WO2014151712A2 - Systèmes et procédés pour accélérer la production d'hydrocarbures visqueux dans un réservoir souterrain à l'aide d'agents chimiques activés thermiquement - Google Patents

Systèmes et procédés pour accélérer la production d'hydrocarbures visqueux dans un réservoir souterrain à l'aide d'agents chimiques activés thermiquement Download PDF

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Publication number
WO2014151712A2
WO2014151712A2 PCT/US2014/026299 US2014026299W WO2014151712A2 WO 2014151712 A2 WO2014151712 A2 WO 2014151712A2 US 2014026299 W US2014026299 W US 2014026299W WO 2014151712 A2 WO2014151712 A2 WO 2014151712A2
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Prior art keywords
reservoir
steam
hydrocarbons
aqueous solution
injecting
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WO2014151712A3 (fr
Inventor
Andrew C. REES
Calvin Coulter
Russell Engelman
Uriel Guerrero-Aconcha
Spencer Taylor
Allan Peats
Huang Zeng
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BP Corp North America Inc
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BP Corp North America Inc
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Priority to CA2902870A priority Critical patent/CA2902870C/fr
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Publication of WO2014151712A3 publication Critical patent/WO2014151712A3/fr
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2406—Steam assisted gravity drainage [SAGD]
    • E21B43/2408—SAGD in combination with other methods
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection

Definitions

  • the invention relates generally to thermal recovery techniques for producing viscous hydrocarbons such as heavy oil and bitumen. More particularly, the invention relates to the injection the chemical agents and subsequent thermal activation of the chemical agents to accelerate production of viscous hydrocarbons with thermal recovery techniques.
  • a steam-assisted gravity drainage (SAGD) operation is one thermal technique for recovering viscous hydrocarbons such as bitumen and heavy oil.
  • 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.
  • 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.
  • 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.
  • the commissioning processes can be time consuming, typically taking more than three months, which results in high costs and delays the ultimate production of oil.
  • the method comprises (a) injecting an aqueous solution into the reservoir with the reservoir at the reservoir ambient temperature.
  • the aqueous solution comprises water and a water-soluble chemical agent that is substantially non-decomposable and substantially non-reactive in the reservoir at the ambient temperature of the reservoir.
  • the method comprises (b) adding thermal energy to the reservoir at any time after (a) to increase the temperature of at least a portion of the reservoir to an elevated temperature greater than the ambient temperature of the reservoir.
  • the method comprises (c) in response to the elevated temperature in (b), mobilizing at least a portion of the hydrocarbons in the reservoir by reducing the viscosity of the hydrocarbons and allowing the chemical agent to enhance mobilization of the hydrocarbons.
  • the method comprises (a) injecting an aqueous solution into the reservoir through an injection well or a production well of a SAGD well pair with the reservoir at the ambient temperature of the reservoir.
  • the aqueous solution comprises water and a water-soluble chemical agent that is substantially non-decomposable and substantially non-reactive in the reservoir at the ambient temperature of the reservoir.
  • the method comprises (b) injecting steam into the reservoir after (a) through the injection well or the production well to increase the temperature of at least a portion of the reservoir to an elevated temperature greater than the ambient temperature of the reservoir.
  • the method comprises (c) in response to the elevated temperature in (b), mobilizing at least a portion of the hydrocarbons in the reservoir by reducing the viscosity of the hydrocarbons and allowing the chemical agent to enhance mobilization of the hydrocarbons.
  • the method comprises (a) injecting a volume of an aqueous solution into the reservoir with the reservoir at the ambient temperature.
  • the aqueous solution comprises a brine and a water-soluble chemical agent that is substantially non-decomposable and substantially non-reactive in the reservoir at the ambient temperature of the reservoir.
  • the chemical agent in the aqueous solution has a concentration greater than or equal to 0.01 wt % and less than the solubility limit of the chemical agent in the brine at the ambient temperature of the reservoir.
  • the volume is based on a pore volume of connate water in a portion of the reservoir to be produced.
  • the method comprises (b) adding thermal energy to the reservoir at any time after (a) to increase the temperature of at least a portion of the reservoir to an elevated temperature greater than the ambient temperature of the reservoir. Further, the method (c) in response to the elevated temperature in (b), mobilizing at least a portion of the hydrocarbons in the reservoir and allowing the chemical agent to enhance mobilization of the hydrocarbons.
  • the method comprises (a) injecting steam into the reservoir.
  • the steam has a steam quality less than 100% and comprises a liquid phase and a vapor phase.
  • Injecting the steam comprises delivering an aqueous solution to the reservoir in the liquid phase of the steam and injecting the aqueous solution into the reservoir with the steam.
  • the aqueous solution comprises a surfactant.
  • the method comprises (b) in response to the steam injected in (a), mobilizing the hydrocarbons in the reservoir by reducing the viscosity of the hydrocarbons.
  • the method comprises (c) emulsifying the hydrocarbons with the surfactant during (b) to enhance the mobilization of the hydrocarbons.
  • the method comprises (a) injecting steam into the reservoir.
  • the steam has a steam quality less than 100% and comprises a liquid phase and a vapor phase.
