Note: Descriptions are shown in the official language in which they were submitted.
137~
OIL RECOVERY PROCESS
USING ALKYL ~YDROXYAROMATIC DIANIONIC SURFACTANTS
AS MOBILITY CONTROL AGENTS
Field of the Invention
This invention relates to recovering oil from a subterranean
oil-bearing formation by injecting into the formation a gas and an
aqueous surfactant solution to control gas mobility. More
specifically, the invention pertains to use of alkyl hydroxyaromatic
dianionic surfactants to reduce gas mobility within an oil-bearing
formation.
Back~round of the Invention
A significant fraction of the oil-in-place is left in the
ground after primary or secondary recovery. Gas injection, sometimes
referred to as gas flooding, has been used to recover this remaining
oil. The terms "gas injection" and "gas flooding" as used herein will
mean an oil recovery process in which the fluid injected is a
hydrocarbon gas, inert gas, carbon dioxide, or steam.
The success of gas floods has been diminished by the
unfavorable mobility ratio between the gas and oil. The viscosities
of gas mixtures are often 10 to 100 times lower than oil and water
viscosities. At these unfavorable viscosity ratios, ga6es finger and
channel through the formation, leaving parts of the reservoir
-2- 1~13~
unswept. Added to this fingering is the inherent tendency of a highly
mobile gas to flow preferentially through the more permeable rock
6ections or to gravity override in the reservoir. These basic factors
--permeability variations and unfavorable mobility and density
ratios-- greatly reduce the effectiveness of gas floods and may make
them uneconomic. One apparent remedy is to control the mobility of
the injected gas.
It has been suggested that the mobility of the gas may be
reduced by injecting into a formation or forming in situ a mixture of
a gas and an aqueous surfactant solution. Such mixtures are commonly
referred to as foams. Since the effective viscosity of foam is
greater than the viscosity of its components, it has been suggested
that such mixtures of gas and aqueous surfactant solution will help
improve the sweep efficiency of gas drives.
Foam is a dispersion of a large volume of gas in a relatively
small volume of liquid. It should be noted, however, that at
reservoir conditions several gases, including C02, exist as a dense
fluid, resembling a liquid more than a gas. For this reason, the term
"solvent" is sometimes used to describe the "gas" and the term
"emulsion" is 60metimes used to describe the solvent-water mixture.
Mobility control may be accomplished by injecting a bank of
aqueous surfactant solution followed by injecting gas. Alternatively,
banks of surfactant solution can be interspersed with the gas during
injection to achieve a more continuous effect.
_3_ 1 31 37~5
It is known that the choice of surfactant for use as a
mobility control a8ent is of vital importance. Many surfactants cause
too severe a reduction of gas mobility, thus making the gas difficult
to inject into the reservoir. Other surfactants cause an insufficient
reduction of gas mobility, thus leading to inadequate improvement of
sweep efficiency.
Conditions existing in a typical oil reservoir impose a
severe challenge to surfactant performance. Most reservoirs have an
aqueous phase of brine that may vary in concentration from 0.5% to 15%
NaCl. Also, there may be divalent ions such as Ca and Mg++
present in significant concentrations (100 ppm or more). Adsorption
or trapping of surfactant in viscous emulsions is another limitation.
The effect of crude oil and temperature can also be deleterious if not
properly taken into consideration.
Considerable effort has been made by the petroleum industry
to identify surfactants with proper chemical stability, adsorption
characteristics, and capability for gas-mobility reduction. Hundreds
of surfactants have been screened. There continues to be a significant
need, however, for improved gas mobility-control processes in which the
amount of additional oil recovered as a result of in~ecting the
surfactant and gas is sufficient to ~ustify the cost of the process.
