US20140014375A1

US20140014375A1 - Enhanced oil recovery methods for producing oil from heavy oil fields

Info

Publication number: US20140014375A1
Application number: US13/718,853
Authority: US
Inventors: Paulus Maria BOERRIGTER; Raul Valdez
Original assignee: Shell Oil Co
Current assignee: Shell USA Inc
Priority date: 2011-12-28
Filing date: 2012-12-18
Publication date: 2014-01-16
Also published as: CA2862251A1; CN104066925A; RU2014131095A; WO2013101520A1

Abstract

The present disclosure relates to enhanced oil recovery methods for highly viscous oil reservoirs containing large amounts of mobile water. One method includes injecting a carbon disulfide formulation or fluid into the formation via a first well and displacing the mobile water from the formation with the carbon disulfide fluid. The highly viscous oil is then solubilized using the carbon disulfide fluid, thereby generating a mixture of mobilized oil. The mixture of mobilized oil is then forced towards a second well and subsequently produced from the second well.

Description

The present application claims the benefit of U.S. Patent Application No. 61/580,906, filed Dec. 28, 2011, the entire disclosure of which is herby incorporated by reference.

FIELD OF THE INVENTION

The present disclosure relates to enhanced oil recovery methods and, in particular, producing highly viscous oil from oil reservoirs that contain large amounts of mobile water.

BACKGROUND

Enhanced oil recovery (EOR) is used to increase oil recovery in hydrocarbon-bearing rock formations worldwide. There are basically three main types of EOR methods: thermal, chemical/polymer, and gas injection, each of which may be used worldwide to increase oil recovery from a reservoir beyond what would otherwise be possible with conventional hydrocarbon extraction means. These methods may also extend the life of the reservoir or otherwise boost its overall oil recovery factor.
Briefly, thermal EOR works by adding heat to a hydrocarbon-bearing reservoir. The most widely practiced form of thermal EOR uses steam which serves to reduce the viscosity of the oil so that the oil is able to freely flow to adjacent producing wells. Chemical EOR, on the other hand, entails flooding the reservoir with a chemical agent or solvent designed to reduce the capillary forces that trap residual oil, and thereby increase hydrocarbon recovery. Polymer EOR entails flooding the hydrocarbon-bearing reservoir with a polymer, which increases hydrocarbon recovery and improves the sweep efficiency of injected fluids. Gas injection, also known as miscible injection, works somewhat similar to chemical EOR in that it involves injecting a gas that is miscible with the oil to mobilize trapped residual oil for recovery.
In very heavy oil reservoirs that contain large amounts of mobile water, however, conventional EOR techniques are unable to efficiently mobilize and produce the oil, and therefore, the reservoirs remain unproduced or produced at a less than desirable level. At least one reason for the formation of mobile water in a heavy oil reservoir is that the reservoir has undergone a period of biodegradation. This leads to shrinkage of the volume of oil initially in place as well as an increase in the overall viscosity of the oil and a decrease in the overall API gravity of the oil. The pore volume that becomes available due to the oil shrinkage will generally become occupied with water, such as from an adjacent aquifer. Over time, the water saturation gradually increases above connate water saturation (i.e., immovable water that is trapped in the formation), thereby filling the available pore volume with large quantities of mobile water. The mobility of the heavy oil, however, remains very low due to its high viscosity.
Heavy oil reservoirs also typically suffer from low initial oil saturation, where very small amounts of highly-viscous oil are able to be produced, but instead large amounts of mobile water are produced. These reservoirs are unable to be efficiently produced using thermal EOR, for example, since the thermal energy is almost entirely absorbed by the mobile water. As a result, thermal EOR is not an economically viable option.

SUMMARY OF THE INVENTION

In one aspect, the present invention is directed to a method for producing oil, comprising, placing a carbon disulfide fluid into a formation comprising oil and mobile water, wherein the formation oil has a viscosity of at least 1000 cP at 20° C.; displacing the mobile water in the formation with the carbon disulfide fluid; contacting the carbon disulfide fluid with the oil in the formation to generate mobilized oil comprised of a mixture of the solvent and the formation oil; displacing the mobilized oil through the formation; and producing the displaced mobilized oil from the formation.
In another aspect, the present invention is directed to a method for producing oil from a formation containing oil and mobile water, comprising: placing a solvent into the formation, the formation having an initial total water saturation at least 10% greater than the connate water saturation in the formation; displacing the mobile water in the formation with the solvent so as to expose the oil in the formation to the solvent; and contacting the exposed oil with the solvent to generate a mobilized oil comprised of a mixture of the solvent and the formation oil.
The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present invention, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure.