  • Injecting the steam comprises delivering an aqueous solution to the reservoir in the liquid phase of the steam and injecting the aqueous into the reservoir with the steam during (a).
  • the aqueous solution comprises a nonvolatile thermally activated chemical species.
  • the liquid phase of the steam has a temperature.
  • the thermally activated chemical species has a conversion rate less than 10 mol % over a time period less than 10 minutes in the presence of the steam and at the temperature of the liquid phase.
  • the method comprises (b) decomposing or reacting the thermally activated chemical species in the reservoir to enhance the mobilization of the viscous hydrocarbons.
  • the method comprises (a) during a loading phase, loading a portion of the reservoir with an aqueous solution injected into the reservoir through an injection well or a production well of a SAGD well pair with the reservoir at the ambient temperature of the reservoir.
  • the aqueous solution comprises water and a water- soluble chemical agent that is substantially non-decomposable and substantially non-reactive in the reservoir at the ambient temperature of the reservoir.
  • the method comprises (b) at any time after the loading phase in (a), commencing a start-up phase wherein steam is injected into the reservoir through the injection well or the production well to increase the temperature of the portion of the reservoir to an elevated temperature greater than the ambient temperature of the reservoir. Further, the method comprises (c) in response to the elevated temperature in (b), mobilizing at least a portion of the hydrocarbons in the reservoir by reducing the viscosity of the hydrocarbons and allowing the chemical agent to enhance mobilization of the hydrocarbons. Still further, the method comprises (d) continuing the startup phase until fluid communication between the injection well and the production well is achieved.
  • the method comprises (e) in response to (d), ceasing the start-up phase and commencing a production phase wherein steam is injected into the reservoir through the injection well and at least a portion of the hydrocarbons are produced from the reservoir through the production well.
  • 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 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.
  • 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;
  • Figure 2 is a schematic cross-sectional end view of the system of Figure 1 taken along section II— II of Figure 1;
  • 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;
  • 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 an aqueous solution into the reservoir of Figure 1 according to the method of Figure 3;
  • 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;
  • Figure 6 is a graphical illustration of the amount of urea reacted versus temperature.
  • the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to... .”
  • 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.
  • 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.
  • an axial distance refers to a distance measured along or parallel to the central axis
  • a radial distance means a distance measured perpendicular to the central axis
  • system 10 for producing viscous hydrocarbons (e.g., bitumen and heavy oil) from a subterranean formation 100 using a thermal recovery technique is shown.
  • system 10 is configured to employ steam- assisted gravity drainage (SAGD) thermal recovery techniques to produce generally immobile, viscous hydrocarbons.
  • SAGD steam- assisted gravity drainage
  • formation 100 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).
  • 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.
  • layer 102 contains a reservoir 105 of viscous hydrocarbons (reservoir 105 shaded in Figures 1 and 2).
  • System 10 mobilizes, collects and produces viscous hydrocarbons in reservoir 105 using SAGD techniques.
  • 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.
  • horizontal sections 22, 32 are lined with perforated or slotted liners, and thus, are both open to reservoir 105.
  • FIG. 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.
  • reservoir 105 is loaded with one or more chemical agents 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 chemical agent(s) 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.
  • 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.
  • 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.
  • 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.
  • 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 in response to thermal energy added during start-up of the SAGD well pair 20, 30.
  • selection of the particular chemical agent(s) is based, at least in part, on its ability to enhance the mobility of the hydrocarbons in the particular formation of interest (e.g., reservoir 105 in formation 101) at an elevated temperature greater than the ambient reservoir temperature.
  • each selected chemical agent is water soluble such that it can be injected into reservoir 105 in an aqueous solution as will be described in more detail below.
  • the cost and availability of various chemical agent(s) may also impact the selection in block 201.
  • each chemical agent selected in block 201 is a water soluble surfactant or a water soluble thermally activated chemical species.
  • Each selected chemical agent can be used alone (e.g., surfactant alone or thermally activated chemical species alone), with one or more other chemical agents (e.g., surfactant in combination with a thermally activated chemical species, multiple surfactants used together, multiple thermally activated chemical species used together, etc.), with one or more other chemical additives (e.g., surfactant in combination with another chemical, thermally activated chemical species in combination with another chemical, etc.), or combinations thereof.
  • 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).
  • bitumen e.g., bitumen of the Canadian oil sands of Alberta
  • ambient reservoir temperatures typically 8-12° C
  • 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.
  • Suitable surfactants that can be selected as a chemical agent 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., ENOROETTM 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.
  • APS branched alcohol propoxylated sulfates
  • alkyl ether sulfactes e.g., Petrostep ES65A from Stepan Chemical Company of Northfield, Illinois
  • poly oxy ethylene alkyl phenyl ether e.g. Triton X-100TM available from The DOW Chemical Company of Midland, Michigan
  • sodium/potassium oleate preferably with a chelating agent such as Na-EDTA
  • gemini (dimeric) surfactants e.g., polyoxyethylenesorbitan esters
  • Each thermally activated chemical species selected for use as a chemical agent in block 201 is a chemical species that (1) is non-decomposable or substantially non-decomposable in reservoir 105 at ambient reservoir temperatures and (2) is non-reactive or substantially non- reactive in reservoir 105 at ambient reservoir temperatures, but decomposes and/or reacts at an elevated temperature that is greater than the ambient reservoir temperature and less than the operating temperature of the thermal recovery process employed (e.g., SAGD operating temperature) 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; (e) a surfactant or surfactant-like compound; or (f) combinations thereof.
