THICKENED CO2 IN GRAVITY DRAINAGE GAS INJECTION PROCESSES

Abstract

A method and a system for oil recovery are provided. An exemplary method includes injecting thickened carbon dioxide (CO.sub.2) into the top of a reservoir containing oil. An interface is formed between the thickened CO.sub.2 and the oil. The oil is mobilized by the thickened CO.sub.2. The mobilized oil is recovered with a recovery well drilled below the reservoir.

Claims

1. A method for oil recovery, comprising: injecting thickened CO.sub.2 into the top of a reservoir containing oil, wherein the thickened CO.sub.2 comprises a copolymer of allenether, acrylate, acrylic long carbon chain ester, acrylic long carbon chain benzene, propylene carbonate ethyl carbonate, propylene allyl ethyl carbonate, dimethyl carbonate, white oil, silicon, petroleum ether, or a combination thereof; forming an interface between the thickened CO.sub.2 and the oil; mobilizing the oil; and recovering the oil with a recovery well drilled below the reservoir.

2. (canceled)

3. The method of claim 2, wherein the thickener has a molecular weight of 500,000 g/mol, a pH of 5.0 to 8.0, a relative density of 0.90 to 1.10, a dissolution speed of less than about three minutes for one percent in liquid CO.sub.2 at 25° C., or a combination thereof.

4. The method of claim 1, wherein about 0.1 to 0.2 pore volumes of thickened CO.sub.2 is injected into the reservoir.

5. The method of claim 1, wherein the thickened CO.sub.2 comprises 2 vol. % thickener and 98 vol. % supercritical CO.sub.2.

6. The method of claim 1, wherein the interface is positioned at the top of a pay zone comprising high-permeable channels.

7. The method of claim 6, wherein the thickened CO.sub.2 blocks the high-permeable channels.

8. The method of claim 1, wherein the thickened CO.sub.2 is injected so that it is uniform across the interface.

9. The method of claim 1, wherein the thickened CO.sub.2 is injected at or below the critical gas injection rate.

10. The method of claim 1, wherein the thickened CO.sub.2 is continuously injected.

11. The method of claim 1, wherein the thickened CO.sub.2 is injected using a vertical injection well.

12. The method of claim 1, wherein the thickened CO.sub.2 is injected using a horizontal injection well.

13. The method of claim 1, wherein the recovery well is a horizontal recovery well.

14. The method of claim 1, wherein the recovery well is a vertical recovery well.

15. The method of claim 1, wherein the reservoir pressure is below ambient pressure.

16. The method of claim 1, wherein the oil is recovered using forced gravity drainage and free gravity drainage.

17. The method of claim 1, wherein the oil is mobilized with unthickened CO.sub.2 injected into the top of the reservoir.

18. A system for oil recovery, comprising: an injection well; a reservoir containing oil positioned below the injection well; thickened CO.sub.2, wherein the thickened CO.sub.2 comprises a copolymer of allenether, acrylate, acrylic long carbon chain ester, acrylic long carbon chain benzene, propylene carbonate ethyl carbonate, propylene allyl ethyl carbonate, dimethyl carbonate, white oil, silicon, petroleum ether, or a combination thereof; an interface between the thickened CO.sub.2 and the oil; and a recovery well drilled below the reservoir.

19. (canceled)

20. The system of claim 18, wherein the thickener has a molecular weight of 500,000 g/mol, a pH of 5.0 to 8.0, a relative density of 0.90 to 1.10, a dissolution speed of less than about three minutes for one percent in liquid CO.sub.2 at 25° C., or a combination thereof.

21. The system of claim 18, wherein the reservoir comprises about 0.1 to 0.2 pore volumes of thickened CO.sub.2.

22. The system of claim 18, wherein the thickened CO.sub.2 comprises 2 vol. % thickener and 98 vol. % supercritical CO.sub.2.

23. The system of claim 18, further comprising a pay zone positioned below the interface, wherein the pay zone comprises high-permeable channels.

