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[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 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
[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.
[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.
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[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° 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.
[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° F. to 200° F. were studied.
[0031] As shown in TABLE 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]
TABLE 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]
TABLE 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] TABLE 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]
TABLE 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]
TABLE 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] TABLE 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]
TABLE 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] TABLE 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
[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.