  • SAGD operating temperature e.g., SAGD operating temperature
  • the phrases “substantially non- decomposable” and “substantially non-reactive” refer to a chemical species that has a conversion rate (via decomposition and/or reaction) of less than 1 mol % over a 24 hour period in an aqueous solution at ambient reservoir temperatures 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.
  • the reaction of the thermally activated chemical species at the elevated temperature may be directly or indirectly thermally driven.
  • the thermal energy from the elevated temperature may sufficiently mobilize the viscous hydrocarbons to enable the thermally activated chemical species to access and react with the hydrocarbons.
  • the thermal energy does not directly trigger the thermally activated chemical species to react, but rather, sufficiently mobilizes the hydrocarbons to enable the thermally activated chemical species to sufficiently comingle and react with the hydrocarbons.
  • the decomposition or reaction of the thermally activated chemical species may form carbon-dioxide gas (CO 2 ) or other compound(s) miscible with hydrocarbons, which increase the mobility of the hydrocarbons.
  • CO 2 carbon-dioxide gas
  • each thermally activated chemical species selected as chemical agent in block 201 decomposes and/or reacts at a temperature preferably between 40° and 200° C, and more preferably between 60° and 120° C.
  • a temperature preferably between 40° and 200° C, and more preferably between 60° and 120° C.
  • the typical ambient reservoir temperature in the Canadian oil sands is about 8° to 12° C
  • the typical operating temperature of a SAGD thermal recovery process is 180° to 220° C.
  • each thermally activated chemical species selected as a chemical agent in block 201 for viscous hydrocarbons in the Canadian oil sands to be produced using SAGD is a chemical species that is non- decomposable (or substantially non-decomposable) and non-reactive (or substantially non- reactive) in the Canadian oil sands between 8° and 12° C (i.e., at ambient reservoir temperatures), but decompose and/or reacts at a temperature above 8° and 12° C (i.e., the ambient reservoir temperature) and below 180° to 220° (i.e., the operating temperature of the SAGD thermal recovery process).
  • thermally activated chemical species examples include, without limitation, urea; ammonium salts (e.g., ammonium carbonate, ammonium bicarbonate, ammonium acetate, ammonium nitrate, ammonium chloride, etc.); thiourea dioxide; bicarbonates (e.g.
  • a metal chelating agent e.g., Na-EDTA
  • any chemical agent that is an alkali metal carbonate or a metaborate salt of alkali metal to reduce the likelihood of divalent cation carbonate precipitation.
  • Table 1 below lists some exemplary thermally activated chemical species (which undergo thermal decomposition), the temperature at which such thermally activated chemical species decompose, and the product(s) that result from the thermal decomposition. At least one of the decomposition products of each thermally activated chemical species listed in Table 1 is a gas. The decomposition temperatures provided in Table 1 are the temperatures at which dry solid samples of the exemplary thermally activated chemical species thermally decompose.
  • the decomposition products resulting from the thermal decomposition of the thermally activated chemical species listed in Table 1 in aqueous solution are the same as the decomposition products listed in Table 1, the temperatures at which the thermally activated chemical species listed in Table 1 in aqueous solutions decompose may be different than those shown in Table 1, but can be experimentally determined.
  • the selected chemical agent(s) is/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.
  • 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).
  • the concentration of each chemical agent in the aqueous solution can be varied depending on a variety of factors, but is preferably at least about 0.01 wt % and less than or equal to the solubility limit of the chemical agent in the brine under ambient reservoir conditions (i.e., at the ambient temperature and pressure of reservoir 105).
  • the parameters for loading or injecting the reservoir 105 with the aqueous solution are determined.
  • 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 of the aqueous solution is preferably greater than the freezing point of the aqueous solution and less than 40° C, and more preferably greater than the freezing point of the aqueous solution and less than or equal to the ambient temperature of reservoir 105.
  • the ambient temperature at the surface 5 may be greater than the ambient temperature of reservoir 105, and thus, the aqueous solution stored the surface 5 may have a temperature greater than the ambient temperature of reservoir 105 (i.e., the injection temperature of the aqueous solution stored at the surface 5 may be greater than the ambient temperature of reservoir 105).
  • the injection temperature of the aqueous solution is preferably greater than the freezing point of the aqueous solution and less than 40° C.
  • reservoir 105 is loaded or injected with the aqueous solution 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.
  • 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.
  • 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).
  • 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.
  • 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 of the aqueous solution offers the potential to enhance distribution of the aqueous solution in reservoir 105 and facilitate 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.
  • 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 injected aqueous solution) into production well 30.
  • Fluids e.g., connate water and/or the injected aqueous solution
  • 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.
  • the aqueous solution is injected into reservoir 105 until the total pore volume in reservoir 105 (or portion of reservoir 105 to be loaded) available for water is filled with the aqueous solution.
