HOT POLYMER INJECTION FOR IMPROVING HEAVY OIL RECOVERY

Abstract

A method for retrieving heavy oil from a reservoir is provided. In the method, an injection well traversing a subsurface into a reservoir containing a heavy oil is treated via introducing a hot aqueous-based fluid into the reservoir through the injection well. The hot aqueous-based polymer solution may be heated to a temperature above the injection well prior to injecting it into the injection well. The method further includes recovery of a heavy oil mixture from a production well of the reservoir.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Pat. Application Serial No. 63/267,349, which was filed on Jan. 31, 2022, and is incorporated herein by reference

BACKGROUND

Heavy oil is a type of oil that is different from conventional oil in that it is much more difficult to recover from a subsurface reservoir. Consequently, up to one-third to one-half of the original heavy oil is left in most reservoirs. However, the rapid rise in global oil demand has generated interest in the recovery of heavy oil. Generally, heavy oil has a higher density, higher viscosity, and lower mobility when compared to conventional oil. The exact definition of heavy oil is not agreed upon by the experts; however, most definitions are based on viscosity, density, and American Petroleum Institute (API) gravity. Heavy oil is usually defined as oil that has a viscosity ranging from 100 to 10,000 cP (centipoise) at reservoir temperature, density ranging from 943 to 1,000 kg/m3, and API gravity of less than 20° or less than 10° API. Density is used to characterize heavy oil only if viscosity measurements are not available.

The resources of global heavy oil are estimated to be more than twice those of conventional light crude oil; however, recovery rates for heavy oil are often limited. There are several challenges and hurdles to the recovery of heavy oil. The extremely high density and viscosity of the heavy oil impedes its ability to flow from the subsurface reservoirs to the production wells under normal reservoir conditions. Current methods attempted or proposed to recover heavy oils include waterflooding, thermal methods and vapor extraction.

Waterflooding is recognized as a cost-effective oil recovery technique for conventional oil production. However, waterflooding for heavy oil reservoir typically achieves low oil recovery due to the large difference in viscosity between water and heavy oil, and hence a poor mobility ratio is associated with water flooding in heavy oil recovery.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In one aspect, embodiments disclosed herein relate to a method for retrieving heavy oil from a reservoir. In such embodiments the method may include providing an injection well traversing a subsurface into the reservoir containing a heavy oil, introducing a hot aqueous-based fluid into the reservoir via the injection well, and retrieving the heavy oil mixture from a production well of the reservoir. The hot aqueous-based fluid of one or more embodiments may include a polymer and an aqueous carrier fluid.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a flow chart of a method 100 in accordance with one or more embodiments.

FIG. 2 is a graph of viscosity of a heavy oil sample as a function of temperature in accordance with one or more embodiments.

FIG. 3 is a diagram that illustrates a well environment in accordance with one or more embodiments

FIG. 4 is a graph of viscosity of an aqueous-based polymer solution as a function of concentration at different temperatures in accordance with one or more embodiments.

FIG. 5 is a graph of mobility ratio of a heavy oil sample as a function of polymer concentrations in an aqueous-based fluid at different temperatures in accordance with one or more embodiments.

DETAILED DESCRIPTION

The present disclosure generally relates to a method of recovering heavy oil using a hot polymer injection fluid. The disclosed method provides the advantage of utilizing thermal techniques to effectively lower the viscosity of heavy oil. The methods described herein combine thermal techniques with polymer flooding to improve the mobility ratio of the reservoir and provide better oil recovery of heavy oil.

In one or more embodiments, the present disclosure relates to a flooding method to improve and enhance the recovery of heavy oil from a subsurface reservoir. FIG. 1 shows a flow chart of a method 100 in accordance with one or more embodiments. The method involves heating an aqueous-based solution 110. The aqueous-based solution in accordance with one or more embodiments also generally includes a polymer. After heating the aqueous-based solution including the polymer, the solution is introduced 120 into a heavy oil reservoir.

As described above, a heavy oil reservoir may be characterized as an oil and gas production site with uniquely high viscosity of targeted products. Viscosity is a property of fluids and slurries that indicates their resistance to flow, defined as the ratio of shear stress to shear rate. This resistance to the flow of the viscous heavy oil may cause difficulties in its production and may determine the success or failure of an oil recovery method. As such, viscosity is also a key parameter for performing simulations and determining the economic viability of an oil recovery project.

