WO2014182628A2 - Systèmes et procédés pour une récupération améliorée des fluides hydrocarbonés - Google Patents

Systèmes et procédés pour une récupération améliorée des fluides hydrocarbonés Download PDF

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Publication number
WO2014182628A2
WO2014182628A2 PCT/US2014/036839 US2014036839W WO2014182628A2 WO 2014182628 A2 WO2014182628 A2 WO 2014182628A2 US 2014036839 W US2014036839 W US 2014036839W WO 2014182628 A2 WO2014182628 A2 WO 2014182628A2
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WIPO (PCT)
Prior art keywords
formation
wellbores
wellbore
directionally drilled
producing formation
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PCT/US2014/036839
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English (en)
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WO2014182628A4 (fr
WO2014182628A3 (fr
Inventor
Paul Grimes
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Paul Grimes
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Publication date
Priority claimed from US13/986,464 external-priority patent/US10087731B2/en
Application filed by Paul Grimes filed Critical Paul Grimes
Priority to CA2911950A priority Critical patent/CA2911950A1/fr
Publication of WO2014182628A2 publication Critical patent/WO2014182628A2/fr
Publication of WO2014182628A3 publication Critical patent/WO2014182628A3/fr
Publication of WO2014182628A4 publication Critical patent/WO2014182628A4/fr

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Classifications

    • 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
    • E21B43/2401—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection by means of electricity
    • 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
    • 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

Definitions

  • PCT Patent Cooperation Treaty
  • Embodiments disclosed herein generally relate to systems and methods that enhance the recovery of hydrocarbonaceous fluids. Specific embodiments relate to systems and methods to stimulate a producing formation by using a gas generated from an electrochemical reaction. Other embodiments relate to the use of AC electrolysis in a machined formation adjacent to and/or within a producing formation to generate a gas that permeates into hydrocarbonaceous fluids disposed in the producing formation.
  • Secondary recovery may include, for example, a pumping operation that draws previously unrecoverable fluids to the surface.
  • these processes vary greatly, and processes that enable successful recovery from one or more formations may not be economical and/or successful when used in conjunction with other formations.
  • the capabilities of secondary recovery methods are limited. For example, formations that contain hydrocarbonaceous fluids with a low specific gravity, and/or high viscosity, and possess little or no natural energy may be unaffected by secondary recovery. In the absence of formation pressure, even fluids of average viscosity and specific gravity are difficult to produce through secondary recovery methods, without the addition of external energy to the formation.
  • tertiary recovery processes consider energy-based techniques that increase the temperature (i.e., reduce viscosity) and/or the pressure of the producing formation, thereby increasing flow.
  • energy-based techniques that increase the temperature (i.e., reduce viscosity) and/or the pressure of the producing formation, thereby increasing flow.
  • "fire flooding” employs the technique of burning oil "in situ” or within the formation, thereby heating the formation and pressurizing the formation with resultant hot combustion gases.
  • Gas injection is another example of a tertiary process.
  • C0 2 gas may be solvent with hydrocarbonaceous fluids, which increases the actual volume of the fluids and also reduces specific gravity and viscosity.
  • the solvency of the injected gas provides increased formation pressure and less viscous hydrocarbonaceous fluids.
  • C0 2 injection into the formation also causes the hydrocarbonaceous fluids to "break out" of the formation matrix, and thereby further promotes increased production.
  • many tertiary processes, such as gas injection require extensive and/or cost-prohibitive surface equipment and operations, and may also cause damage to the producing formation that hinders or terminates future production ability.
  • Some economical tertiary processes include introducing an electric current into the producing formation to cause exothermal heating of the surrounding formation, which lowers the viscosity of hydrocarbonaceous fluids and stimulates flow.
  • electrodes are connected to an electrical power source and are positioned at spaced apart points within the producing formation, whereby single electrodes are usually disposed in a corresponding wellbore that penetrates into the producing formation.
  • high resistance of the formation causes power to dissipate, which results in a power loss that heats the producing formation and hydrocarbonaceous fluids.
  • this process is generally limited to the immediate area involved in the heating process, and is uneconomical and inefficient.
  • Embodiments disclosed herein may provide an electrochemical recovery process that uses horizontally or directionally drilled wellbores in a formation, whereby the wellbores may be filled, at least partially, with an electrolytic solution, such as salt water.
  • the solution may provide an electrical contact in the solution, such that current may be conducted between electrodes disposed in the wellbores.
  • the wellbores themselves may be configured as electrodes.
  • directional wellbores may be drilled through the formation, whereby the wellbores may become an effective, long, isolated electrode in itself.
  • current may be introduced into the formation, and once a critical current density is achieved in the solution, a zone of electrochemical activity may propagate through the formation water and/or solution contained in one or more of the wellbores.
  • Directional drilling may allow recovery processes of the present disclosure to optimally direct the zone of electrochemical activity that may revitalize the formation on a cost-effective, cost basis.
  • the process may enable coverage of a much larger area of the formation relative to previous recovery techniques.
  • These other recovery techniques are frequently limited by faults, fractures, low permeability, and other geological irregularities that hinder the spread of the EOR influence, but because embodiments disclosed herein may propagate the electrochemical reaction, there is no suffrage from these geological effects.
  • Electrodes may be provided into one or more wellbores.
  • the wellbores may include preexisting producing and/or abandoned wellbores, naturally occurring features, or additional wellbores that may be drilled, machined, or otherwise formed, and the wellbores may or may not be fluidly connected to one another. These configurations facilitate and/or improve performance of an enhanced recovery process described herein.
  • Embodiments include wellbores placed in fluid communication and/or electrochemical communication through the creation of a machined flow path(s) therebetween.
  • horizontal drilling or similar methods for forming flow paths may be used to interconnect two or more wellbores.
  • three wellbores, having electrodes therein, may each be provided in fluid communication with one another.
  • a solution such as brine or a similar generally conductive fluid is pumped or otherwise provided within the machined flow path, such that the electrodes extend at least partially therein.
  • a power source operatively connected to the electrodes is then actuated to produce an electrical field therebetween.
  • generation of the electrical field may include application of alternating current to the solution.
  • Other embodiments may include creating an artificial subterranean formation at least partially underneath a producing and/or abandoned formation containing hydrocarbonaceous fluids.
  • a fluid, such as brine, disposed in the artificial formation may be reacted to form a gas (i.e., hydrogen), which may permeate into the producing formation to increase the pressure therein and/or decrease viscosity of the hydrocarbonaceous fluids.
  • a gas i.e., hydrogen
  • Embodiments disclosed herein may be used to increase a formation pressure, or otherwise alter flow characteristics of fluids in the formation. This may include, for example, a tertiary recovery process that establishes an electrical current flow within a formation via one or more electrodes that extend into the formation. The current flow may generate a zone of electrochemical activity in the formation that causes an electrochemical reaction with solutions disposed in the formation, thereby generating volumes of free gases to increase the formation pressure.
  • inventions disclosed herein may be directed to a system for enhanced recovery of hydrocarbonaceous fluids.
  • the system may include a first wellbore with a first electrode, as well as a second wellbore with a second electrode, where the wellbores may be configured such that the second wellbore may be mechanically isolated from the first wellbore.
  • There may be a solution disposed within each of the first and the second wellbores, such that the first electrode and the second electrode may at least partially contact the solution.
  • There may be a power source operatively connected to the first electrode and the second electrode, and configured to produce an electrical field therebetween.
  • the electrical field may create or otherwise cause an electrochemical reaction within the solution to create a gas. As such, the electrical field may electrochemically connect together, at least partially, the first wellbore and the second wellbore.
  • Embodiments disclosed herein provide for a system for enhanced recovery of hydrocarbonaceous fluids that may include a first wellbore configured with a first electrode, and a second wellbore comprising a second electrode.
  • the second wellbore may be mechanically isolated from the first wellbore.
  • There may be a solution disposed within each of the first and the second wellbores, and the first electrode and the second electrode may at least partially contact the solution.
