Patent Description:
The present disclosure generally relates to production of hydrocarbons from hydrocarbon bearing subterranean formations, and more specifically, methods for enhancing oil recovery from hydrocarbon bearing subterranean formations using dense carbon dioxide compositions.

In subterranean resource well drilling, primary oil recovery methods contribute to recovery of only about <NUM>% of the crude oil in the reservoir. Secondary recovery methods, such as water flooding, can produce an additional <NUM>% or more of the original oil in place (OOIP) in the reservoir. During a water flooding recovery process, an injection fluid is injected into the subterranean formation from an injection well that is spaced apart from the production well. The injected water displaces hydrocarbons contained in the subterranean formation and drives these hydrocarbons towards the production well to increase the production of these hydrocarbons from the subterranean formation. One of the main problems associated with this recovery mechanism is the channeling of the injection fluid through high permeability zones. Channeling of the injection fluid through high permeability zones can cause regions of the formation and large amounts of hydrocarbons to be bypassed, which results in a poor sweep efficiency.

At the production well, management of large amounts of produced water is a major challenge facing the oil industry that can cause operational difficulties if left unchecked. These operational difficulties include corrosion of pipes, migration of fines to the production well, and acceleration of well abandonment. It is estimated that water comprises about <NUM>% of the total liquid production from oil production wells, which leads to more than $<NUM> billion that is spent annually to process this large water volume. Water production can be caused by high permeability zones in the subterranean formation. In particular, high permeability zones in the formation can convey connate water from water zones in the formation or can provide a pathway for breakthrough of aqueous injection fluids from water flooding enhanced oil recovery processes at the production well.

The publication <NPL> discloses a method for enhanced oil recovery from a hydrocarbon bearing subterranean formation, the method comprising:.

In the oil and gas industry, there is an ongoing need for compositions and methods for treating high permeability zones in subterranean formations. In particular, there is an ongoing need for compositions and methods for enhancing oil recovery from hydrocarbon bearing subterranean formations by treating high permeability zones from an injection well to improve water flooding sweep efficiency and increase hydrocarbon production. Additionally, there is an ongoing need for compositions and methods for reducing water production from hydrocarbon bearing subterranean formations by blocking high permeability zones from the production well.

Dense carbon dioxide (CO<NUM>) can be used in place of aqueous treatment fluids as a main blocking agent for treating high permeability zones to modify the injection profile during a water flooding process or to reduce or prevent water production from high permeability zones at the production well. Dense carbon dioxide refers to carbon dioxide having increased density as a result of being at a temperature and pressure that causes the carbon dioxide to be in the liquid or supercritical phase. However, dense carbon dioxide alone may not have sufficient viscosity to effectively block high permeability zones or to resist displacement from flow of other formation fluids or treatment fluids, which may result in breakthrough of the carbon dioxide at the production well.

The present disclosure relates to methods of treating high permeability zones by injecting dense carbon dioxide compositions that include dense carbon dioxide and a thickener. The thickener is an environmentally friendly CO<NUM> thickener that is readily soluble in dense CO<NUM> and capable of increasing the viscosity of the dense CO<NUM> by several orders of magnitude at the typical injections conditions of the subterranean formations. Once injected, the dense CO<NUM> compositions with the increased viscosity blocks the pores, fractures, or both of the high permeability zones to reduce or prevent passage of other fluids, such as aqueous treatment fluids or water, through the high permeability zone. The present disclosure relates to methods for enhanced oil recovery to improve recovery of hydrocarbons, such as crude oil, from hydrocarbon bearing subterranean formations that include injecting the dense CO<NUM> compositions into the high permeability zone from an injection well and then conducting a water flooding process while collecting hydrocarbons from the production well. The present disclosure also relates to methods for reducing water production at the production well by injecting the dense CO<NUM> compositions into high permeability zones from the production well. The methods of the present disclosure may enhance the recovery of hydrocarbons, reduce production of produced water from the subterranean formation, or both while at the same time providing a beneficial subterranean use for CO<NUM> to help reduce CO<NUM> in the atmosphere. The use of dense CO<NUM> instead of water may also help reduce water usage and, hence, improve natural water resource preservation.

According to one or more aspects of the present disclosure, a method for enhanced oil recovery from a hydrocarbon bearing subterranean formation may include withdrawing hydrocarbons from a production well extending into the hydrocarbon bearing subterranean formation, identifying a high permeability streak in the hydrocarbon bearing subterranean formation, and injecting a dense carbon dioxide composition from an injection well into the high permeability streak of the hydrocarbon bearing subterranean formation. The dense carbon dioxide composition comprises dense carbon dioxide and a thickener soluble in the dense carbon dioxide. The thickener may comprise a copolymer. The copolymer may be the polymerized reaction product of monomers that include at least one alkenyl ether or dialkenyl ether monomer, at least one acrylate or methacrylate monomer, at least one structural monomer, and at least one allyl ester monomer. The method may further include, after injecting the dense carbon dioxide composition into the high permeability streak, injecting an aqueous treatment fluid from the injection well into the hydrocarbon bearing subterranean formation. The dense carbon dioxide composition may block the high permeability streak to divert at least a portion of the aqueous treatment fluid into bypassed regions of the hydrocarbon bearing subterranean formation during the injecting of the aqueous treatment fluid into the hydrocarbon bearing subterranean formation. The injecting of the aqueous treatment fluid into the hydrocarbon bearing subterranean formation may drive hydrocarbons in the hydrocarbon bearing subterranean formation towards the production well.

Additional features and advantages of the technology described in this disclosure will be set forth in the detailed description which follows, and in part will be readily apparent to those skilled in the art from the description or recognized by practicing the technology as described in this disclosure, including the detailed description which follows, the claims, as well as the appended drawings.

Embodiments of the present disclosure relate to methods for the use and application of the dense carbon dioxide compositions for enhanced oil recovery (EOR) from hydrocarbon-bearing subterranean formations and for reducing water production from hydrocarbon-bearing subterranean formations. Referring to <FIG>, one embodiment of a method for enhanced oil recovery from a hydrocarbon bearing subterranean formation <NUM> is schematically depicted. The method for enhanced oil recovery may include withdrawing hydrocarbons from a production well <NUM> extending into the hydrocarbon bearing subterranean formation <NUM>, identifying one or more high permeability zones <NUM>, <NUM> in the hydrocarbon bearing subterranean formation <NUM>, and injecting a dense carbon dioxide composition <NUM> (dense CO<NUM> composition) from an injection well <NUM> into the high permeability zones <NUM>, <NUM> of the hydrocarbon bearing subterranean formation <NUM>. The dense CO<NUM> composition <NUM> may include dense CO<NUM> and a thickener soluble in the dense CO<NUM>. The thickener may comprise a copolymer that is a polymerized reaction product of monomers that include at least one alkenyl ether or dialkenyl ether monomer, at least one acrylate or methacrylate monomer, at least one structural monomer, and at least one allyl ester monomer. The method may further include, after injecting the dense CO<NUM> composition <NUM> into the high permeability zones <NUM>, <NUM>, injecting an aqueous treatment fluid <NUM> from the injection well <NUM> into the hydrocarbon bearing subterranean formation <NUM>. The dense CO<NUM> composition <NUM> injected into the formation may block the high permeability zones <NUM>, <NUM> and may divert at least a portion of the aqueous treatment fluid <NUM> into bypassed regions of the hydrocarbon bearing subterranean formation <NUM> during the injecting of the aqueous treatment fluid <NUM> into the hydrocarbon-bearing subterranean formation <NUM>. Injecting of the aqueous treatment fluid <NUM> into the hydrocarbon bearing subterranean formation may drive hydrocarbons <NUM> in the hydrocarbon bearing subterranean formation <NUM> towards the production well <NUM>. The methods for enhanced oil recovery according to the present disclosure may improve sweep efficiency of water flooding processes to enhance recovery of hydrocarbons <NUM> from the hydrocarbon bearing subterranean formation <NUM>.

Referring now to <FIG>, one embodiment of a method for reducing water production from a hydrocarbon bearing subterranean formation <NUM> according to the present disclosure is schematically depicted. The method for reducing water production may include identifying one or more high permeability zones <NUM>, <NUM> in the hydrocarbon bearing subterranean formation <NUM> and injecting the dense CO<NUM> composition <NUM> from the production well <NUM> into each of the high permeability zones <NUM>, <NUM>. The dense CO<NUM> composition <NUM> may include dense CO<NUM> and a thickener soluble in the dense CO<NUM>. The thickener may comprise a copolymer that is a polymerization reaction product of monomers that include at least one alkenyl ether or dialkenyl ether monomer, at least one acrylate or methacrylate monomer, at least one structural monomer, and at least one allyl ester monomer. The method may further include, after injecting the dense CO<NUM> composition <NUM> into the high permeability zones <NUM>, <NUM>, withdrawing hydrocarbons <NUM> from the hydrocarbon bearing subterranean formation <NUM> through the production well <NUM>. The dense CO<NUM> composition <NUM> may block pores, fractures, or both in the high permeability zones <NUM>, <NUM> to reduce or prevent flow of water and other aqueous fluids from the high permeability zones <NUM>, <NUM> into the production well <NUM>. The method may reduce water production from the hydrocarbon bearing subterranean formation, which can improve the economic efficiency of the hydrocarbon production process.

As previously discussed, the methods of the present disclosure may improve the sweep efficiency of water flooding techniques for enhanced oil recovery to increase production of hydrocarbons or may reduce water production from the hydrocarbon bearing subterranean formation. Additionally, the methods of the present disclosure may provide a beneficial subterranean use of CO<NUM>. It is a well-known fact that CO<NUM> is a major contributor to the greenhouse effect and global warming, and CO<NUM> injection into subterranean formations can help in reducing the amount of CO<NUM> in the atmosphere and, thus, can assist in mitigating high levels of global warming. Similar to water-less fracking operations, the use of dense CO<NUM> instead of water may also help reduce the use of water in hydrocarbon production processes and, hence, improve water natural resource preservation, among other features of the disclosed methods.

