U.S. patent application number 09/858363 was filed with the patent office on 2003-02-27 for enhanced oil recovery.
Invention is credited to Hwang, Shuen-Cheng, Limbach, Kirk Walton, Ramachandran, Ramakrishnan.
Application Number | 20030037928 09/858363 |
Document ID | / |
Family ID | 25328128 |
Filed Date | 2003-02-27 |
United States Patent
Application |
20030037928 |
Kind Code |
A1 |
Ramachandran, Ramakrishnan ;
et al. |
February 27, 2003 |
Enhanced oil recovery
Abstract
A method for enhancing the recovery of oil from underground
formations is disclosed. A gas mixture which contains greater than
50% by volume carbon dioxide, the remainder being an inert gas, is
injected in the underground formation to lower the oil viscosity
and surface tension and increase the oil swelling. Preferably, the
gas mixture contains greater than 60% by volume carbon dioxide with
a gas mixture containing greater than 70% by volume carbon dioxide
preferred.
Inventors: |
Ramachandran, Ramakrishnan;
(Allendale, NJ) ; Limbach, Kirk Walton; (Dresher,
PA) ; Hwang, Shuen-Cheng; (Chester, NJ) |
Correspondence
Address: |
Philip H. Von Neida
Intellectual Property Dept.
The BOC Group, Inc.
100 Mountain Ave.
Murray Hill
NJ
07974
US
|
Family ID: |
25328128 |
Appl. No.: |
09/858363 |
Filed: |
May 16, 2001 |
Current U.S.
Class: |
166/305.1 ;
166/402 |
Current CPC
Class: |
E21B 43/164
20130101 |
Class at
Publication: |
166/305.1 ;
166/402 |
International
Class: |
E21B 043/16 |
Claims
Having thus described the invention, what we claim is:
1. A method for enhancing the recovery of oil from an underground
formation comprising injecting into said oil a gas mixture
comprising at least 50% by volume carbon dioxide.
2. The method as claimed in claim 1 wherein the remainder of said
gas mixture is selected from the group consisting of an inert gas,
mixtures of inert gases, hydrocarbons, steam, air or mixtures of
these.
3. The method as claimed in claim 2 wherein said inert gas is
selected from the group consisting of nitrogen, helium and
argon.
4. The method as claimed in claim 1 wherein said gas mixture
comprises greater than 60% by volume carbon dioxide.
5. The method as claimed in claim 1 wherein said gas mixture
comprises greater than 70% carbon dioxide by volume.
6. The method as claimed in claim 1 wherein said gas mixture is
injected into said oil at the well head.
7. The method as claimed in claim 1 wherein said gas mixture is
injected into a single production well head.
8. The method as claimed in claim 7 wherein said injection is
cyclical.
9. The method as claimed in claim 7 wherein said gas mixture is
injected into an injection well different from said production well
head.
10. The method as claimed in claim 9 wherein said gas mixture is
injected in an alternating pattern with a driving fluid.
11. The method as claimed in claim 10 wherein said driving fluid is
selected from the group consisting of steam, water, nitrogen,
carbon dioxide and air.
12. The method as claimed in claim 9 wherein there are a plurality
of different injection wells.
13. The method as claimed in claim 1 wherein said gas mixture is
injected into said oil at a pressure ranging from about 100 psi to
about 20,000 psi.
14. The method as claimed in claim 1 wherein said carbon dioxide is
obtained from a power plant or co-generation plant or from in situ
combustion through the injection of air, oxygen enriched air, or
pure oxygen.
15. The method as claimed in claim 1 wherein said nitrogen is
obtained from an air separation plant.
16. The method as claimed in claim 1 wherein after injection of
said gas mixture said underground formation is sealed for at least
one day.
17. The method as claimed in claim 16 wherein said sealed
underground formation is opened and a flood of a material selected
from the group consisting of carbon dioxide, nitrogen, water or
brine is driven through said injection point.
18. A method for enhancing the recovery of oil from an underground
formation comprising injecting into said oil a gas mixture
comprising carbon dioxide and nitrogen wherein said carbon dioxide
is present in said gas mixture in an amount of at least 50% by
volume.
