WO2015157158A1

WO2015157158A1 - Systems and methods for accelerating production of viscous hydrocarbons in a subterranean reservoir with chemical agents that lower water-oil interfacial tension

Info

Publication number: WO2015157158A1
Application number: PCT/US2015/024479
Authority: WO
Inventors: Andrew C. REES; Allan Peats; Xuebing FU; Christopher C. West; Spencer Taylor
Original assignee: Rees Andrew C; Allan Peats; Fu Xuebing; West Christopher C; Spencer Taylor
Priority date: 2014-04-08
Filing date: 2015-04-06
Publication date: 2015-10-15

Abstract

A method for mobilizing viscous hydrocarbons includes (a) injecting a chemical agent into the reservoir with the reservoir at an ambient temperature. The chemical agent is a surfactant or an alkali. In addition, the method includes (b) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (a).

Description

SYSTEMS AND METHODS FOR ACCELERATING PRODUCTION OF VISCOUS HYDROCARBONS IN A SUBTERRANEAN RESERVOIR WITH CHEMICAL AGENTS THAT LOWER WATER-OIL INTERFACIAL TENSION

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims benefit of U.S. provisional patent application Serial No. 61/976,925 filed April 8, 2014, and entitled "Systems and Methods for Accelerating Production of Viscous Hydrocarbons in a Subterranean Reservoir with Chemical Agents that Lower Water-Oil Interfacial Tension," which is hereby incorporated herein by reference in its entirety. This application also claims benefit of U.S. provisional patent application Serial No. 62/045,608 filed September 4, 2014, and entitled "Systems and Methods for Accelerating Production of Viscous Hydrocarbons in a Subterranean Reservoir with Chemical Agents that Lower Water-Oil Interfacial Tension," which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] Not applicable.

FIELD

[0003] The disclosure relates generally to thermal recovery techniques for producing viscous hydrocarbons such as heavy oil and bitumen. More particularly, the disclosure relates to the injection of chemical agents that lower the water-oil interfacial tension before heating the formation (e.g., before injecting steam) to accelerate the production of viscous hydrocarbons with thermal recovery techniques.

BACKGROUND

[0004] As existing reserves of conventional light liquid hydrocarbons (e.g., light crude oil) are depleted and prices for hydrocarbon products continue to rise, there is a push to find new sources of hydrocarbons. Viscous hydrocarbons such as heavy oil and bitumen offer an alternative source of hydrocarbons with extensive deposits throughout the world. In general, hydrocarbons having an API gravity less than 22° are referred to as "heavy oil" and hydrocarbons having an API gravity less than 10° are referred to as "bitumen." Although recovery of heavy oil and bitumen present challenges due to their relatively high viscosities and limited mobility, there are a variety of processes that can be employed to recover such viscous hydrocarbons from underground deposits.

[0005] Many techniques for recovering heavy oil and bitumen utilize thermal energy to heat the hydrocarbons, decrease the viscosity of the hydrocarbons, and mobilize the hydrocarbons within the formation, thereby enabling the extraction and recovery of the hydrocarbons. Accordingly, such production and recovery processes may generally be described as "thermal" techniques. A steam-assisted gravity drainage (SAGD) operation is one thermal technique for recovering viscous hydrocarbons such as bitumen and heavy oil.

[0006] SAGD operations typically employ two vertically spaced horizontal wells drilled into the reservoir and located close to the bottom of the reservoir. Steam is injected into the reservoir through an upper, horizontal injection well, referred to as the injection well, to form a "steam chamber" that extends into the reservoir around and above the horizontal injection well. Thermal energy from the steam reduces the viscosity of the viscous hydrocarbons in the reservoir, thereby enhancing the mobility of the hydrocarbons and enabling them to flow downward through the formation under the force of gravity. The mobile hydrocarbons drain into the lower horizontal well, also referred to as the production well. The hydrocarbons are collected in the production well and are produced to the surface via artificial lift.