-4- 131375~
Summary of the Invention
The present invention relates to an improved process for -
reducing gas mobility in a region of 8 subterranean, oil-containing
formation by introducing into the formation a gas and an aqueous
solutio~ conta~ning a surfactant characterized by the formula
R~O[CH2CH(cH3)0]ylcH2cH2o]yR~so3M
S03M
where R i8 a linear or branched chain alkyl group with n carbon atoms
wherein n ranges from 0 to about 18, except that if the gas
is steam n ranges from about 9 to about 30;
x ranges from 0 to about 20 and y ranges from 0 to about 20,
provided x + y does not exceed about 20;
R' is a linear or branched chain alkyl group with m carbon atoms
wherein m ranges from 0 to 4, except that if the gas is steam
m ranges from 1 to 4, with the proviso that the sum of
x + y + m is at least one; and
each M+ is a cation.
In a preferred embodiment for reducing the mobility of carbon
dioxide, hydrocarbon gas, or inert gas, the aqueous solution contains
0.02 to 1.0~ by weight C6 18 phenol disulfonate contain~ng 0-6
ethoxy groups terminated by an ethyl or a propyl sùlfonate group. A
preferred surfactant for a steam flood is C12 30 phenol disulfonate
containing 0-6 ethoxy groups terminated by an ethyl or propyl
sulfonate group.
13~rl~
The gas mobility is reduced in situ in the formation by
injecting the aqueous surfactant solution into the formation through
an injection well and injecting gas into the formation through the
in3ection well with or after injection of the aqueous surfactant
S solution. In another embodiment the formation is first flooded with
gas before injecting the mobility control agent. The steps of
injecting aqueous surfactant solution and gas may be repeated.
The practice of this invention provides effective mobility
control for gas floods and improves oil displacement efficiency.
Brief Description of the Drawin~s
FIGURE 1, which illustrates the result of an experimental
core displacement test, plots comparative mobility of a mixture of
C2 and aqueous surfactant solution generated in accordance with
this invention as a function of pore volumes of C02 injected.
Detailed Description of the Invention
A mobility control system comprising a mixture of gas and an
aqueous solution containing a surfactant for use as a mobility control
fluid in recovering oil from a subterranean oil-bearing formation
should ideally have the following characteristics:
The mixture should provide resistance to flow of the gas in
gas-swept zones where the oil saturation is low.
The mixture should not impair the mobility of gas and oil in
unswept zones where oil saturation is high.
-6- 13137~5
The 6urfactant retention should be low and the surfactant
should be effective at low concentrations. - --
- -- The properties of the mixture should be insensitive to
reasonable variations in reservoir salinity, temperature, and
surfactant concentration.
The present invention is premised on the discovery that a
mobility control system exhibiting the beneficial characteristics
listed above can be formed by use of a surfactant characterized by the
formula
R~,O[CH2CH~CH3)0]xtC}{2C~20]yR~S03~1 (1)
S03M
where R i8 a linear or branched chain alkyl group with n carbon atoms
wherein n ranges from 0 to about 18, except that if the gas
is steam n ranges from about 9 to about 30;
x ranges from 0 to about 20 and y ranges from 0 to about 20,
provided x + y does not exceed about 20;
R' is a linear or branched chain alkyl group with m carbon atoms
wherein m ranges from 0 to 4, except that if the gas is steam
~ ~ m ranges from 1 to 4, with the proviso that the sum of
;~ x + y + m is at least one; and
each M+ is a cation.
The ethoxy and propoxy groups may be present as a block co-polymer
chain or they may be intermixed within the alkoxy chain.
1313~5
M can include alkali metals such as sodium, potassium and
lithium, alkaline earth metals such as calcium and barium, amines
including alkanol amines and their oxyalkylated adduct~j and
ammonium.
It should be understood the polyalkoxy surfactants used in
the present invention will not normally be pure substances in the
strict sense, but a mixture of components such that x and y are the
resulting average values. It should also be understood that in the
preparation of the surfactants used in the present invention, the
surfactant formulation may contain compounds falling outside
formula (1). For example~ the formulation may include small amounts
of compound6 containing more than one alkyl group or more than one
sulfonate group attached to the benzene ring. The formulation may
also include small amounts of monosulfonate in which either sulfonate
group in formula (1) is absent.
