Miscible gas enhanced oil recovery method using oil-brine compatible pre-formed foam

Oil recovery from a petroleum reservoir using a miscible gas, such as carbon dioxide, nitrogen or methane is enhanced by injecting a preformed stable foam into the reservoir. The foam composition is formed by an effective amount of an alpha olefin sulfonate (AOS) capable of forming a foam with water having a salt content similar to that in the reservoir and the miscible gas. Preferably, the alpha olefin sulfonates have from 8 to 24 carbon atoms. In a preferred form the AOS has on average a carbon content of less than about 12 carbon atoms in higher salt content brines and less than about 12 carbon atoms in lower salt content brines. Most preferably, in brines having a salt concentration of at least 10 weight percent, the AOS has on average about 10 carbon atoms; in brines having a salt concentration of from 2 to 10 weight percent the AOS has on average about 12 carbon atoms; and in brines having less than 2 weight percent salt and AOS has on average about 14 carbon atoms.

FIELD OF THE INVENTION 
The present invention relates to enhanced oil recovery from a petroleum 
bearing formation. More particularly, it relates to enhancing production 
of oil from a producing formation wherein a non-condensible, miscible gas 
is used to improve the mobility of oil through the producing formation and 
a stable foam, compatible with the formation fluids including connate gas, 
oil and water or brine, is injected with the gas to direct gas pressure to 
the less permeable oil-rich portions of the formation. 
It is a particular object of the present invention to provide a pre-formed 
foam that is compatible with the oil and brine content of 
petroleum-bearing formation into which a non-condensible miscible gas such 
as carbon-dioxide, nitrogen or methane, has been injected to assist oil 
displacement. Such gases reduce the viscosity of the native oil and 
re-pressure the formation to increase the flow of petroleum from at least 
one injection well to at least one producing well. These miscible gases 
are known to result in reduced viscosity of the petroleum by their mutual 
interaction, but, because of the inhomogeneity of most earth formations 
for each of the three phases, gas, oil and water, additional means are 
required to control the gas to avoid pressure loss to high permeability 
channels or "fingers" that form in the reservoir rock. Fingering of gas 
into relatively high permeability gas and water, or brine, channels 
interferes with the injection profile of the drive gas in the formation 
because substantially equal gas pressure is not available to move fluids 
through the low permeability oil-rich portions of the formation. Such 
pressure loss channels may also be generated by gravity effects of the low 
density gas which tends to cause the gas to rise to the top of the 
formation so that it overrides oil and water channels in the lower part of 
the formation. 
To control such injection profiles, either due to fingering or gravity 
override, it has been proposed to use foam, in the same manner it is used 
to improve injection of steam to enhance oil recovery. However, in using a 
non-condensible, miscible gas, (rather than condensible steam), creation 
and maintenance of an effective foam in a three phase liquid system is 
difficult, particularly where the salt concentration of water in the 
formation (connate or injected) tends to break the foam or prevent it from 
forming initially. Accordingly, it is a particular object of the invention 
to provide a foam compatible with the formation oil and brine mixture 
which can be preformed before the foam is injected into the formation. 
Such foam is a mixture of the noncondensible gas, a brine comparable to 
that in the formation and an alpha olefin sulfonate (AOS) having from 8-24 
carbon atoms, with the number of such carbon atoms being selected in 
accordance with the salt content of the brine. Contrary to prior known 
methods of forming a foam by using AOS as the foaming agent with water and 
gas and wherein higher molecular weight AOS has been used with higher salt 
concentrations in the brine, I have discovered that to form a stable foam 
in such brines, the carbon content of the AOS must be selected in 
accordance with an inverse relationship between salt content and AOS 
carbon content. Specifically, I have found that in brines having a higher 
salt concentration, desirably the AOS has on average less than about 12 
carbon atoms. In brines having a lower salt concentration, desirably the 
AOS has on average at least about 12 carbon atoms. In a more preferred 
embodiment, the foam is preformed of a non-condensible gas, such as carbon 
dioxide, nitrogen or methane and mixtures thereof, and a brine similar to 
that in the producing formation and an effective foam forming amount of 
alpha olefin sulfonate. Desirably the alpha olefin sulfonates have a 
carbon content of from 10 to 16 carbon atoms. The foam in its most 
preferred form includes: in brines having a salt concentration of at least 
about 10 weight percent, the AOS has on average about 10 carbon atoms; in 
brines having a salt content of from about 2 to 10 weight percent, the AOS 
has on average about 12 carbon atoms; and in brines having a salt 
concentration of not more than about 2 weight percent, the AOS has on 
average about 14 carbon atoms. 