  • There may be a power source operatively connected to the first electrode and the second electrode, and configured to produce an electrical field therebetween.
  • the electrical field may cause an electrochemical reaction within the solution to create a gas, whereby the electrical field may electrochemically connect together, at least partially, the first wellbore and the second wellbore.
  • Further embodiments may include a third wellbore mechanically isolated from the first wellbore and the second wellbore, the third wellbore having a third electrode operatively connected to the power source, and at least partially in contact with solution disposed therein.
  • the method may include the step of creating a plurality of wellbores in a subterranean formation.
  • Each of the plurality of wellbores may include a directionally drilled portion with solution disposed therein, and an electrode operatively connected with a power source.
  • the method may also include the step of generating an electrical field within the subterranean formation, thereby causing an electrochemical reaction to produce a gas from the solution, such that the gas may mix with hydrocarbonaceous fluids present in the formation and increase pressure within at least one of the plurality of wellbores, the subterranean formation, and combinations thereof.
  • the step of generating the electrical field may include providing alternating current to the solution, whereby each of the plurality of wellbores may be electrochemically connected together.
  • the electrochemical activity further enhances flow characteristics of formation fluids by lowering the viscosity of the fluids.
  • the increased formation pressure acts to drive the hydrocarbonaceous fluids into a producing wellbore.
  • the process may also release fluids from the earth formation matrix that are within the zone of electrochemical activity.
  • Figures 1A and IB depict multiple views of a various embodiments of a system for enhanced recovery of hydrocarbonaceous fluids, in accordance with embodiments disclosed herein.
  • Figure 1C shows a cross-sectional view of a conduit usable in one of the systems of Figure 1A and IB, in accordance with embodiments disclosed herein.
  • Figures ID, IE, and IF depict multiple views of systems for enhanced recovery of formation fluids that have mechanically isolated wellbores, in accordance with embodiments disclosed herein.
  • Figure 2 depicts a side view of an embodiment of a system for enhanced recovery of a producing formation separate from a non-producing formation, in accordance with embodiments disclosed herein.
  • Figure 3 depicts a side view of an alternate embodiment of a system for enhanced recovery of hydrocarbonaceous fluids, in accordance with embodiments disclosed herein.
  • Figures 4A - 4H show multiple partial downward sectional views of various embodied arrangements of systems useable to enhance recovery of hydrocarbonaceous fluids, in accordance with embodiments disclosed herein.
  • Figures 5A and 5B depict flow charts illustrating embodiments of methods for enhanced recovery of hydrocarbonaceous fluids, in accordance with embodiments disclosed herein.
  • Figures 6A and 6B show various downward views of representative wellbore configurations directionally drilled in a subterranean formation, in accordance with embodiments disclosed herein.
  • Figure 6C shows an isometric view of the wellbore configuration of Figure 6A, in accordance with embodiments disclosed herein.
  • Figures 6D and 6E show illustrative views of an electrical field generated between one or more wellbores, in accordance with embodiments disclosed herein.
  • Figures 7A and 7B show various views of arrangements and configurations of systems useable to enhance recovery of hydrocarbonaceous fluids, in accordance with embodiments disclosed herein.
  • Figure 8 shows an illustrative lateral side sectional view of multiple wellbores in electrochemical connection, in accordance with embodiments disclosed herein.
  • Figures 9A - 9C show illustrative isometric sectional views of multiple wellbores in mechanical isolation, in accordance with embodiments disclosed herein.
  • directional terms such as “above,” “below,” “upper,” “lower,” etc., are used for convenience in referring to the accompanying drawings.
  • “above,” “upper,” “upward,” and similar terms refer to a direction toward the earth's surface from below the surface along a wellbore
  • “below,” “lower,” “downward,” and similar terms refer to a direction away from the surface along the wellbore (i.e., into the wellbore), but is meant for illustrative purposes only, and the terms are not meant to limit the disclosure.
  • FIG. 1A shows the system 100 may include features and components readily recognized by one of skill in the art, such as a surface production facility 102 that may produce hydrocarbonaceous fluids 130 from a producing formation 110 by way of a wellbore 108.
  • the producing formation 110 may be surrounded by various non-producing formations, such as overburden 114 bed rock 116, and/or other earthen material 118.
  • a producing formation may be a formation that produces appreciable amounts of hydrocarbonaceous fluids as a result of primary, secondary, and/or tertiary recovery processes.
  • An appreciable amount of produced fluid may be, for example, one or more barrels a day.
  • a non-producing formation may be a formation incapable of producing appreciable amounts of hydrocarbonaceous fluids from primary, secondary, and/or tertiary recovery means.
  • An artificial (e.g. , man-made, machined, drilled, etc.) formation may advantageously be formed, at least partially, in the producing formation, the non-producing formation, or combinations thereof.
  • a pressure differential is typically needed between the producing formation and the wellbore.
  • Energy for the pressure differential may be supplied naturally in the form of gas, either free or in solution, evolved under a reduction in pressure.
  • the natural energy forces within the producing formation are insufficient to overcome any retardant forces within the formation, external energy must be added.
  • an artificial formation 112 may be formed within (e.g. , in the vicinity of, as part of, etc.) the producing formation 110, and the artificial formation may include, for example, one or more wellbores drilled therein.
  • the artificial formation 112 may include a first wellbore 104 in fluid communication with a second wellbore 106 as a result of a conduit 128 formed therebetween.
  • Wellbores 104, 106 and conduit 128 may be formed with conventional drilling methods, such that the wellbores 104, 106 and conduit 128 may be pressurized (including use of wellheads 122, etc.), cased, cemented, perforated, etc., as would be understood to one of skill in the art.
  • the conduit 128 may be a substantially horizontally drilled wellbore. It should be understood that in certain embodiments, at least part of the artificial formation 112 may be left uncased, uncemented, or otherwise unmodified.
  • the conduit 128 may be drilled through stable strata of the producing formation 110, such that casing and/or cementing is not required.
  • the wellbores 104, 106 and/or the conduit 128 may be at least partially disposed within or through the producing formation 110, such that the wellbores 104, 106 and/or conduit 128 are independently or simultaneously usable for production of hydrocarbonaceous fluids 130.
  • the artificial formation 112 may be formed in the presence of pre-existing aqueous solutions, such as saltwater, brine, etc.
  • one or more pumps 120 may be configured to convey a surface solution from a source (not shown) to the artificial formation 112.
  • the source may include, for example, a storage tank at the surface or an underground reservoir in communication with the pump.
  • the artificial formation 112, including any of the formation 112 components, such as conduit 128, may be formed in any portion of the producing formation 110.
  • Figure 1A illustrates the conduit 128 near the bottom of the producing formation 110
  • the conduit 128 may be formed through a middle region, or through an upper region (near the overburden 114 or the surface), such that the location of where the conduit 128 is formed is not meant to be limited to any specific location.
  • Figure IB illustrates by way of example the conduit 128 may be disposed in a general middle region of the producing formation 110.
  • the producing formation 110 may be configured with a fresh water flood or a gas injection process (e.g. , carbon dioxide injection), such that embodiments disclosed herein may readily provide for the conversion of these processes to that of a saltwater flood (or flood with other comparable electrolyte).
  • the saltwater flood may be accomplished to provide an electrolytic path or electric circuit formed within the producing formation 110.
  • the wellbores 104, 106 may each have an electrode 132 disposed therein. As illustrated, the electrodes 132 may be located near the bottom of the wellbores 104, 106, such that the electrodes 132 may extend at least partially into the solution 138. Although Figures 1A and IB illustrate two electrodes 132, it should be understood that any number and configuration of electrodes 132 within any number or configuration of wellbores may be provided in contact with the solution 138. For example, the wellbores themselves may be configured as an at least partial or entire electrode. In another embodiment, the electrodes may extend the entire length or part of the length of the vertical and/or deviated portions of the wellbore. This may be accomplished, for example, by electrically insulating a portion of an electrical conductor from its surroundings and/or the solution and maintaining a desired length of the conductor uninsulated, allowing current to be conducted through the solution along the uninsulated portion of the conductor.