, ~
-8- 13~3~5~
Non-limiting examples of surfactants characterized by formula
(1) suitable for reducing the mobility of carbon dioxide, hydrocarbon
gas and inert gas are listed in Table 1:
TABLE 1
R R' x y M
linear C16H33 CH2CH2CH2 o Na+
branched CgHlg CH2CH2 2 Na+
linear C16H33 CH(cH3)cH2cH2 0 0 Na+
branched CgHlg none 0 3 Na+
branched CgHlg CH2CH2 1 3 Na+
branched CgHlg CH2CH2 3 0 Na+
+
branched CgHlg CH2CH2 2 NH4
Non-limiting examples of surfactants characterized by formula
(1) suitable for reducing mobility of steam are listed in Table 2.
TABLE 2
+
R R' x v M
linear C18H37 CH2CH2CH2 0 Na+
branched C12H23 CH2CH2 2 Na+
linear C18H37 CH(CH3)CH2CH2 0 Na+
linear C18H37 CH2CH2 1 3 Na+
linear C18H37 CH2CH2 3 0 Na~
linear C18H37 CH2CH2 0 2 NH4
g 13~3~5
In selecting mobility control surfactants of this invention for
a particular 100ding operation, the effect~ of gas composition should
be-considered. A mobility control sy6tem comprising a surfactant
represented by formula (l) above and steam will generally have higher
mobility than a mobility control system comprising the same surfactant
and other gases such as C02 and N2. Since the mobility of gas in
this invention tends to decrease as the number of carbon atoms of the
lipophile portion of the surfactant increases, the number of carbon
atoms of R in formula (l) is generally higher for use in steam floods
than the number of carbon atoms of R for use in other gas floods.
Referring again to formula (1), when m = 0, the R' alkyl group
is absent, and the surfactant contains a sulfate group. It is well
known to those skilled in the art that sulfate surfactants are
susceptible to rapid chemical degradation by hydrolysis of the sulfate
group at high temperature and/or low pH. The product of the degradation
reaction tends to be less effective as a mobility-reducing agent, and
may have significantly higher retention than the original surfactant.
For this reason, surfactants having m = 0 would generally not be used in
flooding processes where the temperature is high, such as steam
flooding, or where pH is low, such as C02 flooding. Surfactants
having m = 0 may, however, be used under conditions where the rate of
hydrolysis of the sulfate group is low. Examples of such conditions may
include hydrocarbon or inert gas flooding at low temperature, or C02
flooding at low temperature in a reservoir where pH is buffered by
reservoir minerals to a level at which hydrolysis ~ 8 acceptably slow.
-lo- 13137~
Particularly preferred mobility control systems of this
inventian include surfactants having a composition characterized by the
formula ~ --
R ~ O(CH2CH20)yR'S03M (2)
S03M
where: R is a C6 to C18 linear or branched alkyl chain for use
in C02, inert gas, and hydrocarbon gas floods, and R is a
linear or branched C12 to C30 alkyl chain for use in
steam floods; y i6 0 to 6; R' is an alkyl group containing
two or three carbons; and each M is an alkali metal ion.
As understood by those skilled in the art, the optimum
surfactant for a particular gas flooding process will depend on the
reservoir in which it is used. The optimum values of n, m, x, and y
in formula (1) for a particular gas flooding operation will depend on
the reservoir conditions of temperature, pressure, permeability,
salinity, oil composition, and the like. The optimum surfactant maybe determined by performing core displacement tests using procedures
known to those skilled in the art. Such tests may be used to select a
surfactant that has low retention, can be used at low concentration,
provides a substantial but not excessive reduction of gas mobility,
and does not impair the recovery of the oil.
