WO2015157156A1 - Systèmes et procédés pour accélérer la production d'hydrocarbures visqueux dans un réservoir souterrain avec des émulsions comprenant des agents chimiques - Google Patents

Systèmes et procédés pour accélérer la production d'hydrocarbures visqueux dans un réservoir souterrain avec des émulsions comprenant des agents chimiques Download PDF

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WO2015157156A1
WO2015157156A1 PCT/US2015/024476 US2015024476W WO2015157156A1 WO 2015157156 A1 WO2015157156 A1 WO 2015157156A1 US 2015024476 W US2015024476 W US 2015024476W WO 2015157156 A1 WO2015157156 A1 WO 2015157156A1
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reservoir
water
oil
emulsion
phase
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PCT/US2015/024476
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English (en)
Inventor
Xuebing FU
Allan Peats
Andrew C. REES
Christopher C. West
Huang Zeng
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Fu Xuebing
Allan Peats
Rees Andrew C
West Christopher C
Huang Zeng
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Application filed by Fu Xuebing, Allan Peats, Rees Andrew C, West Christopher C, Huang Zeng filed Critical Fu Xuebing
Publication of WO2015157156A1 publication Critical patent/WO2015157156A1/fr

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    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • C09K8/584—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific surfactants
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • C09K8/524—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning organic depositions, e.g. paraffins or asphaltenes
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • C09K8/592—Compositions used in combination with generated heat, e.g. by steam injection

