WO2015157160A1 - Systems and methods for accelerating production of viscous hydrocarbons in a subterranean reservoir with aqueous comprising thrmally partially decomposable surfactants and carbonate-based alkalis - Google Patents

Abstract

A method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation includes (a) forming an aqueous solution with a surfactant and a carbonate-based alkali. The surfactant is water soluble and thermally partially decomposable at a partial decomposition temperature that is greater than the ambient temperature of the reservoir. The method also includes (b) injecting the aqueous solution into the reservoir at a temperature less than or equal to the ambient temperature of the reservoir. Further, the method includes (c) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (b). The operating temperature is greater than or equal to the partial decomposition temperature.

Description

SYSTEMS AND METHODS FOR ACCELERATING PRODUCTION OF VISCOUS HYDROCARBONS IN A SUBTERRANEAN RESERVOIR WITH AQUEOUS COMPRISING THRMALLY PARTIALLY DECOMPOSABLE SURFACTANTS AND

CARBONATE-BASED ALKALIS

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims benefit of U.S. provisional patent application Serial No. 61/976,938 filed April 8, 2014, and entitled "Systems and Methods for Accelerating Production of Viscous Hydrocarbons in a Subterranean Reservoir with Aqueous Solutions Comprising Thermally Partially Decomposable Surfactants and Carbonate-Based Alkalis," which is hereby incorporated herein by reference in its entirety. This application also claims benefit of U.S. provisional patent application Serial No. 62/048,524 filed September 10, 2014, and entitled "Systems and Methods for Accelerating Production of Viscous Hydrocarbons in a Subterranean Reservoir with Aqueous Comprising Thermally Partially Decomposable Surfactants and Carbonate-Based Alkalis," 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 aqueous solutions comprising thermally partially decomposable surfactants and carbonate-based alkalis 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) forming an aqueous solution with a surfactant and a carbonate-based alkali. The surfactant is water soluble and thermally partially decomposable at a partial decomposition temperature that is greater than the ambient temperature of the reservoir. In addition, the method comprises (b) injecting the aqueous solution into the reservoir at a temperature less than or equal to the ambient temperature of the reservoir. Further, the method comprises (c) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (b). The operating temperature is greater than or equal to the partial decomposition temperature.

[0009] In another embodiment disclosed herein, a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) selecting a surfactant. The surfactant is water soluble and thermally partially decomposable at a temperature between 50°C and 100°C. In addition, the method comprises (b) forming an aqueous solution comprising the surfactant and a carbonate-based alkali. Further, the method comprises (c) injecting the aqueous solution into the reservoir at a first temperature that is less than 50°C. Still further, the method comprises (d) adding thermal energy to the reservoir to increase the temperature of the reservoir above 50°C 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 first thermally partially decomposable surfactant. In addition, the method comprises (b) selecting a first carbonate- based alkali. Further, the method comprises (c) forming an aqueous solution comprising the first thermally partially decomposable surfactant and the first carbonate-based alkali. Still further, the method comprises (d) injecting the aqueous solution into the reservoir with the reservoir at the ambient temperature. The method also comprises (e) adding thermal energy to the reservoir after (d) to increase the temperature of the reservoir to an elevated temperature greater than a partial decomposition temperature of the first thermally partially decomposable surfactant.

[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 aqueous solution 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 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 an aqueous solution including a mixture of one or more water soluble thermally partially decomposable surfactants and one or more water soluble carbonate-based alkali prior to initiating start-up of the SAGD well pair 20, 30. The subsequent addition of thermal energy during start-up of the SAGD well pair 20, 30 and/or production operations in combination with the aqueous solution 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. As will be described in more detail below, since the mixture of thermally partially decomposable surfactant(s) and carbonate-based alkali(s) are injected in an aqueous solution, method 200 is particularly suited for use with reservoirs exhibiting a native permeability to water and is generally independent of the native wettability of the reservoir.

