Abstract: Fluids containing surfactants and hydrophobic particles are effective media for cleaning non-aqueous fluids (NAFs) out of a subterranean wellbore. The fibers and surfactants are may be added to a drilling fluid, a spacer fluid, a sacrificial spacer fluid, a chemical wash, a cement slurry or combinations thereof. NAFs, such as an oil-base mud or a water-in-oil emulsion mud, are attracted to the fibers as the treatment fluid circulates in the wellbore.

Abstract: Fluids containing surfactants and hydrophobic particles are effective media for cleaning non-aqueous fluids (NAFs) out of a subterranean wellbore. The fibers and surfactants are preferably added to a drilling fluid, a spacer fluid, a chemical wash, a cement slurry or combinations thereof. NAFs, such as an oil-base mud or a water-in-oil emulsion mud, are attracted to the fibers as the treatment fluid circulates in the wellbore.

Abstract: Methods of treating a subterranean formation are disclosed that include introducing a treatment fluid including thermally shrinkable fibers and a particulate material into a subterranean formation via a wellbore, adjusting at least one parameter of the treatment fluid to trigger the association of the thermally shrinkable fibers, and forming a porous pack including a network of shrunken fibers by applying heat sufficient to raise the temperature of the thermally shrinkable fibers to a temperature at or above a shrinking initiation temperature of the thermally shrinkable fibers.

Abstract: Fluid compositions comprising rigid fibers, flexible fibers and solid plugging particles may effectively control the egress of fluids from a subterranean wellbore into vugs, cracks and fissures in the subterranean formation rock. The compositions may be effective in drilling fluids, cement slurries, gravel packing fluids, acidizing fluids and hydraulic fracturing fluids. Such fluids may also have utility for providing fluid diversion during well stimulation treatments, allowing the stimulation fluid to avoid higher permeability regions in the formation rock and treat the lower permeability regions, thereby improving stimulation results.

Abstract: A method to treat a subterranean formation penetrated by a wellbore, comprising: providing a treatment slurry comprising a carrying fluid, a solid particulate, an agglomerant and an agglomerant aid; injecting the treatment slurry into a fracture to form a mixture of the solid particulate and the agglomerant; and transforming the mixture into areas that are rich in solid particulate and areas that are substantially free of solid particulate. Also disclosed are a composition comprised of the carrying fluid, solid particulate, agglomerant and agglomerant aid, as well as a method of designing a well treatment therewith and a system to form conductive channels in a fracture.

Abstract: A method is given for reducing the flow of a treatment fluid in a well, for example for zonal isolation or for stimulation fluid diversion. The method includes preparing a High Solids Content Fluid (a pumpable slurry containing a carrier fluid and a packed volume fraction of at least 50 per cent solids having a multi-model size distribution), injecting the high solids content fluid into the well, placing the high solids content fluid at the location at which fluid flow is to be decreased, and either reducing the volume or increasing the viscosity of the carrier fluid. Optionally, at least a portion of the solids in the High Solids Content Fluid is subsequently removable to restore fluid flow.

Abstract: Elongated shapeable particles, for example bi-component fibers that are reshaped into tighter structures when heated, are injected into fractures generated during acid fracturing. Collections of such particles form as the temperature in the fracture increases, heterogeneously masking portions of the fracture faces and causing differential etching and increased fracture conductivity when formation-dissolving agents contact the fracture faces. Optionally, the elongated shapeable particles may decompose to release formation-dissolving agents.

Abstract: A method of treating a subterranean formation penetrated by a wellbore is carried out by introducing an emulsion composition into the formation through the wellbore wherein the formation has a formation temperature surrounding the wellbore of at least 120° C. The emulsion composition is formed from an aqueous acid component that forms an internal phase of the emulsion, non-aqueous component that forms an external phase of the emulsion, and a surfactant. The emulsion composition also includes an amount of fibers formed from high temperature polymer material. The high temperature polymer material is characterized by the property of not substantially degrading in water at pH<7 at temperatures below 80° C.

Abstract: A method of treating a subterranean formation penetrated by a wellbore comprising injecting electrically conductive or electromagnetic fibers into the subterranean formation during hydraulic fracturing is provided. Suitable metallic materials, organic polymers, and organic polymers coated with or containing conductive or electromagnetic materials are described. The treatment is followed by measurement of resistivity and/or electromagnetic properties, optionally by a crosswell technique.

Abstract: A method for treating a subterranean formation penetrated by a wellbore is provided. The method includes providing a treatment fluid containing a viscoelastic surfactant having at least one degradable linkage, a hydrolysable material, and a pH control material, and injecting the treatment fluid into a subterranean formation. The pH control material may have a pH equal or greater than about 9 and may include a strongly alkaline material and an oxidizing agent.

Abstract: The current application discloses compositions and methods for reducing fluid loss during subterranean operations. CO2 activated swellable elastomers can be used in subterranean operations to reduce fluid loss. In particular, the current application discloses compositions and methods for reducing lost circulation during drilling and drilling related subterranean operations.