FIG. 1 illustrates a system for producing hydrocarbons from an underground reservoir, according to one or more embodiments.

FIG. 2 a illustrates a well pattern, according to one or more embodiments.

FIG. 2 b illustrates the well pattern of FIG. 2 a during an exemplary enhanced oil recovery process, according to one or more embodiments.

FIGS. 3 a and 3 b illustrate line graphs showing how the viscosity of oil generally decreases corresponding to its interaction with a solvent, such as carbon disulfide.

FIG. 4 illustrates a view of an underground formation during an exemplary enhanced oil recovery process, according to one or more embodiments.

FIGS. 5 a, 5 b, and 5 c illustrate progression models depicting how a solvent interacts with a formation containing highly viscous oils and mobile water.

FIG. 6 illustrates an exemplary method timeline of injection and production using an exemplary enhanced oil recovery process, according to one or more embodiments.

DETAILED DESCRIPTION

The present disclosure relates to enhanced oil recovery methods and, in particular, producing highly viscous oil from oil reservoirs that contain large amounts of mobile water. The mobile water present in the reservoirs proves to be disadvantageous in thermal EOR applications but, surprisingly, a key advantage in the methods disclosed herein. As a solvent or other miscible enhanced oil recovery agent is injected into the formation to mobilize the heavy oil, the mobile water is displaced and thereby provides a path and sufficient formation volume for the solvent to contact and become miscible with the heavy oil. The solvent is believed to solubilize the oil to create a mixture of solvent and oil that exhibits a lower viscosity than the non-solubilized oil. The mixture is then able to be efficiently mobilized and recovered with standard drive methods.
Referring to FIG. 1, illustrated is a system 100 used to produce hydrocarbons (e.g., oil and/or gas) from an subterranean hydrocarbon-bearing formation, such as an oil reservoir. Specifically, the system 100 may be configured to extract hydrocarbons from one or more of a first subterranean formation 102, a second subterranean formation 104, a third subterranean formation 106, and/or a fourth subterranean formation 108. As illustrated, a production facility 110 is generally provided at the surface and a well 112 extends from the surface and through the first and second formations 102, 104, ultimately terminating within the third formation 106. The third formation 106 may include one or more adjacent formation portions 114 from which hydrocarbons or other fluids may be produced and conveyed to the production facility 110 via the well 112. Gases and liquids are separated from each other at the production facility 110, and the extracted gas is stored in a gas storage 116 while the extracted liquid is stored in a liquid storage 118.
Referring to FIG. 2 a, illustrated is a plan view of an exemplary array 200 of wells, according to one or more embodiments. In some embodiments, each of the wells depicted in the array 200 and described below may be substantially similar to the well 112 described above with reference to FIG. 1. As illustrated, the array 200 includes a first well group 202 (denoted by horizontal cross-hatching) and a second well group 204 (denoted by diagonal cross-hatching). In some embodiments, the array of wells 200 may include a total of between about 10 wells and about 1000 wells. For example, the array of wells 200 may include between about 5 wells and about 500 wells from the first well group 202, and between about 5 wells and about 500 wells from the second well group 204.
Each well in the first well group 202 may be arranged a first lateral distance 230 and a second lateral distance 232 from any adjacent well in the first well group 202. The first and second lateral distances 230, 232 may be generally orthogonal to each other. Likewise, each well in the second well group 204 may be arranged a first lateral distance 236 and a second lateral distance 238 from any adjacent well in the second well group 204, where the first and second lateral distances 236, 238 may also be generally orthogonal to each other. Moreover, each well in the first well group 202 may be a third distance 234 from any adjacent wells pertaining to the second well group 204. As a result, each well in the second well group 204 is also the third distance 234 from any adjacent wells belonging to the first well group 202.
