WO2016007485A1 - Systèmes et procédés d'accélération de la production d'hydrocarbures visqueux dans un réservoir souterrain à l'aide d'agents chimiques volatils - Google Patents

Systèmes et procédés d'accélération de la production d'hydrocarbures visqueux dans un réservoir souterrain à l'aide d'agents chimiques volatils Download PDF

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Publication number
WO2016007485A1
WO2016007485A1 PCT/US2015/039342 US2015039342W WO2016007485A1 WO 2016007485 A1 WO2016007485 A1 WO 2016007485A1 US 2015039342 W US2015039342 W US 2015039342W WO 2016007485 A1 WO2016007485 A1 WO 2016007485A1
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Prior art keywords
reservoir
steam
chemical agent
hydrocarbons
well
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PCT/US2015/039342
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English (en)
Inventor
Allan Peats
Andrew C. REES
Spencer Edwin Taylor
Huang Zeng
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Allan Peats
Rees Andrew C
Spencer Edwin Taylor
Huang Zeng
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Application filed by Allan Peats, Rees Andrew C, Spencer Edwin Taylor, Huang Zeng filed Critical Allan Peats
Publication of WO2016007485A1 publication Critical patent/WO2016007485A1/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
    • C09K8/592—Compositions used in combination with generated heat, e.g. by steam injection
    • 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