Definitions

  • This disclosure relates generally to thermal recovery techniques for producing viscous hydrocarbons such as heavy oil and bitumen. More particularly, this disclosure relates to the injection of emulsions comprising chemical agents before heating the formation (e.g., before injecting steam) to accelerate the 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.
  • 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.
  • a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) forming a SAGD well pair extending through the formation.
  • the SAGD well pair includes an injection well and a production well. Each well has a vertical section extending from the surface of the formation and a horizontal section traversing the reservoir.
  • the method comprises (b) forming an oil-in-water emulsion comprising an aqueous solution and a water insoluble solvent or diluent.
  • the aqueous solution includes a non-ionic surfactant that is water-soluble and substantially non-reactive in the reservoir at the ambient temperature of the reservoir.
  • the method comprises (c) injecting the oil-in-water emulsion into the reservoir with the reservoir at the ambient temperature. Still further, the method comprises (d) injecting steam into the reservoir after (c) to increase the temperature of the reservoir to a SAGD operating temperature.
  • a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) forming an aqueous solution with a water-soluble chemical agent that is substantially non-reactive in the reservoir at the ambient temperature.
  • the method comprises (b) making a water-in-oil emulsion with the aqueous solution and a water insoluble solvent or diluent.
  • the method comprises (c) injecting the water-in-oil emulsion into the reservoir with the reservoir at the ambient temperature.
  • the method comprises (d) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (c).
  • a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) forming a SAGD well pair extending through the formation.
  • the SAGD well pair includes an injection well and a production well. Each well has a vertical section extending from the surface of the formation and a horizontal section traversing the reservoir.
  • the method comprises (b) forming a water-in-oil emulsion comprising an aqueous solution mixed in an oil phase.
  • the aqueous solution includes a water soluble chemical agent and the oil phase comprises a water insoluble diluent or solvent.
  • a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) making a micro-emulsion comprising a solvent, a brine, and a surfactant.
  • the method comprises (b) injecting the micro- emulsion into the reservoir with the reservoir at the ambient temperature.
  • the method comprises (c) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (b).
  • 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 the emulsion 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.
  • 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
  • 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 an emulsion including 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 agents facilitates an accelerated mobilization of the viscous hydrocarbons, thereby decreasing the time to achieve fluid communication between SAGD wells 20, 30, increasing start-up quality through improved conformance, and accelerating production from well 30.
  • 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.
  • the ability of a chemical agent to enhance the mobility of hydrocarbons depends on a variety of factors including, without limitation, the type of formation, its oil saturation, water saturation, the native permeability to water, physical and chemical properties of the oil, etc. Core and/or oil samples from the formation of interest can be tested with various chemical agents to facilitate the selection in block 201. The cost and availability of various chemical agent(s) may also impact the selection in block 201.
  • the surfactant i.e., the emulsifier
  • the water defines the continuous phase of the emulsion and the oil soluble diluent(s) or organic solvent(s) (i.e., the chemical agent(s)) define the dispersed phase of the emulsion.
  • oil soluble diluents and organic solvents that can be used as chemical agents in the oil-in-water emulsions include, without limitation, gas condensate, light crude oil, naphtha, kerosene, toluene, xylene, and the like.
  • the water is preferably a brine having a salt concentration and composition analogous to that of reservoir 105 to reduce the potential for the aqueous solution to negatively alter reservoir 105.
  • 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.
  • Each stabilizing surfactant(s) in the oil-in-water emulsion is a non-ionic surfactant that is water soluble or substantially water soluble at ambient reservoir temperatures, but has a reduced solubility at a temperature above the ambient reservoir temperature, referred to herein as the "phase inversion temperature.”
  • the phase inversion temperature a temperature above the ambient reservoir temperature
  • many nonionic surfactants include a polyoxyethylene (POE) group.
  • these surfactants are soluble in water through hydrogen bonding with the POE chain, which enables the surfactant to be water-soluble.
  • the hydrogen bonds weaken, resulting in decreased solubility of the surfactants.
  • the surfactants become more soluble in the oil phase of the emulsion than the water phase such that the original oil-in-water emulsion transitions to a water- in-oil emulsion.
  • phase inversion temperature the oil phase of the emulsion begins to separate from the water phase resulting in the oil-in-water emulsion becoming a cloudy two-phase system. Accordingly, the phase inversion temperature may also be referred to as the "cloud point.”
  • Each surfactant(s) preferably has a phase inversion temperature between 37°C and 90°C.
  • Several non-ionic surfactants have a phase inversion temperatures within this preferred range, and thus, are generally preferred as compared to other types of surfactants.
  • water soluble non-ionic surfactants suitable for use as stabilizing surfactants in the oil-in-water emulsion include, without limitation, ethoxylated non-ionic surfactants, octylphenol ethoyxylates (e.g. TritonTM X series surfactants available from The DOW Chemical Company of Midland, Michigan), secondary alcohol ethoxylates (e.g.
  • TergitolTM 15-S series surfactants available from The DOW Chemical Company of Midland, Michigan branched secondary alcohol ethoxylates (e.g. TergitolTM TMN series surfactants available from The DOW Chemical Company of Midland, Michigan), nonylphenol ethoxylates (e.g. TergitolTM NP series surfactants available from The DOW Chemical Company of Midland, Michigan), polyoxy ethyl enesorbitan esters (e.g., TWEEN® 20 or TWEEN® 40 available from Croda Inc. of Edison, New Jersey), and the like.
  • branched secondary alcohol ethoxylates e.g. TergitolTM TMN series surfactants available from The DOW Chemical Company of Midland, Michigan
  • nonylphenol ethoxylates e.g. TergitolTM NP series surfactants available from The DOW Chemical Company of Midland, Michigan
  • polyoxy ethyl enesorbitan esters e.g., T
  • the oil-in-water emulsion preferably comprises 30.0 to 50.0 wt % water phase, 50.0 to 70.0 wt % oil phase, and less than or equal to 5.0 wt % surfactant(s).
  • the size of the droplets of oil in the oil-in-water emulsion are preferably less than 20.0 ⁇ , more preferably less than 10.0 ⁇ , and even more preferably between 1.0 and 10.0 ⁇ .
  • Other chemical additive(s) that offer the potential to reduce the viscosity of the viscous hydrocarbons may also be added to oil phase or water phase of the oil-in-water emulsion.
  • the emulsion formed in block 202 is an oil-in-water emulsion stabilized by one or more surfactant(s)
  • the emulsion has a relatively low viscosity, which offers the potential for easy injection into reservoir 105 according to block 204 described in more detail below.
  • Embodiments in which the emulsion formed in block 202 is an oil-in-water emulsion are generally preferred for use in reservoirs that exhibit good native water mobility as such an emulsion relies on the high mobility of the water continuous phase, relative to the viscous hydrocarbons, in the reservoir for dispersal in the reservoir 105 described in more detail below.
  • the emulsion formed in block 202 is a water-in-oil emulsion.
  • each chemical agent is a chemical additive dissolved or dispersed in the water phase of the emulsion, and one or more water insoluble diluent(s) and/or solvent(s) define the oil phase of the emulsion.
  • the oil phase is the continuous phase and the water phase containing the chemical agent(s) is the dispersed phase.
  • the water-in-oil emulsions preferably comprises 40.0 to 60.0 wt % oil phase, with the balance being the water phase.
  • the size of the droplets of the dispersed phase are preferably between 1.0 and 20.0 ⁇ .
  • the diluent(s) and/or solvent(s) defining the oil phase of the water-in-oil emulsion are miscible with the viscous hydrocarbons in the reservoir 105, and thus, offer the potential to mix with the viscous hydrocarbons and reduce the viscosity of the viscous hydrocarbons upon injection of the water-in-oil emulsion in block 204 described in more detail below.
