14

of a hydraulic press a load of 1,000 p.s.i. was used to pack the sand to maxi-
mum density in the column. The resulting sand column had a dry air permeabil-
ity of 1.9~ darcys and an effective porosity of 26.2 percent.

The sand was first completely saturated with distilled water, then
flooded with an oil of 850-centipoise viscosity until a maximum oil satura-
tion of 91.4 percent of the pore volume was attained. Displacement of the
oil was accomplished first by gas (air) injection, then by water injection
to water-oil ratios greater than 20, followed then by intermittent gas and
water drives until virtually no additional oil was produced. With an oil
saturation reduced considerably by conventional water and gas drives, foam
was injected into the sand. The same foam-generating apparatus used in
earlier foam-injection tests (see fig. 1) was used in this procedure. The
initial foam was generated from a 0.2 percent solution of Duponol WAQ with
0.02 percent concentration of Sorbit AC. When it became apparent that only a
small amount of oil was being displaced, a 1l-percent solution of Miranol HM
Concentrate was substituted in the generator. Foam was injected continuously
at flow rates from 2.4 to 6 cc./min. under injection pressures ranging from
4 to 21 inches of mercury (in Hg) until foam appeared at the outflow face of
the sand. At this time the foam injection was supplanted by water- flooding
until the water-oil ratio was 100. A third foam drive of short duration com-
pleted the test.

In figure 9 a summary of the test results indicates that the foam drive
succeeded in reducing the residual oil saturation by 32.7 percent of that
attained by conventional gas and water drives. That the process was not
highly efficient is reflected by a yield of only 0.05 volume of oil per volume
of injected foam solution (as foam) and water.

Test 7-956

A plastic tube 100 cm. long, patterned after the prototype used in the
previous experiment, was fabricated and packed with a sand mixture which con-
tained a slightly larger proportion of the smaller size fractions than the
previous blend. The air permeability of the sand column was 1.34 darcys and
the effective porosity was 25.7 percent. Using the procedure described pre-
viously, the sand was first saturated with water, then flooded with an oil
having a viscosity of 154 centipoises. Primary oil displacement was effected
by waterflooding the sand until the water-oil ratio was 16. The sand was
again oil flooded to within 0.6 percent (pore volume) of the original oil
saturation, Foam, generated from a solution containing 0.25 percent Triton
AS-30, 0.25 percent Nacconal NR, and 0.1 percent Hyonic FA-75, was then
injected at pressures ranging from 9 to 18 in. Hg. Injection rates averaged
just under 1 cc./min. Surfactant liquid in the foam comprised approximately
3 percent of the foam volume.

The flow patterns, revealed by color gradations visible through the
plastic tube wall, showed that the initially injected foam advanced along
the wall at the top of the sand column. Less than 2 percent of a pore volume
of oil was displaced. In spite of this early nonuniform distribution of flow,


35

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FIGURE 22. - Foam-Drive Performance, Test 7-1759 (273-Centipoise Oil).


31

breakthrough was imminent led to the conclusion that either the foam bank was
too short to withstand the gas driving pressure or the foam was breaking down
in the interstices. A second attempt was made to establish a competent foam
bank by injecting foam at 7.0 in. Hg followed by gas at that pressure. The
result was the same as that of the first foam injection. To stabilize the
foam, the concentration of Renex 650 in the solution was raised to 0.30 per-
cent and the mixture was acidified to pH 2.5. Within the next few days sev-
eral small banks of foam were injected and seemed competent to withstand the
driving pressure of the gas following the foam.

Pressure measurements across the four equal lengths of sand column showed
that 80 to 90 percent of the total pressure drop across the column was occur-
ring across the upstream section (one-fourth of the total length of the col-
umn). After a total of 26 days, during which additional foam injections were
imposed at pressures up to 23 in. Hg, it became evident that the foam bank and
any bank of oil that may have formed had not progressed beyond the first pres-
sure tap. During this time, almost 0.8 of a pore volume of aqueous liquids
had been produced along with 3.2 percent of a pore volume of oil and almost
2 pore volumes of gas. A discoloration of the produced aqueous liquids raised
the suspicion that the acidic surfactant solution was attacking the surfaces
of the Monel tube and that this action was somehow related to the immobility
of the foam or oil.

To clean out the previously injected surface-active liquids, approxi-
mately 1-1/2 pore volumes of a 0.5-percent solution of Ninol 1001 in 0.25N
brine were injected. The effluent liquid at first was deep green in color
but gradually became colorless. Analysis revealed that the coloration was
due to nickel salts which could have come only from chemical attack of the
Monel-cell walls by the acidic foam solution. During the flushing of the
sand neither gas nor foam was displaced and only 2.1 percent of a pore volume
of oil accompanied the aqueous fluids produced. Presumably, then, the foam
bubbles that were in the sand just prior to the injection of the Ninol solu-
tion were still there. By diffusion and capillary processes the original
acidic liquid in the bubble films should have been almost entirely neutral-
ized or replaced by the Ninol solution,

On the basis of the evidence that foam was present in the sand pores, a
gas drive was instituted rather than a foam drive. Injection of the gas would
displace the bulk of the aqueous liquid and at the same time generate some
additional foam in situ. The gas drive was started at an injection pressure
of 13 in. Hg--almost one-half the pressure required to inject foam prior to
the flushing operation. Over one-half of a pore volume of aqueous liquid
was displaced before gas breakthrough occurred. The aqueous-phase desatura-
tion by gas removed less than 1.0 percent of a pore volume of oil.

Figure 21 shows that during the balance of the test the residual oil
saturation declined at a fairly constant rate, requiring only a gradual
increase in the injection pressure. Gas-oil ratios remained at low values
rising slightly with time. To maintain the foam-solution saturation of the
sand at a level that would permit in-place generation of foam and prevent
dehydration of the foam, small slugs of foam liquid (2 to 4 cc.) were injected


40

Although only a brief study of this phenomenon was conducted, the results
indicated that electroviscosity exhibited by foams was at least partly respon-
sible for eventual blocking of the porous system. A similar action in which
oil was emulsified by the dispersing effect of the foam aggravated this con-
dition. Presumably, development of immobile emulsion zones which hampered
flow of gas and oil was also a manifestation of electrokinetic effect. The
fact that the use of brines as interstitial water in the sand and of electro-
lytes in the foam formulations alleviated both of these difficulties was
interpreted as proof that electrokinetic phenomena were the offending factors.

Of primary interest in the foam-drive study was the role viscosity plays
in determining oil recoverability. The initial investigation of foam proper-
ties revealed that bulk foams generated from dilute solutions of synthetic
detergents exhibit viscosities generally falling within a rather narrow range.
Experiments showed that while foam viscosity is not grossly affected by sur-
factant type, stability is. The factors having greatest influence on the
viscosity of a given foam were found to be flow rate, and density or expansion
factor. However, when foams move through capillary-size channels, the appar-
ent viscosity is dependent also on the relationship between foam bubble size
and capillary diameter. In the flow of Newtonian fluids, flow resistance
varies inversely as the fourth power of the channel radius, whereas in foam
flow, within limits, resistance to movement increases approximately in direct
proportion to the channel radius. The latter statement applies only to sys-
tems in which foam movement is characterized by filamental or "plug" flow,
that is, flow in which shear is taking place almost entirely in the fluid
layer adjacent to the channel boundaries. Since foam viscosity as an intrin-
sic property cannot be varied over a wide range, the study of the influence
of viscosity on oil recovery was based on variation of oil viscosity as the
independent variable.

The final series of three tests covering oil viscosities in the range
from 78 to 850 centipoises showed no discernible correlation between residual
oil saturation and oil viscosity. Owing to alternate formation and displace-
ment of banks of oil in response to injection of banks of foam, the erratic
changes in production rates and gas-oil ratios preclude the possibility of
comparing tests on the basis of steady-state performance. The primary dif-~-
ficulty stems from the lack of a criterion that defines the range over which
variables in one test should be compared with those of other tests. In plan-
ning the viscosity-test series it had been decided arbitrarily that each run
would be terminated when the produced gas-oil ratio exceeded a pseudo-economic
limit of 1Mc.f£./bbl. But in the second test the gas-oil ratio never went
below 1M c.f£./bbl. and the average was nearly 4 Mc.f./bbl. In the third
test the average was almost 5.6 M c.f./bbl. and individual gas-oil ratios
dipped just below 1M c.£./bb1. only during production of the second bank
of oil.

The tendency for foam drives to exhibit higher levels of gas-oil ratio
when lower viscosity oils are being displaced was unexpected. One plausible
explanation might be derived from the following observations and reasoning:
The course of experimentation demonstrated that for effective oil bank forma-
tion to take place a foam of the proper degree of stability must be injected


oil was obtained and at termi-
nation of the test, residual
oil was 33.2 percent of the
pore volume. Thus, the foam
drives and intervening water
drive recovered almost 35
percent of the oil that
remained in the core after
conventional water and gas
drives.

Study of Foam Properties

{0 cooling

manifold To determine if the
greater oil-displacing capa-
bility of foams resulted from
the higher effective viscosity
of the dispersed medium, a
study was undertaken to
develop a rapid method for
measuring viscosities of
foams. The objective was to
correlate, if possible, oil
recovery and foam viscosity.

Foam cup

Figure 3 shows a Fann

8 .
Thermocouple V-G Meter, Model 31,” modi-
~ wires fied to permit use of a

specially designed foam con-
FIGURE 3. - Apparatus for Measuring Viscosities teiner graduated to indicate
of Bulk Foams. total foam volume and volume

of drained liquid. By means
of a thermocouple projecting into the foam through the wall of the container
the tendency for the temperature to increase during prolonged testing can be
detected. By regulating the air flow through a cooling collar around the
viscosimeter shaft, the temperature of the foam can be controlled within
+2° F. The variable-speed feature of the instrument permits measurement
of viscosities at five different rates of shear.

The experimental procedure was as follows: A measured volume of sur-
factant solution was placed in the viscosimeter cup. A single-rotor Hamilton
Beach mixer was used for beating the foam. Foam of desired initial expansion
factor was generated by beating air into the solution until the required foam
level was reached. The cup was immediately placed in position on the visco-
simeter and a series of reading of torque and volume of liquid drainage versus
time was recorded. This procedure was repeated with foams generated from
various surfactant solutions of different concentrations. Each foam also was
tested at several rates of shear. Textural differences between newly gener-
ated foams could be only nominally controlled by visual inspection during
beating.

®Manufactured by Geophysical Machine Works, Houston, Tex.




50

Movement of Bubbles in Capillary Systems

In a solution-gas drive, minute bubbles of gas evolved by the oil are
carried downstream with the oil in response to a pressure gradient, through
many tortuous paths in the porous rock. With migration of the streams to
regions of lower pressure, expansion of previously evolved gas, evolution of
new gas particles, and coalescence of some of the particles form a dispersion
of discrete gas bubbles of various sizes. Bubbles smaller than pore openings
and constrictions along the flow paths pass with relative ease. However, when
the diameters of bubbles exceed those of the pore constrictions the bubble
interfaces may not, or may only partially, enter small openings under local
pressure-gradient conditions. In water-wet sands this development of a dis-
continuous gas phase may simultaneously break the continuity of the oil phase.

The role of the fluid-fluid interface in the coincident movement of
liquids and gases through porous media was probably first revealed by Jamin
(21, 23). The "Jamin effect" has been in the terminology of petroleum reser-
voir engineering since researchers recognized the real function of gas in the
oil-expulsion mechanism. Whereas advancement of oil production technology
caused the realization that gas dissolved in the oil was an important source
of expulsive energy, Herold (21), Tickell (42), Gardescu (16) and others
attempted to show that capillary effects, manifested in the Jamin action of
a dispersed-gas phase, could be highly restrictive to oil flow.

It can be shown (1) that the pressure differential across a curved
meniscus is

a) @

where p, and p, are, respect-
ively, the pressures on the
concave and convex side of a
meniscus of principal radii
ry, and Ya and y is the
interfacial tension between
the two immiscible fluids
forming the meniscus.
Gardescu (16) showed that the
differential pressure, AP,
required to move a bubble of
gas through a pore constric-
tion is dependent on the
radius of curvature, R,, of
the trailing surface of the
— h la bubble when the forward
interface has attained the
radius of curvature equal to

FIGURE 27. - Schematic Diagram of a Bubble Penetrating the radius of constriction
an Abrupt Constriction. (Rg):



48

with increased initial gas saturations. It was shown also that in an oil dis-
placement process, up to the time of water breakthrough, the effectiveness of
trapped gas was greater for higher viscosity oils than for less viscous oils,
but the trapped gas effectiveness’° diminished with continued flooding after
breakthrough. Improved oil displacement brought about by alternate injection
of two immiscible phases, such as water and gas, may stem from the piston-like
action of the larger number of interfaces moving through the porous system
(33). Steward, and others (40) showed that increasing the number of gas bub-
bles formed in a solution gas drive resulted in abnormally high oil-recovery
efficiencies.

The nature of fluid distribution and flow in porous systems depends to a
significant extent upon the physicochemical characteristics of fluid-fluid
and rock-fluid interfaces. Early investigations brought about a better under-
standing of the role wettability plays in determining distribution and flow of
oil, gas, and water (25). The addition of surface-active chemicals to flooding
water for the purpose of altering the natural surface forces between oil,
water, and reservoir rock in order to improve the effectiveness of water in
removing oil from the porous rock, has been tested in the laboratory and in
the field (7, 10, 24, 29, 32, 35, 39, 41). Generally, the use of the surface-
active agents to improve ultimate oil recovery by waterflooding has been only
moderately successful. Definite improvements in water injectivity, and in
chemical treatment of water for flooding have been demonstrated. Experience
seems to indicate that insofar as reduction of residual oil saturations is
concerned, surfactant flooding shows promise only in reservoirs having oil-
wet or "dirty" sands.

As a result of the analysis of the fundamental and some of the practical
factors, which act to limit the amount of oil recoverable by known water- and
gas-injection techniques, it is possible to set forth a number of requirements
for a displacement process which will permit these factors to be circumvented.

1. The process should employ an injection medium mainly using locally
available, low-cost materials--air or gases such as flue gas or surplus dry
gas from nearby fields. It should not require large volumes of wacer.

2. The displacing medium should:

a. Exhibit a high effective viscosity. The increased viscosity
ratio between the displacing and displaced phases favors formation
of an oil bank and greater displacement and sweep efficiency.

b. Tend to increase displacing-phase wettability of the rock
and thereby promote removal of oil from oil-wet surfaces. The
surface-active constituents of the injected medium should resist
adsorption by rock surfaces. This feature would permit injected
fluid to carry surface-active agents to the advancing front.

10Rffectiveness of trapped gas was defined as "the ratio of the reduction in
oil saturation at a given flooding stage (below that obtained in the
reference flood at the same stage) to the trapped-gas saturation causing
this reduction."


54

that, within limits, a given volume of foam liquid can be expanded into a foam
of any desired volume by dispersing in it the required volume of gas. It is
also readily apparent that characteristics of a foam of given expansion factor
will vary according to the degree to which the gas is broken up into foam
bubbles. The greater the degree of dispersion, the greater the surface area
of the foam films, hence, the thinner the films will become.

The foregoing discussion establishes the fact that any method for measur-
ing the viscous nature of foams should provide a means for controlling or
following changes in expansion factor and texture. It must be noted that
as drainage takes place, expansion factor may remain constant or may increase
or decrease. When a bubble collapses, the liquid from that bubble is contrib-
uted to the liquid in the remaining bubbles. Thus, if the rate at which
liquid is released by bubble attrition is greater than, equal to, or less than
the drainage rate, foam density will increase, remain constant or decrease,
respectively. The former trend is typical of an unstable foam; the latter,
of a stable one.

Because foam is non-Newtonian its viscosity is a fictitious property that
can be characterized in terms of its apparent viscous behavior relative to
that of a Newtonian fluid subjected to the same flow conditions. The apparent
viscosity of foam decreases as the rate of shear increases (18, 43). On the
other hand, foams subjected to shear stresses below some critical value act
as plastic solids. Under these conditions "plug flow''of foam may be observed
in capillary tubes and small pipes wherein all the shearing action takes place
at the flow boundaries (4, pp. 123-130). Depending on the expansion factor
and the bubble sizes, the foam will move as a solid plug, exhibiting no meas-
urable shearing within the foam body. In the porous system, shearing between
bubbles, that is, within the filaments of foam, cannot take place except in
pores and channels of at least twice the diameter of the average bubbble
diameter. Moreover, the rates of movement in reservoir rocks, and particu-
larly in pools containing high-viscosity crude oils, may not approach the
eritical shearing stress except perhaps in large channels in the vicinity
of well bores. Thus, it may be surmised that the foam movement in oil reser-
voirs will be characterized by "plug flow" wherein all shear takes place at
the flow-channel boundaries. If this is the case, the resistance to flow
along any given length of flow channel will be proportional to the surface
area of contact between channel walls and the foam bubbles and therefore
proportional to the effective diameter of the channel. Insofar as viscous
forces are concerned, the larger the channel (within limits), the greater the
resistance to flow--a phenomenon diametrically opposite to that for Newtonian
fluids in laminar flow.

