WO2013052093A1

WO2013052093A1 - Method and apparatus to increase recovery of hydrocarbons

Info

Publication number: WO2013052093A1
Application number: PCT/US2012/000440
Authority: WO
Inventors: David Randolph Smith; Eric J. WERNIMONT; Mark Christopher Ventura
Original assignee: David Randolph Smith; Wernimont Eric J; Mark Christopher Ventura
Priority date: 2011-10-03
Filing date: 2012-10-03
Publication date: 2013-04-11
Also published as: US20130146288A1

Abstract

Methods for enhancing the extraction of fluids from subterranean formation through wells using hydrogen produced in-situ. Certain embodiments produce hydrogen in-situ through reactions of a hydride. In one embodiment, at least a portion of the produced hydrogen is retained in the well bore for a sufficient amount of time to allow hydrogen to migrate into the subterranean formation. In certain embodiments, in absorbing the hydrogen, the subterranean formation desorbs and releases certain organic material for production through a well bore. In other embodiments, the subterranean formation is placed under pressure to drive the hydrogen further into the formation and into the molecular structure of the formations and substances contained therein. When pressure is released, the hydrogen creates additional fractures or cracks in the formation through explosive compression, thereby increasing permeability of the formation.

Description

METHOD AND APPARATUS TO INCREASE RECOVERY OF

HYDROCARBONS

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to U.S. Provisional Patent Application No. 61/612,560, filed March 19, 2012 entitled, "METHOD AND APPARATUS TO INCREASE RECOVERY OF HYDROCARBONS," and U.S. Provisional Patent Application No. 61/626,684, filed October 03, 201 1 ; and U.S. Provisional Patent Application No. 61/628,535, filed November 02, 201 1 ; and the disclosure of which are incorporated herein by reference.

TECHNICAL FIELD

[0002] 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.

BACKGROUND

[0003] This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as any admission of prior art.

[0004] To extract substances from subterranean strata below the surface of the earth, it is typically desirable to drill well bores into the earth from the surface to house conduits that transfer substances between the surface and the subterranean strata to extract substances from the subterranean strata. The oil and gas industry often uses hydraulic fracturing methods to enhance the recovery of in-situ hydrocarbon substances. A common method is to pump high pressure fluids from the surface into subterranean strata to fracture, break, and/or rubblize the subterranean strata to enhance the subterranean strata's fluid conductivity, thereby allowing more hydrocarbons to flow to the well bore. One conventional hard rock mining technique often involves rubblizing the strata by placing explosives in the wellbore to alter the strata around the wellbores when the explosives are activated.

[0005] 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.

SUMMARY

[0006] 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.

[0007] According to one aspect of the present invention, a method for the extraction of substances from a subterranean formation is described. The method 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.

[0008] In one embodiment, the hydride substance preferably comprises a metal hydride substance. In another embodiment, the first fluid system and second fluid system are injected into the wellbore simultaneously. In another embodiment, the at least one substance from the formation is produced through a wellbore. In another embodiment, the production wellbore is the wellbore used for the injection of the first fluid system and said second fluid system. In another embodiment, 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. In another embodiment, the second conduit is disposed in the first conduit through at least a portion of the wellbore. In yet another embodiment, the first conduit comprises a well casing and the second conduit comprises a coiled tubing disposed in the well casing.

[0009] In one embodiment, at least one of the first fluid system and second fluid system has a pH less than about 7. In another embodiment, the second fluid system has a pH of about 7 or greater. In another embodiment, 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. In another embodiment, 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. In one embodiment, the hydride catalyst comprises cobalt. In one embodiment, the hydride retarder comprises a substance configured to coat the hydride upon contact with said hydride. In yet another embodiment, 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.

[00010] In one embodiment, the first fluid system and second fluid system are alternatively injected into the wellbore. In another embodiment, the first fluid system comprises a previously recovered subterranean fluid produced from the subterranean formation. In one embodiment, an injected fluid comprises at least one of the following: carbon dioxide, water, and any combination thereof. In one embodiment, 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. In one embodiment, the viscosity modifier is a gelling agent. In one embodiment, the gelling agent comprises a pH less than 7. In another embodiment, the respective fluid comprising the propping agent has a pH less than about 7.

