A method includes treating a reservoir with a damaged near wellbore region (NWR), including introducing a liquid foam treatment into a wellbore proximate to the damaged NWR, where the liquid foam treatment has a solution medium and nanobubbles, transmitting an acoustic wave towards the damaged NWR such that the nanobubbles collapse, causing fluid flow pathways to form for hydrocarbon production. A system includes a solution generation tool for generating a liquid foam treatment, where the liquid foam treatment has a solution medium and nanobubbles, where the nanobubbles migrate along a concentration gradient, and an acoustic signal generator transmits an acoustic signal. The system also includes a downhole tool signally coupled to the acoustic signal generator fluidly coupled to the solution generation tool, and the downhole tool transmits an acoustic wave into an NWR and introduces the liquid foam treatment into the wellbore proximate to the NWR.

A method of treating a lost circulation zone may include positioning a cured lost circulation material composition in the lost circulation zone of a subterranean natural resource well to produce a barrier operable to mitigate wellbore fluids from passing into the lost circulation zone. The cured lost circulation material composition may be a foam comprising a gas phase and a liquid phase. The cured lost circulation material composition may include a cured bisphenol epoxy resin, one or more surfactants positioned at the interface of the liquid phase and the gas phase of the foam and carbon dioxide in the gas phase of the foam. The cured bisphenol epoxy resin may be a reaction product of a bisphenol epoxy resin system including uncured bisphenol epoxy resin, one or more curing agents, and optionally, a diluent. The carbon dioxide may be a reaction product of one or more carbon dioxide gas-generating compounds.

A method of treating a lost circulation zone may include positioning a cured lost circulation material composition in the lost circulation zone of a subterranean natural resource well to produce a barrier operable to mitigate wellbore fluids from passing into the lost circulation zone. The cured lost circulation material composition may be a foam comprising a gas phase and a liquid phase. The cured lost circulation material composition may include a cured bisphenol epoxy resin, one or more surfactants positioned at the interface of the liquid phase and the gas phase of the foam and carbon dioxide in the gas phase of the foam. The cured bisphenol epoxy resin may be a reaction product of a bisphenol epoxy resin system including uncured bisphenol epoxy resin, one or more curing agents, and optionally, a diluent. The carbon dioxide may be a reaction product of one or more carbon dioxide gas-generating compounds.

A sand consolidation composition includes a hydrocarbon mixture comprising asphaltene, bitumen, or tar, and a binding agent, where the binding agent is an amino silane, and where the composition has a viscosity ranging from 5 to 20 cP at 20 to 25° C. A method of sand consolidation includes introducing the sand consolidation composition in a wellbore, contacting sand downhole with the sand consolidation composition, maintaining the wellbore such that a viscosity of the sand consolidation composition and the sand increases from an initial viscosity of the sand consolidation composition, introducing a thermochemical reagent comprising sodium nitrite and ammonium chloride such that it intimately intermingles downhole with the sand consolidation composition and releases a gas, and after a period, forming a productive consolidated sand.

A sand consolidation composition includes a hydrocarbon mixture comprising asphaltene, bitumen, or tar, and a binding agent, where the binding agent is an amino silane, and where the composition has a viscosity ranging from 5 to 20 cP at 20 to 25° C. A method of sand consolidation includes introducing the sand consolidation composition in a wellbore, contacting sand downhole with the sand consolidation composition, maintaining the wellbore such that a viscosity of the sand consolidation composition and the sand increases from an initial viscosity of the sand consolidation composition, introducing a thermochemical reagent comprising sodium nitrite and ammonium chloride such that it intimately intermingles downhole with the sand consolidation composition and releases a gas, and after a period, forming a productive consolidated sand.

A method for enhancing wellbore integrity and/or for sealing a wellbore by sealing formation or micro-annulus fractures in a wellbore. Such sealing can be at least partially accomplished by the use of timed expansion of an expandable sealant material that is placed a wellbore. The expansion of the expandable sealant material causes the cement surface or formation surface to be compressed, thereby creating a tight seal and/or eliminating annulus cracking, fracture, and/or gas channels in the wellbore. A degradable polymer can be used when restoration of the wellbore formation is desired.

A method for enhancing wellbore integrity and/or for sealing a wellbore by sealing formation or micro-annulus fractures in a wellbore. Such sealing can be at least partially accomplished by the use of timed expansion of an expandable sealant material that is placed a wellbore. The expansion of the expandable sealant material causes the cement surface or formation surface to be compressed, thereby creating a tight seal and/or eliminating annulus cracking, fracture, and/or gas channels in the wellbore. A degradable polymer can be used when restoration of the wellbore formation is desired.

A method for improving oil recovery within a subterranean formation that includes forming a barrier within the formation to isolate at least a portion of a first region from a proximate second region. The barrier is formed by introducing a first solution including an ammonium containing compound and a second solution including a nitrite containing compound into the formation. The first solution, the second solution, or both, further include a foaming agent. The compounds react to generate nitrogen gas in the presence of the foaming agent to generate a foam within a first region. The foam provides the barrier. Water is introduced into the formation. The barrier diverts the water away from the first region and into the second region. The water operates to displace at least a portion of a hydrocarbon present in the second region and discharge the hydrocarbon from the formation.

A method for improving oil recovery within a subterranean formation that includes forming a barrier within the formation to isolate at least a portion of a first region from a proximate second region. The barrier is formed by introducing a first solution including an ammonium containing compound and a second solution including a nitrite containing compound into the formation. The first solution, the second solution, or both, further include a foaming agent. The compounds react to generate nitrogen gas in the presence of the foaming agent to generate a foam within a first region. The foam provides the barrier. Water is introduced into the formation. The barrier diverts the water away from the first region and into the second region. The water operates to displace at least a portion of a hydrocarbon present in the second region and discharge the hydrocarbon from the formation.

A method for altering a characteristic of the ground. The method comprises the steps of preparing a lignocellulosic material, suspending the lignocellulosic material in a slurry to create a lignocellulosic slurry, and creating a fluid movement of the lignocellulosic slurry. The method further includes the steps of resuspending a portion of the lignocellulosic slurry with the fluid movement; and injecting the lignocellulosic slurry below the surface of the ground.