In a preferred method of carrying out enhanced oil recovery using a 
preformed foam, a portion of noncondensible miscible gas is mixed with a 
brine having a salt content similar to that of the oil-bearing formation 
and an alpha olefin sulfonate selected in accordance with the invention. 
The fluids are injected into a well entering the formation and either 
preformed into a foam before introduction into the well or by adequate 
mixing of the constituents as the foam is pumped through the well and into 
the formation. The volume of the preformed foam is adequate to establish a 
stable bank of foam within the formation and particularly one which will 
enter the more permeable portions of the formation in sufficient quantity 
and with sufficient stability to maintain the foam when subsequently 
pressurized with the noncondensible miscible gas. The adequacy of the foam 
bank may be determined by production of oil through at least one producing 
well to which oil is driven by continued pressurization, so that reduced 
amounts of water and injection gas bypass oil rich portions of the 
formation before arriving at the producing well. 
BACKGROUND OF THE INVENTION 
It has been proposed heretofore to use a noncondensible miscible gas such 
as carbon dioxide, nitrogen, methane and the like for stimulating oil 
production from a petroleum-bearing formation. Such gas is injected into 
at least one well and petroleum is produced from at least one other well, 
penetrating the same formation. In general these gases have a relatively 
low critical point, that is the temperature above which the gas cannot be 
compressed to a liquid. Such gases are at least partially soluble in the 
oil. Because these gases, although noncondensible, are in fact soluble, or 
miscible in the oil, they are absorbed by the petroleum, either to reduce 
the viscosity of the oil or to increase its mobility through the 
formation, and at the same time the increased pressure of the gas drives 
residual petroleum in the formation to a producing well or wells. 
As with all enhanced oil-recovery processes, the formation is quite 
non-uniform having been formed initially as a geological bed and then 
entrapping oil and gas (generally by displacing water) and gas therein 
over geological time. Because of the heterogeneity of the formation, 
primarily due to the inclusion of clays or shale material in the 
sedimentary beds, permeability to flow of liquids through the formation is 
quite variable throughout its structure. Further, the permeability of the 
formation to flow of each of the components, oil, gas and water frequently 
differs substantially in various parts of the formation. In general, the 
formation permeability is substantially greater for gas than for oil or 
water. As a result, the injection gas tends to "finger" through the 
reservoir formation, and primarily due to density differences through 
upper portions of the reservoir. This creates gravity separation, known as 
"gravity override" of the gas so that it tends to by-pass, or break 
through, the reservoir between injection and producing wells. 
Additionally, water may also create preferential flow-paths and similarly 
by-pass oil in less permeable portions of the earth formation. It is of 
course, most desirable that the injected gas act on the fluids of the 
formation as a piston-like displacement so that all fluids move at 
substantially the same rate through the formation. Thus, desirably the 
"injection profile" for the gas is made as nearly equal as possible at all 
points in the reservoir. 
It has been proposed heretofore to use foam in the same manner as it has 
been used in steam-assisted oil recovery methods to equalize the injection 
profile across the formation. The injected foam tends to block more gas 
permeable portions of the formation so that the steam or gas pressure is 
diverted toward oil in the less permeable channels of the formation. 
However, a particular problem encountered in most earth formations is that 
the connate water is relatively saline, that is, the water or brine has a 
relatively high salt content as compared to fresh water. Furthermore, the 
brine content varies substantially between geological provinces (such as 
California vs. Gulf Coast, or mid-continent fields) as well as from field 
to field and from formation to formation. Depending upon the geological 
formation, the environment in which the oil was originally generated, or 
captured within rocks serving as a reservoir, the salt content of the 
brine may vary from 1% or less by weight to water substantially saturated 
with salt, e.g., in excess of 12% by weight. Such variations in salt 
content of formation waters may be due to either the oil having been 
generated or trapped in substantially fresh water, such as littoral beds 
in lakes, seas or rivers that are relatively salt-free. Higher salt 
content of the brine may be found where the oil is captured in reefs 
including salt beds or along the edges of salt domes, where over 
geological ages the water became saturated by solution of the salt. 