As used throughout the present disclosure, the term "crude oil" refers to liquid hydrocarbons extracted from a hydrocarbon bearing subterranean formation. The term crude oil may include oil extracted from hydrocarbon bearing subterranean formations and subjected to desalting processes. However, crude oil is not intended to include effluents resulting from separation of the crude oil into various hydrocarbon fractions or effluents produced by processes for upgrading the crude oil through one or more chemical reactions, such as cracking, hydrocracking, hydrotreating, reforming, or other upgrading reaction.

As used throughout the present disclosure, the term "hydrocarbon-bearing subterranean formation" refers to a below-ground geologic region containing hydrocarbons, such as crude oil, hydrocarbon gases, or both, which may be extracted from the geologic region. The terms "subterranean formation" or just "formation" may refer to a subterranean geologic region that contains hydrocarbons or a subterranean geologic region proximate to a hydrocarbon-bearing formation, such as a subterranean geologic region to be treated for purposes of enhanced oil recovery.

As used throughout the present disclosure, the term "original oil in place" or "OOIP" may refer to the total volume of hydrocarbons contained in a subterranean reservoir or rock sample (such as a core sample) prior to production of hydrocarbons from the subterranean formation or rock sample.

As used in the present disclosure, the term "uphole" refers to a direction in a wellbore that is towards the surface. For example, a first component that is uphole relative to a second component is positioned closer to the surface of the wellbore relative to the second component.

As used in the present disclosure, the term "downhole" refers to a direction further into the formation and away from the surface. For example, a first component that is downhole relative to a second component is positioned farther away from the surface of the wellbore relative to the second component.

As used in the present disclosure, the term "high permeability zone" refers to a region of a subterranean formation having a permeability to fluids that is at least <NUM> times the permeability of the surrounding portions of the subterranean formation. High permeability zones can include regions of the subterranean formation having greater porosity, larger pore sizes, or both and fractures in the formation providing a flow path through the formation.

As used throughout the present disclosure, the term "dense carbon dioxide" may refer to carbon dioxide that is not in the gaseous phase, such as carbon dioxide in a state having a density of greater than or equal to <NUM>,<NUM> mol per cubic meter and may include liquid carbon dioxide or supercritical carbon dioxide, which is at a temperature and pressure above the critical point for carbon dioxide. The abbreviation CO<NUM> may be used to denote carbon dioxide throughout the present disclosure.

As used throughout the present disclosure, the term "supercritical fluid" may refer to any substance that is at a temperature and pressure that are above the critical point for that substance, but the pressure is less than the pressure required to compress the substance into a solid. The "critical point" of a substance is the temperature and pressure above which distinct liquid and gas phases do not exist for the substance.

Referring now to <FIG>, enhanced oil recovery from a hydrocarbon bearing subterranean formation <NUM> by water flooding is schematically depicted. A production well <NUM> may extend from the surface <NUM> downhole into the hydrocarbon bearing subterranean formation <NUM>. The production well <NUM> may be in fluid communication with the hydrocarbon bearing subterranean formation <NUM> to extract hydrocarbons <NUM> from the hydrocarbon bearing subterranean formation <NUM>. As discussed previously, primary oil recovery methods, such as extracting hydrocarbons <NUM> from the hydrocarbon bearing subterranean formation <NUM> from the production well <NUM>, alone can contribute to recovery of only about <NUM>% of the hydrocarbons in a hydrocarbon bearing subterranean formation (oil reservoir). Secondary oil recovery methods and enhanced oil recovery methods can be used to further increase the recovery of hydrocarbons <NUM> from the hydrocarbon bearing subterranean formation <NUM>.

Water flooding processes can produce an additional <NUM> percent of the original oil in place in the hydrocarbon bearing subterranean formation <NUM>. In a water flooding process, an injection well <NUM> is drilled into the hydrocarbon bearing subterranean formation <NUM> or into a subterranean formation adjacent to the hydrocarbon bearing subterranean formation <NUM>. The injection well <NUM> is spaced apart from the production well <NUM> by a distance of from <NUM> meters to <NUM> meters, or even a distance greater than <NUM> meters. Aqueous treatment fluids <NUM>, such as water or water with one or more oilfield additives, may be injected from the injection well <NUM> into the hydrocarbon bearing subterranean formation <NUM> or into a subterranean formation adjacent to the hydrocarbon bearing subterranean formation <NUM>. The injected aqueous treatment fluids <NUM> may flow towards the production well <NUM> and may displace hydrocarbons <NUM> in the hydrocarbon bearing subterranean formation <NUM>. The injected aqueous treatment fluids <NUM> may drive the hydrocarbons <NUM> towards the production well <NUM> to increase the recovery of the hydrocarbons <NUM> from the hydrocarbon bearing subterranean formation <NUM>.

One of the main problems associated with water flooding to increase hydrocarbon recovery is the channeling of the injected aqueous treatment fluids <NUM> through high permeability zones <NUM>, <NUM> that through portions of the hydrocarbon bearing subterranean formation <NUM>. Channeling of the aqueous treatment fluids <NUM> through the high permeability zones <NUM>, <NUM> can cause bypass of regions of the hydrocarbon bearing subterranean formation <NUM> and bypass of large amounts of hydrocarbons in these regions, which results in a poor sweep efficiency of the water flooding treatment. This can lead to reduced effectiveness of the water flooding process in improving hydrocarbon production and can result in further consumption of water resources to compensate for loss of the aqueous treatment fluids <NUM> through the high permeability zones <NUM>, <NUM>.

In such cases, the injection profile can be modified to reduce the effects of the high permeability zones <NUM>, <NUM>. Some conventional methods for modifying the injection profile during water flooding have included conventional chemical-based techniques such as the injection of treatment compositions comprising gels, polymers, nanoparticles, or combinations of these. All of these chemicals use water as the base fluid. This means that a specific amount of any selected chemical is added to water and then injected into the targeted wells to block the high permeability zones as well as any fractured zones and, hence, improve the injection profile. However, these conventional chemical-based techniques require further consumption of water and result in introducing chemicals, such as gels, polymers, or nanoparticles, into the formation.

High permeability zones in the hydrocarbon bearing subterranean formation can also have an effect at the production well. In particular, high-permeability zones can increase the water cut of fluids produced from the hydrocarbon bearing subterranean formation. Referring now to <FIG>, hydrocarbon production from a hydrocarbon bearing subterranean formation <NUM> having one or more high permeability zones <NUM>, <NUM> is schematically depicted. The production well <NUM> may extend down into the hydrocarbon bearing subterranean formation <NUM> and may be operable to provide a fluid flow path between the hydrocarbon bearing subterranean formation <NUM> and the surface <NUM> for producing hydrocarbons <NUM> from the hydrocarbon bearing subterranean formation <NUM>.

The production well <NUM> may be in fluid communication with one or more high permeability zones <NUM>, <NUM> in the hydrocarbon bearing subterranean formation <NUM>. The high permeability zones <NUM>, <NUM> may convey fluids to the production well <NUM> at a greater rate compared to other less permeable portions of the hydrocarbon bearing subterranean formation <NUM>. Once all the hydrocarbons from the high permeability zones <NUM>, <NUM> are produced at the production well, the high permeability zones <NUM>, <NUM> may become saturated with aqueous fluids <NUM>, such as connate water from nearby water zones, aqueous treatment fluids from nearby injection wells, or other water sources. The high-permeability zones <NUM>, <NUM> may convey these aqueous fluids <NUM> to the production well <NUM>, where the aqueous fluids <NUM> are produced along with hydrocarbons <NUM> from other portions of the hydrocarbon bearing subterranean formation <NUM>. These aqueous fluids <NUM> from the high permeability zones <NUM>, <NUM> may, therefore, increase the water cut in the fluids produced from the production well <NUM>.

This increase in water cut caused by aqueous fluids from high permeability zones <NUM>, <NUM> can cause operational difficulties, such as but not limited to corrosion of pipes, fine migration, and acceleration of well abandonment, if left unchecked. As previously discussed, it is estimated that water comprises about <NUM>% of the total liquid production from oil production wells, which results in more than $<NUM> billion spent annually to deal with this large water volume. To produce the hydrocarbons more cost effectively, techniques to reduce water production have been developed. Some of these existing techniques to reduce water production include chemical as well as mechanical solutions. Such solutions include polymer gel with cross linker treatment, cement squeeze jobs, and mechanical isolation jobs using packers or plugs. Each of these methods has advantages and limitations.

In the methods of the present disclosure, dense CO<NUM> compositions are used as the main blocking agent for blocking high permeability zones in the hydrocarbon bearing subterranean formation in place of aqueous treatment fluids and cements or mechanical isolation using packers or plugs. It is well-known that CO<NUM> is a major contributor to the greenhouse effect and global warming. CO<NUM> injection into subsurface rocks can contribute to reducing the amount of CO<NUM> in the atmosphere and, thus, assists in mitigating high levels of global warming. The use of dense CO<NUM> instead of water can also help to minimize the use of water and, hence, improve water natural resources preservation. However, dense CO<NUM> by itself may not have adequate viscosity to prevent the dense CO<NUM> from being displaced by other more viscous formation fluids or treatment fluids.

In the methods of the present disclosure, the high permeability zones are injected with a dense CO<NUM> composition that includes the dense CO<NUM> and a thickener. The thickener is an effective, inexpensive, and environmentally friendly thickener that is capable of dissolving readily in dense CO<NUM> at diluted concentrations (concentrations less than or equal to <NUM> percent by weight) and can increase the viscosity of the dense CO<NUM> by several orders of magnitude under practical conditions for injection into hydrocarbon bearing subterranean formations. In the methods of the present disclosure, the thickened CO<NUM> provided by the dense CO<NUM> compositions disclosed herein are injected into injection wells <NUM> that have poor performance due to the presence of high permeability zones or fractures. The injected dense CO<NUM> compositions having the thickened viscosity can block the flow channels of the high permeability zones and divert the subsequent injected aqueous treatment fluids into previously bypassed areas of the formation. Additionally, the dense CO<NUM> compositions may be injected from the production well <NUM> into high permeability zones in fluid communication with the production well 110to reduce the production of water at the production well. The dense CO<NUM> compositions having the thicker viscosity may block the high permeability zones to reduce or prevent the flow of connate water or aqueous treatment fluids into the production well <NUM>.

