WO2013052093A1 - Procédé et appareil pour améliorer la récupération d'hydrocarbures - Google Patents

Procédé et appareil pour améliorer la récupération d'hydrocarbures Download PDF

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Publication number
WO2013052093A1
WO2013052093A1 PCT/US2012/000440 US2012000440W WO2013052093A1 WO 2013052093 A1 WO2013052093 A1 WO 2013052093A1 US 2012000440 W US2012000440 W US 2012000440W WO 2013052093 A1 WO2013052093 A1 WO 2013052093A1
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WO
WIPO (PCT)
Prior art keywords
fluid system
subterranean formation
hydrogen
hydride
wellbore
Prior art date
Application number
PCT/US2012/000440
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English (en)
Inventor
David Randolph Smith
Eric J. WERNIMONT
Mark Christopher Ventura
Original Assignee
David Randolph Smith
Wernimont Eric J
Mark Christopher Ventura
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by David Randolph Smith, Wernimont Eric J, Mark Christopher Ventura filed Critical David Randolph Smith
Publication of WO2013052093A1 publication Critical patent/WO2013052093A1/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
    • 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
    • E21B43/25—Methods for stimulating production
    • E21B43/255—Methods for stimulating production including the injection of a gaseous medium as treatment fluid into the formation
    • 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
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures

Definitions

  • Embodiments of the present invention are generally directed to methods and apparatus to extract substances from subterranean depths and more specifically to enhancing the extraction and transformation of substances from subterranean strata by altering the subterranean strata with hydrogen.
  • Embodiments of the present invention are particularly applicable to the extraction and or transformation of hydrocarbons, but they are also applicable to the extraction of other gases and minerals from any subterranean depth.
  • Subterranean non-organic substances that are typically extracted using well bores in the mining process include noble metals such as gold, silver, platinum, palladium, and other minerals such as rare earths, thorium, and uranium.
  • Subterranean organic substances that are typically extracted using well bores often include fluid substances, such as oil, bitumen, kerogen, and natural gas, and solid substances such as coal.
  • the particular subterranean reservoirs or strata containing the subterranean fluid substances often do not have sufficient energy to provide the requisite fluid conductivity to drive such fluids into a wellbore for transfer to the surface of the earth.
  • Fluid permeability of a given strata is often measured by those familiar to the art of oil and gas industry extraction in units of Darcy's.
  • the known reservoirs that are pool-like such as Saudi Arabia, Prudoe Bay, Lake Meraciabo, and many others had permeability in the order of Darcy or milli-Darcy.
  • Today's unconventional sand and shale discoveries in the United States often have permeability in the ranges from micro to nano-Darcy permeability and below. Therefore, what is needed is new extraction methods for these unconventional hydrocarbon reservoirs like shales, tight gas sands, coal bed methane reservoirs, diatomaceous deposits, and siltstones, which have ultra-low permeability.
  • Embodiments of the present invention provide for the extraction of subterranean substances to the surface and or transformation of subterranean substances with hydrogen placed in-situ with hydraulic fracture methods. Certain embodiments of the present invention provide for use of hydrogen in-situ for enhancing the recovery of hydrocarbons from very low permeability strata having permeability in the ranges of micro-Darcy and nano-Darcy, such as the oil shale deposits, tight natural gas sands, gas shales, tar sands, bitumen deposits, coal deposits, kerogen accumulations in oil shales, as well as other non-organic minerals. Embodiments of this invention have further applications for the recovery of other subterranean minerals such as rare earths, copper, gold, uranium, and coal to the surface of the earth.
  • a method for the extraction of substances from a subterranean formation comprises the steps of (a) injecting a first fluid system into a subterranean formation through a wellbore at a pressure sufficient to create at least one fracture in the subterranean formation, where the subterranean formation is in fluid communication with the wellbore; (b) injecting a second fluid system into the subterranean formation through the wellbore, where the second fluid system comprises a hydride substance; (c) mixing, in the wellbore, at least a portion of the first fluid system with at least a portion of the hydride material of the second fluid system to produce hydrogen; (d) retaining at least a portion of the produced hydrogen in the subterranean formation for a period of time of at least 10 hours; and (e) after the period of time of retention, producing at least one substance from the subterranean formation to the surface.
  • the hydride substance preferably comprises a metal hydride substance.
  • the first fluid system and second fluid system are injected into the wellbore simultaneously.
