Provided is a lost circulation material that may consist essentially of an alkaline nanosilica dispersion and a sodium bicarbonate activator. Further provided are methods that may control lost circulation in a lost circulation zone in a wellbore by introducing the lost circulation material such that it contacts the lost circulation zone and forms a gelled solid in the lost circulation zone.

A method of servicing a wellbore penetrating a subterranean formation, comprising placing a wellbore servicing fluid (WSF) into the wellbore proximate a permeable zone having an average fracture width of about W microns, wherein the WSF comprises a particulate blend and water, and wherein the particulate blend comprises (a) a type A particulate material characterized by a weight average particle size of equal to or greater than about W/3 microns, and (b) a type B particulate material characterized by a weight average particle size of less than about W/3 microns, wherein a weight ratio of the type A particulate material to the type B particulate material is from about 0.05 to about 5.

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 of treating a lost circulation zone in a wellbore includes contacting an accelerant composition comprising triethanolamine with a cement composition in the lost circulation zone, the cement composition comprising at least: from 1 weight percent (wt. %) to 90 wt. % cement precursor based on the total weight of the cement composition; and from 5 wt. % to 70 wt. % water based on the total weight of the cement composition; where a weight ratio of triethanolamine to the cement precursor is from 0.1 percent (%) to 60%; and curing the cement composition in the lost circulation zone to form a cured cement, where the triethanolamine accelerates the curing rate of the cement composition and the cured cement seals the lost circulation zone.

The present disclosure relates to downhole fluid additives including a clay, a hydroxylated polymer, a cation, and water. The disclosure further relates to downhole fluids, including drilling fluids, spaces, cements, and proppant delivery fluids containing such as downhole fluid additive and methods of using such fluids. The downhole fluid additive may have any of a variety of functions in the downhole fluid and may confer any of a variety of properties upon it, such as salt tolerance or desired viscosities even at high downhole temperatures.

Compositions, methods, and systems for using particulates treated with one or more hydrophobizing agents in forming filter cakes during drilling to improve filter-cake removal. A method for drilling a wellbore may include circulating a drilling fluid in the wellbore, wherein the drilling fluid comprises particulates treated with one or more hydrophobizing agents; extending the wellbore while the drilling fluid is circulated in the wellbore; and forming a filter cake in the wellbore, wherein the filter cake comprises a portion of the particulates from the drilling fluid.

A method for temporary isolation of a well interval is proposed, the method comprising: pumping a first slurry into the well, the slurry comprising a viscous carrier fluid, degradable particulates, and degradable fibers, until a first filter cake is formed; and pumping a second slurry into the well, the slurry comprising a viscous carrier fluid, non-degradable particulates, and degradable fibers, until a second filter cake is formed. The first and the second slurries are not mixed when pumped into the well. To ensure optimum interval isolation, the ratio of the volume of the first slurry to the volume of the second slurry should be in the range 1:5 to 2:1. A method for hydraulic refracturing within an interval with several hydraulic fractures and a non-damaging well killing method are also proposed. The technical result is manifested in no formation damage and degradation of the sealing layer formed.

A system and method for treating lost circulation, including providing a treatment fluid including a polymer and a nitrogen-generating compound through a wellbore into a lost circulation zone in a subterranean formation, generating nitrogen gas in the lost circulation zone by a reaction of the nitrogen-generating compound, generating foam from the nitrogen gas and the treatment fluid in the lost circulation zone to give foamed polymer in the lost circulation zone, and plugging the lost circulation zone with the foamed polymer.

The present disclosure relates to material for use in oil and gas well completion activities. More particularly, the present disclosure relates to diversion particles, along with methods for making and using the diversion particles. In an embodiment, a composite diversion material includes a non-degradable component comprising two or more non-degradable particulates, wherein the non-degradable particulates have a long term permeability at 7,500 psi of at least about 20 D. The composite diversion material includes a degradable component surrounding at least a portion of the non-degradable component. In another embodiment, a method of making a composite diversion material includes mixing non-degradable proppant particles with an aqueous solution containing a first degradable material to provide a mixture having a proppant concentration of at least about 20 volume percent. The method includes drying the mixture at a temperature of from about 25° C. to about 200° C. to provide the composite diversion material.

A method includes placing a weighted fluid in the subterranean formation. The weighted fluid includes calcium bromide. The weighted fluid includes one or more secondary salts that are each independently an inorganic bromide salt other than calcium bromide. The weighted fluid also includes water. The weighted fluid has a density at standard temperature and pressure of at least about 1.7 g/cm3.