  • any of the electrodes 132 may be made of electrically conducting materials, such as, for example, aluminum or stainless steel. However, other materials are also possible, such as graphite or other semi-conductive material.
  • the electrodes may be any type of electrode known in the industry, such as the electrode(s) described in either of U.S. Patent Nos. 4,084,639 and 4,199,025, incorporated by reference herein in their entireties.
  • the electrodes 132 may be, for example, metallic electrodes that are long enough so that the lower ends of each may be immersed in the solution 138.
  • the upper ends of the electrodes 132 may be connected by suitable leads (not shown) to an electrical power source 124.
  • the electrodes 132 may be disposed within the wellbores 104, 106 (and any solution 138 present in the wellbores) in any fashion.
  • the electrodes 132 may be coupled to the end of a tube string 133 or similar elongate member.
  • the tube string 133 may include various components, such as downhole tools, sliding sleeves, conduits, connectors, etc.
  • the tube string 133 may include portions that are configured with electrically non-conducting material, such as fiberglass, plastic, or other generally non-conductive materials.
  • Hydrocarbonaceous fluids are generally poor conductors, while an electrolyte, such as brine, is a good conductor. Since an electric current will follow the path of least resistance, current applied to the electrodes 132 will flow directly through the solution 138 that is between the electrodes 132. The flow of current may tend to heat the solution 138 in accordance with the amount of solution 138 disposed therebetween, as well as the magnitude of current being applied to the electrodes 132. The heated solution may function as a heater with respect to the fluids 130 within the producing formation 110, whereby the viscosity of the fluids 130 may be decreased, and the flow characteristics of the fluids 130 in the formation 110 may be enhanced.
  • the electrodes 132 may be operatively connected with a power source 124, which may be located at the surface or another location in electrical communication with the electrodes 132.
  • the power source 124 may be used to create an electric field via an electric circuit created by the power source 124, electrodes 132, and solution 138, as described below.
  • the power source 124 may be of appropriate size and capacity in order to generate electric current that may be conducted into the wellbores 104, 106, and into the solution 138.
  • Components connected between the power source, the wellbores, the electrodes, etc. may be fully insulated from any of the formation(s) in order to isolate the electrical current path, as necessary or desired.
  • the power source 124 may be any conventional power source, such as a battery or steam/furnace turbine-generator.
  • the power source 124 may be a non-conventional power source, such as a renewable (i.e. , green, clean, etc.) energy source.
  • a renewable (i.e. , green, clean, etc.) energy source for example, there may be one or more wind turbines that together may collectively form a wind farm (not shown).
  • a wind farm may be a group of wind turbines in the same approximate location that may be used for production of electric power. Individual turbines may be interconnected with a voltage power collection system, whereby electrical current, which is produced by the turbines, may be transferred from the wind farm (via the power system) to the electrodes 132, and into the solution 138.
  • a renewable source "green" energy is used, thereby eliminating the need to obtain power from a conventional source (e.g. , burning fossil fuels).
  • the ability to store and/or covert the green energy into formation energy i.e. , increased formation pressure and/or decreased viscosity
  • a "green" embodiment may include the use of onsite wind power, or other renewable power, as the source of electricity for the electrochemical reaction.
  • the systems and methods described herein may enjoy extremely low power costs over the long term. Because some green power may not be reliable (e.g. , wind power may be intermittent and somewhat unpredictable), other embodiments disclosed herein entail recharging the formation with energy, such that the system effectively creates a large geologic battery.
  • any of the wellbores may be formed with perforations (not shown), which may be present in the casing and/or the artificial formation 112.
  • the perforations may allow injection of brine or other fluids from the surface into the artificial formation 112.
  • the electrodes 132 may also have perforations disposed therein. Accordingly, fluid injection may occur by the conveyance of pressurized fluid through the tube string 133, out the electrode perforations, and into the artificial formation 112.
  • the wellbores 104, 106 may allow fluids 130 from the producing formation 110 to enter the wellbores and make contact with electrodes 132.
  • an electric current may be passed between the electrodes 132 and into the producing formation 110 because the fluids 130 may form an at least partial conductive path.
  • the action of the electrical current passing through the circuit formed by the electrodes 132, the power source 124, and the solution 138 (and/or fluid 130) may heat the formation(s) 110 and/or 112 as a result of the resistive properties of solution 138 and formation(s) 110 and/or 112.
  • the electrochemical reactions may provide increased internal pressure within the formation 110 to thereby drive hydrocarbonaceous fluids 130 into a producing wellbore 108.
  • the electrochemical reaction may, for example, increase the formation pressure as much as 300 psi over a large area.
  • the electrochemical action within the formation(s) may produce at least the following phenomena:
  • pressure within the wellbore(s) may be sufficient enough to disperse solution 138 (and/or gas formed by electrolysis) out into the producing formation 110.
  • the solution 138 may disperse outwardly from the artificial formation 112 in any direction. This may result, in one example, because the pressure within the producing formation 110 is insufficient to drive fluids 130 into the artificial formation 112.
  • pressure within the artificial formation 112 as a result of increased pressure, such as from pump 120, may cause fluids within the artificial formation 112 to enter the producing formation 110.
  • the dispersal of fluid from the conduit 128 may be, for example, in any outward direction from the conduit 128, including 360-degree radial direction.
  • the ability to drive solution 138 into the producing formation 110 helps broaden the area of where the electrolysis process may occur.
  • the electrochemical reaction may occur within the formation 110 in an area that is much greater than the area defined by the conduit 128.
  • the extra pressure of the solution 138 (via the pressurization of the artificial formation 112) may also provide additional pressure to the formation 110. This may create a synergistic effect that helps further enhance the recovery of the hydrocarbonaceous fluids 130 because the extra pressure may facilitate the movement of the fluids 130 toward the wellbore 108.
  • embodiments presently disclosed may include any of the wellbores fluidly connected with one or more additional wellbores
  • Figures ID, IE, and IF together illustrate additional embodiments where one or more wellbores are mechanically disconnected or isolated from one another (e.g. , not connected by conduits, wellbores, etc.).
  • formation 110 there may be formation 110 between, at least partially, each of the wellbores 104 and 106 and conduits 128 and 129, respectively.
  • the wellbores 104, 106 and/or the conduits 128, 129 may be at least partially disposed within or through the producing formation 110.
  • the formation 110 may provide a resistive barrier to establishing an electric circuit between electrodes 132, the formation may not be terminally or infinitely resistive, and the circuit may still be completed, as illustrated by circuit field lines 135.
  • Figure IE illustrates an "offset" configuration of directionally drilled portions, where the wellbores 104 and 106 may extend past one another, or may have portions adjacent one another.
  • the first wellbore 104 may include a first directionally drilled portion 190
  • the second wellbore 106 may include a second directionally drilled portion 191.
  • There may also be additional wellbores with directionally drilled portions, such as the third wellbore configured with a third directionally drilled portion (not shown).
  • the wellbores 104, 106 may each have an electrode 132 disposed therein. As shown, the electrodes 132 may be located near the bottom or end of the wellbores 104, 106, and the electrodes 132 may extend at least partially into solution 138. Although the formation 110 may provide a resistive barrier to the generation of the electric circuit between electrodes 132, the formation may not be terminally resistive, and the circuit may still be completed, as illustrated by circuit field lines 135.
  • Figures ID or IE illustrate two wellbores, each having an electrode 132
  • any number and configuration of electrodes 132 within any number or configuration of wellbores may be provided within the formation and/or in contact with solution 138.
  • a third wellbore may be disposed in the producing formation, the third wellbore (404A, Figure 4F) also having an electrode therein, and a conduit that may not be fluidly connected and/or mechanically connected with other conduits or wellbores (not shown).
  • the wellbores may be mechanically isolated from other wellbores.
  • any of the wellbores may be mechanically isolated from one or more other wellbores, and at the same time, be in fluid and/or electrical communication.
  • the wellbores may be configured in a geometric configuration that may be substantially symmetrical.
