WO2017204280A1 - Perfluoroalkyl acrylate polymeric thickener for enhancing viscosity of fluid co2, critical co2, and supercritical co2 - Google Patents

Abstract

The present invention provides a new polymeric compound, poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate), which is soluble in fluid CO₂ under appropriate conditions. This polymer is effective in enhancing the viscosity of CO₂, especially when it has a number-average molecular weight of greater than 250,000 as measured by gel permeation chromatography. Such thickened CO₂ is useful in recovering oil from underground.

Description

PERFLUOROALKYL ACRYLATE POLYMERIC THICKENER FOR ENHANCING VISCOSITY OF FLUID CO2, CRITICAL CO2, AND SUPERCRITICAL CO2

Carbon dioxide (CO₂) has been promoted as a green solvent for a variety of industrial applications because it is nonflammable, nonhazardous, of low cost, and environmentally benign. CO₂ thus offers new opportunities in chemical manufacturing including polymeric processing, formation of microcellular materials, heterogeneous reactions and polymerizations, protein extraction, complexation of organic acids and heavy metals, and separation processes such as cleaning and purification.

For many years, CO₂ has also been used as a solvent for enhanced oil recovery (“EOR”) and as a well-fracturing fluid by the oil and gas industry. After a petroleum reservoir is waterflooded, dense CO₂ can be injected into the sandstone or limestone to maintain the reservoir pressure and to displace additional petroleum. During a CO₂ flood, CO₂ can dynamically develop effective miscibility with petroleum (as will be explained further below) and can therefore displace oil left behind by waterflooding. The CO₂ is typically introduced at a pressure that yields a CO₂ density of about 0.5-0.7 g/cm³ at a reservoir temperature of 300-400 K. At the production well, CO₂ can be readily separated from the oil by pressure reduction. Other favorable properties of CO₂, such as natural abundance and classification as a non-VOC (volatile organic compound), also contribute to making CO₂-flooding an attractive sustainable oil recovery procedure. Another advantage of CO₂ EOR is that it not only produces oil but also sequesters CO₂.

The foremost disadvantage of CO₂ as an oil displacement fluid is its low viscosity, which is 0.03-0.10 mPa s (cp) at the reservoir conditions. The oil has a viscosity that varies from 0.1 to 50 cp. This results in a much higher CO₂ mobility (which is the ratio of fluid permeability k_r in porous media to fluid viscosity μ) than oil mobility. The mobility ratio M_CO2:oil between CO₂ and oil (i.e., CO₂ mobility/oil mobility) is therefore greater than 1, resulting in unfavorable macroscopic flow patterns. Namely, CO₂ “fingers” towards the production well (“viscous fingering”), bypassing much of the oil in the reservoir, causing areal sweep efficiency and oil production rates of a CO₂ flood to be low, and prolonging the duration of the oil recovery project. In addition, in stratified reservoirs, vertical sweep efficiency can be diminished as CO₂ preferentially flows into higher-permeability layers.

Water is commonly injected along with CO₂ in order to reduce the relative permeability k_r of CO₂ in the porous media, thereby decreasing its mobility. However, this water-alternating-gas (“WAG”) strategy extends the duration of the injection of a specified amount of CO₂. Furthermore, it makes the contact of the CO₂ and oil more difficult to achieve because of the “shielding” of the oil from the CO₂.

If the CO₂ viscosity can be elevated to a level comparable to that of the oil it is displacing, which will be a two-to-twenty-fold increase in viscosity in many cases, the mobility ratio M_CO2:oil will approach or become less than 1, a significant increase in the rate of oil recovery and in the cumulative amount of oil recovered will result, and there will not be a need to inject slugs of water along with the “thickened” CO₂ as performed in WAG. Substantial improvements in oil recovery efficiency and production rate can be expected.

Well fracturing with liquid CO₂ will also be more effective if the viscosity of CO₂ can be increased. Such thickened CO₂ will be able to propagate wider fractures, carry larger sand proppant particles further into a fracture, and reduce “leak-off” of CO₂ into the faces of the fractures.

The present invention provides a new polymeric compound, specified by poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate) (“C₆ SFA homopolymer”), which is soluble in fluid CO₂ under appropriate conditions. When this homopolymer has a number-average molecular weight of greater than 250,000 as measured by gel permeation chromatography, it is effective in enhancing the viscosity of CO₂. The present invention also provides a method of recovering oil from underground using such thickened CO₂.