The dense CO<NUM> composition may include dense CO<NUM> and the thickener, which is soluble in the dense CO<NUM> and operable to increase the viscosity of the dense CO<NUM>. The dense CO<NUM> may be CO<NUM> that is not in the gaseous phase. The dense CO<NUM> may be CO<NUM> having a density of greater than or equal to <NUM>,<NUM> moles per cubic meter. The dense CO<NUM> may be liquid or supercritical CO<NUM>. Supercritical CO<NUM> refers to CO<NUM> that is at a temperature greater than or equal to the critical temperature of <NUM> and at a pressure greater than the critical pressure of <NUM> megapascals (MPa) for carbon dioxide. In embodiments, the dense CO<NUM> may be supercritical CO<NUM>. The dense CO<NUM> may include CO<NUM> recovered from one or more chemical processes, such as but limited to hydrocarbon refining processes (oil refinery), extracted from the atmosphere, obtained from a chemical gas supplier, or other source of CO<NUM>. In embodiments, the CO<NUM> may be pressurized to increase the pressure to greater than or equal to the critical pressure of CO<NUM> to increase the density of the CO<NUM>.

The thickener may include a copolymer and one or more co-solvents. The copolymer may be a polymerized reaction product of one or more monomers that include at least one alkenyl ether or dialkenyl ether monomer, at least one acrylate or methacrylate monomer, at least one structural monomer, and at least one allyl ester monomer. In embodiments, the copolymer may be a linear block copolymer.

Alkenyl ether monomers, dialkenyl ether monomers, or both may be included in the copolymer to act as hydrotropes to improve the solubility of the copolymer in one or more of the co-solvents. The alkenyl ether monomers, dialkenyl ether monomers, or both may include but are not limited to one or more of vinyl ether, divinyl ether, ethyl propylene ether, n-propyl vinyl ether. In embodiments, the copolymer may include at least one dialkenyl ether monomer selected from the group consisting of divinyl ether, ethyl propylene ether, n-propyl vinyl ether, and combinations of these. The copolymer may include an amount of alkenyl ether monomer, dialkenyl ether monomers, or both that is sufficient to improve the solubility of the copolymer in aqueous co-solvents, carbon dioxide, and other solvents. In embodiments, the copolymer may include from <NUM> percent by weight (wt. %) to <NUM> wt. % alkenyl ether or dialkenyl ether monomers based on the total weight of the copolymer.

The copolymer may include at least one acrylate monomer, at least one methacrylate monomer, or both. The acrylate monomer, methacrylate monomer, or both may be included as a tackifying monomer, which may enhance the thickening abilities of the thickener. Not intending to be bound by any particular theory, it is believed that the acrylate monomer, methacrylate monomer, or both can provide a tackifying group on the molecular chain of the copolymer that may interact with structural groups to enhance the thickening effects of the copolymer. The at least one acrylate monomer, at least one methacrylate monomer, or both may include one or more of methyl acrylate, ethyl acrylate, butyl acrylate, methyl methacrylate, ethyl methacrylate, butyl methacrylate, or combinations of these. In embodiments, the at least one acrylate monomer, at least one methacrylate monomer, or both may be selected from the group consisting of methyl acrylate, ethyl acrylate, butyl acrylate, methyl methacrylate, ethyl methacrylate, butyl methacrylate, and combinations of these. The copolymer may include an amount of acrylate monomer, methacrylate monomer, or both that is sufficient to enhance the viscosity thickening properties of the copolymer. In embodiments, the copolymer may include from <NUM> wt. % to <NUM> wt. % acrylate monomer, methacrylate monomer, or both based on the total weight of the copolymer.

The copolymer may include one or more structural monomers that include long carbon chains that interact with the tackifying acrylates and methacrylate groups through various intramolecular and intermolecular forces to build viscosity (increase viscosity). The at least one structural monomer may be selected from the group consisting of an acrylic acid long carbon chain ester, a methacrylic acid long carbon chain ester, styrene, methyl styrene, phenylpropene, and combinations of these. The acrylic acid long carbon chain ester and the methacrylic acid long carbon chain ester include a carbon chain length of from <NUM> carbons to <NUM> carbons. The copolymer may include an amount of structural monomers sufficient to increase the viscosity to enhance the thickening properties of the copolymer. In embodiments, the copolymer may include from <NUM> wt. % to <NUM> wt. % structural monomers based on the total weight of the copolymer.

The copolymer may also include an allyl ester monomer which may provide an affinity for carbon dioxide to improve the solubility of the copolymer in dense carbon dioxide. The at least one allyl ester monomer may include an allyl methyl ester, an allyl ethyl ester, or a combination of these. In embodiments, the at least one allyl ester monomer may include allyl methyl carbonate, allyl ethyl carbonate, or a combination of these. The copolymer may include an amount of the allyl ester monomer that is sufficient to provide adequate solubility of the copolymer in carbon dioxide, such as the dense CO<NUM>. In embodiments, the copolymer may include from <NUM> wt. % to <NUM> wt. % allyl ester monomers based on the total weight of the copolymer.

The thickener may include from <NUM> wt. % to <NUM> wt. % alkenyl ether monomers, dialkenyl monomers, or both based on the total weight of the thickener, including both the copolymer and co-solvents. The thickener may include from <NUM> wt. % to <NUM> wt. % acrylate monomers, methacrylate monomers, or both based on the total weight of the thickener, including both the copolymer and co-solvents. The thickener may include from <NUM> wt. % to <NUM> wt. % structural monomers based on the total weight of the thickener, including both the copolymer and co-solvents. The thickener may include from <NUM> wt. % to <NUM> wt. % allyl ester monomers based on the total weight of the thickener, including both the copolymer and co-solvents.

As previously discussed, the thickener may include one or a plurality of co-solvents. The co-solvents may be included to improve the solubility of the copolymer in the dense CO<NUM>. The co-solvents may also be included in the reaction mixture prior to polymerization to act as a solvent medium for the polymerization reaction. The co-solvents may include but are not limited to one or more of propylene carbonate, allyl ethyl carbonate, dimethyl carbonate, white oil, silicon oil, petroleum ether, or combinations of these. The co-solvents may include one or a plurality of solvents selected from the group consisting of propylene carbonate, allyl ethyl carbonate, dimethyl carbonate, white oil, silicon oil, petroleum ether, and combinations of these. The thickener may include greater than or equal to <NUM> wt. % co-solvents, greater than or equal to <NUM> wt. % co-solvents, or even greater than or equal to <NUM> wt. % co-solvents based on the total weight of the thickener, including the copolymer and all of the co-solvents. In embodiments, the thickener may include from <NUM> wt. % to <NUM> wt. % co-solvents, from <NUM> wt. % to <NUM> wt. % co-solvents, or from <NUM> wt. % to <NUM> wt. % co-solvents based on the total weight of the thickener, including the copolymer and all of the co-solvents.

The thickener may include at least one carbon dioxide compatible co-solvent that may operate to increase solubility of the thickener in the dense CO<NUM>. The carbon dioxide compatible co-solvent may include propylene carbonate, allyl ethyl carbonate, dimethyl carbonate, or combinations of these. In embodiments, the thickener may include propylene carbonate, dimethyl carbonate, or a combination of these as the carbon dioxide compatible co-solvent. The thickener may include an amount of the carbon dioxide compatible co-solvent sufficient to increase the solubility of the thickener in the dense CO<NUM>. In embodiments, the thickener may include from <NUM> wt. % to <NUM> wt. % carbon dioxide compatible co-solvent based on the total weight of the thickener, including the copolymer and all co-solvents.

The co-solvent may additionally include one or a plurality of oil dissolving co-solvents. The oil dissolving co-solvents may include, but are not limited to white oil, silicon oil, petroleum ether, or combinations of these. In embodiments, the thickener may include one or a plurality of the oil dissolving co-solvents selected from the group consisting of white oil, silicon oil, petroleum ether, and combinations of these. The thickener may include from <NUM> wt. % to <NUM> wt. % oil dissolving co-solvent based on the total weight of the thickener, including the copolymer and all of the co-solvents.

The thickener may be made through polymerization of the various monomers dispersed in the co-solvents to produce an emulsion comprising the copolymer dispersed in the co-solvents. In a first step of the process, the monomers may be dispersed in the co-solvents. The carbon dioxide compatible co-solvent and the oil dissolving co-solvent are added in the proportions previous discussed in this disclosure to a vessel maintained at from <NUM> to <NUM>. While stirring, the alkenyl ether or dialkenyl ether monomers, acrylate or methacrylate monomers, structural monomers, and allyl ester monomers may be added sequentially according to the proportions previously discussed. The monomers and co-solvents of the present disclosure are all commercially available. The mixture may be stirred until the monomers are completely dissolved in the co-solvents.

The polymerization reaction may then be initiated by adding an oil-soluble chain transfer agent and an oil-soluble polymerization initiator, sealing the reaction vessel, and heating the reaction vessel to a reaction temperature of from <NUM> to <NUM>. The oil-soluble initiator may include azobisisobutyronitrile, azobisisoheptonitrile, benzoyl peroxide or combinations of these. The oil-soluble initiator may be added in an amount of from <NUM> wt. % to <NUM> wt. % oil-soluble initiator based on the total weight of the polymerization mixture. The oil-soluble chain transfer agent may comprise butyl mercaptan, dodecyl mercaptan, hexadecyl mercaptan, or combinations of these. The polymerization reaction mixture may include from <NUM> wt. % to <NUM> wt. % oil-soluble chain transfer agent based on the total weight of the polymerization reaction mixture. The oil-soluble chain transfer agent may be added first, followed by the oil-soluble initiator. After adding these components and sealing the reactor vessel, the reactor vessel may be maintained at the reaction temperature of <NUM> to <NUM> and a pressure less than or equal to <NUM> MPa for a reaction duration of <NUM> hours to <NUM> hours. After the reaction duration, the reaction vessel may be cooled to ambient temperature with the contents of the reaction vessel being the thickener of the present disclosure.