[0007] The commissioning of a SAGD well pair requires fluid communication between the injection well and the production well. The process of establishing fluid communication between the injection well and the production well of SAGD well pair is typically referred to as "start-up" or the "start-up" phase. Typically, start-up is achieved by steam circulation or "bullheading" of steam, provided the formation is sufficiently permeable to water. Steam circulation and bullheading can occur in both the injection and the production wells. The objective of both techniques is to heat and mobilize the viscous hydrocarbons in the zone between the well pair to allow fluid communication from the injection well to the production well. Once fluid communication is achieved in the interwell zone (i.e., region between the injection well and the production well), then steam is injected through only the injection well and the production well is used to produce fluid, thereby transitioning the well pair from the start-up phase into the "production" phase.

BRIEF SUMMARY OF THE DISCLOSURE

[0008] Embodiments disclosed herein are directed to a methods and systems for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure. In one embodiment disclosed herein, a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) injecting a chemical agent into the reservoir with the reservoir at the ambient temperature. The chemical agent is a surfactant or an alkali. In addition, the method comprises (b) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (a).

[0009] In another embodiment disclosed herein, a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) selecting a chemical agent that is water-soluble. In addition, the method comprises (b) forming an aqueous solution with the chemical agent, wherein the chemical agent has a concentration in the aqueous solution more than 5 vol. % or 5 wt. % of the aqueous solution. Further, the method comprises (c) injecting the aqueous solution into the reservoir with the reservoir at the ambient temperature. Still further, the method comprises (d) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (c).

[0010] In another embodiment disclosed herein, a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) selecting a chemical agent. In addition, the method comprises (b) dissolving the chemical in an organic solvent to form a solvent- chemical agent mixture. Further, the method comprises (c) injecting the solvent-chemical agent mixture into the reservoir with the reservoir at the ambient temperature. Still further, the method comprises (d) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (c).

[0011] Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0012] For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

[0013] Figure 1 is a schematic cross-sectional side view of an embodiment of a system in accordance with the principles described herein for producing viscous hydrocarbons from a subterranean formation;

[0014] Figure 2 is a schematic cross-sectional end view of the system of Figure 1 taken along section II— II of Figure 1;

[0015] Figure 3 is a graphical illustration of an embodiment of a method in accordance with the principles described herein for producing viscous hydrocarbons in the reservoir of Figure 1 using the system of Figure 1;

[0016] Figure 4 is a schematic cross-sectional end view of the system of Figure 1 taken along section II— II of Figure 1 illustrating a loaded zone formed by injecting the injection fluid into the reservoir of Figure 1 according to the method of Figure 3 ; and

[0017] Figure 5 is a schematic cross-sectional end view of the system of Figure 1 taken along section II— II of Figure 1 illustrating a steam chamber formed by injecting steam into the reservoir of Figure 1 according to the method of Figure 3.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0018] The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

[0019] Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

[0020] In the following discussion and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to... ." Also, the term "couple" or "couples" is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms "axial" and "axially" generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms "radial" and "radially" generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Any reference to up or down in the description and the claims will be made for purposes of clarity, with "up", "upper", "upwardly" or "upstream" meaning toward the surface of the borehole and with "down", "lower", "downwardly" or "downstream" meaning toward the terminal end of the borehole, regardless of the borehole orientation.

[0021] The process of establishing fluid communication between the injection well and the production well of SAGD well pair during "start-up" (via steam circulation or "bullheading" of steam) is often time consuming. For example, start-up typically takes more than three months. In many cases, the heating and mobilization of the viscous hydrocarbons during start-up is not uniform due to local variations in permeability and porosity, which may result in a protracted start-up and poor initial conformance of the steam chamber. Limitations on the temperature and pressure of the steam injected in SAGD operations (e.g., due to the reservoir being shallow, poor caprock integrity, etc.) can also lengthen start-up and negatively affect initial conformance of the steam chamber. Protracted start-up operations result in high costs and delays the ultimate production of oil. However, embodiments of systems and methods described herein offer the potential to accelerate mobilization of the viscous hydrocarbons during start-up, thereby decreasing the time to achieve fluid communication between SAGD well pair (e.g., wells 20, 30), increasing start-up quality through improved conformance, and accelerating production.