[00011] In one embodiment, the step of retaining a portion of said hydrogen comprises retaining at least a portion of the hydrogen in the formation under pressure. In one embodiment, the pressure is held from the surface. In another embodiment, the pressure is held from below surface. In another embodiment, the method further comprises the step of releasing at least a portion of the pressure from the formation. In one embodiment, the release of pressure causes explosive decompression of at least a portion of the formation.

[00012] In one embodiment, at least a portion of the hydrogen of said hydride reaction is produced to surface. In another embodiment, the hydride comprises at least one of the following: sodium borohydride, potassium borohydride, and lithium borohydride. In another embodiment, the hydride can comprise a solid substance or a solution. In another embodiment, the hydride substance comprises a blend of different hydrides. In another embodiment, the production of hydrogen is further assisted by geothermal energy from said formation. In yet another embodiment, 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. In another embodiment, 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.

100013] According to another aspect of the invention, a method to enhance the recovery of at least one subterranean substance by decompressing at least a portion of a subterranean formation is described. The method 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.

[00014] In one embodiment the at least one fluid system comprises at least one of the following: carbon dioxide, steam, nitrogen, carbon monoxide, and any combination thereof. In another embodiment, 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. In another embodiment, the additional fluid system is injected at a pressure above hydraulic fracture pressure. In another embodiment, 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. In one embodiment, 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. In another embodiment, at least one of the at least one fluid system and additional fluid system comprises a hydride catalyst. In another embodiment, 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. In another embodiment, the pressure release is done rapidly from surface to force explosive decompression of at least a portion of hydrogen in said subterranean formation. In yet another embodiment, 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.

[00015] According to another aspect of the present invention, a method of recovering at least one subterranean substance from a subterranean formation with hydrogen is described. The method 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.

[00016] In one embodiment, 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. In another embodiment, the fluid systems are injected in alternating stages. In another embodiment, the at least one fluid system has a pH of about 7 or less. In another embodiment, the at least one additional fluid system comprising hydride has a pH of about 7 or greater. In another embodiment, the recovering back to surface said subterranean substances comprises removing at least a portion of said subterranean formation and transferring said portion to surface. In another embodiment, the at least one substance contained in said subterranean formation comprises hydrocarbons. In another embodiment, the at least one substance contained in said subterranean formation comprises at least one rare earth substance. [00017] According to another aspect of the present invention, a method for the extraction of substances from subterranean formation is described. The method 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.

[00018] In one embodiment, the retaining step comprises holding at least a portion of the subterranean reservoir under hydrostatic pressure. In another embodiment, the recovering step to surface is performed through at least one well bore. In another embodiment, the recovering step is performed through removal of at least a portion of the subterranean formation containing the at least one substance.

[00019] According to another aspect of the present invention, a method of transforming in-situ substances in subterranean formation with hydrogen and producing said substances to surface is described. The method 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. In one embodiment, the producing step occurs through a second wellbore.

[00020] The foregoing has outlined rather broadly the features and technical advantages of the present disclosure in one specific field of underground mining, commonly known as the field of upstream oil and gas recovery from wells, in order that the detailed description of this disclosures mining and in-situ processing that follows may be better understood. It is understood that this disclosures methods of placing hydrogen at subterranean depths can be used in other fields of mining substances from the earth to hydrolyze, crack, rubblizing or otherwise enhance the commercialization of other substances from below the surface of the earth. Additional features and advantages of the disclosure will be described hereinafter which form the subject of the claims of the disclosure. It should be appreciated by those skilled in the art of oil and gas recover or underground mining, that the conception and specific embodiment disclosed of placing hydrogen in subterranean environments may be readily utilized as a basis for modifying or designing other structures, substances, and processes for carrying out the same purposes of the present disclosure. It should also be realized by those skilled in the art that such equivalent constructions, substances, methods, processes, or apparatus do not depart from the spirit and scope of the disclosure as set forth in the appended claims. The novel features which are believed to be characteristic of the disclosure, both as to its organization and method of operation, together with further objects and advantages will be better understood from the following description when considered in connection with the accompanying figures. It is to be expressly understood, however, that each of the figures is provided for the purpose of illustration and description only and is not intended as a definition of the limits of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

