US20130168089A1

US20130168089A1 - Method for producing oil

Info

Publication number: US20130168089A1
Application number: US13/729,596
Authority: US
Inventors: Steffen Berg; Raul Valdez; Jorge VIAMONTES; Paul Richard Weider
Original assignee: Shell Oil Co
Current assignee: Shell USA Inc
Priority date: 2011-12-30
Filing date: 2012-12-28
Publication date: 2013-07-04
Also published as: CN104024567A; RU2014131481A; WO2013101599A1; CA2861858A1

Abstract

The present disclosure relates to enhanced oil recovery methods including the injection of solvent and polymer floods to increase hydrocarbon production from oil bearing underground rock formations. One method includes injecting a solvent slug into the underground formation for a first time period from a first well. The solvent slug solubilizes the oil and generates a mixture of mobilized oil and solvent. An aqueous polymer slug may then be injected into the underground formation for a second time from the first well. The polymer slug may have a viscosity greater than the solvent slug and thereby generates an interface between the solvent slug and the polymer slug. The solvent slug and the mobilized oil are then forced towards a second well using a buoyant hydrodynamic force generated by the aqueous polymer slug. Oil and/or gas may then be produced from the second well.

Description

The present application claims the benefit of U.S. Patent Application No. 61/581,670, filed Dec. 30, 2011, the entire disclosure of which is hereby incorporated by reference.

FIELD OF THE INVENTION

The present disclosure relates to enhanced oil recovery methods and, in particular, injecting a combination of solvent and polymer floods to increase hydrocarbon production from oil bearing underground rock formations.

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 improves the sweep efficiency of injected water. Gas injection, also known as miscible injection, works somewhat similar to chemical EOR. By injecting a fluid that is miscible with the oil, trapped residual oil can be more easily recovered.
One of the advantages to chemical EOR is the miscibility of the solvents used with the oil phase. Theoretically, in a 1D displacement a recovery efficiency of 100% can be achieved using chemical EOR. In practice, however, the recovery/displacement efficiency of chemical EOR using a solvent is limited by flow front instabilities, such as viscous fingering and gravity effects. Viscous fingering occurs when the low-viscosity solvent tends to “finger” through the more viscous oil in the reservoir. Once this finger reaches the producer well, very little of the bypassed oil is ultimately displaced. Gravity effects on the solvent and mobilized oil often result in a gravity over-run or a gravity under-run reservoir.

SUMMARY OF THE INVENTION

The present disclosure relates to enhanced oil recovery methods and, in particular, injecting a combination of solvent and polymer floods to increase hydrocarbon production from oil bearing underground rock formations.
In one aspect of the present disclosure, a method for producing oil from an underground formation is disclosed. The method may include injecting or otherwise placing a solvent slug into the underground formation for a first time period from a first well. The solvent slug may be configured to solubilize the oil and generate a mixture of mobilized oil. In one or more embodiments, the solvent slug has a density that is less than 90% or at least 110% of a density of the oil. The method may further include injecting or otherwise placing an aqueous polymer slug into the underground formation for a second time from the first well. The polymer slug may have a viscosity greater than the solvent slug. In some embodiments, the viscosity of the polymer slug may be at least 5 centipoise. The polymer slug may be configured to generate an interface between the polymer slug and the mixture of mobilized oil. The mixture of mobilized oil and the solvent slug may be forced towards a second well by using the injected aqueous polymer slug, and oil and/or gas may subsequently be produced from the second well.
In another aspect of the present disclosure, another method for producing oil from an underground formation is disclosed. The method may include injecting a carbon disulfide slug into the underground formation for a first time period from a first well, and solubilizing the oil with the carbon disulfide slug, thereby generating a mixture of mobilized oil. The method may also include injecting an aqueous polymer slug into the underground formation for a second time from the first well. The aqueous polymer slug may be injected into the formation in a pore volume that is at least 1.5 times more than a pore volume injection of the solvent slug. Moreover, the aqueous polymer slug may have a viscosity that ranges between 5 centipoise and 50 centipoise. The method may further include creating a hydrodynamic force between the carbon disulfide slug and the aqueous polymer slug, impelling the carbon disulfide slug and the mixture of mobilized oil across the formation using the hydrodynamic force, and producing oil from a second well in fluid communication with the first well.
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.