[0022] Referring now to Figures 1 and 2, an embodiment of a system 10 for producing viscous hydrocarbons (e.g., bitumen and heavy oil) from a subterranean formation 100 using a thermal recovery technique is shown. In this embodiment, system 10 is configured to employ steam- assisted gravity drainage (SAGD) thermal recovery techniques to produce generally immobile, viscous hydrocarbons. Moving downward from the surface 5, formation 100 includes an upper overburden layer or region 101 of consolidated cap rock, an intermediate layer or region 102 of rock, and a lower underburden layer or region 103 of consolidated rock. Layers 101, 103 are formed of generally impermeable formation material (e.g., limestone). However, layer 102 is formed of a generally porous, permeable formation material (e.g., sandstone), thereby enabling the storage of hydrocarbons therein and allowing the flow and percolation of fluids therethrough. In particular, layer 102 contains a reservoir 105 of viscous hydrocarbons (reservoir 105 shaded in Figures 1 and 2).

[0023] System 10 mobilizes, collects and produces viscous hydrocarbons in reservoir 105 using SAGD techniques. In this embodiment, system 10 includes a steam injection well 20 extending downward from the surface 5 and a hydrocarbon production well 30 extending downward from the surface 5 generally parallel to injection well 20. Each well 20, 30 extends through overburden layer 101 and includes an uphole end 20a, 30a, respectively, disposed at the surface 5, a downhole end 20b, 30b, respectively, disposed in formation 100, a generally vertical section 21, 31, respectively, extending into the formation 100 from the surface 5, and a horizontal section 22, 32, respectively, extending horizontally through layer 102 and reservoir 105. Horizontal sections 22, 32 are both positioned proximal the bottom of reservoir 105 and above underburden layer 103, with section 32 of production well 30 located below section 22 of injection well 20. In addition, horizontal sections 22, 32 are lined with perforated or slotted liners, and thus, are both open to reservoir 105.

[0024] Referring now to Figure 3, an embodiment of a method 200 for producing viscous hydrocarbons (e.g., heavy oil and/or bitumen) from reservoir 105 (or portion of reservoir 105) using system 10 is shown. In this embodiment, reservoir 105 is loaded with one or more chemical agents prior to initiating start-up of the SAGD well pair 20, 30 (i.e., before injecting steam). The subsequent addition of thermal energy during start-up of the SAGD well pair 20, 30 and/or production operations in combination with the chemical agents facilitates an accelerated mobilization of the viscous hydrocarbons, thereby decreasing the time to achieve fluid communication between SAGD wells 20, 30, increasing start-up quality through improved conformance, and accelerating production from well 30.

[0025] Although embodiments of method 200 can be used to produce hydrocarbons having any viscosity under ambient reservoir conditions (ambient reservoir temperature and pressure) including, without limitation, light hydrocarbons, heavy hydrocarbons, bitumen, etc., embodiments of method 200 are particularly suited to producing viscous hydrocarbons having a viscosity greater than 10,000 cP under ambient reservoir conditions. In general, viscous hydrocarbons having a viscosity greater than 10,000 cP under ambient reservoir conditions are immobile within the reservoir and typically cannot be produced economically using conventional, non-thermal, in situ recovery methods. [0026] Beginning in block 201 of method 200, one or more chemical agents for injection into reservoir 105 are selected. The purpose of the chemical agent(s) is to accelerate and enhance the initial mobilization of the viscous hydrocarbons in reservoir 105 by decreasing the water-oil interfacial tension to enhance the displacement of hydrocarbons in reservoir 105 in response to thermal energy added during start-up of the SAGD well pair 20, 30. Thus, selection of the particular chemical agent(s) is based, at least in part, on its ability to decrease the water-oil interfacial tension (e.g., reservoir 105 in formation 101). In general, the ability of a chemical agent to enhance the mobility of hydrocarbons depends on a variety of factors including, without limitation, the type of formation, its oil saturation, water saturation, the native permeability to water, physical and chemical properties of the oil, etc. Core and/or oil samples from the formation of interest can be tested with various chemical agents to facilitate the selection in block 201. The cost and availability of various chemical agent(s) may also impact the selection in block 201.