In some embodiments, each well in the first well group 202 may be surrounded by four individual wells belonging to the second well group 204. Likewise, each well in the second well group 204 may be surrounded by four individual wells belonging to the first well group 202. In some embodiments, the first and second lateral distances 230, 232 may range from about 5 meters to about 1000 meters, for example, from about 10 meters to about 500 meters, from about 20 meters to about 250 meters, from about 30 meters to about 200 meters, from about 50 meters to about 150 meters, from about 90 meters to about 120 meters, or about 100 meters. Similarly, in some embodiments, the first and second lateral distances 236, 238 may range from about 5 meters to about 1000 meters, for example, from about 10 meters to about 500 meters, from about 20 meters to about 250 meters, from about 30 meters to about 200 meters, from about 50 meters to about 150 meters, from about 90 meters to about 120 meters, or about 100 meters. Moreover, the third distance 234 may range from about 5 meters to about 1000 meters, for example, from about 10 meters to about 500 meters, from about 20 meters to about 250 meters, from about 30 meters to about 200 meters, from about 50 meters to about 150 meters, from about 90 meters to about 120 meters, or about 100 meters.
While FIG. 2 a is described above as depicting a top view of the array of wells 200, where the first and second well groups 202, 204 are vertically-disposed wells, FIG. 2 a may equally and without limitation illustrate a cross-sectional side view of the array 200, without departing from the scope of the disclosure. For instance, FIG. 2 a may alternatively illustrate a cross-sectional side view of the array 200 where the first and second well groups 202, 204 are depicted as horizontally-disposed wells within a subterranean formation. Accordingly, it will be appreciated that the systems and methods disclosed herein may equally function whether the first and second well groups 202, 204 are disposed vertically or horizontally, or combinations thereof.
Oil recovery from an subterranean formation using the array of wells 200 may be accomplished by any known method. Suitable methods include subsea production, surface production, primary, secondary, or tertiary production, and the like. In some embodiments, as described above with reference to FIG. 1, oil may be recovered from a formation 102, 104, 106, 108 into a well 112, and flow through the well 112 to a production facility 110 for processing. In some embodiments, enhanced oil recovery (EOR) techniques may be used, and even required, in order to increase the flow of oil from the formation(s) 102, 104, 106, 108. The exemplary EOR techniques described herein may be especially helpful in oil recovery from reservoirs that exhibit amounts of very heavy crude oil and large quantities of mobile water.
Oil present in the formation(s) 102, 104, 106, 108 may have a viscosity at 20° C. of at least about 100 centipoise (cP), at least about 500 cP, at least about 1000 cP, at least about 2000 cP, at least about 5000 cP, or at least about 10,000 cP. In other embodiments, the oil present in the formation(s) 102, 104, 106, 108 may have a viscosity at 20° C. of up to about 10,000,000 cP, up to about 5,000,000 cP, up to about 2,000,000 cP, up to about 1,000,000 cP, or up to about 500,000 cP. At higher viscosities, as can be appreciated, the heavy oil is either nearly immobile or entirely immobile and can only be removed efficiently through aggressive EOR techniques, such as those described herein.
In some embodiments, the elevated viscosity of the heavy oil may be reduced by placing a solvent into the formation(s) 102, 104, 106, 108, for example by injecting a solvent into the formation(s) through a well. In one or more embodiments, the solvent may be a miscible enhanced oil recovery agent that is generally miscible with highly viscous oils and able to mix, solubilize, and mobilize the oil for faster and more efficient recovery. In one or more embodiments, the solvent may be miscible enhanced oil recovery agent that is generally miscible with highly viscous oils and that may displace mobile water in the formation to access oil within the formation. The miscible enhanced oil recovery agent may include, but is not limited to, a carbon disulfide formulation or fluid. The carbon disulfide formulation may include carbon disulfide and/or carbon disulfide derivatives, such as thiocarbonates, xanthates, mixtures thereof, and the like. In other embodiments, the carbon disulfide formulation may further include one or more of the following: hydrogen sulfide, sulfur, carbon dioxide, hydrocarbons, and mixtures thereof. The carbon disulfide formulation may contain at least 30 mol %, or at least 50 mol %, or at least 75 mol %, or at least 90 mol % carbon disulfide, and may consist essentially of carbon disulfide. Other suitable miscible enhanced oil recovery agents or solvents may include, but are not limited to, hydrogen sulfide, carbon dioxide, octane, pentane, liquefied petroleum gases, C₂-C₆aliphatic hydrocarbons, nitrogen, diesel, mineral spirits, naptha solvent, asphalt solvent, kerosene, acetone, xylene, trichloroethane, mixtures of two or more of the preceding, or other miscible enhanced oil recovery agents or solvents as are known in the art. In some embodiments, suitable solvents or miscible enhanced oil recovery agents are first contact miscible or multiple contact miscible with highly viscous oil in the subterranean formation.