The headings used in this disclosure are for organizational purposes only, and are not meant to limit the scope of the description. As used throughout this disclosure, the words “may” and “can” are used in a permissive sense (i.e., meaning “having the potential to”), rather than in a mandatory sense (i.e., meaning “must”). Similarly, the words “include,” “including,” and “includes” mean “including but not limited to.”

The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee.

The features and advantages of the present invention will be more fully understood with reference to the detailed description in the next section when taken in conjunction with the following figures.

Figure 1 shows a triangular miscibility diagram of CO₂, 100% heavy hydrocarbons, and 100% extractable hydrocarbons.
Figure 2 shows the relationship between CO₂ viscosity and temperature at various pressures in the form of isobaric lines.
Figure 3 depicts flows of CO₂ in 1/4 5-spot injection-production pattern, showing the phenomenon of “viscous fingering.”
Figures 4 and 5 present, in the background, the same graph in which fraction of oil recovered (ordinate) is plotted against mobility ratio M of CO₂:oil (abscissa) at various specified pore volumes of CO₂ (individual curves). Figure 4 shows the case in which M = 100 with pure CO₂, which has a low viscosity (μ). Figure 5 shows the case in which M = 10 with thickened CO₂, whose viscosity is ten times greater than that of pure CO₂.
Figure 6 shows the relationship between k_r (relative permeability) and CO₂ saturation in water.
Figure 7 shows a schematic of water-alternating-gas (“WAG”) operation.
Figure 8 shows a schematic example of a co-polymeric CO₂ thickener molecule.
Figure 9 shows a mechanism of thickening CO₂ via intermolecular associations between copolymers dissolved in CO₂.
Figure 10 shows an example of synthesizing fluoroacrylate-styrene copolymer (“poly-FAST”) with a CH₂CH₂C₈F₁₇ side chain (“PHFDA-yPst”).
Figure 11 shows an example of fluoroacrylate-styrene copolymer (poly-FAST) with a CH₂CH₂C₈F₁₇ side chain, x = 0.71, and y = 0.29 with reference to Figure 10.
Figure 12 shows another example of fluoroacrylate-styrene copolymer (poly-FAST) with a CH₂CH₂C₆F₁₃ side chain, x = 0.71, and y = 0.29.
Figure 13 shows the structural formula of poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate), which is a “C₆ SFA homopolymer” of the present invention.
Figure 14 shows changes in viscosity between pure CO₂ and CO₂ thickened by 1 weight% of poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate) (C₆ SFA homopolymer or “PFA”) having a number-average molecular weight of greater than 250,000 as reflected in a pressure drop observed in a 285 mD Berea sandstone core.
Figure 15 shows changes in viscosity between pure CO₂ and CO₂ thickened by 1 weight% of poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate) (C₆ SFA homopolymer or “PFA”) having a number-average molecular weight of greater than 250,000 as reflected in a pressure drop observed in a 125 mD Berea sandstone core.
Figure 16 shows examples of CO₂-philic segments.
Figure 17 shows examples of CO₂-phobic associating groups.
Figure 18 presents a table listing the polymer samples used as the examples and comparative examples of the present invention.
Figure 19 shows the relative viscosity of CO₂ thickened by an embodiment of poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate) designated “PD1” at 25°C under different pressures (psig) and at various weight percentages. The relative viscosity is plotted along the ordinate in logarithmic scale.
Figure 20 shows the viscosity (cp) of pure CO₂ and of CO₂ thickened by an embodiment of poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate) designated “PD1” at 25°C under different pressures (psig) and at various weight percentages. The viscosity (cp) is plotted along the ordinate in logarithmic scale.
Figure 21 shows the viscosity (cp) of pure CO₂ and of CO₂ solutions containing 1 weight% of various polymers at 25°C under different pressures (psig). The viscosity (cp) is plotted along the ordinate in linear scale.
Figure 22 shows the relative viscosity of CO₂ solutions containing certain weight percentages of selected polymers at 25°C under different pressures (psig). The relative viscosity is plotted along the ordinate in logarithmic scale.
Figure 23 presents a table of the numerical data plotted in the graph of Figure 19 (“PD1 Relative Viscosities at 25°C”).
Figure 24 presents a table of the numerical data plotted in the graph of Figure 20 (“PD1 Viscosity 25°C”).
Figure 25 presents a table of the numerical data plotted in the graph of Figure 21 (“1 wt% Solution Viscosities at 25°C”).
Figure 26 presents a table of the numerical data plotted in the graph of Figure 22 (“PD1 vs. PDx Relative Viscosities at 25°C”).