  • the at least one substance from the formation is produced through a wellbore.
  • the production wellbore is the wellbore used for the injection of the first fluid system and said second fluid system.
  • the first fluid system is injected into the wellbore using a first conduit and said second fluid system is injected into the wellbore using a second conduit separate from the first conduit.
  • the second conduit is disposed in the first conduit through at least a portion of the wellbore.
  • the first conduit comprises a well casing and the second conduit comprises a coiled tubing disposed in the well casing.
  • the method further comprises a step of heating the first fluid system to a temperature greater than the surface ambient temperature prior to injecting it into the wellbore.
  • the first fluid system comprises at least one of the following: steam, carbon dioxide, water, nitrogen, a hydride catalyst, a hydride retarder, and any combination thereof.
  • the hydride catalyst comprises cobalt.
  • the hydride retarder comprises a substance configured to coat the hydride upon contact with said hydride.
  • the second fluid system has a pH of about 7 or greater, the second fluid system comprises at least one of the following: an ammoniated fluid, ammonia hydroxide, and any combination thereof. In one embodiment, the second fluid system comprises at least one of the following: a hydrocarbon, a hydride reaction stabilizer, and an alcohol.
  • the first fluid system and second fluid system are alternatively injected into the wellbore.
  • the first fluid system comprises a previously recovered subterranean fluid produced from the subterranean formation.
  • an injected fluid comprises at least one of the following: carbon dioxide, water, and any combination thereof.
  • at least one of said first fluid system and second fluid system contains at least one of the following: a propping agent, a fluid viscosity modifier, a surface tension reducing agent, a micro- emulsion, and any combination thereof.
  • the viscosity modifier is a gelling agent.
  • the gelling agent comprises a pH less than 7.
  • the respective fluid comprising the propping agent has a pH less than about 7.
  • the step of retaining a portion of said hydrogen comprises retaining at least a portion of the hydrogen in the formation under pressure.
  • the pressure is held from the surface.
  • the pressure is held from below surface.
  • the method further comprises the step of releasing at least a portion of the pressure from the formation.
  • the release of pressure causes explosive decompression of at least a portion of the formation.
  • the hydride comprises at least one of the following: sodium borohydride, potassium borohydride, and lithium borohydride.
  • the hydride can comprise a solid substance or a solution.
  • the hydride substance comprises a blend of different hydrides.
  • the production of hydrogen is further assisted by geothermal energy from said formation.
  • the method further comprises the steps of absorbing by said formation at least a portion of the retained hydrogen; and in response to said absorption, desorbing at least one substance from the formation.
  • the at least one subterranean substance is produced through a second well bore separate from the well bore provided for injection of the first and second fluid systems.
  • a method to enhance the recovery of at least one subterranean substance by decompressing at least a portion of a subterranean formation comprises the steps of a) injecting at least one fluid system comprising a hydride into a subterranean formation through a wellbore, wherein the subterranean formation is in fluid communication with the wellbore; b) producing hydrogen in-situ from a chemical reaction of at least a portion of the hydride; c) retaining at least a portion of the produced hydrogen in the subterranean formation for at least 10 hours; d) increasing pressure of the formation at least through the hydrogen production and retention; e) releasing at least a portion of pressure from the subterranean formation; f) recovering to surface at least one subterranean substance from the subterranean formation through a wellbore.
  • the at least one fluid system comprises at least one of the following: carbon dioxide, steam, nitrogen, carbon monoxide, and any combination thereof.
  • the method further comprises the step of injecting an additional fluid system into the wellbore prior to the step of injecting the at least one fluid system.
  • the additional fluid system is injected at a pressure above hydraulic fracture pressure.
  • the method further comprises injecting an additional fluid system into the wellbore after the step of injecting the at least one fluid system, wherein the additional fluid system is injected at a pressure below hydraulic fracture pressure.
  • the additional fluid system comprises at least one of the following: an acid, carbon dioxide, an ammoniated fluid, steam, a hydride retarder, and any combination thereof.
  • At least one of the at least one fluid system and additional fluid system comprises a hydride catalyst.
  • the pressure is released from the well allowing at least a portion of the in-situ generated hydrogen to flow out of said subterranean formation.
  • the pressure release is done rapidly from surface to force explosive decompression of at least a portion of hydrogen in said subterranean formation.
  • the method further comprises the step of placing a packer in said wellbore at a position near where said at least one fluid system is introduced to the subterranean formation, said packer is configured to release at least a portion of pressure in the subterranean formation.