The surfactants of the present invention may be prepared by
known procedures. The following is a description of one way of
-ll- 1 3 ~
preparing such surfactants. For those surfactants having two or more
carbon atoms attached to the benzene ring, the synthesis procedure
usually begins by reacting phenol with olefins at temperatures and
pressures sufficient to alkylate the phenol. The reaction is
conducted in the presence of an effective amount of an acid catalyst
such as boron triflouride, sulfuric acid, phosphoric acid, or sulfonic
acid. The alkyl phenols may then be reacted with alkylene oxides in
the presence of a base to provide alkyl-phenyl polyalkoxy alcohols.
The alkoxy derivatives may then be reacted with a sultone such as
propane sultone or butane sultone to form an alkyl phenol alkoxy
monosulfonate. A sulfonate group may be added on the aromatic ring to
produce a disulfonate by sulfonating the alkyl phenol alkoxy
monosulfonate product with a suitable sulfonating agent such as
chlorosulfonic acid. The disulfonic acid may then be neutralized with
a base such as 50% NaOH.
The present invention is useful where it is desirable to
reduce gas mobility in an area of a subterranean, oil-containing
formation to facilitate production of oil from or displacement of oil
through the pores of the formation. The formation may be any light or
heavy oil reservoir having a permeability suitable for an application
of a fluid to displace oil away from a well borehole in a
well-cleaning operation or to displace oil through the formation to a
producing location in an oil recovery operation.
In general, the gaseous fluids can comprise steam, carbon
dioxide, inert gases such as air and nitrogen, hydrocarbons such as
methane, ethane, propane, and natural gas, and mixtures thereof.
-12~ 3~
Gas and aqueous surfactant solution may be-in~e~ted ineo the
formation in the form of alternating banks. The gas and aqueous
surfactant solution will mix in the format;on. However, where
desirable, the gas and aqueous solution may be injected
simultaneously, as a dispersion of the gas in the liquid or as a pair
of co-flowing streams of the two fluids within a common conduit. The
components are preferably injected at a pressure sufficient to
displace the oil without fracturing the reservoir. However, in low
permeability reservoirs controlled fractures of limited extent may be
required to obtain adequate injectivity.
In the practice of one embodiment of this invention, C02 is
injected into an oil-bearing subterranean formation through an
injection well. The highly mobile gas will tend to flow
preferentially through the more permeable rock sections. The C02
mobilizes the recoverable oil in those sections. Gas injection
continues until sufficient gas has been injected to ensure recovery of
a substantial portion of the oil in the more permeable zones, or until
gas breakthrough occurs at the production well which is spaced apart
from the injection well. A bank of brine containing a surfactant
characterized by formula (1) above is then injected, followed by a
second bank of C02. The surfactant solution will preferentially
enter the more permeable zones and will reduce gas mobility in those
areas, thus diverting C02 to previously unswept zones of the
formation. Banks of surfactant solution may be alternated with banks
of C02. Optionally, the composition of surfactant in the aqueous
solution may be varied from one bank to the next to optimize the
process. If desired, a bank of drive fluid may be injected after the
-13- 1~13755
last C02 bank has been injected to displace the C02 through the
formation. -- ~-
In another embodiment of this invention, a small amount of
surfactant characterized by formula (1) above is added to water duringthe last stage of a waterflood operation. Surfactant is injected
before start-up of a gas injection project to avoid time delays
associated with injecting an additional surfactant bank after the
usual waterflood operation has been completed.
The process of this invention may be applied to a
6ubterranean, oil-containing formation penetrated by at least one
injection well and at least one spaced-apart production well. The
injection well is perforated or other fluid flow communication is
established between the well and the formation. The production well
is completed in fluid communication with a substantial portion of the
vertical thickness of the formation. While recovery of the type
contemplated by this invention may be carried out with only two wells,
this invention is not limited to any particular number of wells. The
invention may be practiced using a variety of well patterns as is well
known in the art of oil recovery, such as a repeated five-spot pattern
in which each injection well is surrounded with four production wells,
or in a line-drive arrangement in which a series of aligned injection
wells and a series of aligned production wells are utilized.