FIG. 3 illustrates another system for producing hydrocarbons from an underground reservoir, according to one or more embodiments.

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

FIG. 4 a is a graph indicating viscosity reduction in oil when interacting with various solvents and solvent/polymer mixtures.

FIG. 5 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, injecting a combination of solvent and polymer floods to increase hydrocarbon production from oil bearing underground rock formations.
The present invention provides improved methods of extracting hydrocarbons from underground reservoirs using miscible solvents and immiscible polymer floods. At least one of the advantages of the disclosure is the increased displacement stability of the miscible solvent and the mobilized oil. Viscous fingering and gravity effects, such as gravity over-run or a gravity under-run reservoirs, are substantially minimized. As a result, the miscible solvent is more efficiently or otherwise effectively used in enhanced oil recovery processes. This improves not only the recovery efficiency of the reservoir, but also the effective utilization of both the solvents and the polymers.
Referring to FIG. 1, illustrated is a system 100 used to produce hydrocarbons (e.g., oil and/or gas) from an underground hydrocarbon-bearing formation, such as an oil reservoir. Specifically, the system 100 may be configured to extract hydrocarbons from a first underground formation 102, a second underground formation 104, a third underground formation 106, and/or a fourth underground 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 removed and transported 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 completion 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 in 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 in 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 horizontally-disposed wells within a 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 vertically or horizontally-disposed, or combinations thereof. As used herein, a “vertical” well may refer to a well that is slanted. In other embodiments, the array of wells 200 may be indicative of j-shaped wells or any other type of well known to those skilled in the art.
The recovery of oil and/or gas from an underground 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 and/or gas may be recovered from a formation 102, 104, 106, 108 into a production well 112, and flow through the well 112 to a production facility 110 for processing. In other embodiments, enhanced oil recovery (EOR) techniques may be used to increase the flow of oil and/or gas from the formation(s) 102, 104, 106, 108. As will be described in greater detail below, exemplary EOR techniques and methods may include injecting or otherwise placing a solvent flood into one or more of the formations 102, 104, 106, 108 to solubilize and mobilize portions of the viscous oil found therein. Following the injection of the solvent, an aqueous polymer flood may be injected into the formation to force the solubilized oil toward an adjacent production well and simultaneously improve the front stability of the solvent as it traverses the formation.
In one or more embodiments, the solvent may be a miscible enhanced oil recovery agent that is generally miscible with highly viscous oil and able to solubilize and mobilize the oil for faster and more efficient recovery. The miscible enhanced oil recovery agent may include, but is not limited to, a carbon disulfide formulation. 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. Other suitable miscible enhanced oil recovery agents will have a density that is less than approximately 0.7 g/ml and may include, but are not limited to, hydrogen sulfide, carbon dioxide, octane, pentane, LPG, 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 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 oil in the underground formation.
In one or more embodiments, the aqueous polymer flood may be characterized as an immiscible enhanced oil recovery agent configured to help mobilize the solvent flood and the solubilized oil 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 flood to be more easily mobilized through the formation. The immiscible enhanced oil recovery agent includes a polymer and may include an additional immiscible enhanced oil recovery agent such as, but not limited to, 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. In yet other embodiments, suitable polymers include liquid viscosifiers, such as ShellVis 50. Moreover, in some embodiments, suitable immiscible enhanced oil recovery agents are not first contact miscible or multiple contact miscible with oil in the formation.
Referring now to FIG. 2 b, illustrated is the array of wells 200 being treated using one or more exemplary EOR techniques, according to one or more embodiments disclosed. In some embodiments, the solvent and/or polymer floods are injected into the second well group 204 and result in an injection profile 208. 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 some embodiments, the injected polymer flood may force the solvent and solubilized/mobilized oil toward the first well group 202 for production. In alternative embodiments, plugs of each of the solvent and polymer floods are injected into the first well group 202 in alternating stages, and oil is subsequently recovered from the second well group 204.
In some embodiments, the solvent flood may be continuously injected into the first well group 202 for a first time period. Following the first time period, oil and/or gas may be produced from the second well group 204 for a second time period. In other embodiments, following the first time period, the aqueous polymer flood 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 or placing the solvent and polymer floods and producing oil and/or gas 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 flood may be injected at the beginning of a cycle, and the polymer flood or a mixture including one or more immiscible enhanced oil recovery agents 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 cycle.