In the following discussion it is assumed that the oil and water satu-
rations at the entry face of water-wet oil sand which has previously been
flushed by water and gas are such that gas injected at the face will flow
through the porous medium with practically no movement of either of the
liquid phases. Thus, if a mass of foam of uniform-size bubbles of radius
R,' is brought into contact with the sand entry face the differential pres-
sure required to move the bubbles into any gas-filled pore opening of radius
R, is nearly


58

In the foregoing analysis it was shown that a polydisperse foam could be
introduced into a porous medium under certain conditions of pressure accord-
ing to the size distribution of bubbles relative to that of the void spaces.
The required conditions are attainable in the region immediately adjacent to
the sand entry face. The question remaining concerns the movement of a bank
of foam through distances of hundreds of feet between wells. The preceding
paragraphs indicated that for initial entry into the pore openings pressure
differentials as high as 10 p.s.i. may be required across single bubbles
measuring only a few microns in length. In terms of conventional flow this
would be equivalent to gradients of the order of 10* or 10® p.s.i. per foot--
far greater than any gradients practicably attainable under conventional-flow
conditions in oil reservoirs.

However, there is considerable difference between injecting bulk foam
from the free space in a well bore into the confinement of a porous system,
and moving the foam through the vast network of communicating channels of
various shapes and sizes. Once they have gained entry the bubbles can reside
in the porous structure in an extremely large variety of configurations: A
single small bubble in a relatively large pore, a cluster of bubbles occupying
a pore channel, or a single large bubble extending into several pore spaces.
The possible orientations and configurations are almost innumerable. It was
shown previously (see table 2) that even at low pressure gradients the small
bubbles, those having diameters in the range of the smallest pore openings,
could move with relative ease through a large percentage of the pore constric-
tions in the sand. The larger foam particles may protrude into a number of
adjacent pore spaces of various sizes. The radius of the upstream surface
of the bubble may be larger than, smaller than, or of the same size as the
downstream surface. In any case, there usually are a number of alternate
routes through which the bubble may move. It is only necessary that the
required pressure differential between two openings be in proper relation to
their relative sizes, as prescribed by equation (9). Statistically, there
should be as many points at which expulsive forces tend to move the upstream
surfaces of bubbles forward out of constrictions as there are points at which
deterring forces tend to restrict the forward movement of bubbles into con-
strictions at their downstream surfaces. Since these two opposing forces tend
to balance each other, only a nominal imposed pressure gradient should be
required to move a bank of foam bubbles forward.

Consider a capillary channel across which a film of wetting liquid has
been established. If the film is not moving or if it is moving under steady-
state conditions and interfacial forces are acting uniformly on both sides of
the film, the film has zero curvature. Similarly, two bubbles of equal diam-
eter in contact with each other will have a planar septum dividing them, that

is, the curvature,=, of the septum equals zero. If the radius of one bubble
Cc

is R,, and that of the other is R,, the radius of curvature, R,, of the
lamella between the two bubbles is that produced by the resultant of the pres-
sures across the interface of contact, that is,

dy _ Ay _ Ay

4Po = 2, RL RS

(10)


46

APPENDIX I. - THEORETICAL ASPECTS OF THE FOAM-DRIVE MECHANISM

Factors Influencing Oil Recovery

The concept of the foam-drive mechanism was developed from an analysis
of factors that limit the recovery of oil by immiscible displacement. Each
factor has been investigated and is treated in the literature. For this
discussion it is necessary only to show what the factors are and how they
adversely influence oil recovery. Considerations of means whereby they could
be circumvented led to the development of the foam-drive concept.

The fundamental relationships governing the flow of two immiscible phases
in a porous system have been well established in the field of petroleum reser-
voir mechanics (5, 31, 34). For a given rock-fluid system, the relative per-
meability to each fluid phase is a function of the relative amounts of the
fluids present. Figure 26 from Leverett and Lewis' (27) study of steady flow
of gas-oil-water mixtures through unconsolidated sands, shows the gas and
oil relative permeability-saturation relationships for a water-wet sand.

For comparison, curves also are presented to show the same relationships
exhibited by the sand when no water is present, that is, when the oil is the
wetting phase. Of particular interest are the saturations at which the per-
meability to one or the other fluid phase disappears. These equilibrium
saturations show the theoret-

20°48 SATURATION, percent of pore volume ical limits to which one fluid

can displace another with
which it is immiscible.

100
100

In practice, such satu-
rations are almost never
reached by ordinary recovery
methods. Once breakthrough
of the driving medium occurs,
the fraction of the displacing
phase in the produced stream
at the well becomes progress-
ively large and eventually
reaches a level beyond which
operation of the well becomes
uneconomical. In general,
the higher the viscosity of
the reservoir oil the higher
the residual-oil content of
the sand at the limiting
economic gas-oil or water-
oil ratio (12, 14, 15). One

so 46 a) 30 oo ©«Of - the primary objectives in
OIL SATURATION, percent of pore volume the newly developed secondary
recovery processes using in
FIGURE 26. - Typical Gas and Oil Relative Permeability situ combustion is to gain the
Curves for Unconsolidated Sand (After advantages of an increased
Leverett and Lewis). ratio of displacing-phase

80}—

40}—

RELATIVE PERMEABILITY, percent



18

when regeneration effectively stops further foam movement, redivision ceases
until the effects of aging, diffusion, and coalescence of bubbles permit
resumption of flow. Experiments showed, however, that with stable foams the
period of immobility may last for days before the latter process has pro-
gressed far enough to reestablish mobility. Moreover, once flow has again
started, the regeneration which caused the stoppage reoccurs and flow again
ceases.

On the basis of the experimental evidence, attention was focused on
surface-active substances regarded as low or medium foamers. A brief study
of the emulsion-forming characteristics of surfactants revealed that high
foamers generally are powerful mineral-oil emulsifiers even when these sur-
factants are present in low concentrations. Emulsification by the lower
foaming detergents tends to be much less pronounced, although not in all
instances.

The preceding observations were verified by run 6-757 in which the sand
column first was totally saturated with a 30-centipoise oil (the refractive
index of which matched that of the Pyrex sand), was subjected to a waterflood,
a detergent-solution flood, alternate water and gas drives and, finally, foam
drives. The results are summarized in figure 12. The foam, generated from a
0.5 percent solution of Petrowet R, flowed at a satisfactory rate under
imposed pressure differentials of 4 to 8 in. Hg. At the end of the foam
injection period a small amount (approximately 0.25 percent) of a high foamer,
Duponal WAQ, was added to the Petrowet R foam solution to test whether addi-
tional oil production would result from a more stable foam. The increased
foam stability caused almost immediate blocking of flow at injection pres-
sures as high as 27 in. Hg. Attempts to remove the block by waterflooding
were unsuccessful,

In the next experiment, run 6-1357, the transparent model was initially
saturated with 38-centipoise oil. The oil was then displaced by water injec-
tion until the water-oil ratio was 64, Foam was injected using a 0.5 percent
solution of Petrowet R in the generator. Injection pressures ranged from 5
to 14 in. Hg, but only a small amount of oil was displaced. The foam-solution
concentration was then increased to 1.0 percent and 0.05 percent Duponol EP
added to further stabilize the foam. Foam injection progressed normally at
first but development of increased flow resistance required higher injection
pressures until at 28 in. Hg the sand became almost totally blocked to flow.
To remove the block by breaking the foam, a 1 percent magnesium sulfate solu-
tion was injected under an imposed pressure of 25 in. Hg. Injection of
approximately 2 pore volumes of this solution succeeded in partially breaking
the blockage and produced a small volume of emulsified oil. Based on the
volume of liquid injected, the oil-displacement efficiency of the foam was no
better than that of the conventional water drive. However, the test again
verified the detrimental effect that overstabilization of foam has on foam
mobility.

The displacement of 30- to 40-centipoise oil from an 11- to 12-darcy sand
was not a satisfactory test for evaluating the foam-drive method. Gas and
water drives tended to reduce oil saturations to too low a level before gas-oil


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/ 3 Nl 3 | 7
/ ° wN, u =4
( 3 _{\ |
r 3 (See — =F
~ | ere] a _ “|s
| Z| N,
a Le
| | | Po l l ————— ae
fo} Oo ° en) T fo) 7) rr] 2) +
nu _ A 1] fo} °

ro)
“BHU! 3YNSS3Yd NOILOSCNI

oi = = 3
“"4Y/'99 60] “ALVY NOILONGOYd SVD 44/"99 ‘ALVE NOILONGOYd 710

TIME, hours
FIGURE 23. - Foam-Drive Performance, Test 11-259 (78-Centipoise Oil).




CONTENTS

Introduction and summary....sseeeeeee
Acknowledgments..
Discussion of the foam-drive mechanism
Experimental procedure and results......sseeeee
Preliminary oil-displacement experiments...
Study of foam propertieS.....cceesecseceeeeeeeeeeee
Long sand column oil-displacement tests........
Test 3-156
Test 7-956.
Test 9-1056.. de eeeeeees
Visual study of the mechanism of foam drive..
Transparent-model tests--lst series.....
Effect of foam stability on flow.
Study of electrokinetic effects seco
Transparent-model tests--2d seriesS......sseo0e

Long sand column tests--effect of viscosity on
recovery..
Test 1
Test 7- 1759.....
Test 11-259
Discussion of results..
Concluding statement.........0. bcecenccce
Appendix I. - Theoretical aspects of the foam-drive
mechanism.......eeseeeee
Factors influencing oil recovery... oe
Movement of bubbles in capillary systems...........

Foam properties and foam movement in capillary
SYSTEMS cr eeseseceeversevees
Displacement of oil by foam.. se eeeeces
Appendix II. - Chemical identification of surface-active
agents used in foam experiments........
Bibliography. .cecsccccsccccncccccccccccersvcesseescssees

ILLUSTRATIONS

Fig.
+ Foam-injection apparatus for preliminary tests.....

1
2. Graphical summary of results of preliminary oil-
displacement teStS....cecccseccrercccscecvcrcsens
3. Apparatus for measuring viscosities of bulk foams..
4. Composite scatter diagram of results of bulk-foam
viscosity teStS. cc cecceccccceccc rec cecseceeees
5. Effect of shear rate and foaming-agent (Duponol RA)
concentration on bulk-foam viscosity........... oe
6. Apparatus for measuring viscosities of foams flow-
ing in capillary-size channels. ee eccees
7. Effect of expansion factor and capillary size on
foam ViSCOSLLY. .. cc cece eee e cece erec er cecceesesens
8. Effect of linear flow rate at fixed expansion
factor on foam ViscoSity....cccesssececccessesees

on

10

11

12

13


29

following gas drives which had been terminated when gas-oil ratio exceeded
20 Mc.f./bbl. Whereas, gas injected at a pressure of 10 in. Hg flowed
through the sand at the rate of 235 to 240 cc./hr. just prior to foam injec-
tion, the same pressure moved the gas into the sand at only 0.18 cc./hr.
after foam injection. The produced fluids were oil, water, and occasional
bubbles of gas.

Long Sand Column Tests--Effect of Viscosity on Recovery

The main objective of the transparent-model experiments were accomplished,
and attention was again directed to the effectiveness of the foam-drive method
in recovering oil from a long sand column. The primary purpose of the new
series of oil-displacement tests was to determine the relationship between oil
viscosity and oil recovery by foam drive. For the new series, a stainless-
steel tube 5 cm. in diameter and 100 cm. long was used. Five pressure taps
equally spaced along the tube provided a means for measuring pressure differ-
entials across the quarter lengths of the sand column. The sand mixture
utilized in the former long-core experiments was again used. Figure 20 is
a schematic diagram of the sand column and the associated equipment compris-
ing the test apparatus.

Test 12-3058

The average air permeability of the sand pack was 1.9" darcys; the
porosity, 26.9 percent. Initially, the sand was completely saturated with
0.5N brine and the homogeneous permeability of the column to brine was found
to be within one percent of the air permeability. To establish the initial
brine and oil saturation conditions, 850-centipoise oil, injected at 20 in.
Hg pressure, was flowed through the sand until brine no longer was displaced.
The oil replaced 88.6 percent of the brine.

Primary depletion was simulated by brine flooding until the produced
water-oil ratio just exceeded 20. For secondary recovery, air was injected
continuously until the produced gas-oil ratio exceeded 10 Mc.f./bbl. Gas
injection pressures averaged 4 in. Hg during the gas drive. Primary recovery
had yielded only 11 percent of the oil in place when water breakthrough
occurred. However, when the water-oil ratio reached the assumed economic
limit, 32.4 percent had been recovered and 59.9 percent of the pore volume
remained oil saturated. The ensuing gas injection displaced only 0.8 percent
of a pore volume of oil before gas breakthrough occurred and a total of 3.4
percent during the entire gas drive. Thus, after application of conventional
displacement methods the residual oil saturation was 56.5 percent of the pore
space. By material balance calculations, residual water and gas saturations
were 22.8 and 20.7 percent, respectively.

For the foam drive, foam at first was generated by bubbling carbon diox-
ide through a 0.25-percent solution of Aerosol C-61 in 0.5N brine acidified
to pH 6.5. The initial slug of foam was injected by flowing foam across the
sand face under an imposed pressure of 5.8 in. Hg, followed by air at the
same pressure, Although a steep pressure gradient developed across the
upstream section of the sand column, within 24 hours indications that gas


15

Unconsolidated sand column, 5 cm. diam., 18.4 cm. long.
Air permeability, 1.97 darcys; porosity, 26.2%.
8 } aqueous phase, distilled H20;

Duponol WAQ, 0.2%; Sorbit AC, 0.02%.
Il, Miranol HM, 1.0%.

Unconsolidated sand column, 5 cm. diam., 100 em. long.
Air permeability, 1.34” darcys; porosity, 25.7%.
Oil visco e distilled H20;

& .
Foam solution, Triton AS-30, 0.25%; Nacconal NR, 0.25%
Hyonic FA-75, 0.1%.

fey
oS

o
is}
T

o
is]
T

>=40-I6in. Hg.

‘AP:

OIL SATURATION, percent of pore volume

FIGURE 9. - Graphical Summary of Results
of Oil-Displacement Test 3-156.

FIGURE 10. - Graphical Summary of Results
of Oil-Displacement Test 7-956.

Unconsolidated sand column, 5 cm. diam., 100 cm. long.
Air permeability, 1.3 darcys; porosity, 25.2%.
Oil viscosity, 133 cp.; aqueous phase, distilled HzO;
gas phase, nitrogen.
Foam solution: I, Sulfanole FAF, 0.5%:

x
fo)
T

2
f=)
T

ay
ce} &
T T

OIL SATURATION, percent of pore volume
8 s
T i

6
T

fo)

Unconsolidated synthetic (Pyrex) sand in transparent cell
0.78 cm. diam., 30 em. long.

Air permeability, 11.3 darcys. Oil viscosity, 30 cp.

Water flood with distilled water.

Detergent-solution drive with 0.5% Petrowet R.

Foam solution, 0.5% Petrowet R. (At end of foam drive,
solution was stabilized with 0.01% Duponol WAQ,
led to blocking of foam flow.

100)

Yl

\)

YY

WU

o
is)
T

Le

g
T
‘AP=2-9 in, Hg.
9

Initial oi! saturation

After gas injection

1.5-13.5

Yd
4-8
27

After water flooding

Yi

After alternate gos
‘ond water injection

After foam-solution
flooding

After foam drive

WY

WY

OIL SATURATION, percent of pore volume

FIGURE 11.- Graphical Summary of Results
of Oil-Displacement Test 9-1056.

FIGURE 12. - Graphical Summary of Results
of Oil-Displacement Test 6-757.


21

resistance to flow of the liquid or dispersion medium (19). This resistance
becomes a component of the apparent or effective viscosity of the flowing
streams. When the emulsion problem became evident, the study of methods for
circumventing it led to consideration of electrokinetics.

To determine the extent of the electrokinetic effects in foam and emul-
sion movement, an apparatus was assembled for measuring the magnitude of
streaming potentials developed by foams flowing in capillary channels. The
basic element of the device was the capillary viscosimeter previously used to
measure the apparent viscosities of foams. A calomel reference electrode was
connected to each end of the viscosimeter capillary tube by salt bridges.
Electropotentials were measured by means of an electronic potentiometer.
Figure 14 illustrates schematically the apparatus used for the study of elec-
trokinetic effects.

To regulated Qo [
air supply ~ ©

Recorder

Solution
reservoir

To regulated _ : Q

air supply

Pressure
cell

Capillary tube
FL
P ial

Foam
generator

Eas

( ; ) Paro S|

To regulated_ eseonl
air supply =—-

i

Receiver

Salt
bridge

Potentiometer

FIGURE 14. - Apparatus for Measuring Streaming Potentials of Foams.


17

part of the oil in that state. Moreover, in the second foam drive the resist-
ance to the flow of foam developed to such an extent that the sand became
virtually blocked and the run had to be terminated.

Visual Study of the Mechanism of Foam Drive

Transparent-Model Tests--1st Series

An apparatus was devised to permit visual observation of the actual
behavior of foam as it displaced oil and water from a porous medium made of
granulated Pyrex glass packed in a Pyrex glass tube 0.78 cm. in diameter and
30 cm. long. The particle-size distribution of the synthetic sand ranged from
65- to 120-mesh. The average air permeabilities of these sand packs ranged
from 11 to 12 darcys; the effective porosity averaged 26.25 percent. When
saturated with an oil of the same refractive index as Pyrex (1.474), the col-
umn was highly transparent. By means of a microscope mounted on the flow
apparatus, flow patterns developed during the displacement tests could be
observed readily. Later it was found that the Pyrex sand when saturated with
refined lubricating oils had sufficient transparency to permit good visibility
to depths of from 5- to 10-grain diameters from the tube wall. A series of
21 tests conducted with the transparent model produced a number of highly
significant results.