  • any of the wellbores may be formed with perforations (not shown), which may allow injection of brine or other fluids from the surface into areas around the wellbores.
  • the electrodes 132 may also have perforations disposed therein. Accordingly, fluid injection may occur by the conveyance of pressurized fluid through one or more tube strings 133, out the electrode perforations, and into the conduits 128, 129, and/or out into the formation 110.
  • the wellbores 104 and 106 may allow fluids 130 from the producing formation 110 to enter the wellbores and make contact with electrodes 132.
  • an electric current may be passed between the electrodes 132, and into the producing formation 110.
  • the action of the electrical current passing through the circuit formed by the electrodes 132, the power source 124, the formation 110, the solution 138, field 135, etc. may heat the formation(s) 110 as a result of the resistive properties of solution 138 and formation(s) 110.
  • the electrochemical reactions may provide increased internal pressure within the formation 110 to thereby drive hydrocarbonaceous fluids 130 into a producing wellbore 108.
  • Figure IF shows a side perspective view of the wellbores 104 and 106 with corresponding conduits 128 and 129, respectively, offset from each other.
  • offset wellbores may include, for example, one or more wellbores that extend into the formation in the vicinity of one or more additional wellbores.
  • one wellbore may be offset from another wellbore, yet close enough so that the formation may complete the circuit between the wellbores, as shown by circuit field lines 135.
  • the pressure within the wellbore(s) may be sufficient enough to disperse solution 138 (and/or gas formed by electrolysis) out into the producing formation 110 through one or more openings within the wellbore (not shown).
  • the solution 138 may disperse outwardly in any direction. This may result, in one example, because the pressure within the producing formation 110 is insufficient to drive fluids 130 into the formation 110.
  • the dispersal of fluid from the conduit 128 may be, for example, in any outward direction from the conduit 128, including 360- degree radial direction.
  • the ability to drive solution 138 into the producing formation 110 may help broaden the area of where the electrolysis process may occur.
  • the electrochemical reaction may occur within the formation 110 in an area that may be much greater than the area defined by the conduits 128 and 129.
  • the extra pressure of the solution 138 may also provide additional pressure to the formation 110. This may create a synergistic effect that helps further enhance the recovery of the hydrocarbonaceous fluids 130 because the extra pressure facilitates the movement of the fluids 130 toward the wellbore 108.
  • FIG. 2 an embodiment of a system for enhanced recovery of a producing formation separate from a non-producing formation according to embodiments of the present disclosure, is shown.
  • System 200 may include a surface production facility 202 that produces hydrocarbonaceous fluids 230 from a producing formation 210 by way of a wellbore 208.
  • the electrodes 232 may be operatively connected with a power source 224, such as DC power or AC power, which may be located at the surface.
  • the producing formation 210 may be surrounded by one or more non-producing formations, such as overburden 214, bed rock 216, and/or other earthen material 218.
  • a non-producing artificial formation 212 may be created adjacent (e.g. , in the vicinity of, next to, separate from, etc.) and external to the producing formation 210.
  • the artificial formation 212 may include, for example, a plurality of wellbores drilled therein.
  • the artificial formation 212 may include a first wellbore 204 in fluid communication with a second wellbore 206, with a conduit 228 formed therebetween.
  • the artificial formation 212 may be formed in the presence of pre-existing aqueous solutions, or there may be one or more prime movers (e.g. , a pump) 220 configured to convey a surface solution from a source (not shown) to the artificial formation 212.
  • prime movers e.g. , a pump
  • the wellbores 204, 206 and/or the conduit 228 may have an aqueous solution 238 disposed therein, and each of the wellbores may have an electrode 232 disposed therein and in electrical communication with the solution 238, as previously described.
  • any of the wellbores may be formed with perforations (not shown), which may be present in the casing and/or the artificial formation 212.
  • the perforations may allow injection of brine or other fluids from the surface into the artificial formation 212.
  • the electrodes 232 may also have perforations disposed therein. Accordingly, fluid injection may occur by the conveyance of pressurized fluid through a tube string 233, out the electrode perforations, and into the artificial formation 212.
  • the wellbores 204, 206 and/or the conduit 228 may be at least partially disposed within or through the producing formation 110, such that the wellbores 204, 206 and/or conduit 228 are independently or simultaneously useable for production of hydrocarbonaceous fluids 230, in addition to creation of the electric field within the solution 238.
  • a non-producing artificial formation may be converted to a producing artificial formation, if desired.
  • System 300 which may be of similar construction and/or configuration as the systems previously described, may include a surface production facility 302 that produces hydrocarbonaceous fluids 330 from a producing formation 310 by way of a wellbore 308.
  • Figure 3 also includes a wellhead 322.
  • the producing formation 310 may be surrounded by one or more non-producing formations, such as overburden 314, bed rock 316, and/or other earthen material 318.
  • Figure 3 depicts an artificial formation 312 formed adjacent to the producing formation 310, which may be conditioned using methods such as fracturing, acidizing, etc., that may facilitate creation of the artificial formation 312.
  • the artificial formation 312 may include various structures, such as, for example, at least two wellbores 304, 306 and a conduit 328.
  • the wellbores 304, 306 and/or the conduit 328 may have a solution 338 disposed therein, the solution 338 including a pre-existing body of solution, or provided using one or more pumps 320, as described previously.
  • any of the wellbores 304, 306 may be usable to convey fluids to or from the artificial formation 312.
  • the electrodes 332 as shown in Figure 3 may have perforations disposed therein for allowing fluid flow. Fluid injection may occur by the conveyance of pressurized fluid through a tube string 333, out the electrode perforations, and into the artificial formation 312.
  • Figure 3 also depicts a third wellbore 326, which may be drilled, at least partially, through the producing formation 310 and into the artificial formation 312.
  • the third wellbore 326 may include a preexisting wellbore used to recover hydrocarbonaceous fluids from the producing formation 310. Accordingly, drilling operations may be used to extend the third wellbore 326 beyond the producing formation 310, while preexisting or additional cementing and/or casing may be used to selectively isolate the third wellbore 326 from the producing formation 310.
  • the third wellbore 326 may be in fluid communication with the artificial formation 312, isolated from the producing formation 310, or combinations thereof.
  • the wellbores 304, 306, 326 may each include an electrode 332 therein, such that any of the electrodes 332 may extend at least partially into the solution 338. It should be appreciated that one or more of the electrodes may function as a cathode, and one or more of the electrodes 332 may function as an anode, the operation of which would be known to one of skill in the art.
  • the electrodes 332 may be operatively connected with a power source 324, such as a DC power source or an AC power source, which may be located, for example, at the surface.
  • the power source 324 may generate single-phase AC. In another embodiment, the power source 324 may generate three-phase AC.
  • the AC signal may be, for example, rectangular, sinusoidal, saw tooth, etc.
  • the power source 324 may be used to create an electric field through the use of an electric circuit created between the power source 324, electrodes 332, and solution 338, and may include any of the power sources previously described, but is not meant to be limited.
  • Gas may be produced in the artificial formation 312 by an electrolysis process, which may generally be understood as a process that uses an electric current to drive an otherwise non-spontaneous chemical reaction in a medium that contains mobile ions, such as an electrolyte.
  • the medium may be the solution 338, which may include, for example, salt water or brine.
  • the electrodes 332 may provide an electrical interface between the power source 324 and the solution 338.
  • the power source 324 may be configured to provide the energy to achieve the electrolysis, the further details of which would be understood by one of ordinary skill in the art. Accordingly, generation of an electric field within the solution 338 may initiate a region of exothermic electrochemical reaction at the electrodes 332, in the solution 338, in the artificial formation 312, in the formation 310, and combinations thereof.
  • the producing formation 310 may include earthen material that has a porosity sufficient to maintain the hydrocarbonaceous fluids 330 within the producing formation 310, while permitting gas from the artificial formation 312 to permeate into the producing formation so that the gas may solvently mix with hydrocarbonaceous fluids 330. As such, generated gas released from the solution 338 may permeate from the artificial formation 312 into the producing formation 310.