The detailed description that follows generally describes various exemplary embodiments of the present invention, and should not be considered to be exclusive of other equally effective embodiments, as would be understood by those of ordinary skill in the art. Further, numerous specific details are given in order to provide a thorough understanding of the embodiments and other examples. In some instances, however, well-known methods, procedures, and components have not been described in detail, so as to not obscure the following description. The embodiments and examples disclosed are for exemplary purposes only. Other embodiments and examples may be employed in lieu of, or in combination with, the embodiments and examples disclosed.

A. Miscibility of CO₂ and oil
In enhanced oil recovery (“EOR”), one need not aim at making CO₂ a better solvent of oil. Instead, one can take advantage of the ability of CO₂ to become completely miscible with crude oil as it flows from an injection well through the rock towards a production well, extracting light oil components like pentane and hexane. “Miscible CO₂ EOR” then results.

Specifically, if a solvent is “miscible” with crude oil, then one can mix the solvent and the crude oil in any proportion whatsoever and only a single phase results. This is also referred to as “first contact miscible” or “completely miscible.” For example, toluene and crude oil are miscible in this sense. High-pressure LPG (a liquid mixture of propane and butane) is also miscible with crude oil in this sense. A triangular miscibility diagram of CO₂, 100% heavy hydrocarbons, and 100% extractable hydrocarbons is presented in Figure 1.

CO₂ is not “completely miscible” or “first contact miscible” with crude oil, however. If one has a windowed phase-behavior cell, and adds 90% CO₂ and 10% crude oil and mixes them, one gets two liquid phases (a CO₂-rich liquid with some light oils in it, and an oil-rich liquid with some CO₂ dissolved in it) even if one compresses the system to 20,000 psi. Nevertheless, CO₂ is very cheap and available in plentiful amounts compared to toluene or LPG, and CO₂ can become a good solvent in the sandstone or carbonate formation in the following way.

When CO₂ flows into the injection well and begins to flow in the oil-bearing formation, the CO₂ can extract some of the lighter “extractable” hydrocarbons from the crude oil (Figure 1). This moving front of CO₂ therefore changes its composition: it becomes enriched in the lighter ends of the oil. As it does so, the mixture becomes a stronger and stronger solvent for crude oil, and this process continues until the CO₂ has “developed” miscibility. In other words, CO₂-light hydrocarbon blend becomes completely miscible with the crude oil in the long porous medium of sandstone or carbonate rock. This is “multiple contact miscibility.” This way, one can extract essentially all of the crude oil from a core or a long piece of tubing packed with sand and crude oil (with the exception of a small amount of oil near the inlet of the core or tubing) as long as one is at or above the so-called “minimum miscibility pressure” (“MMP”), which is the minimum pressure required for the extraction of lighter ends by CO₂ to occur.

In short, essentially all of the crude oil, even the heavy components (which are not completely miscible with CO₂ as seen in Figure 1), can be recovered as long as the CO₂ is injected into the layer of rock at a pressure that exceeds the MMP. While the perfluoroalkyl acrylate homopolymer of the present invention may affect the miscibility or the MMP of CO₂ with crude oil, its primary property is to increase CO₂ viscosity.

In an EOR operation, there can be a pressure drop of thousands of psi between the injector and the producer. The CO₂ pressure at the bottom of the injection well is usually kept at least several hundred psi above the MMP to ensure the pressure in the formation stays at or above the MMP so that CO₂ remains a good solvent. However, one cannot go to too high a pressure because the compression costs become high and the high pressure may also cause the formation to fracture.