The thickener of the present disclosure may be an emulsion of the copolymer in the co-solvents. The copolymer of the thickener may have a weight average molecular weight of from <NUM>,<NUM> grams per mole to <NUM>,<NUM> grams per mole. The thickener may have an acidic pH. In particular, the thickener may have a pH of from <NUM> to <NUM>. The thickener may have a specific gravity of from <NUM> to <NUM>.

The thickener may be readily soluble in dense CO<NUM> (liquid or supercritical). For instance, the thickener may have a solubility in dense CO<NUM> such that <NUM> percent by weight of the thickener dissolves in dense CO<NUM> in less than or equal to <NUM> minutes at <NUM> degrees Celsius. Not intending to be bound by any particular theory, it is believed that the carbon dioxide compatible co-solvent and the oil-dissolving co-solvent have an affinity for the dense CO<NUM> such that the carbon dioxide compatible co-solvent and the oil-dissolving co-solvent are quickly dispersed and dissolved in the dense CO<NUM> while carrying the copolymer in rapid dispersion in dense CO<NUM>. Because the copolymer is directly dissolved in the mixture of the carbon dioxide compatible co-solvent and the oil-dissolving co-solvent, it is believed that the molecular chain of the copolymer may be in a pre-stretched state so that solubilizing groups and the strong carbon dioxide-philic groups on the molecular chain (such as the allyl ester groups provided by the allyl ester monomer) can quickly interact with the dense CO<NUM> to solubilize the copolymer in the dense CO<NUM>. The thickener may be readily soluble in dense CO<NUM> at temperatures of from <NUM> to <NUM>. At temperatures less than <NUM>, the thickener may dissolve more slowly in the dense CO<NUM>, but may still be soluble in the dense CO<NUM>.

The thickener may be operable to increase the viscosity of dense CO<NUM> when added to the dense CO<NUM> to produce the dense CO<NUM> compositions. Not intending to be bound by any particular theory, it is believed that intermolecular and intramolecular interactions between the structural groups (provided by the structural monomers) and the acrylate groups (provided by the acrylate and methacrylate monomers) of the copolymer molecules may result in a thickening effect that increases the viscosity of the dense CO<NUM> compositions. The dense CO<NUM> compositions of the present disclosure may include an amount of the thickener that is sufficient to increase the viscosity of the dense CO<NUM> compositions but not so much that the increase in the viscosity of the dense CO<NUM> composition causes fracture of the subterranean formation into which the dense CO<NUM> is injected. When added to the dense CO<NUM>, the amount of the thickener may be sufficient to increase the viscosity of the dense CO<NUM> composition by greater than or equal to <NUM> times, or greater than or equal to <NUM> times, the viscosity of the dense CO<NUM> without the thickener. In embodiments, the amount of the thickener may be sufficient to increase the viscosity of the dense CO<NUM> composition by from <NUM> to <NUM> times the viscosity of the dense CO<NUM> without the thickener.

The amount of thickener in the dense CO<NUM> composition may depend on the specific application and the characteristics of the formation being treated. The dense CO<NUM> composition may have a concentration of the thickener sufficient to increase the viscosity of the dense CO<NUM> composition to improve the blocking effectiveness, but not so much that the viscosity of the dense CO<NUM> composition causes fracture of the formation. The dense CO<NUM> composition may include greater than or equal to <NUM> wt. %, greater than or equal to <NUM> wt. % or even greater than <NUM> wt. % thickener based on the total weight of the dense CO<NUM> composition. When the amount of the thickener is less than <NUM> wt. %, the concentration of the thickener may not be great enough to increase the viscosity of the dense CO<NUM> composition sufficiently to prevent the dense CO<NUM> composition from being swept from the pores and fractures of the high permeability zones in the formation. The dense CO<NUM> composition may include less than or equal to <NUM> wt. %, less than or equal to <NUM> wt. %, less than or equal to <NUM> wt. %, less than or equal to <NUM> wt. % or less than or equal to <NUM> wt. % thickener based on the total weight of the dense CO<NUM> composition. Depending on the nature of the formation, a concentration of the thickener in the dense CO<NUM> composition that is too great may increase the viscosity of the dense CO<NUM> composition to a degree that causes the fracture of the subterranean formation into which the dense CO<NUM> composition is injected. The balance of the dense CO<NUM> compositions may comprise the dense CO<NUM>.

The dense CO<NUM> compositions may be prepared by providing dense CO<NUM> at a pressure and temperature greater than or equal to the critical pressure and critical temperature of CO<NUM>. While maintaining the pressure and temperature of the dense CO<NUM>, the thickener may be added to the dense CO<NUM> and the mixture may be mixed for a period of time sufficient to completely disperse and dissolve the thickener in the dense CO<NUM> to produce the dense CO<NUM> composition. In embodiments, the dense CO<NUM> and thickener may be mixed for a period of time greater than or equal to <NUM> minutes, or even greater than or equal to <NUM> minutes.

The dense CO<NUM> composition comprising the dense CO<NUM> and the thickener may have a viscosity greater than the dense CO<NUM> without the thickener. The dense CO<NUM> composition may have a viscosity of greater than or equal to <NUM> millipascal seconds (mPa·s), greater than or equal to <NUM> millipascal seconds, or even greater than or equal to <NUM> millipascal seconds, where the viscosity is determined using a Cambridge viscometer apparatus. The dense CO<NUM> composition may have a viscosity of less than or equal to <NUM> millipascal seconds, less than or equal to <NUM> millipascal seconds, or even less than or equal to <NUM> millipascal seconds, where the viscosity is determined using a Cambridge viscometer apparatus. The dense CO<NUM> composition may have a viscosity of from <NUM> millipascal seconds to <NUM> millipascal seconds, from <NUM> millipascal seconds to <NUM> millipascal seconds, or from <NUM> millipascal seconds to <NUM> millipascal seconds. Below a viscosity of about <NUM> millipascal seconds, the dense CO<NUM> composition may not have sufficient viscosity to remain in the pores of the formation and may be at least partially swept from the treated region of the subterranean formation by subsequent water flooding or hydrocarbon production activities. Above a viscosity of about <NUM> millipascal seconds, the dense CO<NUM> composition may cause fracture of the subterranean formation during injection into the subterranean formation.

As previously discussed, the dense CO<NUM> compositions comprising dense CO<NUM> and the thickener may be used in methods of enhanced oil recovery to block high permeability zones in a hydrocarbon bearing subterranean formation to improve the efficiency and effectiveness of water flooding methods for increasing production of hydrocarbons from the hydrocarbon bearing subterranean formation. Referring again to <FIG>, the methods of the present disclosure for enhanced oil recovery from the hydrocarbon bearing subterranean formation <NUM> may include withdrawing hydrocarbons <NUM> from the production well <NUM> extending into the hydrocarbon bearing subterranean formation <NUM> and identifying one or more high permeability zones <NUM>, <NUM> in the hydrocarbon bearing subterranean formation <NUM>. Referring to <FIG> and <FIG>, the methods for enhanced oil recovery include injecting the dense CO<NUM> composition <NUM> from an injection well <NUM> into the high permeability zones <NUM>, <NUM> of the hydrocarbon bearing subterranean formation <NUM>. The dense CO<NUM> composition <NUM> may include dense CO<NUM> and the thickener, each of which may have any of the features, compositions, or characteristics previously discussed in the present disclosure. In particular, the thickener may be soluble in the dense CO<NUM> and may include a copolymer that is the polymerized reaction product of monomers that include at least one alkenyl ether or dialkenyl ether monomer; at least one acrylate or methacrylate monomer; at least one structural monomer; and at least one allyl ester monomer. Referring to <FIG>, after injecting the dense CO<NUM> composition <NUM> into the high permeability zones <NUM>, <NUM>, the method for enhanced oil recovery may include injecting an aqueous treatment fluid <NUM> from the injection well <NUM> into the hydrocarbon bearing subterranean formation <NUM>. The dense CO<NUM> composition <NUM> may block the high permeability zones <NUM>, <NUM> to divert at least a portion of the aqueous treatment fluid <NUM> into bypassed regions of the hydrocarbon bearing subterranean formation <NUM> during the injecting of the aqueous treatment fluid <NUM> into the hydrocarbon bearing subterranean formation <NUM> after injection of the dense CO<NUM> composition <NUM>. The injecting of the aqueous treatment fluid <NUM> into the hydrocarbon bearing subterranean formation <NUM> after treating the high permeability zones <NUM>, <NUM> may drive hydrocarbons <NUM> in the hydrocarbon bearing subterranean formation <NUM> towards the production well <NUM>.

The hydrocarbon bearing subterranean formation <NUM> may be any type of rock formation in which hydrocarbon deposits are typically found, and the methods of the present disclosure are not intended to be limited to any specific type of rock formation of the hydrocarbon bearing subterranean formation <NUM>. In embodiments, the hydrocarbon bearing subterranean formation <NUM> may be carbonate rock, sandstone rock, or a combination of these.

Referring again to <FIG>, the high permeability zones <NUM>, <NUM> may include portions of the hydrocarbon bearing subterranean formation <NUM> having a greater permeability, such as greater porosity, compared to the rest of the formation or may include fractures in the hydrocarbon bearing subterranean formation <NUM>. In embodiments, the high permeability zones <NUM>, <NUM> may be in direct fluid communication with the injection well <NUM> such that fluids can flow directly from the injection well <NUM> into the high permeability zone <NUM>, <NUM> without first passing through another portion of the formation. In embodiments, the high permeability zones <NUM>, <NUM> may be in fluid communication with a water flooded region <NUM>, which may in turn be in fluid communication with the injection well <NUM>. The hydrocarbon bearing subterranean formation <NUM> may include one or a plurality of high permeability zones <NUM>, <NUM>. Although shown in <FIG> as having two high permeability zones <NUM>, <NUM>, it is understood that the hydrocarbon bearing subterranean formation <NUM> may have one, three, four, or more than four high permeability zones <NUM>, <NUM>. Methods for identifying and locating the high permeability zones <NUM>, <NUM> in the hydrocarbon bearing subterranean formation <NUM> may include analyzing well log information obtained from wireline well logging tools. High permeability zones <NUM>, <NUM> may also be identified and located through various formation mapping techniques such as but not limited to seismic surveys or formation mapping through injection of tracer compounds, examples of which may include but are not limited to molecules or nanoparticles that can be tracked as they travel through the hydrocarbon bearing subterranean formation <NUM>. Other known techniques for identifying high permeability zones <NUM>,<NUM> in the hydrocarbon bearing subterranean formation <NUM> are contemplated.