Effect of Foam Stability on Flow

Two attempts were made to foam drive a 30-centipoise oil fromthe sand
following conventional water and gas drives. Foam progressed only a short
distance, 2 to 5 cm., into the sand and became progressively more resistant
to flow, finally becoming immobile despite pressures of 25 to 30 in. Hg (above
atmospheric pressure) at the upstream sand face. Observation through the
microscope revealed the occurrence of two separate processes, both of which
may have contributed to the decrease in foam mobility. Foam bubbles entering
the sand were observed to redivide into smaller and smaller bubbles as they
passed through pore constrictions. Simultaneously, some of the oil in the
region invaded by the foam became emulsified and the newly formed oil parti-
cles soon became immobile. Either one or both of these actions--foam division
and emulsification--could have been responsible for the resulting blockage to
flow. When foam was injected with no oil present in the sand, regeneration
of the foam and cessation of flow again occurred. When this experiment was
repeated with a low-stability foam, the foam moved intact through the entire
length of the sand under imposed pressures of 3 to 4 in. Hg. However, even
with the low-stability foam, the blocking tendency caused by excessive foam
regeneration became evident when flow rates were increased.

From the inception of the foam study, maximum foam stability was believed
to be a prime requisite for a successful foam drive. Some degree of regenera-
tion of the foam was anticipated and was considered as necessary to the per-
sistence of the dispersed phase. The foregoing experiments indicate that the
degree of foam regeneration should balance the rate of bubble attrition and
coalescence. Highly stable foams evidently undergo redivision to a degree out
of proportion to the rate of attrition in the reservoir model. Undoubtedly,


Foam-solution
reservoir

To cir supply A Q

Upstream-pressure
ok manifold

Pressure recorder

Pressure cell

To injection-
gas supply

To oir supply oA Q

Trap

Foam
generator

To generator-
gos supply

To oir supply

ar

Foam-residue
tank

Downstream-
pressure
manifold

{ Pressure tap —

Sand column

To air supply

Flooding-water
(or solution)
reservoir

FIGURE 20. - Apparatus for Oil-Displacement Tests in Long Sand Column.

Wet-test Receiver
meter

OE


12

'0 T TT T T T TT T
8b 4
wea
6 DIAMETER - |
fe}
-
Fd
i 4- 4
z
oO
Q
Zz
é
Pad
WwW
ar 4
\ a 1 Nl a L
4 6 8 10 40 60 80 100 200 300

20
APPARENT VISCOSITY, centipoises

FIGURE 7. - Effect of Expansion Factor and Capillary Size on Foam Viscosity.

the limited range of mixer speeds over which the magnetic stirring device
operated, large differences in foam texture could not be obtained. Figure 7
shows correlations between expansion factor and apparent viscosity at constant
linear flow rate in capillaries of three different diameters. Figure 8 is a
smoothed-data plot showing the trend of apparent viscosity with linear flow
rates at fixed expansions. To obtain the correlation, the apparent absolute
viscosity, ,, was multiplied by the expansion factor Fx which, in effect, is
the reciprocal of foam density relative to liquid density. Thus, Fx is a
kinematic-viscosity function. As previously indicated, the viscosity of a
given foam is proportional to the radius of the channel in which the foam is
moving. By normalizing the viscosity function with respect to radius, the

group BE permitted correlation of data from tests utilizing three different
capillary sizes.

The results of the brief study of foam properties indicated that surfac-
tant foams exhibit viscosities considerably higher than those of the aqueous
solutions from which they are generated, Although bulk foams may demonstrate
apparent viscosities over 100 times greater than the aqueous liquid, the
viscosities of the same foams in capillary systems may only be from 5 to 10
times greater than the foam-liquid viscosity. Moreover, there is a limited
range over which viscosities may be varied solely by choice of foam- forming
chemical or concentration used. Despite these limitations, injection of
foams may have the same effect on oil recovery as would a 5- to 10-fold
increase in the viscosity of a flooding water. The author (15) showed that
in tests using a 300-md. core, a reduction in the ratio of oil viscosity to


TABLE 2. - Effect of pressure and bubble size in determining the size of pores

enterable by foam bubbles

9S

AP" -0.001 p.s.i. -0.01 p.s.i. -0.1 p.s.i. -1.0 p.s.i. -10 p.s.i.
Ry! Difference, Difference, Difference, Difference, Difference,
Microns | Ry! /R,? | percent? Rp! /Ro percent Rp' /Re percent Rp’ /Re percent Rp! /R percent.
1 1.000086 0.009- 1.000863 0.086 1.008625 0.855 1.08625 7.940 1.8625 46.31
2 1.000173 017 1.001725 .172 1.017250 1.696 1.1725 14.710 2.7250 63.30
4 1.000345 +034 1.003450 +344 1.034500 3.332 1.3450 25.651 4.450 77.53
8 1.000690 069 1.006900 685 1.06900 6.455 1.6900 40.828 7.900 87.34
10 1.000863 086 1.008625 855 1.08625 7.940 1.8625 46 .309 9.625 89.61
20 1.001725 172 1.017250 1.696 1.17250 14.712 2.7250 63.303 18.25 94.52
40 1.003450 2344 1.034500 3.332 1.34500 25.651 4.450 77.524 35.50 97.18
80 1.006900 685 1.069000 6.455 1.6900 40.828 7.900 87.342 70.00 98.57
100 1.008625 855 1.086250 7.940 1.8625 46.309 9.625 89.610 87.25 98.85
TR ,
ey. eR
R, 4y 9D

where Rp = radius of upstream surface of bubble under given AP'; Rc = pore entry radius; y = interfacial
(Units must be consistent, that is, Rp, Rc, centimeters;
AP', dynes per square centimeter; Y, dynes per centimeter.)

tension--20 dynes per centimeter in this example.

2 Difference, percent =

_ Rp!
Rp’

- Re

x 100


most likely contain wetting liquid (water) and perhaps some oil, it is appar-
ent that the gas can enter small capillaries only if the required displace-
ment pressure is reached. As gas is injected and forces liquid and foam
ahead of it, the oil displacement mechanism previously described continues
to develop the oil bank at the upstream front.

Factors that tend to dissipate or destroy the foam bank are: (1) The
radial outward movement reduces its thickness, (2) the coalescence of larger
bubbles and the diffusion of gas from the smaller to the larger bubbles
reduce the number of bubbles and hence the number of gas-liquid interfaces,
and (3) adsorption of the surface-active substances from the foam liquid to
the solid surfaces, or diffusion into the interstitial brines, depletes the
foam-forming agent required to sustain the bubble films.

Conversely, movement of foam may result in its redivision into smaller
bubbles as it passes through the tortuous paths and constrictions. As the
foam and its associated liquid move to regions of lower reservoir pressure,
expansion of small bubbles and formation of new bubbles as gas comes out of
solution in the liquid, tend to counteract the attrition of the foam bank.
Moreover, liquids containing surface-active foam chemicals tend to be pulled
by capillarity into constrictions. As gas passes through them, new bubbles
are formed. In short, two simultaneous processes occur--one tending to dis-
sipate or destroy the foam, the other acting to renew or regenerate the foam
in the formation. The latter action not only aids persistence of the foam
bank as it moves toward the producing well but also acts to renew foam in
channels in which gas might tend to break through.

As the foam bank moves radially outward from the point of injection it
must eventually become so thinly dispersed as to lose those properties bene-
ficial to oil displacement. The foam bank may be augmented by injecting
slugs of foam liquid from time to time during the gas-injection phase of the
drive. The liquid, owing to the relatively high water permeability of the
sand, overtakes and supplements the foam bank by in-situ generation of foam.

Without fundamental relationships that describe the time rate of flow of
a heterogeneous dispersed phase (foam) in a porous system, it is not possible
to determine quantitatively the effect of foam on areal sweep efficiency.
High sweep efficiency has been correlated with low mobility ratios. The
presence of foam certainly has the same effect as a decrease in mobility of
gas in the invaded regions of the sand but does not alter the mobility of
oil in unswept portions ahead of the foam bank. The effect is an apparent
decrease in mobility ratio. On this basis it may be surmised that fluids in
unswept portions of the unit patterns, formed by injection and producing
wells, move downstream under the influence of existing pressure gradients
while flow of injected gas through previously flushed areas is restrained by
the foam bank.

In a field operation it is apparent that the foam zone must be limited
to a thickness that will permit its movement under imposed pressures of a
practicable magnitude. Operating pressures will be determined by such factors
as depth of pay, reservoir pressure, sand permeability, viscosity of the oil,
characteristics of the foam, and other fundamental and practical considerations.


Water flood,
0. 5N brine.
Gas drive, nitrogen.
Foam solution: iL
Aerosol C-61,
0. 25% in 0. 25N M1.
brine; pH 2.5.
m.
Vv.
v.
90/—

40;—-

OIL SATURATION, percent of pore volume

Water flood, 0. 5N brite.

Gas drive, nitrogen.

Foam solution:

Renex 650, 1.0%; 0. 5N brine;

pH 2.5,

Renex 650, 0.8%; Triton AS-30,
pH

Foam solution:

4.5.

Renex 650, 0.5%; Triton AS-30,
0. 1%; 0. 5N brine; pH 3.0.

3.6-6

Gas drive, nitrogen.

Water flood, 0.5N brine.

Solution flood, Ethomid HT-60, 1%;
in 0.5N brine; pH 4.5.

I, Ethomid HT-60, 1.0% in 0. 5N brine;

UL, Ethomid HT-60, 0.9%; Arquad T, 0. 3%;
0.5N brine; pH 4. 5*.

M1. Ethomid HT-60, 0.9%; Arquad T, 0.55%;
0. 5N brine; pH 4.5*.

14-08
08-10

27

Gas drive, nitrogen.
Foam solution:
‘Arquad T, 0.9%;
Ethomid HT-60,
0.05%; NaOH to
adjust pH to 11.3.
Water flood, 0. 5N
brine.

03-8
03-5.5
26-16
26-15.
18.5

ae

Gas (air) drive test

OIL SATURATION, percent of pore volume

Water flood test only; Water flood, 0.5N

Water flood, 0.5N

ony. OSN Prine: Gas drive, air. Gae drive, air.
peat, Manat,
9.25% in 0.5 0. 35%; Renex 650,
Foam gener bine, at 2.6.
ee with Cop Bae.
Gas drive after
COpair minture. 4
- 2288 i gs | $8 _
_. Br'kthry \ \ Initial oi! soturotion |
After gas injection
| : : After woter flooding B |
: HE After alternate gos | |
a \ 2 \ ‘and water injection |
= \S5 \\ After foom-solution
3A \ = \ flooding ci |
ST: cn T30b | " After foam drive |
== 3 Ws N |
8-158 8-21 9

FIGURE 19. - Graphical Summary of Results of Transparent-Model Tests—2d Series.


10.

11.

12,

13.

63

BIBLIOGRAPHY

. ADAM, NEIL KENSINGTON. The Physics and Chemistry of Surfaces, Oxford

Univ. Press, London, 3d ed., 1941, pp. 8-9.

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ARONOFSKY, J. S., AND RAMEY, H. J., JR. Mobility Ratio--Its Influence
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. BIKERMAN, J. J. Foams: Theory and Industrial Applications. Reinhold

Publishing Corp., New York, N. Y., 1953, 347 pp.

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Sands. Trans. AIME, Petrol. Devel. and Technol., vol. 146, 1944,
pp. 107-116.

BURDINE, N. T., GOURNAY, L. S., AND REICHERTZ, P. P. Pore Size Distribu-
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Technol., vol. 189, 1950, pp. 195-204.

CARO, H. A., CALHOUN, J. C. JR., AND NIELSEN, R. F. Surface-Active
Agents May Increase Oil Recovery. Oil and Gas Jour., vol. 51, No. 33,
Dec. 29, 1952, pp. 62-63, 86-87.

CLARK, N. 0. AND BLACKMAN, M. The Degree of Dispersion of the Gas Phase
in Foam. Trans. Faraday Society, vol. 44, 1948, pp. 1-7.

DETLING, K. D. Process of Recovering Oil From Oil Sands. U.S. Patent
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DYKSTRA, H., AND PARSONS, R. L. The Prediction of Oil Recovery by
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EAKIN, J. L., HOPKINS, A. D., AND DUNNING, H. N. Foam Removes Brine
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1960, pp. 162-163.


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65

MOORE, THOMAS F., AND BLUM, HAROLD A. Importance of Wettability in
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INT. ©BULOF MINES.PGH..PA, 3108




24

“ne aenes 620 (nonone), Love ekion a | \ | oe
ec Se conc . 7
-300}— \ “|

-200|

~1ool— Fine foam Coarse foam _|
a
a4
fe) SS
ere —O=y=O—O- =
+100) _l [ot |} ttt | | | ot | tid
fe) 10? 108

Hp» cs.

FIGURE 17. - Effect of pH and Neutral Electrolyte Concentration on Streaming
Potentials of Nonionic-Surfactant Foam.

and liquid dropped out, the foam passing into the streaming-potential appara-
tus became drier, Texture remained about the same until a transition occurred
during which the filament of foam flowing through the capillary was observed
to form alternate bands of fine, thin foam and coarse foam. The transition
was completed when the foam again became a continuous filament but of much
coarser texture. During the transition period, Eg values fluctuated widely
and rapidly depending upon the length and rate of flow of the alternately
fine and coarse sections of foam. When the transition was completed, the
potentials again settled to a relatively smooth trend. The effects of the
transition were absent or nearly so when NaCl was added or acidification
eliminated the change in Eg with variation of ue

The brief study of electrokinetic effects indicated that foam flow, and
presumably oil-emulsion mobility, can develop appreciable flowing potentials
in capillary channels. Reducing pH in most instances and adding an electro-
lyte (such as NaCl) in all cases, markedly depressed and limited flowing
potentials to a small negative magnitude. If the countereffect to flowing
potentials is manifested in electroviscosity, hence greater flow resistance,
the method by which it may be circumvented has been demonstrated in the
experiments. In the subsequent transparent-model experiments the validity
of this conclusion was tested.


THE FOAM-DRIVE PROCESS FOR INCREASING
THE RECOVERY OF OIL!

by

A. N. Fried?

INTRODUCTION AND SUMMARY

With the growing importance of fluid injection in recent years, the
petroleum industry has been investigating and field-testing a variety of
new methods designed to modify the physical properties of reservoir oil to
improve the efficiency of gas and water injection. These procedures include
condensing-gas drive, LPG (liquefied petroleum gas) injection, alcohol-slug
process, high-pressure-gas displacement, detergent-solution flooding, and
in situ combustion (30, 37).°

A new and different method to increase the effectiveness of gas and water
injection has been tested by the Bureau of Mines. Consideration of both fun-
damental and practical factors that operate to limit the oil recovery attain-
able by conventional oil-displacement mechanisms led to the concept of a dis-
placement mechanism called the foam-drive method. This report describes the
experimental study that tested this concept in the laboratory.

The residual oil of a reservoir depleted by conventional displacement
processes is retained primarily because of heterogeneity in rock permeability,
pore geometry, capillary or surface properties of the solid-fluid contacts,
and the relative viscosity characteristics of the fluid phases. In some parts
of the reservoir a large part of the oil has been displaced, leaving globules
or small discrete masses of oil. In other parts of the reservoir, oil has
been bypassed and remains in isolated islands in the sand body. It thus may
be reasoned that to displace the residual oil, any subsequent recovery process
must provide a means by which (1) expulsive energy may be brought to unflushed
regions of the reservoir, (2) surface or capillary forces which cause reten-
tion of oil may be counteracted, (3) viscosity effects which permit extremely
high rates of flow of the displacing medium relative to the oil flow rates
may be favorably modified, and (4) the number of flow paths available exclu-
sively to the movement of the displacing phase may be decreased. Analysis of

1Work on manuscript completed December 1960.

2Petroleum research engineer, San Francisco Petroleum Research Laboratory,
Bureau of Mines, San Francisco, Calif.

Underlined numbers in parentheses refer to items in the bibliography at the
end of this report. Page references refer to pages in the items and not
to pages in this report.


16.

7.

18.

19.
20.
21.
22,
23.
24,
25.
26.
27.

28.

ILLUSTRATIONS (Con. )

Graphical summary of results of oil-displacement
test 3-156. ccceecccccseecsncecceccseeeesseersseees
Graphical summary of results of oil-displacement
test 7-956, saeeee
Graphical summary of results of oil-displacement
test I-LOSG. ccc cecsccesceescccesceccccescenscevees
Graphical summary of results of oil-displacement
test 6-757.. ee ee eee errr
Graphical summary of results of transparent-model
tests-lst SCTiCS. cc cceecesee seen eecenscesecenece
Apparatus for measuring streaming potentials of
LOAMS cece cece cee e cece cree eee en ec eeeeeesssensenees
Effect of surfactant concentration, pH, and neutral
electrolyte on streaming potentials of anionic-
surfactant foam..
Effect of surfactant concentration, pH, and neutral
electrolyte on streaming potentials of cationic-
Surfactant foaMecssscssecsssccsccessccscceescrenes
Effect of pH and neutral electrolyte concentration
on streaming potentials of nonionic-surfactant
LOAM. cece eee cece e cece erence e eee e ener eeesseneeeees
Effect of pH and neutral electrolyte concentration
on streaming potentials of amphoteric-surfactant
LOAM. cece cece cree eee e eee neeeeereeeeseereseeeeees
Graphical summary of results of transparent-model
tests--2d series..

COLUMN. .e cece e cree eee eee eneeece ene eeeeeeeeeees
Foam-drive performance, test 12-3058 (850-centipoise
Foam vive performance, test 7-1759 (27.
poansarive performance, test ii359 (Jévoentipoise
prosae gradient history, foam-drive portion of :

-centipoise

COSt T1759. cc cceccccccrenarencceessseeeereeeeeee
Pressure gradient history, foam-drive portion of
test 11-259... cccccccccccccccccccccccevevssssevees

Typical gas and oil relative permeability curves for
unconsolidated sand (after Leverett and Lewis)....