In some embodiments, the oil present in the formation prior to the injection of any of the enhanced oil recovery agents (i.e., solvents and/or polymers) may have a viscosity of at least about 100 centipoise (MPa s), or at least about 500 centipoise (MPa s), or at least about 1000 centipoise (MPa s), or at least about 2000 centipoise (MPa s), or at least about 5000 centipoise (MPa s), or at least about 10,000 centipoise (MPa s). In other embodiments, however, the oil present in the formation prior to the injection of any of the enhanced oil recovery agents may have a viscosity of up to about 5,000,000 centipoise (MPa s), or up to about 2,000,000 centipoise (MPa s), or up to about 1,000,000 centipoise (MPa s), or up to about 500,000 centipoise (MPa s).
Injecting or placing the solvent flood into the formation 106 (FIG. 1) may be accomplished by methods known by those skilled in the art. In at least one embodiment, the solvent flood is injected into a single conduit in a single well, such as the well 112 of FIG. 1. The solvent, such as a carbon disulfide formulation, is then allowed to soak into the adjacent hydrocarbon-bearing formations and react with the viscous oil. As the carbon disulfide reacts with the oil, the oil solubilizes and begins to mobilize. After the solvent has soaked for a predetermined amount of time, a mixture of the solvent with the mobilized oil may then be either pumped out of the formation 106 through well 112 or flooded across the formation 106 to an adjacent production well using the aqueous polymer flood.
In one or more embodiments, the solvent may have a density that is less than 90% of the density of the oil or at least 110% of the density of the oil. Adding other agents or surfactants to the solvent may help achieve lower or higher densities, depending on what is required for the particular application. For example, one or more of CO₂, H₂S, C₃, C₄, and/or C₅hydrocarbons may be added to the solvent to help achieve the proper density ratio between the solvent and the oil.
Referring now to FIG. 3, illustrated is another system 300 used to produce hydrocarbons (i.e., oil and/or gas) from an underground hydrocarbon-bearing formation, such as an oil reservoir. The system 300 may be similar in some respects to the system 100 described above with reference to FIG. 1. Accordingly, the system 300 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. In one or more embodiments, the production facility 110 may further include a production storage tank 302 and the system 300 may further include a second well 304. Similar to the first well 112, the second well 304 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 306. It will be appreciated that the adjacent formation portions 114 and 306 of each well 112, 302, respectively, may be optionally fractured and/or perforated to enhance production.
The production storage tank 302 may be configured to store miscible and/or immiscible enhanced oil recovery agents and/or formulations (i.e., solvents and/or polymers) for injection into the underground formations 102, 104, 106, 108. In one or more embodiments, the production storage tank 302 is communicably coupled to the second well 304 and configured to provide the solvent and/or aqueous polymer thereto for injection. In other embodiments, however, the production storage tank 302 may be communicably coupled to the first well 112 and configured to provide solvent and/or aqueous polymer thereto for injection. In yet other embodiments, the production storage tank 302 may be communicably coupled to both the first and second wells 112, 302 and configured to provide solvent and/or aqueous polymer to both for injection, without departing from the scope of the disclosure.
In some embodiments the second well 304 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 304 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. In one or more embodiments, the solvent formulation may be pumped down the second well 304 and injected as a slug into the adjacent formation portions 306 of the third underground formation 106. Once coming into contact with the viscous oil present in the formation 106, the solvent flood solubilizes the oil and forms a mixture of the solvent and the oil which exhibits a reduced viscosity as compared with the oil prior to solubilization. As a result of the solubilization, the less viscous mixture becomes mobilized for easier extraction from the formation 106.
In some embodiments, continual pumping of the solvent via the second well 304 may flow the mixture 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 an aqueous polymer flood also injected via the second well 304 into the adjacent formation portions 306 of the third underground formation 106. The polymer flood 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 to FIG. 4, with continued reference to FIG. 3, illustrated is an enlarged view of one or more solvent and polymer slugs traversing the third underground formation 106, according to one or more embodiments. As illustrated, the underground formation 106 may be geologically-bounded on an upper edge 402 a and a lower edge 402 b, thereby being geologically-separated or sealed by the second and fourth underground formations 104, 108. While not shown, it will be appreciated that the first and second wells 112 and 304 may be arranged at either end of the underground formation 106 in order to either inject or produce fluids into or out of the formation 106. Flow across the formation 106 may be in the direction indicated by the arrows. In other embodiments, however, the flow may be reversed, without departing from the scope of the disclosure.
The formation 106 may consist of an oil bearing layer 404 providing oils ranging from light oils to heavy oils. As illustrated, a solvent slug 406 may be injected into the formation 106 and, once coming into contact with the oil bearing layer 404, may solubilize a portion 408 of the oil such that the solubilized portion 408 is more easily mobilized across the formation 106 for extraction. In some embodiments, the solvent slug 406 may be pumped into the formation 106 below the fracture pressure of the formation 106, for example from about 40% to about 90% of the fracture pressure.