24. The system of claim 23, wherein the thickened CO.sub.2 blocks the high-permeable channels.

25. The system of claim 18, wherein the thickened CO.sub.2 is uniform across the interface.

26. The system of claim 18, wherein the injection well is a vertical injection well.

27. The system of claim 18, wherein the injection well is a horizontal injection well.

28. The system of claim 18, wherein the recovery well is a horizontal recovery well.

29. The system of claim 18, wherein the recovery well is a vertical recovery well.

30. The system of claim 18, wherein the reservoir pressure is below ambient pressure.

Description

BRIEF DESCRIPTION OF DRAWINGS

[0007] FIG. 1 is a schematic diagram of an example system for using thickened CO.sub.2 in a gravity drainage gas injection process.

[0008] FIG. 2 is a schematic diagram of an example system where thickened CO.sub.2 blocks high-permeable channels.

[0009] FIG. 3 is a schematic diagram of an example system where thickened CO.sub.2 causes uniform sweep across a pay zone.

[0010] FIG. 4 is a flow chart of an example method for using thickened CO.sub.2 in a gravity drainage gas injection process.

[0011] FIG. 5 shows CO.sub.2 viscosities at 2000 psi after being mixed with different amounts of an example thickener.

[0012] FIG. 6 shows CO.sub.2 viscosities at 2500 psi after being mixed with different amounts of an example thickener.

[0013] FIG. 7 is a schematic diagram of the device used to measure the data shown in FIGS. 5 and 6.

[0014] FIG. 8 shows the results of an experiment showing the pressure drop across a rock sample during water injection for pre-thickened-CO.sub.2 and post-thickened-C.sub.2 treatments.

DETAILED DESCRIPTION

[0015] Gravity drainage gas injection processes involve injecting a gas, such as CO.sub.2, into a reservoir to mobilize oil in the reservoir, allowing the oil to be recovered. Gravity drainage gas injection is typically used as an EOR process. Most gravity drainage gas injection processes have a slow response, meaning that it takes a relatively longer time after injecting the displacing fluids to see the impact on the oil recovery, and low oil recovery rates. The slow response and the low oil recovery rates increase the amount of injection gas required to recover oil. These limitations have rendered gravity drainage gas injection processes, including processes using CO.sub.2, unattractive for field practice and not economically feasible.

[0016] Gravity drainage gas injection processes are limited because of low gas injection rates used. Low gas injection rates have been required to meet the so-called “critical gas injection rate” criterion. The critical gas injection rate is the highest-allowable gas injection rate in a gravity drainage gas injection process that can maintain a balanced gas front by relying on gravitational stability while lowering the viscous force with the reduced rate of injection.

[0017] The critical gas injection rate is one of the most important operational parameters for gravity drainage gas injection processes because it defines the stability of the growing gas-oil interface that steadily moves towards the recovery well. The critical gas injection rate defines the upper limit that the injection rate in a gravity drainage gas injection process should not exceed. If the gas injection rate exceeds the critical gas injection rate, the gas front destabilizes, resulting in premature gas breakthrough and gas short-circuiting in the recovery well. To avoid this issue, oil production is maintained at slow rates in the recovery wells such that the oil production rate is balanced by the equivalent CO.sub.2 injection volume. The interface between the advancing injection gas and the recovered oil must be precisely controlled to stabilize gravitational forces and result in stable movement of gas-oil interface downward with the controlled production withdrawal rate.

[0018] Critical gas injection rates are typically low, rendering gravity drainage gas injection process impractical. Gas thickeners may be used to increase critical gas injection rates. But despite many years of research, the industry has not found a thickener that is inexpensive, environmentally-friendly, and effective—such as a thickener that can dissolve in dense CO.sub.2 at diluted concentrations and decrease the mobility of the CO.sub.2 to a level comparable to that of oil. A major obstacle hindering these efforts has been the limited solubility of proposed thickeners in CO.sub.2, which restricts their ability to increase the CO.sub.2 viscosity and the critical gas injection rate. Prior proposed solutions also involve costly materials and materials with environmental concerns (such as those associated with fluorinated thickeners), which have prevented their use in the oilfield.