B. Viscous fingering of CO₂ in oil
CO₂ has a low viscosity (on the order of 0.01 to 0.25 cP under most practical conditions), which is roughly 10-100 times lower than the viscosity of oil normally subjected to CO₂ EOR (on the order of 0.5 to 6.0 cP). Isobaric lines of CO₂ viscosity plotted against temperature are presented in Figure 2. The relevant temperature for EOR purpose is in the 30°C-100°C (303.15 K-373.15 K) range, since almost all CO₂ flooding is done at these temperatures, with many big formations found in the 40°C-70°C range. The relevant pressure generally ranges from about 1,200 psi (8.27 MPa) at 25°C for the shallowest formations with a light oil to 4,000 psi (27.58 MPa) for deep hot formations at 110°C with a heavier oil.

The low viscosity of CO₂ results in “viscous fingering.” Namely, the low viscosity of CO₂ increases the so-called “mobility ratio” M, in which M_CO2:oil = (k_r,CO2/μ_CO2)/(k_r,oil/μ_oil). Here, μ represents viscosity and k_r represents relative permeability of the respective components. When M is greater than 1, undesirable phenomena take place, such as viscous fingering. (The relative permeability k_r is defined as relative to the permeability of the rock that is completely saturated only with one phase, typically water. When there is only one fluid in the rock, the highest possible permeability is obtained. Therefore, relative permeability values are by definition less than 1.)

Figure 3 depicts the flow of CO₂ in 1/4 5-spot injection-production pattern that visualizes the phenomenon of viscous fingering. In such a “quarter 5-spot injection-production pattern,” only the bottom left-hand corner is the injector, the top right-hand corner is the producer, and the remaining edges represent “no flow boundaries.” Although CO₂ will be a good solvent where it flows, when CO₂ fingers as seen in Figure 3, CO₂ “breaks through” at the production well (i.e., at the top right-hand corner) early, and much of the subsequently injected CO₂ does not sweep the formation. Instead, it flows into these fingers and to the production well. When this happens, one must produce, separate, re-compress, and re-inject recycled CO₂ along with newly purchased CO₂. This prolongs the process of oil recovery, increases the ratio of (CO₂ injected):(oil produced), and increases the ratio of (gaseous CO₂ produced):(oil produced) as well.

The plots in Figures 4 and 5 quantify this effect and show how much better it is for one to thicken CO₂, that is, to increase the viscosity of CO₂. Figure 4 shows the case in which the low viscosity of pure CO₂ results in a high mobility ratio of CO₂:oil, and Figure 5 shows the case in which a thickened CO₂ results in a lower mobility ratio of CO₂:oil. Thus, according to these figures, 30% oil recovery requires 0.5 pore volume of pure CO₂ or 0.3 pore volume of thickened CO₂, 50% oil recovery requires 1.5 pore volume of pure CO₂ or 0.6 pore volume of thickened CO₂, and 70% oil recovery requires 4.0 pore volume of pure CO₂ or 1.2 pore volume of thickened CO₂.

C. Water-alternating-gas (WAG) technology
One solution to get around viscous fingering is to not inject CO₂ alone, but to inject both CO₂ and brine but alternatively (“water-alternating-gas” or “WAG”). This decreases the volume fraction of CO₂ in the pores, which in turn results in reduced relative permeability k_r of CO₂. Figure 6 shows the relative permeability k_r as a function of mixing ratio of water and CO₂. In a WAG, for example, only CO₂ is injected for a month, the CO₂ saturation near the wellbore becomes very high, the relative permeability k_r also becomes high, and CO₂ can be injected at a high rate. Then the injection operation is switched to water. Initially it is difficult to get a high flow rate of water because its saturation near the wellbore is low, but after a few days its saturation near the wellbore becomes high, its relative permeability k_r also becomes high, and water can be injected at a high flow rate for a month. As one moves away from the wellbore, say, 50 to 150 feet, these “slugs” of alternating CO₂ and brine have a chance to mix and flow together as they flow through the vast majority of the formation. This is shown in Figure 7. The volumetric ratio of water to CO₂ is about 1:1 for a constant WAG, but the ratio can vary for a variable WAG, and can start at ~0.1 (water):1 (CO₂) and increase to values as high as ~2 (water):1 (CO₂) with time.

However, this technology does not entirely solve the problem of mobility control in the context of CO₂ EOR. This is partly because brine is not a good solvent for oil, and brine and oil do not mix with each other well. Therefore, even if brine sweeps the volume of a core or a formation completely, it will only be able to displace or push a portion of the oil called the “mobile oil.” It will leave behind the so-called “residual oil,” which can be roughly half of all of the oil. In contrast, CO₂ at a pressure above the MMP is a much better solvent for crude oil than is brine, and it can leave behind close to 0% of the residual oil.