Schematic diagram of a bubble penetrating an abrupt
CONSELICtLON. ce seesscescesecsecressvesesscvesseees

Curves showing how pressure gradient and bubble size
determine the size of pores the bubbles will enter

TABLES

Comparison of effective and relative permeabilities
exhibited during foam drives in 3 long-colum
COSTES cee ecc cece renrnereeeeresrnesereseeereeresenes

Effect of pressure and bubble size in determining
the size of pores enterable by foam bubbles.......

Page

15
15
15
15
20

21

22

23

24

25
27
30
32
35
36
37
43
46
50
53

42

56


fe) T T T TTY T T TTY T T TTT
TUBE DIAMETER
ee O33

x 73
N u 3.90 4

T
/ /

SN y / ~ i> |
L wy —_ 4

<P

TM~

L ~. / ~—. na
et WL J
L —_/ 7

| L oe \ , 1 4 | | py

lo? to" ' lo

LINEAR FLOW VELOCITY, cm./sec.

FIGURE 8. - Effect of Linear Flow Rate at Fixed Expansion Factor on Foam Viscosity.

u
displacing-phase viscosity —°, from 1,000 to 100 or from 100 to 10, lowered
d

residual oil saturation (at a water-to-oil ratio of 20) by 12 to 15 percent
of the pore volume. Felsenthal and Uster (14), working with a 420-md. sand,
found that a ten-fold reduction in viscosity ratio resulted in an increase

in oil recovery equal to 6 percent of the sand pore volume. In the present
study it was desired to determine what effect varying the ratio of oil viscos-
ity to foam viscosity has on oil recovery. Owing to the narrow ranges over

which foam viscosities may be varied, the desired ratios, ia could be

obtained most readily by varying the oil viscosity.

Long Sand Column Oil-Displacement Tests

Test 3-156

In preparation for tests utilizing long sand columns, the initial experi-
ment was conducted on a prototype unconsolidated-sand column 5 cm. in diameter
and 18.4 cm. long in an acrylic plastic tube. The sand column consisted of an
almost pure silica sand ranging in grain sizes from 28- to 200-mesh. By means


force on discontinuous oil masses lodged in the interstices. The multiplicity
of mobile interfaces of various sizes and curvatures greatly increases the
probability that the force or combination of forces required to move most of
the static oil masses will be developed. Simultaneously, the unique action of
the dispersed phase alters flow patterns and fluid distribution thereby chang-
ing the permeability distribution so that the driving medium invades previ-
ously bypassed portions of the sands.

Foam injected into the sand surrounding a well bore first disperses
through the largest pore channels, presumably those which have been flushed
of their oil content. With movement of foam into larger voids and channels,
the resistance to flow increases rapidly owing to the high effective viscos-
ity of the foam and to the blocking tendencies of the constrictions along the
flow paths. As flow resistance builds up and injection pressure is increased,
smaller bubbles are forced into the smaller channels thereby causing a foam
bank to be developed. Owing to greater resistance to flow at the injection
well relative to resistance to flow in the downstream region of the reservoir,
the pressure in the latter region is reduced. Thus, in effect, the pressure
gradient across the foam front is increased. With establishment of a mobile
foam front, continuous flow paths that had previously carried the greatest
part of the total flow of the prior displacing medium become blocked or
restricted resulting in (1) diversion of flow to small unflushed flow chan-
nels, (2) migration of a medium exhibiting high effective viscosity, and
(3) presence of a high-pressure gradient at the invading front. Scavenging
of residual oil by foam creates an oil bank or zone of high oil saturation
ahead of the foam front.

Foams exhibit markedly greater viscosities than the separate viscosi-
ties of the gaseous and liquid phases of which they are constituted. The
increased viscosity ratio between displacing and displaced phases favors
formation of an oil bank and greater displacement and sweep efficiency.

Since the surface-active agents occur as adsorbed molecules in the gas-
liquid interfaces forming foam bubble walls, the tendency to be adsorbed by
rock-mineral surfaces is more strongly opposed than in surfactant-solution
flooding. In oil-wet or partially oil-wet formations the detergent and wet-
ting effects of surface-active agents used to generate foams promote the
displacement of oil from rock surfaces.

The presence of a discontinuous gas phase formed by foam increases the
gas saturation of the sands without creating high gas-oil relative permeabil-
ity ratios. Thus, to some extent, foam tends to produce the effect of a
trapped gas.

Presumably, for each porous system there is an optimum thickness of
foam bank, At present, neither a fundamental nor empirical method is known
for predicting optimum foam bank dimension. After a mobile foam bank of
approximately optimum thickness has been established and further injection
of foam is terminated, the permeability to injected gas must derive from the
network of small communicating capillaries which foam has not entered and
from the propulsion of foam in the foam bank. Because the finer capillaries


19

or water-oil ratios approached what might be considered a typical economic
limit in field practice. In the remaining experiments with the transparent
model, the oil used had a viscosity of 850 centipoises and the initial satu-
rations included connate water.

The series of transparent-model experiments led to verification of
several factors considered in developing the theoretical aspects of the foam-
drive method. It had been theorized that injecting gas into a sand containing
a foam-forming solution would generate foam in situ. Three attempts were made
to verify this contention; and two runs--6-757 and 10-257--were successful.

In run 6-757, detergent-solution injection followed by alternate gas and water
injection reduced the oil saturation to about the same extent as foam drives
following conventional drives in other tests. Again, in run 10-257, gas
injection after foam-solution flooding, yielded appreciable oil whereas the
solution drive itself produced little or none.

In the transparent-model tests using 850-centipoise oil, waterflooding
after foam injection did not effectively advance the foam bank. However, the
tests substantiated the theory that foam banks do develop high flow resistance
in the larger highly conductive channels, The water then moves through the
network of smaller capillaries. This continuity of the water phase throughout
the upstream region of the sand prevents the development, across the foam bank,
of differential pressures required to move the foam. Owing to the extremely
high viscosity ratio between the oil and the water, only small amounts of oil
were recovered by flooding after foam injection.

Figure 13 shows the results of the previous two as well as the nine
ensuing transparent-model tests using various sequences of conventional gas
and water drives and utilizing a number of different detergents for the foam-
drive portion of the tests. Most of these runs were terminated when flow
resistance became too great to permit required rates of flow at practical
pressure levels. In almost every instance the difficulty was traced to oil
emulsion formation and to overly stable foams. In spite of this problem, 7
out of the latter 10 oil-displacement tests yielded over 20 percent addi-
tional oil as a result of foam injection after gas and water drives.

The almost consistent presence of emulsified oil in this group of experi-
ments led to a closer examination of the influence of the emulsions on the
displacement mechanism. Observation through a microscope showed that the
emulsified oil particles were much smaller than many pore channels of the
sand; yet, the particles, after flowing some distance downstream, became
static and formed an emulsion zone. These observations led to the conclusion
that factors not heretofore considered were affecting the flow process.

Study of Electrokinetic Effects

One physicochemical phenomenon associated with movement of colloids and
emulsions is the electrokinetic effect. In flowing systems the electrokinetic
effect is manifested in such phenomena as electroviscosity and streaming
potential. It is believed the electrical double layer surrounding colloid
particles or developed at solid surfaces in solid-liquid systems, exerts a


tee.

bi f mi
f | ee mearmaihna 5866

THE FOAM-DRIVE
PROCESS FOR INCREASING
THE RECOVERY OF OIL

By A.N. Fried

metadc38691 |

UNITED STATES DEPARTMENT OF THE INTERIOR

BUREAU OF MINES

1961


42

that gas relative permeabilities were normal at the residual oil saturations
attained during the final stages of the conventional gas drives. At the end
of the conventional gas drive in run 7-1759 the effective permeability to gas
was 56 md. with 51 percent oil saturation of the sand, compared to an average
effective gas permeability during foam drive of 6.6 md. over the range of
residual oil saturations from 47.5 to 13.85 percent of the pore volume. At
the end of conventional gas drive the effective permeability to oil was 585
md. compared with an average of 196 md. during foam drive. Thus, while the
gas effective permeability decreased over eightfold, the average oil permea-
bility was reduced less than threefold as a result of foam injection. If,
instead of inaugurating the foam drive, the conventional gas drive had been
continued, the oil permeability would have declined virtually to zero by the
time the oil saturation had reached an estimated 37 percent of the pore space.
Of course, during this process gas-oil ratios would have averaged far above
any economically practicable level.

TABLE 1. - Comparison of effective and relative permeabilities
exhibited during foam drives in 3 long-column tests

Test

12-3058 7-1759 11-259
Oil viscosity...............-..centipoises 850. 273. 78.
Average oil flow rate........cc./hr./in.Hg .0055 0152 0433
Average gas flow rate........cc./hr./in.Hg «2325 9.16 39.6
Effective oil permeability..........darcys 221 .196 159
Effective gas permeability.,.........darcys -0002 0066 0337
Homogeneous permeability......... 1.9 1.55 1.42
Oil relative permeability........ .116 126 .112
Gas relative permeability.......... -0001 0042 -0237
Average oil saturation, pct. pore vol..... 37.2 30.7 31.9

In run 12-3058, the influence of the dispersed-bubble phase on flow per-
formance was pronounced. As previously described, just prior to the foam drive
a gas drive had been conducted until the produced gas oil ratio had exceeded
10 Mc.£./bbl. at 56.3-percent residual oil saturation. Calculations showed
that with 56.3-percent residual oil saturation the effective permeability
of the sand to oil was about 500 md. and to gas, approximately 17 md, After
foam injection had reduced the saturation to 35 percent, these permeabilities
were, respectively, 190 and 0.1 md; and at 24.2-percent saturation they were
143 and 0.24 md. This means that as oil saturation declined from 56.3 to 35
percent, the kg/ko ratio decreased fifty-fold from 0.03 to 0.0006. It then
rose only threefold to 0.0017 as oil saturation dropped to 24 percent just
before the test was ended.

Attainment of a competent foam bank is accompanied by a sharp pressure
drop across the foam-occupied zone of the sand and by a marked reduction in
gas production rate. Mobility of the foam bank, of course, is evidenced by
the advancement of the pressure front. A study of the pressure-gradient his-
tories shown in figures 24 and 25 when related to the respective production
histories shown in figures 22 and 23 indicate that when a foam was injected
the pressure drop between the inlet and the first pressure tap rose to a peak


As foam entered the core, water, followed by a small amount of foam liquid and
then foam were produced. The movement of the foam in pores adjacent to the
transparent plastic sheath was observed through a magnifying glass.

The next displacement test was conducted to determine if foam would remove
oil not recoverable by gas or water injection. After it had been flushed and
dried, the Aloxite core was again completely saturated with water and then
flooded with a 350-centipoise lubricating oil until water no longer appeared
in the effluent stream. The volume of water displaced was 76.4 percent of
the pore space. A gas drive, aided by gravity drainage, displaced 68 percent
of the oil in place and left a residual oil saturation of 24.3 percent of the
pore volume, Subsequent attempts to displace additional oil by water injec-
tion and by alternate water and gas injection, failed to reduce the residual
oil by a measurable amount.

Foam generated from a 1.5-percent solution of Miranol HM Concentrate was
then injected into the core. First, gas was displaced, then water, and then
oil. After considerable clean oil was displaced the foam broke through. The
color of the initially produced foam showed the foam was heavily loaded with
oil. As flow continued, the foam became progressively lighter until it was
as white as the inflowing foam. At this juncture, water injection was sub-
stituted for foam injection and additional oil production was obtained. A
second foam drive again reduced residual oil saturation. The results of the
experiment are summarized graphically in figure 2(a). Significantly, the
ratio of produced water (including foam solution) to recovered oil was only
3:1 in the first foam drive.

A second oil-displacement test was conducted to determine if the foam
was more effective when injected after a gas drive or after a water drive.
Another important objective was to ascertain if, in the previous run, the
"third crop" of oil produced by foam injection derived primarily from the
detergent and wetting properties of the surface-active chemicals in the foam
or from the unique physical properties of the dispersed driving medium. After
establishing the primary water and oil saturations in the manner described
previously, the initial waterflood was followed by gravity drainage until
liquid no longer was produced. A second flood, using foam solution as the
driving medium, produced no measurable quantity of oil. In contrast, the
ensuing foam drive did reduce the residual oil saturation, as shown in figure
2(b), and indicated quite clearly that the additional yield of oil was pri-
marily the result of intrinsic foam properties rather than the physicochem-
ical action of the surfactant alone. Since the viscosity of the foam liquid
was only 1.13 centipoises and the oil viscosity was 350 centipoises, it is
unlikely that surfactant-liquid viscosity had any effect on the yield of oil.
The run was completed with a final water drive which removed only 1 percent
more oil.

Although results of these preliminary tests were encouraging, the
extremely high permeability of the porous specimen may have been too favor-
able to displacement of oil by foam. Moreover, the average pore size of the
Aloxite core was considerably greater than that in most naturally occurring
oil sands. Therefore, an Alundum core which had an air permeability of


To 7
air suj
pply Foam-solution
reservoir

To
air supply
Core

Foom
generator

Receiver

To
generator-gas
supply

a

air supply

Water
reservoir

FIGURE 1. - Foam-Injection Apparatus for Preliminary Tests.

EXPERIMENTAL PROCEDURE
AND RESULTS

Preliminary Oil-
Displacement Experiments

Before large-scale
laboratory tests of the
foam-drive process were
started, a series of
exploratory foam-
injection experiments
was run to gain some
experience with experi-
mental techniques and
apparatus, and to deter-
mine if foam would pass
intact through a porous
medium and displace oil.

An Aloxite® core
5.16 cm. in diameter
and 4.85 cm. long was
mounted in a transparent
thermoplastic. The
average air permeability
of the core was 30+
darcys; the effective
porosity, 36.8 percent.
After the core was satu-
rated with distilled
water, it was placed in
a vertical position to
permit water to drain
by gravity. It was then
connected to the foam
generator shown in
figure 1. Foam was
generated by bubbling
nitrogen through an
Alundum diffuser at
the bottom of a column

containing a 2-1/2-percent® aqueous solution of Miranol HM Concentrate.”

Foam formed on the surface of the liquid was forced into the core at
desired flow rates by regulating the pressure in the space above the column.

5Reference to specific brand names is made to facilitate understanding and
does not imply endorsement of such brands by the Bureau of Mines.
SConcentrations of surface-active chemicals are given as weight-percent of

active material in the solutions.

7See appendix II for further identification of surfactants mentioned by

proprietary name in this report.


55

wnt QR). (8)

Cc

R,' is the radius of the trailing surface of the bubble at the time the con-
striction is penetrated and is related to the original bubble radius Rp by
equation (4).1?

Conversely, if some pressure AP' is placed on the foam the bubbles will
move into all pore openings larger than

Ry!
Re = 4p 9
c 1-2 Re (9)
ay

Although the pressure AP' is qualitatively positive in the direction of flow,
the direction of surface forces and curvatures in the derivation require that
AP' is negative as used in the equation. The physical interpretation is that
AP' is actually the force tending to push the meniscus back from a constric-
tion it is trying to enter. Hence, it is the force which must be overcome by
application of pressure in the positive direction. In equation (9), as AP'
increases, the denominator of the member to the right of the equality sign
becomes larger and Re becomes smaller. It may thus be seen that at a given
injection pressure the largest flow channels, those which contribute to the
greatest proportion of the total gas flow, will be most easily invaded by the
foam bubbles.

If the foam introduced at the sand face is polydisperse, that is, com-
prised of bubbles of various sizes, then at any given pressure on the foam
in excess of that in the sand, bubbles will enter those channels which have
pore-entry radii approximately equal to or larger than Re given by equation
(9). Table 2 shows the ratio of bubble radius, Rp' , to minimum radius, Rc,
of capillary openings that will be entered when the foam contains bubbles
ranging in radius from 1 to 100 microns. The differences, in percent, between
the radius of foam bubbles and the radius of the smallest pore they will enter
under pressure AP', are also tabulated. For these examples the bubble surface
tension, y, was taken as 20 d./cm, and the excess pressure, AP', 0.001 to 10
p.s.i., as indicated, The plotted data in figure 28 reveal that under low
injection pressures the minimum-size channels foam bubbles can enter are those
only slightly smaller in radii than the individual bubble radii. However,
note the increasing rate of change in the ratio Rp' with rising pressure.

Re

A bubble of 4 micron radius can enter a pore only very slightly smaller when
the pressure differential is 0.001 or 0.01 p.s.i. At 1 p.s.i. the same size
bubble can enter capillary openings 25 percent smaller than its own dimension;
at 10 p.s.i. a pore 77.5 percent smaller than the bubble can be penetrated by
it. The significance of the effect of the two parameters, pressure and bubble
size, may be more fully realized by comparing the range of values for Re when
AP' is 0.1 p.s.i., and those for Rc when AP' is 10 p.s.i. A polydisperse foam
under low pressure will enter only the largest pore channels but as the pres-
sure is raised the fraction of total pore openings permeated by a foam of the
same bubble size distribution will rapidly approach unity.
11Note that the factor 2 in equation (6) now is 4 because each foam-bubble

film has two gas-liquid surfaces on which surface tension acts.



