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.

Degradable particulate materials are provided that may be utilized in various wellbore treatment fluids, such as hydraulic fracturing fluids. In particular, the degradable particulate materials can be formed from a cellulosic polymer, a polyester polymer, a polyvinyl alcohol, or a guar gum ester that are capable of effectively degrading at specific rates when exposed to the aqueous environments in low temperature wellbores (50° C. to 100° C.).

Wellbore fluids may contain an aqueous base fluid comprising a monovalent brine, a modified starch, and a metal oxide. Methods of using wellbore fluids may include drilling a subterranean well while circulating a wellbore fluid into the subterranean well, wherein the wellbore fluid contains an aqueous base fluid comprising a monovalent brine, a modified starch, and a metal oxide.

A wellbore fluid may include an oleaginous continuous phase; a non-oleaginous discontinuous phase; an emulsifier stabilizing the non-oleaginous phase within the oleaginous phase; a low density material selected and in an amount to result in a specific gravity of the wellbore fluid that is less than 0.83; and at least one rheology modifier selected to suspend the low density material within the wellbore fluid.

An invert emulsion drilling fluids having a combination of fatty acids derived from waste vegetable oil (WVO) and a fatty alcohol as a rheology modifier. An invert emulsion drilling fluid may include a water in oil emulsion, an invert emulsifier, a fatty alcohol having six to thirty carbon atoms, and a fatty acid having six to eighteen carbon atoms. The fatty acid is provided by esterifying a waste vegetable oil to produce a methyl ester of the waste vegetable oil and cleaving an ester group from the methyl ester of the waste vegetable oil. The invert emulsion drilling fluid may be formulated free of organoclay. Methods of drilling a wellbore using an invert emulsion drilling fluid are also provided.

An aqueous dispersion includes polyacrylamide, a crosslinker, and a filler. The crosslinker includes at least one of hydroquinone or hexamethylenetetramine. The filler includes at least one of a metal oxide or a nanomaterial. The metal oxide includes at least one of zirconium oxide, zirconium hydroxide, or titanium oxide. The nanomaterial includes at least one of graphene, graphene oxide, or boron nitride. In some cases, the filler is a nanocomposite of the metal oxide and the nanomaterial.

A drilling fluid formulation is provided, which includes an aqueous base fluid, a synthetic modified phyllosilicate as an anti-sagging additive, an inorganic base, and a weighting agent (e.g. barite). The synthetic modified phyllosilicate contains a clay material (e.g. smectite) and a metal selected from ruthenium, rhodium, palladium, osmium, iridium, and platinum. The synthetic modified phyllosilicate is effective in preventing barite sagging as demonstrated by low sag factor when drilling at elevated temperatures. Rheology properties of the drilling fluid including gel strength, yield point, plastic viscosity, and storage modulus are also specified.

A multi-slug staged method for plugging a fractured formation includes: determining an average opening of fractures around a well as D, an average particle size of bridging particles for first-stage plugging as D.sub.1 that is slightly less than D, and average particle sizes of plugging particles for second to last-stage plugging as D.sub.2-D.sub.n, where D.sub.n is small enough to form a tight plugging layer; and sequentially injecting a plugging slurry only containing the bridging particles having the average particle size of D.sub.1, plugging slurries containing the plugging particles having the average particle sizes of D.sub.2-D.sub.n-1, and a plugging slurry containing the plugging particles having the average particle size of D.sub.n into the fractures to achieve the fractured formation plugging.

A method of treating a well that includes introducing a well treatment fluid into the well, and a well treatment fluid, are provided. The well treatment fluid comprises an aqueous base fluid, a bridging agent, a viscosifying agent, and a water soluble, biodegradable graft copolymer. In one embodiment, for example, the method is a method of cementing a casing in a well. In this embodiment, the well treatment fluid is a cement spacer fluid.

A method of hydraulic fracturing may comprise mixing at least one liquid sand mixture with a fluid to produce a fracturing fluid; and conveying the fracturing fluid to two or more wellbores simultaneously, wherein the wellbores penetrate a subterranean formation.