[0027] Although a variety of chemical agents may be useful, in embodiments described herein, each chemical agent selected in block 201 is a surfactant or alkali that can be used alone (e.g., surfactant alone or alkali alone), with one or more other chemical agents (e.g., surfactant in combination with an alkali, multiple surfactants used together, multiple alkalis used together, etc.), with one or more other chemical additives (e.g., surfactant in combination with another chemical, alkali in combination with another chemical, etc.), or combinations thereof.

[0028] Each surfactant selected for use as a chemical agent in block 201 is a surface active agent that is generally unable to emulsify immobile hydrocarbons in reservoir 105 at ambient reservoir temperatures, owing to the relatively high viscosity of the hydrocarbons but is capable of emulsifying hydrocarbons in reservoir 105 once they become mobile (i.e., at temperatures above the ambient reservoir temperature). In general, bitumen (e.g., bitumen of the Canadian oil sands of Alberta) is immobile at ambient reservoir temperatures (typically 8-12°C), and must be heated to a temperature of at least 40° to 60°C to be converted into sufficiently mobile hydrocarbons within reservoir 105. For example, as disclosed in Ivory et al, Handbook Of Canadian Heavy Oil And Oil Sand Properties For Reservoir Simulation, 2^nd Ed, Report #0708- 22, AERI/ARC Core Industry Research Program (2008) (Fig 3-1), which is hereby incorporated herein by reference in its entirety for all purposes, heating a typical Athabasca bitumen from 10°C to 50°C will reduce its viscosity from about 2,000,000 cP to about 5,000 cP. Consequently, each surfactant selected as a chemical agent in block 201 is generally unable to emulsify immobile bitumen at ambient reservoir temperatures, but is capable of emulsifying bitumen once it is warmed to at least 40° to 60°C and converted to mobile hydrocarbons. Examples of suitable surfactants that can be selected as chemical agents in bock 201 include, without limitation, branched alcohol propoxylated sulfates (APS) (e.g., Alfoterra® series surfactants available from Sasol North American Inc. of Houston, Texas); alkyl ether sulfactes (e.g., Petrostep ES65A from Stepan Chemical Company of Northfield, Illinois); internal olefin sulfonates (e.g., ENOROET™ O Series from Shell Chemicals); branched alpha olefin sulfonates (e.g. Bio-Terge® series surfactants available from Stepan Chemical Company of Northfield, Illinois); alkylaryl sulfonate (e.g. Biosoft D-40 from Stepan Chemical Company of Northfield, Illinois); poly oxy ethylene alkyl phenyl ether (e.g. Triton X-100™ available from The DOW Chemical Company of Midland, Michigan); sodium/potassium oleate preferably with a chelating agent such as Na-EDTA; gemini (dimeric) surfactants; and polyoxyethylenesorbitan esters (e.g., TWEEN® 20 or TWEEN® 40 available from Croda Inc. of Edison, New Jersey).

[0029] Each alkali selected for use as a chemical agent in block 201 is a basic, ionic salt of an alkali metal or alkaline earth metal element that reacts with viscous hydrocarbons to yield lower interfacial tension. Examples of suitable alkalis include, without limitation, sodium carbonate, potassium carbonate, lithium carbonate, and cesium carbonate. It should be appreciated that the reaction of the alkali(s) may be directly or indirectly thermally driven. For example, thermal energy may sufficiently mobilize the viscous hydrocarbons to enable the alkali(s) to access and react with the organic acids in the hydrocarbons.

