Note: Descriptions are shown in the official language in which they were submitted.
Case No. 5517
1.12 9 6 3 4 RDS/eob
1/22/80
TERTIARY OIL RECOVERY PROCESS
BACKGROUND OF THE INVENTION
FIELD OF THE INVENTION
This invention relates to a tertiary oil recovery
process using polymer flooding as an integral part of a
W~G, water alternating with gas, CO2 flood.
DESCRIPTION OF THE PRIOR ART
Oil has been produced by either primary or
secondary methods for many years. These methods can re-
cover oil at relatively low costs and rapid rates. How-
ever, large amounts of oil, usually more than 50 percent,
will remain in the reservoir even aEter secondary re-
covery, water flooding. This is because of the relative-
ly high interfacial tension at the oil-water interface,
which causes th~ entrapment of residual oil in the oil-
bearing formations and poor sweep efficiency during
wa~erfloods.
It is possible to reduce this interfacial tension
between the oil and water phases by adding surface active
agents to a waterflood. Petroleum sulfonates are good
surface active agents.
Injection of CO2 at high pressures into a forma-
tion has also been practiced. The CO2 vaporizes some
components of the crude and carries them forward to con-
tact additional oil, and a portion of the CO2 also dis-
solves in the crude. When C02 dissolves in crude oil,
the crude swells and the viscosity drops.
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11~9~34
At a certain point in the reservoir, when the C02-hydro-
carbon mixture reaches a certain compOSitiQn, miscibility occurs.
This is so-called multiple contact miscibility. ~esidual oil can
be reduced to a very low level, five to ten percent of the porous
space, during the miscible displacement process.
In the immiscible regionJ oil recovery also can be improved
because it is easier to displace the less viscous crude, and the
swelling action of the C02 minimizes the amount of crude left be-
hind.
The basic miscible C02 flooding process patent is disclosed
in United States Patent 2,623,596 ~United States Class 166-21).
Various improvements have been made in the C02 miscible flood pro-
cesses.
Some problems occur in CO2 fLooding, one of the most signi-
ficant being the tendency of the ;njected CO2 to by-pass signifi-
cant portions of the formation. The C02 does this, to even a greater
extent than does water in a water flood, because ~he CO2 and the
CO2-hydrocarbon mixtures are much more mobile than the oil or water
in a formation.
Use of a surfactant in conjunction with the C02 flood was
disclosed in United States Patent 3,3~2,256 (United States Class 166/9).
The patentee taught adding a surfactant capable of forming a stable
foam under formation conditions before or during the CO2 flood.
The foam would tend to block highly permeable strata, cracks and
fissures. The foam also increases the ~iscosity of the carbon dio-
xide making it a more efficient displacing fluid.
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Another solution to the by-pass problem is the WAG pro-
cess, Water Alternating with Gas, preferably CO2. This reduces
the mobility of the CO2 and promotes a better sweep of the forma-
tion. Frequently WAG injection of CO2, or injection of a single
large slug of CO2, is followed with a water flood to drive the
C2 through the formation. This minimizes the amount of relatively
expensive C02 which must be injected, and perhaps left, in a forma-
tion.
One variation upon the water flooding theme is disclosed ~;
in United States Patent 3,817,331, ~nited States Class 166/275),
Jones, Waterflooding Process. Jones recognized that prior re-
searchers had tried to improve conventional water flooding tech-
niques by creating a foam bank between the oil and the water
flood to control the mobility of the water. The improvement
disclosed by Jones consisted of injecting a non-foaming surfact-
ant into a well, flooding with water, and then injecting gas
through the water flood. The gas collected the surfactant and -
carried it ahead of the water to contact the oil. Jones contem-
plated using CO2, and recognized the advantages of contacting
crude with CO2. The patentee taught that it was crucial that the
gas phase have a relatively high mobility, and that conditions be
provided which favored the free forward movement of gas through
a water flood.
In the example of this patent, very little CO2 was used,
only the amount which would dissolve in water at 13 psi, presum-
ably at room temperature. This carbonated water is not even close
to the amount of CO2 which would be required to achieve a CO2
miscible flood.
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Another hybrid process has been proposed in United States
Patent 3,882,940, ~United States Class 166/273), Carlin, Tertiary
Oil Recovery Process Involving Multiple Cycles of Gas-Water Injection
after Surfactant Flood. Carlin proposes conventional surfactant
flooding followed by use of small, alternating gas and water slugs,
followed by injection of a drive fluid, usually water.
Both the processes of Carlin and Jones require the addi-
tion of substantial amounts of surfactants. Neither makes substant-
ial use of the advantages of a miscible CO2 flocding process,
relying~ on the surfactant flooding as the primary method of re-
covering oil.