Abstract: The current application discloses compositions and methods for treating a subterranean formation. CO2 swellable elastomers can be used in a treatment fluid to at least partially block a high permeability region, therefore improving the performance of an operation such as matrix stimulation, acidizing, and acid fracturing.

Abstract: A method of treating a geologic formation including injecting into a wellbore a high viscosity composition which comprises a base fluid wherein the base fluid has an initial viscosity of 100 cP or greater and which exhibits a decrease in viscosity upon exposure to a viscosity reducing agent, and fibers wherein the fibers exhibit flocking upon a decrease in the viscosity of the base fluid, and injecting into the wellbore a viscosity reducing agent wherein the viscosity reducing agent is injected into the wellbore with or separately from the high viscosity composition is provided.

Abstract: Methods for controlling fluid flow through one or more pathways in one or more rock formations penetrated by a borehole in a subterranean well, comprise injecting into or adjacent to the formation a treatment fluid comprising at least one polysaccharide polymer; at least one crosslinker; and fibers, or a mixture of fibers and particles. The fluids are pumped into the well through a tubular body that comprises at least one flow restriction. Shearing of the treatment fluid as it passes through the flow restriction causes the viscosity to decrease, allowing the fibers to form masses that migrate to formation-rock openings such as pores, cracks, fissures and vugs. As a result, the fibrous masses are useful for curing lost circulation, providing fluid-loss control and as diverting agents.

Abstract: Methods for controlling fluid flow through one or more pathways in one or more carbonate-rock formations penetrated by a borehole in a subterranean well, comprise injecting into or adjacent to the formation a treatment fluid comprising at least one viscoelastic surfactant; fibers, or a mixture of fibers and particles; and at least one acid. The initial fluid viscosity is sufficient to transport the fibers and particles; however, upon reacting with the carbonate rock, the fluid viscosity falls. The lower fluid viscosity promotes efficient fiber bridging across the pathways, thereby providing diversion.

Abstract: Methods for controlling fluid flow through one or more pathways in one or more rock formations penetrated by a borehole in a subterranean well, comprise injecting into or adjacent to the formation a treatment fluid comprising at least one viscoelastic surfactant; fibers, or a mixture of fibers and particles; and one or more flocculation initiators. Flocculation of the mixture produces fibrous masses that migrate to formation-rock openings such as pores, cracks, fissures and vugs. As a result, the fibrous masses are useful for curing lost circulation, providing fluid-loss control and as diverting agents.

Abstract: A method of treating a subterranean formation penetrated by a wellbore is carried out by introducing an emulsion composition into the formation through the wellbore wherein the formation has a formation temperature surrounding the wellbore of at least 120° C. The emulsion composition is formed from an aqueous acid component that forms an internal phase of the emulsion, non-aqueous component that forms an external phase of the emulsion, and a surfactant. The emulsion composition also includes an amount of fibers formed from high temperature polymer material. The high temperature polymer material is characterized by the property of not substantially degrading in water at pH<7 at temperatures below 80° C.

Abstract: A method for treating a subterranean formation penetrated by a wellbore is carried out introducing a treatment fluid into the formation through the wellbore wherein the formation has a formation temperature of at least 70° C. A composition for such treatment is also provided. The composition and treatment fluid for the method is formed from water and an amount of fibers formed from high temperature polymers of at least one of a polyester, polyamide, polyurethane, polyurea polymers, and copolymers of these. Each of said high temperature polymers is characterized by the property of not substantially degrading in water at a pH of from 5 to 9 at temperatures below 80° C. A fiber degrading accelerant that facilitates degrading of the fibers at the formation temperature is also included in the treatment fluid.

Abstract: In a method of treating a sandstone-containing formation penetrated by a wellbore, a treatment fluid comprising an aqueous fluid containing a Bronsted acid, a hydrogen fluoride source and an organic acid or salt thereof that is substantially soluble in the aqueous fluid is formed. The treatment fluid contains less than about 2% of fluoride (F?) by weight of the fluid and from 2% or less of sodium (Na+) by weight of the fluid. The treatment fluid is introduced into the formation through the wellbore as a single-stage without introducing an acid-containing fluid preflush into the formation prior to introducing the treatment fluid.

Abstract: In a method of treating a sandstone-containing formation penetrated by a wellbore, a treatment fluid comprising an aqueous fluid containing a Bronsted acid, a hydrogen fluoride source and an organic acid or salt thereof that is substantially soluble in the aqueous fluid is formed. The treatment fluid contains less than about 2% of fluoride (F?) by weight of the fluid and from 2% or less of sodium (Na+) by weight of the fluid. The treatment fluid is introduced into the formation through the wellbore as a single-stage without introducing an acid-containing fluid preflush into the formation prior to introducing the treatment fluid.