Referring now to <FIG> and <FIG>, once the high permeability zones <NUM>, <NUM> have been identified and located, the dense CO<NUM> composition <NUM> may be injected into each of the high permeability zones <NUM>, <NUM>. Injecting the dense CO<NUM> composition <NUM> may include isolating a portion of the injection well <NUM> that is in fluid communication with the high permeability zone <NUM>, <NUM> from other portions of the injection well <NUM> before injecting the dense CO<NUM> composition into the high permeability zone <NUM>, <NUM>. Isolating the portion of the injection well <NUM> that is in fluid communication with the high permeability zone <NUM>, <NUM> may include installing one or more temporary plugs <NUM> in the injection well <NUM>. The temporary plugs <NUM> may be installed and disposed downhole of the portion of the injection well <NUM> in fluid communication with the high permeability zone <NUM>, <NUM> or both uphole and downhole of the portion of the injection well <NUM> in fluid communication with the high permeability zone <NUM>, <NUM>. Referring to <FIG>, in embodiments, the temporary plugs <NUM> may be disposed uphole and downhole of the high permeability zone <NUM> being treated to fluidly isolate the portion of the injection well <NUM> that is in fluid communication with the high permeability zone <NUM> from uphole and downhole portions of the injection well <NUM>.

Each temporary plug <NUM> may be a composition or mechanical apparatus capable of fluidly isolating a portion of a wellbore for a specified duration and capable of being removed from the wellbore to restore fluid communication. Each of the temporary plugs <NUM> may be a mechanical plug, such as a packer or other mechanical device capable of sealing off the injection well <NUM> at a particular downhole location and then being removed once injection of the dense CO<NUM> composition <NUM> is completed. Alternatively or additionally, in embodiments, each of the temporary plugs <NUM> may be a temporary gel plug that may include a gelling polymer that creates a semi-solid or solid plug when installed downhole. Temporary gel plugs may be removed from the injection well by introducing chemicals to break up or dissolve the gel formed by the gelling polymer or by mechanically piercing or removing the temporary gel plug. Once the dense CO<NUM> composition <NUM> is injected into the high permeability zone <NUM>, <NUM>, the temporary plugs <NUM> may be removed from the injection well <NUM>.

The dense CO<NUM> composition <NUM> may be injected from the injection well <NUM> into the high permeability zones <NUM>, <NUM> by known methods. In embodiments, the dense CO<NUM> composition <NUM> may be injected from the injection well <NUM> into the high permeability zones <NUM>, <NUM> through a conduit <NUM> extending from the surface <NUM> of the injection well <NUM> downhole to the portion of the injection well <NUM> in fluid communication with the high permeability zone <NUM>, <NUM> (the portion of the injection well <NUM> isolated by the temporary plugs <NUM>). The conduit <NUM> may include, but is not limited to, coiled tubing, wireline, a jointed pipe string, or other type of conduit.

The dense CO<NUM> composition <NUM> may be injected at the temperature of the hydrocarbon bearing subterranean formation <NUM> at the high permeability zones <NUM>, <NUM>. In embodiments, the dense CO<NUM> composition <NUM> may be injected into the high permeability zones <NUM>, <NUM> at a temperature of from <NUM> to <NUM>, such as from <NUM> to <NUM>, or from <NUM> to <NUM>. The dense CO<NUM> composition <NUM> may be injected into the high permeability zones <NUM>, <NUM> at a pressure greater than the critical pressure of CO<NUM>, such as a pressure greater than or equal to <NUM> megapascals. The dense CO<NUM> composition <NUM> may be injected into the high permeability zones <NUM>, <NUM> at a pressure equal to the formation pressure of the hydrocarbon bearing subterranean formation <NUM>. The dense CO<NUM> composition <NUM> may be injected into the high permeability zones <NUM>, <NUM> at a pressure of from <NUM>,<NUM> psi (<NUM> megapascals) to <NUM>,<NUM> psi (<NUM> megapascals). The pressure at which the dense CO<NUM> composition <NUM> is injected into the high permeability zones <NUM>, <NUM> may be less than a pressure that causes fracture of the formation.

Injection of the dense CO<NUM> composition <NUM> may be characterized by an injection duration, an injection volume, or both that are sufficient to adequately block the high permeability zones <NUM>, <NUM> to reduce or prevent aqueous treatment fluids from flowing into the high permeability zones <NUM>, <NUM> during subsequent water flooding. The dense CO<NUM> composition <NUM> may be injected into each high permeability zone <NUM>, <NUM> for a duration of from <NUM> hours to <NUM> hours. The volume of dense CO<NUM> composition <NUM> injected into each high permeability zone <NUM>, <NUM> may be sufficient to block the high permeability zone <NUM>, <NUM> and divert subsequent treatment fluids to other portions of the hydrocarbon bearing subterranean formation <NUM>. The volume of dense CO<NUM> composition <NUM> injected into each high permeability zone <NUM>, <NUM> may depend on the porosity of the high permeability zone <NUM>, <NUM>, which may be characterized by a total pore volume of the high permeability zone <NUM>, <NUM>. In embodiments, the volume of dense CO<NUM> composition injected into each of the high permeability zones <NUM>, <NUM> may be from <NUM> to <NUM> or from <NUM> to <NUM> times the total pore volume (PV) of the high permeability zone being treated.

Injection of the dense CO<NUM> compositions <NUM> into the high permeability zones <NUM>, <NUM> may displace fluids, such as aqueous formation fluids, aqueous treatment fluids, or other fluids, in the high permeability zone <NUM>, <NUM>. The dense CO<NUM> compositions <NUM> may also penetrate outward from the high permeability zone <NUM>, <NUM> into the pores of the formation surrounding the high permeability zone <NUM>, <NUM>. The increased viscosity of the dense CO<NUM> compositions <NUM> provided by the thickener may be sufficient to prevent subsequent fluid flow in the formation from displacing the dense CO<NUM> compositions <NUM> from the high permeability zones <NUM>, <NUM>. Thus, the injection of the dense CO<NUM> composition <NUM> into the high permeability zones <NUM>, <NUM> may reduce the permeability of the formation in the high permeability zones <NUM>, <NUM>, which may reduce or prevent aqueous treatment fluids in subsequent water flooding steps from flowing into and through the high permeability zones <NUM>, <NUM>. The injected dense CO<NUM> composition <NUM> may reduce the permeability of the formation in the high permeability zones <NUM>, <NUM> by greater than or equal to <NUM>%, greater than or equal to <NUM>%, greater than or equal to <NUM>%, greater than or equal to <NUM>% or even greater than or equal <NUM>%. In embodiments, the hydrocarbon bearing subterranean formation <NUM> may be carbonate rock, and the injection of the dense CO<NUM> composition may reduce the permeability of carbonate rock by greater than or equal to <NUM>%, greater than or equal to <NUM>%, greater than or equal to <NUM>%, greater than or equal to <NUM>% or even greater than or equal <NUM>%. Injection of the dense CO<NUM> composition <NUM> having the increased viscosity does not fracture the formation in the high permeability zones <NUM>, <NUM> or any other region in which the dense CO<NUM> composition <NUM> flows. The reduced permeability of the high permeability zones <NUM>, <NUM> caused by injection of the dense CO<NUM> composition <NUM> may act as a barrier to reduce or prevent fluid flow into and through the high permeability zones <NUM>, <NUM> and divert subsequent treatment fluids to other regions of the hydrocarbon bearing subterranean formation <NUM>, such as bypassed regions of the hydrocarbon bearing subterranean formation <NUM>.

Referring to <FIG> and <FIG>, each of the high permeability zones <NUM>, <NUM> may be treated with the dense CO<NUM> composition <NUM> sequentially. Referring to <FIG>, the hydrocarbon bearing subterranean formation <NUM> may include a first high permeability zone <NUM> and a second high permeability zone <NUM>. The first high permeability zone <NUM> may be fluidly isolated from the rest of the injection well <NUM> and hydrocarbon bearing subterranean formation <NUM> by installing the temporary plugs <NUM> uphole and downhole of the first high permeability zone <NUM>, as previously described. The dense CO<NUM> composition <NUM> may then be injected into the first high permeability zone <NUM> to treat the first high permeability zone <NUM>. In embodiments, the temporary plugs <NUM> isolating the first high permeability zone <NUM> may be removed from the injection well <NUM> after injection of the dense CO<NUM> composition <NUM>. In embodiments, such as when the first high permeability zone is downhole of the second high permeability zone <NUM>, the temporary plugs <NUM> isolating the first high permeability zone <NUM> may be left in the injection well <NUM> until after treating the second high permeability zone <NUM>.

Referring now to <FIG>, after treating the first high permeability zone <NUM>, the second high permeability zone <NUM> may be treated with the dense CO<NUM> composition <NUM>. The portion of the injection well <NUM> in fluid communication with the second high permeability zone <NUM> may be fluidly isolated from the rest of the injection well <NUM> by installing the temporary plugs <NUM> uphole and downhole of the second high permeability zone <NUM>. Once the second high permeability zone <NUM> is isolated, the dense CO<NUM> compositions <NUM> may be injected into the second high permeability zone <NUM> to block the second high permeability zone <NUM>. The temporary plugs <NUM> isolating the second high permeability zone <NUM> may then be removed following injection of the dense CO<NUM> composition <NUM>. The process of isolation, injection, and de-isolation may be repeated for additional high permeability zones in fluid communication with the injection well <NUM> until all the high permeability zones have been treated.