38

Test 11-259

The final test of the series used an oil of 78-centipoise viscosity.
Initial oil and brine saturations, established in the manner previously
described, were respectively 86.1 and 13.9 percent of the sand pore space.
Brine flooding to a water-oil ratio of 40 reduced oil saturation to 46.2
percent. Brine injection was conducted under a constant pressure of 20 in.
Hg. In the ensuing gas drive, air was injected at 8 in. Hg pressure. Owing
to lower oil viscosity the residual saturation was reduced to 43.8 percent
by the time the produced gas-oil ratio had risen to only 1,556 cu. ft./bbl.
As the series was being conducted for comparative purposes, it was desirable
that residual oil saturations be of approximately the same order of magnitude
at the end of the conventional oil-displacement phase of each test. Accord-
ingly, in run 11-259, the gas drive was curtailed to prevent further oil
depletion by gas injection. Extrapolation of the gas-oil ratio trend indi-
cated that at 10 Mc.f./bbl. the residual oil saturation would have been
approximately 40 percent of the void space.

Figure 23 shows the performance history of the foam drive portion of
the test. The foam-forming solution for initial foam injection (F-1) con-
tained 0.2 percent Renex 650 and 0.25 percent Aerosol OT in 0.3N brine
solution. The first foam bank, injected under a pressure of 20 in. Hg
exhibited poor stability. The first oil production was obtained at an aver-
age gas-oil ratio of almost 5 M c.f£./bbl. When the residual oil saturation
had declined from 43.8 to about 38 percent (pore volume), instantaneous gas-
oil ratios suddenly increased to approximately 9 Mc.f£./bbl. A new foam
solution of 0.3 percent Renex 650 and 0.2 percent Ninol 1001 in 0.25N brine
with 0.06 Sorbit AC as a clarifier, was substituted in the foam generator
and a second bank of foam (F-2a) was injected into the sand, Although the
gas flow rate dipped to one-third of the rate prior to introduction of the
foam, the gas-oil ratio continued to increase. By the time a third bank of
foam (F-2b) was started into the sand column, the produced gas-oil ratio
had risen to 15, and the cumulative gas-oil ratio had risen to 8 M c.f./bbl.
at a residual oil saturation of 36 percent. Formation of the new foam bank
was evidenced by an abrupt drop in the instantaneous gas-oil ratio to 6.3
M c.f£./bbl., with an attendant decrease in the cumulative ratio. To improve
the effectiveness of the foam bank, a fourth injection of foam (F-2c) was
imposed. It resulted in a further reduction in instantaneous gas-oil ratio
to 5.5 Mc.£./bbl. By increasing the concentration of Renex 650 to 0.5 per-
cent in the foam solution, injection of enriched foam in a fifth bank (F-3),
following close behind its predecessor, cut the gas-oil ratio to 0.9Mc.£./
bbl. while permitting oil production to continue at a relatively high rate.
The period of oil bank depletion yielded 12.1 percent of a pore volume of
oil, while the cumulative gas-oil ratio remained almost constant at 6.3
M c.£./bbl.

In an attempt to prevent premature gas breakthrough following foam injec-
tion and oil bank formation, the inlet valve was closed with 20 in. Hg gas
pressure on the upstream sand face. The pressure was then allowed to bleed
down by the production of fluids through the downstream end of the sand colum
until the upstream pressure had dropped to 5 in. Hg whereupon the valve was


26

Figure 19 shows the results of tests in which the foam liquids either
contained brine or were acidified to decrease the pH, or both. Comparison of
the results of run 12-1757 (fig. 13) in which the interstitial aqueous phase
was distilled water and the foam solution had a pH of 8.9, and run 1-258 (fig.
19) in which the sand initially contained water but the foam solution was
acidified to a pH of 2.5, shows that in the former test the residual oil satu-
ration after conventional water and gas drives and foam injection was 57 per-
cent of the pore volume as against 36.5 percent after the same sequence in
the later run.

In the remaining tests of the series and in the subsequent long sand
column tests the sands were saturated with brine prior to oil flooding. As
shown in figure 19, a number of various surfactant foams were tested at dif-
ferent concentrations and produced varying results in runs 5-2058, 6-1158,
and 6-2658. However, two significant developments resulted from these
experiments.

In order to reveal the manner in which bubbles gained access to the
porous system of the transparent model, enough sand was removed at the
upstream end to permit visual observation of the sand entry face. In the sub-
sequent experiment the largest foam bubbles not only would not enter the core
except under high pressure differentials, but blocked access to the smaller
bubbles. Of particular interest was the manner in which the boundaries
between adjacent bubble films acted as capillary channels for foam liquid.

As the foam came in contact with the sand face the liquid between the layers
streamed into the sand and the bubble walls thinned noticeably. If the injec-
tion pressure was not high enough to move the bubbles into the sand pores,

the films remained static while liquid from the foam in the generator trav-
ersed continuous channels between bubble walls and flowed into the sand.
Herein was demonstrated the reason why water cannot efficiently act as a
driving medium behind a foam bank. Many small bubbles which moved readily
into the core with the liquid were observable in the liquid streams. These
"secondary" bubbles evidently were not numerous enough to form a foam front
without the injection of large volumes of the liquid in which they are carried.
It was concluded that a more mobile foam bank might be established under lower
injection pressures if freshly generated foams either were much more finely
divided or yielded a greater number of "secondary" bubbles. If the latter
condition were achievable, and if, by circulating foam across the sand face,

a large number of small bubbles could be delivered to the sand face in a
given interval of time, the desired foam bank could be established.

To test these concepts, the inlet of the transparent aand column was
modified so that foam from the generator was delivered through a hypodermic
needle to the sand face and circulated across it while the uninjected residue
was removed through the annulus around the needle and flowed to a residue tank.
Injection pressures and flow rates were controlled by regulating both the gen-
erator pressure and the back pressure in the residue tank. The yield of
"secondary" bubbles in the foam was increased by using carbon-dioxide gas to
generate the foams.


43

DIFFERENTIAL PRESSURE, AP, in. Hg.

T T 7 T
= \ 4
= 4 APaa \
a
| . ,
T T T T T T C T
i 7 AP 34 7
/ MW | q
L _ spt | |
T T T T T T T T
“treo
“ N
aa aN |
We") ae a | | !
I I ] ] ] I T T T
| APi2 \ 4
\ \ \
| \ \ \ 4
\ \ |
\ \ \
- \ \ ’ =
\ \ \
IL \ \ \ 4
\ \ \ oh
[— \ I 4
\ ft
| Dashed curve = Vt
estimated trend i}
Ss |
| | | | [>>> | |
fo 2 40 60 80 100 120 140 160 180 200

TIME, hours
FIGURE 25. - Pressure Gradient History, Foam-Drive Portion of Test 11-259.


25

~400) TT TTT TTT ITT) TT TTT
Miranol MM (ampholytic), 0.25% solution
o pHiOs”
-300}— x pH 3.0" _|

4a do. ,in O.5N NaCl

V Ue

4200 || manent | | manent {| SAT TL)
10 to? 108 1o*
Hyp» &8

FIGURE 18. - Effect of pH and Neutral Electrolyte Concentration on Streaming
Potentials of Amphoteric-Surfactant Foam.

Transparent-Model Tests--2d Series

The primary objective of the first oil-displacement experiments of this
series was to determine the extent to which suppression of electrokinetic
effects would alleviate the foam blocking and emulsion-zone formation encoun-
tered in the earlier tests. In the previous oil-displacement experiments the
sand columns were saturated initially with distilled water; in the ensuing
experiments a 0.5N NaCl solution was used. All solutions of foam- forming
chemicals were made in brine rather than water or were acidified to low pH
values. In several instances both salt and acid were incorporated in the sur-
factant liquid. Moreover, an attempt was made to employ only those surface-
active agents known to have relatively low emulsifying power but good or fair
foam-forming properties. Generally, this selection tended to exclude the
anionic surfactant types because as foamers they are either incompatible with
acids and high electrolyte concentrations or they are powerful mineral-oil
emulsifiers. Among the nonionics, one having a high HLB (hydrophilic-
lipophilic balance) was selected. It has been demonstrated (17) that as
HLB values increase, for example, as the number of molecules of ethylene
oxide in the surfactant molecule increases, emulsion-forming activity lessens
and water solubility and cloud point rise. In addition to the nonionics,
several cationic agents showed excellent foam-forming properties and little
tendency to form stable oil-in-water emulsions, although a slight tendency to
disperse water-in-oil was observed.


62

APPENDIX Il. - Chemical identification of surface-active agents
used in foam experiments

Trade name Manufacturer Chemical name Type
Aerosol C-61....... | American Cyanamid Co. Ethanolated alkyl guanidine-amine complex [Cationic
Aerosol 0S. do. Isopropyl naphthalene sodium sulfonate —_| Anionic
Aerosol OF..+.es005 do. Dioctyl sodium sulfosuccinate Do.
Arquad 2¢.. «| Armour and Co. Dicoco dimethyl ammonium chloride Cationic
Arquad T..sseeeeeee do. Tallow trimethyl ammonium chloride Do.
Drench EP-3 National Foam Systems, Inc.| Unknown Unknown
Duponol EP.........] EB. I. du Pont de Nemours Fatty alcohol alkylolamine sulfate Anionic

and Co., Inc.
Duponol RA...+eseee do. Modified ether alcohol sulfate sodium salt} Do.
Duponol WAQ..+++++e do. Sodium lauryl alcohol sulfate Do.
Ethomid HT-60...... | Armour and Co, Condensation of hydrogenated tallow amide |Nonionic
and ethylene oxide
Hyonic FA-75....... Nopco Chemical Co. Modified fatty alkylolamide Do.
Miranol HM Miranol Chem. Co., Inc. Ethylene cyclomido 1-lauryl, 2-hydroxy Amphoteric
Concentrate....... ethylene Na alcoholate, methylene Na
carboxylate
Miranol MM do. Same as Miranol HM except myristyl Amphoteric
Concentrate....... group is substituted for lauryl group
Nacconal NR........| National Aniline Div., Alkyl aryl sulfonate Anionic
Allied Chem. and Dye Corp.
Ninol AA62... Ninol Laboratories, Inc. Lauric diethanolamide Nonionic
Ninol 1001.......4. do. Fatty acid alkanolamide Do.
Petrowet R. E. I. du Pont de Nemours Sodium alkyl sulfonate Anionic
and Co., Inc.
Pluronic 144.......| Wyandotte Chem. Corp. Condensation product of ethylene oxide ‘Nonionic
with propylene glycol
Product BCO........| E. I, du Pont de Nemours G-cetyl betaine Amphoteric
and Co., Inc.
Renex 650.......+++| Atlas Powder Co. Polyoxyethylene alkyl aryl ether Nonionic
Sorbit AC..........| Geigy Chemical Corp. Sodium alkyl naphthalene sulfonate Anionic
Sulfanole FAF......| Warwick Chem. Co., Div. Sodium salt of fatty alcohols, sulfated Do.
Sun Chem. Corp.
Triton AS-30. Rohm and Haas Co. Sodium lauryl sulfate Do.
Triton X-100...+e++ do. Alkyl aryl polyether alcohol Nonionic



the known properties of foams, plus other factors deduced from fundamental
properties of colloidal dispersed systems, seemed to indicate that injection
of foam might fulfill the foregoing requirements and increase oil recovery.

In this process, foam of required stability is generated by dispersing a
suitable gas (air, nitrogen, methane, and so forth) in dilute aqueous solu-
tions of surface-active agents, and the foam is injected into the reservoir.
The foam forms a zone or bank which is pushed through the reservoir by
injected gas. A sharp pressure drop across the foam bank combined with the
unique action of mobile and trapped foam bubbles causes displacement of oil
and the formation of an oil bank, which is moved effectively through the
reservoir. The presence of foam in the sand markedly lowers the effective
gas permeability (k,) and to a lesser degree oil permeability (k,). Thus,
despite decreased oil saturation, the kg/ky ratio is reduced, which is an
aid to recovery.

Laboratory-scale oil-displacement experiments showed that the foam-
injection technique can be used to recover a large proportion of the oil
remaining in unconsolidated sands that have been subjected to conventional
gas drives and water or surfactant-solution flooding. In tests utilizing 78-
to 850-centipoise oils, oil saturations were reduced by 44 to 70 percent of
the oil that was left in the sand by conventional displacement methods, Best
results were obtained with high viscosity oils. Not only were final residual
oil saturations reduced to as low as 13.8 percent of the sand pore volume,
but average produced gas-oil ratios during oil depletion by foam-drive ranged
between the equivalent of 5 to 5.6 Mc.f. per barrel of oil. These perforn-
ances, in sands in which gas-oil ratios just prior to foam injection exceeded
the equivalent of 10 Mc.f. per barrel at the end of conventional gas drives,
indicate the effectiveness of foam in altering flow distribution and fluid
conductivity in the reservoir.

This report discusses the mechanism of the process and presents results
of laboratory tests of the foam-drive method,

ACKNOWLEDGMENTS

For their critical reviews and helpful comments, the author is greatly
indebted to Dr. Irving Fatt, professor of petroleum engineering, University
of California, Berkeley, Calif.; Ionel I. Gardescu, manager, Oil,and Gas
Division, H. Zinder and Associates, Inc., Houston, Tex.; and George J. Heuer,
Jr., section supervisor, Production and Research Division, Continental Oil
Co., Ponca City, Okla.

DISCUSSION OF THE FOAM-DRIVE MECHANISM*

The possibility of using foam driven by injected gas to move oil left
immobile by previous displacement processes is based on the premise that
injecting a suitable foam into the pore system of a reservoir introduces a
large number of tenacious and resilient interfaces which exert a pistonlike

*A more detailed discussion of the theoretical aspects of the foam-drive
method is presented in appendix I.


16

continued foam injection reduced the oil saturation by 22.3 percent of the
pore volume, and the ensuing waterflood yielded an additional 12.4 percent.
The results of the entire run are shown in figure 10. Owing to the separation
between tube wall and sand column and to the resulting channeling of foam, the
run was not believed to be truly indicative of the performance to be expected
of foam drives. It is noteworthy, however, that the foam drive and the water-
flood which followed it produced more oil at a lower ratio of injected-liquid-
to-produced-oil than did the earlier conventional water drive (1.11 in the
former versus 1.97 in the latter).

Test 9-1056

To obtain better contact between tube wall and sand, a layer of sand was
cemented to the inner surface of the tube and the sand was repacked. The air
permeability of the sand column was 1.38 darcys or within 40 md, of the per-
meability of the previous sand column. The porosity was 25,2 or within 2
percent of the previous porosity. Initial water and oil saturations were
again established in the new sand-packed column, but this time an oil having
a viscosity of 133 centipoises was used. Experience gained during the pre-
vious run led to the conclusion that injection of foam into a sand containing
100 percent liquid, of which over 80 percent was high-viscosity oil, was an
unnecessarily severe and unrealistic test of the foam-drive method. It was
reasoned that application of foam drives probably would be restricted to
those oil fields where conventional secondary recovery operations had already
been completed. The remaining foam-drive tests, therefore, were run in sands
that had been depleted first by waterfloods, then by gas drives.

In run 9-1056, primary recovery was simulated by gas driving (with
nitrogen instead of air) and secondary recovery by waterflooding the sand.
Oil flooding then reestablished the oil saturation within 3 percent of a pore
volume less than the original oil saturation. Primary recovery was again
obtained by injecting gas into the sand. Foam for the foam drive in this test
was generated from a 0.5 percent Sulfanole FAF, of 0.02-percent agar (stabi-
lizer) solution, using nitrogen as the gas phase. The dispersed driving
medium was injected initially at very low pressure. The pressure gradually
was raised to 24 in. Hg to maintain an average foam input rate of 0.3 cc./min.
The foam drive was followed by water injection and again by foam. In the lat-
ter, the original foam solution was replaced with a l-percent solution of
Sulfanole FAF and the resulting foam was considerably more stable than the
previously injected foam.

Figure 11 presents a summary of the results of run 9-1056. Lower resi-
dual oil saturation was attained by using the foam drives and the intervening
waterflood than by using the conventional waterflood, but the ratio of total
liquid injected to oil produced in the foam drive was considerably greater
than that for the conventional waterflood. The gas saturation after conven-
tional water drives was less than 4 percent, whereas after foam drive and the
ensuing water drive there was 27 percent, gas in the sand. This supports the
theoretical contention that one of the functions of foam in the displacement
mechanism is to increase the trapped-gas saturation. There was a definite
tendency for the foam drive to emulsify the oil, as revealed by production of


100, percent

Ro- Re

I
AP'=lOpsii.

—
—_— Ol

[4-7 a L

10 'L===

!

Rp, microns

FIGURE 28. - Curves Showing How Pressure Gradient and Bubble Size Determine

the Size of Pores the Bubbles Will Enter.

To?

53


60

flow paths that had previously carried the greatest part of the total flow of
the prior displacing medium become blocked or restricted resulting in the
following conditions favoring displacement of oil and water: (1) Diversion
of flow to the small unflushed flow channels, (2) migration of a medium exhib-
iting high effective viscosity, and (3) presence of a sharp pressure gradient
at the invading front. Scavenging of the residual oil by the foam causes an
oil bank or zone of high oil saturation to form ahead of the foam front.

It is assumed a mobile foam bank of approximately optimum thickness has
been established.12 Further injection of foam is terminated and gas is
injected into the sand, The injected gas flows through small communicating
capillaries which foam has not entered and the channels through which the
propulsion of foam in the foam bank takes place. Because the finer capil-
laries will most likely contain water and perhaps some oil, it is apparent
that gas can enter small capillaries only if the required displacement pres-
sure is reached.