Following the solvent slug 406, an aqueous polymer slug 410 may be injected into the formation 106. In one or more embodiments, the polymer used may exhibit a higher viscosity than the solvent and is immiscible with the solvent slug 406, and may exhibit a viscosity on the same order of magnitude as the mixture of solvent and oil and is immiscible with the mixture of solvent and oil 408. For example, in one or more embodiments, the viscosity of the aqueous polymer slug 410 may range between about 1 centipoise (MPa s) and about 1000 centipoise (MPa s), or between 5 centipoise (MPa s) and 100 centipoise (MPa s). As a result, an interface 412 is generated by interfacial tension and/or capillary pressure between the solvent slug 406 and the polymer slug 410. The generated interface 412 may be seen or otherwise measured using CT scan technology, pressure drop measurements derived from multiple pressure taps along the span of the formation 106, and/or from fluid sampling as the fluids are being produced. In operation, the interface 412 may provide a layer of uniform pressure that forces the solvent plug 406 and the mixture of solvent and solubilized oil 408 across the third underground formation 106. Consequently, a hydrodynamic force impels the solvent slug 406 and the mixture of solvent and solubilized oil 408 across the formation 106 with a substantially uniform front. The hydrodynamic force is able to actively and/or passively impel the solvent slug 406 and the mixture of solvent and solubilized oil 408 across the formation 106 depending on whether the polymer slug is actively being driven (e.g., through the use of a pump or other driving mechanism) or passively being driven with the built up pressures in the wellbore and/or formation 106.
As can be appreciated, this may prove advantageous in improving displacement stability of the solvent plug 406 within the oil bearing layer 404, such that the solvent plug 406 will be less prone to viscous fingering at the front of the mixture of solvent and solubilized oil 408 and/or the oil bearing layer 404. For example, various solvents, such as carbon disulfide, are less viscous than the oils encountered in the underground formations. As such, these solvents naturally tend to finger at the flow front. When followed by a polymer slug 410, however, as described herein, a substantially uniform pressure is applied at the interface 412 which forces the solvent plug 406 and the mixture of solvent and solubilized oil 408 across the formation 106 in an increasingly uniform progress such that the potential for viscous fingering is dramatically reduced.
The polymer slug 410 also helps alleviate other front flow instabilities, such as gravity effects where the solvent plug 406 may be prone to gravity over-run or gravity under-run. For example, as a more dense solvent (e.g., carbon disulfide) mixes with the viscous oil, the solvent/oil mixture becomes more dense than the remaining oil in the formation 106 and gravity naturally forces the solvent/oil mixture 408 to lower portions of the formation 106. Likewise, as a less dense solvent mixes with the viscous oil, the resulting solvent/oil mixture becomes less dense than the remaining oil in the formation 106 and natural buoyant forces will force these solvent/oil mixtures 408 to higher portions of the formation 106. As a result, the solvent may be unevenly forced through the formation 106, thereby causing gravity over-run and gravity under-run, where an excess of less dense solvent may traverse at higher portions of the formation 106 and an excess of more dense solvent may traverse at lower portions of the formation 106, while the intermediate portions are not efficiently produced. The polymer slug 410, however, sharpens the displacement of the oil and facilitates a more uniform movement across the entire front of the solvent/oil mixture 408.
In some embodiments, the solvent slug 406 may be heated prior to being injected into the formation 106 to lower the viscosity of fluids in the formation 106, for example, the heavy oils, paraffins, asphaltenes, etc. In other embodiments, the solvent slug 406 may be heated and/or boiled while within the formation 106 to heat and/or vaporize the solvent formulation. The solvent slug 406 may be heated either actively or passively. For example, the solvent slug 406 may be heated using, for example, a heated fluid (i.e., steam) or a heater. In other embodiments, however, the solvent slug 406 may be heated naturally via the naturally-occurring heat emanating from the formation 106. In one or more embodiments, a brine flood or chase 414 may be injected into the formation 106 following the polymer plug 410. The brine chase 414 may be configured to displace the remaining mobilized fluids. In at least some embodiments, the chase 414 may be undertaken using nitrogen.
In other embodiments, the polymer slug 410 may be injected into the formation 106 prior to the solvent slug 406 in order to pretreat the formation 106. Moreover, instead of a brine chase 414 following the polymer slug 410, another solvent slug 406 may be injected followed by another polymer slug 410, thereby creating an alternating sequence. In yet other embodiments, a pore volume of the polymer slug 410 may be at least 1.5 times the pore volume of the solvent slug 406 injected into the formation 106. “Pore volume” is defined as the pore volume of the formation 106, relative to total volume of the formation. “Pore volume” may also refer to the swept volume between an injection well and a production well and may be readily determined by methods known to those skilled in the art. Such methods include modeling studies. However, the pore volume may also be determined by passing a high salinity water having a tracer contained therein through the formation form the injection well to the production well. The swept volume is the volume swept by the displacement fluid averaged over all flow paths between the injection well and production well. This may be determined with reference to the first temporal moment of the tracer distribution in the produced high salinity water, as would be well known to the person skilled in the art.
Referring to FIG. 4 a, illustrated is a graph 416 indicating the reduction in oil viscosity at a reservoir as the oil comes into contact with solvents or solvent/polymer combinations. Of note, the graph 416 shows the decreasing viscosity of the oil as it contacts carbon disulfide (CS₂) by itself, as it contacts a CS₂and polystyrene (PS) mixture, and as it contacts a CS₂and ShellVis 50 mixture. Table 1 below provides the properties of the CS₂/PS solution at about 23° C., and Table 2 below provides the properties of the CS₂/ShellVis 50 solution at about 23° C.

