Olefin sulfonate-improved steam foam drive

Claim 2

A steam-foam-forming composition useful in the displacement of oil within the pores of or a production of oil from an oil-containing reservoir, consisting essentially of (a) water, present in the composition, at a temperature substantially equalling its boiling temperature at the reservoir pressure, in both a liquid phase and a vapor phase of steam having a quality of at least about 30% but not more than about 80%, (b) an electrolyte, present in the liquid phase in an amount between about 0.1 and 5 percent by weight, calculated on the weight of the liquid phase, (c) a surfactant component, present in the liquid phase in an amount between about 0.01 and 5 percent by weight, calculated on the weight of the liquid phase, said surfactant component comprising in substantial part olefin sulfonate obtained by hydrolysis and neutralization of the product of reacting sulfur trioxide with C 14 to C 20 olefins, and (d) a noncondensable gas, present in the vapor phase in an amount between about 0.0003 and 0.3 percent by mol, calculated on total mols in the vapor phase.

Claim 3

The composition of claim 1 wherein at least about 50% of the olefins have linear carbon chains.

Claim 4

The composition of claim 2 wherein the olefin sulfonate is derived from C 15 to C 20 olefins.

Claim 5

The compositions of claim 3 wherein at least about 50% of the olefins have linear carbon chains.

Claim 6

The composition of claim 4 wherein at least about 50% of the olefins are alpha-olefins.

Claim 7

The composition of claim 4 wherein at least about 75% of the olefins have linear carbon chains.

Claim 8

The composition of clain 6 wherein at least about 50% of the olefins are in the C 16 to C 18 range.

Claim 9

The composition of clain 6 wherein at least about 50% of the olefins are in the C 16 to C 18 range.

Claim 10

The composition of claim 7 wherein at least about 85% of the olefins have linear carbon chains.

Claim 11

The composition of claim 8 wherein at least about 50% of the olefins are alpha-olefins.

Claim 12

The composition of claim 7 wherein at least about 75% of the olefins are alpha-olefins.

Claim 13

The composition of claim 10 wherein at least about 90% of the olefins are alpha-olefins.

Claim 14

The composition of claim 8 wherein the electrolyte is an alkali metal salt.

Claim 15

The composition of claim 4 wherein the electrolyte is an alkali metal salt.

Claim 16

The composition of claim 7 wherein the electrolyte is an alkali metal salt.

Claim 17

The composition of claim 10 wherein the electrolyte is an alkali metal salt.

Claim 18

The composition of claim 13 wherein the electrolyte is a halide, sulfate, phosphate, or nitrate salt.

Claim 19

The composition of claim 16 wherein the electrolyte is a halide or sulfate salt of a metal selected from the class consisting of sodium and potassium, and the noncondensable gas is selected from the class consisting of nitrogen, air, methane, ethane, flue gas, and carbon dioxide.

Claim 20

A steam-foam-forming composition useful in the displacement of oil within the pores of, or recovering oil from an oil-containing reservoir, consisting essentially of (a) water, present in the composition at substantially its boiling temperature at the reservoir pressure, in both a liquid phase and a vapor phase, said vapor phase containing between about 30 and 80% by weight of the water and said liquid phase containing between about 70 and 20% by weight of the water, (b) the chloride salt of potassium or sodium, present in the liquid phase in a concentration of about 1 to 4% by weight, (c) olefin sulfonate derived from C 15 to C 20 olefins, present in the liquid phase in a concentration of about 0.2 to 1.0% by weight, at least about 50% of said C 15 to C 20 olefins having a carbon number in the range of from 16 to 18, inclusive, at least about 75% of said olefins having linear carbon chains and at least about 50% of said olefins being alpha-olefins, and (d) nitrogen, present in the vapor phase of the composition in a concentration of about 0.003 to 0.3% by mol.