Because of such wide variations in the salt content, it has been found 
difficult both to form and maintain a foam which will remain stable in the 
presence of such brines. Further, the oil content of the formation may 
also prevent the formation of the foam or rapidly break such a foam when 
formed by a common foaming agent, such as alpha olefin sulfonates, in 
brine or water and introduced into a producing formation using a 
noncondensible miscible gas drive. 
As particularly distinguished from prior art methods, the present invention 
forms a stable foam of the noncondensible, miscible gas, such as the gas 
being used in an enhanced oil recovery process in a reservoir and one or 
more alpha olefin sulfonates which are effective to form a foam that is 
stable in contact with reservoir fluids, including petroleum and water 
comparable in salt content to water present in the reservoir. 
SUMMARY OF THE INVENTION 
In accordance with one aspect of the present invention there is provided a 
method of enhancing recovery of petroleum from an oil bearing formation 
during injection of a non-condensible gas having at least partial 
miscibility in the oil by at least periodically injecting a preformed foam 
composition into the reservoir. The foam is formed by an effective amount 
of alpha olefine sulfonates (AOS) and a brine similar to the reservoir 
water. The preformed foam is preferably a mixture of the non-condensible 
gas, brine and an alpha olefin sulfonate having from 8 to 24 carbon atoms. 
The number of carbon atoms of the AOS constituents are desirably selected 
in accordance with the salt content of the brine so that at higher salt 
concentrations the AOS has on average less than about 12 carbon atoms and 
at lower salt concentrations the AOS has on average at least about 12 
carbon atoms. In a preferred form the non-condensible gas includes 
CO.sub.2, N.sub.2, CH.sub.4 and mixtures thereof. 
Most preferably, where the salt concentration of the brine is at least 
about 10 percent by weight, the AOS has on average about ten carbon atoms. 
Where the salt concentration of the brine is not greater than about two 
percent by weight, the AOS has about fourteen carbon atoms. 
The effective amount of foam forming AOS required is determined by a 
combination of the concentration of AOS dissolved in the brine portion of 
the foam and the foam quality, that is, the relative proportions of liquid 
and gas in the foam. Preferably the liquid volume fraction of the 
preformed foam does not exceed about fifty percent; more preferably the 
liquid volume fraction is between five percent and fifty percent; and most 
preferably between about ten percent and thirty percent. The concentration 
of AOS in the brine can range from about 0.1 weight percent, which is just 
above the critical micelle concentration, to 1% or more, the upper limit 
usually being selected by cost constraint. 
In accordance with another aspect of the present invention, it comprehends 
a method of enhancing oil recovery from an oil bearing formation wherein a 
miscible, non-condensible gas is injected to pressurize the formation 
fluids and/or increase the mobility of oil in the formation by preforming 
a stable foam from a portion of the miscible gas, a brine having a salt 
content substantially similar to water in the formation and an alpha 
olefin sulfonate compatible with said brine. The foam, stable in the 
presence of oil in the formation, is injected through at least one well 
bore penetrating the formation in sufficient volume to maintain a 
substantially continuous bank of the stable foam between the miscible gas 
and the permeability channels for gas, oil and water through said 
formation. Gas is then injected into said formation to drive said foam 
into said channels to enhance recovery of oil from the less permeable 
portions of said formation through at least one producing well penetrating 
the formation. 
In a preferred form the alpha olefin sulfonate of the foam is selected to 
have from 8 to 24 carbon atoms so that such AOS is compatible with the 
salt content of the brine forming the foam. In a brine having a salt 
content in excess of about ten percent by weight, the alpha olefin 
sulfonate component has on average about 10 carbon atoms. In a brine 
having a salt content of not over two percent by weight, said alpha olefin 
sulfonate has on average about 14 carbon atoms. 
Further in accordance with the method of the invention the alpha olefin 
sulfonate is selected to have on average about 12 carbon atoms in foam 
formed of brine having a salt concentration of from about two percent to 
ten percent by weight. 
In accordance with the invention, alpha olefin sulfonates having either an 
odd or an even number of carbon atoms in the molecule may be used with 
equal effectiveness. As well understood in the art, alpha olefins may be 
produced either by the Ziegler process which generates even numbers of 
carbon atoms in the alpha olefin molecules or by steam cracking of wax 
which produces both odd and even numbers of carbon atoms in the molecule. 
The latter process is described in U.S. Pat. No. 3,488,384--Kessler et al. 
Accordingly, the number of carbon atoms in alpha olefin sulfonates "on 
average" as used in the practice of the method includes not only mixtures 
of molecules having an even number of carbon atoms, but also an odd number 
of carbon atoms. 