19. The method as claimed in claim 18 wherein said carbon dioxide
is present in said gas mixture in an amount greater than 60% by
volume.
20. The method as claimed in claim 18 wherein said carbon dioxide
is present in said gas mixture in an amount greater than 70% by
volume.
21. The method as claimed in claim 18 wherein said carbon dioxide
is present in said gas mixture in an amount greater than 50% by
volume and less than 99% by volume.
22. The method as claimed in claim 18 wherein said gas mixture is
injected into said formation at a pressure of about 100 psi to
about 20,000 psi.
23. The method as claimed in claim 18 wherein steam is additionally
injected into said underground formation.
24. A method for enhancing the recovery of oil from an underground
formation having at least one production well comprising injecting
into said underground formation in at least two distinct injection
points a gas mixture comprising carbon dioxide and nitrogen wherein
said carbon dioxide is present in said gas mixture in an amount of
at least 50% by volume at the first injection point and further
wherein the volume percentage of nitrogen in said mixture is higher
at said second injection point than said first injection point, and
said first injection point is closer to said at least one
production well than said second injection point.
25. The method as claimed in claim 24 wherein the volume percentage
of nitrogen in said gas mixture increases at each injection point
further from said production well.
26. The method as claimed in claim 24 wherein the viscosity and
surface tension of said oil at said second injection point is
higher than the surface tension and viscosity at said first
injection point.
27. The method as claimed in claim 24 wherein said underground
formation is sealed for at least one day.
28. The method as claimed in claim 27 wherein said underground
formation is opened and flooded with a material selected from the
group consisting of carbon dioxide, nitrogen, water and brine to
improve oil recovery.
29. A method for lowering the viscosity and surface tension of oil
in an underground formation comprising injecting the said oil a gas
mixture comprising at least 50% by volume carbon dioxide.
30. The method as claimed in claim 29 wherein the remainder of said
gas mixture is selected from the group consisting of an inert gas,
mixtures of inert gases, hydrocarbons, steam, air or mixtures of
these.
31. The method as claimed in claim 29 wherein said inert gas is
selected from the group consisting of nitrogen, helium and
argon.
32. The method as claimed in claim 29 wherein said gas mixture
comprises at least 60% by volume carbon dioxide.
33. The method as claimed in claim 29 wherein said carbon dioxide
comprises at least 70% by volume of said gas mixture.
34. The method as claimed in claim 29 wherein said gas mixture
comprises about 50% to about 99% by volume carbon dioxide and about
1% to about 49% nitrogen by volume.
35. The method as claimed in claim 29 wherein said gas mixture is
injected into said underground formation at a pressure of about 100
psi to about 20,000 psi.
36. The method as claimed in claim 29 wherein said hydrocarbons are
derived from associated gas produced during the production of
oil.
37. The method as claimed in claim 29 wherein said hydrocarbons are
present in said mixture in an amount ranging from about 1% to about
50%.
Description
FIELD OF THE INVENTION
[0001] The present invention provides for a method for enhancing
the recovery of oil from underground formations. More particularly,
the present invention provides for injecting into the oil in the
underground formation a gas mixture which contains at least 50% by
volume carbon dioxide and the remainder nitrogen or other inert
gas.
BACKGROUND OF THE INVENTION
[0002] Oil or gas and any water which is contained in the porous
rock surrounding the oil or gas in a reservoir or formation are
typically under pressure due to the weight of the material above
them. As such, they will move to an area of lower pressure and
higher elevation such as the well head. After some pressure has
been released, the oil may still flow to the surface but it does so
more slowly. This movement can be helped along by a mechanical pump
such as the grasshopper pumps one often sees. These processes are
typically referred to as primary oil recovery. Typically, less than
50% of the oil in the oil formation is recovered by primary
techniques. Recovery can be increased by pursuing enhanced oil
recovery (EOR) methods. Typically, these methods are divided into
two groups: secondary and tertiary.