As gas is injected, it forces liquid and foam ahead of it. The oil-
displacement mechanism previously described continues to develop the oil bank
at the upstream front. Considering the complexity of the porous system and
the physical obstacles presented to the foam as it moves through the sand,
it is reasonable to assume that many of the bubbles will be left behind as
the foam bank progresses. Other factors tend to dissipate or destroy the
foam bank: (1) The radial outward movement reduces its thickness; (2) the
coalescence of bubbles and the diffusion of gas between bubbles reduce the
number of bubbles and hence the number of gas-liquid interfaces; and (3)
adsorption of the surface-active substances from the foam liquid to the solid
surfaces, or diffusion into the interstitial brines, depletes the bubble
walls of foam-forming material.

Conversely, movement of the foam may result in its redivision into
smaller bubbles as it passes through the tortuous paths and constrictions.
Moreover, as the foam and its associated liquid move to regions of lower
reservoir pressure, expansion of small bubbles and formation of new bubbles,
as gas comes out of solution in the liquid, tend to counteract the attrition
of the foam bank. In addition, liquids containing some of the surface-active
foam chemicals will tend to be pulled by capillarity into constrictions so
that as gas passes through them new bubbles will be formed. In short, there
will be two simultaneous processes occurring, one tending to destroy the foam,
the other acting to renew or regenerate the foam in the formation. The latter
action not only aids persistence of the foam bank as it moves toward the pro-
ducing well but also acts to renew foam in channels in which gas might tend
to break through.

As the foam bank moves radially outward from the point of injection it
must eventually become so thinly dispersed as to lose those properties bene-
ficial to oil displacement. It may be possible to augment the foam bank by

12Presumably, for each porous system there is an optimum thiclmess of foam
bank. At present, neither a fundamental nor empirical method is known
for predicting the optimum foam bank dimension.


33

whenever the oil production rate tended to decrease or the gas-oil ratio trend
showed an abrupt upturn. The test was terminated when the produced gas-oil
ratio exceeded 1,000 cu.ft./bbl. and could not be lowered by injecting small
slugs of solution or foam. This occurred when the residual oil saturation had
been reduced to 23.7 percent of the sand pore space.

Primary recovery by water drive (to a produced water-oil ratio of 40) and
secondary recovery by gas injection (to a produced gas-oil ratio of over
10,000 cu.ft./bbl.) together yielded the equivalent of 670 barrels of oil per
acre-foot of sand. Foam injection followed by gas injection produced another
680 bbl. of oil per acre-foot of sand. The latter yield was not the ultimate
quantity of oil recoverable by the foam drive; it was the amount displaced
during the time the produced gas-oil ratios remained below the arbitrary
economic limit of 1,000 cu.ft./bbl. The overall efficiency of oil displace-
ment by foam drive, in terms of total gas injected, was 511 cu. ft. of gas per
barrel of oil. However, over 90 percent of the oil recovered was produced
during the latter half of the foam drive when the ratio was 306 cu. ft. of
injected gas per barrel of displaced oil.

Test 7-1759

In the second test of the series, the initial brine and oil saturations
were established in the same manner as in the former run. In this test, how-
ever, the oil had a viscosity of 273 centipoises, almost one-third that of the
oil used in the previous experiment. The sand was subjected to a conventional
brine flood at 20 in. Hg injection pressure before foam drive. When the pro-
duced water-oil ratio just exceeded 30, detergent solution was substituted for
brine and flooding was continued to a water-oil ratio of 73, at which time one-
half of a pore volume of solution had been injected. By flowing three-fourths
of a pore volume of brine through the sand the detergent solution was dis-
placed. To complete the conventional oil-recovery phase of the test, a gas
drive was imposed until the gas-oil ratio exceeded 14 Mc.f£./bbl. Summarizing,
the test to this point had produced the following results: The initial brine
flood reduced the oil saturation from 88.4 to 60.5 percent of the void volume,
detergent flooding yielded a volume of oil slightly less than 0.7 percent of a
pore volume, brine flushing produced another 2.1 percent, and the gas drive
further reduced oil saturation from 57.8 to 51.1 percent.

For the foam drive, foam-1 was generated from the same fluid used in the
detergent flood; a 0.5 percent solution of Ninol 1001 and 0.05 percent Renex
650 in 0.25N brine solution. The first foam bank (F-1a),® injected under 8
in. Hg pressure, proved incompetent and permitted gas to break through after
only 1.2 percent of a pore volume of oil had been produced, A second bank of
foam-1 (F-1b) followed by 2 small slugs of foam-1 solution (S-1), and later a
third foam bank (F-1c) injected at the same pressure, failed effectively to
improve the rate of oil depletion but they restrained the gas-oil ratio trend
at an almost constant level of 5.5 to 6 Mc.f./bbl. Pressure differentials

°In figures 22 and 23, points at which foam or foam solution were injected are
indicated by the letter F and S, respectively. The numeral suffix indi-
cates the composition of the solution, for example, F-1 means foam-1 solu-
tion injected as foam, S-1 means foam-1 solution injected as liquid.


34

along the sand column showed no indication that a mobile oil bank had formed.
During this period a total oil yield of 2.4 percent of a pore volume was
recorded. After enriching the foam-1 solution by an additional 0.05 percent
Renex 650 the resultant foam-2 was injected in 2 banks at 18 in. Hg (F-2a
and F-2b). Foam bank formation and advancement were definitely indicated

by the pressure differential pattern along the sand column (see fig. 24).
Gas-oil ratios dropped and oil production rates rose abruptly for a period
during which 7.5 percent of a pore volume of oil was recovered. However, as
the oil production rate continued to rise, the gas-oil ratio trend turned
sharply upward until injection of a small slug of foam-2 solution (S-2) and
a bank of foam-2 (F-2c) again brought it under control. Subsequent injection
of a bank of foam-2 (F-2d) maintained the gas-oil ratio trend almost level but
ultimately the influence of steadily decreasing oil saturation was noted in
the rise in gas flow rate. In an attempt to deter a rapid rise in gas-oil
ratio a solution capable of producing a slightly more stable foam was substi-
tuted for foam-2 solution. Foam-3 solution, consisting of 0.25 percent Ninol
AA62 and 0.02 percent Renex 650 in 1/8 N NaCl solution, was injected in two
slugs (S-3). Shortly after that injection the oil production rate increased
sharply. This period was short lived, however, and injection of foam-3 (F-3)
in the final stage of the test did not alter the rising gas-oil ratio trend.
As indicated in figure 23, the enriched foams and surfactant solutions enabled
recovery of an additional 33.6 percent of a pore volume of oil at an average
produced gas-oil ratio of 3.77 Mc.f£./bbl. The final residual oil saturation
was just under 13.9 percent of the pore volume.

Figure 22 shows graphically the performance history of the foam drive.
Because the flow rates of liquid and gas were erratic, instantaneous gas-oil
ratios are not particularly significant and are not shown. The cumulative
gas-oil ratio exhibited a marked decline followed by a small increase during
the latter part of the test. In spite of recurrent tendencies for gas-oil
ratios to rise to very high values, the effectiveness of small banks of foam
in generating banks of oil and preventing formation of large numbers of con-
tinuous gas-flow channels is evidenced by the low range over which cumulative
gas-oil ratios varied. Comparison of the results of the previous test with
those of this test shows that gas-oil ratio levels were much higher in the
latter. On the other hand, average oil production rates in the two runs were
approximately in inverse proportion to oil viscosities. This infers that
while the effective permeability to gas was considerably greater in the second
test, the oil permeability was about the same as in the first run. The over-
all performance of the foam drive can best be summarized as follows: In a
porous system depleted by conventional water drives to high water-oil ratios
(>60) and by a gas drive to high gas-oil ratios (>14 Mc.f./bbl.), injection
of foam permitted the reduction in residual oil content by 37.2 percent of a
pore volume, or, in terms of practical units, 721 bbl./acre ft. of sand, by
injecting approximately 1.2 bbl. of foaming solutions and 3,950 cu.ft. of
gas, per barrel of oil recovered. To recover over one-third of a pore volume
of oil, foam solution injected as foam and as liquid slugs totaled less than
50 percent of a pore volume whereas an even larger volume of detergent solu-
tion previously injected during the detergent flood produced only 1 percent
of a pore volume of oil when the sand contained a much higher oil saturation.


49

c. Act as a temporary selective plugging or retarding agent
restricting flow through highly-permeable streaks and previously
flushed regions through which channelling or bypassing occurs.
The plugging effect would thus tend to redistribute flow into
unflushed regions of the pay.

d. Introduce a large number of highly tenacious and elastic
interfaces which would exert a piston-type action on interfaces of
immobile, discontinuous ganglia or globules of oil.

e. Be compatible with the reservoir-rock minerals and reservoir
fluids.

A study of these requirements led to the concept of injecting a gas-
liquid dispersed phase, foam, driven by natural gas. Of the possibilities
suggested by the prior analysis, foam best fulfilled the basic requirements.
This contention was based partly on known principles and partly on hypothesis:

1. Foams exhibit markedly greater viscosities than the separate viscos-
ities of the gaseous and liquid phases of which they are composed.

2. Foams can be generated by dispersing a gas in dilute aqueous solu-
tions of surface-active agents. Air, reservoir gas or other gases readily
available in large quantities at low cost are suitable. The low ratio of
liquid-phase volume to gas-phase volume in foams reduces the requirement
for large volumes of water.

3. Injection of foam into the rock pore system introduces a large num-
ber of rigid, yet resilient, interfaces which exert a piston-like force on
discontinuous oil masses lodged in the interstices. The large number of
mobile interfaces of various sizes and curvatures, greatly increases the
probability that the required force or combination of forces will be brought
to bear on static oil masses and move them to the producing well.

4, The injection of a dispersed-fluid phase alters the flow patterns
and fluid distribution, thereby changing the permeability distribution so
that the driving medium invades previously bypassed portions of the sands.

5. In oil-wet or partially oil-wet formations the detergent and wetting
effects of surface-active agents used to generate foams promote oil removal
from rock surfaces.

6. Since surface-active agents occur as adsorbed molecules in the gas-
liquid interfaces forming foam-bubble walls, the tendency to be adsorbed by
rock-mineral surfaces will be more strongly opposed than in surfactant-
solution floods.

7. The presence of a discontinuous gas phase formed by the foam
increases the free gas saturation of the sands without creating high gas-
oil relative permeability ratios. Thus, to some extent, foam tends to
produce the effect of a trapped gas.


22

+700 TTT TT TTT T TTT

Triton AS-30 (anionic)

+600}—

+500-—

+400}—
=

E,,m

+300/— 0.03%, pH 2.77
0.25%, pH INI

+200;—

+100;—

0.25% in OSN_NoCl, pH 6.7

Lot |ilitt
[

bop rid Li
° 10%
Hip, CS.

Littl
108 i0*

FIGURE 15. - Effect of Surfactant Concentration, pH, and Neutral Electrolyte on Streaming
Potentials of Anionic-Surfactant Foam.

The streaming potentials of foams were measured as follows: Nitrogen
gas bubbled through a column of surfactant solution caused a layer of foam to
form on the surface of the liquid. To control the rate at which the foam was
displaced into the capillary tube the pressure in the space above the foam was
regulated. The density of the foam entering the capillary tube was varied by
raising or lowering the liquid surface to permit newly formed foam at the
bottom of the layer or partially drained foam near the top to enter the tube,
Weight rates of flow were determined by weighing the foam discharged from the
tube during a measured time interval. Volume rates of flow were determined
by measuring the traverse time of foam bubbles between two reference marks
on the capillary tube. The data recorded were rates of flow, electrical
potential, and pressure drop across the tube. From this information apparent
viscosity, ,,, and foam density, p, were calculated and related to the elec-
trical measurement.

The results of these experiments demonstrated that when foams flowed
through the capillary tube, potentials as high as 3 volts were developed
across the 35-cm. length of tube. The potential, E,,was found to correlate

with the kinematic viscosity, oe of the foams. These trends differed accord-

ing to the ionic type of surfactant and the pH or electrolyte concentration


52

two interfacial tensions and two contact angles must be accounted for in the
equation. Let y,, and @,, designate, respectively, the upstream interfacial
tension and contact angle; y,, and @,, the same characteristics at the down-
stream surface. The pressure drop across the former meniscus will be

cos G2 cos G3
M0 —e across the latter, 2y,, > Hence, equation (6) becomes
cos 6. cos 6.
AP = 2%y9 > - 259 =z . (7)
‘b c

The foregoing treatment applies to essentially spherical bubbles penetrat-
ing a constriction formed by an abrupt change in channel radius as shown in
figure 28, In porous media comprised of nominally round or angular sand
grains often consolidated by cementatious materials the occurrence of such
sharp constrictions probably is rare. The majority of flow-path constric-
tions are rounded or tapered narrowings. Spherical bubbles traversing such
constrictions undergo a more gradual deformation during which they are
elongated and the ratios of the radii of the trailing to that of the leading
menisci are less than those for the same bubbles passing through a sharp con-
striction. It would be expected that AP computed from equations (6) or (7)
would be considerably higher than the actual pressure differential required
in reservoir rock,

Foam Properties and Foam Movement
in Capillary Systems

Foams are colloidal systems which, like emulsions, exhibit non-Newtonian
or anomalous flow properties. In emulsions of oil-in-water, there is a tend-
ency for the oil globules to concentrate by gravity at the surface of the body
of emulsion. Foams exhibit an analogous tendency; that is, the liquid between
the bubbles tends to drain out of the foam. As drainage takes place, a foam
undergoes changes which affect its properties. At first, bubble surfaces
become closer together as the free liquid separating them is removed. Then,
as liquid from the bubble films drains away, the films become progressively
thinner until rupture becomes imminent. In the early stages of drainage the
rate of fluid movement is relatively rapid, governed to a great extent by the
bulk liquid viscosity. Thus, if concentration of foam-forming chemicals in
the foam solution influences liquid viscosity it must also influence drainage
characteristics. During the film-drainage stage the fluid-loss rate is much
slower owing to the high surface viscosity of the liquid remaining in the
bubble walls (4, pp. 98-112). Bulk flow properties of foam must thus be
dependent to some extent upon the state of drainage and hence upon the age
of the foam. In comparing foams, Miles, Shedlovsky, and Ross (28) showed
that drainage rate increases as foam bubble size decreases, In a water-
wetted porous medium the capillary retention of the wetting liquid would
tend to counteract the drainage process.

Another factor to be considered is expansion factor, that is, the ratio
of foam density to liquid density or the ratio of the volume of foam to the
volume of liquid in the foam. Consideration of this parameter will reveal


61

injecting slugs of foam liquid from time to time during the gas injection
phase of the drive. The liquid, owing to the relatively high water perme-
ability of the sand, would tend to overtake, and through in-place generation
of foam, supplement the foam bank.

Lacking fundamental relationships that describe the time rate of flow of
a heterogeneous dispersed phase (foam) in a porous system, it is not possible
to determine quantitatively the effect of foam on areal sweep efficiency.
It was stated earlier that high sweep efficiency has been correlated with low
mobility ratio. Presence of foam certainly has the same effect as a decrease
in the mobility of the fluids in the invaded regions of the sand and yet does
not alter the mobility of the fluids in the unswept portions ahead of the
foam bank. The effect is an apparent decrease in mobility ratio. On this
basis it may be surmised that fluids in unswept portions of the unit patterns
formed by injection and producing wells, may move downstream under the influ-
ence of existing pressure gradients, while the flow of injected gas through
previously flushed areas is restrained by the foam bank.


This publication has been cataloged as follows:

Fried, Arthur N
The foam-drive process for increasing the recovery of oil.
[Washington] U.S. Dept. of the Interior, Bureau of Mines [1961]

ii, 65 p. illus., diagrs., tables. 27cm. (U. S. Bureau of Mines.
Report of investigations, 5866)

Bibliography: p. 63-65

1, Petroleum—Production. I. Title. II. Title: Recovery of oil.

TN23.U7 no. 5866 622.06173

U. S. Dept. of the Int. Library



41

at or above some critical pressure. According to the proposed theory, this
pressure is a function of the foam bubble sizes relative to the sand pore
sizes. In the experiments the same sand was used in all three tests of the
series and for that porous system the critical pressure appears to be between
12 and 16 in. Hg. To move foam, once it ts introduced into the porous system,
requires a certain minimum pressure drop across both the foam bank and any oil
bank the foam has developed. This critical pressure differential is deter-
mined primarily by sand geometry and foam-bubble sizes and would be the same
for the particular porous system and foam regardless of the viscous nature

of the oil. With the very high viscosity oils used in these tests, flow
resistance of the oil bank must have been the overall rate-controlling factor.
However, the less viscous the oil, the faster it flows in response to the
critical pressure. The faster the oil moves, the more rapidly the foam moves
behind it. Since the effective viscosity of the foam varies as some inverse
function of flow rate, the ratio of effective foam viscosity to oil viscosity
decreases with increasing rates of flow. Thus, it is reasonable to expect
that faster flowing, low-viscosity oils would not be as efficiently displaced
by foams of a given stability as would high-viscosity oils.

On the other hand, it has been proposed in prior considerations that the
faster a foam moves through a porous system the greater the degree of foam
regeneration; the effect of which should be to increase the viscous resistance
of the foam. Theoretically the foam-flow process should tend to be self-
regulating, but in the long-column tests the overall results do not seem to
substantiate this theory. Perhaps the degree of stability of the foams
employed was too low and within too narrow a range to permit regeneration
at the low flow rates experienced,

Owing to unsteady flow performance, characterized by formation and pro-
duction of banks of oil, it is impossible to compare results of the three
long-column foam-drive tests on bases generally used for conventional flow
mechanisms, that is, gas-oil ratio history, and permeability versus satura-
tion. In seeking a basis for comparison, the net volumes of oil produced
per unit of total pressure drop (inch of mercury) across the column were com-
puted for each portion of the foam drive during which the injection pressure
was held at a given value. The average rate of oil production for the entire
foam-drive portion of each test was then computed and from this value the
average effective oil permeability and the average relative oil permeability
were calculated. This procedure was applied also to the gas production per-
formance of each of the three tests. The calculated values are shown in
table l.