Further objects and advantages of the present invention will become 
apparent from the following detailed description of the methods of the 
present invention set forth below, including the drawings and examples 
forming an integral part of the present application.

DESCRIPTION OF THE INVENTION 
The present invention is, at least in part, based on the discovery that 
creation and maintenance of a foam in an earth formation containing waters 
of different salt content and oil composition require special tailoring of 
the surfactant material to prevent the salt content of the water or brine 
from interfering with foam generation or stability. Contrary to normal 
expectations as to activity of foaming agents, such as alpha olefin 
sulfonates, I have found that qualitatively the higher the salt content of 
the brine the lower the number of carbon atoms in such AOS that are 
required to make a stable foam that will persist in an environment of oil, 
gas and water within a formation. And such persistence is particularly 
useful in reservoirs undergoing assisted recovery using a miscible, 
non-condensible gas such as nitrogen, carbon dioxide or methane. Further 
the foam is desirably formed to a desirable liquid fraction or foam 
quality before it is injected into the formation with greater expectation 
that the foam will persist and thereby form a barrier particulary in the 
high permeability areas, such as those through which gas flows due to 
gravity override or fingering. Thus the injected gas will apply equal but 
higher pressure to the low permeability channels primarily in the lower 
part of the formation and richest in oil content. Increased oil production 
accordingly is obtained from a production well penetrating the same 
formation. 
FIG. 1 illustrates schematically an arrangement for injecting the foam into 
an injection well and the formation. A source of gas under relatively high 
pressure is supplied to each injection well which in practice may either 
be a central well producing radially outwardly to a group of producing 
wells surrounding the injection well or the injection well may be one of 
several in a line capable of creating a "front" for driving oil through 
the formation to one or a line of producing wells. In FIG. 1 a single 
injection well and a single producing well are illustrative of the system. 
A source gas 10 supplies a miscible, non-condensible gas such as carbon 
dioxide, nitrogen, or methane through pipe line 10 to injection well 12. 
For illustrative purposes, a compressor 14 driven by motor 16 supplies the 
gas at a desirable pressure to well 12 through well head 18 and injection 
pipe 20. The gas is conducted to the desired earth formation 22 through an 
injection pipe string 24 within casing 26. Injection string 24 may be 
isolated within well bore 12 in casing 26 above and below formation 22 by 
packers 28. 
As indicated before, the permeability of nearly all sedimentary earth 
formations which form petroleum reservoirs such as 22 are inherently 
inhomogeneous to flow of connate liquids, water, oil, and gas. Each of 
these fluids tend to flow selectively in permeability channels that have 
the least resistance to such flow. The resistance of flow of each 
primarily depends on viscosity either through or along with the other 
fluids. Typically, the resulting permeability for flow of each fluid is 
different in each formation. Since gases are more mobile than either oil 
or water, or their mixtures, injected gas in general tends to flow through 
more permeable gas channels or "fingers" 30 of formation 22 as indicated 
by dash lines. This gas flow by-passes "tighter" or less permeable zones 
wherein the oil-permeable passages are smaller or the oil is more tightly 
bound to the surface of the rock. In particular, the oil may also be in 
contact with clay or shale material with sand or carbonate components that 
form the permeable channels. Thus, "fingering" as indicated by channels 
30, or "gas override" as indicated by area 32 at the top of formation 22, 
generally develops so that large portions of the liquid oil is not 
adequately pressured by the injected gas. As a result, gas flows 
predominantly through the lower resistance paths, gas channels 30 and 32. 
This distorts the desired injection profile for the gas as indicated 
generally by dotted line 34 to produce a piston-like movement of oil 
through the formation. 
As indicated above, distortion of the injection profile may be corrected by 
addition of particular foam-forming components to the injected gas stream 
through injection line 35. For this purpose, surfactant and water brines 
are supplied by tanks 36 and 38 through valves 40 and 42, respectively by 
metering pump 37 to foam generator 44 and then to injection line 35. Foam 
may be supplied to the formation by forming it in generator 44 with gas 
before injection into well head 18. For this purpose a portion of such gas 
flow is from line 20 to generator 44 through line 46 under control of 
valve 48 to develop the desirable foam quality (gas/liquid ratio). Foam 
may also be formed in injection line 24 before contact with formation 
fluids, as by flow of surfactant solution and gas throughout perforations 
50 and the lower end of tubing 24. Foam so generated upon injection 
preferentially flows with the gas to gas-permeable channels 30, 32. It 
effectively plugs them so that gas in the formation is then diverted to 
increase pressure on oil-rich portions of the formation. The desired 
result is indicated by the relatively piston-like movement of the miscible 
gas front indicated by dotted lines 34. 