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 volatile chemical agents while heating the formation (e.g., during steam injection) 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 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.
  • a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) selecting one or more chemical agent(s) for injection into the reservoir.
  • Each chemical agent is a volatile chemical having a normal boiling point below 200° C.
  • the method comprises (b) co-injecting the one or more chemical agent(s) and steam into the reservoir.
  • the steam has a temperature greater than the normal boiling point of each chemical agent.
  • a method for mobilizing viscous hydrocarbons in a reservoir in a subterranean formation comprises (a) forming a SAGD well pair extending through the formation, wherein 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) selecting one or more chemical agent(s) for injection into the reservoir.
  • the one or more chemical agent(s) comprises an acetylenic alcohol, an ethoxylated acetylenic alcohol, or tetrahydrofuran.
  • the method comprises (c) co-injecting the one or more chemical agent(s) and steam into the reservoir.
  • the steam has a temperature between 180° C and 220° C. Still further, the method comprises (d) increasing the temperature of the reservoir during (c) to a SAGD operating temperature. Moreover, the method comprises (e) decreasing the viscosity of the hydrocarbons in the reservoir during (d). The method also comprises (f) mobilizing at least some of the hydrocarbons in the reservoir.
  • 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; and [0015]
  • 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 steam chamber including injected steam, condensed hot water, and one or more chemical agent(s) 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
  • 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 simultaneously injected with steam including one or more chemical agents.
  • the chemical agents facilitate 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 (e.g., 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.
  • each chemical agent selected in block 201 is a volatile chemical having a relatively high vapor pressure and a normal boiling point (i.e., boiling point at atmospheric pressure) less than the operating temperature of the thermal recovery process.
  • system 10 is configured to employ SAGD thermal recovery techniques, and thus, each chemical agent selected in block 201 is a volatile chemical having a normal boiling point less than the operating temperature of a SAGD thermal recovery process (i.e., lower than the temperature of the steam injected in blocks 203 and 204 described in more detail below).
  • the typical operating temperature of a SAGD thermal recovery process is 180° to 220° C.
  • each chemical agent selected in block 201 is a volatile chemical preferably having a normal boiling point less than 220° C, and more preferably less than 200° C.
  • One exemplary group of volatile chemical agents suitable for selection in block 201 includes acetylenic alcohols and their ethoxylated products (i.e., ethoxylated acetylenic alcohols).
  • acetylenic alcohols include an acetylene group and an alcohol group such as:
  • R 1 is hydrogen (H), or a linear, branched, or cyclic alkane group
  • R 2 is a linear, branched, or cyclic alkane group.
  • acetylenic alcohols suitable for selection as a chemical agent in block 201 include, without limitation, the following: methyl butynol (e.g., 2- methyl-3-butyn-2-ol), methyl pentynol (e.g., 3 -methyl- 1-pentyn-ol), hexynol (e.g., 3, 5- dimethyl-l-hexyn-3-ol, Surfynol® 61 available from Air Products and Chemicals, Inc.), ethyl octynol (e.g., 4-ethyl-l-octyn-3-ol), ethynyl cyclohexanol (e.g., 1-ethylnyl-l-cyclohexanol
  • acetylenic alcohols and ethoxylated acetylenic alcohols are surface active, and offer the potential to reduce the surface tension of an aqueous solution and enable the aqueous solution to distribute and spread on a solid surface. Consequently, acetylenic alcohols and their ethoxylated products function as good "wetting" agents.
  • any acetylenic alcohol or ethoxylated acetylenic alcohol selected in block 201 can be used on its own or in connection with other chemical additives.
  • a solvent e.g., tetrahydrofuran
  • volatile alkaline e.g., ammonia or alcoholamine
  • THF tetrahydrofuran
  • THF can dissolve many non- polar and polar compounds, and the oxygen center of its ether structure can act as a Lewis base.
  • THF can dissolve asphaltene, which is the heaviest and most polar oil component. Consequently, THF is a particularly good solvent for heavy oil and bitumen.
  • THF selected in block 201 can be used on its own or in connection with other chemical additives.
  • a stabilizer is preferably used in connection with THF.
  • Other volatile chemical agents suitable for selection in block 201 include monoethanolamine (MEA) and ethanolamine.
  • MEA monoethanolamine
  • ethanolamine any combination of two or more chemical agents can be combined and used together with or without additional chemical additives.
  • Some combinations include, without limitation, THF and MEA, Surfynol® 61 and MEA, MEA and heptane, and MEA and Naphta.
  • the selected chemical agent(s) are co-injected with steam into the reservoir 105.
  • the parameters for co-injecting the selected chemical agent(s) with steam into the reservoir 105 are determined in block 202 prior to actually co-injecting the selected chemical agent(s) and steam into the reservoir 105.
  • the co-injection parameters can be determined by any suitable means known in the art such as by completing an "injectivity test.”
  • the co-injection parameters include, without limitation, the injection pressure, the injection temperature, the concentration of the selected chemical agent(s) in the steam, and the flow rate at which the selected chemical agent(s) and the steam will be co-injected into reservoir 105.
  • the injection pressure 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 the SAGD operating temperature, which is between 180° and 220°, and preferably greater than the boiling point of each of the selected chemical agent(s).
  • the concentration of the selected chemical agent(s) in the steam is preferably sufficient to enable enhanced production, yet economically feasible considering the cost of the chemical agent(s).
  • the chemical agent(s) selected in block 201 are co- injected with the steam (i.e., injected simultaneously with steam) during (a) the start-up phase in block 203 to accelerate fluid communication between wells 20, 30, and (b) the production phase in block 204 to accelerate and increase production.
  • the chemical agent(s) are co-injected in accordance with the injection parameters determined in block 202.
  • the steam and selected chemical agent(s) can be injected into the reservoir 105 during start-up and production continuously, intermittently, or pulsed by controllably varying the injection pressure within an acceptable range of pressures as determined in block 202. It should be appreciated that any one or more of these injection options can be performed alone or in combination with other injection options.