[0003] Secondary EOR generally refers to pumping a fluid, either
liquid or gas, into the ground to build back pressure that was
dissipated during primary recovery. The most common of these
methods is to inject water and is simply called a water flood.
[0004] The tertiary recovery schemes typically use chemical
interactions or heat to either reduce the oil viscosity so the oil
flows more freely or to change the properties of the interface
between the oil and the surrounding rock pores so that the oil can
flow out of the small pores in the rock and enter larger channels
where the oil can be swept by a driving fluid or move by pressure
gradient to a production well. The oil may also be swelled so that
a portion of the oil emerges from small pores into the channels or
larger pores in the rock. Typical of these processes are steam
injection, miscible fluid injection and surfactant injection.
[0005] Thermal techniques employing steam can be utilized in a well
to well scheme or also in a single-well technique which is know as
the huff and puff method. In this method, steam is injected via a
well in a quantity sufficient to heat the subterranean
hydrocarbon-bearing formation in the vicinity of the well. The well
is then shut in for a soaking period after which it is placed on
production. After production has declined, the huff and puff method
may again be employed on the same well to again stimulate
production.
[0006] The use of carbon dioxide and its injection into oil
reservoirs is known for well to well and single well production
enhancement. The carbon dioxide dissolves in the oil easily and
causes the oil to swell and reduces the viscosity and surface
tension of the oil which in turn leads to additional oil recovery.
The carbon dioxide may also be employed with steam such that the
steam and carbon dioxide are injected either simultaneously or
sequentially, often followed by a soak period, followed by a
further injection of carbon dioxide or other fluids.
[0007] U.S. Pat. No. 2,623,596 describes enhanced recovery using
gases in an injection well with oil recovery from a separate
production well. Enhanced recovery using CO2 and N2 mixtures is
discussed with data presented showing oil recovery increasing
monotonically as CO2% in the gas mixture is increased. However, the
data presented does not demonstrate results when between 85% CO2
and 100% CO2, is employed.
[0008] U.S. Pat. No. 3,295,601 teaches that a slug of gas
consisting of carbon dioxide and hydrocarbon gases, preferably of
two to four carbon atoms, or nitrogen, air, hydrogen sulfide, flue
gases and similar gases in a gas mixture, when injected in a well,
establishes a transition zone. This transition zone is then driven
through the injection well by a driving fluid which will produce
oil from the stratum and reduce viscous fingering. The preferred
slug of gas consists of 50% carbon dioxide and a substantial
concentration of C.sub.2 to C.sub.4 hydrocarbon gases such as 10 to
50% by volume. It appears that the remainder of the gases in this
gas mixture are selected from the group consisting of nitrogen,
air, hydrogen sulfide and flue gases and similar gases would make
up the balance in the preferred composition of carbon dioxide and
C.sub.2 to C.sub.4 hydrocarbon gas.
[0009] US Pat. No. 5,725,054 teaches a method for recovering oil
from a subterranean formation by injecting into said well a gas
mixture which comprises carbon dioxide and a gas selected from the
group consisting of methane, nitrogen and mixtures thereof. The gas
mixture comprises about 5 to about 50% by volume of carbon dioxide.
As noted in the examples, the highest percentages were 50% by
volume carbon dioxide.
[0010] The present inventors have discovered that the use of carbon
dioxide in percentages greater than 50%, up to 99%, along with
nitrogen or another inert gas as the remainder of the gas mixture
will enhance oil production.
SUMMARY OF THE INVENTION
[0011] The present invention provides for a method for enhancing
the recovery of oil from an underground formation comprising
injecting into the oil a gas mixture comprising at least 50% by
volume of carbon dioxide and an inert gas. The present invention
further provides for a method for enhancing the recovery of oil
from an underground formation comprising injecting into the oil a
gas mixture comprising carbon dioxide and nitrogen wherein the
carbon dioxide is present in the gas mixture in an amount of at
least 50% by volume. In addition, the present invention will
provide for a method for lowering the viscosity and surface tension
as well as increasing the volume or swelling of the oil in an
underground formation comprising injecting into the oil a gas
mixture comprising at least 50% by volume carbon dioxide and an
inert gas.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 is a graphical representation of the effect of carbon
dioxide content of gas on paraffin oil viscosity.