[00021] For a more complete understanding of the embodiments of the present invention, reference is now made to the following descriptions taken in conjunction with the accompanying drawing, in which:

[00022] FIG. 1 illustrates an exemplary embodiment of a production system employing certain aspects of the present invention to enhance production of subterranean substances;

[00023] FIG. 2 illustrates an exemplary effect of implementing certain techniques of the present invention to enhance production of subterranean substances; [00024] FIG. 3 illustrates another exemplary effect of implementing certain techniques of the present invention to enhance production of subterranean substances; and

[00025] 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.

[00026] It should be understood that the drawings are not necessarily to scale and that the disclosed embodiments are sometimes illustrated diagrammatically and in partial views. In certain instances, details which are not necessary for an understanding of the disclosed methods and apparatuses or which render other details difficult to perceive may have been omitted. Also, for simplification purposes, there may be only one exemplary instance, rather than all, is labeled. It should be understood, of course, that this disclosure is not limited to the particular embodiments illustrated herein.

DETAILED DESCRIPTION OF THE DISCLOSURE

[00027] As used herein, "a" or "an" means one or more. Unless otherwise indicated, the singular contains the plural and the plural contains the singular. Where the disclosure refers to "perforations" it should be understood to mean "one or more perforations."

[00028] As used herein, "surface" refers to locations at or above the surface of the earth, whether that surface is covered with water or not.

[00029] As used herein, "hydraulic fracturing" refers to the method of injecting a fluid above the fracture pressure of a subterranean reservoir into which the fluid is injected.

[00030] As used herein, "matrix stimulation" refers to the method of injection a fluid below the hydraulic fracture pressure of the reservoir in which the fluid is injected. [00031] As used herein "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.

[00032] As used herein "fluid system" refers to fluids that contain chemicals, catalyst, and/or propping agents.

[00033] As used herein "conduit" refers to a path that allows for transmission of fluid and any pressure of such fluid.

[00034] As used herein " strata," "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.

[00035] As used herein the term "reservoir" includes a deposit of substances in subterranean strata.

[00036] As used herein "fluids" is defined as any liquid, plasma, gas or substance that deforms under shear stress.

[00037] 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. In one embodiment, 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.

[00038] In one embodiment, 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. In another embodiment, 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.

[00039] Attention is first directed to FIG. 1, which shows a preferred embodiment of injection system 100 implementing certain aspects of the present invention. Referring to FIG. 1, there is well casing 1 that is disposed in wellbore 2. In a preferred embodiment, well casing 1 is a conduit that provides at least a path for fluid transmission between the surface and subterranean formation 4. In another embodiment, 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. In a preferred embodiment, injection system 100 further includes tank components 5, 10, and 11 preferably in fluid communication with well casing 1. In one embodiment, tank components 10 and 1 1 each preferably contains first fluid system 12, and tank component 5 preferably contains second fluid system 9. In a preferred embodiment, 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. In a preferred embodiment, first fluid system 12 in tank components 10, 11 comprises a water gel solution configured for hydraulic fracturing of subterranean formation 4. In one embodiment, first fluid system 12 has a pH of less than about 7. In another embodiment, first fluid system 12 has a pH of about 7 or greater. In yet another embodiment, first fluid system 12 is heated to a temperature greater than the surface ambient temperature prior to its injection into well casing 1.