[0030] In general, the selected chemical agent(s) (i.e., surfactant(s) and/or alkali(s)) can be injected into the formation in block 204, described in more detail below, alone, in an aqueous solution (e.g., a mixture of the chemical agent(s) and water), or in a non-aqueous solution (e.g., a mixture of the chemical agent(s) and an organic solvent) depending on a variety of factors including, without limitation, the availability of the chemical agent(s) and the form in which the chemical agent(s) are commercially available. Thus, prior to loading the reservoir 105 in block 204, the selected chemical agent(s) can be mixed with water (e.g., a brine) to form an aqueous solution or mixed with one or more organic solvent(s) to form a non-aqueous solution. In general, the concentration of each chemical agent in the aqueous or non-aqueous solution can be varied depending on a variety of factors, but is preferably relatively high. In some embodiments, the concentration of the surfactant in the aqueous or non-aqueous solution is preferably greater than 5.0 wt. %, more preferably greater than 10.0 wt. %, and even more preferably greater than 15.0 wt. %. [0031] In embodiments where the chemical agent(s) are mixed with water to form an aqueous solution, the selected chemical agent(s) are preferably water soluble and the water is preferably a brine having a salt concentration and composition analogous to that of reservoir 105 to reduce the potential for the aqueous solution to negatively alter reservoir 105. In general, the salt concentration and composition of the reservoir 105 can be determined from core samples and/or from samples of fluids that naturally migrate from reservoir 105 into a wellbore traversing reservoir 105. In embodiments where the selected chemical agent(s) are mixed with solvent(s) to form a non-aqueous solution, the chemical agent(s) are preferably soluble in the solvent(s). The solvent(s) used to form the non-aqueous solution with the chemical agent(s) preferably have high solvency for the chemical agent(s) as previously described, and further, preferably have a high solvency for the viscous hydrocarbons in reservoir 105. Examples of suitable solvents include, without limitation, xylene, toluene, benzene, naphtha, tetrahydrofuran (THF), or any diluent.

[0032] In general, method 200 can be employed in connection with reservoirs that exhibit good or poor native water mobility. However, in embodiments where the chemical agent(s) are in an aqueous solution, the water functions as the surfactant carrier. Consequently, in such embodiments, method 200 may be particularly useful with reservoirs exhibiting a good native permeability to water. Further, in embodiments where the chemical agent(s) are mixed with one or more solvent(s), the solvent(s) function as the surfactant carrier. Consequently, in such embodiments, method 200 may be particularly useful with reservoirs exhibiting a poor native permeability to water.

[0033] Referring still to Figure 3, as previously described, the selected chemical agent(s) can be injected into the formation in block 204 alone, in an aqueous solution (e.g., a mixture of the chemical agent(s) and water or brine), or in a non-aqueous solution (e.g., a mixture of the chemical agent(s) and a solvent). Therefore, as used herein, the phrase "injection fluid" is generally used to describe the fluid comprising the chemical agent(s) injected into the formation in block 204 whether the fluid comprises only the chemical agent(s), comprises an aqueous solution including the chemical agent(s) and a brine, or comprises a non-aqueous solution including the chemical agent(s) and organic solvent(s). In block 203, the parameters for loading or injecting the reservoir 105 with the injection fluid are determined. In general, the injection parameters can be determined by any suitable means known in the art such as by completing an "injectivity test." The injection parameters include, without limitation, the pressure, the temperature, and the flow rate at which the injection fluid will be injected into reservoir 105. The injection pressure of the injection fluid is preferably sufficiently high enough to enable injection into reservoir 105 (i.e., the pressure is greater than or equal to the ambient pressure of reservoir 105), and less than the fracture pressure of overburden 102, the fracture pressure of reservoir 105 (if one exists), and the pressure at which hydrocarbons in reservoir 105 will be displaced. The injection temperature is preferably greater than the freezing point and less than the thermal recovery technique operating temperature (e.g., SAGD operating temperature). In some embodiments, the injection fluid may be heated to improve its injectivity, particularly in cases where the reservoir 105 has a relatively lower initial water mobility.