EXAMPLES

To facilitate a better understanding of the solubilization of oil, the following examples are given. It will be appreciated that in no way should the following examples be read to limit, or to define, the scope of the invention. Referring briefly to FIGS. 3 a and 3 b, illustrated are exemplary line graphs, respectively, that show how the viscosity of oil generally decreases corresponding to its interaction with a solvent, such as carbon disulfide (CS₂). The first graph as shown in FIG. 3 a depicts oil measurements taken from the Camp Hill, Tex., USA oil reservoir. As indicated, the approximate temperature of the oil in the reservoir is about 20° C. and exhibits a viscosity of about 1000 cP when the volume fraction of carbon disulfide is zero. As the volume fraction of carbon disulfide is increased, however, the viscosity of the oil gradually decreases. For example, at 0.2 (20%) volume fraction of carbon disulfide, the oil exhibits a viscosity of about 30-40 cP at 20° C., which makes the oil fairly mobile and more amenable to extraction.
The second graph as shown in FIG. 3 b depicts oil measurements taken from the Peace River, Alberta, Canada oil reservoir. As indicated, the approximate temperature of the oil in the reservoir is about 20° C. and exhibits a viscosity of about 10,000,000 cP when the volume fraction of carbon disulfide is zero. As the volume fraction of carbon disulfide increases, however, the viscosity of the oil gradually decreases. For example, at 0.3 (30%) volume fraction of carbon disulfide, the oil exhibits a viscosity of about 100 cP at 20° C., which may be sufficiently mobile for some EOR techniques, such as water flooding.
The exemplary methods disclosed herein may be especially suited for the recovery of heavy crude oils (i.e., oils with very high viscosities) found in reservoirs that contain large amounts of mobile water. Reservoirs that contain large amounts of mobile water may include formations where the amount of initial total water saturation (total water saturation=mobile water saturation+connate water saturation) in the formation is greater than the amount of connate water saturation in the formation. In some embodiments, the initial total water saturation is at least 10% or greater than the connate water saturation in order to qualify as a formation having large quantities of mobile water. As used herein, “water saturation” in a formation is used in accordance with its conventional definition, e.g. the percent of the pore volume of a formation occupied by water (total water saturation (%)=[total water volume/pore volume]*100; connate water saturation (%)=[connate water volume/pore volume]*100). The mobile water provides a pathway into the formation for a solvent, such as carbon disulfide, to enter into contact with oil in the formation. In operation, the injected solvent displaces the mobile water which allows the solvent to then contact, mix with, soak into, and solubilize the oil exposed by displacement of the mobile water. The resulting mixture of solvent and oil will exhibit a reduced viscosity and consequently behave like a ‘light’ oil occupying a larger volume than the remaining viscous oil. The volume of mobile water initially in the formation upon displacement of the mobile water provides sufficient formation volume for the less-viscous mixture to collect.
In some embodiments, the respective viscosities of the solvent and the mobile water are on the same order of magnitude, thereby providing for a favorable displacement of the water and corresponding ingress of the solvent, such as a carbon disulfide formulation or fluid. For example, the viscosity of carbon disulfide may range between about 0.2 cP and about 0.3 cP, depending on the ambient pressure and temperature. The viscosity of water, on the other hand, may range between about 0.7 cP and about 1.1 cP at ambient pressure and temperature. As a result, the solvent is able to push the mobile water out of the way and simultaneously contact and solubilize the oil.
In one or more embodiments, the solvent may be mixed or otherwise combined with the viscous oil until the mixture of solvent and oil achieves a viscosity of about 1000 cP or less at 20° C. To accomplish this, the solvent may be contacted with the viscous oil to form a mobilized oil comprising a mixture of solvent and oil that may contain at least 10 vol. %, or at least 20% volume, or at least 30 vol. %, or at least 40 vol. %, or at least 50 vol. %, or greater than a 50 vol. % of solvent. In some embodiments, the mobilized oil may then be displaced for production using one or more drive methods such as, but not limited to, a water/polymer drive, miscible/immiscible displacement, solvent alternated with water, solvent (or other miscible fluid) recirculation, and combinations thereof. As will be discussed in more detail below, the actual production process may include periods of solvent injection, soaking of the solvent in the oil, and follow-up injections of one or more chase fluids, potentially in cycles of different duration.