[00040] Referring to FIG. 1, in a preferred embodiment, second fluid system 9 preferably comprises a hydride substance, more preferably a metal hydride substance. Preferably, the introduction of second fluid system 9 to first fluid system 12 causes a chemical reaction that produces hydrogen. In a preferred embodiment, the chemical reaction involves the hydride, and preferably metal hydride, in second fluid system 9. Referring to FIG. 1 , in a preferred embodiment, 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. In one embodiment, second fluid system 9 can include ammonia hydroxide, or a metal hydride hydrocarbon fluid system. In another embodiment, second fluid system 9 can have a pH of less than about 7, about 7, or greater than 7. In an embodiment where second fluid system 9 comprises a base, it preferably comprises ammoniated fluid, ammonia hydroxide, and anhydrous ammonia. In an embodiment containing hydride, the hydride in second fluid system 9 comprises at least one of the following: sodium borohydride, potassium borohydride, and lithium borohydride. In one embodiment, the hydride comprises a solid substance. In another embodiment, the hydride comprises a solution. In another embodiment, the hydride comprises a blend of different hydrides, particularly metal hydrides. In another embodiment, second fluid system 9 further includes at least one of the following alcohol, a hydrocarbon, a hydride stabilizer.

[00041] Referring to FIG. 1 , in one preferred embodiment, 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. Preferably, coiled tubing 6 is another conduit that provides at least a path for fluid transmission between the surface and subterranean formation 4. In a preferred embodiment, pump component 8 is used to inject second fluid system 9 into coiled tubing 6 for injection into well casing 1. Preferably, coiled tubing 6 can be placed at any desired depth in well casing 1 , allowing for the desired placement of where second fluid 9 is introduced into well casing 1 , as well as the desired placement of where fluid systems 12, 9 are mixed with one another conduit that provides at least a path for fluid transmission between the surface and subterranean formation 4. Other means known to one of ordinary skill in the art can be used as a second conduit that provides at least a path for fluid transmission between the surface and subterranean formation 4, such as for injection of second fluid system 9 into well casing 1. [00042] Referring to FIG. 1, in a preferred embodiment, 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. In one embodiment, propping agent 14 and first fluid system 12 have a pH of less than about 7. In a preferred embodiment, the mixture of first fluid system 12 and proppant 14 in blender truck unit 13 can be injected directly into casing 1.

[00043] In another embodiment, 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. The hydride catalyst and/or retarder are preferably selected based on the particular temperature of the area in well casing 1 around subterranean formation 4. Other additives can also be added to first fluid system 12 in blender truck unit 13, such as, but not limited to, stabilizers and frac chemicals known to those familiar with the art of hydraulic fracturing, including pH adjusters, cross linkers, surfactants, breakers, tracers, and any combination thereof. In one embodiment, 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.

[00044] In a preferred embodiment, once first fluid system 12, proppant 14, and any additional additives are sufficiently mixed, 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. Referring to FIG. 1, in a preferred embodiment, 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.

[00045] According to another aspect of the present invention, there is provided a method of enhancing production in low permeability formations using injection system 100. Referring to FIG. 1, in a preferred embodiment, first fluid system

12 from tank components 10 and 1 1, proppant 14 from proppant dump truck 15, and any desired additives are added to blender truck unit 13 for mixing. At any point in time, 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. In a preferred embodiment, 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. Once blender truck unit 13 has sufficiently mixed the substances therein, both 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. In another embodiment, first fluid system 12 in blender truck unit 13 and second fluid system 9 are each injected in an alternating manner. Referring to FIG. 1 , in a preferred embodiment, 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. In a preferred embodiment, first fluid system 12 is injected at a pressure sufficient to hydraulically fracture subterranean formation 4. In another embodiment, 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.

[00046] In one embodiment, injection of 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. Once the hydraulic fracture injection of first fluid system 12 and second fluid system 9 is completed, coiled tubing 6 is preferably pulled from well casing 1. Upon being introduced to one another, first fluid system 12 and second fluid system 9 react with one another to produce hydrogen 20. Preferably, the hydride in second fluid system 9 reacts with certain substances in first fluid system 12 to produce hydrogen 20. In a preferred embodiment, 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. In one embodiment, production of hydrogen 20 is further assisted by geothermal energy from formation 4. In a preferred embodiment, 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. Further, it is contemplated that 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. In the preferred embodiment where 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. Because 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. In other embodiments, 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.

