carbamate. The thermally activated chemical agent is thermally activated at or above a threshold temperature less than 200 C. In addition, the method includes (b) thermally activating the thermally activated chemical species in the aqueous solution during or after (a) at a temperature equal to or greater than the threshold temperature to produce carbon-dioxide and at least one of ammonia, amine, and alkanolamine within the reservoir. Further, the method includes (c) increasing the water wettability of the subterranean formation in response to the thermally activation in (b). Still further, the method includes (d) waterflooding the reservoir with water after (a), (b) and (c).

A method for producing hydrocarbons within a reservoir includes (a) injecting an aqueous solution into the reservoir. The aqueous solution includes water and a thermally activated chemical species. The thermally activated chemical species is urea, a urea derivative, or a carbamate. The thermally activated chemical agent is thermally activated at or above a threshold temperature less than 200 C. In addition, the method includes (b) thermally activating the thermally activated chemical species in the aqueous solution during or after (a) at a temperature equal to or greater than the threshold temperature to produce carbon-dioxide and at least one of ammonia, amine, and alkanolamine within the reservoir. Further, the method includes (c) increasing the water wettability of the subterranean formation in response to the thermally activation in (b). Still further, the method includes (d) waterflooding the reservoir with water after (a), (b) and (c).

A method includes injecting an aqueous-based injection fluid into a wellbore at a first temperature, where the aqueous-based injection fluid includes phase-changing nanodroplets having a liquid core and a shell. The method also includes exposing the phase-changing nanodroplets to a second temperature in the wellbore that is greater than or equal to a boiling point of the liquid core to change a liquid in the liquid core to a vapor phase and expand the phase-changing nanodroplets, thus removing debris from the wellbore and surrounding area.

A method includes injecting an aqueous-based injection fluid into a wellbore at a first temperature, where the aqueous-based injection fluid includes phase-changing nanodroplets having a liquid core and a shell. The method also includes exposing the phase-changing nanodroplets to a second temperature in the wellbore that is greater than or equal to a boiling point of the liquid core to change a liquid in the liquid core to a vapor phase and expand the phase-changing nanodroplets, thus removing debris from the wellbore and surrounding area.

Cementing compositions containing a hydraulic cement, halloysite nanoparticles, and silica flour. The cementing compositions may optionally include other additives such as a friction reducer, a defoamer, and a fluid loss additive. Cement samples made therefrom and methods of producing such cement samples are also specified. The addition of halloysite nanoparticles and silica flour provides enhanced mechanical strength (e.g. compressive strength, flexural strength) and improved durability (e.g. resistance to CO.sub.2 and salinity) to the cement, making them suitable cementing material for oil and gas wells.

Cementing compositions containing a hydraulic cement, halloysite nanoparticles, and silica flour. The cementing compositions may optionally include other additives such as a friction reducer, a defoamer, and a fluid loss additive. Cement samples made therefrom and methods of producing such cement samples are also specified. The addition of halloysite nanoparticles and silica flour provides enhanced mechanical strength (e.g. compressive strength, flexural strength) and improved durability (e.g. resistance to CO.sub.2 and salinity) to the cement, making them suitable cementing material for oil and gas wells.

Disclosed is a combined catalytic viscosity reducing system and a use of the combined system. The combined catalytic viscosity reducing system comprises four slugs, the four slugs are a catalyst slug, a heat generating system slug, a gas injection slug, and a water-soluble viscosity reducing system slug; the catalyst slug includes 10%-15% of azacarbene iron, 15%-30% of tert-butyl hydroperoxide, 2%-5% of phosphoric acid, 2%-5% of hydrogen donor, and 0.5%-1% of emulsifier agent, and the others are solvent; the heat generating system slug includes 10%-30% of NaNO.sub.2, 8%-25% of NH.sub.4Cl, and 3%-10% of acid initiator, and the others are water, totaling 100%; the water-soluble viscosity reducing system slug, according to mass percentage, includes 0.2%-0.5% of surfactant and 2%-10% of alkali, and the others are water. The combined catalytic viscosity reducing system can effectively reduce viscosity without injecting steam, and the viscosity reduction rate can reach 96.5%.

Disclosed is a combined catalytic viscosity reducing system and a use of the combined system. The combined catalytic viscosity reducing system comprises four slugs, the four slugs are a catalyst slug, a heat generating system slug, a gas injection slug, and a water-soluble viscosity reducing system slug; the catalyst slug includes 10%-15% of azacarbene iron, 15%-30% of tert-butyl hydroperoxide, 2%-5% of phosphoric acid, 2%-5% of hydrogen donor, and 0.5%-1% of emulsifier agent, and the others are solvent; the heat generating system slug includes 10%-30% of NaNO.sub.2, 8%-25% of NH.sub.4Cl, and 3%-10% of acid initiator, and the others are water, totaling 100%; the water-soluble viscosity reducing system slug, according to mass percentage, includes 0.2%-0.5% of surfactant and 2%-10% of alkali, and the others are water. The combined catalytic viscosity reducing system can effectively reduce viscosity without injecting steam, and the viscosity reduction rate can reach 96.5%.