Referring now to FIG. 2 b, with continued reference to FIG. 2 a, illustrated is the array of wells 200 being treated with one or more exemplary EOR techniques, according to one or more embodiments disclosed. In some embodiments, a solvent (e.g., carbon disulfide) may be injected into the second well group 204, thereby resulting in an injection profile 208. The injected solvent may be configured to displace amounts of mobile water contained in the formation, and either dewater the formation, produce the mobile water via the first well group 202, or simply push the mobile water out of the way so that the solvent can contact the viscous oil. Upon coming into contact with the oil in the formation, including oil exposed by displacing the mobile water in the formation, the injected solvent solubilizes and mobilizes the more viscous oil trapped in the formation such that it may be recovered via the first well group 202, as depicted by a resulting oil recovery profile 206. In one or more embodiments, a chase fluid, such as other miscible or immiscible enhanced oil recovery agents, formulations, or mixtures, may then be injected into the second well group 204, thereby also generating the injection profile 208. In some embodiments, the chase fluid is injected to force or otherwise displace the solvent and the solubilized/mobilized oil toward the first well group 202 for production.
In one or more embodiments, the chase fluid(s) may be characterized as an immiscible enhanced oil recovery agent configured to displaced the mobilized oil and excess solvent through the formation. The immiscible enhanced oil recovery agent may further be configured to reduce the mobility of the water phase in pores of the formation which, as can be appreciated, may allow the solvent to be more easily mobilized through the formation. The immiscible enhanced oil recovery agent may include, but is not limited to, an aqueous polymer fluid, a monomer, a surfactant, water in gas or liquid form, carbon dioxide, nitrogen, air, mixtures of two or more of the preceding, or other immiscible enhanced oil recovery agents as are known in the art. Suitable polymers may include, but are not limited to, polyacrylamides, partially hydrolyzed polyacrylamide, polyacrylates, ethylenic copolymers, biopolymers, carboxymethylcellulose, polyvinyl alcohol, polystyrene sulfonates, polyvinylpyrolidone, AMPS (2-acrylamide-2-methyl propane sulfonate), combinations thereof, or the like. Examples of ethylenic copolymers include copolymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, lauryl acrylate and acrylamide. Examples of biopolymers include xanthan gum and guar gum. In some embodiments, polymers may be crosslinked in situ in a formation. In other embodiments, polymers may be generated in situ in a formation. Moreover, in some embodiments, suitable immiscible enhanced oil recovery agents are not first contact miscible or multiple contact miscible with oil in the formation.
In some embodiments, the solvent may be continuously injected into the first well group 202 for a first time period. Following the first time period, oil, gas, and/or mobile water may be produced from the second well group 204 for a second time period. In other embodiments, following the first time period, one or more chase fluids may be injected into the first well group 202 for a second time period. Oil and/or gas may be produced from the second well group 204 during the first time period, or during the second time period, or during both the first and second time periods, or for a third time period including a period of time after the first time period and the second time period and may include a period of time within the first and/or second time periods. It will be appreciated, however, that the injection and production processes may be carried out through either the first or second well groups 202, 204, without departing from the scope of the disclosure.
The first, second, and third time periods may be predetermined lengths of time which together may be characterized as a complete cycle. In some embodiments, an exemplary cycle may span about 12 hours to about 1 year. In other embodiments, however, the exemplary cycle may span about 3 days to about 6 months, or between about 5 days to about 3 months. In one or more embodiments, each consecutive cycle may increase in time from the previous cycle. For example, each consecutive cycle may be from about 5% to about 10% longer than the previous cycle. In at least one embodiment, a consecutive cycle may be about 8% longer than the previous cycle.
In some embodiments, multiple cycles may be conducted which include alternating well groups 202, 204 between injecting the solvent and/or chase fluids and producing oil, gas, and/or mobile water from the formation. For example, one well group may be injecting and the other well group may be producing for the first time period, and then they may be switched for the second time period.
In some embodiments, the solvent may be injected at the beginning of a cycle, and the chase fluid or flood may be injected at the end of the cycle. In one or more embodiments, the beginning of the cycle may be the first 10% to about 80% of a cycle, the first 20% to about 60% of a cycle, or the first 25% to about 40% of a cycle. The end of the cycle may simply span the remainder of the particular cycle.
Referring now to FIG. 4, illustrated is another system 400 used to produce hydrocarbons (i.e., oil and/or gas) from an subterranean hydrocarbon-bearing formation, such as an oil reservoir. The system 400 may be similar in some respects to the system 100 described above with reference to FIG. 1. Accordingly, the system 400 may be best understood with reference to FIG. 1, where like numerals are used to indicated like components that will not be described again in detail. One or more of the formation(s) 102, 104, 106, 108 may contain highly viscous oil and large amounts of mobile water. The particular formation of interest may initially be identified as a candidate for production via known techniques, such as computer modeling, analytical models, core testing, seismic studies, etc. In one or more embodiments, the production facility 110 may further include a production storage tank 402 and the system 400 may further include a second well 404. Similar to the first well 112, the second well 404 extends through the first and second formations 102, 104 and ultimately terminates within the third formation 106 surrounded by one or more adjacent formation portions 406. It will be appreciated that the adjacent formation portions 114 and 406 of each well 112, 402, respectively, may be optionally fractured and/or perforated to enhance production.