[0013] FIG. 2 is a graphical representation of carbon dioxide
content of gas on naphthene oil viscosity.
[0014] FIG. 3 is a graphical representation of carbon dioxide
content of gas on aromatic oil viscosity.
[0015] FIG. 4 is a graphical representation of carbon dioxide
content of gas on paraffin oil surface tension.
[0016] FIG. 5 is a graphical representation of carbon dioxide
content of gas on naphthene oil surface tension. FIG. 6 is a
graphical representation of carbon dioxide content of gas on
aromatic oil surface tension.
[0017] FIG. 7 is a graphical representation of carbon dioxide
content of gas on paraffin oil viscosity at various
temperatures.
[0018] FIG. 8 is a graphical representation of carbon dioxide
content of gas on paraffin oil surface tension at various
temperatures.
[0019] FIG. 9 is a graphical representation of carbon dioxide
content of gas on paraffin oil volume at various temperatures.
DETAILED DESCRIPTION OF THE INVENTION
[0020] The present invention comprises a method for enhancing the
recovery of oil from an underground formation comprising injecting
into the oil a gas mixture comprising at least 50% by volume carbon
dioxide and an inert gas. The inert gas is preferably nitrogen.
Other inert gases such as helium and argon may also be employed.
The present invention also comprises a method for enhancing the
recovery of oil from an underground formation comprising injecting
into the oil a gas mixture which comprises carbon dioxide and
nitrogen. The carbon dioxide is present in the gas mixture in an
amount of at least 50% by volume. The introduction of a combination
of carbon dioxide and nitrogen gas to the formation provides an
unexpected advantage of lower oil viscosity and surface tension
than the introduction of carbon dioxide or nitrogen alone. This
will also provide greater oil swelling than the use of carbon
dioxide or nitrogen alone. The use of nitrogen adds an economic
advantage to the mixture as there is lower cost than that for pure
carbon dioxide consumption.
[0021] For purposes of the present invention, applicants define oil
as being a hydrocarbon which comprises paraffin, aromatic or
naphthene constituents or mixtures thereof.
[0022] The mixture of the carbon dioxide and nitrogen will be
injected into the formation containing the oil at a pressure of 100
pounds per square inch to 20,000 pounds per square inch depending
upon the depth of the oil reservoir. This injection method allows
for use of WAG (water alternating gas) well-to-well process whereby
an injection of gas is followed by a water flood to drive the oil
and enhance production at the well head. This injection method will
also work in a huff and puff process. In the huff and puff process,
the mixture would be injected into the formation. The formation
would then be sealed allowing a soak period of determinate length
of time, followed by an improved oil recovery or production
period.
[0023] The mixtures of carbon dioxide and nitrogen may be created
by any means. Preferably, a carbon dioxide-rich stream and a
nitrogen-rich stream are combined or a hydrocarbon is combusted
using air or oxygen-enriched air to produce the carbon dioxide. The
present inventors assert that in addition to nitrogen, other inert
gases, when combined with carbon dioxide in an optimum ratio, will
minimize oil viscosity and surface tension while increasing
swelling.
[0024] One means for producing the carbon dioxide-rich gas stream
involves the use of a power plant or co-generation plant at or near
the well site. Oxygen-enriched air and hydrocarbon are combusted to
generate power and carbon dioxide-rich gas. The power is used to
operate an air separation plant which provides the oxygen for the
oxygen enrichment of the power or co-generation plant. Additional
nitrogen and/or steam produced may also be used to enhance oil
recovery by placing these materials in an injection well either
individually or in combination with the carbon dioxide-rich gas
stream. The combination of heat and carbon dioxide can further
improve recovery and little carbon dioxide would be lost to the
aqueous phase as a result.
