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.
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.
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.
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.
a illustrates a well pattern, according to one or more embodiments.
b illustrates the well pattern of
a and 3b illustrate line graphs showing how the viscosity of oil generally decreases corresponding to its interaction with a solvent, such as carbon disulfide.
a, 5b, and 5c illustrate progression models depicting how a solvent interacts with a formation containing highly viscous oils and mobile water.
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
Referring to
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
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
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-C6 aliphatic 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.
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
The second graph as shown in
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
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
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
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
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
Referring again to
Referring now to
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
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.
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.
Number | Date | Country | |
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61580906 | Dec 2011 | US |