Referring now to <FIG>, after treating each of the high permeability zones <NUM>, <NUM> by injecting the dense CO<NUM> composition <NUM>, water flooding operations may be commenced or resumed. After injecting the dense CO<NUM> composition <NUM> into the high permeability zones <NUM>, <NUM>, the methods of enhanced oil recovery may include injecting the aqueous treatment fluid <NUM> from the injection well <NUM> into the hydrocarbon bearing subterranean formation <NUM>.

The aqueous treatment fluid <NUM> may include water. The water used in the aqueous treatment fluid <NUM> may be in the form of an aqueous solution containing additives or impurities. The water comprises one or more of freshwater, seawater, natural brine, synthetic brine, salt water, municipal water, well water, formation/connate water, produced water, brackish water, distilled water, deionized water, water produced from crude oil desalting processes, or combinations of these. Salts may be present in or incorporated into the water. Salts may include, but are not limited to, alkali metal chlorides, hydroxides, or carboxylates. In embodiments, salts present in the water may include, but are not limited to, sodium, calcium, cesium, zinc, aluminum, magnesium, potassium, strontium, silicon, lithium, chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, sulfates, phosphates, oxides, fluorides, and combinations of these.

In embodiments, the aqueous treatment fluid <NUM> may include one or more oilfield additives to modify one or more properties of the aqueous treatment fluid <NUM>. Oilfield additives may include but are not limited to one or more viscosifiers, surfactants, stabilizers, pH control agents, scale inhibitors, polymers, nanoparticles, tracer compounds, or combinations of these. Other typical oilfield additives commonly used in water flooding processes are contemplated.

Referring again to <FIG>, the aqueous treatment fluids <NUM> may be injected from the injection well <NUM> into the hydrocarbon bearing subterranean formation <NUM> using known methods. In embodiments, the aqueous treatment fluids <NUM> may be injected from the injection well <NUM> into the hydrocarbon bearing subterranean formation <NUM> through a conduit, such as but not limited to coiled tubing, wireline, a jointed pipe string, or other type of conduit. In embodiments, the aqueous treatment fluids <NUM> may be injected from the wellbore casing itself. Other devices or processes for injecting the aqueous treatment fluids <NUM> into the hydrocarbon bearing subterranean formation <NUM> are contemplated. The dense CO<NUM> compositions <NUM> injected into the high permeability zones <NUM>, <NUM> may provide a barrier that blocks the high permeability zones <NUM>, <NUM> and diverts at least a portion of the aqueous treatment fluid <NUM> into bypassed regions <NUM> of the hydrocarbon bearing subterranean formation <NUM> during the injecting of the aqueous treatment fluids <NUM> into the hydrocarbon bearing subterranean formation <NUM>.

The aqueous treatment fluids <NUM> injected into the hydrocarbon bearing subterranean formation <NUM> may flow generally from the injection well <NUM> towards the production well <NUM>. The flow of aqueous treatment fluids <NUM> into the hydrocarbon bearing subterranean formation <NUM> may displace hydrocarbons in the bypassed regions <NUM> of the hydrocarbon bearing subterranean formation <NUM>. The aqueous treatment fluids <NUM> flowing into the bypassed regions <NUM> of the hydrocarbon bearing subterranean formation <NUM> may exert pressure on the hydrocarbon fluids to provide motive force for driving the hydrocarbons <NUM> towards the production well <NUM>. While injecting the aqueous treatment fluids <NUM> at the injection well <NUM>, the hydrocarbons <NUM> may be produced at the production well <NUM>. The methods of the present disclosure may include withdrawing the hydrocarbons <NUM> from the production well <NUM>.

The methods of the present disclosure for enhancing oil recovery from hydrocarbon bearing subterranean formations may further include preparing the dense CO<NUM> composition <NUM>. Preparing the dense CO<NUM> composition <NUM> may include providing dense CO<NUM>, combining the thickener with the dense CO<NUM>, and mixing the dense CO<NUM> and thickener for a period of time sufficient to completely dissolve the thickener in the dense CO<NUM> to produce the dense CO<NUM> composition, as previously discussed in the present disclosure. In embodiments, the dense CO<NUM> composition may be prepared at the surface <NUM> immediately prior to injection into the injection well <NUM>.

As previously discussed, the dense CO<NUM> compositions comprising dense CO<NUM> and the thickener may be used to reduce water production at the production well by injecting the dense CO<NUM> compositions from the production well into high permeability zones in fluid communication with the production well. Reducing water production by treating the high permeability zones in fluid communication with the production well may reduce the cost and improve the economic efficiency of producing hydrocarbons from the hydrocarbon bearing subterranean formation. Referring now to <FIG>, the methods of the present disclosure for reducing water production from a hydrocarbon bearing subterranean formation <NUM> may include identifying one or more high permeability zones <NUM>, <NUM> in the hydrocarbon bearing subterranean formation <NUM>. Referring to <FIG> and <FIG>, the methods for reducing water production may further include injecting the dense CO<NUM> composition <NUM> from the production well <NUM> into each of the high permeability zones <NUM>, <NUM>. The dense CO<NUM> composition <NUM> may include the dense CO<NUM> and the thickener, each of which may have any of the features, compositions, or characteristics previously discussed in the present disclosure. In particular, the thickener may be soluble in the dense CO<NUM> and may comprise a copolymer that is the polymerized reaction product of monomers that include at least one alkenyl ether or dialkenyl ether monomer; at least one acrylate or methacrylate monomer; at least one structural monomer; and at least one allyl ester monomer. Referring to <FIG>, after injecting the dense CO<NUM> composition <NUM> into the high permeability zones <NUM>, <NUM>, the methods of reducing water production may include withdrawing hydrocarbons <NUM> from the hydrocarbon bearing subterranean formation <NUM> through the production well <NUM>. The dense CO<NUM> composition may block pores, fractures, or both in the high permeability zones <NUM>, <NUM> to reduce or prevent flow of water from the high permeability zones <NUM>, <NUM> into the production well <NUM>. This may reduce the production of water from the hydrocarbon bearing subterranean formation <NUM> and may improve the economic efficiency of hydrocarbon production from the production well <NUM>, among other features of the methods.

As previously discussed, the hydrocarbon bearing subterranean formation <NUM> may be any type of rock formation in which hydrocarbon deposits are typically found, and the methods of the present disclosure are not intended to be limited to any specific type of rock formation of the hydrocarbon bearing subterranean formation <NUM>. In embodiments, the hydrocarbon bearing subterranean formation <NUM> may be carbonate rock, sandstone rock, or a combination of these.

Referring again to <FIG>, the high permeability zones <NUM>, <NUM> may include portions of the hydrocarbon bearing subterranean formation <NUM> having a greater permeability, such as greater porosity, compared to the rest of the formation or may include fractures in the hydrocarbon bearing subterranean formation <NUM>. The high permeability zones <NUM>, <NUM> may be in direct fluid communication with the production well <NUM> such that fluids can flow directly from the high permeability zones <NUM>, <NUM> into the production well <NUM> without first passing through other portions of the subterranean formation. The hydrocarbon bearing subterranean formation <NUM> may include one or a plurality of high permeability zones <NUM>, <NUM> in fluid communication with the production well <NUM>. Although shown in <FIG> as having two high permeability zones <NUM>, <NUM>, it is understood that the hydrocarbon bearing subterranean formation <NUM> may have one, three, four, or more than four high permeability zones <NUM>, <NUM>. The high permeability zones <NUM>, <NUM> may be in fluid communication with one or more water zones (not shown) in the hydrocarbon bearing subterranean formation <NUM>, such as but not limited to a water zone comprising connate water or one or more water flood regions <NUM> (<FIG>). When untreated, these high permeability zones <NUM>, <NUM> in fluid communication with the production well <NUM> can provide a flow path that enables connate water from water zones, aqueous treatment fluids from water flood regions <NUM>, or both to flow to the production well <NUM>, which increases the water production at the production well <NUM>.

Identifying and locating the high-permeability zones <NUM>, <NUM> may include analyzing well log information obtained from wireline well logging tools or identifying the high permeability zones <NUM>, <NUM> through formation mapping techniques, as previously discussed in the present disclosure in relation to <FIG>.

Referring now to <FIG> and <FIG>, once the high permeability zones <NUM>, <NUM> have been identified and located, the dense CO<NUM> composition <NUM> may be injected from the production well <NUM> into each of the high permeability zones <NUM>, <NUM>. Injecting the dense CO<NUM> composition <NUM> may include isolating a portion of the production well <NUM> that is in fluid communication with the high permeability zone <NUM>, <NUM> from other portions of the production well <NUM> before injecting the dense CO<NUM> composition into the high permeability zone <NUM>, <NUM>. Isolating the portion of the production well <NUM> that is in fluid communication with the high permeability zone <NUM>, <NUM> being treated may include installing one or more temporary plugs <NUM> in the production well <NUM>. The temporary plugs <NUM> may be installed and disposed downhole of the portion of the production well <NUM> in fluid communication with the high permeability zone <NUM>, <NUM> or both uphole and downhole of the portion of the production well <NUM> in fluid communication with the high permeability zone <NUM>, <NUM> being treated. Referring to <FIG>, in embodiments, the temporary plugs <NUM> may be disposed uphole and downhole of the high permeability zone <NUM> being treated to fluidly isolate the portion of the production well <NUM> that is in fluid communication with the high permeability zone <NUM> from uphole and downhole portions of the production well <NUM>.