[00047] FIG. 2 shows a preferred embodiment of the effect of the process described in FIG. 1. After the injection of second fluid system 9 and first fluid system 12 from blender truck unit 13 and injection pump truck 16 is completed, well casing 1 is preferably sealed off to allow produced hydrogen 20 to be retained and permeate formation 4. Referring to FIG. 2, in a preferred embodiment, 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. When the hydride in second fluid system 9 reacts with additives in first fluid system 12, hydrogen 20 is formed. Other suitable ways to isolate well casing 1 known to those of ordinary skill in the art can be used. Sealing off of well casing 1 forces hydrogen 20 to permeate subterranean formation 4 where it is absorbed by formation 4 and substances therein. In one embodiment, 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. In another embodiment, 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. Further, 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.

[00048] 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. In one embodiment, 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.

[00049] It is understood that known aspects of hydraulic fracturing can be used with embodiments of the present invention. In one embodiment, 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.

[00050] 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"). In one embodiment, production system 400 has injection well 420 and at least two production wells 421. In a preferred embodiment, injection well 420 is placed between the at least two production wells 421. Preferably, 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. In a preferred embodiment, 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. In a preferred embodiment, 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.

[00051] According to another aspect of the present invention, first fluid 100 is injected into injection well 420 down injection tubing 405. First fluid 100 migrates into formation 4 through perforations 403. In a preferred embodiment, first fluid 100 comprises carbon dioxide. After a sufficient amount of first fluid 100 has been injected, second fluid 200 is injected into injection well 420 through injection tubing 405. In a preferred embodiment, second fluid 200 comprises salt water. Second fluid 200 also migrates into formation 4 through perforations 403. After a sufficient amount of second fluid 200 has been injected, 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. In a preferred embodiment, third fluid 300 comprises a hydride substance, preferably a metal hydride substance. The successive stages of injection of first fluid 100, second fluid 200, and third fluid 300 migrate through formation 4 from injection well 420 toward both production wells 421. As the successive stages of first fluid 100, second fluid 200, and third fluid 300 travel through formation 4, the fluids mix with one another. In the preferred embodiment, 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. These successive injection stages allow the low pH carbon dioxide to mix with water forming carbonic acid, which then reacts with the high pH hydride fluid system. The reaction between the carbonic acid and hydride releases hydrogen and heat into formation 4, mobilizing and/or driving organic material such as oil, kerogen, and other materials in formation 4 toward production wells 421 and into well casing 401 of the respective production well 421 for production through production tubing 406. In a preferred embodiment, fluids 100, 200, and 300 are injected below fracture pressures of formation 4. It is understood that the descriptions of 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.

[00052] As described, 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.

[00053] Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims. For example, the extraction of oil and gas from subterranean reservoirs is subset of a larger field known as mining, and as such this disclosure has clear and obvious application to other fields of mining including but not limited to the extraction of minerals and fluid other than hydrocarbons. Additionally, the methods and apparatus taught by this disclosure have clear and obvious application in the field of hydrogenation of minerals and fluids in-situ. Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the process, mineral extraction, fluid extraction, in-situ hydrogenation, machine, manufacture, composition of matter, means, methods and steps described in the specification. As one of ordinary skill in the arts of hydrocarbon extraction, water extraction, mining, and hydrogenation will readily appreciate from the disclosure of the present disclosure, processes, devices, manufacture, compositions of matter, means, methods, or steps, presently existing or later to be developed that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein may be utilized according to the present disclosure. Accordingly, the appended claims are intended to include within their scope such processes, devices, manufacture, compositions of matter, means, methods, or steps.

Claims

CLAIMS What is claimed is:

1. A method for the extraction of at least one substance from a subterranean formation comprising:

(a) injecting a first fluid system into a subterranean formation through a wellbore at a pressure sufficient to create at least one fracture in said subterranean formation, wherein said subterranean formation is in fluid communication with said wellbore;

(b) injecting a second fluid system into said subterranean formation through said wellbore, said second fluid system comprising a hydride substance;

(c) mixing, in said wellbore, at least a portion of said first fluid system with at least a portion of the hydride material of said second fluid system to produce hydrogen;

(d) retaining at least a portion of the produced hydrogen in said subterranean formation for a period of time of at least 10 hours; and

(e) after said period of time of retention, producing at least one substance from said subterranean formation to the surface.