In some embodiments the second well 404 may be representative of a well belonging to the first well group 202, and the first well 112 may be representative of a well belonging to the second well group 204, as described above with reference to FIGS. 2 a and 2 b. In other embodiments, however, the second well 404 may be representative of a well belonging to the second well group 204, and the first well 112 may be representative of a well belonging to the first well group 202.
The production storage tank 402 may be configured to store miscible and/or immiscible enhanced oil recovery agents and/or formulations (i.e., solvents, chase fluids, etc.) for injection into the underground formation(s) 102, 104, 106, 108. In one or more embodiments, the production storage tank 402 is communicably coupled to the second well 404 and configured to provide the solvent and/or chase fluids thereto for injection. In other embodiments, however, the production storage tank 402 may be communicably coupled to the first well 112 and configured to provide solvent and/or chase fluids thereto for injection. In yet other embodiments, the production storage tank 402 may be communicably coupled to both the first and second wells 112, 402 and configured to provide solvent and/or chase fluids to both for injection, without departing from the scope of the disclosure.
In one or more embodiments, the solvent formulation or fluid may be pumped down the second production well 404 and injected into the adjacent formation portions 406 of the third underground formation 106. The solvent, such as a carbon disulfide formulation or fluid, displaces the mobile water contained within the formation 106, thereby exposing heavy oil deposits that can then be contacted with the influx of the solvent. Upon the solvent being contacted with the viscous oil present in the formation 106, the solvent and the oil become miscible resulting in a “mobilized” oil comprising a mixture of the solvent and oil which exhibits a reduced viscosity comparable to a ‘light oil.’ The mobilized oil may be extracted from the formation much more easily than the initial heavy viscous oil.
Referring briefly to FIGS. 5 a, 5 b, and 5 c, illustrated are progression models depicting how a solvent interacts with a formation 502 containing highly viscous oils and large quantities of mobile water. FIG. 5 a depicts a hydrocarbon-bearing formation 502 having a layer of heavy oil initially in place 504, a layer of mobile water 506, and a layer of saturated connate water 508. The connate water 508 may be effectively immobile in the formation 502. FIG. 5 b depicts an injection of the solvent 510 which effectively displaces the mobile water 506 (FIG. 5 a) from the formation 502. In one or more embodiments, the injected solvent is a carbon disulfide formulation or fluid.
As the solvent 510 interacts with the heavy oil 504, a mixture 512 of solvent 510 and oil 504 is generated. The mixture 512 will exhibit a lower viscosity than the heavy oil 504, thereby mobilizing the mixture 512 for production (e.g. producing mobilized oil). At this point, the mobilized oil comprising the mixture of solvent and oil 512 may be produced via an adjacent well using, for example, one or more known drive methods (e.g., water/polymer drive, miscible immiscible displacement, etc.).
In other embodiments, however, the solvent 510 may be allowed to soak into and solubilize the heavy oil 504 for a predetermined amount of time, thereby resulting in a mobilized oil comprising a mixture of oil and solvent 514 having a viscosity comparable to light oil, as shown in FIG. 5 c. In some embodiments, the solvent 510 is allowed to soak into the heavy oil 504 until the mobilized oil 514 achieves a viscosity of about 1000 cP or less (as measured at 20° C.). In other embodiments, the solvent 510 is injected or otherwise allowed to soak into the heavy oil 504 until the mobilized oil mixture of oil and solvent 514 contains at least 10 vol. %, or at least 20 vol. % or at least 30 vol. % of solvent. At this point, the mobilized oil may be produced via an adjacent well using, for example, one or more known drive methods (e.g., water/polymer drive, miscible immiscible displacement, etc.).
Referring again to FIG. 4, continual pumping of the solvent via the second well 404 may displace the mixture 512, 514 (FIGS. 5 b and 5 c) across the third underground formation 106, as indicated by the arrows, and ultimately to the first well 112 to be produced to the production facility 110. In other embodiments, however, the solvent flood may be followed by one or more chase fluids (e.g., miscible/immiscible enhanced oil recovery agents, brine, etc.) also injected via the second well 404 into the adjacent formation portions 406 of the third underground formation 106. The injected chase fluids may be configured to improve the displacement stability of the solvent flood and the mixture of the solvent and the oil as each traverses the formation 106.
Referring now to FIG. 6, with continued reference to FIGS. 2 a, 2 b and 4, illustrated is an exemplary method or pattern 600 of injection and production, according to one or more embodiments disclosed. The exemplary pattern 600 may provide an illustration of an exemplary injection and production timing for the first well group 202, as shown by the top timeline, and an exemplary injection and production timing for the second well group 204, as shown by the bottom timeline. As illustrated, injection of a solvent is indicated by a checkerboard pattern, injection of chase fluids is indicated by a diagonal pattern, and the blank areas are indicative of producing oil, gas, and/or mobile water from the formation.