  • suitable diluent(s) and solvent(s) for the oil phase include, without limitation, used engine oil, gas condensate, naphtha, biofuel, and the like.
  • the used engine oil preferably contains surface active agents (e.g., soot particles, oxidized oil, and residual detergent).
  • the water phase of the water-in-oil emulsion comprises a brine and one or more chemical agent(s).
  • the chemical agent(s) preferably make up 5.0 to 20.0 wt % of the water phase, with the balance being the brine.
  • 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.
  • Each chemical agent is preferably a water soluble chemical additive that enhances the performance of steam in displacing the viscous hydrocarbons in the reservoir 105.
  • suitable chemical agent(s) includes, without limitation, water soluble urea, ammonium carbonate, ammonium bicarbonate, (ammonium acetate plus sodium carbonate or sodium bicarbonate), and the like.
  • Embodiments in which the emulsion formed in block 202 is a water-in-oil emulsion are generally preferred for use in reservoirs that exhibit poor native water mobility.
  • the emulsion is a micro-emulsion.
  • micro- emulsions are thermodynamically stable, isotropic mixtures of oil, water, and surfactant.
  • the micro-emulsion comprises one or more solvent(s) defining the oil phase, a brine defining the water phase, and one or more surfactant(s).
  • the chemical agent(s) selected in block 201 are the solvent(s) and the surfactant(s).
  • 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.
  • Formation of a micro-emulsion typically requires an ultra-low interfacial tension between the water phase and the oil phase of the emulsion.
  • interfacial tension between the water phase and the oil phase can be varied by adjusting the relative volumetric ratios of the oil phase, the water phase, and the surfactant(s).
  • the solvent(s) defining the oil phase and the surfactant(s) in the micro-emulsion are the active components that facilitate mobilization of the viscous hydrocarbons, and thus, in embodiments where the emulsion is a micro-emulsion, the relative volumetric ratios of the solvent(s) and/or surfactant(s) are preferably relatively high.
  • the micro-emulsion comprises a mixture of xylene (solvent), Triton X-100TM (surfactant) available from The DOW Chemical Company of Midland, Michigan, and brine in a volume ratio capable of forming a micro- emulsion (e.g., 8: 1 : 1).
  • micro-emulsions can be oil-in-water emulsions, water-in-oil emulsions, or bicontinuous.
  • the size of the droplets of the dispersed phase are preferably less than 5.0 ⁇ , more preferably less than 1.0 ⁇ , and even more preferably less than 0.1 ⁇ .
  • micro-emulsions form upon mixing of the components and do not require the high shear conditions typically employed to form ordinary emulsions. Accordingly, embodiments of micro-emulsions described herein can be formed via mixing by slight agitation. Alternatively, embodiments of micro-emulsions described herein can be formed in-situ during via a chemical reaction and/or soaking.
  • Embodiments in which the emulsion formed in block 202 is a micro-emulsion are generally preferred for use in reservoirs that exhibit good native water mobility.
  • the parameters for loading or injecting the reservoir 105 with the emulsion 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 emulsion will be injected into reservoir 105.
  • the injection pressure of the emulsion 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).
  • reservoir 105 is loaded or injected with the emulsion according to the injection parameters determined in block 203. Since the emulsion 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 emulsion according to block 204 may be referred to herein as "cold" loading of reservoir 105.
  • the emulsion is an oil-in-water emulsion stabilized by one or more surfactant(s) as previously described
  • the emulsion is delivered easily into the reservoir at ambient reservoir temperature due to the relatively low viscosity of the water continuous phase.
  • the continuous water phase offers the potential for improved mobility and dispersion of the oil-in-water emulsion through reservoir 105.
  • the oil-in-water emulsion moves through reservoir 105, it carries the chemical agent(s) (i.e., the diluent(s) and/or solvent(s) defining the oil phase) with it.
  • the diluent(s) and/or solvent(s) defining the oil phase are miscible with the viscous hydrocarbons in the reservoir 105, and thus, mix with the viscous hydrocarbons in reservoir 105 upon injection in block 204, thereby reducing the viscosity of the viscous hydrocarbons.
  • the continuous oil phase offers the potential for improved mobility and dispersion of the water-in-oil emulsion through reservoir 105 and the viscous hydrocarbons therein. As the water-in-oil emulsion moves through reservoir 105, it carries the chemical agent(s) with it.
  • micro-emulsions can mix with water and oil. Consequently, in embodiments where the emulsion formed in block 202 is a micro-emulsion, the emulsion can mix with both the water and the viscous hydrocarbons in reservoir 105, thereby offering the potential for improved mobility and dispersion of the emulsion through reservoir 105 upon injection in block 204. As the micro-emulsion moves through reservoir 105, it carries the chemical agent(s) with it.
  • the micro-emulsion can mix with the viscous hydrocarbons in reservoir 105
  • the chemical agent(s) i.e., the solvent(s) and the surfactant(s)
  • the viscous hydrocarbons upon injection in block 204, thereby offering the potential to reduce the viscosity of the viscous hydrocarbons in reservoir 105.
  • the emulsion can be injected into reservoir 105 utilizing one well 20, 30, both wells 20, 30, or combinations thereof over time.
  • the emulsion 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 emulsion since the emulsion is injected into the reservoir 105 in block 204 before commissioning SAGD well pair 20, 30, the emulsion 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 emulsion 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 emulsion 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 emulsion 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.
  • 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 emulsion) into production well 30.
  • Fluids e.g., connate water and/or the emulsion
  • 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 emulsion through reservoir 105 and the saturation of reservoir 105 with the emulsion.
  • Injection of the emulsion in block 204 is performed until reservoir 105 (or portion of reservoir 105 to be loaded) is sufficiently charged.
  • reservoir 105 and formation 101 are shown following injection of the emulsion according to block 204.
  • the emulsion is represented with reference numeral 110.
  • the emulsion 110 forms a loaded zone 111 extending radially outward and longitudinally along the portion of horizontal section(s) 22, 32 from which the emulsion 110 was injected into reservoir 105.
  • 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.
  • 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.
  • 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 and associated thermal energy are sufficient to reduce the viscosity of the viscous hydrocarbons in reservoir 105.
  • emulsion 110 is generally stable upon injection at the reservoir ambient temperature in block 204, however, once the temperature of the reservoir exceeds the phase inversion temperature (i.e., the cloud point), destabilization of the oil-in- water emulsion results in the release of the diluent(s) and organic solvent(s) (i.e., the oil phase of the emulsion begins to separate from the water phase of the emulsion).
  • the released diluent(s) and organic solvent(s) mix with the viscous hydrocarbons to further reduce their viscosity and further enhancing their mobility.
  • the any released surfactant(s) can facilitate emulsification of the mobilized hydrocarbons in reservoir 105.
  • emulsion 110 is a water-in-oil emulsion as previously described
  • the diluent(s) and/or solvent(s) defining the oil phase mix with the viscous hydrocarbons to reduce the viscosity of the viscous hydrocarbons prior to injection of steam in block 205, as well as during injection of steam in block 205.
  • the hydrocarbons in reservoir 105 are mobilized, thereby allowing chemical agent(s) in the water phase of the water-in-oil emulsion to access and interact with the hydrocarbons (e.g., react with the hydrocarbons, emulsify the hydrocarbons, etc.) to further reduce viscosity and enhance mobilization.
  • select chemical agents described above are thermally activated by the steam to produce gaseous products (e.g., urea thermally decomposes in presence of water to form gaseous ammonia and carbon-dioxide), which further reduce the viscosity and enhance mobilization of the hydrocarbons in reservoir 105.
  • gaseous products e.g., urea thermally decomposes in presence of water to form gaseous ammonia and carbon-dioxide