  • the volume of aqueous solution injected into reservoir 105 in block 204 is preferably at least equal to the pore volume of connate water in reservoir 105 (or portion of reservoir 105 to be loaded).
  • the pore volume of connate water in a reservoir (or portion of a reservoir to be loaded) can be calculated using techniques known in the art.
  • the duration of injection in block 204 will depend on the volume of reservoir 105 to be pretreated (i.e., the entire reservoir 105 vs. a portion of reservoir 105), the permeability to water, the water saturation, and the maximum injection pressure.
  • injection of the aqueous solution 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 aqueous solution outside of the portion of reservoir 105 into which they were injected in block 204.
  • reservoir 105 and formation 101 are shown following injection of the aqueous solution according to block 204.
  • the aqueous solution is represented with reference numeral 110.
  • the injected aqueous solution 110 forms a loaded zone 11 1 extending radially outward and longitudinally along the portion of horizontal section(s) 22, 32 from which the solution 1 10 was injected into reservoir 105.
  • Loaded zone 111 defines the volume of reservoir 105 that has had its connate water replaced (or at least partially replaced) with the aqueous solution 110.
  • the selected chemical agents are (a) surfactants unable to emulsify immobile hydrocarbons in reservoir 105 at the ambient reservoir temperature; and/or (b) thermally activated chemical species that are (1) non-decomposable or substantially non- decomposable and (2) non-reactive or substantially non-reactive in reservoir 105 at the ambient reservoir temperature.
  • the selected chemical agents are injected into reservoir 105 at the ambient reservoir temperature in block 204.
  • the chemical agent(s) in the aqueous solution do not substantially react with or alter the viscous hydrocarbons in reservoir 105 upon injection.
  • preconditioning chemical compounds that are designed to or inherently react with or alter the hydrocarbons in a reservoir at ambient reservoir temperatures, which may generally be described as “preconditioning” the reservoir.
  • chemical compounds that react with or alter the hydrocarbons in a reservoir at the ambient reservoir temperature are sometimes referred to as “preconditioning” agents.
  • start-up of the SAGD well pair 20, 30 is commenced in block 205.
  • 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.
  • commencing start-up in block 205 is preferably performed immediately after injection in block 204.
  • commencing start-up in block 205 preferably begins within 50 days after loading reservoir 105 in block 204, more preferably within 10 days after loading reservoir 105 in block 204, and even more preferably as soon as loading reservoir 105 in block 204 ceases.
  • 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 (a) reduce the viscosity of the viscous hydrocarbons in reservoir 105 and mobilize at least a portion of the hydrocarbons in reservoir 105; and (b) thermally "activate” or “trigger” the chemical agent(s) in the aqueous solution. More specifically, for each chemical agent that is a surfactant, the elevated temperature sufficiently mobilizes the hydrocarbons in reservoir 105 to allow the surfactant in the aqueous solution to emulsify the hydrocarbons in reservoir 105; and for each chemical agent that is a thermally activated chemical species, the elevated temperature is sufficient to decompose and/or react the thermally activated chemical specie(s) in the aqueous solution.
  • the thermal energy from steam chamber 120 in combination with the thermal activation of the chemical agent(s) (e.g., the surfactant(s) and/or thermally activated chemical species) in the aqueous solution enables the chemical agent(s) to enhance the mobility of the hydrocarbons above and beyond what the thermal energy can do alone.
  • This offers the potential to accelerate start-up of the SAGD well pair 20, 30 (i.e., accelerates the establishment of pressure and fluid communication between wells 20, 30), as well as accelerate production of hydrocarbons in reservoir 105 according to block 206 described in more detail below.
  • the front of the thermal energy generated from steam chamber 120 moves through the reservoir 105 ahead of the steam chamber 120 itself, and thus, the reduction in the viscosity of the hydrocarbons in the reservoir 105, the mobilization of the hydrocarbons in the reservoir 105, and the thermal activation of the chemical agent(s) in the aqueous solution begins prior to the arrival of steam chamber 120 (e.g., in response to the thermal front that moves ahead of the edge of steam chamber 120) and after the arrival of the steam chamber 120.
  • the injection of steam in block 205 and associated thermal energy reduces the viscosity of the viscous hydrocarbons in reservoir 105.
  • the reduced viscosity of the hydrocarbons enhances their mobility, which in turn allows the alkali metal carbonate in the aqueous solution to access and react with the organic acids in the hydrocarbons to form surfactants in-situ.
  • surfactants formed in-situ enhance the release of hydrocarbons from the formation surface and emulsify the hydrocarbons into oil-in-water emulsions, thereby offering the potential to further enhance hydrocarbon mobility.
  • alkali metal carbonates can be used alone in the aqueous solution to form surfactants in-situ, they can also be used in combination with surfactants in the aqueous solution. Since alkali metal carbonates react to form surfactants in-situ upon injection of steam, they can be used to reduce the amount of surfactants in the aqueous solution and/or to supplement the surfactants in the aqueous solution. [0050] Referring again to Figure 3, in block 206, steam continues to be injected through injection well 20 as the mobilized hydrocarbons in reservoir 105 drain under gravity through reservoir 105 and formation 101 into horizontal section 32.
