Abstract: An open hole formation surface within a wellbore of a well system is sealed with a polymer seal. A deployment system is inserted into the wellbore to the location of the open hole formation surface. The open hole formation surface may be located at the bottom of the wellbore or at an interval between two casing strings. The deployment system delivers an expandable polymer grout system to the location of the open hole formation surface. The expandable polymer grout system cures to form the polymer seal on the open hole formation surface.

Abstract: Systems and techniques may be used to increase recovery of a geothermal energy resource. An example technique includes selecting a first borehole that extends from a surface of the earth into a first location in a geothermal reservoir, conditioning the first borehole by pumping a fluid into or out of the first borehole at a predetermined operating condition to change a property of the geothermal reservoir, and selecting a second borehole that extends from the surface of the earth into a second location in the geothermal reservoir. The example technique may include enhancing permeability of the geothermal reservoir by using a reservoir stimulation technique on the second borehole, wherein a property of a stimulated reservoir volume is controlled by the property of the geothermal reservoir that was changed by conditioning the first borehole.

Abstract: The present invention is broadly concerned with mineralization methods that assist in permanent carbon storage. The methods provide a storage mechanism for oxalic acid generated by existing or future-developed carbon capture and conversion methods that convert CO2 to oxalic acid. That oxalic acid can be injected into a subsurface rock formation containing non-carbonate rock to form oxalates or oxalate hydrates. Alternatively, oxalic acid can be mixed with mine tailings, well drilling dirt, crushed rocks, etc., that contain desired non-carbonate rock minerals, to promote mineralization.

Abstract: A system includes a drilling sub-system configured to form a wellbore from a terranean surface toward a subterranean formation by rotating a drill bit on a drill string; a drilling fluid circulation sub-system configured to circulate a drilling fluid downhole through the drill string, to and through the drill bit, into the wellbore, and uphole toward the terranean surface while the drilling sub-system drills the portion of the wellbore; and a lost circulation sub-system including a plurality of lost circulation material (LCM) pills configured to circulate, with the drilling fluid, through the drill string and the drill bit and into the wellbore in an inactive state. Each of the LCM pills is set to adjust from the inactive state to an active state to reduce at least a portion of the drilling fluid circulated into the wellbore that is lost to the subterranean formation.

Abstract: A liquid additive composition comprising (i) a biopolymer gum and (ii) a latex, wherein a ratio of biopolymer gum to latex ranges from about 1:50 to about 1:500. A method of preparing a liquid additive composition comprising contacting a biopolymer gum and a latex to form a mixture wherein a ratio of biopolymer gum to latex ranges from about 1:60 to about 1:500. A method of servicing a wellbore penetrating a subterranean formation comprising placing a treatment fluid comprising (i) a biopolymer gum and (ii) a latex into the wellbore and/or the subterranean formation, wherein a ratio of biopolymer gum to latex ranges from about 1:50 to about 1:500.

Abstract: A non-cementitious loss control composition and a method for preparing a non-cementitious loss control composition is provided. The method comprises adding bentonite to water to form a gel slurry and adding a cross linking agent to the gel slurry. The method further comprises adding a binding agent to the gel slurry and the cross linking agent and adding a strengthening agent to the binding agent, the gel slurry and the cross-linking agent. Further, the method comprises adding a bridging agent to the strengthening agent, the binding agent, the gel slurry and the cross linking agent. The method further comprises adding a retarder to the bridging agent, the strengthening agent, the binding agent, the gel slurry and the cross linking agent, where the loss control composition is a lightweight thixotropic composition that is prepared in a density range of 10 Pounds Per Gallon (ppg) to 16 ppg.

Abstract: Provided are a downhole tool, a well system, and a method. The downhole tool, in one aspect, includes a housing, as well as an expandable metal member positioned about the housing, the expandable metal member comprising a metal configured to expand in response to hydrolysis. The downhole tool, according to one aspect, further includes colloid particles surrounding a surface of the expandable metal member.

Abstract: Provided is a well system, and a method. The well system, in one aspect, includes a wellbore positioned within a subterranean formation, as well as a downhole tool positioned within the wellbore. The downhole tool, according to one aspect, includes a housing, as well as an expandable metal member positioned about the housing, the expandable metal member comprising a metal configured to expand in response to hydrolysis. The well system, in one further aspect, includes a reactive colloidal dispersion of colloid particles surrounding a surface of the expandable metal member.

Abstract: Naphthenic imidazoline can be used in inhibiting formation of natural gas hydrate. A composition contains the naphthenic imidazoline and modified polysaccharide. The modified polysaccharide may be cationic amylose.

Abstract: A fracturing fluid for fracturing subterranean formations comprising ascorbic acid. The fracturing fluid can use ascorbic acid to delay increases in viscosity until desired. The viscosity increase can then be maintained over a period of time to perform fracturing operations.

Abstract: A variety of methods and compositions are disclosed, including, in one embodiment, A friction reducer comprising: a continuous phase comprising a base oil and a secondary oil, wherein the secondary oil is different than the base oil; a discontinuous phase dispersed in the continuation phase, wherein the discontinuous phase comprises water and a water-soluble polymer, and an emulsifying surfactant.