[0025] Another means for producing the carbon dioxide is by
injection of pure oxygen, oxygen-enriched air or air downhole. For
wells that are sufficiently deep enough, the temperature will be
sufficient to sustain combustion and produce carbon dioxide. For
example, a 8000 foot deep well may have a temperature of
300.degree. F. which is hot enough to produce the carbon dioxide
necessary for the enhanced oil recovery.
[0026] In a preferred embodiment of the present invention, a carbon
dioxide nitrogen mixture with carbon dioxide present greater than
50% by volume is injected into the formation at or near the
production well by optimizing the composition of the gas mixture.
Due to the varied rates in the uptake of carbon dioxide and
nitrogen, a near optimum composition can be maintained in the
formation at that injection location. A second mixture of carbon
dioxide and nitrogen would then be injected through injection
well(s) located at a distance from the production well. The
composition of this gas mixture would be such that the viscosity
and surface tension of the oil is higher than that of the oil near
or at the production well but still reduced in comparison to the
untreated oil. Gas may be fed continuously to the injection well(s)
or the well(s) can be shut for a period of at least a day to
facilitate the uptake of the gas by the oil.
[0027] Oil is driven to the production well and fingering or bypass
of the gas though the oil is minimized as a result. In this
preferred embodiment, more than one remote injection point may be
employed such that the viscosity and surface tension of the oil at
the remote injection point becomes higher with each injection point
further away from the well head injection point by optimizing the
content of the carbon dioxide and nitrogen gas mixture.
Accordingly, the nitrogen content of the gas mixture will increase
as one injects the mixture further from the production well. This
gradient will result in a raising of carbon dioxide content above
the 50% by volume as one injects at points getting sequentially
closer to the production well. In this embodiment, a later possibly
intermittent use of carbon dioxide flood, nitrogen flood or water
flood to drive the oil to the production well would further improve
yields.
[0028] A preferred composition for use in the methods of the
present invention is that of at least 50% by volume carbon dioxide,
the remainder being nitrogen or other inert gas including helium,
argon or steam. In a more preferred embodiment, greater than 60%
carbon dioxide by volume with the remainder being inert gases would
comprise the gaseous mixture. In the most preferred embodiment,
greater than 75% by volume of the gas mixture would be carbon
dioxide and the remainder being inert gases.
[0029] In an additional embodiment, hydrocarbons can be added to
the above described compositions. These hydrocarbons, such as
methane, ethane and propane can come from traditional sources but
may also come from the associated gas produced during oil
production. The hydrocarbons can be separated from oil and
reinjected into the ground or may be separated from oil and
reinjected into the ground after burning a portion of the
hydrocarbon in air, oxygen or oxygen enriched air.
EXAMPLES
[0030] Three model oils were studied to explore the potential of
mixtures of carbon dioxide and nitrogen for enhanced oil recovery.
A simulation was developed based on the Peng-Robinson equation of
state for vapor-liquid equilibrium, the Twu model for liquid phase
viscosity and a modified form of the Brock and Bird equation for
surface tension. The three oils employed in this study were of
paraffin, naphthene and aromatic types. A gas mixture of carbon
dioxide and nitrogen with a usage rate of 1 mole per mole of oil
was presumed and a small quantity of water was added to the mixture
since typically carbon dioxide flooding operations follow water
flood procedures or are conducted as in the WAG method
alternatively with water flood. The quantity of water was based on
20% saturation for a typical oil. Pressures in the range of 1,500
psia to 2,500 psia and temperatures in the range of 75.degree. F.
to 200.degree. F. were studied.