An improved CO2 process was disclosed in United States
Patent 4,113,011 ~United States Class 166/273). The patentee used
a surfactant comprising alkyl polyethylene oxide sulfates. This
reference also discloses adding some low molecular weight alcohol
to the surfactant solution. The patentee noted that at very high
pressures, carbon dioxide behaved as a dense fluid, and there
would be no significant volume increase as the carbon dioxide
passed through permeable strata underground. This would result
in no ~oam formation, though increased recovery was claimed. It
is believed that the patentee saw the results of a combination of
a combination of CO2 miscible displacement and conventional sur-
factant miscible displacement.
3~
SUMMARY O~ THE INVENTION
In the process of the invention, a WAG, CO2 miscible
flooding process is supplemented by the addition of polymer into
the watar to improve sweep efficiency and oil recovery.
Accordingly, the present invention provides in a process
for recovering petroleum from an underground formation, said form-
ation having an injection well and a producing well, and oil is
forced toward said producing well by-miscible displacement with
C2 in a water-alternating-gas process, the improvement comprising
adding to at least a portion of the water used in said WAG process,
50 to 500 wt. ppm of a polymer as a water thickening agent.
In another embodiment, the prese~nt invention provides in
a process for recovering petroleum from an underground formation,
said formation containing connate water which is hard and deleter-
ious to conventional surfactant flooding process and having an
injection well and a producing well and oil is forced toward said
producing well by miscible displacement with CO~ in a water-
alternating-gas process, the improvement comprising use of water in
said WAG process which contains 50 to 500 ppm of a water thickening
agent comprising a polymer selected from a group of polyacrylamides
and Xanthan gums, and wherein the water-alternating-gas process
consists of at least five separate injections of CO2 alternated
with water injections, and wherein at least the first two water
injections contain a water thickening agent and at least the last
two water injections contain a surfactant.
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Case No. 5517
~IL2~ RDS/eob
1/22/80
The carbon dioxide which is used in the practice
of the present invention is preferably at least 90 mole
percent CO2 or higher. The mechanisms of CO2 injection
are well known in the art and need not be discussed. An
overview of this process was presented by Stalkup, F.I.
"Carbon Dioxide Miscible Flooding: Past, Present, and
Outlook for -the Future", Paper SPE 7042, presented at
SPE-AIME Improved Oil Recovery Symposium, Tulsa, April
16-19, 1978.
DETAILED DESCRIPTION
In conventional CO2 miscible flooding processes
about 0.1 to 0.5 pore volumes of CO2 would be injected
into a formation. In -the present invention, somewhat
lesser amounts of CO2 injection are possible. Alter-
natively, an amount of CO2 injection equivalent to prior
art processes may be used with improved oil recovery
being the result.
Polymers which may be added to the water may be
broadly classed as either synthetic or biopolymers. Syn-
thetic polymers are usually polyacrylamides. Riopolymers
are usually derived from a fermentation process, e.g.,
Xanthan gums. The concentrations needed are relatively
low, on the order of 50 to 500 wt. ppm, based on active
ingredients.
Use of thickened water will improve sweep ef-fi-
ciency, but by itself it will not significantly improve
oil recovery in an area which would have been swept
anyway by the CO2 flood. Improved sweep efficiency will
result in more oil recovery because more of the formation
will be contacted with the CO2 flooding agent.
Case No. 5517
Harry L. Chang
RDS/eob
~ 6 3 ~ 1/22/80
Surfactants may also be added to the water in the
present invention. Any surfactants used conventionally in
surfactant flooding may be used, so long as the presence
of C2 will not cause formation of precipitates. Swr-
factants may be broadly classified an anionic, cationic
or nonionic. Preferably anionic surfactants having an
equivalent weight of 250-600 are used.
Typical anionic surfactants are:
(1) Alkyl-aryl sulfonates having the following
structure:
R-phenyl -SO3 M
~here R is an alkyl radical, linear or branched,
with 8-15 carbon atoms~ and M is a monovalent cation such
as Na , K+ or NH4 .
(2) Alkyl sulfonates having the following struc- ,
ture:
R-S03-M~
Where R and M have the same meaning as in (1).
(3) Alkyl polyethoxylated sulfates having the
following structure:
(R-(ocH2cH2)nso4) M
Where R and M have the same meaning as in (1),
and n is an integer from 2 to 6.
(4) Alkyl aryl disulfonate e-thers having the
following structures:
~L~ 3~ Harry L Chang
RDS/eob
1/22/80
R-phenyl-0-phenyl and R-phenyl-0-phenyl-R
S03 M S03 ~1 S03 M S03-M+
Where R and M having the same meaning as in (1)
except the carbon atoms range from 6 to 16.
These surfactants preferably include a foaming
agent, since foams will improve mobility control. Sur-
factant concentrations of 0.01 to 10 wt. % are within the
scope of the present invention, with a surfactant con-
centration of 0.1 to 2 wt. % being preferred.