  • a method of recovering at least one subterranean substance from a subterranean formation with hydrogen comprises the steps of a) injecting, through at least one conduit disposed in a first wellbore, at least a portion of one fluid system from surface into a subterranean formation in fluid communication with the wellbore; b) injecting at least one additional fluid system into the subterranean formation, the at least one additional fluid system comprising a hydride; c) releasing at least a portion of hydrogen released from said hydride in the at least one additional fluid system by mixing the at least one fluid system with the at least one additional fluid system in-situ; d) allowing at least a portion of the hydrogen to enter the subterranean formation; and e) recovering at least one substance contained in the subterranean formation to the surface through a second wellbore.
  • At least one fluid system comprises at least one of the following: carbon dioxide, a hydride catalyst, a reactive substance configured to liberate hydrogen from said hydride substance, and water.
  • the fluid systems are injected in alternating stages.
  • the at least one fluid system has a pH of about 7 or less.
  • the at least one additional fluid system comprising hydride has a pH of about 7 or greater.
  • the recovering back to surface said subterranean substances comprises removing at least a portion of said subterranean formation and transferring said portion to surface.
  • the at least one substance contained in said subterranean formation comprises hydrocarbons.
  • the at least one substance contained in said subterranean formation comprises at least one rare earth substance.
  • a method for the extraction of substances from subterranean formation comprises the steps of (a) injecting at least one fluid systems from the surface of the earth through at least one conduit disposed in a first wellbore into a subterranean formation at a pressure sufficient to hydraulically fracture the subterranean formation; (b) injecting at least one additional fluid system comprising hydrogen; (c) exposing the subterranean formation to at least a portion of the hydrogen by retaining at least a portion of the hydrogen in the subterranean formation for more than 10 hours; (d) releasing at least a portion of pressure in the subterranean reservoir; and (e) recovering back to surface at least one substance disposed in said subterranean formation.
  • the retaining step comprises holding at least a portion of the subterranean reservoir under hydrostatic pressure.
  • the recovering step to surface is performed through at least one well bore.
  • the recovering step is performed through removal of at least a portion of the subterranean formation containing the at least one substance.
  • a method of transforming in-situ substances in subterranean formation with hydrogen and producing said substances to surface comprises the steps of (a) injecting at least one fluid system through at least one conduit disposed in a first wellbore into a subterranean formation in fluid communication with at least the first wellbore; (b) injecting at least one additional fluid system into the subterranean formation, the at least one additional fluid system comprising a hydride; (c) creating a reaction with said hydride to release hydrogen contained in at least a portion of the hydride; (d) retaining at least a portion of the released hydrogen in said subterranean formation for at least 10 hours; (e) allowing at least a portion of the hydrogen to transform at least a portion of a substance contained in the subterranean formation; and (f) producing to surface at least a portion of the transformed substance contained in the subterranean formation.
  • the producing step occurs through
  • FIG. 1 illustrates an exemplary embodiment of a production system employing certain aspects of the present invention to enhance production of subterranean substances
  • FIG. 2 illustrates an exemplary effect of implementing certain techniques of the present invention to enhance production of subterranean substances
  • FIG. 3 illustrates another exemplary effect of implementing certain techniques of the present invention to enhance production of subterranean substances
  • FIG. 4 illustrates another exemplary embodiment of a production system employing certain aspects of the present invention to enhance production of subterranean substances from multiple wellbores.
  • surface refers to locations at or above the surface of the earth, whether that surface is covered with water or not.
  • hydraulic fracturing refers to the method of injecting a fluid above the fracture pressure of a subterranean reservoir into which the fluid is injected.
  • matrix stimulation refers to the method of injection a fluid below the hydraulic fracture pressure of the reservoir in which the fluid is injected.
  • propping agent refers to any solid material that has substantial strength to resist the overburden forces of the earth in the reservoir wherein it is pumped.
  • fluid system refers to fluids that contain chemicals, catalyst, and/or propping agents.
  • conduit refers to a path that allows for transmission of fluid and any pressure of such fluid.
  • strata As used herein "stratum,” or “formation” includes a particular depth or various depths below the surface of the earth of solids, liquids, and gas constituents that comprise the earth.
  • reservoir includes a deposit of substances in subterranean strata.
  • fluids is defined as any liquid, plasma, gas or substance that deforms under shear stress.