[0034] Referring still to Figure 3, moving now to block 204, reservoir 105 is loaded or injected with the injection fluid according to the injection parameters determined in block 203. Since the injection fluid is injected prior to start-up in block 205, and is not injected with steam, but rather, is injected into reservoir 105 with reservoir 105 at its ambient temperature, injection of the injection fluid according to block 204 may be referred to herein as "cold" loading of reservoir 105.

[0035] Since SAGD well pair 20, 30 are not yet commissioned, and thus, are not injecting steam and collecting hydrocarbons, respectively, during the cold loading of reservoir 105 in block 204, the injection fluid can be injected into reservoir 105 utilizing one well 20, 30, both wells 20, 30, or combinations thereof over time. The injection fluid is preferably injected into reservoir 105 via injection well 20 alone, via both wells 20, 30 at the same time, or via both wells 20, 30 at the same time followed by injection well 20 alone. It should be appreciated that since the injection fluid is injected into the reservoir 105 in block 204 before commissioning SAGD well pair 20, 30, the injection fluid can be injected into the reservoir in block 204 through one of the wells 20, 30 while the other well 20, 30 is being formed (e.g., drilled). Following the formation of the second well 20, 30, the injection fluid can be injected solely through the first well 20, 30, solely through the second well 20, 30, or simultaneously through both wells 20, 30. In general, the injection fluid can be injected into the reservoir 105 continuously, intermittently, or pulsed by controllably varying the injection pressure within an acceptable range of pressures as determined in block 203. Pulsing the injection pressure offers the potential to enhance distribution of the injection fluid (and chemical agent(s) therein) in reservoir 105 and facilitates dilation of reservoir 105. It should be appreciated that any one or more of these injection options can be performed alone or in combination with other injection options. [0036] In implementations where production well 30 is not employed for injection of the injection fluid, production well 30 is preferably maintained at a pressure lower than the ambient pressure of reservoir 105 (e.g., with a pump) to create a pressure differential and associated driving force for the migration of fluids (e.g., connate water and/or the injection fluid) into production well 30. Pumping fluids out of production well 30 to maintain the lower pressure also enables chemical analysis and monitoring of the fluids flowing into production well 30 from the surrounding formation 101, which can provide insight as to the migration of the injection fluid, and hence the chemical agent(s), through reservoir 105 and the saturation of reservoir 105 with the injection fluid. Injection of the injection fluid in block 204 is performed until reservoir 105 (or portion of reservoir 105 to be loaded) is sufficiently charged.

[0037] In embodiments where the chemical agent(s) include one or more surfactants, the surfactant(s) may slightly increase the viscosity of the injection fluid, thereby offering the potential for improved distribution homogeneity of the injection fluid in the reservoir 105. In embodiments where the chemical agent(s) are mixed with organic solvent(s) in a non-aqueous solution, the solubility of the injection fluid with the viscous hydrocarbons allows the injection fluid to mix with the viscous hydrocarbons. The organic solvent(s) in the injection fluid function as diluent(s) that reduce the viscosity of the viscous hydrocarbons, thereby enhancing the mobilization of the viscous hydrocarbons.

[0038] In embodiments where the chemical agent(s) are injected into the reservoir 105 alone or in aqueous solution, loading of reservoir 105 in block 204 is preferably performed as quickly as possible and as close as possible to commencing start-up in block 205 to minimize and/or avoid natural dispersion of the chemical agent(s) outside of the portion of reservoir 105 into which they are injected in block 204. However, in embodiments wherein the chemical agent(s) are injected into the reservoir 105 in a non-aqueous solution (i.e., the chemical agent(s) are mixed with organic solvent(s)), a soaking period may be preferred after loading reservoir 105 in block 204 and before start-up in block 205. As previously described, the organic solvent(s) function as diluent(s) that reduce the viscosity of the viscous hydrocarbons, thereby enhancing mobilization. A soaking period provides the solvent(s) with additional time to disperse and mix with the hydrocarbons in reservoir 105. In general, the soaking period can last a few days to a few months. It should be appreciated that the solvent in the injection fluid may also enhance penetration of the chemical agent(s) in the formation as it displaces connate mobile water as well as dilutes the viscous hydrocarbons. [0039] Referring briefly to Figure 4, reservoir 105 and formation 101 are shown following injection of the injection fluid according to block 204. In Figure 4, the injection fluid is represented with reference numeral 110. The injection fluid 110 forms a loaded zone 111 extending radially outward and longitudinally along the portion of horizontal section(s) 22, 32 from which the injection fluid 110 was injected into reservoir 105.