Abstract: A hydraulic fracturing method for recovering oil from a low-temperature subterranean oil formation is disclosed. Before, during, or after inducing hydraulic fracturing within the formation, a particulate, degradable polyester diverting agent is introduced into the formation in an amount effective to improve oil production from the formation. The diverting agent is allowed to degrade, and oil is recovered. The diverting agent has a melting point greater than the average temperature of the formation and is selected from: (i) ethylene glycol succinates; (ii) acid-terminated ethylene glycol succinates; (iii) acid-terminated polyglycolic acids; (iv) acid-terminated polylactic acids; and (v) mixtures of any of (i) through (iv) with a half acid ester.

Abstract: A composition of matter including a fluorescent assembly and a drilling fluid is provided. The fluorescent assembly includes a matrix material and a plurality of fluorophores held within the matrix material and has an average particle size of at least one millimeter. A method includes introducing the fluorescent assembly into a drilling fluid and circulating the drilling fluid through a well during a drilling operation that creates formation cuttings such that the fluorescent assembly interacts with the formation cuttings, creating tagged cuttings. The method further includes collecting returned cuttings from the circulating drilling fluid at a surface of the well, detecting the presence of the fluorescent assembly on the returned cuttings to identify the tagged cuttings, and correlating the tagged cuttings with a drill depth in the well at a time during the drilling operation.

Abstract: A system and a method for determining hydrocarbon production from multiple subterranean formations. Different nanotag tracers are sequentially injected into subterranean production zones fluidly coupled to a wellbore extending from a surface of the Earth through the subterranean production zones. The respective nanotag tracers are injected into a respective subterranean production zone. The different nanotag tracers and production fluids contained within the subterranean production zones are produced through the wellbore to the surface. A turbidity of the production fluids containing the different nanotag tracers is determined at the surface. A quantity of each of the one or more different nanotag tracers from each of the subterranean production zones in the production fluids is determined. Based on the turbidity of the production fluids and the quantity of the different nanotag tracers, a total oil production rate from the subterranean production zones is determined.

Abstract: Methods of stimulating a hydrocarbon well are disclosed herein. The hydrocarbon well includes a wellbore that extends within a subterranean formation and a tubular that extends within the wellbore and defines a tubular conduit. The methods include retaining a sealing structure within the tubular conduit and, during the retaining, stimulating a zone of the subterranean formation. Subsequent to the stimulating, the methods include fluidly isolating the zone of the subterranean formation from the uphole region by at least partially sealing the plurality of perforations. Subsequent to the fluidly isolating, the methods include moving the sealing structure in a downhole direction within the tubular conduit. The methods also include repeating the retaining, the stimulating, the fluidly isolating, and the moving a plurality of times to stimulate a plurality of corresponding zones of the subterranean formation.

Abstract: An integrated device and a method for continuously capturing, storing and separating a flue gas in an underground rock stratum are provided. An injection well, a monitoring well and an emission well are arranged in sequence at locations from near to far from a flue gas emission source. The injection well, the monitoring well and the emission well are respectively drilled to different depths in a storage rock stratum. A horizontal injection channel is arranged at bottom end of the injection well. During migrating the flue gas in the storage rock stratum, CO2 and sulfur nitride are absorbed by a rock porous medium and gradually enriched, and meanwhile, the CO2 and sulfur nitride, after chemically reacting with water, minerals and biomass in a rock, are gradually mineralized to achieve storage; and separated N2 is gradually migrated upwards to the emission well to achieve separation.

Abstract: A method may include providing a treatment fluid comprising a metal sulfide dissolver and a base fluid. The metal sulfide dissolver includes a chelating agent, a boosting agent, a scaling agent, and a dispersing agent. The treatment fluid is then injected to contact a metal sulfide scale, which dissolves at least partially. The treatment fluid may be injected into a wellbore as a standalone treatment or as an additive.

Abstract: Techniques for treating a hydrocarbon reservoir include delivering a composition to the hydrocarbon reservoir. The composition includes at least one acid, and liquid or supercritical carbon dioxide (CO2). The method further includes exposing the delivered composition to water to activate the composition; and treating a rock formation of the hydrocarbon reservoir with the activated composition.

Abstract: Methods include pumping a fracturing pad fluid into a subterranean formation under conditions of sufficient rate and pressure to create at least one fracture in the subterranean formation, the fracturing pad fluid including a carrier fluid and a plurality of bridging particles, the bridging particles forming a bridge in a fracture tip of a far field region of the formation. Methods further include pumping a first plurality of fibers into the subterranean formation to form a low permeability plug with the bridging particles, and pumping a proppant fluid comprising a plurality of proppant particles.

Abstract: A hematite-based fly ash composition includes a curable component including a fly ash binder material (FFA) and a hematite weighting agent present in an amount of 20 to 80% by weight of the fly ash binder material (BWOB). The composition further includes superplasticizers (SPs) in an amount of 5 to 10% BWOB; retarders in an amount of 5 to 10% BWOB; a defoamer in an amount of 0.01 to 0.02% BWOB; and an aqueous alkaline solution in an amount of 50 to 60% BWOB. The hematite-based fly ash composition has a thickening time of from 80 to 580 minutes at 195° F. and a plastic viscosity of 150 to 350 cP.