  • Embodiments of the present invention provide a method to improve production of subterranean substances from subterranean formations that have permeability in the ranges of nano-Darcy to micro-Darcy, which the convention hydraulic methods are not as effective at improving permeability as reservoir-like formations with permeability in the milli-Darcy to Darcy range.
  • the method to enhance production of the present invention fractures or transforms the subterranean formation or strata using molecular cracking mechanisms.
  • Certain embodiments of the present invention provide fracturing of the subterranean formation having low permeability to fluid flow using material that is environmentally safer than the substances used in conventional hydraulic fracturing process.
  • the method to enhance production of the present invention uses hydrogen that is generated in the subterranean environment to modify the properties of formation fluid and to further increase the permeability of the subterranean formation by molecularly cracking and desorbing hydrocarbons.
  • the method to enhance production of the present invention uses an energizing fluid that, if flowed back from the reservoir, it can be sold directly with the hydrocarbon fluids produced from the reservoir.
  • FIG. 1 shows a preferred embodiment of injection system 100 implementing certain aspects of the present invention.
  • well casing 1 that is disposed in wellbore 2.
  • well casing 1 is a conduit that provides at least a path for fluid transmission between the surface and subterranean formation 4.
  • wellbore 2 may not include any well casing such that wellbore 2 itself or other conduits that can be removably inserted serves as the conduit providing a path for fluid transmission between the surface and subterranean formation 4.
  • Well casing 1 and wellbore 2 preferably have perforations 3 that provide fluid communication between well casing 1 and formation 4, allowing fluids to flow from well casing 1 to subterranean formation 4, such as during an injection stage, or vice versa, allowing fluids to flow into well casing 1 from subterranean formation 4, such as during production of formation substances to the surface.
  • injection system 100 further includes tank components 5, 10, and 11 preferably in fluid communication with well casing 1.
  • tank components 10 and 1 1 each preferably contains first fluid system 12, and tank component 5 preferably contains second fluid system 9.
  • both first fluid system 12 and second fluid system 9 are introduced to subterranean formation 4 by injecting both fluid systems 12, 9 into well casing 1.
  • First fluid system 12 is preferably used for hydraulic fracturing of subterranean formation 4 where first fluid system 12 is injected at a pressure above the fracture pressure of subterranean formation 4.
  • first fluid system 12 in tank components 10, 11 comprises a water gel solution configured for hydraulic fracturing of subterranean formation 4.
  • first fluid system 12 has a pH of less than about 7.
  • first fluid system 12 has a pH of about 7 or greater.
  • first fluid system 12 is heated to a temperature greater than the surface ambient temperature prior to its injection into well casing 1.
  • second fluid system 9 preferably comprises a hydride substance, more preferably a metal hydride substance.
  • the introduction of second fluid system 9 to first fluid system 12 causes a chemical reaction that produces hydrogen.
  • the chemical reaction involves the hydride, and preferably metal hydride, in second fluid system 9.
  • both fluid systems 12, 9 are kept separate from each other through at least a portion of well casing 1 to prevent them from mixing with one another prematurely.
  • the two fluid systems 12, 9 are preferably combined or mixed near perforations 3.
  • second fluid system 9 can include ammonia hydroxide, or a metal hydride hydrocarbon fluid system.
  • second fluid system 9 can have a pH of less than about 7, about 7, or greater than 7.
  • second fluid system 9 comprises a base, it preferably comprises ammoniated fluid, ammonia hydroxide, and anhydrous ammonia.
  • the hydride in second fluid system 9 comprises at least one of the following: sodium borohydride, potassium borohydride, and lithium borohydride.
  • the hydride comprises a solid substance.
  • the hydride comprises a solution.
  • the hydride comprises a blend of different hydrides, particularly metal hydrides.
  • second fluid system 9 further includes at least one of the following alcohol, a hydrocarbon, a hydride stabilizer.
  • tank component 5 is fluidly coupled to well casing 1 using coiled tubing 6 that can be lowered into well casing 1 through coiled tubing injector head 7 coupled to well casing 1, where coiled tubing injector head 7 is preferably supported by crane 17.
  • coiled tubing 6 is another conduit that provides at least a path for fluid transmission between the surface and subterranean formation 4.
  • pump component 8 is used to inject second fluid system 9 into coiled tubing 6 for injection into well casing 1.