Heavy oil of the reservoir may have low mobility due to an inherently high viscosity as described above. Heavy oil may be defined as the oil with a viscosity ranging from 100 to 10,000 cP (centiPoise) at a reservoir temperature. As is understood by those skilled in the art, the viscosity of oil may be measured using a traditional rheometric instrument, such as an Anton-Paar rheometer. The reservoir temperature affects the viscosity of heavy oil as shown in FIG. 2. For example, the reservoir temperature may be elevated such that the viscosity of the heavy oil may be reduced. In such embodiments, a temperature of at least 60° C. may be sufficient to reduce the viscosity of the heavy oil.

As one skilled of the art may appreciate, a high viscosity heavy oil reservoir may have a high resistance to flow. The high viscosity of the heavy oil causes low oil recovery and production from such reservoirs. In such reservoirs, an efficiency of an injection fluid for heavy oil recovery may be defined by a mobility ratio.

In one or more embodiments, the mobility ratio may be defined as a ratio of the mobility of an injection fluid to that of a heavy oil of a reservoir as shown in Equation 1, below.

$MobilityRatio=\left(\raisebox{1ex}{$K_D$}\!\left/ \!\raisebox{-1ex}{$K_d$}\right.\right)\left(\raisebox{1ex}{${\mu }_d$}\!\left/ \!\raisebox{-1ex}{${\mu }_D$}\right.\right)$

where K_D and K_d are permeabilities of displacing and displaced fluids, respectively, µ_d is the viscosity of the displaced fluid, such as the viscosity of the heavy oil of the reservoir, and µ_D is the viscosity of the displacing fluid, such as the viscosity of the hot aqueous-based fluid as described in embodiments of the present disclosure.

As noted above, an aqueous-based solution including a polymer may be used as an injection fluid for heavy oil recovery. The injection fluid may be an aqueous-based carrier fluid. In particular embodiments of the present disclosure, a temperature of the aqueous-based fluid may be affected to achieve a desired mobility ratio. For example, the mobility ratio of a reservoir with heavy oil deposits may be elevated when flooding with an aqueous-based fluid at a temperature of 60° C. and below.

The temperature of the aqueous-based fluid may be affected such that the temperature is elevated. The elevated temperature of the aqueous-based fluid produces a hot aqueous-based fluid. The hot aqueous-based fluid reduces a viscosity of heavy oil of a reservoir upon contact such that the hot aqueous-based fluid increases the mobility of heavy oil via localized heating. In effect, the localized heating decreases the viscosity of heavy oil. In such embodiments, the hot aqueous-based fluid reduces the mobility ratio of the reservoir.

The temperature of the aqueous-based fluid may be elevated to a temperature higher than a reservoir but lower than a boiling point of the aqueous-based fluid. The temperature of the hot aqueous fluid injected into the reservoir may be in a range from 10° C. to about 100° C. above the reservoir temperature, such as from a lower limit of about 10° C., 15° C., 20° C., 25° C., 30° C., 35° C., 40° C., 45° C., or 50° C. above the reservoir temperature, to an upper limit of about 55° C., 60° C., 65° C., 70° C., 75° C., 80° C., 85° C., 90° C., 95° C., or 100° C. above the reservoir temperature. As noted above, it is desired to maintain the hot aqueous-based fluid as a liquid within the reservoir, and thus an upper limit for injection temperature of the water may depend upon the pressure of the specific reservoir.

The aqueous-based fluid includes water. The water may be distilled water, deionized water, tap water, fresh water from surface or subsurface sources, production water, formation water, natural and synthetic brines, brackish water, natural and synthetic sea water, black water, brown water, gray water, blue water, potable water, non-potable water, other waters, and combinations thereof, that are suitable for use in a wellbore environment. In one or more embodiments, the water used may naturally contain contaminants, such as salts, ions, minerals, organics, and combinations thereof, as long as the contaminants do not interfere with the tracer particle operations.

Generally, a polymer used in heavy oil recovery is composed of water-soluble molecules that increase the viscosity of an aqueous-based fluid. For example, increasing the viscosity of the hot aqueous-based fluid improves the mobility ratio between the hot aqueous-based fluid and the heavy oil such that the mobility ratio is sufficiently decreased. Additionally, injecting a polymer solution, such as the hot aqueous-based solution including the polymer, into the reservoir may increase the reservoir pressure more effectively than water flooding, especially in heavy oils. This is because the polymer solution reduces the water-cut (the water fraction in the total liquid produced).