  • Artificial lift e.g., pumping via an electric submersible pump, progressive cavity pump, or rod pump, gas lift, etc.
  • production well 30 Injection of steam while hydrocarbons are being collected in production well 30 and produced to the surface 5 is referred to as "production" or the “production” phase.
  • an aqueous solution comprising one or more surfactants can optionally be injected with steam during the start-up phase in block 205 and/or injected with steam during the production phase in block 206.
  • the injection of surfactant(s) in aqueous solution with steam according to block 207 is shown in connection with the loading of reservoir 105 in block 204 (prior to the injection of steam in block 205), the injection of one or more surfactant(s) in aqueous solution with steam according to block 207 can be performed independent of blocks 201-204 (i.e., without loading the reservoir in block 204).
  • steam delivered to and injected into a reservoir is often characterized by its steam or vapor "quality,” which refers to the mass fraction of the steam that is vapor (as opposed to liquid).
  • quality refers to the mass fraction of the steam that is vapor (as opposed to liquid).
  • steam having a steam quality of 100% is completely vapor phase
  • steam having a steam quality of 0% is completely liquid
  • steam having a steam quality of 75% is 75% (by mass) vapor phase and 25% (by mass) liquid phase.
  • steam having a steam quality less than 100% comprises a vapor phase and a liquid phase.
  • the injected steam when an aqueous solution comprising one or more surfactants is injected with steam according to block 207, the injected steam preferably has a steam quality less than 100%, and thus, comprises both a vapor phase and a liquid phase.
  • the liquid phase in the injected steam provides the medium to carry and deliver the aqueous solution (including the surfactant) to reservoir 105.
  • references herein to the injection of an aqueous solution comprising one or more surfactants "with steam” refer to the injection or delivery of the aqueous solution (including the surfactant(s)) in the liquid phase of steam that has a quality less than 100%.
  • each surfactant selected for use in block 207 is preferably water soluble, and further, is preferably an emulsifier of mobile hydrocarbons in reservoir 105.
  • bitumen e.g., bitumen of the Canadian oil sands of Alberta
  • bitumen is immobile at ambient reservoir temperatures, and must be heated to a temperature of at least 40° to 60° C to be converted into mobile hydrocarbons within reservoir 105.
  • any surfactant(s) injected with steam in block 205 and/or block 206 is preferably capable of emulsifying bitumen once the bitumen is warmed to at least 40° to 60° C and mobilized.
  • Suitable surfactants that can be used in block 207 for injection with steam include, without limitation, the surfactants previously described that are suitable for selection as chemical agent(s) in block 201 - 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., ENOROETTM O Series from Shell Chemicals); branched alpha olefin sulfonates (e.g.
  • 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
  • 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); polyoxyethylene alkyl phenyl ether (e.g. Triton X-100TM 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).
  • alkylaryl sulfonate e.g. Biosoft D-40 from Stepan Chemical Company of Northfield, Illinois
  • polyoxyethylene alkyl phenyl ether e.g. Triton X-100TM available from The DOW Chemical Company of Midland, Michigan
  • sodium/potassium oleate preferably with a chelating agent such as
  • Each selected surfactant for use in block 207 can be used alone, with one or more other chemical agents (e.g., surfactant in combination with a thermally activated chemical species, multiple surfactants used together, etc.), with one or more other chemical additives (e.g., surfactant in combination with another chemical, etc.), or combinations thereof.
  • one or more other chemical agents e.g., surfactant in combination with a thermally activated chemical species, multiple surfactants used together, etc.
  • chemical additives e.g., surfactant in combination with another chemical, etc.
  • the selected surfactant(s) is/are mixed with a brine (i.e., solution of salt in water) to form the aqueous solution.
  • the brine preferably has a salt concentration and composition analogous to (a) the liquid phase of the steam injected (i.e., the steam injected in block 205 and/or block 206) or (b) the reservoir 105.
  • the concentration of each surfactant in the aqueous solution for use in block 207 is preferably determined taking into account its subsequent dilution by the liquid water in the injected steam and condensed liquid water from the injected steam, and thus, will typically be greater than the concentration of the same surfactant in the aqueous solution loaded into the reservoir in block 204.
  • the aqueous solution comprising one or more surfactants is injected with steam during startup (block 205) and/or production (block 206), and thus, the injection parameters are those selected for the steam itself - the steam pressure and temperature, the steam flow rate, etc.
  • an aqueous solution comprising one or more thermally activated chemical species can optionally be injected with steam during the start-up phase in block 205 and/or injected with steam during the production phase in block 206.
  • the injection of a thermally activated chemical species in aqueous solution with steam according to block 208 is shown in connection with the loading of reservoir 105 in block 204 (prior to injecting steam in block 205), the injection of a thermally activated chemical species in aqueous solution with steam according to block 208 can be performed independent of blocks 201-204 (i.e., without loading the reservoir in block 204.
  • the injected steam when one or more thermally activated chemical species in aqueous solution is injected with steam according to block 208 (during start-up phase and/or production phase), the injected steam preferably has a steam quality less than 100%, and thus, comprises both a vapor phase and a liquid phase.
  • the liquid phase in the injected steam provides the medium to carry and deliver the aqueous solution (including the thermally activated chemical species) to reservoir 105.