  • injection system 100 further includes blender truck unit 13 fluidly coupled to tank components 10 and 11 to combine first fluid system 12 from both tank components 10 and 1 1.
  • Injection system 100 preferably includes propping agent transport truck 15 that adds propping agent 14, preferably a proppant known to one of ordinary skill in the art for use in hydraulic fracturing, to blender truck unit 13, which is configured to combine propping agent 14 to first fluid system 12.
  • Blender truck unit 13 is preferably adapted to combine other materials with first fluid system 12 that are added to blender truck unit 13.
  • propping agent 14 and first fluid system 12 have a pH of less than about 7.
  • the mixture of first fluid system 12 and proppant 14 in blender truck unit 13 can be injected directly into casing 1.
  • injection system 100 is adapted to heat at least one of second fluid system 9, first fluid system 12, and any other fluid component used to a temperature greater than the surface ambient temperature.
  • One exemplary way to raise the temperature of first fluid 12 is to add steam to blender truck unit 13.
  • Other gas can also be added to blender truck unit 13, such as nitrogen, carbon dioxide, or carbon monoxide.
  • Other additives can also be added to first fluid system 12 in blender truck unit 13, such as water, a surface tension reducing agent, a scale inhibitor, a micro- emulsion, a hydride catalyst, a hydride retarder.
  • An exemplary embodiment of a hydride catalyst is cobalt.
  • An exemplary embodiment of a hydride retarder is a coating for a hydride.
  • first fluid system 12 can include a previously recovered subterranean fluid, more preferably produced from subterranean formation 4.
  • the previously recovered fluid can include carbon dioxide, water, or any combination thereof.
  • Blender truck unit 13 can further add to and mix other fluids with first fluid system 12 for injection such as a fluid viscosity modifier, such as a gelling agent, preferably having a pH of less than 7. It is understood that any of the additives or materials added to blender truck unit 13 can also be added, as an alternative or addition, to second fluid system 9 as appropriate.
  • a fluid viscosity modifier such as a gelling agent, preferably having a pH of less than 7. It is understood that any of the additives or materials added to blender truck unit 13 can also be added, as an alternative or addition, to second fluid system 9 as appropriate.
  • first fluid system 12 in blender truck unit 13 is transferred to at least one high pressure pump truck, such as high pressure pump truck 16, to be injected into well casing 1.
  • high pressure pump truck such as high pressure pump truck 16
  • first fluid system 12 in blender truck unit 13 is injected into well casing 1 through an opening at the side of well casing 1 above the surface.
  • first fluid system in a preferred embodiment, first fluid system
  • blender truck unit 13 for mixing.
  • coiled tubing 6 can be lowered through coiled tubing injector head 7 and preferably lowered to a position near perforations 3 in well casing 1.
  • at least the location of the open end of coiled tubing 6 helps to determine the location of the mixing point of first fluid system 12 and second fluid system 9.
  • the mixing point is preferably below the surface near perforations 3.
  • first fluid system 12 in blender truck unit 13 and second fluid system 9 from tank component 5 are preferably simultaneously injected into well casing 1.
  • first fluid system 12 in blender truck unit 13 and second fluid system 9 are each injected in an alternating manner.
  • first fluid system 12 in blender truck unit 13 is injected into well casing 1 with pump truck 16, and second fluid system 9 is injected into well casing 1 through coiled tubing 6 with pump 8.
  • first fluid system 12 is injected at a pressure sufficient to hydraulically fracture subterranean formation 4.
  • at least one of the fluid systems 12, 9 is injected to provide matrix stimulation, e.g., injected at a pressure below the hydraulic facture pressure of formation 4.
  • first fluid system 12 containing various substances and second fluid system 9 produces hydraulic fractures 18 in subterranean formation 4.
  • Second fluid system 9 and first fluid system 12 which can contain additives, like catalyst, retarders, cross-linkers, surfactants, pH adjusters, are preferably mixed in well casing 1 below the surface and transferred out into the subterranean formation 4 through well perforations 3 and into fractures 18.
  • coiled tubing 6 is preferably pulled from well casing 1.
  • first fluid system 12 and second fluid system 9 react with one another to produce hydrogen 20.
  • the hydride in second fluid system 9 reacts with certain substances in first fluid system 12 to produce hydrogen 20.
  • the hydride in second fluid system 9 reacts with a hydride catalyst, preferably in first fluid system 12, where the catalyst is configured to release the hydrogen in the hydride material.