2. The method of claim 1 wherein the hydride substance preferably comprises a metal hydride substance.

3. The method of claim 1 wherein the first fluid system and second fluid system are injected into said wellbore simultaneously.

4. The method of claim 1 wherein said at least one substance is produced to surface through a wellbore.

5. The method of claim 4 wherein said wellbore is the wellbore used for the injection of said first fluid system and said second fluid system.

6. The method of claim 1 wherein said first fluid system is injected into said wellbore using a first conduit and said second fluid system is injected into said wellbore using a second conduit separate from said first conduit.

7. The method of claim 6 wherein said second conduit is disposed in said first conduit through at least a portion of said wellbore.

8. The method of claim 7 wherein said first conduit comprises a well casing and said second conduit comprises a coiled tubing disposed in said well casing.

9. The method of claim 1 wherein at least one of the first fluid system and second fluid system has a pH less than about 7.

10. The method of claim 1 wherein said second fluid system has a pH of about 7 or greater.

11. The method of claim 1 further comprising heating the first fluid system to a temperature greater than the surface ambient temperature prior to injecting it into the wellbore.

12. The method of claim 1 wherein 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.

13. The method of claim 12, wherein the hydride catalyst comprises cobalt.

14. The method of claim 12 wherein the hydride retarder comprises a substance configured to coat the hydride upon contact with said hydride substance.

15. The method of claim 1 wherein the second fluid system has a pH of about 7 or greater, said second fluid system comprises at least one of the following: an ammoniated fluid, ammonia hydroxide, and any combination thereof.

16. The method of claim 1, wherein the second fluid system comprises a hydrocarbon.

17. The method of claim 1 wherein the second fluid system comprises a hydride reaction stabilizer.

18. The method of claim 1 wherein the first fluid system and second fluid system are alternatively injected into the wellbore.

19. The method of claim 1, wherein the first fluid system comprises a previously recovered subterranean fluid produced from the subterranean formation.

20. The method of claim 19 wherein the previously recovered fluid comprises at least one of the following: carbon dioxide, water, and any combination thereof.

21. The method of claim 1 wherein 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.

22. The method of claim 21 wherein said viscosity modifier is a gelling agent.

23. The method of claim 22 wherein said gelling agent comprises a pH less than 7.

24. The method of claim 21 wherein the respective fluid comprising the propping agent has a pH less than about 7.

25. The method of claim 1 wherein the second fluid system comprises an alcohol.

26. The method of claim 1 wherein the step of retaining a portion of said hydrogen comprises retaining a portion of said hydrogen in said formation under pressure.

27. The method of claim 26 wherein said pressure is held from the surface.

28. The method of claim 26 wherein said pressure is held from below surface.

29. The method of claim 26 further comprising the step of releasing at least a portion of the pressure from said formation.

30. The method of claim 29 further comprises explosive decompression of said formation in response to said releasing pressure step.

31. The method of claim 1 , wherein at least a portion of the hydrogen of said hydride reaction is produced to surface.

32. The method of claim 1 wherein the hydride comprises at least one of the following: sodium borohydride,^' potassium borohydride, and lithium borohydride.

33. The method of claim 1 wherein the hydride comprises a solid substance.

34. The method of claim 1 wherein the hydride fluid comprises a solution.

35. The method of claim 1 wherein the hydride comprises a blend of different hydrides.

36. The method of claim 1 wherein the production of hydrogen is further assisted by geothermal energy from said formation.

37. The method of claim 1 further comprising the steps of:

absorbing by said formation at least a portion of said retained hydrogen; and

in response to said absorption, desorbing at least one substance from said formation.

38. The method of claim 1, wherein said at least one subterranean substance is produced through a second well bore separate from the well bore provided for injection of said first and second fluid systems.

