[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.
[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 waterflood.
[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] US-A-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] US-A-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
2 to C
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
2 to C
4 hydrocarbon gas.
[0009] US-A-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 gas, preferably an inert
gas as the remainder of the gas mixture will enhance oil production.
[0011] The present invention provides 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. In addition, the present invention provides
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.
[0012] The gas mixture preferably includes 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.
[0013] For purposes of the present invention, oil is defined as being a hydrocarbon which
comprises paraffin, aromatic or naphthene constituents or mixtures thereof.
[0014] 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 a WAG (water alternating gas) well-to-well process whereby an injection
of gas is followed by a waterflood 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.
[0015] 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. Other
inert gases, when combined with carbon dioxide in an optimum ratio, are believed to
minimize oil viscosity and surface tension while increasing swelling.
[0016] 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.
[0017] 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°F which is hot enough to produce
the carbon dioxide necessary for the enhanced oil recovery.
[0018] 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.
[0019] 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.
[0020] 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 one or more 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.
[0021] 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.
[0022] The method according to the invention will now be described by way of example with
reference to the accompanying drawings in which Figure 1 is a graphical representation
of the effect of carbon dioxide content of gas on paraffin oil viscosity.
[0023] Figure 2 is a graphical representation of carbon dioxide content of gas on naphthene
oil viscosity.
[0024] Figure 3 is a graphical representation of carbon dioxide content of gas on aromatic
oil viscosity.
[0025] Figure 4 is a graphical representation of carbon dioxide content of gas on paraffin
oil surface tension.
[0026] Figure 5 is a graphical representation of carbon dioxide content of gas on naphthene
oil surface tension.
[0027] Figure 6 is a graphical representation of carbon dioxide content of gas on aromatic
oil surface tension.
[0028] Figure 7 is a graphical representation of carbon dioxide content of gas on paraffin
oil viscosity at various temperatures.
[0029] Figure 8 is a graphical representation of carbon dioxide content of gas on paraffin
oil surface tension at various temperatures.
[0030] Figure 9 is a graphical representation of carbon dioxide content of gas on paraffin
oil volume at various temperatures.
[0031] 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 waterflood. 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°F to 200°F were studied.
[0032] As shown in Figures 1, 2 and 3, and Tables 1, 2 and 3, the relationship of a paraffin,
naphthene and aromatic oil viscosity at 75°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 dioxide.
Table 1:
Effect of CO2 Content of Gas on Paraffin Oil Viscosity at Various Pressures and 75
F |
CO2 content of gas (%) |
Oil viscosity at 1500 psia (cP) |
Oil viscosity at 2000 psia (cP) |
Oil viscosity at 2500 psia (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 |
Table 2:
Effect of CO2 Content of Gas on Naphthene Oil Viscosity at Various Pressures and 75
F |
CO2 content of gas (%) |
Oil viscosity at 1500 psia (cP) |
Oil viscosity at 2000 psia (cP) |
Oil viscosity at 2500 psia (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 |
Table 3:
Effect of CO2 Content of Gas on Aromatic Oil Viscosity at Various Pressures and 75
F |
CO2 content of gas (%) |
Oil viscosity at 1500 psia (cP) |
Oil viscosity at 2000 psia (cP) |
Oil viscosity at 2500 psia (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 |
[0033] Figures 4, 5 and 6 and Tables 4, 5 and 6 show the relationship of a paraffin, naphthene
and aromatic oil surface tension at 75°F to the percentage carbon dioxide and the
oil recovery gas mixture for three different pressures. As can be seen in Figures
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.
Table 4:
Effect of CO2 Content of Gas on Paraffin Oil Surface Tension at Various Pressures
and 75 F |
CO2 content of gas (%) |
Oil surface tension at 1500 psia (dyne/cm) |
Oil surface tension at 2000 psia (dyne/cm) |
Oil surface tension at 2500 psia (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 |
Table 5:
Effect of CO2 Content of Gas on Naphthene Oil Surface Tension at Various Pressures
and 75 F |
CO2 content of gas (%) |
Oil surface tension at 1500 psia (dyne/cm) |
Oil surface tension at 2000 psia (dyne/cm) |
Oil surface tension at 2500 psia (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 |
Table 6:
Effect of CO2 Content of Gas on Aromatic Oil Surface Tension at Various Pressures
and 75 F |
CO2 content of gas (%) |
Oil surface tension at 1500 psia (dyne/cm) |
Oil surface tension at 2000 psia (dyne/cm) |
Oil surface tension at 2500 psia (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 |
[0034] Figures 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.
Table 7:
Effect of CO2 Content of Gas on Paraffin Oil Viscosity at Various Temperatures and
2000 psia |
CO2 content of gas (%) |
Oil viscosity at 75 F (cP) |
Oil viscosity at 100 F (cP) |
Oil viscosity at 125 F (cP) |
Oil viscosity at 150 F (cP) |
Oil viscosity at 200 F (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 |
Table 8:
Effect of CO2 Content of Gas on Paraffin Oil Surface Tension at Various Temperatures
and 2000 psia |
CO2 content of gas (%) |
Oil surface tension at 75 F (dyne/cm) |
Oil surface tension at 100 F (dyne/cm) |
Oil surface tension at 125 F (dyne/cm) |
Oil surface tension at 150 F (dyne/cm) |
Oil surface tension at 200 F (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 |
[0035] Figure 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.
Table 9:
Effect of CO2 Content of Gas on Paraffin Oil Relative Volume at Various Temperatures
and 2000 psia* |
CO2 content of gas (%) |
Oil relative volume at 75 F |
Oil relative volume at 100 F |
Oil relative volume at 125 F |
Oil relative volume at 150 F |
Oil relative volume 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 |
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. A method according to claim 1, wherein the remainder of said gas mixture additionally
includes one or more of the following: at least one inert gas; at least one hydrocarbon;
steam; and air.
3. A method according to claim 2, wherein the inert gas is one or more of the following:
nitrogen, helium, and argon.
4. A method according to any one of the preceding claims, wherein said gas mixture is
injected into said oil at the well head.
5. A method according to claim 4, wherein said gas mixture is injected into a single
production well head.
6. A method according to claim 5, wherein said injection is cyclical.
7. A method according to any one of the preceding claims, wherein said gas mixture is
injected into an injection well other than a production well head.
8. A method according to claim 7, wherein said gas mixture is injected in an alternating
pattern with a driving fluid.
9. A method according to claim 8, wherein said driving fluid is selected from the group
consisting of steam, water, nitrogen, carbon dioxide and air.
10. A method according to any one of the preceding claims, wherein said gas mixture is
injected into said oil at a pressure ranging from about 100 psi to about 20,000 psi.
11. A method according to any one of the preceding claims, wherein after injection of
said gas mixture said underground formation is sealed for at least one day.
12. A method according to claim 11, 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.
13. A method according to claim 12, wherein said gas mixture is injected into said underground
formation in at least two distinct injection points 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.
14. A method according to any one of the preceding claims, wherein said gas mixture further
reduces the viscosity and the surface tension of said oil in said underground formation.
15. A method according to any one of the preceding claims, wherein the gas mixture contains
at least 70% by volume of carbon dioxide.