[0031] As shown in FIGS. 1, 2 and 3, and Tables 1, 2 and 3, the
relationship of a paraffin, naphthene and aromatic oil viscosity at
75.degree. F. to the percentage of carbon dioxide in the oil
recovery gas mixture is demonstrated. It can be seen that greater
than 50% carbon dioxide in the gas mixture is advantageous in
lowering the oil viscosity relative to the use of 100% carbon
1TABLE 1 Effect of CO2 Content of Gas on Paraffin Oil Viscosity at
Various Pressures and 75 F CO2 Oil Oil Oil content of viscosity at
viscosity at viscosity at gas 1500 psia 2000 psia 2500 psia (%)
(cP) (cP) (cP) 0 0.592 0.571 0.552 25 0.557 0.534 0.513 50 0.515
0.49 0.468 68 0.478 0.453 0.437 75 0.462 0.443 0.449 80 0.45 0.451
0.457 85 0.451 0.46 0.466 88 0.456 0.465 0.472 92 0.464 0.472 0.479
100 0.478 0.487 0.493
[0032]
2TABLE 2 Effect of C02 Content of Gas on Naphthene Oil Viscosity at
Various Pressures and 75 F CO2 Oil Oil Oil content of viscosity at
viscosity at viscosity at gas 1500 psia 2000 psia 2500 psia (%)
(cP) (cP) (cP) 0 1.93 1.87 1.82 25 1.69 1.62 1.57 50 1.44 1.38 1.32
68 1.26 1.19 1.14 75 1.18 1.12 1.07 80 1.12 1.06 1.02 85 1.06 1.01
0.997 88 1.02 0.993 1.01 92 0.986 1.01 1.02 100 1.02 1.04 1.05
[0033]
3TABLE 3 Effect of CO2 Content of Gas on Aromatic Oil Viscosity at
Various Pressures and 75 F CO2 Oil Oil Oil content of viscosity at
viscosity at viscosity at gas 1500 psia 2000 psia 2500 psia (%)
(cP) (cP) (cP) 0 0.827 0.811 0.797 25 0.7566 0.738 0.722 50 0.679
0.658 0.642 68 0.615 0.595 0.578 75 0.587 0.567 0.552 80 0.566
0.547 0.532 85 0.544 0.526 0.512 88 0.529 0.512 0.519 92 0.51 0.52
0.527 100 0.527 0.537 0.544
[0034] FIGS. 4, 5 and 6 and Tables 4, 5 and 6 show the relationship
of a paraffin, naphthene and aromatic oil surface tension at
75.degree. F. to the percentage carbon dioxide and the oil recovery
gas mixture for three different pressures. As can be seen in FIGS.
4, 5 and 6, greater than 60% carbon dioxide in the gas mixture is
advantageous in reducing surface tension in comparison to the use
of pure carbon dioxide.
4TABLE 4 Effect of CO2 Content of Gas on Paraffin Oil Surface
Tension at Various Pressures and 75 F CO2 Oil surface Oil surface
Oil surface content of tension at tension at tension at gas 1500
psia 2000 psia 2500 psia (%) (dyne/cm) (dyne/cm) (dyne/cm) 0 19.22
18.39 17.65 25 17.1 16.19 15.41 50 14.93 13.99 13.21 68 13.27 12.35
11.8 75 12.59 11.86 11.86 80 12.09 11.91 11.9 85 11.96 11.95 11.95
88 11.98 11.98 11.98 92 12.02 12.02 12.02 100 12.09 12.1 12.1
[0035]
5TABLE 5 Effect of CO2 Content of Gas on Naphthene Oil Surface
Tension at Various Pressures and 75 F CO2 Oil surface Oil surface
Oil surface content of tension at tension at tension at gas 1500
psia 2000 psia 2500 psia (%) (dyne/cm) (dyne/cm) (dyne/cm) 0 29.21
28.56 27.96 25 26.14 25.3 24.59 50 22.93 21.97 21.23 68 20.4 19.44
18.73 75 19.34 18.42 17.72 80 18.53 17.64 16.97 85 17.69 16.85
16.59 88 17.16 16.61 16.62 92 16.65 16.66 16.66 100 16.72 16.73
16.73
[0036]
6TABLE 6 Effect of CO2 Content of Gas on Aromatic Oil Surface
Tension at Various Pressures and 75 F CO2 Oil surface Oil surface
Oil surface content of tension at tension at tension at gas 1500
psia 2000 psia 2500 psia (%) (dyne/cm) (dyne/cm) (dyne/cm) 0 29.84
29.29 28.79 25 26.71 25.96 25.33 50 23.41 22.53 21.87 68 20.81
19.94 19.28 75 19.73 18.87 18.25 80 18.92 18.08 17.48 85 18.06
17.28 16.72 88 17.52 16.77 16.76 92 16.8 16.8 16.8 100 16.86 16.86
16.86
[0037] FIGS. 7 and 8 and Tables 7 and 8 show the relationship of a
paraffin oil viscosity and surface tension at various temperatures
to the percentage carbon dioxide and the oil recovery gas mixture.