This process can also be used in "huff and puff" operations
through a single well. In the huff and puff procedure, the reduced
gas mobility is generated through the same well that is subsequently
-14- i3137~
used for production. The reduced gas mobility improves the injection
profile. The gas bility in swept zones is greatly reduced so the
gas will invade the previously unswept tighter ~ones. The well may be
shut in for a period of time before placing it on the production
cycle. After the production cycle, additional cycles of injection and
production can be utilized.
The aqueous surfactant solution used in this invention may be
prepared from brine or carbonated water. Preferably the water
available at the injection well site, often formation brine, will be
used to prepare the aqueous surfactant solution.
The concentration of surfactant in the aqueous solution will
ordinarily range from about 0.01 to 2% by weight and preferably from
about 0.05 to 1%, and still more preferably from 0.05 to 0.5%.
As known to those skilled in the art, the volumes required
for the banks of aqueous solution and gas are different for different
reservoirs, but it can be estimated by known proccdures with
reasonable accuracy. Generally, the total pore volume of surfactant
solution used in this invention will range from 0.01 to l and
preferably from 0.1 to 0.5 pore volume.
C2 used in this invention can be obtained from any
; 25 available source. It is not necessary that it be pure. The C02
that is produced through the production wells can be separated
therefrom and reinjected into the formation. Recycling methods for
C2 are generally known and do not need further explanation.
-1S- ~ 7 ~ ~
Steam used in the present invention can be generated as a
dry, superheatedj or wet steam and subsequently mixed with aqueous
liquid. The steam can be generated at surface or downhole locations
and mixed with the aqueous surfactant solution at surface or downhole
locations. Optionally, the steam may include a gas that is
noncondensable at reservoir temperature and pressure.
Experimental Results
This invention is further illustrated by the following
laboratory experiments, which demonstrate the operability of the
invention. The experiments are not intended as limiting the scope of
the invention as defined in the appended claims.
All of the core flooding laboratory experiments described
below used 1 in. X 1 in. X 12 in. (2.54cm X 2.54cm X 30.5cm) Berea
sandstone cores. Differential pressures were monitored between inlet
and outlet and between three pairs of taps 1 in. (2.54 cm) apart
located 2 in. (5.04 cm), 6 in. (15.24 cm) and 10 in. (25.40 cm) from
the inlet. All experiments were carried out at 2000 psi (13,789 kPa)
with decane as the oil phase. Two high-salinity brines were used:
; 3.5% and 7.0% by weight total dissolved solids (TDS). Both brines had
high contents of divalent ions, with a weight-ratio of CaC12 to NaCl
of 1 to 4. Two temperatures were used: 100F (37.8C) and 150F
(65.6C). Five corefloods are discu66ed below in detail. All of the
cores were flooded with oil (decane) to connate water saturation and
then waterflooded with brine at a rate of 3 ft/day (0.91 m/day) prior
to carrying out the experiments. Decane was completely miscible with
-16- 1~13~
C2 at the conditions o the tests. The injection rate~of C~2-
through the cores was 1 ft/day (0.30 m/day) and the injection rate of
surfactant solution was 3 ft/day (0.91 m/day). At this rate, no oil
was produced when only surfactant solution flowed through the cores.
Table 3 below sets forth core permeability, brine
concentration, temperature, and injection sequence for each run.
TABLE 3
Berea
Core
Permea- Brine, Temp.,
Run bility TDS C Iniection Sequence
1 450 md 3.5% 37.8 C2 Flood
2 550 md 3.5~ 37.8 0.1~ Surfactant, then
CO2
3 530 md 7.0~ 37.8 0.1% Surfactant, then
CO2
4 650 md 3.5% 65.6 0.1~ Surfactant, then
CO2
520 md 3.52 37.8 0.5% Surfactant, then
CO2
The surfactant in runs 2-5 was a linear C16 alkyl phenol disulfonate
(C16APDS), a surfactant represented by formula (1) above where
x = 0, y = 0, and m = 3.