[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 water soluble thermally partially decomposable surfactant(s) and one or more carbonate-based alkali(s) are selected. Each water soluble thermally partially decomposable surfactant selected is partially decomposable at a "partial decomposition temperature" greater than the ambient temperature of reservoir 105 to release one or more acids. Thus, at the partial decomposition temperature, the surfactant partially thermally decomposes - a portion, but not all, of the surfactant is thermally decomposed. As will be described in more detail below, the acid(s) released upon partial thermal decomposition of the selected surfactant(s) react with the carbonate-based alkali(s) in the aqueous solution to form a gas (e.g., carbon-dioxide gas). In embodiments described herein, each thermally partially decomposable surfactant selected in block 201 preferably has a partial decomposition temperature between 50°C and 200°C. Examples of suitable surfactants that are thermally partially decomposable between 50°C and 200°C include, without limitation, ammonium alkyl ether sulfate (e.g., Petrostep® ES-65A available from Stepan Company of Northfield, Illinois, Alpha Foamer® available from Stepan Company of Northfield, Illinois, etc.), sodium laureth sulfate (e.g., Steol® CS-270 available from Stepan Company of Northfield, Illinois, Steol® CS-330 available from Stepan Company of Northfield, Illinois, etc.), ammonium lauryl ethyl sulfate (Polystep® B-11 available from Stepan Company of Northfield, Illinois, Steol® CA-330 available from Stepan Company of Northfield, Illinois, etc.), ammonium nonylphenol ethoxylate sulfate (e.g., Polystep® B-l available from Stepan Company of Northfield, Illinois, etc.), and the like. [0027] Examples of suitable water soluble carbonate-based alkalis include, without limitation, lithium carbonate, sodium carbonate, potassium carbonate, cesium carbonate, and the like.

[0028] One or more other water soluble chemical additives can also be added to the aqueous solution comprising the one or more thermally partially decomposable surfactants and the one or more carbonate-based alkali(s). Each water soluble chemical additive is preferably non- reactive or substantially non-reactive in reservoir 100 at ambient reservoir temperatures, but decomposes at a temperature above the ambient reservoir temperature and below the operating temperature of the thermal recovery process employed to produce reservoir 100 to form one or more of (a) a gas or gases; (b) an alkaline compound or compounds, which can react with naturally occurring acids in hydrocarbon reservoir to form surfactant-like compounds; (c) a compound miscible with hydrocarbons to some extent; (d) a compound that controls the wettability of solid surfaces; or (e) combinations thereof. As used herein, the phrase "substantially non-reactive" refers to a chemical additive that has a conversion rate of less than 10% over a 24 hour period in an aqueous solution, as prepared according to block 202 described in more detail below, and in the presence of hydrocarbons in a reservoir at the ambient reservoir temperature. For most reservoirs containing viscous hydrocarbons and most thermal recovery processes (e.g., SAGD, steam flooding, cyclic steam stimulation (CSS), electric reservoir heating operations, etc.), each chemical additive selected in block 201 preferably decomposes at a temperature between 40°C and 200°C, and more preferably between 80°C and 150°C. For example, the typical ambient reservoir temperature in the Canadian Oil Sands is about 8°C to 12°C, and the typical operating temperature of a SAGD thermal recovery process is 180°C to 220°C. Thus, each chemical additive included in the aqueous solution for use in the Canadian Oil Sands to be produced using SAGD is a chemical additive that is non-reactive or substantially non-reactive in the Canadian Oil Sands between 8°C and 12°C (i.e., at ambient reservoir temperatures), but decompose at a temperature above 8°C and 12°C (i.e., the ambient reservoir temperature) and below 180°C to 220°C (i.e., the operating temperature of the SAGD thermal recovery process). Examples of suitable chemical additives that can be added to the aqueous solution include, without limitation, urea and thiourea dioxide.