For example, generally speaking, waterflooding recovers 25-50% of OOIP (Original Oil In Place). CO₂ EOR WAG recovers an additional 10-20% of OOIP. Together 35-70% of OOIP is recovered, which means 30-65% of the OOIP still remains in the rock after WAG.

In addition, WAG requires massive amounts of water (brine). WAG also delays the injection of the solvent (CO₂). Although WAG usually provides improvement, it does not provide complete recovery. WAG further results in water production, water separation, water treatment, and water-reinjection facilities, all of which require a significant capital and operating expense.

D. Approaches to enhancing CO₂ viscosity
Another solution to mobility control, that is, to suppress viscous fingering, is to decrease the mobility ratio M_CO2:oil = (k_r,CO2/μ_CO2)/(k_r,oil/μ_oil) by increasing the viscosity of CO₂, μ_CO2. By way of background, it is fairly easy to thicken hydrocarbon liquids and organic solvents. For example, “napalm” refers to small molecules (namely, hydroxyaluminum alkanoates based on naphthenic and palmitic acids) that self-assemble and thicken gasoline, and napalm B is a gasoline thickener that uses dissolved polystyrene.

To significantly enhance the viscosity of CO₂ when present in dilute concentrations, thickening agents should be soluble in liquid CO₂ and create macromolecular structures of a very high molecular weight via non-covalent associations. Materials that exhibit low or negligible solubility in pure CO₂ include most polymers (except amorphous or low-melting fluoropolymers and silicones), waxes, heavy oils, proteins, salts, and metal oxides. For example, styrene repeat units are known to be CO₂-phobic, and high-polarity salts are more CO₂-phobic. Conventional hydrocarbon-based polymers, telechelic ionomers, organometallic compounds, surfactants, and ammonium carbamates have very low CO₂ solubility. Identification of an effective viscosity-raising agent (a “thickener”) for neat CO₂ remains elusive.

There are two strategies for thickening CO₂, which are quite similar to the strategies for thickening water or oil. One is to rely on high and ultra-high molecular weight polymers and associating polymers (the polymer route). The other is to rely on small molecules with associating groups that self-assemble into viscosity-enhancing macromolecules in solution (the small-molecule route). In either case, the resultant thickened CO₂ should be thermodynamically stable, transparent, and capable of flowing through the pore throats (about 1 μm) of the sandstone or limestone. If the solution is transparent, it has a good chance of flowing nicely through porous rock. On the other hand, if the solution is cloudy because there is a second dispersed phase (such as solid particles, solid fibers, or droplets of a viscous liquid), then those tiny bits of the second phase can be “screened” by the rock inlet surface and can clog the core or the rock.

In the small-molecule route, every small-molecule thickener has two types of segments. One is a CO₂-philic segment that promotes solubility in CO₂. The other is a CO₂-phobic segment that promotes the molecules’ association into viscosity-enhancing worm-like, rod-like, fiber-like, cylindrical, or helical micelles or complexes. The relevant intermolecular interactions include hydrogen bonding, electropositive-electronegative interactions, Lewis acid-Lewis-base interactions, π-π stacking, and dimerization. Examples of CO₂-philic segments include polydimethyl siloxane, polyvinyl acetate, polypropylene glycol, sugar acetate-rich polymers, polylactic acid, short alkanes, and branched alkanes, as shown in Figure 16. Examples of CO₂-phobic associating groups include aromatics, acids, alcohols, tin fluoride, hydroxyl aluminum, urea, amides, and amines, as shown in Figure 17. Most candidate thickeners fail to even dissolve in CO₂ because CO₂ is a very poor solvent for most associating groups.

In the polymer route, a copolymer containing CO₂-philic side chains and CO₂-phobic side chains on a polymeric backbone may be used. A schematic example is presented in Figure 8. The copolymer has the advantage of being easily dissolved in CO₂ with static mixers and without the need of heating. Thickening of CO₂ occurs via intermolecular associations between the copolymers dissolved in CO₂, namely, via associations between the CO₂-phobic side chains, as shown in Figure 9.