In the present illustration, oil is produced from an adjacent producing 
well, such as 51, by a pump 53 operating through sucker rods 52 through 
well head 54. The surfactant composition prepared in accordance with the 
present invention, is preferably supplied as a liquid solution so that it 
may be pumped from tanks 36 and 38, and metered by pump 37 through line 35 
at a desired rate to contact gas flowing in well head 18 or injection 
string 24. 
Test Apparatus 
Referring now to FIG. 2, there is shown a test apparatus suitable for 
evaluating foam forming surfactant compositions in the presence of oil and 
brine having different percentages of salt content to simulate permeable 
oil-bearing reservoir rock being subjected to miscible gas injection. In 
the apparatus, the rock is simulated by a glass bead pack 60 of known 
permeability. Such a core is disposed in an autoclave or visual pressure 
container 57 suitable for holding the pack at reservoir temperatures and 
pressures. Heat may be added to the incoming fluids by electrical heater 
61. Pressure is applied by gas source 63, such as nitrogen or carbon 
dioxide. Temperatures on the order of 70.degree. F. to 500.degree. F. and 
at pressures of up to 10,000 psi are respectively simulated by heater 61 
and gas pressure source 63. Fluids selectively flow through cylinder 60 
under suitable flow conditions. The flow arrangement includes inlet and 
outlet means, pipes 62 and 72, for passing fluids including (a) aqueous 
liquids, (b) oil and (c) a noncondensible gas. Differential pressure cell 
59 provides means for measuring the pressure drop across the cylinder 60 
during the testing process. In one embodiment, the main bed 56 of cylinder 
60 was a hollow cylinder, six inches long, packed with 70-100 mesh 
(250-180 micron) glass beads. It was preceded by and connected to a three 
inch long cylinder 55 packed with the same glass beads which function as a 
foam generator. High pressure liquid metering pump 67 was attached to line 
68 from oil-containing vessel 65 and fed into the line 62 between foam 
generator 55 and main bed 56. Outlet line 72 from main bed 56 passes 
through a back pressure regulator 70 and into a liquid separator vessel 
74. Gas from vessel 74 passes through wet test meter 73 where its volume 
is measured at standard temperature and pressure. A pressure measuring 
device such as recorder 72 records differential pressure measured by (DP) 
cell 59 and indicated by meter 71. Cell 59 measures the pressure 
difference between inlet and outlet lines 62 and 72, respectively, to main 
bed 56. 
A second high pressure liquid metering pump 80 was attached to surfactant 
solution vessel 64 and brine vessel 66 to form an aqueous surfactant 
solution. Tank 66 may be filled with a water solution including salt to 
simulate oil field brines of different concentrations. The outlet of pump 
80 is fed into a T-joint 81 where it mixes with a noncondensible gas from 
tank 63 through pressure let down valve 82 and through gas flow measuring 
device 83. The combined liquid surfactant and noncondensible gas passes 
through line 69 into the entrance of foam generator cylinder 55. All 
connecting lines in the above apparatus were 1/4 inches in outside 
diameter. 
Test Procedure 
The following experiments demonstrate the efficiency of the foam 
compositions of the present invention to improve miscible gas enhanced oil 
recovery. They were carried out as follows: 
Oil storage vessel 65 was charged with the test oil. The surfactant storage 
vessel 64 was charged with an aqueous solution of the test surfactant. The 
aqueous solution also contained brine bearing a salt content under 
consideration, supplied from tank 66. Tank 63 containing the 
noncondensible gas of the experiment was attached to pressure-let-down 
valve 82 and test bed 56. The apparatus was heated to the desired 
temperature. Noncondensible gas was then passed through foam cylinder 55 
and main test bed 56 to establish a desired back pressure as measured by 
DP cell 59. Then the surfactant solution was pumped into the system at a 
rate calculated to give the desired ratio of gas to liquid (foam quality). 