  • hydrogen gas may be generated, as illustrated by Equation 1 below:
  • hydrogen molecules As hydrogen gas is generated, hydrogen molecules, as a result of the molecules' small size and inherent properties, may permeate through the artificial formation, the producing formation, and into the hydrocarbonaceous fluids. Permeation of hydrogen molecules, or another similar gas, into the hydrocarbonaceous fluids, may decrease the viscosity of the hydrocarbonaceous fluids and increase pressure within the producing formation 310 to enhance and/or enable production of the hydrocarbonaceous fluids. If necessary, the artificial formation 312 may be maintained at a selected pressure to facilitate permeation of the gas into the producing formation 310.
  • any components of the system may be configured with monitoring and sensor capability (not shown), such that the recovery and/or overall operation of the system may be measured, as would be known to one of skill in the art.
  • the system may be optimized as a result of system measurements and analysis thereof.
  • the optimization may include select adjustment of system variables, such as the electric field generated by the power source.
  • the electric field may be adjusted by changing at least one of a current, a voltage, a frequency, and combinations thereof.
  • Other methods of optimization are possible in view of the embodiments described herein, such as the placement of wellbores and/or electrodes.
  • an additional synergistic effect of the reaction may include dissipation of heat into the formation that further reduces the viscosity of the formation fluids, and further increases pressure in the formation, due to the additional volume of the gas at the heated temperature.
  • the increased volume of the formation fluids may also "break out" hydrocarbonaceous fluids from the formation matrix, whereby the fluids may flow more readily toward the producing wellbore.
  • the hydrocarbonaceous fluids may flow more readily toward the producing wellbore 308, and the fluids may be easier and therefore cheaper to recover to the surface.
  • Figure 4A shows a system 400, which may include various features and components previously described but not shown, that may be used to produce hydrocarbonaceous fluids 430 from a producing formation 410 by way of a wellbore.
  • the producing formation 410 may be surrounded by non-producing formations, such as an overburden, bed rock, and/or other earthen material (not shown).
  • an artificial formation may be formed that includes a first wellbore 404 in fluid communication with a second wellbore 406. Fluid communication between the wellbores 404, 406 may be provided, for example, by conduit 428. Additional wellbores may be provided, such as, for example, a wellbore 426, that is part of the system 400, but is not in fluid communication with other wellbores 404, 406; however, it should be understood that another conduit (not shown) may be drilled to connect the wellbore 426 with other wellbores 404, 406 and the conduit 428, as desired.
  • the wellbores 404, 406, and/or the conduit 428 may have a solution disposed therein, and any of the wellbores that are part of the artificial formation may be used to convey fluids into or from the artificial formation.
  • the wellbores 404, 406, may be configured with an electrode (132, Figure 1A) disposed therein. As previously described, the electrodes may be used in conjunction with the solution (138, Figure 1A) to carry out an electrolysis process.
  • Figures 4B - 4F together illustrate operational variants and/or various configurations of system 400.
  • Figure 4B shows each of the wellbores 404, 406, and 426 in fluid communication.
  • the artificial formation is shown including a first conduit 428 formed, at least partially, under the producing formation 410.
  • the location of the bottom of any of the wellbores and/or conduits may be as previously described.
  • the bottom of the wellbores 404, 406, 426, etc. may fully reside within the producing formation 410.
  • conduit 428 may also fully reside within the producing formation 410.
  • conduit 428 may be a substantially horizontally drilled wellbore.
  • Figure 4D illustrates wellbores 404, 406, and 426, as well as conduits 428, 412, and 413, disposed within the producing formation 410.
  • the wellbores and connecting conduits may define an artificial formation, which in one embodiment, may reside within, but are fluidly isolated from, the producing formation 410.
  • Figure 4C illustrates an embodiment of the system 400 that may include wellbores 404, 426 disposed external of the producing formation 410, and a wellbore 406 disposed, at least partially, through the producing formation 410.
  • any of the wellbores disposed at least partially through the producing formation 410 may be formed from a previously producing wellbore.
  • wellbore(s) may be simultaneously or sequentially used to produce the hydrocarbonaceous fluids 430.
  • Figure 4E further illustrates an embodiment of the system 400 that includes a fourth wellbore 429 provided in fluid communication with the other wellbores 404, 406, 426 via a conduit 415.
  • Figure 4F depicts an alternate embodiment of system 400 whereby wellbores and conduits may be in separately isolated fluid communication.
  • wellbores 404 and 406 may be in fluid communication as a result of conduit 428, while wellbores 404a and 406a are connected with each other by conduit 413, but are fluidly separated and/or mechanically isolated from wellbores 404, 406.
  • system 400 is not limited to any specific number or configuration of wellbores and/or electrodes 432 so that any number of wellbores may be configured in fluid communication or fluid isolation with or from other wellbores, as desired.
  • Figures 4G and 4H illustrate embodiments where wellbores 404, 404A, and 406 are not fluidly connected (e.g. , fluidly isolated) and/or mechanically isolated (e.g. , disconnected) from each other. As shown, there may be formation 410 in-between, at least partially, each of the wellbores 404, 404A, and 406, as well as corresponding conduits 428, 428A and 429, respectively.
  • Figure 4G illustrates a plurality of wellbores disposed at least partially within the producing formation 410. In this embodiment, the three wellbores 404, 404A, and 406 may each have an electrode 432 disposed therein.
  • the solution may be pumped or otherwise provided into one or more of the wellbores, such that the electrode(s) 432 may extend at least partially therein.
  • a power source operatively connected to the electrodes may then be actuated to produce an electrical field therebetween.
  • generation of the electrical field may include application of alternating current to the solution.
  • the formation 410 may provide a resistive barrier to the generation of the electric circuit between electrodes 432, the formation may not be terminally or infinitely resistive, and accordingly the circuit may still be completed, as illustrated by circuit field lines 435
  • the electrical field may cause an electrochemical reaction within the solution to create a gas that may solvently mix with in situ hydrocarbonaceous fluids, thereby increasing pressure within the formation and/or decreasing the viscosity of the hydrocarbonaceous fluids.
  • a gas may solvently mix with in situ hydrocarbonaceous fluids, thereby increasing pressure within the formation and/or decreasing the viscosity of the hydrocarbonaceous fluids.
  • brine may be provided into the wellbores, and the electrochemical reaction of the solution may form hydrogen gas.
  • the formed gas may freely pass into adjacent formations containing hydrocarbonaceous fluids, mix with hydrocarbonaceous fluids to reduce the viscosity thereof, and increase pressure within the machined flow path, wellbores, and/or adjacent formations.
  • System 500 is shown having three parallel directional wellbores 404, 404a, and 406 which are deviating in the horizontal direction at different heights in the producing formation 410.
  • the system 500 is depicted having electrodes 432 extending the length of the horizontal portion of the wellbores.
  • the electrodes may comprise electrical conductors, such as cables, rods, or piping, which are not electrically insulated or covered by an electrical insulation, thus forming an electrode having a length defined by the length of electrical conductor without electrical insulation.
  • Figure 9A show portions of the insulated electrical conductor 433 located primarily in the vertical portion of the wellbores, wherein the insulation prevents electrical conduction between the conductor and matter in the wellbores that is in contact with the insulation.
  • the uninsulated portions of the electrical conductors, or the electrodes 432 may extend along a portion of the horizontal part of the wells.
  • the electrodes may extend along both the horizontal and the vertical portions of the well.
  • System 500 is shown having three directional wellbores 404, 404a, and 406 which are shown deviating in the horizontal direction in the producing formation 410.
  • the system 500 comprises horizontal wellbore portions having a "Y" or a tri-wing configuration.
  • the system 500 is depicted having electrodes 432 extending the length of the horizontal portion of the wellbores.
  • the electrodes may comprise electrical conductors, such as cables, rods, or piping, which are not electrically insulated or covered by an electrical insulation, thus forming an electrode having a length defined by the length of electrical conductor having no electrical insulation.