An example of such a copolymer is fluoroacrylate-styrene copolymer (“poly-FAST”), in which the monomer 3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,10-heptadecafluorodecyl acrylate (“HFDA”) provides the CO₂-philic fluoroacrylate side chains, and the monomer styrene provides the CO₂-phobic side chains. Figure 10 shows an example of synthesizing a poly-FAST having such a CH₂CH₂C₈F₁₇ side chain (“PHFDA-yPst”), and Figure 11 shows a poly-FAST in which the fluoroacrylate portion (x) is 71 mol% and the styrene portion (y) is 29 mol%. Intermolecular associations are achieved by the π-π interactions between the aromatic rings of styrene. This poly-FAST can enhance the viscosity of CO₂ by factors greater than 100 at concentrations of about 5 weight%, and 3- to 10-fold increases in viscosity are realized for 1 weight% solutions at shear rates much greater than those associated with EOR (Z. Huang et al., Macromolecules, 33, 5437 (2000) (“Huang”), whose content is incorporated herein by reference in its entirety).

On the other hand, copolymers lacking the aromatic side groups (styrene) generally produce a much lower degree of viscosity enhancement in CO₂. For example, for telechelic (sulfonate-terminated) fluorinated polyurethanes (which may undergo association in solution), the relative viscosity approaches 3 at concentrations of 5 weight% copolymer.

The poly-FAST derived from HFDA has CO₂-philic fluoroacrylate side chains with eight fluorinated carbons, namely, -C₈F₁₇. Polymers and oligomers based on HFDA, however, are bio-accumulative, in which perfluorooctanoic acid (CF₃(CF₂)₆COOH) is the most notorious degradation product. HFDA is also expensive. When the number of fluorinated carbons is reduced from eight to six (namely, to-C₆F₁₃), the polymer is no longer bio-accumulative, but it is still relatively expensive. Figure 12 shows a poly-FAST with such a CH₂CH₂C₆F₁₃ side chain.

E. Homopolymer approach
Fluoropolymers and silicones have been shown to be greatly soluble in CO₂. Thus, poly(1,1-dihydroperfluorooctyl acrylate), with a molecular weight of about 1.4 x 10⁶, was miscible with CO₂ without the need for a co-solvent, and was able to induce a significant increase in solution viscosity (J.B. McClain et al., Polym. Mater. Sci. Eng., 74, 234 (1996) (“McClain”), whose content is incorporated herein by reference in its entirety). At 50°C, 6.7 weight% of this homopolymer increased CO₂ viscosity from 0.08 to 0.2-0.6 cP (Huang), or at concentrations of 5-10 weight%, the viscosity of CO₂ was increased by a factor of 3-8 at 323 K and a pressure of 200-350 bar (C. Shi et al., Ind. Eng. Chem. Res., 40, 908 (2001) (“Shi”), whose content is incorporated herein by reference in its entirety). Likewise, poly(3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,10-heptadecafluorodecyl acrylate) (i.e., poly-HFDA) was soluble in liquid CO₂ at a concentration of 5 weight% at room temperature and low pressure (below 10 MPa) (Huang), and at concentrations of 3-5 weight%, this homopolymer increased the viscosity of CO₂ by a factor of 1.25-1.7 at 297 K and an experimental shear rate range of 3,500-9,700 s^-1 (Shi). However, it is desirable to attain the target level of viscosity enhancement for EOR with lower thickener concentrations (e.g., less than 1 weight%).

The present invention provides a homopolymer also made only of CO₂-philic side chains, namely, poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate), which is a polyfluoroacrylate containing the environmentally-acceptable -C₆F₁₃ tails (“C₆ SFA homopolymer”). Figure 13 presents the structural formula of a C₆ SFA homopolymer. It is able to dissolve in CO₂ at a typical MMP value without the need of a co-solvent.

Thus, a C₆ SFA homopolymer with a number-average molecular weight of greater than 250,000 increased the viscosity of CO₂ by 2.5 to 4 in field tests, depending on the conditions of the subject sandstone core, when it was mixed into CO₂ in a concentration of 1 weight% and was displaced through the core at a superficial velocity of 10 ft/day. (One would expect even greater increases in viscosity at lower superficial velocities (i.e., lower shear rates)). Specifically, as shown in Figure 14, 1 weight% of a C₆ SFA homopolymer having a number-average molecular weight of greater than 250,000 increased the viscosity of CO₂ by 4 at a superficial velocity of 10 ft/day in a 285 mD Berea sandstone core. And as further shown in Figure 15, 1 weight% of a C₆ SFA homopolymer having a number-average molecular weight of greater than 250,000 increased the viscosity of CO₂ by 2.5 at a superficial velocity of 10 ft/day in a 125 mD Berea sandstone core.