This mixture was passed through foam generator 55 and the resulting foam 
was passed into the main bed 56. The pressure developed by passing this 
foam through the glass bead packed bed was detected by pressure cell 59, 
and measured and recorded by recorder 71. After passing through back 
pressure valve 70, the foam was collected in liquid separator vessel 74 
wherein the foam broke and the gaseous portion passed out through wet test 
meter 73. Measurement of temperature, total pressure, gas flow rate, 
surfactant flow rate, pressure drop, and outlet gas volume were taken. 
Next, oil metering pump 67 was started, and oil was pumped into the foam 
line 62 at a predetermined rate. Again, the same measurements were made 
and in addition, the oil flow rate was measured. The value of the 
differential pressure with foam only flowing through the test bed and then 
oil flowing through the foam is given as the ratio R.sub.2 which is 
calculated as an indication of the foam susceptibility to breakdown when 
exposed to oil flow. R.sub.2 is calculated as follows: 
##EQU1## 
Wherein P FOAM is the differential pressure with foam formed of surfactant 
and brine flowing through the bed. 
P OIL is the differential pressure of oil and foam flowing through the bed. 
EXAMPLES 
Following are tables of values which were obtained with the foregoing 
apparatus and test method. Brines and oils from three different oil fields 
were run wherein the salt content of the brine was respectively 15 weight 
percent, 3 weight percent and 5 weight percent and the alpha olefin 
sulfonate used as the foaming agent with those brines included varying 
numbers of carbon atoms. As demonstrated, the nearer the value of R.sub.2 
to 1.0, the more resistant the foam is to breaking due to oil flow 
therethrough. Conversely, the higher the value of R.sub.2, the less 
resistant the foam is to being broken by oil flow. The more stable the 
foam is against being so broken by such flow, the more resistant foam in 
the reservoir is to breaking during flow through the reservoir connate 
water and oil. For measurements made in accordance with the foregoing 
procedure to be most meaningful, desirably the differential pressure 
measured in the absence of oil flow, must be greater than 20 psi at a 
pumping rate of about 250 ml/min. 
TABLE I 
__________________________________________________________________________ 
HIGH BRINE (15%) 
AOS Surfactant Feed Rate, ml/min. 
Run No. 
Carbon No. Conc. wt % 
Surfac. 
Oil.sup.1 
Gas.sup.2 
Foam Quality 
.DELTA.p.sup.3, 
R.sub.2 calc 
__________________________________________________________________________ 
1 C.sub.10 0.5 1.6 0 260 
89 109.8 
-- 
1.6 0.53 
260 
89 98.0 1.12 
2 C.sub.10 0.5 1.5 0 208 
87 81 -- 
1.5 0.5 208 
87 70 1.16 
3 C.sub.12 0.5 1.5 0 208 
87 83 -- 
1.5 0.5 208 
87 43 1.93 
4 C.sub.10 /C.sub.12 = 1/1 
0.5 1.6 0 260 
88 100.9 
-- 
1.6 0.53 
260 
88 70.6 1.43 
5 C.sub.8 /C.sub.10 = 1/1 
0.5 1.6 0 260 
89 111.8 
-- 
1.6 0.53 
260 
89 66.9 1.67 
6 C.sub.10 /C.sub.12 /C.sub.14 = 1/1/1 
0.5 1.6 0 260 
89 116.8 
-- 
1.6 0.53 
260 
89 80.0 1.46 
7 C.sub.10 /C.sub.12 /C.sub.14 = 1/3/1 
0.5 1.5 0 208 
87 84 -- 
1.5 0.5 208 
87 50 1.68 
__________________________________________________________________________ 
.sup.1 The crude oil for these runs came from the Sacroc Oil Field, Scurr 
County, Texas 
.sup.2 Gas was CO.sub.2, rate was measured at 70.degree. F., 1 atmosphere 
.sup.3 Outlet pressure 250 psig. 
TABLE II 
__________________________________________________________________________ 
LOW BRINE (3%) 
AOS Surfactant Feed Rate, ml/min. 
Run No. 
Carbon No. Conc. wt % 
Surfac. 