  • Figure 9B shows a portion of the insulated electrical conductor 433 located primarily in the vertical portion of the wellbores.
  • the uninsulated portion of the electrical conductors, or the electrodes may extend along portions of the horizontal part of the well.
  • the electrodes may extend along both the horizontal and the vertical portions of the wells.
  • System 500 is shown having three directional wellbores 404, 404a, and 406 which are shown deviating in the horizontal direction in the producing formation 410.
  • the system 500 comprises horizontal wellbore portions having a triangular configuration.
  • the system 500 is depicted having electrodes 432 extending the length of the horizontal portion of the wellbores.
  • the electrodes may comprise electrical conductors, such as cables, rods, or piping, which are not electrically insulated or covered by an electrical insulation, thus forming an electrode having a length defined by the length of the electrical conductor having no electrical insulation.
  • Figure 9C shows a portion of the insulated electrical conductor 433 located primarily in the vertical portions of the wellbores.
  • the uninsulated portion of the electrical conductors, or the electrodes 432 may extend along portions of the horizontal part of the wells.
  • the electrodes may extend along both the horizontal and the vertical portions of the wells.
  • System 600 may be of similar construction and/or configuration as any of the systems previously discussed, and as such, may include one or more wellbores disposed in a producing formation 610.
  • Figure 6A illustrates three wellbores mechanically disconnected (e.g.
  • Figure 6B illustrates three wellbores in fluid communication and mechanical connection with each other, the former resembling a tri-wing or "boomerang" configuration and the latter resembling a triangular configuration.
  • the wellbores may be electrically or electrochemically connected.
  • a first wellbore 604 may include a first directionally drilled portion 690, and similarly a second wellbore 606 may include a second directionally drilled portion 691. There may also be additional wellbores with directionally drilled portions, such as a third wellbore 604A configured with a third directionally drilled portion 692.
  • any of the wellbores 604, 604A, and 606 may have portions that may be offset from one or more of the others, such as conduit portions 628, 628A, and 629 associated therewith.
  • the directionally drilled portions may include in entirety and/or partially conduits 628, 628A, and 629.
  • the conduits 628, 628A, and 629 which may be separated or unconnected from each other, may be configured such that there may be formation 610 between, at least partially, each of the wellbores.
  • the wellbores 604, 604A, and 606 and/or the conduits may contain a solution (not shown), as well as an electrode (not shown), disposed therein, as described previously.
  • the wellbores may be configured as an electrode in and of themselves, such as by being an elongated conducting material.
  • the a tri-wing configuration of wellbores may result in a tri-wing, chevron, Y-shape, or "boomerang" shaped completion of an electrical circuit that may be used to enhance recovery.
  • Figure 6C which depicts an isometric view of system 600, illustrates the wellbores 604, 604A, and 606 may be at least partially disposed within or through the producing formation 610, along with conduits 628, 628A, and 629. The distances of these subsurface paths may stretch thousands of feet.
  • the producing formation 610 may be configured with a fresh water flood or a gas injection process (e.g. , carbon dioxide injection) that includes injection wells 607, such that embodiments disclosed herein may readily provide for the conversion of these systems to that of a saltwater flood (or flood with other comparable electrolyte).
  • the saltwater flood may be accomplished to provide an electrolytic path formed within the producing formation 610.
  • an artificial formation 612 which may include, for example, the conduits, may be formed in the presence of pre-existing aqueous solutions, such as saltwater, brine, etc.
  • a power source 624 may be used to create an electric field 635 via an electric circuit created by the power source 624, electrodes 632, solution 638 (as shown in Figure 6E), conduit 628, formation 610, etc., as previously described.
  • the action of the electrical current passing through the circuit and/or field may heat the formation 610.
  • the electrochemical reactions may provide increased internal pressure within the formation 610 to thereby drive hydrocarbonaceous fluids into a producing wellbore 608.
  • Pressure within the wellbore(s) may be sufficient enough to disperse solution (and/or gas formed by electrolysis) out into the producing formation 610, such that the circuit may be completed even though there is formation 610 between the electrodes.
  • the ability to drive solution into the producing formation 610 may help broaden the area of where the electrolysis process may occur.
  • the electrochemical reaction may occur within the formation 610 in an area that is much greater than the area defined by the conduit(s) 628, 628A, 629.
  • the electrochemical process, and the aforementioned phenomena that may result from the process, may be utilized in order to create an effect in the formation 610 that may re-establishes a driving force within the formation.
  • the reaction(s) may enhance formation pressures as a result of disassociation of molecules, such as the disassociation of free hydrogen and oxygen from the naturally occurring formation water and the solution. Modest amounts of any gases entrained in the formation 610 may also be released.
  • the electrochemical process may create additional gas(es) within the formation, whereby the new gas may result in increased formation pressure.
  • the new gases may be hydrogen and oxygen, which may be generated from the breakdown of water found in both the naturally occurring water of the formation, as well as any introduced solution.
  • Formation water, interstitial water, etc. may be a naturally occurring water electrolyte located in, for example, pore spaces of the formation, and may not have been present when the formation was formed. This water may have a saline electrolyte that may act as a conductor of electrical current.
  • Embodiments disclosed herein may produce significant amounts of gases, such as hydrogen and oxygen, as a result of the electrochemical reactions in the zone between those electrodes.
  • gases such as hydrogen and oxygen
  • the electrochemical reaction may propagates through the solution, formation water, connate water, etc., which may have mixed with hydrocarbonaceous fluids in the rock formation.
  • Connate water is trapped in the pores of a rock during formation of the rock.
  • the chemistry of connate water can change in composition throughout the history of the rock.
  • Connate water can be dense and saline compared with seawater.
  • Formation water, or interstitial water, in contrast, is simply water found in the pore spaces of a rock, and might not have been present when the rock was formed.
  • Connate water is also described as fossil water.
  • Figure 6E illustrates how freed oxygen and hydrogen may migrate throughout the formation, whereby some of the freed gas may combine with other gases, such as carbon, and form C02.
  • the C02 may dissolve in the hydrocarbonaceous fluids, which may expand the volume of the fluids, reduce the fluid viscosity, and/or increase formation pressure. Any freed hydrogen may also increase formation pressure, thereby further enhancing the overall effect of the process.
  • Much of these freed gases may be produced with the formation fluids as the fluids are recovered via wellbores 608.
  • gases may be separated from the formation fluids, and re-injected into the formation through the injection wells 607 (see Figure 6C).
  • wellbores may be drilled in order to provide multiple conductive paths within a given formation that may then be used to achieve an optimization for the enhanced recovery of the formation.
  • the configuration of any of the wellbores and subterranean paths may be contingent upon, for example, the particular attributes of a specific field, the characteristics of the formation, and the design (i.e., configuration) of the subsurface electrical circuit.
  • the paths for the electrodes may be arrayed or situated in the formation in such a manner that the coverage area of the process should be significant.
  • the above diagram also shows small triangles 622 at the surface that represent the wellheads of existing vertical production wells in the field. As the cumulative effects of the electrochemical process propagate through the formation 610, hydrocarbonaceous fluid flow to these existing wells will significantly increase.
  • system 600 may require onsite electrical generation, such as in the form of a conventional diesel or gas generator(s) specifically sized to produce electricity amounts appropriate for the prospective field.
  • This onsite generation may provide a reliable, independent electricity source that system 600 may use to precisely control system needs. Because the process may create gases such as hydrogen in the formation, and the gas may be created in an already compressed environment, there may be an avoidance of substantial compression costs as compared to traditional methods of hydrogen production.
  • FIG. 5A a flow chart illustrating an embodiment of a method for enhanced recovery of hydrocarbonaceous fluids according to embodiments of the present disclosure, is shown.
  • a producing formation that has a number of producing wellbores used for the recovery of hydrocarbonaceous fluids from the formation.
  • an artificial formation may be created adjacent to the producing formation.
  • the artificial formation may include a number of man-made or machined components, such as a plurality of wellbores and/or directionally drilled flow paths.
  • Step 510 may include at least two of the plurality of wellbores in fluid communication with at least one flow path.