In Figures 14 and 15, in order to evaluate the effect of the homopolymer on the viscosity of CO₂, the core is first filled only with pure CO₂ at a specified pressure of 1850 psi. (It is possible to dissolve 1 weight% of the C₆ SFA homopolymer in CO₂ at 21°C and 1850 psi.) Pure CO₂ is then displaced from a positive displacement pump into the core at a constant volumetric flow rate that is exactly the same as the flow rate that fluids are withdrawn from the core with a separate positive displacement pump. A steady-state pressure drop for pure CO₂ flowing through the core is then measured. Subsequently, thickened CO₂ is displaced into the core at the same flow rate, and the pressure drop across the length of the core will increase as thickened CO₂ displaces the pure (low-viscosity) CO₂ from the core. After several pore volumes of thickened CO₂ have been injected into the core, a steady-state pressure drop for thickened CO₂ is measured. Because the test is done at a constant volumetric flow rate, the change in pressure across the length of the core reflects the change in viscosity. Therefore, the ratio of the steady-state pressure drop for thickened CO₂ flowing through the core to the steady-state pressure drop for pure CO₂ flowing through the core provides a measure of how much the viscosity of the CO₂ has been increased by the dissolved polymer.

At the present, poly-FAST and C₆ SFA homopolymers remain the only polymeric CO₂ thickeners that work and that do not need a co-solvent to dissolve in CO₂. In contrast, C₈ SFA homopolymers (namely, homopolymers with a CH₂CH₂C₈F₁₇ side chain) and poly(1,1-dihydroperfluorooctyl acrylate) of McClain above require a high concentration (4.4 to 7.7 weight%) to get a two- to five-fold increase in viscosity.

Various examples of the present invention and comparative examples will be presented below. In what follows, unless otherwise specified, the amounts of the components in a composition are all expressed in weight% relative to the total amount of the composition.

A. Synthesis of C₆ SFA homopolymer
A C₆ SFA homopolymer of the present invention was synthesized as follows. In a 300 ml flask equipped with a condenser, 30 g of 3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctane-1-yl acrylate was dispersed into 70 g of distilled water and 0.2 g of an emulsifier, followed by the addition of an initiator, and the mixture was stirred vigorously for 5 hours under a gentle nitrogen flow at an elevated temperature. The reaction mixture was then precipitated and re-precipitated with methanol. The polymer obtained (29 g) was then dried under vacuum overnight. The resulting C₆ SFA homopolymer had a number-average molecular weight of greater than 250,000 when measured by gel permeation chromatography.

A C₆ SFA homopolymer having a different number-average molecular weight was prepared as follows. In a 200 ml flask equipped with a condenser, 10 g of 3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctane-1-yl acrylate was dissolved into 70 g of a fluorinated solvent and 0.2 g of an initiator, and the mixture was stirred vigorously for 5 hours under a gentle nitrogen flow at an elevated temperature. The C₆ SFA homopolymer obtained had a number-average molecular weight of approximately 110,000 when measured by gel permeation chromatography.

B. Measurement of number-average molecular weight
The number-average molecular weight (Mn) of a polymer was measured by gel permeation chromatography.

C. Measurement of viscosity
The viscosity of a CO₂ solution containing a polymer was measured by falling cylinder viscometry.

D. Examples and comparative examples
Figure 18 presents a table listing examples of the present invention (designated PD1 and PD1c) and comparative examples (designated PD5, PD6, PD7, PD8, HFO-1234yf homopolymer, BP-PF-C6-P, and BP-PF-C8-P), whose effects on CO₂ viscosity were measured. Here, “Poly-FAST (C₆ SFA-styrene copolymer)” refers to a sample type in which the molecular weight was controlled, while “Bulk-polymerized poly-FAST (C₆ SFA-styrene copolymer)” and “Bulk-polymerized poly-FAST (C₈ SFA-styrene copolymer)” refer to sample types in which the molecular weight was not controlled.