[0029] Moving now to block 202, the selected thermally partially decomposable surfactant(s) and carbonate-based alkali(s), as well as any chemical additives (if any), are mixed with a brine (i.e., solution of salt in water) to form an aqueous solution. The brine preferably has a salt concentration and composition analogous to that of reservoir 105 to reduce the potential for the aqueous solution to negatively alter reservoir 105. 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 general, an aqueous solution is preferred as water is generally mobile within a reservoir comprising viscous hydrocarbons such as heavy oil and bitumen (e.g., reservoir 105).

[0030] In one exemplary embodiment, the aqueous solution formed in block 202 comprises Petrostep® ES-65A (thermally partially decomposable surfactant), sodium carbonate (carbonate-based alkali), and urea (other chemical additive) mixed with a brine. Petrostep® ES-65A has a partial thermal decomposition temperature above 100°C. The urea is water soluble and generally non-reactive at the ambient temperature of reservoir 105, but when heated to 100°C to 150°C in the presence of water, decomposes to form carbon-dioxide gas and ammonia gas.

[0031] In general, the relative concentrations of the thermally partially decomposable surfactant(s), the carbonate-based alkali(s), and any other chemical additives in the aqueous solution formed in block 202 can be varied depending on a variety of factors including, without limitation, costs, concentration(s) necessary to achieve the desired result (i.e., accelerated commissioning of the SAGD well pair and/or production), the viscosity of the viscous hydrocarbons, the type of formation, etc. However, in embodiments described herein, for most applications the aqueous solution formed in block 202 preferably comprises less than 5.0 wt % of the thermally partially decomposable surfactant(s), less than 10.0 wt % of the carbonate- based alkali(s), and less than 1.0 wt % of other chemical additives. In block 203, the parameters for loading or injecting the reservoir 105 with the aqueous solution 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 aqueous solution will be injected into reservoir 105. The injection pressure of the aqueous solution 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). [0032] Referring still to Figure 3, moving now to block 204, reservoir 105 is loaded or injected with the aqueous solution formed in block 202 according to the injection parameters determined in block 203. Since the aqueous solution 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 aqueous solution according to block 204 may be referred to herein as "cold" loading of reservoir 105.

[0033] 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 aqueous solution can be injected into reservoir 105 utilizing one well 20, 30, both wells 20, 30, or combinations thereof over time. The aqueous solution 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 aqueous solution is injected into the reservoir 105 in block 204 before commissioning SAGD well pair 20, 30, the aqueous solution 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 aqueous solution 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 aqueous solution 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 aqueous solution 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.

[0034] In implementations where production well 30 is not employed for injection of the aqueous solution, 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 aqueous solution) 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 aqueous solution through reservoir 105 and the saturation of reservoir 105 with the aqueous solution. Injection of the aqueous solution in block 204 is performed until reservoir 105 (or portion of reservoir 105 to be loaded) is sufficiently charged.

[0035] It should be appreciated that the relatively low viscosity of the aqueous solution facilitates easy injection into the formation (i.e., the formation does not substantially resist injection of the aqueous solution). At the ambient temperature of reservoir 105, the surfactant(s) and/or carbonate-based alkali(s) may facilitate the release of some hydrocarbons from the surfaces of the sand and rocks in the formation. The carbonate-based alkali(s) in the aqueous solution also offer the potential to reduce retention of the surfactant(s) on the rock surfaces in the reservoir 105.

[0036] Referring briefly to Figure 4, reservoir 105 and formation 101 are shown following injection of the aqueous solution according to block 204. In Figure 4, the aqueous solution is represented with reference numeral 110. The aqueous solution 110 forms a loaded zone 1 11 extending radially outward and longitudinally along the portion of horizontal section(s) 22, 32 from which the aqueous solution 110 was injected into reservoir 105.

[0037] Referring again to Figure 3, once reservoir 105 (or the portion of reservoir 105 being loaded) is sufficiently charged with the aqueous solution according to block 204, 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.

[0038] 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. The elevated temperature is sufficient to reduce the viscosity of the viscous hydrocarbons in reservoir 105.