[0040] Referring again to Figure 3, once reservoir 105 (or the portion of reservoir 105 being loaded) is sufficiently charged with the injection fluid according to block 204 and the soaking period (if any) is complete, start-up of the SAGD well pair 20, 30 is commenced in block 205. In general, start-up of SAGD well pair 20, 30 is performed by injecting steam through injection well 20 and production well 30 in either circulation or "bullheading" modes until appropriate pressure and fluid communication between wells 20, 30 is achieved. Then, injection of steam into production well 30 is ceased, while steam continues to be injected through injection well 20.

[0041] Referring briefly to Figure 5, the steam and associated hot water percolate through reservoir 105, thereby forming a steam chamber 120 that extends horizontally outward and vertically upward from horizontal section 22 of injection well 20. Steam chamber 120 is generally shaped like an inverted triangular prism that extends along and upward from the full length of horizontal section 22. Thermal energy from steam chamber 120 increases the temperature of reservoir 105. In other words, the thermal energy from steam chamber 120 raises the temperature of reservoir 105 and loaded zone 111 to an elevated temperature greater than the ambient temperature of reservoir 105. In embodiments described herein, the elevated temperature is sufficient to reduce the viscosity of the viscous hydrocarbons in reservoir 105 and mobilize at least a portion of the hydrocarbons in reservoir 105.

[0042] As previously described, each surfactant selected for use as a chemical agent in block 201 is a surface active agent that is generally unable to emulsify immobile hydrocarbons in reservoir 105 at ambient reservoir temperatures, but are capable of emulsifying hydrocarbons in reservoir 105 once they become mobile (i.e., at temperatures above the ambient reservoir temperature). Thus, in the embodiments where the chemical agent(s) include surfactant(s), once the hydrocarbons in reservoir 105 are mobilized, the surfactant(s) can emulsify the hydrocarbons in reservoir 105 to further enhance mobility. In addition, as previously described, each alkali selected for use as a chemical agent in block 201 can access and react with the organic acids in the mobilized hydrocarbons. In particular, the alkalis react with the organic acids in the mobilized hydrocarbons to form surfactants in-situ. Such surfactants formed in-situ enhance the release of hydrocarbons from the formation surfaces and emulsify the hydrocarbons into oil-in-water emulsions, thereby offering the potential to further enhance hydrocarbon mobility. In embodiments where the chemical agent(s) are mixed with one or more solvent(s) to form a non-aqueous solution, the solvent(s) continue to facilitate mobilization of the hydrocarbons in reservoir 105. The conventional approach to start-up of a SAGD well pair via injection of steam to initiate mobilization of viscous hydrocarbons and allow fluid communication between the SAGD well pair may take several months. During this lengthy start-up period before production of hydrocarbons, money and resources are being invested into the SAGD operations. In embodiments described herein, the injection of an injection fluid comprising one or more chemical agents described herein into the reservoir (e.g., reservoir 105) prior to injection of steam in the start-up phase offers the potential to accelerate subsequent start-up of the SAGD well pair (e.g., SAGD well pair 20, 30).