As previously discussed, each temporary plug <NUM> may be a composition or mechanical apparatus capable of fluidly isolating a portion of a wellbore for a specified duration and capable of being removed from the wellbore to restore fluid communication. Each of the temporary plugs <NUM> may be a mechanical plug, such as a packer or other mechanical device capable of sealing off the production well <NUM> at a particular downhole location, or a temporary gel plug, as previously described. Temporary gel plugs may be removed from the production well <NUM> by introducing chemicals to break up or dissolve the gel formed by the gelling polymer or by mechanically piercing or removing the temporary gel plug. Once the dense CO<NUM> composition <NUM> is injected into the high permeability zone <NUM>, <NUM>, the temporary plugs <NUM> may be removed from the production well <NUM>.

The dense CO<NUM> composition <NUM> may be injected from the production well <NUM> into the high permeability zones <NUM>, <NUM> by known methods. The dense CO<NUM> composition <NUM> may be injected from the production well <NUM> into each of the high permeability zones <NUM>, <NUM> through a conduit <NUM> extending from the surface <NUM> of the production well <NUM> downhole to the portion of the production well <NUM> in fluid communication with the high permeability zone <NUM>, <NUM> (the portion of the production well <NUM> isolated by the temporary plugs <NUM>). The conduit <NUM> may include, but is not limited to, coiled tubing, wireline, a jointed pipe string, or other type of conduit. Injection of the dense CO<NUM> composition <NUM> into the high permeability zones <NUM>, <NUM> does not fracture the high permeability zones <NUM>, <NUM>.

Injection of the dense CO<NUM> composition <NUM> may be characterized by an injection duration, an injection volume, or both that are sufficient to adequately block the high permeability zones <NUM>, <NUM> to reduce or prevent aqueous fluids <NUM> from flowing from the high permeability zones <NUM>, <NUM> into the production well <NUM> during subsequent hydrocarbon production. The dense CO<NUM> composition <NUM> may be injected from the production well <NUM> into each high permeability zone <NUM>, <NUM> for an injection duration of from <NUM> hours to <NUM> hours. The volume of dense CO<NUM> composition <NUM> injected into each high permeability zone <NUM>, <NUM> may be sufficient to block the high permeability zone <NUM>, <NUM> to reduce or prevent aqueous fluids from flowing from the high permeability zones <NUM>, <NUM> into the production well <NUM>. The volume of the dense CO<NUM> composition <NUM> injected into each high permeability zone <NUM>, <NUM> may depend on the porosity of the high permeability zone <NUM>, <NUM>, which may be characterized by a total pore volume of the high permeability zone <NUM>, <NUM>. In embodiments, the volume of dense CO<NUM> composition injected into each of the high permeability zones <NUM>, <NUM> may be from <NUM> to <NUM> or from <NUM> to <NUM> times the total pore volume (PV) of the high permeability zone being treated.

Injection of the dense CO<NUM> compositions <NUM> into the high permeability zones <NUM>, <NUM> may displace fluids, such as aqueous formation fluids, aqueous treatment fluids, or other fluids, in the high permeability zone <NUM>, <NUM>. The dense CO<NUM> compositions <NUM> may also penetrate outward from the high permeability zone <NUM>, <NUM> into the pores of the formation surrounding the high permeability zone <NUM>, <NUM>. The increased viscosity of the dense CO<NUM> compositions <NUM> provided by the thickener may be sufficient to prevent subsequent fluids flow in the formation from displacing the dense CO<NUM> compositions <NUM> from the high permeability zones <NUM>, <NUM>. Thus, the injection of the dense CO<NUM> composition <NUM> into the high permeability zones <NUM>, <NUM> may reduce the permeability of the formation in the high permeability zones <NUM>, <NUM>. The reduced permeability caused by the dense CO<NUM> composition may reduce or prevent aqueous fluids from the high permeability zones <NUM>, <NUM> into the production well <NUM> from the high permeability zones <NUM>, <NUM>. The injected dense CO<NUM> composition <NUM> may reduce the permeability of the formation in the high permeability zones <NUM>, <NUM> by greater than or equal to <NUM>%, greater than or equal to <NUM>%, greater than or equal to <NUM>%, greater than or equal to <NUM>% or even greater than or equal <NUM>%. In embodiments, the hydrocarbon bearing subterranean formation <NUM> may be carbonate rock, and the injection of the dense CO<NUM> composition may reduce the permeability of carbonate rock by greater than or equal to <NUM>%, greater than or equal to <NUM>%, greater than or equal to <NUM>%, greater than or equal to <NUM>% or even greater than or equal <NUM>%. Injection of the dense CO<NUM> composition <NUM> having the increased viscosity does not fracture the formation in the high permeability zones <NUM>, <NUM> or any other region in which the dense CO<NUM> composition <NUM> flows. The reduced permeability of the high permeability zones <NUM>, <NUM> caused by injection of the dense CO<NUM> composition <NUM> may act as a barrier to reduce or prevent fluid flow into and through the high permeability zones <NUM>, <NUM> and reduce or prevent aqueous fluids from flowing from the high permeability zones <NUM>, <NUM> into the production well <NUM>, thereby reducing water production from the production well <NUM>.

Referring to <FIG> and <FIG>, each of the high permeability zones <NUM>, <NUM> may be treated with the dense CO<NUM> composition <NUM> sequentially. Referring to <FIG>, the hydrocarbon bearing subterranean formation <NUM> may include a first high permeability zone <NUM> and a second high permeability zone <NUM>. The first high permeability zone <NUM> may be fluidly isolated from the rest of the production well <NUM> by installing the temporary plugs <NUM> uphole and downhole of the first high permeability zone <NUM>, as previously described. The dense CO<NUM> composition <NUM> may then be injected into the first high permeability zone <NUM> to treat the first high permeability zone <NUM>. In embodiments, the temporary plugs <NUM> isolating the first high permeability zone <NUM> may be removed from the production well <NUM> after injection of the dense CO<NUM> composition <NUM>. In embodiments, such as when the first high permeability zone <NUM> is downhole of the second high permeability zone <NUM>, the temporary plugs <NUM> isolating the first high permeability zone <NUM> may be left in the production well <NUM> until after treating the second high permeability zone <NUM>.

Referring now to <FIG>, after treating the first high permeability zone <NUM>, the second high permeability zone <NUM> may be treated with the dense CO<NUM> composition <NUM>. The portion of the production well <NUM> in fluid communication with the second high permeability zone <NUM> may be fluidly isolated from the rest of the production well <NUM> by installing the temporary plugs <NUM> uphole and downhole of the second high permeability zone <NUM>. Once the second high permeability zone <NUM> is isolated, the dense CO<NUM> compositions <NUM> may be injected into the second high permeability zone <NUM> to block the second high permeability zone <NUM>. The temporary plugs <NUM> isolating the second high permeability zone <NUM> may then be removed following injection of the dense CO<NUM> composition <NUM>. The process of isolation, injection, and de-isolation may be repeated for additional high permeability zones in fluid communication with the production well <NUM> until all the high permeability zones <NUM>, <NUM> have been treated or injected with the dense CO<NUM> compositions.

Referring again to <FIG>, the methods of the present disclosure for reducing water production from the hydrocarbon bearing subterranean formation <NUM> may include withdrawing the hydrocarbons <NUM> from the production well <NUM>. The dense CO<NUM> compositions <NUM> injected into the high permeability zones <NUM>, <NUM> may reduce the permeability of the high permeability zones <NUM>, <NUM>, which may provide a barrier that blocks the high permeability zones <NUM>, <NUM> to reduce or prevent the flow of aqueous fluids, such as but not limited to connate water, aqueous treatment fluids, or other aqueous fluids, through the high permeability zones <NUM>, <NUM> to the production well <NUM>. This reduces the volume of water produced at the production well <NUM>. Thus, the fluids produced by the production well <NUM> may include a greater proportion of hydrocarbons <NUM> from the hydrocarbon bearing subterranean formation <NUM> compared to the fluids produced before treatment of the high permeability zones <NUM>, <NUM>.

The methods of the present disclosure for reducing water production from hydrocarbon bearing subterranean formations may further include preparing the dense CO<NUM> composition <NUM>. Preparing the dense CO<NUM> composition <NUM> may include providing dense CO<NUM>, combining the thickener with the dense CO<NUM>, and mixing the dense CO<NUM> and thickener for a period of time sufficient to completely dissolve the thickener in the dense CO<NUM> to produce the dense CO<NUM> composition, as previously discussed in the present disclosure. In embodiments, the dense CO<NUM> composition may be prepared at the surface <NUM> immediately prior to injection into the injection well <NUM>.

The various embodiments of the dense carbon dioxide compositions and methods employing the dense carbon dioxide compositions to enhance oil recovery from hydrocarbon bearing subterranean formations according to the present disclosure will be further clarified by the following examples. The examples are illustrative in nature, and should not be understood to limit the subject matter of the present disclosure.

In Examples <NUM> and <NUM>, the objective is to assess solubility of the thickener in different phases of CO<NUM> and to investigate the compatibility of the thickener with CO<NUM> at different conditions. The solubility tests of Examples <NUM> and <NUM> provide an indication of the stability of the thickener with the CO<NUM> over time. In all of the examples of the present disclosure, the thickener used was Dry-Fracturing Fluid Friction Reducer and Thickener: APFR-<NUM> manufactured by Beijing AP Polymer Technology Co. , LTD located in Beijing, China. The solubility of the thickener was evaluated by combining the thickener with CO<NUM> at a pressure of <NUM> psi (<NUM>,<NUM> kPa) in Example <NUM> and a pressure of <NUM> psi (<NUM>,<NUM> kPa) for Example <NUM>. For each of Examples <NUM> and <NUM>, a known volume of the thickener equal to <NUM> volume percent of the final composition was charged into a high pressure/high temperature (HPTP) cell under vacuum and at ambient temperature. CO<NUM> was then injected into the HPHT cell at <NUM> psi in Example <NUM> and at <NUM> psi in Example <NUM>. The HPHT cell was equipped with a stirrer so that mixing could be instigated at the experimental conditions.