[0039] The aqueous solution injected into the reservoir 105 in block 204 is generally stable at the ambient temperature of reservoir 105. However, once the temperature of the reservoir exceeds the partial decomposition temperature of the surfactant(s) in the aqueous solution, the surfactant(s) partially decompose to form acid(s), which react with the carbonate-based alkali(s) in the aqueous solution to form carbon dioxide gas in situ (i.e., within reservoir 105). Formation of the carbon dioxide gas in situ offers the potential to decrease the viscosity of the viscous hydrocarbons and enhance mobilization of the hydrocarbons. In addition, the carbon dioxide gas formed in situ provides additional energy and drive force (e.g., pressure) for mobilizing and producing the hydrocarbons. The partial decomposition of the surfactant(s) may also yield or produce smaller surfactant molecules. The portion of the surfactant(s) that have not decomposed at the partial decomposition temperature (i.e., the remaining surfactant(s)), as well as any smaller surfactant molecules resulting from the partial decomposition of the surfactant(s), can access and emulsify the mobilized hydrocarbons to further enhance mobilization.

[0040] Any other chemical additive(s) in the aqueous solution are preferably selected and included to facilitate a further reduction in the viscosity of the hydrocarbons and enhanced mobilization of the hydrocarbons. For example, the optional chemical additive urea is generally stable at the ambient temperature of reservoir 105, but when the temperature of the reservoir is increased to about 100°C to 120°C upon steam injection, the urea hydrolyzes into carbon dioxide gas and ammonia gas in situ (i.e., within reservoir 105). The carbon dioxide gas resulting from the hydrolysis of the urea functions in a similar manner as the carbon dioxide gas resulting from the reaction of acid(s) derived from the partial decomposition of the surfactant(s) with the carbonate-based alkali(s). Namely, the carbon dioxide gas resulting from the hydrolysis of the urea offers the potential to decrease the viscosity of the viscous hydrocarbons and enhance mobilization of the hydrocarbons, as well as provides additional energy and drive force (e.g., pressure) for mobilizing and producing the hydrocarbons. The ammonia gas resulting from the hydrolysis of the urea react with organic acids in the viscous hydrocarbons to form surfactants in situ, which can access and emulsify the mobilized hydrocarbons to further enhance mobilization.

[0041] 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 aqueous solution comprising one or more partially thermally decomposable surfactants and a carbonate-based alkali 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).

[0042] 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.

[0043] 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) forming an aqueous solution with a surfactant and a carbonate-based alkali, wherein the surfactant is water soluble and thermally partially decomposable at a partial decomposition temperature that is greater than the ambient temperature of the reservoir;

(b) injecting the aqueous solution into the reservoir at a temperature less than or equal to the ambient temperature of the reservoir; and

(c) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (b), wherein the operating temperature is greater than or equal to the partial decomposition temperature.

2. The method of claim 1, further comprising:

(d) partially thermally decomposing the surfactant during (c);

(e) forming an acid in response to (d);

(f) reacting the acid with the carbonate-based alkali to form a gas.

3. The method of claim 2, wherein the gas is carbon dioxide.

4. The method of claim 3, wherein the aqueous solution comprises a chemical additive, wherein the chemical additive is water soluble and substantially non-reactive in the reservoir at the ambient temperature of the reservoir and decomposes at a temperature above the ambient reservoir temperature and below the operating temperature.

5. The method of claim 4, wherein the chemical additive is urea.

6. The method of claim 5, further comprising:

(g) converting the urea into carbon dioxide gas and ammonia gas during (c); (h) reacting the ammonia gas with an organic acid in the viscous hydrocarbons to form a surfactant in the reservoir.

7. The method of claim 1, 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, the surfactant, and the carbonate-based alkali to form the aqueous solution in (a).

8. The method of claim 1, wherein the partial decomposition temperature is between 50°C and 200°C.

9. The method of claim 8, wherein the surfactant is ammonium alkyl ether sulfate, sodium laureth sulfate, ammonium lauryl ethyl sulfate, or ammonium nonylphenol ethoxylate sulfate.