  • the selected chemical agent(s) can be mixed with water at the surface, and then the resulting aqueous solution heated to convert the water to steam. Since the steam has a temperature between 180° C and 220° C, which is greater than the normal boiling point of each of the selected chemical agent(s), the chemical agent(s) change from a liquid to vapor along with the water. Alternatively, the selected chemical agent(s) can be injected into the steam at the surface. Since the steam has a temperature between 180° C and 220° C, which is greater than the normal boiling point of each of the selected chemical agent(s), the chemical agent(s) change from a liquid to vapor once injected into the steam.
  • the vaporized chemical agent(s) flow with and be carried by the steam.
  • the selected chemical agent(s) and the steam can be delivered to the reservoir 105 via injection well 20 and/or production well 30, and injected from the horizontal sections 22, 32, respectively, into the reservoir 105.
  • the selected chemical agent(s) and the steam are delivered to the reservoir 105 via injection well 20, and injected from horizontal section 22 into the reservoir 105.
  • the 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 selected chemical agent(s) through reservoir 105 and the saturation of reservoir 105 with the selected chemical agent(s).
  • reservoir 105 and formation 101 are shown during co- injection of the selected chemical agent(s) and steam according to blocks 203 and 204.
  • the mixture of the selected chemical agent(s), steam, and associated hot water percolate through reservoir 105, thereby forming a steam chamber 120 that extends horizontally outward and vertically upward from horizontal sections 22, 32 of wells 20, 30.
  • Steam chamber 120 is generally shaped like an inverted triangular prism that extends along and upward from the full length of sections 22, 32.
  • 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 to an elevated temperature greater than the ambient temperature of reservoir 105.
  • the elevated temperature is sufficient to reduce the viscosity of the viscous hydrocarbons in reservoir 105, thereby enhancing the mobility of the viscous hydrocarbons.
  • the elevated temperature is below the boiling point of the selected chemical agent(s), and thus, the selected chemical agent(s) condense and percolate through the formation with the steam and associated hot water.
  • the selected chemical agent(s) include an acetylenic alcohol and/or ethoxylated acetylenic alcohol
  • the acetylenic alcohols and/or ethoxylated acetylenic alcohols enhance the water wettability of the sand, rock, and clay surfaces. This offers the potential to accelerate fluid communication between wells 20, 30 during the start-up phase, as well as accelerate and increase production during the production phase according to block 205 described below.
  • the selected chemical agent(s) include THF
  • the THF softens the viscous hydrocarbons by dissolving asphaltene. This offers the potential to accelerate fluid communication between wells 20, 30 during the start-up phase, as well as accelerate and increase production during the production phase according to block 205 described below.
  • the co-injection of the selected chemical agent(s) and steam through injection well 20 continues 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.
  • hydrocarbons collected in production well 30 to the surface 5 is typically employed to produce hydrocarbons collected in production well 30 to the surface 5.
  • 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
  • acetylenic alcohols and acetylenic ethoxylated products are suitable chemical agents for co-injection with steam in SAGD thermal recovery operations
  • acetylenic alcohols and their ethoxylated products can also be used to enhance production in other types of steam-based thermal recovery operations.
  • SAGD operations are generally unsuitable and/or not feasible for use with relatively thin reservoirs and reservoirs disposed below weak cap rock.
  • one or more selected acetylenic alcohols and/or acetylenic ethoxylated products can be co-injected with steam to improve production.
  • one or more selected acetylenic alcohols and/or acetylenic ethoxylated products can be co-injected with steam to improve production in non-SAGD operations such as cyclic steam stimulation (CSS) operations, steam flooding operations, etc.
  • non-SAGD operations such as cyclic steam stimulation (CSS) operations, steam flooding operations, etc.
  • CSS cyclic steam stimulation
  • THF is a suitable chemical agent for co-injection with steam in SAGD thermal recovery operations (e.g., method 200 described above).
  • THF can also be used to enhance production in other types of thermal and non-thermal recovery operations.
  • THF can be used to enhance cold production of viscous hydrocarbons.
  • THF can be injected at ambient reservoir temperatures (i.e., without steam) into a reservoir containing viscous hydrocarbons. Once injected, the THF softens the asphaltene and effectively reduces the viscosity of the viscous hydrocarbons. The reduced viscosity hydrocarbons can then be produced via primary production methods and the THF recovered, recycled and reused.
  • THF can be used as a pretreatment agent for subsequent recovery operations.
  • THF can be injected at the ambient reservoir temperature into a reservoir containing viscous hydrocarbons to dissolve the organic compounds coating the sand, clay, and carbonate surfaces. This makes the formation water- wet, which it particularly beneficial for subsequent water-flooding recovery operations.
  • THF can be used as an additive in water-flooding operations. In particular, THF can be added to water for use in water-flooding operations.
  • the resulting aqueous solution can be injected at the ambient reservoir temperature into a reservoir containing viscous hydrocarbons to reduce the viscosity of the viscous hydrocarbons, thereby enhancing the mobility of the viscous hydrocarbons.
  • THF can be used as a pretreatment agent and start-up enhancement agent in SAGD operations.
  • THF can be injected the ambient reservoir temperature into a reservoir containing viscous hydrocarbons to soften the asphaltene, reduce the viscosity of the viscous hydrocarbons, and dissolve the organic compounds coating the sand, clay, and carbonate surfaces to make them water- wet.
  • THF can be co-injected with steam in applications where SAGD operations are not suitable or feasible for SAGD (e.g., relatively thin reservoirs and reservoirs disposed below weak cap rock).
  • SAGD operations e.g., relatively thin reservoirs and reservoirs disposed below weak cap rock.
  • THF can be co-injected with steam to improve production in non-SAGD operations such as cyclic steam stimulation (CSS) operations, steam flooding operations, etc.
  • CCS cyclic steam stimulation
  • separation of the produced oil-water is often difficult.
  • the addition of THF in the recovery process as discussed in any of the examples above offers the potential to sufficiently reduce the viscosity of the viscous hydrocarbons to enable easier separation of the produced oil- water.