For Example <NUM>, the solubility test was conducted at <NUM> psi and <NUM>. According to the CO<NUM> phase diagram, CO<NUM> is in the supercritical phase at these conditions. In Example <NUM>, the thickener was observed to be soluble in the dense supercritical CO<NUM> and a single phase of both fluids formed. For Example <NUM>, the solubility test was conducted at <NUM> psi and <NUM>. At these conditions, CO<NUM> is in the supercritical phase. In Example <NUM>, the thickener was observed to be soluble in the dense supercritical CO<NUM> and a single phase of the supercritical CO<NUM> and the thickener formed. Examples <NUM> and <NUM> show that the thickener is soluble in supercritical dense CO<NUM>. In particular, Examples <NUM> and <NUM> demonstrate that the thickener is able to dissolve in supercritical dense CO<NUM> at conditions (pressure) very similar to oilfield conditions, such as the pressures encountered in hydrocarbon bearing subterranean formations.

For Comparative Examples <NUM> and <NUM>, the viscosity of dense CO<NUM> was determined without the thickener at pressures of <NUM> psi (<NUM>,<NUM> kPa) and <NUM> psi (<NUM>,<NUM> kPa), respectively. A Cambridge viscometer apparatus was used to conduct the viscosity measurements. The pressure and viscosity measurements for Comparative Examples <NUM> and <NUM> are provided in Table <NUM> and graphically depicted in <FIG>. Comparative Example <NUM> is indicated in <FIG> by reference number <NUM> and Comparative Example <NUM> is indicated in <FIG> by reference number <NUM>.

For Examples <NUM>-<NUM>, the viscosity of the dense CO<NUM> compositions were evaluated at different concentrations of the thickener in the dense CO<NUM> compositions and at different conditions. The Cambridge viscometer apparatus discussed in Comparative Examples <NUM> and <NUM> was used to conduct the viscosity measurements at different pressures. The concentrations of the thickener, pressure, and measured viscosities for each of Examples <NUM>-<NUM> are provided in Table <NUM> and are graphically depicted in <FIG>. The viscosities in Table <NUM> are provided in units of millipascal seconds (mPa·s).

The results reported in Table <NUM> and <FIG> show that the addition of the thickener to the dense CO<NUM> enhances the viscosity of the dense CO<NUM> significantly. The increase in the viscosity of the CO<NUM> resulting from adding the thickener (Examples <NUM>-<NUM>) is in the range between <NUM> and <NUM> times the viscosity of the dense CO<NUM> without the thickener (Comparative Examples <NUM> and <NUM>). The increase in viscosity is accomplished at pressures typical of conditions in oilfields, such as pressures encountered in hydrocarbon-bearing subterranean formations.

In Example <NUM>, dense CO<NUM> compositions comprising the dense CO<NUM> and thickener were evaluated for use in enhanced oil recovery processes by conducting coreflood studies. The core samples used in the coreflood experiments were Indiana limestone (carbonate rock) cores having an initial permeability of <NUM><NUM> (<NUM> millidarcies (mD)). The properties of the core sample is provided below in Table <NUM>.

Referring now to <FIG>, the coreflood experimental system <NUM> for conducting the coreflood experiments of Example <NUM> is schematically depicted. The coreflood experimental system <NUM> used was a Model RPS-<NUM>-Z coreflood system specifically designed for injection of dense CO<NUM> and manufactured by Coretest Systems, Inc. of Reno, Nevada. The coreflood experimental system <NUM> includes a core holder <NUM> operable to hold the core sample <NUM> and direct a fluid to pass longitudinally through the core sample <NUM> from the upstream end <NUM> to the downstream end <NUM>. The core holder <NUM> may include a confining fluid <NUM> that may be operable to maintain the core sample <NUM> at a simulated downhole operating pressure and to prevent the fluids directed into the core sample <NUM> from passing radially outward out of the core sample <NUM>. The core holder <NUM> may include a pressure regulation system <NUM> operable to regulate the pressure of the core sample <NUM>. The coreflood experimental system <NUM> may also include a high-pressure pump <NUM>, a water accumulator <NUM>, a dense CO<NUM> composition accumulator <NUM>, and a fraction collector <NUM> as depicted in <FIG>. The coreflood experimental system <NUM> may also include a back pressure regulator <NUM> downstream of the core holder <NUM> and upstream of the fraction collector <NUM> to control back pressure in the system.

For Example <NUM>, each core sample was placed in the core holder and flooded with water under a confining pressure of <NUM>,<NUM> psi (<NUM>,<NUM> kPa) and an injection flow rate of <NUM> milliliters per minute. The confined pressure is the pressure under which the core plug sample is confined. A volume of water equivalent to <NUM> times the total pore volume of the core sample was injected. Following the initial water injection, one equivalent pore volume of the dense CO<NUM> composition was injected into the core sample under the same confining pressure. The dense CO<NUM> composition included a mixture of <NUM> volume percent thickener and <NUM> volume percent supercritical CO<NUM>. Following injection of the dense CO<NUM> composition, a second stage of water equal to <NUM> times the total initial pore volume of the core sample was injected into the core sample at the same confining pressure. The confining pressure of <NUM> psi and injection flowrate of <NUM>/min were the same for all three injection stages (water <NUM>/dense CO<NUM> composition/water <NUM>). The pressure drop across the core sample was measured as a function of injection volume for the first water injection stage, the dense CO<NUM> composition injection, and the second water injection stage. The results are provided graphically in <FIG>. The first water injection stage is indicated by reference number <NUM> in <FIG>, the dense CO<NUM> composition injection stage is indicated by reference number <NUM> in <FIG>, and the second water injection stage is indicated by reference number <NUM> in <FIG>.

Referring to <FIG>, the pressure drop across the core sample increased by over <NUM> psi (<NUM> kPa) during injection of the dense CO<NUM> composition (<NUM>). Following injection of the dense CO<NUM> composition, the pressure drop of the subsequent second water flood stage (<NUM>) was at least <NUM> psi (<NUM> kPa) greater than the pressure drop during the first water flood stage (<NUM>), indicating that the dense CO<NUM> composition greatly reduced the permeability of the core sample. The water permeability of the core sample was measured before and after the injection of dense CO<NUM> composition. The injection of the dense CO<NUM> composition comprising the thickener into the limestone rock core sample significantly reduced the permeability of the core sample from <NUM><NUM> (<NUM> mD) to <NUM><NUM> (<NUM> mD). This is about <NUM> times reduction in the permeability of the rock provided by injecting the dense CO<NUM> composition.

In Comparative Example <NUM>, a core sample was subjected to coreflooding using dense CO<NUM> without thickener, for comparison purposes. The coreflood experiment of Comparative Example <NUM> was conducted using the coreflood experimental setup <NUM> previously described in Example <NUM>. The core samples used in the coreflood experiment of Comparative Example <NUM> were Indiana limestone (carbonate rock) cores having an initial permeability of <NUM><NUM> (<NUM> millidarcies (mD)). The properties of the core sample were provided previously in Table <NUM>. For Comparative Example <NUM>, the core sample was placed in the core holder and flooded with unthickened dense CO<NUM> (without the thickener) under a confining pressure of <NUM>,<NUM> psi (<NUM>,<NUM> kPa) and an injection flow rate of <NUM> milliliters per minute.

Referring now to <FIG>, the pressure drop across the core sample as a function of the volume of unthickened dense CO<NUM> of Comparative Example <NUM> is graphically depicted. The average pressure drop across the core sample for Comparative Example <NUM> was <NUM> kPa (<NUM> psi), which was less than the average pressure drop across the core sample of <NUM> kPa (<NUM> psi) for the first water stage injection of Example <NUM>. Water has a greater viscosity than unthickened dense CO<NUM> (without thickener). Thus, without the thickener, the dense CO<NUM> is less effective than water at blocking the pores of the formation, as shown by the reduced pressure drop across the core sample for Comparative Example <NUM> compared to the pressure drop across the core sample during the first water injection stage in Example <NUM>. Referring to <FIG>, addition of the thickener to the dense CO<NUM> to form the dense CO<NUM> composition greatly increases the viscosity and, thus, greatly increases the blocking effectiveness of the dense CO<NUM> composition of Example <NUM> compared to the unthickened dense CO<NUM> of Comparative Example <NUM>.

It is noted that one or more of the following claims utilize the terms "where," "wherein," or "in which" as transitional phrases. For the purposes of defining the present technology, it is noted that these terms are introduced in the claims as an open-ended transitional phrase that are used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term "comprising.

It should be understood that any two quantitative values assigned to a property may constitute a range of that property, and all combinations of ranges formed from all stated quantitative values of a given property are contemplated in this disclosure.

Claim 1:
A method for enhanced oil recovery from a hydrocarbon bearing subterranean formation, the method comprising:
withdrawing hydrocarbons from a production well extending into the hydrocarbon bearing subterranean formation;
identifying a high permeability streak in the hydrocarbon bearing subterranean formation;
injecting a dense carbon dioxide composition from an injection well into the high permeability streak of the hydrocarbon bearing subterranean formation, where:
the dense carbon dioxide composition comprises dense carbon dioxide and a thickener soluble in the dense carbon dioxide, and
the thickener comprises a copolymer, the copolymer being the polymerized reaction product of monomers that include:
at least one alkenyl ether or dialkenyl ether monomer;
at least one acrylate or methacrylate monomer;
at least one structural monomer selected from the group consisting of an acrylic acid long carbon chain ester having a carbon chain length of from <NUM> carbons to <NUM> carbons, a methacrylic acid long carbon chain ester having a carbon chain length of from <NUM> carbons to <NUM> carbons, styrene, methyl styrene, phenylpropene, and combinations of these; and
at least one allyl ester monomer; and
after injecting the dense carbon dioxide composition into the high permeability streak, injecting an aqueous treatment fluid from the injection well into the hydrocarbon bearing subterranean formation,
wherein:
the dense carbon dioxide composition blocks the high permeability streak to divert at least a portion of the aqueous treatment fluid into bypassed regions of the hydrocarbon bearing subterranean formation during the injecting of the aqueous treatment fluid into the hydrocarbon bearing subterranean formation; and
the injecting of the aqueous treatment fluid into the hydrocarbon bearing subterranean formation drives hydrocarbons in the hydrocarbon bearing subterranean formation towards the production well.