  • at least one of the flow paths may be substantially horizontal.
  • a solution may pre-exist within the artificial formation, or solution may be provided thereto, as shown by step 520.
  • the method may include providing a surface solution to any of the wellbores and/or flow paths within the artificial formation.
  • the method may further include steps 530 and 540, which provide for generating an electrical field within the flow path, thereby causing an electrochemical reaction to produce a gas from the solution.
  • the solution may be an electrolyte, such as brine.
  • the solution may help conduct electricity between any of the plurality of electrodes.
  • the gas may permeate out from the artificial formation, and into the producing formation. Once the gas enters the producing formation, the gas may be solvent to and/or mix with the hydrocarbonaceous fluids, as indicated by step 550. Accordingly, the production of gas may increase pressures within any part of the artificial formation, the producing formation, or combinations thereof, thereby enhancing recovery of the hydrocarbonaceous fluids.
  • the electrical field, and hence the electrochemical reaction may occur as a result of a power source operably connected to a plurality electrodes.
  • the power source may be an AC source that provides alternating current to the solution.
  • the power source may provide, for example, a voltage of predetermined magnitude, for example, up to several thousand volts.
  • a current flow of, for example, one thousand amperes may flow between electrodes.
  • the current may flow between the electrodes via a medium disposed in the artificial formation.
  • the medium may be brine, and application of the electrical field applied to the brine may produce hydrogen gas.
  • the method may include step 610 of creating an artificial subterranean formation at least partially underneath a non-artificial producing formation, step 620 reacting a solution disposed in the artificial formation to form a gas, and step 630 permeating the gas into the producing formation, such that the permeated gas in the producing formation increases pressure within the producing formation.
  • the artificial subterranean formation may include three wellbores in fluid communication, such that a triangulated wellbore pattern may be formed.
  • each of the wellbores may be mechanically isolated from one another.
  • Each of the three wellbores may include electrodes configured therein, and usable to provide polarization to the solution.
  • the artificial subterranean formation may include a plurality of wellbores, with at least two of the plurality of wellbores in fluid communication as a result of a horizontally drilled conduit formed directly underneath a natural producing formation.
  • Solution in the artificial formation may react to produce a gas as a result of an electrolysis process created by an electric field generated within the artificial subterranean formation.
  • the solution may be brine, and the produced gas may be hydrogen.
  • the solution and produced gas are not meant to be limited, and there may be other solutions that produce other gases that are capable of permeating from the artificial formation into the producing formation.
  • Step 640 provides for mixing the gas with hydrocarbonaceous fluids disposed in the natural producing formation, thereby enhancing recovery of the hydrocarbonaceous fluid.
  • the mixing of hydrogen gas into the hydrocarbonaceous fluids may advantageously increase the producing formation pressure, and may advantageously help release hydrocarbonaceous fluids from the formation matrix. Accordingly, gas may beneficially mix with the fluids thereby reducing the viscosity of the fluids. Production of gases within a producing formation may advantageously provide energy within the formation to repressurize the formation if the natural energy is no longer adequate to overcome the resistive forces.
  • Figures 7A and 7B various views of arrangements and configurations of systems useable to enhance recovery of hydrocarbonaceous fluids, according to embodiments of the present disclosure, are shown.
  • Figures 7A shows a system 700, which may be of a similar construction and/or configuration as any of the systems previously described. As such, there may be one or more sections of producing formation 710 that may be surrounded by one or more non-producing formations, such as overburden, bed rock, and/or other earthen material.
  • At least one non-vertical wellbore 712 may be formed within (e.g. , in the vicinity of, as part of, etc.) or near the producing formation 710, as well as one or more wellbores 704 and 706 that have a different orientation in the formation with respect to wellbore 712.
  • the orientation of the wellbore 712 with respect to wellbores 704 and 706 may be perpendicular.
  • the at least one non- vertical wellbore 712 may be in fluid communication with any of the wellbores 704, 706.
  • the wellbores 704, 706, 712, etc. be formed with conventional drilling methods, such that the wellbores may be pressurized (including use of wellheads, etc.), cased, cemented, perforated, etc., as would be understood to one of skill in the art. It should be understood that in certain embodiments, one or more of the wellbores may be left uncased, uncemented, or otherwise unmodified.
  • the wellbores may be at least partially disposed within or through the producing formation, such that the wellbores are independently or simultaneously useable for production of hydrocarbonaceous fluids.
  • the wellbores may be formed in the presence of pre-existing aqueous solutions, such as saltwater, brine, etc.
  • the wellbore 712 may be a directionally drilled wellbore. Any of the wellbores 704, 706, and/or 712 may have an electrode 732 disposed therein. In an embodiment, the electrodes may be disposed in, at least partially, a solution (not shown). The electrodes 732 may be disposed within the wellbores in any fashion. For example, the electrodes 732 may be configured as an elongate member disposed therein. The electrodes 732 may be positioned within the wellbores by way of, for example, downhole tools. In addition, the electrodes may be maintained in any desired position as well as in connection with the corresponding wellbore by way of anchoring devices or the like.
  • the electrodes 732 may be operatively connected with a power source 724, which may be located at the surface or another location.
  • the power source 724 may be used to create an electric field via an electric circuit created by the power source, electrode(s), and solution.
  • any of the wellbores may fluidly connected with one or more additional wellbores, while in other embodiments one or more wellbores may be mechanically disconnected or isolated from one another (e.g. , not connected by conduits, wellbores, etc.). In further embodiments, any of the wellbores may be fluidly connected and/or electrochemically connected, but mechanically isolated.
  • the wellbores may include various orientations, such as horizontal, vertical, angled, and combinations thereof.
  • Figure 7B illustrates an additional vertical wellbore 704A, as well as an additional horizontal wellbore 799.
  • Any of the wellbores may have an electrode 732 disposed therein.
  • the wellbores may each have an electrode 732 disposed therein, such that any of the electrodes 732 may extend at least partially into solution (not shown).
  • system(s) 700 is not limited to any specific number or configuration of wellbores and/or electrodes, such that any number of wellbores may be configured in fluid communication or fluid isolation with or from other wellbores, as desired.
  • Figure 8 a lateral side sectional view of multiple wellbores in electrochemical connection according to embodiments of the present disclosure, is shown.
  • Figure 8 shows a system 800, which may be of a similar construction and/or configuration as any of the systems previously described. As such, there may be one or more sections of producing formation 810 that may be surrounded by one or more non-producing formations, such as overburden, bed rock, and/or other earthen material.
  • non-producing formations such as overburden, bed rock, and/or other earthen material.
  • At least one or more wellbores 804 and 806 may be disposed within or near the formation 810.
  • the wellbores 804, 806 may be formed with conventional drilling methods, such that the wellbores may be pressurized (including use of wellheads, etc.), cased, cemented, perforated, etc., as would be understood to one of skill in the art. It should be understood that in certain embodiments, one or more of the wellbores may be left uncased, uncemented, or otherwise unmodified.
  • the wellbores may be at least partially disposed within or through the producing formation, such that the wellbores are independently or simultaneously useable for production of hydrocarbonaceous fluids.
  • the wellbores may be formed in the presence of pre-existing aqueous solutions, such as saltwater, brine, etc.
  • the wellbores 804 and/or 806 may be a directionally drilled wellbore. Any of the wellbores 804, 806 may have an electrode 832 configured therein. In an embodiment, the electrodes may be in contact with, at least partially, a solution 838.
  • the electrodes 832 may be disposed within the wellbores in any fashion. For example, the electrodes 832 may be configured as an elongate member disposed therein.
  • the electrodes 832 may be positioned within the wellbores by way of, for example, downhole tools.
  • the electrodes may be maintained in any desired position as well as in connection with the corresponding wellbore by way of anchoring devices, centralizers, or the like (not shown).
  • the electrodes 832 may be operatively connected with a power source (not shown), which may be located at the surface or another location.
  • the power source may be used to create an electric field 835 via an electric circuit created by the power source, electrode(s), and solution.