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Abstract

La présente invention concerne un procédé de mobilisation d'hydrocarbures visqueux dans un réservoir dans une formation souterraine, ledit procédé consistant (a) à sélectionner un ou plusieurs agents chimiques en vue d'une injection dans le réservoir. Chaque agent chimique consiste en un produit chimique volatil présentant un point d'ébullition normal inférieur à 200 °C. De plus, le procédé consiste (b) à co-injecter le ou les agents chimiques et de la vapeur d'eau dans le réservoir. La vapeur d'eau présente une température supérieure au point d'ébullition normal de chaque agent chimique.
PCT/US2015/039342 2014-07-09 2015-07-07 Systèmes et procédés d'accélération de la production d'hydrocarbures visqueux dans un réservoir souterrain à l'aide d'agents chimiques volatils WO2016007485A1 (fr)

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US62/022,357 2014-07-09

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Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3056452A (en) * 1959-11-16 1962-10-02 Pure Oil Co Surfactant-water flooding process
US5622921A (en) * 1993-01-21 1997-04-22 Nowsco Well Service, Inc. Anionic compositions for sludge prevention and control during acid stimulation of hydrocarbon wells
US5685371A (en) * 1995-06-15 1997-11-11 Texaco Inc. Hydrocarbon-assisted thermal recovery method
US20070111903A1 (en) * 2005-11-17 2007-05-17 General Electric Company Separatory and emulsion breaking processes
WO2012128608A1 (fr) * 2011-03-18 2012-09-27 Petroliam Nasional Berhad (Petronas) Préparation thermo-chimique améliorée
US20120312532A1 (en) * 2011-06-13 2012-12-13 Kimberly Jantunen Cross Additives for improving hydrocarbon recovery

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3056452A (en) * 1959-11-16 1962-10-02 Pure Oil Co Surfactant-water flooding process
US5622921A (en) * 1993-01-21 1997-04-22 Nowsco Well Service, Inc. Anionic compositions for sludge prevention and control during acid stimulation of hydrocarbon wells
US5685371A (en) * 1995-06-15 1997-11-11 Texaco Inc. Hydrocarbon-assisted thermal recovery method
US20070111903A1 (en) * 2005-11-17 2007-05-17 General Electric Company Separatory and emulsion breaking processes
WO2012128608A1 (fr) * 2011-03-18 2012-09-27 Petroliam Nasional Berhad (Petronas) Préparation thermo-chimique améliorée
US20120312532A1 (en) * 2011-06-13 2012-12-13 Kimberly Jantunen Cross Additives for improving hydrocarbon recovery

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