In some embodiments, at time 620, a solvent slug is injected into the first well group 202 for time period 602, while oil, gas, and/or water is produced from the second well group 204 for time period 603. A solvent slug may then be injected into the second well group 204 for time period 605, while oil, gas, and/or water is produced from the first well group 202 for time period 604. This injection/production cycling for well groups 202 and 204 may be continued for any number of cycles, for example from about 5 cycles to about 25 cycles.
In some embodiments, at time 630, there may be a cavity in the formation due to oil, gas, and/or water that has been produced during time 620. During time 630, only the leading edge of cavity may be filled with a solvent slug, which is then pushed through the formation with a chase fluid. For example, a solvent slug may be injected into the first well group 202 for time period 606, then a chase fluid may be injected into the first well group 202 for time period 608, while oil, gas, and/or water may be produced from the second well group 204 for time period 607. In one or more embodiments, a solvent slug may then be injected into the second well group 204 for time period 609, and then a chase fluid may be injected into the second well group 204 for time period 611, while oil, gas, and/or water may be produced from the first well group 202 for time period 610. This injection/production cycling for well groups 202 and 204 may be continued for any number of cycles, for example from about 5 cycles to about 25 cycles.
In some embodiments, at time 640 there may be significant hydraulic communication between the first well group 202 and the second well group 204. In one or more embodiments, a solvent slug may be injected into the first well group 202 for time period 612, then a chase fluid may be injected into the first well group 202 for time period 614 while oil, gas, and/or water may be produced from the second well group 204 for time period 615. The injection cycling of solvent and chase fluids into the first well group 202 while producing oil, gas, and/or water from the second well group 204 may be continued as long as desired, for example as long as oil, gas, and/or water is produced from the second well group 204.
In some embodiments, time periods 602, 603, 604, and/or 605 may be from about 6 hours to about 10 days, for example, from about 12 hours to about 72 hours, or from about 24 hours to about 48 hours. In some embodiments, each of time periods 602, 603, 604, and/or 605 may increase in length from time 620 until time 630. In other embodiments, however, each of time periods 602, 603, 604, and/or 605 may continue relatively unchanged from time 620 until time 630 for about 5 cycles to about 25 cycles, for example from about 10 cycles to about 15 cycles.
In some embodiments, time period 606 is from about 10% to about 50% of the combined length of time period 606 and time period 608, for example from about 20% to about 40%, or from about 25% to about 33%. In some embodiments, time period 609 is from about 10% to about 50% of the combined length of time period 609 and time period 611, for example from about 20% to about 40%, or from about 25% to about 33%. In some embodiments, the combined length of time period 606 and time period 608 is from about 2 days to about 21 days, for example from about 3 days to about 14 days, or from about 5 days to about 10 days. In some embodiments, the combined length of time period 609 and time period 611 is from about 2 days to about 21 days, for example from about 3 days to about 14 days, or from about 5 days to about 10 days. In some embodiments, the combined length of time period 612 and time period 614 is from about 2 days to about 21 days, for example from about 3 days to about 14 days, or from about 5 days to about 10 days.
Referring once again to FIG. 4, after separating the oil from the solvent, mobile water, and/or chase fluids in production facility 110, the solvent formulation may then be processed for recycling and placed back in the production storage vessel 402. Processing the solvent formulation for recycling may include boiling, condensing, filtering, and/or reacting the solvent. Moreover, the oil and/or gas produced may be transported to a refinery and/or a treatment facility. The oil and/or gas may be processed to produced to produce commercial products such as transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. Processing may include distilling and/or fractionally distilling the oil, gas, and/or water to produce one or more distillate fractions. In some embodiments, the oil, gas, and/or water, and/or the one or more distillate fractions may be subjected to a process of one or more of the following: catalytic cracking, hydrocracking, hydrotreating, coking, thermal cracking, distilling, reforming, polymerization, isomerization, alkylation, blending, and dewaxing.
It will be appreciated that the embodiments disclosed herein may be suitable for the recovery of highly viscous oils in formations containing large amounts of mobile oil. However, these same embodiments may be effectively applied in formations containing amounts of light oils where there are also large quantities of mobile water but which are unable to be effectively recovered using conventional EOR techniques.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

