A surfactant of formula (I) ##STR00001## wherein each of R.sub.1 and R.sub.2 are independently a hydrogen, an optionally substituted alkyl, an optionally substituted cycloalkyl, or an optionally substituted arylalkyl, R.sub.3 and R.sub.4 are independently an optionally substituted alkyl, an optionally substituted cycloalkyl, or an optionally substituted arylalkyl, x is an integer in a range of 2-8, y is an integer in a range of 1-15, z is an integer in a range of 4-10, n is an integer in a range of 2-5, and A is one of a carboxybetaine group, a sulfobetaine group, or a hydroxy sulfobetaine group. An oil and gas well servicing fluid containing the surfactant and methods of servicing an oil and gas well are also described.

A surfactant of formula (I) ##STR00001## wherein each of R.sub.1 and R.sub.2 are independently a hydrogen, an optionally substituted alkyl, an optionally substituted cycloalkyl, or an optionally substituted arylalkyl, R.sub.3 and R.sub.4 are independently an optionally substituted alkyl, an optionally substituted cycloalkyl, or an optionally substituted arylalkyl, x is an integer in a range of 2-8, y is an integer in a range of 1-15, z is an integer in a range of 4-10, n is an integer in a range of 2-5, and A is one of a carboxybetaine group, a sulfobetaine group, or a hydroxy sulfobetaine group. An oil and gas well servicing fluid containing the surfactant and methods of servicing an oil and gas well are also described.

A method of improving rheological properties of a divalent brine based downhole treatment fluid at an elevated temperature comprises adding to the divalent brine based downhole treatment fluid a rheological modifier, which comprises a carboxylic acid ester, or a phosphate ester blended with an ethoxylated glycol, or a combination comprising at least one of the foregoing in an amount effective to improve the rheological properties of the divalent brine based downhole treatment fluid at a temperature of greater than about 200° F. The divalent brine based downhole treatment fluid comprises calcium bromide, calcium chloride, zinc bromide, zinc chloride, or a combination comprising at least one of the foregoing.

A method of improving rheological properties of a divalent brine based downhole treatment fluid at an elevated temperature comprises adding to the divalent brine based downhole treatment fluid a rheological modifier, which comprises a carboxylic acid ester, or a phosphate ester blended with an ethoxylated glycol, or a combination comprising at least one of the foregoing in an amount effective to improve the rheological properties of the divalent brine based downhole treatment fluid at a temperature of greater than about 200° F. The divalent brine based downhole treatment fluid comprises calcium bromide, calcium chloride, zinc bromide, zinc chloride, or a combination comprising at least one of the foregoing.

A modified high density brine for use in subterranean drilling and completion operations. The modified high density brine includes a heavy brine and the addition of high density particles. The resultant modified high density brine eliminates the need for toxic, corrosive, and costly ZrBr.sub.2 or cesium formate additions or other ionic additives to boost the density of the modified high density brine to more than 14 lbs./gallon.

A modified high density brine for use in subterranean drilling and completion operations. The modified high density brine includes a heavy brine and the addition of high density particles. The resultant modified high density brine eliminates the need for toxic, corrosive, and costly ZrBr.sub.2 or cesium formate additions or other ionic additives to boost the density of the modified high density brine to more than 14 lbs./gallon.

A method for the fracking or stimulation of a hydrocarbon-bearing formation, said method comprising the steps of: providing a wellbore in need of stimulation; inserting a plug in the wellbore at a predetermined location; inserting a perforating tool and a spearhead or breakdown acid into the wellbore; positioning the tool at said predetermined location; perforating the wellbore with the tool thereby creating a perforated area; allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient to prepare the formation for fracking or stimulation; removing the tool from the wellbore; and initiating the fracking of the perforated area using a fracking fluid. Also disclosed is a corrosion inhibiting composition for use with the acid composition.

A method for the fracking or stimulation of a hydrocarbon-bearing formation, said method comprising the steps of: providing a wellbore in need of stimulation; inserting a plug in the wellbore at a predetermined location; inserting a perforating tool and a spearhead or breakdown acid into the wellbore; positioning the tool at said predetermined location; perforating the wellbore with the tool thereby creating a perforated area; allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient to prepare the formation for fracking or stimulation; removing the tool from the wellbore; and initiating the fracking of the perforated area using a fracking fluid. Also disclosed is a corrosion inhibiting composition for use with the acid composition.

Heavy fluids are made from calcium bromide and at least one hydrogen bond donor such as a low molecular weight polyol or an organic acid. The combination of a hydrogen bond donor and calcium bromide as a hydrogen bond acceptor in an appropriate molar ratio forms a higher density clear completion fluid at a low temperature not otherwise obtainable with heavy aqueous solutions of calcium bromide such as are used in oilfield wells. A method of making the fluid comprises mixing calcium bromide with the polyol(s) in the presence of water and then reducing the water content, thus forming a heavy fluid. A crystallization inhibitor such as nitrilotriacetamide or a particulate silicate is included in the formulation. When the heavy fluid “freezes,” its physical form is somewhat amorphous and pumpable rather than crystalline. The heavy fluid is useful as a drilling fluid as well as a completion fluid and for other purposes in oil recovery processes where extreme density is beneficial.

Heavy fluids are made from calcium bromide and at least one hydrogen bond donor such as a low molecular weight polyol or an organic acid. The combination of a hydrogen bond donor and calcium bromide as a hydrogen bond acceptor in an appropriate molar ratio forms a higher density clear completion fluid at a low temperature not otherwise obtainable with heavy aqueous solutions of calcium bromide such as are used in oilfield wells. A method of making the fluid comprises mixing calcium bromide with the polyol(s) in the presence of water and then reducing the water content, thus forming a heavy fluid. A crystallization inhibitor such as nitrilotriacetamide or a particulate silicate is included in the formulation. When the heavy fluid “freezes,” its physical form is somewhat amorphous and pumpable rather than crystalline. The heavy fluid is useful as a drilling fluid as well as a completion fluid and for other purposes in oil recovery processes where extreme density is beneficial.