  • references herein to the injection of an aqueous solution comprising one or more thermally activated chemical species "with steam” refer to the injection or delivery of the aqueous solution (including the thermally activated chemical species) in the liquid phase of steam that has a quality less than 100%.
  • thermally activated chemical species and the formation of the aqueous solution for use in block 208 are generally performed in the same manner as previously described with regard to blocks 201, 202.
  • selection of the particular thermally activated chemical species for use in block 208 is based, at least in part, on its ability to enhance the mobility of the hydrocarbons in the particular formation of interest (e.g., reservoir 105 in formation 101) at an elevated temperature greater than the ambient reservoir temperature.
  • each thermally activated chemical species injected with steam according to block 208 is preferably is a water soluble chemical species that (1) is non-decomposable or substantially non-decomposable in reservoir 105 at ambient reservoir temperatures and (2) is non-reactive or substantially non-reactive in reservoir 105 at ambient reservoir temperatures, but decomposes and/or reacts at a temperature greater than the ambient reservoir temperature and less than the operating temperature of the thermal recovery process employed (e.g., SAGD operating temperature) 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; (e) a surfactant or surfactant-like compound; or (f) combinations thereof.
  • SAGD operating temperature e.g., SAGD operating temperature
  • the phrases “substantially non-decomposable” and “substantially non-reactive” refer to a chemical species that has a conversion rate (via decomposition and/or reaction) of less than 1 mol % over a 24 hour period in an aqueous solution at ambient reservoir temperatures in the presence of hydrocarbons in a reservoir at the ambient reservoir temperature. It should be appreciated that the reaction of the thermally activated chemical species at the elevated temperature (i.e., temperature greater than the ambient reservoir temperature and less than the operating temperature of the thermal recovery process) may be directly or indirectly thermally driven.
  • the thermal energy from the elevated temperature may sufficiently decrease the viscosity of the viscous hydrocarbons to mobilize the hydrocarbons, which enables the thermally activated chemical species to access and react with the hydrocarbons.
  • the thermal energy does not directly trigger the thermally activated chemical species to react, but rather, sufficiently mobilizes the hydrocarbons to enable the thermally activated chemical species to sufficiently comingle and react with the hydrocarbons.
  • the decomposition or reaction of the thermally activated chemical species may form carbon-dioxide gas (CO 2 ) or other compound(s) miscible with hydrocarbons, which increase the mobility of the hydrocarbons.
  • each thermally activated chemical species selected for use in block 208 decomposes and/or reacts at a temperature preferably between 40° and 200° C, and more preferably between 60° and 120° C.
  • the typical operating temperature of a SAGD thermal recovery process is 180° to 220° C.
  • each thermally activated chemical species injected with steam in block 205 and/or block 206 for viscous hydrocarbons in the Canadian oil sands to be produced using SAGD is a chemical species that is non-decomposable (or substantially non-decomposable) and non-reactive (or substantially non-reactive) in the Canadian oil sands between 8° and 12° C (i.e., at ambient reservoir temperatures), but decompose and/or reacts at a temperature above 8° and 12° C (i.e., the ambient reservoir temperature) and below 180° to 220° (i.e., the operating temperature of the SAGD thermal recovery process).
  • thermally activated chemical species examples include, without limitation, urea; ammonium salts (e.g., ammonium carbonate, ammonium bicarbonate, ammonium acetate, ammonium nitrate, ammonium chloride, etc.); thiourea dioxide; bicarbonates (e.g.
  • sodium bicarbonate, etc. sodium bicarbonate, etc.
  • nitrates e.g., sodium carbonate, potassium carbonate, cesium carbonate, lithium carbonate, etc.
  • alkali metal carbonates e.g., sodium carbonate, potassium carbonate, cesium carbonate, lithium carbonate, etc.
  • metaborate salts of alkali metals e.g., sodium metaborate, potassium metaborate, etc.
  • a metal chelating agent e.g., Na-EDTA
  • any chemical agent that is an alkali metal carbonate or a metaborate salt of an alkali metal to reduce the likelihood of divalent cation carbonate precipitation.
  • Each selected thermally activated chemical species for use in block 208 can be used alone, with one or more other chemical agents (e.g., thermally activated chemical species in combination with a surfactant, multiple thermally activated chemical species used together, etc.), with one or more other chemical additives (e.g., thermally activated chemical species in combination with another chemical, etc.), or combinations thereof.
  • one or more other chemical agents e.g., thermally activated chemical species in combination with a surfactant, multiple thermally activated chemical species used together, etc.
  • chemical additives e.g., thermally activated chemical species in combination with another chemical, etc.
  • each thermally activated chemical species injected in aqueous solution with steam according to block 208 decomposes and/or reacts at a temperature preferably between 40° and 200° C, and more preferably between 60° and 120° C.
  • the injected steam preferably comprises a vapor phase and liquid phase, with the thermally activated chemical species being carried and delivered in the liquid phase.
  • the temperature of the vapor phase of the injected steam and the liquid phase of the injected steam will be the substantially the same, typically greater than 180° C.