The active surfactant contained 92% disulfonate and 8%
monosulfonate. The monosulfonate component had the sulfonate group on
the aromatic ring.
-17- 1313~
The objectives of the tests were to reduce C0z mobility in
a core containing waterflood residual oil- and displace the residual
oil with the C02. In all of the core floods in which surfactant was
injected, C02 mobility was reduced by an unsteady-state process -
involving a two step injection sequence: injection of surfactantsolution followed by injection of C02. In runs 2-5, sufficient
surfactant solution was injected so that the effluent surfactant
concentration nearly reached the influent surfactant concentration
prior to injection of C02.
The comparative mobility, oil recovery and surfactant
retention of each run are summarized in Table 4 below. The
comparative mobility i8 defined as the ratio of the mobility of the
gas-aqueous surfactant solution mixture to water mobility at residual
oil saturation. At 2.0 pore volumes of C02 injection, the mobility
of the aqueous phase is extremely low, so that for good approximation
the comparative mobility is simply the mobility of C02. A
comparative mobility greater than unity indicates the gas will be more
mobile than water at residual oil saturation. Generally, for
effective mobility control in C02 floods, the comparative mobility
should be below about 1, depending on field conditions. A comparative
mobility above about 1 would not be desirable due to instability at
the displacement front resulting in fingering, bypassing and low
displacement efficiency. However, any reduction of mobility brought
about by the injection of surfactant solution of this invention will
be beneficial, even if the comparative mobility somewhat exeeds 1.
-18- 13137~S
TABLE 4
. .
RUN OIL SAlVRA- SURFACTANT OIL COMPARA--
TION BEFORE RETENTION RECOVERY TIVE
SURFACTANT at 1.2 M08ILIl~Y
INJECTION PV C02 at 2.0 PV
INJECT- CO2 IN-
TION JECTION
mg/g rock ~ Sor
.
1 0.34 _ 80
2 0.440.18 76 0.2
3 0.420.22 82 0.4
4 0.490.17 85 0.3
0.490.20 80 0.25
C2 Flood (No Surfactant) - Run 1
Run 1 provided a base case for the other runs. The
comparative mobility of C02 characteristically increased to 10 after
C2 breakthrough. The high mobility i8 related to the low viscosity
of CO2, about 0.06 cp at 2000 psi (13,789 kPa) and 100F (37.8C).
The oil recovery was about 80% of waterflood residual oil saturation
(Sor) after 1.2 pore volumes of C02 were injected.
Mobility Control Process in Waterflooded Core - Run 2
`:
An aqueous solution containing 3.5% total dissolved solids
and 0.1% C16APDS was injected into a waterflooded core. No
additional oil was removed from the core during injection of over 3
pore volumes of the surfactant solution. During the subsequent CO2
injection, CO2 mobility was much lower than in Run 1. As shown in
FIGURE l, the comparative mobility dropped gradually, leveling off at
about 0.2 after 2PV of CO2 injection.
~ 3 ~
--lg--
The oil recovery at-1.2 pore volumes of C02 injected was
76Z of waterflood residual oil ~S ~, similar to that o~tained in
Run 1.
Effect of Salinity, Temperature and Surfactant concentration - Runs 3,
4, and 5
Runs 3, 4, and 5 were similar to Run 2 except that the brine
was more saline in Run 3, the temperature was higher in Run 4, and the
surfactant concentration was greater in Run 5.
Despite the large changes in conditions, neither surfactant
retention, oil recovery, nor comparative mobility was significantly
different from the values obtained in Run 2, as shown in Table 4.
These results suggest that the performance of a gas mobility control
process using the surfactants of this invention is relatively
insensitive to reasonable variations in salinity, temperature, and
surfactant concentration.
The principle of the invention and the best mode contemplated
for applying that principle have been described. It will be apparent
to those skilled in the art that various changes ~ay be made to the
embodiments described above without departing from the spirit and
scope of this invention as defined in the following claims. It is,
therefore, to be understood that this invention is not limited to the
specific details shown and described.