Although increasing the temperature of the hot aqueous-based solution that includes the polymer may decrease the viscosity, the reduction in viscosity as a function of temperature is lower than the reduction rate of the viscosity occurring with heavy oil. In one or more embodiments, an optimal temperature for the minimum heavy oil viscosity maintains the lowest possible mobility ratio without impacting a stability of the polymer as a function of temperature. The optimal temperature may be determined based on laboratory experiments. The laboratory experiments may be performed for a specific reservoir. As one of ordinary skills in the art may appreciate, the laboratory experiments may include experiments to evaluate the variations of oil and polymer viscosities with temperature. Thus, the mobility ratio may be sufficiently decreased to allow for increased heavy oil production of the reservoir. In such embodiments, the mobility ratio may be decreased to a value below 1.

The water-soluble polymer may be included in a concentration of the aqueous-based solution in an amount ranging from 0.001 to 5 wt% (weight percent) based on the total weight of the aqueous-based fluid. For example, the amount of water-soluble polymer may have a lower limit of one of 0.001, 0.01, 0.05, 0.10, 0.20, 0.50, 1.0, 1.5, 2.0 and 2.5 wt% and an upper limit of one of 1.0, 1.5, 2.0, 2.5, 3.0, 3.5, 4.0, 4.5 and 5.0, where any lower limit pay be paired with any mathematically compatible upper limit. In one or more embodiments, the polymer concentration in the aqueous-based fluid may be determined based on a measured heavy oil viscosity of a reservoir. In such embodiments, an oil viscosity may determine a requisite viscosity of the injected solution. The requisite viscosity of the injected solution is dependent upon the concentration of the polymer of the aqueous-based solution.

Non-limiting examples of the polymers that may be included in the aqueous solution are partially hydrolyzed polyacrylamides; copolymers of acrylamide and acrylate; copolymers of acrylamide tertiary butyl sulfonate (ATBS) and acrylamides; terpolymers of acrylamide, acrylic acid and ATBS; Xanthan gum and scleroglucan.

In one or more embodiments, the polymer may be a copolymer. In particular embodiments, the copolymer may include N-vinylpyrrolidone monomers (NVP), sulfonated monomers, such as ATBS, and combinations thereof into acrylamide-based polymers. As someone skilled in the art may appreciate, polymers with longer chains and higher molecular weights may be included in the aqueous-based solution.

In particular embodiments, the polymer may be a copolymer of acrylamide and ATBS. The copolymerized ATBS may be in a range from about 25 to 99 mol percent (mol%) with respect to the acrylamide. For example, the copolymerized acrylamide-ATBS may include 90 mol% ATBS. The copolymerized acrylamide-ATBS may have a molecular weight in a range from about 5 million Daltons (Da) to about 30 million Da.

In one or more embodiments, the polymer of the aqueous-based solution may have a thermal stability such that the polymer does not degrade at elevated temperature. The polymer may have a molecular weight in a range from about 5 million Daltons (Da) to 30 million Da, such as from a lower limit of about 5 million Da, 10 million Da, or 15 million Da to an upper limit of about 20 million Da, 25 million or 30 million Da.

In one or more embodiments, viscosifiers, polymers, surfactants, and combinations thereof may be added to the aqueous fluid to enhance the dispersion stability of the tracers in the fluid. Suitable surfactants may include anionic surfactants, cationic surfactants, and zwitterionic surfactants known in the art. Non-limiting examples of viscosifiers include xanthan gum, polymers commonly used in enhanced oil recovery operations, such as AN-132, and combinations thereof.

FIG. 3 is a diagram that illustrates a well environment in accordance with one or more embodiments. The well environment 300 includes a surface 335, which represents the surface of the earth. The surface 335 may be located above water, under water, or under ice. Below the surface 335 is the subsurface 337 comprising a reservoir 310 containing heavy oil 333 having a reservoir top 315 and a reservoir bottom 320. Above the reservoir top 315 is a fluid-impenetrable overburden 325, which is part of the well environment 300. Below the reservoir bottom 320 is the underburden 330, which is also part of the well environment 300.