Comparison of the figures shown in the table reveals several highly
important features. First, it is seen that the average relative permeability
to oil during depletion by foam drive was almost identical in the three runs,
but the average relative permeability to gas differed by a factor of almost
240 between the lowest value, for the 850-centipoise oil test, and the high-
est, for the 78-centipoise oil test. The low magnitude of effective and
relative gas permeabilities is unusual especially because prior to inaugura-
tion of the foam drives the sand had been subjected to a conventional gas
drive until high produced gas-oil ratios were obtained. Calculations showed


39

opened and pressure again was restored at 20 in. Hg. The procedure was
repeated, this time for an extended period of time. During the latter inter-
val the oil production rate dropped to zero as the upstream pressure fell to
about 3 in. Hg. However, gas flow continued at a very low rate, presumably
supplied by expansion and deterioration of in-place foam. By this means,

the average pressure in the sand was reduced to a low level so that a high
pressure gradient could be developed for the ensuing foam-injection operation.
The fourth foam solution contained 0.2 percent Ninol AA62, 0.5 percent Renex
650 and 0.06 percent Sorbit AC in 0.25N NaCl solution. At the start of the
sixth foam injection (F-4a) a pressure of 12 in. Hg was imposed but was grad-
ually increased to 20 in. Hg before gas injection was resumed. As gas flow
rate increased without indication of oil production the injection pressure was
bled down to 10.4 in. Hg. Within a short interval oil appeared in the efflu-
ent. To speed up depletion of the new oil bank, the gas injection pressure
was boosted to 25 in. Hg and resulted in rapid production of a volume equiv-
alent to 10.7 percent of the sand pore volume, at an average gas-oil ratio
of 3.4 Mc.£./bbl. By following the trend of the pressure drop across the
downstream section of the column, the passing of the oil bank was detected.
As this pressure differential peaked and started to decline, the gas-oil
ratio abruptly rose. A bank of foam injected (F-4b) immediately at that time
reduced the gas-oil ratio from 3.6 to 1.36 Mc.f£./bbl., with only 21.6 per-
cent residual oil in the sand. The foam bank effectiveness lasted only
momentarily and although oil flow resumed at an appreciable rate, gas flow
increased more than proportionately with gas-oil ratios rising to 6.8, 11.3,
and 24.4 M c.f£./bbl, as residual oil saturations declined, respectively,

to 20.6, 20.2, and finally to 20.0+ percent, when the test was terminated,

DISCUSSION OF RESULTS

The early series of foam-drive experiments utilizing the small, highly
permeable, transparent sand column showed that foams can be injected into the
porous medium and, followed by a gas drive, will displace oil not recoverable
by conventional displacement mechanisms. In contrast, water injection follow-
ing foam injection does not effectively propel foam or displace significant
amounts of oil.

Although a number of different foam-forming agents were used, no corre-
lation was observed between foam viscosity and oil-displacement efficiency.
Instead, the criterion for foam performance appeared to be foam stability.

If the foam is too stable, foam bubbles may redivide into progressively
smaller particles while they are passing through pore constrictions. It

was shown that such redivision, which does reduce the pressure drop required
to move the bubbles through a constriction of given size, can increase the
viscosity of the dispersed medium to a point where the sand is blocked to
flow. Conversely, if foam is very unstable it will not persist long enough
to effect formation of an oil bank or to reduce permeability to gas following
the foam. Accordingly, the most efficient foams were found to be those gener-
ated from solutions of "medium" foamers.

Another noteworthy feature disclosed by the tests was the influence of
electrokinetic potentials developed when foams flow through capillaries.


64

14,

15.

16.

17.

18.

19.

20.

21.

22.

23.

24.

25.

26.

27.

28.

FELSENTHAL, M., AND YUSTER, S. T. A Study of the Effect of Viscosity on
Oil Recovery by Water Flooding. AIME Paper 163-G, preprint, 1951.

FRIED, A. N. Effect of Oil Viscosity on the Recovery of Oil by Water
Flooding, Bureau of Mines Rept. of Investigations 5115, 1955, 34 pp.

GARDESCU, IONEL I. Behavior of Gas Bubbles in Capillary Spaces. Trans.
AIME, Petrol. Devel. and Technol., vol. 83, 1930, pp. 351-368.

GRIFFIN, W. C. Clues to Surfactant Selection Offered by the HLB System.
Reprint from June 1956 issue of Official Digest published by the
Federation of Paint and Varnish Production Clubs.

GROVE, C. S. JR., WISE, G. E., MARCH, W. C., AND GRAY, J. B. Viscosity
of Fire-Fighting Foam. Ind. Eng. Chem., vol. 43, No. 5, May 1951,
pp. 1120-1122.

HAUSER, ERNST A. Colloidal Phenomena, An Introduction to the Science
of Colloids. McGraw-Hill Book Co., Inc., New York, N. Y., 1939, p. 91.

HENDERSON, J. H. Low Pressure Mercury Injection in Reservoir Sands.
Producers Monthly, vol. 14, No. 1, Nov. 1959, pp. 32-39.

HEROLD, STANLEY C. Analytical Principles of the Production of Oil, Gas
and Water From Wells. Stanford Univ. Press, 1928, pp. 410-414.

HOLMGREN, C. R., AND MORSE, R. A. The Effect of Free Gas Saturation on
Oil Recovery by Water Flooding. Jour. Petrol. Technol., vol. 3, No. 5,
May 1951, pp. 135-140.

JAMIN, J. C. Mémoire sur 1'équilibre et le mouvement des liquides dans
les corps poreaux. Compt. rend., vol. 50, 1860.

KENNEDY, HARVEY T., AND GUERRERO, ERASMO T. The Effect of Surface and
Interfacial Tensions on the Recovery of Oil by Water Flooding. Trans.
AIME, Petrol. Devel. and Technol., vol. 201, 1954, pp. 124-131.

KINNEY, P. T., AND NIELSEN, R. F. The Role of Wettability in Oil Recov-
ery. Producers Monthly, vol. 14, No. 3, January 1950, pp. 29-35.

KYTE, J. R., STANCLIFT, R. J. JR., STEPHENS, S. C. JR., AND RAPOPORT,
L. A. Mechanism of Water Flooding in the Presence of Free Gas. Trans.

AIME, vol. 207, 1956, pp. 215-221.

LEVERETT, M. C., AND LEWIS, W. B. Steady Flow of Gas-Oil-Water Mixture
Through Unconsolidated Sands. Trans. AIME, Petrol. Devel. and Technol.,
vol. 142, 1941, p. 114, fig. 9.

MILES, G. D., SHEDLOVSKY, L., AND ROSS, J. Foam Drainage. Jour. Phys.
Chem., vol. 49, 1945, pp. 93-107.


220; T
200F- 7
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FIGURE 4. - Composite Scatter Diagram of Results of Bulk-Foam Viscosity Tests.

The study of viscous properties of bulk foam revealed a number of per-
tinent factors. The first of these was that the apparent viscosities of most
foams fell within a relatively narrow range. Varying the concentrations of
surfactants in the foam solution had surprisingly little effect on viscosity
except at the lowest concentrations tested, generally when surfactant concen-
trations were below the critical micelle concentration. Moreover, most foams
exhibited closely similar trends of decreasing viscosity with increasing
drainage. In several instances, however, at very low surfactant concentra-
tions where stability was markedly affected, the reverse trend was noted.

Figure 4 is a composite scatter diagram showing the relatively narrow
range of viscosities exhibited by foams generated from various concentrations
of the different surfactants tested. All tests represented by the data
plotted in figure 4 were run at a viscosimeter-rotor speed of 75 r.p.m.
Figure 5 shows the influence of viscosimeter-rotor speed (shear rate) on
apparent viscosity of foams generated from solutions of various concentra-
tions of Product BCO.


51

ap = 2y(g - z): (2)

Equation (2) is a general statement based on the assumption that both upstream
and downstream contact angles are zero and hysteresis is absent. Moreover, it
applies to a bubble having the same fluid-fluid contact at its upstream and
downstream surfaces.

Figure 27 is a diagram of a capillary in which a spherical bubble of
radius Rp has reached an abrupt constriction of radius R,. By equation (2),
the differential pressure required to move the bubble through the constriction
will be just slightly greater than

Note, in equation (3), Rp' is the radius of the trailing surface of the
bubble when the downstream surface has been distorted to the radius of the
constriction, Re. Disregarding compressibility effects and considering only
the change in the geometry of the bubble as it undergoes distortion it can be
shown that

R! = [ $@R° - Ry? Ry? - RP - Be [ia - BR? - ay)? (4)

If the ratio Rp/Ro is defined as c, equation (6) may be normalized to

Rp! /Re “or (Bek =e? VERT VERA T- 1) (5)

The effect of the ratio of bubble radius to constriction radius on the radius
of curvature Ry! may be shown by means of equation (5). A study of the equa-
G

Ry
tion reveals that as ba) increases from unity, pa) will be smaller than by a
c c c
Ry
maximum of about 11 percent at R = 1.1. However, this difference declines
Cc

R
rapidly to values less than 1 percent when = >4,. Thus, in determining the
c
pressure differential required to force a bubble of given radius through a
pore constriction of given radius, the correction for the difference between
R, and R,; is insignificant and equation (2) may be written

ap = a ae) (6)

c

If the upstream interfacial contact is different from that at the down-
stream bubble interface, for example, water-gas at one, gas-oil at the other,


57

The compressibility of foam influences the behavior of foam at the entry
face of the sand. To inject a foam into a porous system, the bulk foam must
be brought to the sand face under a pressure adequate to cause its influx.

As the pressure on the foam is increased, its ability to move into smaller
and smaller pore openings is enhanced by the compression of the bubbles to
smaller sizes. Hence, when a foam containing bubbles of radii in the range

10 to 200 microns at atmospheric pressure is compressed by an imposed pressure
of 2 atmospheres, the bubble radii are reduced to the approximate range from 8
to 160 microns. At 10 atmospheres the range would be reduced to from 4.6 to
34 microns, With a 10 p.s.i. pressure gradient between the foam and the porous
system, a foam of this bubble-size range would enter all pore openings larger
than 1 micron in radius, as shown by table 2. Studies have shown that equiv-
alent pore entry radii in oil reservoir sands range from approximately 20
microns to less than 1 micron (6, 20). However, in many coarse highly per-
meable and poorly cemented sands such as those found in a number of California
reservoirs, the frequency of occurrence of pore radii in the less-than-2-
micron range is relatively low. Assuming the smaller channels are impene-
trable, they not only represent a small proportion of the void volume open to
fluid flow, but also a small fraction of the total void space available to
residual fluids. In strongly water-wet sands, most of the small channels
probably contain aqueous fluid.

Clark and Blackman (8) showed that owing to the differences in the
internal pressure of various size bubbles, gas will diffuse from the smaller
to the larger. Thus, with time the small bubbles tend to decrease while the
larger ones grow in volume. In addition, compressing a foam shifts the
equilibrium saturation of the gas in the foam liquid. To restore equilib-
rium some of the dispersed gas must pass into solution in the liquid and in
so doing further decreases the average size of the foam bubbles. It may be
observed that during injection of a foam the several simultaneously occurring
changes tend to permit some of the gas globules to move more readily as they
decrease in size relative to the pores through which they are passing. How-
ever, as other gas globules increase in volume they do not necessarily
increase in radius. When, for example, a spherical bubble initially 20
microns in diameter enters a straight capillary 10 microns in diameter, the
bubble becomes a cylinder of 10 microns diameter and about 53 microns long.
An increase in volume merely elongates the bubble. In a real porous system,
bubbles may occur wholly in a single channel enlargement or may extend into
several adjacent pore enlargements.

A large bubble moving through a small constriction may be divided into
smaller bubbles. When the pressure differential between the portion of the
bubble upstream of the constriction and that downstream exceeds the cohesive
forces of the bubble walls within the constriction, the two parts will sepa-
rate. Turbulence and gravity effects aid this division. Thus, foam moving
through the sand can be regenerated into finer bubbles. Such occurrences
may at least partially counteract the coarsening effect of coalescence of
bubbles as well as enlargement by the diffusion of gas from smaller to
larger bubbles.


il

of the parameters could
] be fixed at desired
levels. To accomplish
Recorder these objectives, an
entirely different type

of viscosimeter was
cell

Figure 6 is a
schematic diagram of the
capillary viscosimeter
used in the second study
of foam properties. The
Copillary tube Pipette surfactant solution of

fz a ACO \) desired concentration

is fed into the foam
Foam generator generator by the

. constant-rate pump.

o qeoaurot Receiver Simultaneously, the gas
(air, nitrogen, CO,)
also is metered into the

Magnetic stirrer generator where a

magnetically-driven
Foam-solution rotor beats the two
pomp streams into a foam.
From the generator the
foam flows through the
capillary tube and into
FIGURE 6. - Apparatus for Measuring Viscosities of Foams the pipette. The pres-
Flowing in Capillary-Size Channels. sure drop across the
capillary tube is
measured by the differential-pressure gage and is continuously plotted on the
recorder. Foam flow is measured either in the graduated pipette at the out-
flow end of the viscosimeter tube or by the time of travel of foam bubbles
along a calibrated length of the capillary tube. By regulating gas flow rela-
tive to liquid flow, the desired expansion factor is obtained. Variation in
volume rate of foam flow at fixed values of expansion factor may be achieved
by changing both liquid and gas rate in proper proportion. A limited degree
of flexibility in regulating the foam texture is provided by the speed con-
trol of the magnetic stirrer. The effect of capillary diameter relative to
average bubble size was determined by conducting a series of viscosity meas-
urements in capillary tubes of various diameters. When the viscosimeter was
tested against National Bureau of Standards standard viscosity samples, the
flow behavior was found to be exactly in accordance with Poiseville's law,
and therefore, apparent viscosities could be calculated directly from the
measured quantities.

The new series of tests showed that the viscosity of a foam flowing in
capillary tubes varies almost directly as the diameter of the flow channel.
Presumably, for a given size of capillary, flow resistance should increase
as bubble size decreases in a foam of given expansion factor. This was qual-
itatively verified by the study but not quantitatively correlated. Owing to


THE FOAM-DRIVE
PROCESS FOR INCREASING
THE RECOVERY OF OIL

By A. N. Fried

x oxo» » » » » © & * » report of investigations 5866

UNITED STATES DEPARTMENT OF THE INTERIOR
Stewart L. Udall, Secretary

BUREAU OF MINES
Marling J. Ankeny, Director


32

BUINIOA a1od 40 juadIad *NOLLWYNLVS 10 TwNaisay

. 8 8 8 ¢@ $$ g 8g @g
“BH Ul “3UNSS3ud NOLLOSPNI,
8 8 2 19Q/F9W ‘OLLYY T10-SV9 3ALLVIAWND
0 ° ve) ° 0 ° 0
2) 9 a a = = : Oy
U nN
rar | | TF G
c- {
L———-,
= _ i 448
L—,
= 4 r °
C___, eg
' crc
H |
' |
L— ' r 42
! rt
tay
: 7a
= H ty —|a
H |
i |
' coo
= ‘ r In
i r? ~
’ ae
Li
= H : 42
1
| ?
‘ rc
i
i

Gas rate
Gas-oil ratio

Ut

TIME, 10% hours

Pressure f

ih. a a
|
(2

|
10

Oil saturation
—~a.

j l
Soro —4-~-—4—-$ + ~~~ +4+——~—~|—-—~-~| [—~—~~+ —~ ~-|-~~~+45 °
ae © nu a < fo} © rm © +
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° 14/202.01*3LV¥ NOILONGOY 10
2 8 $$ $$ “eB go og g ¢ ®

+ + oo)
ay72 “3.1V¥ NOLLONGOYd SV

FIGURE 21. - Foam-Drive Performance, Test 12-3058 (850-Centipoise Oil).


850 cp. oil.
Foam solution:
Miranol HM, 1. 0%

850 cp. oil.
Foam solution:
Aerosol OS, 0.5%

850 cp. oil.
Foam solution:
Miranol MM, 2.0%

30 ep. oil.
Foam solution:
Petrowet R, 0.5%

38 cp. oil.
Foam solution:
PetrowetR, 0. 5%;
(increased to 1.0%
with Duponol EP,
0.05%).

100-— 4
90f- 4

WI,

Yl
15-135
4-27

27

AP, 2~9in.Hg.
9

Ya

OIL SATURATION, percent of pore volume

VELL

LLL ld

10}
ol
6-757 6-1357 6-2457 6-2757 7-357
Initia! oi! saturation RY After alternate gas B
N and water injection
After gas injection 4 After foam-solution O
flooding
After water flooding B After foam drive
ie
850 cp. oil. 850 ep. oil. 850 ep. oil. 850 cp. oil. 850 ep. oil. 850 ep. oil.
Foam solution: Foam solution: Foam solution: Foam solution: Foam solution: Foam solution:
I Pluronic L-44, 0.25% Pluronic Pluronic L-44, 5,0 % Aerosol
Aerosol OS, 0.5% AerosolOT, 0.5% Ninol AA62, 0.25% L-44, 2.5%  Ninol AA62, 0.02% C-61, 0.2 %
ug NinolAA62, 0.2% Acrysol GS, 0.06% Ninol Ninol
Aerosol OS, 0.5% AcrysolGS, 0.3% AAG2, 0.05% AAG2, 0.02%
Duponol EP, 0. 2% 1 (In situ foam gener- Miranol
alginate, 0. 2% Same as I ation by gas drive MM, 0.02%
1007 diluted 1:1 following solution 4
flood),
90;-

@
S

3
YA

2
te}

YY

dd

Vd

s
Wl

\S

rc}

&

OIL SATURATION, percent of pore volume
x
i}

6

oLK
12-1757

10-1757 11-457

10-257

FIGURE 13. - Graphical Summary of Results of Transparent-Model Tests—1st Series.