[0019] The subject matter described in this specification can be implemented in particular implementations, to realize one or more of the following advantages. The subject matter seeks to resolve the above issues by implementing thickened CO.sub.2 to replace prior recovery methods. In some embodiments, the techniques are used to enhance production from oil sands or other unconsolidated reservoirs. The thickened CO.sub.2 increases the response and recovery rate of gas-drainage processes by increasing the critical gas injection rate. The increased critical gas injection rate allows for the use of higher gas injection rates. This results in increased response due to the combined effects of forced gravity drainage with free gravity drainage. Further, this allows higher oil production recovery rates, thereby increasing ultimate oil recovery in recovery wells. The higher oil recovery rates reduce the CO.sub.2 gas utilization per barrel of oil recovered.

[0020] In addition, CO.sub.2is known to be a major contributor to the greenhouse effect and global warming. In some embodiments, environmental effects of using CO.sub.2 are mitigated because it can be injected into subsurface rocks helping to reduce the amount of CO.sub.2 in the atmosphere. Further, similar to waterless fracking operations, using thickened C.sub.2 instead of water-based chemicals, such as foams, helps minimize water consumption.

[0021] FIG. 1 is a schematic diagram of an example system for using thickened CO.sub.2 in a gravity drainage gas injection process. FIG. 1 includes injection wells 100, a reservoir containing oil 102 positioned below the injection wells 100, thickened CO.sub.2 104, an interface 106 between the thickened CO.sub.2 and the oil, and a recovery well 108 drilled below the reservoir.

[0022] FIG. 1 further shows the interface 106 positioned at the top of a pay zone. The pay zone includes high-permeable channels 112. The injection wells 100 inject the thickened CO.sub.2 104 to create the interface 106.

[0023] FIG. 2 is a schematic diagram of an example system. Thickened CO.sub.2 200 is injected into a reservoir 202 by injection wells 204. The thickened CO.sub.2 200 blocks high-permeable channels 206 in a pay zone 208. This reduces the relative permeability of the gas and increases the critical gas injection rate. Therefore, the thickened CO.sub.2 200 can be injected at higher gas injection rates to form the interface 210 quickly at the top of the pay zone 208. After thickened CO.sub.2 200 is injected, the oil 212 is mobilized with unthickened CO.sub.2 and driven towards a recovery well 214 to be drained.

[0024] In some implementations, the thickener for the CO.sub.2 is a mixture of different compounds including copolymer of allenethers, acrylate, acrylic long carbon chain esters/benzenes, propylene carbonate/allyl ethyl carbonate, dimethyl carbonate, and white oil/silicon or oil/petroleum ether.

[0025] FIG. 3 is a schematic diagram of an example system. As thickened CO.sub.2 300 is injected by injection wells 302, it creates an expanded gas chamber 304 in the reservoir 306. The blockage of high-permeable channels 208, as shown in FIG. 2, equalizes the resistances in different pathways and creates a more uniform sweep at the interface 308, increasing sweep efficiency. The interface 308 will expand with time and the forced gravity drainage will supplement the free gravity drainage and increase the oil drainage rate. After thickened CO.sub.2 300 is injected, the oil 310 is mobilized with unthickened CO.sub.2 and driven towards a recovery well 312 to be drained.

[0026] In an embodiment, the thickened CO.sub.2 is injected at an amount of 0.1 to 0.2 pore volumes. Pore volume is the volume within a certain number of injectors and producers and is used herein to mean the pore volume of the target zone and not of the entire reservoir. Further, thickened CO.sub.2 is injected by a vertical injection well. In some embodiments, thickened CO.sub.2 is injected by any other type of injection wells, such as a horizontal injection well. Additionally, oil is recovered with a horizontal recovery well. Oil is alternatively recovered by any other type of recovery well, such as a vertical recovery well.

[0027] FIG. 4 is a flow chart of an example method for using thickened CO.sub.2 in a gravity drainage gas injection process. At block 402, thickened CO.sub.2 is injected into the top of a reservoir containing oil. At block 404, an interface is formed between the thickened CO.sub.2 and the oil. At block 406, the oil is then mobilized. At block 408, the oil is recovered with a recovery well drilled below the reservoir 408.