TABLE 1

concentration	density ρ	viscosity μ
wt-%	(g/cm³)	(cP)

0	1.26	0.4 ± 0.1
6.9	1.26	1.0 ± 0.1
13.2	1.25	4.3 ± 0.4
16.2	1.24	7.4 ± 0.7
22.4	1.22	26.8 ± 2.7

TABLE 2

concentration	density ρ	viscosity μ
wt-%	(g/cm³)	(cP)

0	1.26	0.4 ± 0.1
3.4	1.26	5.1 ± 0.5
5.5	1.25	14.9 ± 1.5
8.3	1.24	65.9 ± 1.6

Referring now to FIG. 5, with continued reference to FIGS. 3 and 4, illustrated is an exemplary method or pattern 500 of injection and production, according to one or more embodiments disclosed. The exemplary pattern 500 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 solvent slugs is indicated by a checkerboard pattern, injection of polymer slugs is indicated by a diagonal pattern, and the white areas are indicative of producing oil and/or gas from the formation.
In some embodiments, at time 520, a solvent slug is injected into the first well group 202 for time period 502, while oil and/or gas is produced from the second well group 204 for time period 503. A solvent slug may then be injected into the second well group 204 for time period 505, while oil and/or gas is produced from the first well group 202 for time period 504. 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 530, there may be a cavity in the formation due to oil and/or gas that has been produced during time 520. During time 530, only the leading edge of cavity may be filled with a solvent slug, which is then pushed through the formation with a polymer slug. For example, a solvent slug may be injected into the first well group 202 for time period 506, then a polymer slug may be injected into the first well group 202 for time period 508, while oil and/or gas may be produced from the second well group 204 for time period 507. In one or more embodiments, a solvent slug may then be injected into the second well group 204 for time period 509, and then a polymer slug may be injected into the second well group 204 for time period 511, while oil and/or gas may be produced from the first well group 202 for time period 510. 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 540 there may be a 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 512, then a polymer slug may be injected into the first well group 202 for time period 514 while oil and/or gas may be produced from the second well group 204 for time period 515. The injection cycling of solvent and polymer slugs into the first well group 202 while producing oil and/or gas from the second well group 204 may be continued as long as desired, for example as long as oil and/or gas is produced from the second well group 204.
In some embodiments, time periods 502, 503, 504, and/or 505 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 502, 503, 504, and/or 505 may increase in length from time 520 until time 530. In other embodiments, however, each of time periods 502, 503, 504, and/or 505 may continue relatively unchanged from time 520 until time 530 for about 5 cycles to about 25 cycles, for example from about 10 cycles to about 15 cycles.
In some embodiments, time period 506 is from about 10% to about 50% of the combined length of time period 506 and time period 508, for example from about 20% to about 40%, or from about 25% to about 33%. In some embodiments, time period 509 is from about 10% to about 50% of the combined length of time period 509 and time period 511, for example from about 20% to about 40%, or from about 25% to about 33%. In some embodiments, the combined length of time period 506 and time period 508 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 509 and time period 511 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 512 and time period 514 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 again to FIG. 3, after separating the oil from the solvent and the polymer, the solvent formulation may then be processed for recycling and placed back in the production storage vessel 302. 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 and/or gas to produce one or more distillate fractions. In some embodiments, the oil and/or gas, 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.
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. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. 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 from an underground oil-bearing formation, comprising:

placing a solvent slug into the underground oil-bearing formation for a first time period from a first well, the solvent slug being configured to solubilize the oil upon contacting the oil and generate a mixture of mobilized oil, wherein the solvent slug has a density that is less than 90% or at least 110% of a density of the oil;

placing an aqueous polymer slug into the underground formation for a second time period from the first well, the polymer slug having a viscosity greater than the mixture of mobilized oil and at least 5 centipoise;

displacing the mixture of mobilized oil and the solvent slug towards a second well with the aqueous polymer slug; and

producing oil and/or gas from the second well.

2. The method of claim 1 wherein an interface is generated between the polymer slug and the mixture of mobilized oil and solvent.

3. The method of claim 1 wherein the solvent slug comprises a carbon disulfide formulation.

4. The method of claim 1 further comprising placing a brine chase into the formation following the aqueous polymer slug.

5. The method of claim 1 further comprising repeating the placement of the solvent slug and the aqueous polymer slug in an alternating sequence.

6. The method of claim 1 wherein the polymer of the aqueous polymer slug is selected from the group of polymers consisting of polyacrylamides, partially hydrolyzed polyacrylamide, polyacrylates, ethylenic copolymers, biopolymers, carboxymethylcellulose, polyvinyl alcohol, polystyrene sulfonates, polyvinylpyrolidone, AMPS (2-acrylamide-2-methyl propane sulfonate), copolymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, lauryl acrylate and acrylamide, xanthan gum, and guar gum.

7. The method of claim 1 wherein the aqueous polymer slug is placed in the formation in a pore volume that is at least 1.5 times more than a pore volume of the solvent slug placed in the formation immediately preceding placement of the aqueous polymer slug.

8. The method of claim 1 wherein the polymer slug has a viscosity greater than the solvent slug.

9. A method for producing oil from an underground oil-bearing formation, comprising:

placing a first carbon disulfide slug into the underground formation for a first time period from a first well;

contacting at least a portion of the oil with the first carbon disulfide slug, thereby generating a mixture of mobilized oil and carbon disulfide;

placing an aqueous polymer slug into the underground formation for a second time from the first well, wherein a quantity of the aqueous polymer slug is placed in the formation in a pore volume that is at least 1.5 times more than a pore volume of the first carbon disulfide slug placed into the formation, and the aqueous polymer slug has a viscosity ranging between 5 centipoise (MPa s) and 100 centipoise (MPa s);

creating a hydrodynamic force between the first carbon disulfide slug and the aqueous polymer slug;

impelling the first carbon disulfide slug and the mixture of mobilized oil and carbon disulfide across the formation using the hydrodynamic force; and

producing oil from a second well in fluid communication with the first well.

10. The method of claim 9 further comprising placing a second carbon disulfide slug into the underground formation for a third time period from the first well.

11. The method of claim 9 further comprising placing a brine chase into the formation following the aqueous polymer slug.

12. The method of claim 9 further comprising repeating the placement of the first carbon disulfide slug and the aqueous polymer slug in an alternating sequence.

13. The method of claim 9 wherein the underground formation interposes two adjacent underground formations which seal the underground formation on an upper edge and a lower edge.

14. The method of claim 9 wherein the first carbon disulfide slug has a density that is at least 110% of a density of the oil.