Claim 21

A steam-foam-forming composition useful in the displacement of oil within the pores of, or recovering oil from an oil-containing reservoir, consisting essentially of (a) water, present in the composition at substantially its boiling temperature at the reservoir pressure, in both a liquid phase and a vapor phase, said vapor phase containing between about 30 and 80% by weight of the water and said liquid phase containing between about 70 and 20% by weight of the water, (b) the chloride salt of potassium or sodium, present in the liquid phase in a concentration of about 1 to 4% by weight, (c) olefin sulfonate derived from C 15 to C 20 olefins, present in the liquid phase in a concentration of about 0.2 to 1.0% by weight, at least about 50% of said C 15 to C 20 olefins having a carbon number in the range of from 16 to 18, inclusive, at least about 75% of said olefins having linear carbon chains and at least about 50% of said olefins being alpha-olefins, and (d) nitrogen, present in the vapor phase of the composition in a concentration of about 0.003 to 0.3% by mol.

Claim 22

In a process for displacing oil within an oil-containing subterranean reservoir by flowing a steam-containing fluid in conjunction with a surfactant component through the pores of a relatively steam-permeable zone with said reservoir, the improvement which comprises: employing as the fluid flowed through the pores of the reservoir the steam foam-forming composition of claim 1.

Claim 23

The process of claim 19, wherein the aqueous liquid phase of the steam-foam-forming composition contains between about 0.2 and 1.0 percent by weight of olefin sulfonate.

Claim 24

The process of claim 19, wherein the olefin sulfonate is derived in major part from C 16 to C 18 olefins.

Claim 25

The process of claim 19, wherein at least about 50 percent of the olefins are alpha-olefins.

Claim 26

The process of claim 19, wherein at least about 75 percent of the olefins have linear carbon chains and at least about 75 percent of the olefins are alpha-olefins.

Claim 27

The process of claim 19, wherein at least about 90 percent of the olefins have linear carbon chains and at least about 90 percent of the olefins are alpha-olefins.

Claim 28

A well treating process for displacing oil within pores of or recovering oil from a subterranean reservoir comprising: injecting into the pores of a steam-permeable oil-containing reservoir a steam-containing fluid which consists essentially of the steam foam-forming composition of claim 18.

Claim 29

The process of claim 25 in which the steam-foam-forming capability of said surfactant component is sufficient to provide a permeability reduction factor of less than about 0.18 in contact with the reservoir oil, or an oil substantially equivalent to it in viscosity and steam-foam-debilitating properties, when tested within a steam-containing fluid containing proportions of electrolyte and noncondensable gas which are at least near optimum for steam-foam-forming surface activity.

Claim 30

In a steam-channel-expanding steam foam drive process in which a steam-foam-forming mixture which contains a surfactant component, an electrolyte and a substantially noncondensable gas is injected into the pores of an oil-containing subterranean reservoir after a steam channel has been formed between wells by flowing steam through said pores in a portion of the reservoir in which the disposition of a steam flow path is determined by gravity and oil distribution rather than being substantially confined within layers of rlatively high absolute permeability, the improvement comprising: employing in said process a steam-foam-forming mixture consisting essentially of steam, noncondensable gas and an aqueous electrolyte-containing solution or dispersion of surfactant component which includes a proportion of C 14 to C 20 olefin sulfonate surfactant at least large enough so that the steam-foam-forming capability of the surfactant component which is employed exceeds that of a surfactant component containing less of the olefin sulfonate surfactant; correlating the composition of the steam-foam-forming mixture with the properties of the rocks and fluids in the reservoir so that the pressure required to inject the mixture and the foam it forms or comprises into and through the steam channel exceeds that required for steam alone but is less than the reservoir fracturing pressure; and adjusting the composition of the fluid being injected into the steam channel to the extent required to maintain a flow of both steam and foam within the channel in response to a relatively high pressure gradient at which the oil-displacing and channel-expanding effects are significantly greater than those provided by steam alone, without plugging the channel.