EXAMPLES

Example 1

[0028] Preparing Thickened CO.sub.2

TABLE-US-00001 TABLE 1 Thickener Property Value Molecular Weight 500,000 g/mol pH 5.0-8.0 Appearance White emulsion Relative Density 0.90-1.10 Solubility Soluble in liquid and supercritical CO.sub.2 Dissolution speed of 1% of the ≤3 minutes chemical in liquid CO2 at 25° C.

[0029] Table 1 shows properties of the thickener used in the present tests of the techniques. CO.sub.2 gas with 99.50% purity was used to determine the thickener properties shown in Table 1. The thickener described is available commercially as a dry-fracturing fluid friction reducer and thickener under the name APFR-2 by manufacturer Beijing AP Polymer Technology CO., LTD. The thickener is 50 vol. % of allenether, acrylate, acrylic long carbon chain ester, acrylic long, and carbon chain benzene and 50 vol. % propylene carbonate ethyl carbonate, propylene allyl ethyl carbonate, dimethyl carbonate, white oil, silicon, and petroleum ether. Table 1 shows that the thickener has a molecular weight of 500,000 g/mol, a pH of 5.0 to 8.0, a relative density of 0.90 to 1.10, and a dissolution speed of less than about three minutes for one percent in liquid CO.sub.2 at 25° C. The thickener is able to dissolve in CO.sub.2 at conditions similar to those of oil fields.

[0030] FIG. 5 is a graph of CO.sub.2 viscosities at 2000 psi after being mixed with different amounts of the thickener. FIG. 6 is a graph of CO.sub.2 viscosities at 2500 psi after being mixed with different amounts of the thickener. A Cambridge HTHP viscometer apparatus, as shown in the schematic of FIG. 7, was used to conduct the viscosity measurements using different concentrations of the thickener and at different pressures. The objective of the tests shown in FIGS. 5 and 6 was to measure liquid and supercritical CO.sub.2 viscosity at different conditions when the thickener is added to the dense CO.sub.2. FIGS. 5 and 6 show that the addition of the thickener to the CO.sub.2 enhances the CO.sub.2 viscosity significantly. As seen, CO.sub.2 viscosity increases between about 1100 and 1250 times as a result of adding the thickener.

Example 2

[0031] Injecting Thickened CO.sub.2 Into a Rock Sample

TABLE-US-00002 TABLE 2 Permeability Permeability After a Pore Before Volume of 2 Thickened Thickened CO.sub.2 CO.sub.2 Injection Length Diameter Porosity Injected Injected rate Pressure Rock Inches Inches % mD mD ml/min Psi Indiana 4 1.5 18 58.9 1.3 5 2000 Limestone

[0032] Table 2 shows Indiana limestone properties and experimental conditions. Thickened CO.sub.2 in the amount of a pore volume of 2 was injected into the Indiana limestone sample. The thickened CO.sub.2 was a mixture of 2 vol. % of the thickener and 98 vol. % supercritical CO.sub.2. The thickened CO.sub.2 reduced the permeability of the rock from 58.9 mD (at 0 pore volumes thickened CO.sub.2) to 1.3 mD (at 2 pore volumes thickened CO.sub.2). This is about a 45 times reduction.

[0033] FIG. 8 shows the results of an experiment showing the pressure drop across the Indiana limestone sample of Table 2 during water injection for pre-thickened-CO.sub.2 and post-thickened-CO.sub.2 treatments. First, the Indiana limestone was injected with water in the amount of two pore volumes. The water injection was a baseline test used for a comparison purpose to model the initial state of the reservoir. The water injected was seawater similar to that used in the fields. As seen, the pressure drop across the Indiana limestone sample was negligible.

[0034] Next, thickened CO.sub.2 in the amount of two pore volumes was injected into the Indiana limestone. This caused a pressure drop of over 350 psi.

[0035] The Indiana limestone was then injected with a second sample of water in the amount of over five pore volumes. This caused an additional pressure drop of close to 100 psi. The increase in the pressure drop during the second water injection reflects the resistance caused by the presence of thickened CO.sub.2 in the porous media. After treating the formation with thickened CO.sub.2, which blocks the high-permeable channels, the second injected water follows paths in the low-permeable channels.