The presence of surfactant in the WAG water
assists in oil recovery by improving the displacement of
crude oil from a formation. It is typical of a C02
miscible flooding process that no oil bank is developed
near the injection well because time and distance are
needed for the C02 to vaporize light components from the
crude, and also for the C02 to dissolve in the crude. It
is known from laboratory tests using a C02 miscible
process that a relative~y long core is necessary to
develop an oil bank. Miscibility cannot be achieved near
the point of C02 injection. The C02 miscible flood is
preferably complimented by the action of the sur:Eactant
- flood. What is left behind by the C02 flood may be
picked up by the surfactanL flood. The C02 flood is re-
latively ineffective near the injection well, while the
surfactant ~lood is most effective at that point. The
operation of the C02 flood improves with time and dis-
tance through the formation, just as the efficiency of
the surfactant flood drops off dwe to dilution with con-
nate water and/or contac-t with high salinity reservoir
brines.
Case No. 5517
Harry L. Chang
~ 1/22/80
The two different flooding mechanisms which are
used simultaneously in the practice of my invention com-
plement one another in that the simultaneous flooding im-
proves sweep e:Eficiency which benefits both the CO2 flood
and the surfactant flood. Another advantage of this pro-
cess is that the CO2 flood tends to displace some of the
connate water before it, resulting in less dilution and
degradation of surfactant and/or polymer which is con-
tained in the water portion of my WAG process.
The volume ra-tio of water and CO2 injected during
the WAG portion of my process should range from about 5:1
to about 0.5:1, and preferably from about 3:1 to 1:1
volumes of water per volume of CO2 at reservoir con-
ditions.
ILLUSTRATIVE EMBODIMENT
Although I have not tested my inven-tion in the
field, the following is an illustration of the best way
known to apply this invention commercially and the re-
sults I expect to obtain.
29 I would inject five cycles of alternating CO2-
thickened water plus surfactant. Each cycle consists of
injecting 0.04 pore volumes CO2 followed by 0.04 pore
volu~es water containing surfactant. The water will con-
tain 1.0% petroleum sulfonate. The water will also
contain about 200 ppm biopolymer, on average. A decreas-
ing polymer content is preferred, with higher levels of
biopolymer being added to the first slug, and less added
to the final slug, e.g., 350, 300, 250, 200, 150 ppm of
biopolymer would be added to the 1st through 5th slugs,
respectively.
Case No. 5517
Harry L. Chang
~`~Z ~3~ R S/eob
It is believed that the practice of the present
invention will increase oil recovery, while reducing
consumption of surfactant and polymer. To be an economic
success, the practice of the present invention requires
an economical source of relatively pure CO2, but such CO2
sources are available both from subterranean sources and
exhaust streams from fertili~er plants, power plants,
etc.
Other variations of the present inven-tion which
may be useful in particular formations include tapered
injection of surfactants and/or polymer. It may be de-
sirable to load most of the surfactant injection into the
first one or two surfactant s:lugs. Alternatively, sur-
factant concentration in the water may be kept relatively
constant, with the size of the water slug tapering while
holding size of the CO2 slug constant. Polymer may be
added to all or some of the water slugs, in a constant or
varying composition.
Polymer and surfactant may be used in the follow-
ing manner:
(l) Slug Volume Slug Type:;
0 04 C2
0.04 Surfactant
0 04 C2
0.04 Surfactant
0 04 C2
0.04 Surfactant
0 04 C2
0.04 Surfactant
0 04 C2
Case No: 5517
3 ~ RDS/eob
1/22/80
0.04 Surfactant
0.10 Polymer ~350 wt. ppm)
0.20 Polymer (250 wt. ppm)
0.20 Polymer (150 wt. ppm)
(2) 0 04 C2
0.04 Surfactant
0'04 C2
0.04 Polymer (250 wt. ppm)
0.04 Polymer ~250 wt. ppm)
0 04 Polymer (250 wt. ppm)
0.04 Polymer (250 wt. ppm)
0.04 Polymer (250 wt. ppm)
0.50 Polymer, tapered
concentration
In its simplest embodiment, the present invention
- calls for use of a CO2 miscible flood process used in
conjunction with thickened water. My process will give
superior oil recovery, as compared to the prior art
processes using CO2 miscible flooding in conjunction with
surfactant additions. This is because my process does
not depend upon the formation of a foam to act as the
water thickening agent. In the practice of the preferred
embodiment of my invention, CO2 miscible flooding, thick-
ened water, and surfactant flooding are used together. In
this mode of operation, thickened water improves the
efficiency of the CO2 flood, while the surfactant flood
compliments the action of the CO2 flood. The CO2-polymer
flood can also be used to sweep from the formation un-
desirable connate water which would o-therwise adversely
Case No. 5517
Harry L. Chang
:~12~3~ Rl~2S/~C80b
affect the surfactant materials used in the surfactant
flood. Thus, results could be achieved with the practice
of my invention which coulcl not be achieved with prior
art processes, wherein -the efficiency of the surfactant
flood would ~e harmed by the presence of hard water or
other problem minerals in the formation. Similarly, my
process is not dependent on the presence of pressure
drops across any part of the formation to generate foam.