Traversing through subsurface environment is well injection system 400. The well injection system 400 includes an injection well 405 with an injection well bottomhole 410, an aqueous fluid storage 420, an aqueous fluid heater 422, and a polymer storage 425. The bottomhole 410 of the injection well 405 is positioned within the reservoir 310. In one or more embodiments, if the underburden 330 is porous or permits fluid migration, the injection well 405 may transverse the reservoir bottom 320 where the injection well bottomhole 410 is positioned in the underburden 330. The well injection system 400 also includes a recovery or production well 430 that is utilized to collect the heavy oil 333. The bottomhole 435 of the production well 430 is positioned within the reservoir 310. The reservoir may be a partially depleted reservoir because other non-heavy oils may have been produced by conventional methods. As such, many characteristics of the reservoir, such as the fracture pressure, may already be known before the present heavy oil recovery method is initiated.

FIG. 3 shows that an aqueous fluid is dispensed from the aqueous fluid storage 420 to the aqueous-based fluid water heater 422. The aqueous-based fluid may be heated to a temperature higher than that of the reservoir but lower than the boiling point of water at the prevailing reservoir pressure. The polymer may then be introduced from the polymer storage 425 to the hot aqueous-based fluid and dissolved. In alternative embodiments, the polymer may be added to the aqueous-based fluid heater 422 before heating. The hot aqueous-based fluid including the polymer 421 is further dispensed from the aqueous-based heater 422 and introduced into the reservoir 310 through the injection well 405. The hot aqueous based fluid including the polymer 421 traverses into the reservoir 310 for some distance away from the injection well bottomhole 410. If desired, prior to heating and injecting the hot aqueous-based fluid including the polymer, the aqueous-based fluid may be pre-treated to meet the heater requirements and the injection requirements for the specific reservoir, and such aqueous-based fluid treatment may include filtration, reduction in total dissolved solids (salt removal), and other injection system treatments known to those skilled in the art.

The hot aqueous-based fluid including the polymer 421 is introduced into the reservoir 310 through the injection well 405 and traverses into the reservoir 310 for some distance away from the injection well bottomhole 410. The hot aqueous-based fluid including the polymer 421 increases the viscosity of the water thereby reducing the water fingering and increasing a sweep of the reservoir. In one or more embodiments, the hot aqueous-based fluid including the polymer 421 is injected at a pressure sufficient to promote heavy oil flow towards the production well. However, the pressure should be maintained below the fracture pressure of a formation.

The heavy oil 333 that interacts with the hot aqueous-based fluid including the polymer 421 has lower viscosity and migrates through the reservoir 310 and towards the production well bottomhole 435. The heavy oil 333 with lower viscosity flows through the production well 430 and is collected/retrieved and further processed at the surface 335. The aqueous-based fluid including the polymer 421 is also recovered via the production well, and may be separated from the heavy oil and reused for continued heavy oil production or disposed.

In one or more embodiments, the hot aqueous-based solution including the polymer may decrease heavy oil viscosity to 10% to 80% of an original value of the viscosity of heavy oil.

In one or more embodiments, the hot aqueous-based solution including the polymer may decrease the mobility ratio of the reservoir to a range of 0.1 to 2.

EXAMPLES

In both examples provided below, a copolymer of acrylamide and ATBS was employed. ATBS content was 90 mol% . The resultant molecular weight of the copolymer was around 14 million Daltons.

Example 1: Evaluation of Temperature Effect on Polymer Viscosity

Aqueous-based polymer solutions were formulated using the copolymer described above at various concentrations. Polymer solutions were formulated using concentrations ranging from 2000-10,000 ppm (parts per million) of the copolymer of acrylamide and ATBS. The polymer powder was dissolved in a brine with 57,670 ppm total dissolved solids (TDS). Solutions were either heated to 80° C. or maintained at 32° C., and the viscosities were measured. The viscosity was measured using an Anton-Paar rheometer (Anton-Paar USA Inc, Ashland, VA).

FIG. 4 shows the viscosities of various solutions at 32° C. and 80° C. As shown, heated solutions including the polymer maintained relatively a low viscosity. In contrast, polymer solutions at reservoir temperature (32° C.) indicated the desired increase in viscosity, which is necessary to decrease the mobility ratio of a reservoir. However, the reduction in viscosity as a function of temperature is less than the reduction rate occurring with heavy oil. Experiments to further support this were performed and shown in Example 2.