E. Viscosity of CO₂ thickened by PD1 (embodiment of present invention)
Figure 19 shows the relative viscosity at 25°C and different pressures (in psig) of CO₂ thickened by a C₆ SFA homopolymer having a number-average molecular weight of greater than 250,000 (example “PD1”) dissolved in concentrations of 0.5 weight%, 1 weight%, and 5 weight%. Relative viscosity is defined as the viscosity of the measured sample divided by the viscosity of pure CO₂ under the same conditions. In Figure 19, the relative viscosity is plotted along the ordinate in logarithmic scale. The table in Figure 23 summarizes the numerical data plotted in Figure 19.

Figure 20 shows the viscosity (in cp) at 25°C and different pressures (in psig) of pure CO₂ and of CO₂ thickened by a C₆ SFA homopolymer having a number-average molecular weight of greater than 250,000 (example “PD1”) dissolved in concentrations of 0.5 weight%, 1 weight%, and 5 weight%. In Figure 20, the viscosity (cp) is plotted along the ordinate in logarithmic scale. The table in Figure 24 summarizes the numerical data plotted in Figure 20.

F. Viscosity of CO₂ thickened by 1 weight% (and other weight%) of various polymers
Figure 21 shows the viscosity (in cp) at 25°C and different pressures (in psig) of pure CO₂ and of CO₂ thickened by the polymers listed in the table of Figure 18 dissolved in a concentration of 1 weight%. In Figure 21, the viscosity (cp) is plotted along the ordinate in linear scale. The table in Figure 25 summarizes the numerical data plotted in Figure 21.

It can be seen that the examples of the present invention, PD1 and PD1c, exhibit remarkable effects in increasing the viscosity of CO₂.

Figure 22 shows the relative viscosity at 25°C and different pressures (in psig) of CO₂ thickened by the polymers listed in the table of Figure 18 dissolved in various concentrations. In Figure 22, the relative viscosity is plotted along the ordinate in logarithmic scale. The table in Figure 26 summarizes the numerical data plotted in Figure 22.

It can be seen again that the examples of the present invention, PD1 and PD1c, exhibit remarkable effects in increasing the viscosity of CO₂.

Now that exemplary embodiments of the present invention have been shown and described in detail, various modifications and improvements thereon will become readily apparent to those skilled in the art.

It will be understood that one or more of the elements or exemplary embodiments described can be rearranged, separated, or combined without deviating from the scope of the present invention. For ease of description, various elements are, at times, presented separately. This is merely for convenience and is in no way meant to be a limitation.

Further, it will be understood that one or more of the steps described can be rearranged, separated, or combined without deviating from the scope of the present invention. For ease of description, steps are, at times, presented sequentially. This is merely for convenience and is in no way meant to be a limitation.

While the various elements, steps, and exemplary embodiments of the present invention have been outlined above, it is evident that many alternatives, modifications, and variations will be apparent to those skilled in the art. The various elements, steps, and exemplary embodiments of the present invention, as described above, are intended to be illustrative, not limiting. Various changes can be made without departing from the spirit and scope of the present disclosure. Accordingly, the spirit and scope of the present disclosure is to be construed broadly and not limited by the foregoing specification.

No element, act, or instruction used in the description of the present invention should be construed as critical or essential unless explicitly described as such. Also, as used herein, the article “a” is intended to include one or more items. Where only one item is intended, the term “one,” “single,” or similar language is used.

The present invention has industrial applicability in that it provides, among other things, a polymeric compound useful in improving EOR technology.

Claims (6)

1. A polymer represented by poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate).
2. The polymer according to claim 1, having a number-average molecular weight of greater than 250,000 as measured by gel permeation chromatography.
3. A single-phase composition comprising carbon dioxide and a polymer represented by poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate).
4. The single-phase composition according to claim 3, wherein the polymer has a number-average molecular weight of greater than 250,000 as measured by gel permeation chromatography.
5. A method of recovering oil from underground, comprising the step of injecting a composition containing carbon dioxide and a polymer represented by poly(3,3,4,4,5,5,6,6,7,7,8,8,8-tridecafluorooctyl acrylate) into an underground region.
6. The method according to claim 5, wherein the polymer has a number-average molecular weight of greater than 250,000 as measured by gel permeation chromatography.

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