  • each thermally activated chemical species selected for injection with steam in block 208 is preferably non-volatile at the temperature of the injected steam and preferably has a relatively low rate of decomposition and reaction at the temperature of the injected steam such that it remains substantially unchanged within the injection conduit (within injection well 20 and/or production well 30) during its short residence time within the injection system.
  • each thermally activated chemical species selected for injection with steam in block 208 preferably has a conversion rate less than 10 mol % at the temperature of the injected steam and in the presence of the liquid water in the injected steam over a time period up to 10 minutes, and more preferably has a conversion rate less than 1 mol % at the temperature of the injected steam and in the presence of the liquid water in the injected steam over a time period up to 10 minutes.
  • non-volatile is used to describe chemical agents (e.g., thermally activated chemical species) that have a boiling point greater than 200° C at standard pressure (1.0 bar absolute).
  • the selected thermally activated chemical species are mixed with a brine (i.e., solution of salt in water) to form the aqueous solution.
  • the brine preferably has a salt concentration and composition analogous to (a) the liquid phase of the steam injected (i.e., the steam injected in block 205 and/or block 206) or (b) the reservoir 105.
  • the concentration of each thermally activated chemical species in the aqueous solution for use in block 208 is preferably determined taking into account its subsequent dilution by the liquid water in the injected steam and condensed liquid water from the injected steam, and thus, will typically be greater than the concentration of the same thermally activated chemical species in the aqueous solution loaded into the reservoir in block 204.
  • the aqueous solution comprising one or more thermally activated chemical species is injected with steam during startup (block 205) and/or production (block 206), and thus, the injection parameters are those selected for the steam itself - the steam pressure and temperature, the steam flow rate, etc.
  • the chemical agents in the aqueous solution loaded into the reservoir are generally inert - the surfactants are generally unable to emulsify the immobile hydrocarbons, and the thermally activated chemical species do not decompose or react.
  • sufficient thermal energy from steam injected during the start-up phase (and associated elevated temperature) initiates the mobilization of the hydrocarbons and activates/triggers the chemical agents, which further enhances the mobilization of the hydrocarbons.
  • the chemical agent in the aqueous solution is activated or triggered in situ by the increase in temperature.
  • embodiments described herein are employed to produce viscous hydrocarbons in a subterranean reservoir.
  • 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.
  • 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.
  • CCS cyclic steam stimulation
  • thermally activated chemical species in aqueous solution undergo a hydrolysis reaction upon heating (i.e., thermal activation) and produce gas(es) and/or liquid(s).
  • the production of gas(es) upon thermal activation of such thermally activated chemical species loaded into the formation increase the pressure within the formation and enhance the mobilization of hydrocarbons in the formation.
  • Urea is one exemplary thermally activated chemical species that undergoes hydrolysis in aqueous solution upon thermal activation to produce carbon dioxide gas and ammonia, which exist in equilibrium between the gas and liquid phases. Experiments were conducted to analyze the thermal activation of urea and the associated hydrolysis.
  • the oven temperature was then gradually increased to a specific, predetermined target temperature (50 C, 80 C, 100 C, and 150 C), and then kept at the target temperature for an extended period of time until little to no pressure increase within the reactor vessel was observed (i.e., approaching the equilibrium pressure).
  • a specific, predetermined target temperature 50 C, 80 C, 100 C, and 150 C
  • the reactor was allowed to cool to ambient temperature, and then the concentration of urea, dissolved carbon dioxide (CO 2 ) and ammonia (NH 3 ) in the water, and carbon dioxide (CO 2 ) in the gas phase were determined.
  • Figure 6 illustrates the wt % of urea reacted as a function of temperature (at 10° C, 50° C, 100° C, and 150° C) when samples of aqueous solutions, each comprising 10 wt % of urea were heated (to 50° C, 100° C, and 150° C) in the reactor vessel in the manner previously described.
  • the experimental results shown in Figure 6 indicated that the hydrolysis of urea in aqueous solution strongly depends on the temperature, and further, that the hydrolysis of urea in aqueous solution can be thermally triggered when the aqueous solution is heated up to above approximately 50 C.
  • Table 2 illustrates the measured equilibrium pressure within the reactor vessel and the wt % of urea reacted (via hydrolysis) when samples of aqueous solutions having different concentrations of urea (5 wt % urea, 10 wt % urea, 15 wt % urea, and 20 wt % urea) were heated to 150° C in the manner as previously described.
  • the experimental results shown in Table 2 indicated that the increase in pressure (the difference between the equilibrium/final pressure and the initial 10 psig pressure) due to reaction of urea (via hydrolysis) was strongly dependent on the urea concentration - the greater the urea concentration in the aqueous solution, the greater the increase in pressure.
  • the experimental results shown in Table 2 indicated that all or substantially all of the urea in the aqueous solution was reacted (via hydrolysis).
  • Table 3 illustrates the wt % of urea reacted (via hydrolysis), the volumes of gas(es) produced by the reaction of urea, and the time allowed for the reaction when samples of aqueous solutions having different concentrations of urea (5 wt %, 10 wt %, 15 wt %, and 20 wt %) were heated (to 50° C, 80° C, 100° C, and 150° C) in the manner previously described.