[0036] FIG. 8 shows the efficiency of the thickened CO.sub.2 to block the high-permeable channels and therefore reduce the mobility of the injected fluids. The results showed that even after injecting a few pore volumes (less than 0.5 pore volume), the pressure drop increased, which indicates the efficiency of the thickened CO.sub.2.

[0037] Described implementations of the subject matter can include one or more features, alone or in combination. For example, an implementation is a method that includes the following steps. Injecting thickened CO.sub.2 into the top of a reservoir containing oil; forming an interface between the thickened CO.sub.2 and the oil; mobilizing the oil; and recovering the oil with a recovery well drilled below the reservoir.

[0038] The foregoing and other described implementations can each, optionally, include one or more of the following features:

[0039] The thickened CO.sub.2 includes CO.sub.2 and thickener including a copolymer of allenether, acrylate, acrylic long carbon chain ester, acrylic long carbon chain benzene, propylene carbonate ethyl carbonate, propylene allyl ethyl carbonate, dimethyl carbonate, white oil, silicon, petroleum ether, or a combination thereof.

[0040] The thickener has a molecular weight of 500,000 g/mol, a pH of 5.0 to 8.0, a relative density of 0.90 to 1.10, a dissolution speed of less than about three minutes for one percent in liquid CO.sub.2 at 25° C., or a combination thereof

[0041] About 0.1 to 0.2 pore volumes of thickened CO.sub.2 is injected into the reservoir.

[0042] The thickened CO.sub.2 comprises 2 vol. % thickener and 98 vol. % supercritical CO.sub.2.

[0043] The interface is positioned at the top of a pay zone comprising high-permeable channels.

[0044] The thickened CO.sub.2 blocks the high-permeable channels.

[0045] The thickened CO.sub.2 is injected so that it is uniform across the interface.

[0046] The thickened CO.sub.2 is injected at or below the critical gas injection rate.

[0047] The thickened CO.sub.2 is continuously injected.

[0048] The thickened CO.sub.2 is injected using a vertical injection well.

[0049] The thickened CO.sub.2 is injected using a horizontal injection well.

[0050] The recovery well is a horizontal recovery well.

[0051] The recovery well is a vertical recovery well.

[0052] The reservoir pressure is below ambient pressure.

[0053] The oil is recovered using forced gravity drainage and free gravity drainage.

[0054] The oil is mobilized with unthickened CO.sub.2 injected into the top of the reservoir.

[0055] A second implementation is a system that includes an injection well; a reservoir containing oil positioned below the injection well; thickened CO.sub.2; an interface between the thickened CO.sub.2 and the oil; and a recovery well drilled below the reservoir.

[0056] The foregoing and other described implementations can each, optionally, include one or more of the following features:

[0057] The thickened CO.sub.2 comprises CO.sub.2 and thickener comprising a copolymer of allenether, acrylate, acrylic long carbon chain ester, acrylic long carbon chain benzene, propylene carbonate ethyl carbonate, propylene allyl ethyl carbonate, dimethyl carbonate, white oil, silicon, petroleum ether, or a combination thereof.

[0058] The thickener has a molecular weight of 500,000 g/mol, a pH of 5.0 to 8.0, a relative density of 0.90 to 1.10, a dissolution speed of less than about three minutes for one percent in liquid CO.sub.2 at 25° C., or a combination thereof

[0059] The reservoir comprises about 0.1 to 0.2 pore volumes of thickened CO.sub.2.

[0060] The thickened CO.sub.2 comprises 2 vol. % thickener and 98 vol. % supercritical CO.sub.2.

[0061] The system has a pay zone positioned below the interface, and the pay zone has high-permeable channels.

[0062] The thickened CO.sub.2 blocks the high-permeable channels.

[0063] The thickened CO.sub.2 is uniform across the interface.

[0064] The injection well is a vertical injection well.

[0065] The injection well is a horizontal injection well.

[0066] The recovery well is a horizontal recovery well.

[0067] The recovery well is a vertical recovery well.

[0068] The reservoir pressure is below ambient pressure.

[0069] Thus, particular implementations of the subject matter have been described. Other implementations are within the scope of the following claims.