What is claimed is:

1. A method for producing oil, comprising:

placing a carbon disulfide fluid into a formation comprising oil and mobile water wherein the formation oil has a viscosity of at least 1,000 centipoise at 20° C.;

displacing the mobile water in the formation with the carbon disulfide fluid;

contacting the carbon disulfide fluid with the oil in the formation to generate mobilized oil comprised of a mixture of the solvent and the formation oil;

displacing the mobilized oil through the formation; and

producing the displaced mobilized oil from the formation.

2. The method of claim 1, wherein displacing the mobile water comprises producing the mobile water from the formation.

3. The method of claim 1, wherein displacing the mobile water comprises contacting the mobile water with the carbon disulfide fluid placed into the formation.

4. The method of claim 1, wherein the formation oil has a viscosity of 1,000,000 centipoise or more at 20° C.

5. The method of claim 4, wherein contacting the carbon disulfide fluid with the formation oil further comprises reducing the viscosity of the oil to 1,000 centipoise or less at 20° C.

6. The method of claim 4, wherein the carbon disulfide fluid is mixed with the oil until the mixture of the solvent and the oil contains at least 20 vol. % of the carbon disulfide fluid.

7. The method of claim 1, wherein contacting the carbon disulfide fluid with the formation oil further comprises reducing the viscosity of the oil to less than 1,000 centipoise at 20° C.

8. The method of claim 1, wherein the formation oil has a viscosity of about 5,000,000 centipoise or more at 20° C.

9. The method of claim 8, wherein contacting the carbon disulfide fluid with the formation oil further comprises reducing the viscosity of the oil to 1,000 centipoise or less at 20° C.

10. The method of claim 1, wherein the carbon disulfide fluid is mixed with the formation oil until the mixture of the oil and solvent contains at least 10 vol. % of the carbon disulfide fluid.

11. The method of claim 1, wherein displacing the mobilized oil through the formation further comprises placing one or more chase fluids into the formation.

12. The method of claim 11, wherein the one or more chase fluids comprises an aqueous polymer fluid.

13. The method of claim 11, wherein the one or more chase fluids comprises carbon dioxide.

14. The method of claim 11, further comprising repeating the placement of the carbon disulfide fluid and the one or more chase fluids into the formation in an alternating sequence.

15. The method of claim 1, further comprising identifying the formation that comprises the oil and the mobile water.

16. The method of claim 1, wherein the formation is a subterranean formation, the carbon disulfide fluid is placed into the subterranean formation by injecting the carbon disulfide fluid into the formation via a first well, the mobilized oil is displaced through the formation towards a second well, and oil is produced from the formation via the second well.

17. A method for producing oil from a formation containing oil and mobile water, comprising:

placing a solvent into the formation, the formation having an initial total water saturation at least 10% greater than the connate water saturation in the formation;

displacing the mobile water in the formation with the solvent so as to expose the oil in the formation to the solvent; and

contacting the exposed oil with the solvent to generate a mobilized oil comprised of a mixture of the formation oil and the solvent.

18. The method of claim 17, further comprising producing the mobilized oil from the formation.

19. The method of claim 17, further comprising:

displacing the mobilized oil through the formation; and

producing the displaced mobilized oil from the formation.

20. The method of claim 19, wherein displacing the mobilized oil through the formation further comprises placing one or more chase fluids in the formation.

21. The method of claim 20, wherein the one or more chase fluids comprises a aqueous polymer fluid.

22. The method of claim 17, wherein the solvent comprises a carbon disulfide fluid.

23. The method of claim 17, wherein the oil in the formation has a viscosity of at least 1,000 centipoise at 20° C.

24. The method of claim 17, wherein the oil in the formation has a viscosity of at least 5,000,000 centipoise at 20° C.

25. The method of claim 24, wherein the oil in the formation is mixed with the solvent to reduce the viscosity of the oil to about 1,000 centipoise or less at 20° C.

26. The method of claim 17, wherein the solvent in contacted with the exposed oil until the mobilized oil contains at least 10 vol. % of the solvent.

27. The method of claim 17, further comprising soaking the formation oil with the solvent to generate the mobilized oil.

28. The method of claim 17, wherein the formation is a subterranean oil-bearing formation, the carbon disulfide fluid is placed into the subterranean formation via a first well, and oil is produced from the formation via a second well.