Abstract

La présente invention concerne un procédé pour mobiliser des hydrocarbures visqueux dans un réservoir dans une formation souterraine, qui comprend (a) la formation d'une solution aqueuse avec un tensioactif non ionique. De plus, le procédé comprend (b) la fabrication d'une émulsion d'huile dans l'eau avec la solution aqueuse et un solvant ou diluant insoluble dans l'eau. De plus, le procédé comprend (c) l'injection de l'émulsion d'huile dans l'eau dans le réservoir avec le réservoir à température ambiante. En outre, le procédé comprend (d) l'ajout d'énergie thermique au réservoir pour augmenter la température du réservoir à une température de service après (c).
PCT/US2015/024476 2014-04-08 2015-04-06 Systèmes et procédés pour accélérer la production d'hydrocarbures visqueux dans un réservoir souterrain avec des émulsions comprenant des agents chimiques WO2015157156A1 (fr)

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US61/976,915 2014-04-08
US201462042632P 2014-08-27 2014-08-27
US62/042,632 2014-08-27

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CN108624313A (zh) * 2017-03-15 2018-10-09 中国石油化工股份有限公司 用于降低稠油粘度的组合物和稠油降粘剂及制备方法和稠油降粘方法和稠油油藏开采方法
US20190345800A1 (en) * 2015-09-02 2019-11-14 Chevron U.S.A. Inc. Enhanced oil recovery compositions and methods thereof
CN110452676A (zh) * 2018-05-08 2019-11-15 中国石油化工股份有限公司 用于降低稠油粘度的组合物和稠油降粘剂及其制备方法和应用及稠油降粘的方法

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