  • the experimental results shown in Table 3 indicated that urea is very stable in aqueous solution at ambient temperatures, and further, that the hydrolysis of urea in aqueous solution does not occur until the aqueous solution is heated to a certain temperature.
  • the sample of aqueous solution including urea at a concentration of 10 wt % was heated to 50 C for several days and no gas was produced.
  • the sample of aqueous solution including urea at a concentration of 10 wt % maintained at 10° C for 8 months exhibited no reactions of urea (i.e., no reduction in urea concentration was found).
  • Aqueous solutions comprising chemical agents as described herein offer the potential to enhance and accelerate the recovery of viscous hydrocarbons from subterranean formations during thermal recovery processes such as SAGD.
  • chemical agents as described herein e.g., surfactants and thermally activated chemical species
  • SAGD thermal recovery processes
  • a sample of -10.0 g of high grade oil sand core (containing bitumen was packed into a vial made of PTFE, and then -12.0 ml aqueous solutions comprising a chemical agent was injected into the oil sand core in the vial.
  • the vial containing the oil sand core and the aqueous solution was sealed in a reactor and heated to 200 C for 2 hrs.
  • the reactor and vial therein were allowed to cool down to ambient temperature, and then the vial was opened and the produced hydrocarbons (i.e., the hydrocarbons that separated from the oil sands core) were collected and quantified.
  • the cores tested were high grade oil sand cores acquired from wells drilled in the Canadian oil sands of Northern Alberta, Canada.
  • Aqueous solutions comprising surfactants as described herein offer the potential to emulsify mobilized hydrocarbons in subterranean formations to enhance and accelerate the recovery of such hydrocarbons during thermal recovery processes such as SAGD.
  • SAGD thermal recovery processes
  • ⁇ 1.0 g of bitumen recovered from SAGD operations in Northern Alberta was placed in a vial.
  • a 10.0 mL aqueous solution comprising a brine and a predetermined concentration of surfactant (e.g. 1000 ppmw) was added to the vial.
  • the brine had a pH and composition representative of water produced at the Northern Alberta SAGD operations.
  • the brine was an aqueous solution having a pH of 7.8 and including the salts shown in Table 5 below.
  • the vial was placed in an oven and heated to an elevated temperature (50° C or 80° C) for 30 minutes. After this time, the vial was removed from the oven and gently turned from end-to-end 10 times in an effort to avoid high shear. The vial was then placed back in the oven at the elevated temperature (50° C or 80° C) for 1 hour, then taken out and turned gently 10 times, and then placed back into the oven at the elevated temperature (50° C or 80° C) for another 1 hour. After the additional hour, the vial was removed from the oven and gently turned 10 times, and then placed back into the oven at the elevated temperature (50° C or 80° C) for another 24 hours.
  • an elevated temperature 50° C or 80° C
  • the vial was placed back into the oven at the elevated temperature (50° C or 80° C) for an additional 24 hours, taken out, and turned gently 10 times. An optical microscope was then used to image the emulsion formed in the vial. The volumetric percentage (vol %) of the hydrocarbons in the emulsion, which represented the hydrocarbons released from the initial sample of bitumen, were then calculated based on the image analyses.
  • Table 6 illustrates the aqueous solutions tested, the concentration of each surfactant in the corresponding aqueous solution (if any), the testing temperature, and the volumetric percentage of the hydrocarbons in the emulsion (if any).
  • Table 6 indicated that when the bitumen samples were at ambient temperature (25 C), it was not mobilized and no emulsion was formed with the surfactants. However, when the bitumen was heated to 50 C (or higher) and became mobile, some of the surfactants tested were able to emulsify the bitumen into bitumen-in-water emulsion. The results also showed that when select surfactants were combined with an alkali metal carbonate (e.g.
  • bitumen-in-water emulsion additional bitumen was emulsified into bitumen-in-water emulsion, and further, an emulsion was created by some surfactants (e.g. Bio-Terge PAS 7S) which were not able to emulsify the bitumen by themselves.
  • some surfactants e.g. Bio-Terge PAS 7S
  • metaborate salts of alkali metals alone e.g. sodium metaborate

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Abstract

La présente invention concerne un procédé destiné à mobiliser des hydrocarbures visqueux dans un réservoir consistant à (a) injecter une solution aqueuse dans le réservoir, ce dernier étant à une température ambiante de réservoir. La solution aqueuse comprend de l'eau et un agent chimique hydrosoluble qui est sensiblement non-décomposable et sensiblement non-réactif dans le réservoir à la température ambiante du réservoir. De plus, le procédé consiste à (b) ajouter de l'énergie thermique au réservoir à tout moment après (a) pour augmenter la température d'au moins une partie du réservoir à une température élevée supérieure à la température ambiante du réservoir. En outre, le procédé consiste, en réponse à la température élevée dans (b), à (c) mobiliser au moins une partie des hydrocarbures dans le réservoir en réduisant la viscosité des hydrocarbures et en permettant à l'agent chimique d'améliorer la mobilisation des hydrocarbures.
PCT/US2014/026299 2013-03-15 2014-03-13 Systèmes et procédés pour accélérer la production d'hydrocarbures visqueux dans un réservoir souterrain à l'aide d'agents chimiques activés thermiquement Ceased WO2014151712A2 (fr)

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