10. The method of 9, wherein the carbonate-based alkali is lithium carbonate, sodium carbonate, potassium carbonate, or cesium carbonate.

11. The method of claim 1, wherein the aqueous solution comprises a chemical additive, wherein the chemical additive is water soluble and substantially non-reactive in the reservoir at the ambient temperature of the reservoir and decomposes at a temperature above the ambient reservoir temperature and below the operating temperature.

12. The method of claim 11, wherein the chemical additive is urea or thiourea dioxide.

13. The method of claim 11, wherein the aqueous solution comprises less than 5.0 wt % of the water soluble surfactant, less than 10.0 wt % of the carbonate-based alkali, and less than 1.0 wt % of the chemical additive.

14. 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 surfactant, wherein the surfactant is water soluble and thermally partially decomposable at a temperature between 50°C and 100°C;

(b) forming an aqueous solution comprising the surfactant and a carbonate-based alkali;

(c) injecting the aqueous solution into the reservoir at a first temperature that is less than 50°C; and

(d) adding thermal energy to the reservoir to increase the temperature of the reservoir above 50°C after (c).

15. The method of claim 14, further comprising:

(e) thermally decomposing a portion of the surfactant to yield an acid in response to

(d);

(f) reacting the acid with the carbonate-based alkali to form carbon dioxide gas in the reservoir.

16. The method of claim 15, wherein the aqueous solution comprises a chemical additive, wherein the chemical additive is water soluble and substantially non-reactive in the reservoir at the ambient temperature of the reservoir and decomposes at a temperature above the ambient reservoir temperature and below the operating temperature.

17. The method of claim 16, wherein the chemical additive is urea.

18. The method of claim 17, further comprising:

(g) converting the urea into carbon dioxide gas and ammonia gas during (d);

(h) reacting the ammonia gas with an organic acid in the viscous hydrocarbons to form a surfactant in the reservoir.

19. The method of claim 14, 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, the surfactant, and the carbonate-based alkali to form the aqueous solution in (a).

20. The method of claim 14, wherein the surfactant is ammonium alkyl ether sulfate, sodium laureth sulfate, ammonium lauryl ethyl sulfate, or ammonium nonylphenol ethoxylate sulfate.

21. The method of 14, wherein the carbonate-based alkali is lithium carbonate, sodium carbonate, potassium carbonate, or cesium carbonate.

22. The method of claim 14, wherein the aqueous solution comprises a chemical additive, wherein the chemical additive is water soluble and substantially non-reactive in the reservoir at the ambient temperature of the reservoir and decomposes at a temperature above the ambient reservoir temperature and below the operating temperature.

23. The method of claim 22, wherein the chemical additive is urea or thiourea dioxide.

24. The method of claim 22, wherein the aqueous solution comprises less than 5.0 wt % of the water soluble surfactant, less than 10.0 wt % of the carbonate-based alkali, and less than 1.0 wt % of the chemical additive.

25. 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 first thermally partially decomposable surfactant;

(b) selecting a first carbonate-based alkali;

(c) forming an aqueous solution comprising the first thermally partially decomposable surfactant and the first carbonate-based alkali;

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

(e) adding thermal energy to the reservoir after (d) to increase the temperature of the reservoir to an elevated temperature greater than a partial decomposition temperature of the first thermally partially decomposable surfactant.

26. The method of claim 25, wherein the partial decomposition temperature is between 50°C and 200°C.

27. The method of claim 25, wherein the first thermally partially decomposable surfactant is ammonium alkyl ether sulfate, sodium laureth sulfate, ammonium lauryl ethyl sulfate, or ammonium nonylphenol ethoxylate sulfate; and

wherein the first carbonate-based alkali is lithium carbonate, sodium carbonate, potassium carbonate, or cesium carbonate.

28. The method of claim 27, wherein the aqueous solution comprises urea or thiourea dioxide.