  • production of hydrogen 20 is further assisted by geothermal energy from formation 4.
  • the injected second fluid system 9 and first fluid system 12 are preferably retained in subterranean formation 4 for at least 10 hours to allow the produced hydrogen 20 to be released into fractures 18 in-situ. While FIG. 1 shows injection system 100 used with a vertical well, it is understood that injection system 100 is equally applicable to horizontal wells.
  • injection system 100 can be used to simultaneously inject second fluid system 9 and first fluid system 12 into a plurality of strata having a plurality of perforated intervals.
  • second fluid system 9 is simultaneously mixed with first fluid system 12
  • these fluid systems mix in well casing 1 and formation 4, causing the hydride in second fluid system 9 to react with additives in first fluid system 12, forming hydrogen 20.
  • well casing 1 is closed off for a period of at least 10 hours, subterranean formation 4 is held under pressure in the presence of hydrogen 20.
  • the period of time can be about 12 hours, about 18 hours, about 24 hours, more than 24 hours, more than 36 hours, more than 48 hours, or more than 72 hours.
  • FIG. 2 shows a preferred embodiment of the effect of the process described in FIG. 1.
  • well casing 1 is preferably sealed off to allow produced hydrogen 20 to be retained and permeate formation 4.
  • well casing 1 is sealed off using valve 21 to seal where coiled tubing 6 was inserted and valve 22 to seal where first fluid system 12 from blender truck unit 13 was injected.
  • valve 21 to seal where coiled tubing 6 was inserted
  • valve 22 to seal where first fluid system 12 from blender truck unit 13 was injected.
  • hydrogen 20 is formed.
  • Other suitable ways to isolate well casing 1 known to those of ordinary skill in the art can be used.
  • Hydrogen 20 forces hydrogen 20 to permeate subterranean formation 4 where it is absorbed by formation 4 and substances therein.
  • the absorbed hydrogen 20 displaces organic material like hydrocarbons, kerogen, and minerals from formation 4, which allows the organic material to flow to well casing 1 for production.
  • hydrogen 20 interacts with the organic material in formation 4, transforming certain properties of the organic material, such as causing it to expand, thereby increasing pressure and temperature in formation 4 and enhancing the mobilization of the hydrocarbon substances. Hydrogen 20 can easily flow from well casing 1 into formation 4 because of its small atomic size.
  • the pressure and temperature gradient created by the exothermic chemical reaction of the hydride with at least the additives in first fluid system 12 in forming hydrogen 20 facilitates the permeation of hydrogen 20 into formation 4 and substances, preferably fluid substances, in formation 4.
  • the pressure in well casing 1 and/or subterranean formation 4 can be held from the surface or below the surface.
  • FIG. 3 illustrates formation 4 from FIGS. 1 and 2 after hydrogen 20 has been sufficiently retained, e.g., after the period of time of at least 10 hours, and valve 22 is opened to release pressure and produce fluids to the surface from formation 4, which include subterranean fluid substances like hydrocarbons and the injected first fluid system 12 and second fluid system 9.
  • valve 22 is opened to release pressure and produce fluids. Opening of at least one valve, preferably valve 22, depressurizes fracture 18 and/or formation 4, creating a new pressure gradient out toward well perforations 3 for the escape and depressurization of hydrogen 20 that permeated formation 4.
  • the depressurization drives hydrogen out of the formation 4, thereby causing explosive decompression of formation 4, which further creates cracks and rubblizing of formation 4 depicted by cloud like zones 24 along fractures 18 and into formation 4.
  • This depressurization is also referred to as explosive decompression.
  • Hydrogen 20's ability to permeate spaces, particularly small spaces in the micrometer and nanometer ranges, in formation 4 allows it to create more cracks in formation 4 to increase permeability formation 4 as a result of explosive decompression.
  • the increased permeability e.g., cracks, frees and/or creates additional paths to allow organic substances such as kerogen, oil, and natural gas trapped in formation 4 to flow into well casing 1 through fractures 18 and perforations 3 and produced through casing 1 to the surface for commercialization. While the descriptions herein relate to production of subterranean fluids, it is understood that subterranean substances can also be produced through physical removal of such substances through suitable means, such as those known to be employed in mining operations.