Example 2: Evaluation of Temperature Effect on Mobility Ratio

It is generally understood that the relative permeability is independent of temperature. Therefore, the variation of mobility ratio with respect to temperature is only dependent on the viscosity ratio of oil to the displacing phase (i.e. aqueous phase). For simplicity, the mobility ratio was calculated by assuming the ratio of aqueous phase permeability to oil permeability in Equation 1 is 1.0. Results of FIG. 5 were derived from results obtained from FIGS. 2 and 4.

As displayed in FIG. 5, the required concentration to reach a favorable mobility ratio of 1 or lower was determined to be 4,700 ppm of polymer at 80° C. This result was a substantially decreased polymer concentration compared to 8,800 ppm polymer concentration at reservoir temperature. Thus, it was also determined that it is possible to obtain lower mobility ratios at temperatures higher than reservoir temperature. In addition, results shown in FIG. 5 indicate the possibility of reaching a favorable range of mobility equal or less than 1, with lower polymer concentration. Moreover, the results indicate that the mobility ratio of can still be high if low polymer concentration of a non-heated aqueous-based solution is used in a reservoir.

Embodiments of the present disclosure indicate that the present method for recovering heavy oil from a reservoir mitigates a challenging aspect associated with the recovery of heavy oil, which is the unfavorable mobility ratio of the reservoir. In such embodiments, the hot aqueous-based fluid injected into a reservoir may penetrate to locations of the reservoir where heavy oil may be located. This improves the overall sweep of the reservoir. As such, the hot aqueous-based fluid injected into the reservoir will flow into lower permeability zones even when the permeability of the upper layers is higher than that of the lower layers. This characteristic of hot aqueous-based fluid injection may be contrasted with characteristics of steam injection, which is commonly employed for heavy oil recovery. In steam injection, the steam tends to preferentially sweep the upper layers of the reservoir while inefficiently sweeping the lower layers of the reservoir.

Unlike steam flooding which requires clean water for steam generation, polymer flooding can use lower quality water, therefore it is also less expensive. As described above, traditional polymer flooding is also used to improve the mobility ratio during the recovery of heavy oil, but very high concentrations of polymer solution may be required to measurably decrease the mobility ratio. In one or more embodiments of the method of the present disclosure, decreased concentrations of polymers may be used in the recovery of heavy oil. In effect, decreased costs of operation may be achieved.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

1. A method for retrieving heavy oil from a reservoir, the method comprising:

providing an injection well traversing a subsurface into the reservoir containing a heavy oil;

introducing a hot aqueous-based fluid into the reservoir via the injection well, wherein the hot aqueous aqueous-based fluid comprises a polymer and an aqueous carrier fluid; and

retrieving the heavy oil from a production well of the reservoir.

2. The method of claim 1, wherein the hot aqueous aqueous-based fluid comprises the polymer in a concentration in a range of from about 0.001 wt% to 5.0 wt.% based on a total weight of the aqueous-based fluid.

3. The method of claim 1, wherein the polymer is selected from a group consisting of partially hydrolyzed polyacrylamides, copolymers of acrylamide and acrylate, copolymers of acrylamide tertiary butyl sulfonate (ATBS) and acrylamides, copolymers of acrylamide, acrylic acid and ATBS, Xanthan gum, scleroglucan, and combinations thereof.

4. The method of claim 1, wherein the polymer comprises a copolymerized of an acrylamide and ATBS.

5. The polymer of claim 4, wherein the polymer comprises ATBS in a range of 25 mol % to 99 mol % based on the acrylamide.

6. The polymer of claim 4, wherein the polymer has a molecular weight in a range of 5 million Daltons (Da) and 30 million Da.

7. The method of claim 1, wherein a temperature of the hot aqueous-based fluid is higher than that of the reservoir but lower than a boiling point of water at a prevailing reservoir pressure.

8. The method of claim 1, wherein a temperature of the hot aqueous aqueous-based fluid is in a range from about 10° C. to 100° C. above reservoir temperature.

9. The method of claim 1, wherein the hot aqueous-based fluid decreases a viscosity of the heavy oil to 10% to 80% of an original value of a viscosity of heavy oil.

10. The method of claim 1, wherein the hot aqueous-based fluid decreases a mobility ratio of the reservoir to a range of 0.1 to 2.