Claim 31

In a steam-channel-expanding steam foam drive process in which a steam-foam-forming mixture which contains a surfactant component, an electrolyte and a substantially noncondensable gas is injected into the pores of an oil-containing subterranean reservoir after a steam channel has been formed between wells by flowing steam through said pores in a portion of the reservoir in which the disposition of a steam flow path is determined by gravity and oil distribution rather than being substantially confined within layers of rlatively high absolute permeability, the improvement comprising: employing in said process a steam-foam-forming mixture consisting essentially of steam, noncondensable gas and an aqueous electrolyte-containing solution or dispersion of surfactant component which includes a proportion of C 14 to C 20 olefin sulfonate surfactant at least large enough so that the steam-foam-forming capability of the surfactant component which is employed exceeds that of a surfactant component containing less of the olefin sulfonate surfactant; correlating the composition of the steam-foam-forming mixture with the properties of the rocks and fluids in the reservoir so that the pressure required to inject the mixture and the foam it forms or comprises into and through the steam channel exceeds that required for steam alone but is less than the reservoir fracturing pressure; and adjusting the composition of the fluid being injected into the steam channel to the extent required to maintain a flow of both steam and foam within the channel in response to a relatively high pressure gradient at which the oil-displacing and channel-expanding effects are significantly greater than those provided by steam alone, without plugging the channel.

Claim 32

The process of claim 27 in which the steam-foam-forming capability of the steam-foam-forming mixture is sufficient to provide a permeability reduction factor of less than about 0.18 in contact with the reservoir oil, or one substantially equivalent to it in viscosity and steam-foam-debilitating properties.

Claim 33

A process for recovering oil from a subterranean reservoir, comprising: injecting steam and producing fluid at horizontally spaced locations within a portion of a viscous oil reservoir in which the disposition of a steam flow path is determined by the effect of gravity and/or oil distribution, rather than being substantially confined within only one or a few most permeable layers of reservoir rocks; maintaining rates of steam injection and fluid production such that a steam breakthrough into a production location becomes at least substantially imminent and the extension of a steam channel from an injection location to a production location is at least substantially complete; changing the composition of the fluid being injected from steam to a steam-foam-forming mixture consisting essentially of steam, noncondensable gas and an aqueous electrolyte-containing solution or dispersion of surfactant; said surfactant consisting of a surfactant component which contains enough C 14 to C 20 olefin sulfonate surfactant to cause the steam-foam-forming capability of said surfactant component to exceed that of an otherwise similar surfactant component containing less of said olefin sulfonate; correlating the composition of the steam-foam-forming mixture with the properties of the rocks and fluids in the reservoir so that the pressure required to inject the mixture and the foam it forms or comprises into and through the steam channel exceeds that required for steam alone but is less than the reservoir fracturing pressure; and adjusting the composition of the fluid being injected into the steam channel to the extent required to maintain a flow of both steam and foam within the channel in response to a relatively high pressure gradient at which the oil-displacing and channel-expanding effects are significantly greater than those provided by steam alone, without plugging the channel.

Claim 34

A process for recovering oil from a subterranean reservoir, comprising: injecting steam and producing fluid at horizontally spaced locations within a portion of a viscous oil reservoir in which the disposition of a steam flow path is determined by the effect of gravity and/or oil distribution, rather than being substantially confined within only one or a few most permeable layers of reservoir rocks; maintaining rates of steam injection and fluid production such that a steam breakthrough into a production location becomes at least substantially imminent and the extension of a steam channel from an injection location to a production location is at least substantially complete; changing the composition of the fluid being injected from steam to a steam-foam-forming mixture consisting essentially of steam, noncondensable gas and an aqueous electrolyte-containing solution or dispersion of surfactant; said surfactant consisting of a surfactant component which contains enough C 14 to C 20 olefin sulfonate surfactant to cause the steam-foam-forming capability of said surfactant component to exceed that of an otherwise similar surfactant component containing less of said olefin sulfonate; correlating the composition of the steam-foam-forming mixture with the properties of the rocks and fluids in the reservoir so that the pressure required to inject the mixture and the foam it forms or comprises into and through the steam channel exceeds that required for steam alone but is less than the reservoir fracturing pressure; and adjusting the composition of the fluid being injected into the steam channel to the extent required to maintain a flow of both steam and foam within the channel in response to a relatively high pressure gradient at which the oil-displacing and channel-expanding effects are significantly greater than those provided by steam alone, without plugging the channel.