As demonstrated in the earlier examples, greater than 50% carbon
dioxide in the gas mixture is advantageous in comparison to the use
of pure carbon dioxide. Oil viscosity is greatly reduced at around
70 to 80% carbon dioxide while surface tension remains
approximately constant at the higher carbon dioxide
concentrations.
7TABLE 7 Effect of CO2 Content of Gas on Paraffin Oil Viscosity at
Various Temperatures and 2000 psia CO2 Oil Oil Oil Oil Oil content
viscosity viscosity viscosity viscosity viscosity of gas at 75 F.
at 100 F. at 125 F. at 150 F. at 200 F. (%) (cP) (cP) (cP) (cP)
(cP) 0 0.571 0.486 0.419 0.365 0.282 50 0.49 0.429 0.375 0.329
0.257 75 0.443 0.387 0.341 0.301 0.235 80 0.451 0.394 0.342 0.298
0.229 85 0.46 0.402 0.348 0.304 0.23 88 0.465 0.407 0.352 0.307
0.233 92 0.472 0.413 0.358 0.312 0.237 100 0.487 0.426 0.369 0.321
0.244
[0038]
8TABLE 8 Effect of CO2 Content of Gas on Paraffin Oil Surface
Tension at Various Temperatures and 2000 psia Oil Oil Oil Oil Oil
CO2 surface surface surface surface surface content tension tension
tension tension tension of gas at 75 F. at 100 F. at 125 F. at 150
F. at 200 F. (%) (dyne/cm) (dyne/cm) (dyne/cm) (dyne/cm) (dyne/cm)
0 18.39 17.3 16.21 15.13 13 50 13.99 12.91 12.29 11.63 10.26 75
11.86 10.53 10.06 9.582 8.574 80 11.91 10.52 9.887 9.265 8.167 85
11.95 10.52 9.888 9.266 8.044 88 11.98 10.52 9.887 9.266 8.046 92
12.02 10.52 9.888 9.266 8.044 100 12.1 10.52 9.887 9.265 8.045
[0039] FIG. 9 and Table 9 show the relationship of a paraffin oil
relative volume at various temperatures as to the percentage carbon
dioxide in the oil recovery gas mixture. The relative volume is
taken in comparison to a standard oil volume. Roughly 70% to 99%
carbon dioxide in the gas mixture is advantageous in comparison to
the use of pure carbon dioxide to maximize swelling in this case.
As swelling of the oil increases, the oil will exit small pores
within the subterranean formation and can be swept or driven to the
production well by use of the various flood techniques.
9TABLE 9 Effect of CO2 Content of Gas on Paraffin Oil Relative
Volume at Various Temperatures and 2000 psia* CO2 Oil Oil Oil Oil
Oil content relative relative relative relative relative of gas
volume volume volume volume volume (%) at 75 F. at 100 F. at 125 F.
at 150 F. at 200 F. 0 1.036 1.053 1.071 1.090 1.131 50 1.118 1.135
1.154 1.176 1.235 75 1.193 1.222 1.244 1.27 1.353 80 1.188 1.217
1.249 1.287 1.392 85 1.183 1.211 1.243 1.280 1.398 88 1.179 1.207
1.239 1.276 1.391 92 1.175 1.203 1.234 1.271 1.383 100 1.167 1.194
1.224. 1.261 1.366 *Relative volume is in comparison to a standard
oil volume
[0040] While this invention has been described with respect to
particular embodiments thereof, it is apparent that numerous other
forms and modifications of the invention will be obvious to those
skilled in the art. The appended claims of this invention generally
should be construed to cover all such obvious forms and
modifications which are within the true spirit and scope of the
present invention.
* * * * *