[0043] In the manner described, embodiments described herein (e.g., system 10 and method 200) are employed to produce viscous hydrocarbons in a subterranean reservoir. Although such embodiments can be used to recover and produce heavy oil having any viscosity under ambient reservoir conditions, it is particularly suited for the recovery and production of viscous hydrocarbons having an API gravity greater than 10,000 cP under ambient reservoir conditions. In addition, although method 200 shown in Figure 3 is described in the context of well system 10 including SAGD well pair 20, 30, in general, embodiments of methods described herein (e.g., method 100) can be used in connection with other types of thermal recovery technique for viscous hydrocarbons such as steam flooding, cyclic steam stimulation (CSS), electric reservoir heating operations, etc.

[0044] While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

Claims

CLAIMS What is claimed is:

1. A method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure, the method comprising:

(a) injecting a chemical agent into the reservoir with the reservoir at the ambient temperature, wherein the chemical agent is a surfactant or an alkali; and

(b) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (a).

2. The method of claim 1, further comprising:

forming an aqueous solution comprising the chemical agent before (a);

wherein (a) comprises injecting the aqueous solution into the reservoir with the reservoir at the ambient temperature.

3. The method of claim 2, further comprising:

determining a salt concentration and a salt composition in the reservoir;

forming a brine having a salt concentration and a salt composition analogous to the salt concentration and the salt composition of the reservoir; and

mixing the brine and the chemical agent to form the aqueous solution before (a).

4. The method of claim 1, further comprising:

forming a non-aqueous solution comprising the chemical agent and an organic solvent before (a);

wherein (a) comprises injecting the non-aqueous solution into the reservoir with the reservoir at the ambient temperature.

5. The method of claim 4, wherein the organic solvent comprises xylene, toluene, benzene, naphtha, or tetrahydrofuran (THF).

6. The method of claim 2, wherein the chemical agent is a surfactant.

7. The method of claim 6, wherein the surfactant is a branched alcohol propoxylated sulfate, an alkyl ether sulfacte, an internal olefin sulfonate, a branched alpha olefin sulfonate, an alkylaryl sulfonate, a polyoxyethylene alkyl phenyl ether, a sodium oleate, a potassium oleate, a gemini (dimeric) surfactant, or a polyoxyethylenesorbitan ester.

8. The method of claim 2, wherein the chemical agent is an alkali.

9. The method of claim 8, wherein the alkali is a sodium carbonate, potassium carbonate, lithium carbonate, or cesium carbonate.

10. A method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure, the method comprising:

(a) selecting a chemical agent that is water-soluble;

(b) forming an aqueous solution with the chemical agent, wherein the chemical agent has a concentration in the aqueous solution more than 5 vol. % or 5 wt. % of the aqueous solution;

(c) injecting the aqueous solution into the reservoir with the reservoir at the ambient temperature; and

(d) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (c).

11. The method of claim 10, wherein the chemical agent is a surfactant or an alkali.

12. The method of claim 11, further comprising:

determining a salt concentration and a salt composition in the reservoir;

forming a brine having a salt concentration and a salt composition analogous to the salt concentration and the salt composition of the reservoir;

wherein (b) comprises mixing the brine and the chemical agent to form the aqueous solution.

13. The method of claim 1 1, wherein the chemical agent is a branched alcohol propoxylated sulfate, an alkyl ether sulfacte,an internal olefin sulfonate, a branched alpha olefin sulfonate, an alkylaryl sulfonate, a polyoxyethylene alkyl phenyl ether, a sodium oleate, a potassium oleate, a gemini (dimeric) surfactant, or a polyoxyethylenesorbitan ester.

14. The method of claim 10, wherein the chemical agent is sodium carbonate, potassium carbonate, lithium carbonate, or cesium carbonate.

15. A method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure, the method comprising:

(a) selecting a chemical agent;

(b) dissolving the chemical in an organic solvent to form a solvent-chemical agent mixture;

(c) injecting the solvent-chemical agent mixture into the reservoir with the reservoir at the ambient temperature; and

16. The method of claim 15, wherein the chemical agent is a surfactant or an alkali.

17. The method of claim 16, wherein the solvent comprises xylene, toluene, benzene, naphtha, or tetrahydrofuran (THF).