39. A method to enhance the recovery of at least one subterranean substance by decompressing at least a portion of a subterranean formation comprising a) injecting at least one fluid system comprising a hydride substance into a subterranean formation through a wellbore, wherein said subterranean formation is in fluid communication with said wellbore;

b) producing hydrogen in-situ from a chemical reaction of at least a portion of the hydride substance;

c) retaining at least a portion of said produced hydrogen in the subterranean formation for at least 10 hours;

d) increasing pressure of said formation at least through said hydrogen production and retention;

e) releasing at least a portion of pressure from said subterranean formation; and f) recovering to surface at least one subterranean substance from said subterranean formation through a wellbore.

40. The method of claim 39, wherein the at least one fluid system comprises at least one of the following: carbon dioxide, steam, nitrogen, carbon monoxide, and any combination thereof.

41. The method of claim 39 further comprising injecting an additional fluid system into the wellbore prior to the step of injecting the at least one fluid system.

42. The method of claim 41 wherein said additional fluid system is injected at a pressure above hydraulic fracture pressure.

43. The method of claim 39 further comprising injecting an additional fluid system into the wellbore after the step of injecting said at least one fluid system, wherein said additional fluid system is injected at a pressure below hydraulic fracture pressure.

44. The method of claim 43 wherein 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.

45. The method of claim 44 wherein at least one of the at least one fluid system and additional fluid system comprises a hydride catalyst.

46. The method of claim 39 wherein said pressure is released from the well allowing at least a portion of the in-situ generated hydrogen to flow out of said subterranean formation.

47. The method of claim 39 wherein said pressure release is done rapidly from surface to force explosive decompression of at least a portion of hydrogen in said subterranean formation.

48. The method of claim 39 further comprising the step of placing a packer in said wellbore at a position near where said at least one fluid system is introduced to said subterranean formation, said packer is configured to release at least a portion of pressure in said subterranean formation.

49. A method of recovering at least one subterranean substance from a subterranean formation with hydrogen comprising; 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 said wellbore;

b) injecting at least one additional fluid system into said subterranean formation, said at least one additional fluid system comprising a hydride;

c) releasing hydrogen in said at least one additional fluid system by mixing said at least one fluid system with said at least one additional fluid system in-situ;

d) allowing at least a portion of said hydrogen to enter said subterranean formation; and e) recovering at least one substance contained in said subterranean formation to the surface through a second wellbore.

50. The method of claim 49 wherein 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.

51. The method of claim 49 wherein said fluid systems are injected in alternating stages;

52. The method of claim 49 wherein said at least one fluid system has a pH of about 7 or less.

53. The method of claim 49 wherein said at least one additional fluid system comprising hydride has a pH of about 7 or greater.

54. The method of claim 49 wherein recovering back to surface said subterranean substances comprises removing at least a portion of said subterranean formation and transferring said portion to surface.

55. The method of claim 49 wherein said at least one substance contained in said subterranean formation comprises hydrocarbons.

56. The method of claim 49 wherein said at least one substance contained in said subterranean formation comprises at least one rare earth substance. A method for the extraction of at least one substance from a subterranean formation comprising:

(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 said subterranean formation;

(b) injecting at least one additional fluid system comprising hydrogen;

(c) exposing said subterranean formation to at least a portion of said hydrogen by retaining at least a portion of said hydrogen in said subterranean formation for more than 10 hours;

(d) releasing at least a portion of pressure in said subterranean reservoir; and

(e) recovering back to surface at least one substance disposed in said subterranean formation.

The method of claim 57 wherein said retaining at least a portion of said hydrogen comprises holding at least a portion of said subterranean reservoir under hydrostatic pressure.

The method of claim 57 wherein said recovering step to surface is performed through at least one well bore.

The method of claim 57 wherein said recovering step is performed through removal of at least a portion of said subterranean formation containing said at least one substance.

A method of transforming in-situ at least one substance in a subterranean formation with hydrogen comprising;

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 said first wellbore;

b) injecting at least one additional fluid system into said subterranean formation, said 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 said hydride;

d) retaining at least a portion of said released hydrogen in said subterranean formation for at least 10 hours;

e) allowing at least a portion of said hydrogen to transform at least a portion of a substance contained in said subterranean formation; and f) producing to surface at least a portion of said transformed substance contained in said subterranean formation.

The method of claim 61, wherein said producing step occurs through a second wellbore.