  • pumping of the second fluid system 9 into the formation 4 can be done in stages throughout the hydraulic fracturing process. For instance, it can be done prior to the gel stages comprising first fluid system 12 or after the gel stages which comprise proppant such as bauxite and sand. Certain embodiments of the present invention can be divided into multiple injection stages of second fluid system 9 containing a hydride substance followed by multiple injection stages of first fluid system 12. These are merely exemplary orders of injections that are not meant to limit embodiments of the present invention.
  • FIG. 4 illustrates another embodiment to enhance production of subterranean substances, such as oil and gas in the field of enhanced oil production referred to those familiar with the art of oil and gas production as enhanced oil recovery (“EOR").
  • production system 400 has injection well 420 and at least two production wells 421.
  • injection well 420 is placed between the at least two production wells 421.
  • each injection well 420 and production wells 421 comprises wellbore 402 with well casing 401 disposed therein, where well casing 401 has perforations 403 to allow fluid communication between surface 430 with formation 4 through well casing 401.
  • Injection well 420 further includes injection tubing 405 disposed in well casing 401 of injection well 420.
  • Production wells 421 each preferably includes production tubing 406 disposed in well casing 401 of the respective production well 421.
  • at least one well e.g., injection well 420 and/or production wells 421 , further includes packer element 440 disposed near the open end of the respective tubing where either fluid is being introduced or fluid is being transferred out.
  • Packer element 440 is placed in the annular space between the respective tubing and the respective casing to help ensure the fluid is done only through the respective tubing, rather than into the annular space.
  • packer element 440 can be used to release pressure from said subterranean formation. It is understood that embodiments shown in FIGS. 1-3 can also include packer element 440 as appropriate.
  • first fluid 100 is injected into injection well 420 down injection tubing 405.
  • First fluid 100 migrates into formation 4 through perforations 403.
  • first fluid 100 comprises carbon dioxide.
  • second fluid 200 is injected into injection well 420 through injection tubing 405.
  • second fluid 200 comprises salt water.
  • Second fluid 200 also migrates into formation 4 through perforations 403.
  • third fluid 300 is injected into injection well 420 through injection tubing 405.
  • Third fluid 300 also migrates into formation 4 through well perforations 403.
  • third fluid 300 comprises a hydride substance, preferably a metal hydride substance.
  • first fluid 100 comprises carbon dioxide, and it has a pH of less than about 7.
  • Second fluid 200 comprises salt water.
  • Third fluid 300 comprises a hydride substance, preferably a metal hydride substance, and it has a pH of 7 or greater.
  • first fluid system 12 and second fluid system 9 of FIG. 1 are equally applicable to fluids 100, 200, and 300 of FIG. 4 as appropriate, for instance the additives and materials that can be added to first fluid system 12 and/or second fluid system 9 can also be correspondingly added to fluids 100, 200, and 300 as appropriate.
  • Another exemplary applicable aspect is the various descriptions of the hydrides, and particularly metal hydrides. Further, it is contemplated that certain embodiments disclosed herein can be used to release hydrogen contained in the hydride substance, preferably in-situ below the surface and preferably in a wellbore.
  • embodiments of the present invention provide advantages over other methods that use hydrides, such as that disclosed in US Patent No. 2,889,884. Such prior art method does not allow the hydrogen to be retained in the subterranean strata. Further, this prior art method neither transmits large amounts of the hydride far into the reservoir nor provide for sufficient mixing.

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Abstract

L'invention concerne des procédés pour améliorer l'extraction de fluides provenant de formations sous-terraines par des puits en utilisant l'hydrogène produit in situ. Certains modes de réalisation produisent de l'hydrogène in situ par les réactions d'un hydrure. Dans un mode de réalisation, au moins une partie de l'hydrogène produit est retenu dans le puits de forage pendant une durée suffisante pour que l'hydrogène migre dans la formation sous-terraine. Dans certains modes de réalisation, lors de l'absorption de l'hydrogène, la formation sous-terraine désorbe et libère certains matériaux organiques en vue de la production à travers un puits de forage. Dans d'autres modes de réalisation, la formation sous-terraine est mise sous pression afin d'entraîner l'hydrogène plus profondément dans la formation et dans la structure moléculaire des formations et des substances qu'elles contiennent. Lorsque la pression est libérée, l'hydrogène crée des fractures ou fissures supplémentaires dans la formation par compression explosive, ce qui augmente la perméabilité de la formation.
PCT/US2012/000440 2011-10-03 2012-10-03 Procédé et appareil pour améliorer la récupération d'hydrocarbures WO2013052093A1 (fr)

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