  • any of the wellbores may fluidly connected with one or more additional wellbores, while in other embodiments one or more wellbores may be mechanically disconnected or isolated from one another (e.g. , not connected by conduits, wellbores, etc.).
  • any of the wellbores 804, 806 may be fluidly connected and/or electrochemically connected, but mechanically isolated.
  • the wellbores may include various orientations, such as horizontal, vertical, angled, and combinations thereof.
  • system(s) 800 is not limited to any specific number or configuration of wellbores and/or electrodes, such that any number of wellbores may be configured in fluid communication or fluid isolation with or from other wellbores, as desired.
  • the electrochemical reaction of the present disclosure may advantageously occur within and/or outside the producing formation, such that the reaction does not depend on constituent elements within the producing formation. Accordingly, systems and methods of the present disclosure have no dependence on any formation properties. There may beneficially include measurement configurations for the select optimization of systems and methods described herein.
  • Embodiments disclosed herein may provide systems and methods for establishing an electrical field in a subsurface formation, and establishing in response to the electrical field, a zone of electrochemical activity that may result in an electrochemical reaction that increases the formation pressure, reduces the viscosity of any hydrocarbonaceous fluids in the formation, and enhances recovery of the hydrocarbonaceous fluids.
  • Embodiments herein may beneficially combine modern directional drilling techniques with electricity in order to generate electrochemical activity in an underproducing formation so that production may be revitalized.
  • Other embodiments disclosed herein advantageously use modern drilling techniques in order to direct and optimize electrochemical activity within a previously poorly producing formation.
  • Embodiments disclosed herein are readily and easily modeled. Thus, unlike previous conventional EOR activity that necessarily requires very detailed reservoir modeling before operations begin, the embodiments disclosed herein beneficially do not need a similar level of reservoir detail. For example, embodiments disclosed herein may provide a large three-dimensional field of electrochemical activity inside a formation and does not mechanically introduce or require a new driver from the surface. In contrast, conventional EOR processes mechanically introduce reservoir driver(s) (e.g. , C02) through individual wellbores from the surface; as a result, those methods require detailed reservoir modeling to avoid problems such as channeling.
  • reservoir driver(s) e.g. , C02
  • embodiments disclosed herein advantageously require no exploration activity.
  • these embodiments may beneficially be applied to known hydrocarbon formations that are in a state of decline, abandoned, or otherwise difficult-to-produce, such that there may be significantly enhanced extraction of fluids from these formations.
  • embodiments disclosed herein may be applicable to onshore, as well as offshore formations.
  • Embodiments disclosed herein may readily use larger megawattage than previously possible because the electrode array configuration may beneficially be much larger in size. Current densities associated with the embodiments disclosed herein may advantageously be maintained at levels that do not generate steam at the electrodes.
  • embodiments disclosed herein may produce gases that are not limited to the electrical contacts in the reservoir. Instead, freed gases generated by the electrochemical reaction may readily migrate throughout the reservoir, leading to enhanced production beyond areas defined by lines of electrical flow.
  • Embodiments disclosed herein advantageously generate a hyper-efficient in situ gas flood that may be applied to most of the known stranded formations in the U.S and the world. This process dramatically reduces the costs, limitations, and complexities associated with traditional or otherwise conventional enhanced oil recovery.
  • Embodiments of the present disclosure may favorably produce a pressurized gas flood that may encompass the entirety of the formation and significantly enhances the amount of recoverable fluids in the formation.
  • the electrochemical activity that provides the in situ generation of gas does not rely on an external source of C02; therefore, there are no geographic limitations, and systems may be used with and/or applied to any hydrocarbon formation.
  • Embodiments disclosed herein may beneficially provide systems and methods that dramatically lower costs; provide hyper-efficient coverage of the formation; and significant expansion of the scope of potentially recoverable reserves in comparison to previous known EOR processes.
  • Embodiments disclosed herein do not require traditional DC electrolysis; instead, AC electricity may be readily used, which beneficially has electric properties that generate electrochemical activity between large horizontal electrodes within the formation.
  • the electrochemical recovery process includes directionally drilled boreholes, wellbores, conduits, etc. through the formation, whereby they may be filled with an electrolytic solution like salt water. This solution may provide an electrical contact with the naturally occurring formation fluids (e.g., water), thereby allowing current to be conducted between electrodes.
  • the directionally drilled borehole and injected electrolyte may form a long, pressurized, and relatively stable electrode for electricity to conduct therethrough.
  • Each path or conduit drilled through the formation may beneficially become a very long, isolated electrode, through which electrical current may be introduced.
  • a zone of electrochemical activity may propagate through naturally existing formation fluids between the electrodes disposed in the formation.
  • formation pressure increases may be achieved up to 8,000 to 10,000 feet away, which is a substantial increase over conventional EOR. This improved efficiency was attributed to the increase in power distribution resulting from the electrical field's larger coverage area based on the geometry of the wellbore configuration(s).
  • Embodiments disclosed herein beneficially stimulate the formation with electrochemical activity in the zone between electrodes.

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  • Electrolytic Production Of Non-Metals, Compounds, Apparatuses Therefor (AREA)

Abstract

Cette invention concerne un procédé pour une récupération améliorée des fluides hydrocarbonées, le procédé comprenant les étapes de création d'une pluralité de trous de forage dans une formation souterraine, un ou plusieurs trous de forage de ladite pluralité pouvant comprendre une partie de forage directionnel dans laquelle est placée une solution, et une électrode fonctionnellement raccordée à une source d'alimentation. Les autres étapes comprennent la génération d'un champ électrique au sein de la formation souterraine, pour induire ainsi une réaction électrochimique apte à produire un gaz à partir de la solution, de façon que le gaz se mélange aux fluides hydrocarbonés présents dans la formation et élève la pression au sein au moins d'un des trous de forage de ladite pluralité de trous de forage, de la formation souterraine, et de leurs combinaisons, pour améliorer ainsi le taux de récupération du fluide hydrocarboné.
PCT/US2014/036839 2013-05-06 2014-05-05 Systèmes et procédés pour une récupération améliorée des fluides hydrocarbonés WO2014182628A2 (fr)

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Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2017060747A1 (fr) * 2015-10-07 2017-04-13 Petroleum Institute Récupération électrocinétique avancée de pétrole au moyen d'acides à faible concentration
WO2017060748A1 (fr) * 2015-10-07 2017-04-13 Petroleum Institute Récupération électrocinétique avancée de pétrole au moyen de nanoparticules et d'agents tensioactifs
WO2023147670A1 (fr) * 2022-02-04 2023-08-10 Novus Earth Energy Operations Inc. Boucle de transfert d'énergie géothermique équilibrée

Family Cites Families (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US1784214A (en) * 1928-10-19 1930-12-09 Paul E Workman Method of recovering and increasing the production of oil
US4199025A (en) * 1974-04-19 1980-04-22 Electroflood Company Method and apparatus for tertiary recovery of oil
US5803171A (en) * 1995-09-29 1998-09-08 Amoco Corporation Modified continuous drive drainage process
US7398823B2 (en) * 2005-01-10 2008-07-15 Conocophillips Company Selective electromagnetic production tool
US20070102152A1 (en) * 2005-09-20 2007-05-10 Alphonsus Forgeron Recovery of hydrocarbons using electrical stimulation
US20110277992A1 (en) * 2010-05-14 2011-11-17 Paul Grimes Systems and methods for enhanced recovery of hydrocarbonaceous fluids

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2017060747A1 (fr) * 2015-10-07 2017-04-13 Petroleum Institute Récupération électrocinétique avancée de pétrole au moyen d'acides à faible concentration
WO2017060748A1 (fr) * 2015-10-07 2017-04-13 Petroleum Institute Récupération électrocinétique avancée de pétrole au moyen de nanoparticules et d'agents tensioactifs
WO2023147670A1 (fr) * 2022-02-04 2023-08-10 Novus Earth Energy Operations Inc. Boucle de transfert d'énergie géothermique équilibrée

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