4h

while at the same time the pressure gradients across the three downstream sec-
tions tended to drop. In many instances the time sequence of the appearance
of these pressure peaks at the downstream sections may be followed in the
trends of the pressure-gradient history. The correlation between the rise in
pressure gradient in the outlet section and the production of a bank of oil

is significant evidence supporting the theory of the foam-drive mechanism.
The scavenging action of the foam in developing a zone of high oil saturation
must result in a decrease in gas flow because the gas permeability in the oil
bank is low or even nil. With very high viscosity oils used in this study it
would not be expected that gas alone could move an oil bank only a very short
distance before breaking through it and exhibiting high rates of gas flow.
The conclusion, based on the performance of the tests, is that foam banks push
oil banks ahead and act as buffer zones between the injected gas and the oil.

CONCLUDING STATEMENT

The results of this first study of the foam-drive method of oil recovery
support to a large degree the major premises set forth in the discussion of
the theory. These premises have not been rigorously proved, primarily because
fundamental relationships between basic parameters have not yet been quanti-
tatively established. Until the fundamental elements involved in the foam-
drive mechanism have been isolated and experimental techniques developed so
that the various elements may be controlled and studied, the process must be
evaluated on empirical and qualitative bases.

Admittedly, this investigation raises more questions than it answers.
The questions, however, concern the interpretation of the results and not the
results themselves. Much remains to be done before the foam-drive principle
can be brought into the field for application to real reservoirs. In the
laboratory the complete evaluation of the mechanism will depend to a great
extent on refinement of experimental techniques. A need exists for a better
method for following the progress of the foam and the fluid-saturation changes
in the sand, for maintaining a complete material balance, for controlling and
measuring flow rates, and for continuously recording pressure histories at
various points along the test specimen. Ideally, it would be desirable to be
able to distinguish between the gas contributed to the effluent stream by
attrition of the foam and by the gas injected behind the foam. Similarly, it
would be of value to be able to measure the relative amounts of interstitial
water and foam solution comprising aqueous-phase production during foam drive.

Another area not studied in the present work concerns the adsorption, by
the sand surfaces, of surface-active substances in the foam as compared to
similar phenomena observed in detergent-flooding methods, Future studies
should attempt to determine optimum size or thickness of banks of foam, par-
ticularly in radial flow systems. The investigation of the foam-drive method
should be extended to natural oil-field cores of lower permeability and
porosity than the porous materials used in this study. There is a whole
range of problems concerning chemical compatibilities of surfactant foams and
reservoir crude oils, gases and brines. There is the question of possible
clay swelling induced by foam-forming chemicals.


28

In the ensuing oil-displacement tests, the new technique proved effective.
The results of run 8-2158 are shown in figure 19. After saturating the sand
with brine and oil (850-centipoise), the sand was brine flooded to a water-oil
ratio of 40 and gas driven (with air) to a gas-oil ratio equivalent to 21.5
Mc.£./bbl. Brine flooding reduced the oil saturation from 79.0 percent to
63.9 percent of the sand pore volume; gas injection reduced it to 57.2 percent.
Foam was generated by bubbling carbon dioxide through a 0.25 percent solution
of Aerosol C-61 in 0.5N brine acidified with HCl to pH 2.5. At the start of
the foam drive the displacing medium entered the sand at an injection pressure
of only 12 in. Hg. As the foam bank formed, the pressure was raised gradually
to 21 in. Hg until foam was observed to have progressed a distance of 1 cm,
into the sand. Foam injection was stopped and gas under 18 in. Hg pressure
was brought into contact with the sand entry face. Within several minutes,
a dark band or bank of oil became clearly visible, extending from 1 cm. down-
stream of the sand face a distance of 12 cm. along the sand column. The oil
bank progressed intact toward the effluent end of the sand until the upstream
edge had moved 60 percent of the column length at which time gas breakthrough
occurred, Oil recovery at this occurrence was 42.8 percent of the oil in the
sand at the start of foam injection; the residual saturation was 32.7 percent
of the pore volume. A second foam bank was established, this time by inject-
ing foam until it had invaded the sand a distance of 3 cm., and following this
by gas at a pressure of 18 in. Hg. Gas production dropped almost to zero but
after increasing the injection pressure to 21.8 in. Hg breakthrough reoccurred
and the test was terminated after the gas-oil ratio had risen to the equiv-
alent of almost 2 Mc.f£./bbl. The final residual oil saturation was 28.6
percent, the cumulative produced water-oil ratio during foam drive was 1.3+
and the cumulative produced gas-oil ratio was equal to 98.5 cu.ft./bbl.
Total oil recovery by foam drive was equivalent to 994 bbl./acre-ft. The
foam drive produced 50 percent of the oil remaining in the sand after water
and gas drives.

In foam-drive test 9-558, the same procedure was followed but the foam-
ing solution was slightly enriched to 0.35 percent Aerosol C-61, and 0.1
percent Renex 650 was added. The oil saturations attained at the various
stages of the experiment are shown in figure 19. To establish the initial
foam bank, foam was injected at an initial pressure of 12 in. Hg which was
lowered to 6.4 in. Hg at the start of the gas injection phase. During the
entire foam drive a series of gas breakthroughs occurred but each was effec-
tively "shut-off" by injecting small banks of foam as soon as abnormal gas
flow became evident. Altogether, seven l-cm. banks of foam were injected
during the test. Oil recovery by foam drive amounted to 36.7 percent of the
pore volume or 69 percent of the oil occupying the sand after application of
conventional displacement methods. The cumulative water-oil ratio for the
foam drive was 1.38 bbl./bbl.; the amount of gas required to displace the
oil was insufficient to register on the wet-test meter which can reliably
indicate somewhat less than 5 cc. total input. It can be safely stated that
the cumulative gas-oil ratio did not exceed the equivalent of 10 cu.ft./bbl.
Total oil recovery by foam drive corresponded to 1,209 bbl./acre-ft. of sand.

A significant effect of the foam drives was the immediate reduction in
the permeability of the sand to gas. The foams were injected immediately


DIFFERENTIAL PRESSURE, AR in. Ho,
MV oA 7 @ S YN oO

fo}

37

Pag

APi2  AP23 AP3q APag

Sand_column

| | | | | | | | |

6 7 8 9 10 " 12 13 14 15
TIME, 107 hours

FIGURE 24. - Pressure Gradient History, Foam-Drive Portion of Test 7-1759.


23

~400) rT TTT] TT TTATTT TT TTT
Aerosol C-61 (cationic)
© 0.25%, pH 89, /
x do, 23t f
-300;-— 4 do. 8.6, in O.1N NaCl o! 4
Vv O1s%, 8.5, 0.05N NoCi
Oo do. 29, do.
-200}-— 4
Z 3
we
-100}— om
fe)
+100;-— 4
+200 Le iil Leis Lob tii
10 102 103 1o*

Hips ©.

FIGURE 16. - Effect of Surfactant Concentration, pH, and Neutral Electrolyte on Streaming
Potentials of Cationic-Surfactant Foam.

of the foam-forming solution used to generate the foams, Anionic surfactant
foams exhibited trends shown in figure 15; cationics, as shown in figure 16;
nonionics, as shown in figure 17; and an ampholytic, as shown in figure 18.

At low values of kinematic viscosity (characterized by fine-textured
foams of low expansion factor, that is, wet foams) all of the surfactants
exhibited low positive flowing potentials regardless of surfactant, electro-
lyte concentration, or pH. With rising kinematic viscosity (viscosity, y,
increasing; density, p, decreasing), the streaming potentials of cationic-
surfactant foams decreased, finally changing to rapidly increasing negative
values when no electrolyte was added or when the pH was neutral to alkaline.
When a neutral electrolyte, NaCl, was added or when the pH was rendered acid,
cationic-surfactant foams exhibited low E, values that were nearly constant
over a large range of values of bb .

i

The shaded portion of the curves shown in the figures indicates a transi-
tion from fine foam to coarse foam. To obtain the desired range of t, the

density of the foam was varied by controlling the rate of foam generation,
hence, the length of time the foam was in the generator before it entered
the capillary tube. The longer the residence time, the more the liquid
drained out of the foam; hence, the lower the foam density. Freshly gener-
ated foam was fine-textured and dense. As the foam in the generator aged


'00 IST OIL- DISPLACEMENT TEST | 2ND OIL-DISPLACEMENT TEST | 3RD OIL-DISPLACEMENT TEST
Aloxite core, 350-cp. oil. Aloxite core, 350-cp. oil ‘Alundum core, 350-cp. oil.
90;-—- 4
Initial oil
80}— Ky _ saturation +
After gas INN
70}— injection 4
i ==)-+—At breakthrough
After water
60/— flooding |

At high WOR

After foam-solu-
tion flooding

a)
3°
T

After foam drive

HEeEMHEA

S
fe}
T

T

OIL SATURATION, percent of pore volume

8
T

6
I

==

(a) (b) (c)

FIGURE 2. - Graphical Summary of Results of Preliminary Oil-Displacement Tests.

350 md. was used in the third oil-displacement experiment. The specimen,
2-1/2 cm. in diameter and 12-1/2 cm. in length, was encased in Lucite. The
core was saturated with water and then flooded with the same oil used in the
previous tests. The water-wet, semipermeable diaphragm, which had been
placed at the outlet face of the core to minimize end effect during oil
flooding, was removed. The core was subjected to a waterflood, a gas drive,
and a second waterflood, which was terminated when the water-oil ratio became
excessively high.

The initial waterflood reduced oil saturation from 75.0 to 54.85 percent
of the pore volume, as shown in figure 2 (c). Less than 1 percent additional
oil was removed by the gas drive. The second waterflood was terminated with
a residual oil saturation of 50.8 percent. Foam, generated from a 2-percent
solution of Miranol HM, was injected continuously during the first foam drive
and produced slightly more than 23 percent of the residual oil, leaving 39
percent oil saturation in the core. A subsequent waterflood removed almost
10 percent of the remaining oil and reduced the oil saturation to 35.2 per-
cent of the pore volume, In a second foam drive, using a less stable foam
generated from a 0.24-percent solution of Drench EP-3, only a small yield of


59

Solving for Rg

Rie
Re RR” qu)

This relationship reveals (4, pp. 22-23) that the curvature = can vary only
S

between zero, when R, = R,, and = when R, = 2R, (no deformation of the

larger bubble by the smaller).

The fact that foam bubbles which have approximately the same radius of
curvature when separate, have a greatly increased radius of curvature at the
interface of contact when they are joined, leads to a significant observation.
As previously indicated, to move a single bubble through a pore constriction
requires a certain minimum differential between the pressure immediately
upstream of the trailing bubble surface and that immediately downstream of the
bubble surface at the pore constriction. If two such bubbles are in tandem
they do not act as two separate bubbles because the contact between them is
not a point contact of two spherical surfaces but a flattened interface common
to both bubbles. In the joining of the two, a gas-liquid surface is elimi-
nated thereby reducing the total surface energy and requiring an equal amount
of work to separate the two spheres again. The forward and rearward surfaces
remain the same, as though two separate bubbles were in the space occupied by
the tandem unit. Thus, to move the dual-bubble through the pore constriction
requires the same differential pressure as before. But now the differential
is imposed across a length perhaps twice that for the single bubble and the
pressure gradient is thereby halved. Similarly, a string of bubbles joined
in the same manner as described for the two-bubble unit and extending over
perhaps the entire length of the foam bank should require a greatly, but
certainly not proportionately, reduced pressure gradient to move it through
the porous system, while the required total pressure drop will be of the same
order of magnitude as for the single bubble. This highly over-simplified pic-
ture does not take into consideration the pressure gradient required to over-
come viscous resistance of the foam filament and to move it at a particular
rate along the flow path.

Displacement of Oil by Foam

The injection of foam into the sand immediately adjoining a well bore
establishes a "foam bank." Initially, foam particles, or aggregates, dis-
perse through the large pore channels, presumably those which have been
previously flushed of most of their oil content. The resistance to flow
increases rapidly owing to the high effective viscosity of the foam and to
the blocking tendencies of constrictions along the flow paths. As flow
resistance builds up, and injection pressure is increased, the smaller bub-
bles are forced into the smaller channels thereby causing a foam bank to be
developed. Owing to greater resistance to flow at the injection well rela-
tive to the resistance to flow in the downstream region of the reservoir, the
pressure in the latter region is reduced and a higher pressure gradient is
developed across the foam front. With establishment of a mobile foam bank,


45

Beyond the laboratory, the application of foam injection to actual reser-
voirs will pose practical problems requiring development of methods and equip-
ment for generating and injecting foams. The techniques for generating foams
in situ should be studied further, because this method is simpler and costs
less. The results attained in several experiments using that method were
highly encouraging.

None of the problems cited appear to be formidable. The large number of
surface-active agents now available provide a range of physical and chemical
properties that should permit fulfillment of most requirements for application
of the foam-drive method to a specific reservoir. Moreover, new synthetic
detergents are continually being made available. During the early considera-
tion of the foam-injection process, high reservoir temperatures were consid-
ered a serious practical problem. Recently Eakin and coworkers (13) tested
a unique method for dewatering gas wells by using foams to carry the water to
the surface, They found at least one agent (Triton QS-15) that produced
excellent foams capable of withstanding temperatures of nearly 200° F.

In conclusion, the results of the foam-drive study have revealed an
entirely new oil-displacement mechanism which can greatly reduce the amount
of oil unrecovered by conventional secondary-recovery methods. The author
believes that the results obtained in this relatively brief study are suffi-
ciently significant to warrant the additional research and development
needed tobring the foam-drive method to the field-test stage.


47

viscosity to oil viscosity by reducing the latter. Excluding consideration
of flow rates, the same effects should result in the displacement process
wherein a similar increase in viscosity ratio is attained by increasing the
viscosity of the displacing phase. The latter approach (9) is based on the
use of certain substances in the flood water to increase its effective
viscosity. Unfortunately, at the concentrations required, the cost of the
additives makes the method uneconomical under present conditions.

Another feature that prevents the attainment of maximum oil recovery is
the heterogeneity of rock properties throughout the oil-bearing strata. Owing
to the presence of highly permeable regions and areas of low permeability,
fluid movement is not uniform between wells or between outlying regions of
the reservoir and the producing wells. Thus, at the time production from the
wells has reached the economic limit some parts of the reservoir have been
depleted of oil to a degree approaching the theoretical maximum while other
parts have been left with close to the initial oil content.

Even without the deleterious effects of nonuniform fluid conductivity
of oil reservoirs, a loss of displacement efficiency occurs by virtue of the
difference in mobility, kq/yqg, of the displacing phase behind the two-phase
interface and mobility, ko/uo, of the displaced phase ahead of the front (2,
3, 38). Dyes, Caudle and Erickson (11) showed that for a given well pattern
the fraction of the reservoir swept out by the displacing phase is a function

k,
of mobility ratio, ee t ~). The areal sweep efficiency, at various stages

of the displacement beyond breakthrough, declines markedly as mobility ratio
increases, particularly in systems in which mobility ratios are high, for
example, when a low-viscosity displacing phase drives a high-viscosity oil.

Accordingly, changes in the viscosity ratio, #0, have a two-fold effect on
bd

oil recovery; first, in the efficiency with which oil is displaced from
regions invaded by the displacing medium; and second, in the areal sweep
efficiency of the two-phase system. Systems in which the viscosity ratio,

ro is high will not only yield less oil from invaded portions of the reservoir

but will also have a smaller fraction of the unit pattern around producing
wells swept by the displacing medium.

Additional oil can be recovered from watered-out sands by intermittent
injection ("slugging") of gas or air during waterflooding (33, 36). The
presence of free gas in the core has the effect of shifting the equilibrium
oil saturation to a value somewhat lower than that indicated for the two-
phase system of oil and water. Similar results have been reported by
Holmgren and Morse (22). In a study of the effect of free gas saturation on
oil displacement by water drives, Kyte, and others, (26) found a correlation
between the residual oil saturation after flooding and the amount of gas
trapped behind the oil bank. The trapped-gas saturation was in turn found
to be a function of the mobile gas that was in the porous system before
waterflooding was started. Although the advancing water front formed an
oil bank which then displaced part of this gas as the oil bank traversed the
sand, lower residual oil saturations after waterflooding could be correlated


10

80 T T T T T T T T T

20 L | | I I | ! I {
1007 T T T T T T T T T

140)
120
100

APPARENT VISCOSITY, centipoises

140)

120)

100)

80;-

60 L L 1 ! \ _L \ \
fe} ile} 20 30 40 50 60 70 80 90 100

DRAINAGE, percent

FIGURE 5. - Effect of Shear Rate and Foaming-Agent (Duponol RA)
Concentration on Bulk-Foam Viscosity.

The bulk- foam tests served to show that the viscous properties of foams
may not be varied widely by either manipulation of surfactant concentration
or by selection of surfactant. Foam texture combined with expansion factor
had considerable influence on the viscous properties of freshly generated
foams but the trends were generally convergent as drainage progressed. In
the experimental method employed, the latter effects were transient and could
not be measured reliably.

The question arose as to the applicability of the measurements of bulk-
foam viscosities to systems in which foam-bubble diameters approach flow-
channel diameters, A method was required which would permit apparent-
viscosity measurements under steady-state conditions in which the values