Nano-sized clay minerals enhance the viscosity of aqueous fluids that have increased viscosity due to the presence of viscoelastic surfactants (VESs). In one non-limiting theory, the nano-sized phyllosilicate mineral viscosity enhancers associate, link, connect, or relate the VES elongated micelles into associations thereby increasing the viscosity of the fluid, possibly by mechanisms involving chemisorption or surface charge attractions. The nano-sized phyllosilicate mineral particles, also called clay mineral nanoparticles, may have irregular surface charges. The higher fluid viscosity is beneficial to crack the formation rock during a fracturing operation, to reduce fluid leakoff, and to carry high loading proppants to maintain the high conductivity of fractures.

An acid corrosion inhibitor is provided that is compatible with viscoelastic surfactants and useful for enhancing the production of hydrocarbon bearing formations. The viscoelastic surfactant can used in fracturing of subterranean formations penetrated by an oil or gas well or in connection with acidizing or other treatment processes. The acid corrosion inhibitor can include a viscoelastic surfactant and an active inhibition compound which can comprise a reaction product of thiourea, paraformaldehyde and acetophenone, or amines (linear or cyclic), amine quaternaries (linear or cyclic) or combinations or mixtures thereof.

A viscosified aqueous solution, optionally for use in a subterranean wellbore, is made by reacting in aqueous solution (i) an initial polymer with either carboxylic acid or amino groups on its polymer chain, (ii) a second compound with an amino group or carboxylic acid group, and (iii) a coupling agent, so that molecules of the second compound join to the polymer chain through amide groups, thereby forming an aqueous solution of a modified polymer which, without separation from the aqueous solution, participates in cross-linking thereby enhancing viscosity of the solution. The second compound may include hydrophobic groups so that the modified polymer contains hydrophobic groups and is able to cross-link with itself or a viscoelastic surfactant through association of hydrophobic groups (without covalent bond formation) in aqueous solution. Such cross-links can reform after the fluid has been subjected to shear.

A method, system, and program for billing for service provided to destination device according to the calling plan of the individual receiving the call. An authenticated identity for a callee answering a call placed to a destination device is received at an intermediary device. The intermediary device then accesses a billing plan for the authenticated identity of the callee and loads the billing plan for specifying charges for the call, such that telephone service billed to the callee is accessible at multiple destination devices.

A wellbore fluid may include a gemini surfactant, a zwitterionic surfactant, an activator, and an aqueous base fluid. The gemini surfactant may have a structure represented by formula (I):

##STR00001##

where R.sup.1 is a C.sub.1-C.sub.10 hydrocarbon group, m and o are each, independently, an integer ranging from 1 to 4, and n is an integer ranging from 8 to 12.

Stimulation treatments are designed and performed in a manner that takes into account radial acid flow into the formation. A reservoir core plug is selected and a liner core flow test is performed. The core flow test comprises measuring a flowing fraction, injecting into the core plug a treatment volume of at least one candidate stimulation fluid at an injection rate at reservoir conditions, and measuring an effective reaction rate constant. The linear flow data are then scaled to radial flow. A skin, an acid concentration at a wormhole tip and a fluid velocity at a wormhole tip are calculated. A stimulation treatment is then performed. The method can also be performed on analog cores. The stimulation treatment may be matrix acidizing, fracture acidizing or acidizing natural fractures.

A method and reactive treatment fluid for treating a wellbore for filter cake removal, including providing the reactive treatment fluid having a viscoelastic surfactant (VES) into a wellbore in a subterranean formation and attacking the filter cake via the reactive treatment fluid.

A fluid and a method for treating a subterranean formation penetrated by a wellbore. The method provides for injecting a treatment fluid for hydraulic fracturing, wherein the treatment fluid contains a low viscosity carrier fluid, a proppant dispersed in the low viscosity carrier fluid and a fiber blend with different stiffnesses that have silicone finishing. The method provides for improved dispersion of fibers, reduces the proppant settling rate and reduces the probability of fiber bridging in hydraulic fractures.

A method of recycling a direct emulsion wellbore fluid may include disrupting a direct emulsion comprising an aqueous external phase and an oleaginous internal phase, wherein the direct emulsion is stabilized by a surfactant composition; and separating the aqueous phase and the oleaginous phase.

A wellbore fluid including a first surfactant, a second surfactant, an activator and an aqueous base fluid is provided. The first surfactant has a structure represented by Formula (I): ##STR00001##
where Y.sub.1, Y.sub.2, Y.sub.3, Y.sub.4 are each, independently, a sulfonate, a carboxylate, an ester or a hydroxyl group, m is an integer ranging from 2 to 3, and n, o, and k are each, independently, integers ranging from 2 to 10. The second surfactant has a structure represented by Formula (III): ##STR00002##
where R.sub.2 is a C.sub.15-C.sub.27 hydrocarbon group or a C.sub.15-C.sub.29 substituted hydrocarbon group, R.sub.3 is a C.sub.1-C.sub.10 hydrocarbon group, and p and q are each, independently, an integer ranging from 1 to 4. A method of using the wellbore fluid for treating a hydrocarbon-containing formation is also provided.