Oil.sup.1 
Gas.sup.2 
Foam Quality 
.DELTA.P.sup.3, 
R.sub.2 calc 
__________________________________________________________________________ 
1 C.sub.10 0.5 1.6 0 158 
83 90.7 -- 
1.6 0.13 
158 
83 36.0 2.52 
2 C.sub.12 0.5 1.6 0 142 
81 86.4 -- 
1.6 0.13 
142 
81 76.0 1.14 
3 C.sub.14 0.5 1.6 0 175 
84 86.4 -- 
1.6 0.13 
175 
84 80.0 1.08 
4 C.sub.16 0.5 1.6 0 153 
82 87.6 -- 
1.6 0.13 
153 
82 78.4 1.12 
5 C.sub.12 /C.sub.14 /C.sub.16 = 1/1/1 
0.5 1.6 0 143 
81 90.0 -- 
1.6 0.13 
143 
81 86.4 1.04 
6 C.sub.10 /C.sub.12 = 1/1 
0.5 1.6 0 158 
83 87.6 -- 
1.6 0.13 
158 
83 69.5 1.26 
__________________________________________________________________________ 
.sup.1 The crude oil for these runs came from the Huntington Beach field, 
Orange County, California. 
.sup.2 The gas was CO.sub.2, rate was measured at 70.degree. F., 1 
atmosphere. 
.sup.3 Outlet pressure was 250 psig. 
TABLE III 
__________________________________________________________________________ 
MEDIUM BRINE (5%) 
AOS Surfactant Feed Rate, ml/min. 
Run No. 
Carbon No. Conc. wt % 
Surfac. 
Oil.sup.1 
Gas.sup.2 
Foam Quality 
.DELTA.P.sup.3, 
R.sub.2 calc 
__________________________________________________________________________ 
1 C.sub.12 0.5 2.3 0 200 
80 70 -- 
2.2 0.6 168 
80 56 1.25 
2 C.sub.12 /C.sub.14 /C.sub.16 = 3.5/5.5/1 
0.5 2.3 0 199 
80 71 -- 
2.2 0.6 167 
80 54 1.31 
3 C.sub.10 /C.sub.12 /C.sub.14 = 8/1/1 
0.5 1.5 0 212 
87 82 -- 
1.5 0.5 212 
87 44 1.86 
4 C.sub.10 /C.sub.12 = 4/1 
0.5 1.5 0 218 
87 82 -- 
1.5 0.5 218 
87 18 4.56 
5 C.sub.12 0.5 1.5 0 212 
87 80 -- 
1.5 0.5 212 
87 54 1.48 
__________________________________________________________________________ 
.sup.1 The crude oil for these runs was from the Sacroc Oil Field, Scurry 
Co., Texas. 
.sup.2 Gas was CO.sub.2, rate was measured at 70.degree. F., 1 atmosphere 
.sup.3 Outlet pressure was 250-300 psig. 
From Table I it will be readily understood that higher resistance to foam 
breaking is obtained in a formation containing a brine having a high (15%) 
salt content when the alpha olefin sulfonate has on average about 10 
carbon atoms, as compared to those containing 8 or 12 carbon atoms. Runs 1 
and 2, for example, show that in the presence of such high salt content 
brine, AOS which on average contains 10 carbons atoms, R.sub.2 approaches 
1. Where the AOS contains on average 12 carbons atoms, as in Run 3, 
R.sub.2 approaches a value of 2. And where the AOS is a mixture containing 
50% 8 and 10 carbon atoms, as in Run 5, R.sub.2 is greater than 1.5. 
Mixtures of AOS as in Runs 6 and 7 containing 10, 12 and 14 carbon atoms, 
or as in Run 4 containing 10 and 12 carbon atoms tend to cause R.sub.2 to 
vary in accordance with the relative amount of C.sub.10. 
With brines of low salt content (3%) shown in Table II where the AOS has a 
carbon content from about 12 to 16 carbon atoms the foam is most resistant 
to oil breaking through the foam as compared to 10 carbon atoms as in Run 
1. 
In brines of medium salt content (5%), shown in Table III an average carbon 
content of 12 atoms in the surfactant is preferred, as in Runs 1, 2 and 5 
as compared to Runs 3 and 4 where C.sub.12 represented only 10% and 20%, 
respectively, and C.sub.10 representing 80% in both of the Runs. 
While only a few examples of the present invention have been disclosed in 
detail, various modifications and changes in the composition and the 
method of forming foams to enhance miscible gas recovery of petroleum will 
occur to those skilled in the art. As noted above, the specific examples 
using AOS of differing molecular weights include only even numbers of 
carbon atoms, such as alpha olefins produced by the Ziegler process. 
However, alpha olefins produced by steam cracking of wax having both odd 
and even numbers of carbon atoms may also be used with equal effectiveness 
in practice of the present invention. Accordingly, all such modifications 
and changes coming within the scope of the appended claims are intended to 
be included therein.