[001] Cross-Reference to Related Applications

[002] This application claims the benefit of priority under 35 U.S.C. § 119 to U.S. Provisional Application Number 62/477,229, filed March 27, 2017, the entire disclosure of which is incorporated herein by reference.

[003] Technical Field

[004] This invention relates to methods for delivering water reactive chemicals, such as alkali metal silicides, metal silicides, and mixtures thereof, to subterranean reservoirs in order to increase the amount of crude oil that can be extracted from an oil field. The invention uses non-reactive and partially reactive hydrocarbon fluids, particle coatings, and/or fluidic flow control to manage the delivery of the water reactive chemical. The invention also relates to methods using water reactive chemicals to improve recovery of subterranean hydrocarbon and bituminous material and deposits.

[005] Background of the Invention

[006] In hydrocarbon and bitumen material deposits, such as oil and natural gas deposits, a significant fraction of the hydrocarbon resource remains unrecoverable even after primary natural pressure depletion production, secondary water flood, or pressure maintenance operations and even after tertiary enhanced techniques. Existing recovery techniques access only a small portion of known heavy crude reserves, with the balance remaining trapped underground. This is particularly true for the heavier crudes and bitumens in the 10 to 20 degree API (American Petroleum Institute) category, where the viscosity of the deposits may range to several poise. The deposits may also have adverse wettability and/or capillary forces preventing efficient recovery efforts. For example, heavy crudes with the higher viscosities make it difficult to push them toward a production well with water-based fluids. The heavier crudes tend to be younger in age and contain appreciable acidic components as determined by the Total Acid Number (TAN) measured via titration with potassium hydroxide (KOH). Also, many of these crudes may be classified as "dead" crudes in that there is little, if any, gas associated with them to provide a natural energy to assist with the recovery efforts.

[007] Chemically enhanced recovery methods that are often employed include alkaline flooding techniques (US Patent 2,288,857, Subkow) to react with the acidic components of the crude oil to create surfactants in situ and thereby emulsify a portion of the crude oil resulting in lower viscosity and wettability alteration. Alkaline silicates (US Patent 2,920,041, Meadors) have been extensively studied over the years and applied for these purposes. Alkalis may be combined with added surfactants and polymers (US Patent 6,022,834, Hsu et al.) to improve performance and extend applicability to lighter crudes.

[008] Thermally enhanced recovery technologies have also been used to reduce viscosity so that a greater portion of the crude can be forced to a production well before coning or water breakthrough occurs. These techniques include primarily steam flooding (US Patent 5,626,193, Nzekwu et al.) as well as, and to a lesser extent, in situ combustion techniques (US Patent 3,566,967, Shelton et al.). These techniques provide sufficient heat to the reservoir to lower the viscosity of the crude so it can be more easily driven to a production well. Steam is generally limited to shallower reservoirs (less than 3,000 ft) where heat loss to the wellbore and surrounding rock is manageable. Steam may be applied either in a huff-and-puff mode (injecting and producing from the same well) or continuously to drive crude to a dedicated production well.

[009] Horizontal drilling techniques allow contact with a larger cross section of the reservoir such that steam soak via huff-and-puff can be effective. A combination of steam and alkalis in horizontal wells has been proposed (US Patent 4,892,146, Shen). In situ combustion is not limited by depth but burns a portion of the recoverable reserves via injection of oxygen to create both heat and carbon dioxide, which is miscible with crude to swell and reduce viscosity.

[010] Miscible technologies primarily include injection of carbon dioxide gas (US Patent 2,875,830, Martin), (US Patent 4,589,486, Brown et al.) to swell the oil and reduce viscosity, but may include other gases such as hydrogen. Hydrogen is regarded as a less effective swelling agent, since it is on average about 15 times less soluble in crude. However, if the reservoir temperature can be raised above 425 °C (800 °F), there is the possibility for some in situ cracking/hydrogenation reactions (US Patent 2,857,002, Pevere et al.) to occur, which will improve the flowability of the crude. This can be further enhanced by injection of suitable catalytic agents.

[011] Hydrovisbreaking (US Patent 6,328,104, Graue) is the application of hydrogen gas under elevated pressure and temperature to a heavy crude oil or bitumen, which results in a viscosity reduction of the heavy oil or bitumen to a lighter American Petroleum Institute (API) gravity material with reduced viscosity. The hydrovisbreaking process uses combustion units installed in injection wells to burn industrial-grade hydrogen with industrial-grade oxygen. This allows the injection of high-quality steam and hot hydrogen into the hydrocarbon-bearing formation to create the conditions required to promote in situ hydrovisbreaking. This thermal cracking process, involving hydrogenation of the heavy oil or bitumen is usually carried out at the refinery to process the heavy crude or bitumen into products that can be sold. Herron (Experimental Verification of In Situ Upgrading of Heavy Oil, E. Hunter Herron, Oct. 2003) and others have shown that the hydrogenation reaction can be carried out to a significant extent in situ by application of hydrogen and heat. Conditions required were temperatures of 345 °C (650 °F) or greater and hydrogen partial pressure up to 8.7 megapascal (M Pa), or 1,275 psia (88 bar). At these conditions, it was observed that viscosity reduction could be up to 99% with gravity increases of 5 to 10 degrees within several days.

[012] Recovery efforts are often subject to widely varying permeability throughout the production zone or to fissures that direct fluids away from intended production wells. This leads to premature breakthrough and can bypass significant amounts of otherwise recoverable oil. Methods to deal with these challenges include various blocking techniques for the very severe channels and profile modification for less severe cases. Blocking methods include injection of cross-linkable organic polymers or other gelling/grouting inorganic agents such as silicates to rapidly form impermeable barriers in the highest permeability channels. Profile modification can be accomplished more gradually over time by deposition and buildup of gelatinous material (US Patent 2,402,588, Andresen) in the highest permeability flow channels, thereby diverting fluids to less permeable channels containing oil that had been previously bypassed. Aqueous slugs of silicates alternating with multivalent cation salts (US Patent 4,081,029, Holm) build precipitates in the primary channels to divert fluids. Also, gelatinous silicate precipitates may help to stabilize unconsolidated sands, thereby preventing unwanted production of sand.

[013] Despite the existence of these techniques, large heavy crude reserves remain largely untapped, and these recovery methods add significant cost per barrel of recovered oil. These current enhanced oil recovery techniques often produce large quantities of brine at the surface, which can contain toxic metals and pose a threat to water sources if not properly contained.

[014] Summary of the Invention

[015] The invention relates to methods of delivering a composition containing at least one water reactive chemical to a subterranean reservoir through a wet piping system in a wellbore casing, comprising the steps of:

introducing the composition into the wet piping system;

optionally introducing at least one hydrocarbon fluid into the wet piping system; and controlling the flowrate of the composition and the hydrocarbon fluid, when present; wherein the composition is not reacted with aqueous fluid in the wet piping system.

[016] The methods of the invention provide for enhanced delivery of compositions containing water reactive chemicals through a wet piping system in a wellbore casing. The compositions are delivered downhole through a well where the heat and the hydrogen generated in the reaction is immediately available to producing zones of the reservoir. This avoids potential heat loss during transit down the well string. To accomplish this delivery, various techniques can be employed within the scope of the invention to prevent, control, or delay premature reaction with aqueous fluids (e.g., water). For example, these techniques include controlling the flowrate of the compositions and optional hydrocarbon fluids to prevent reaction with aqueous fluids in the wet piping system, encapsulating the compositions in non- reactive viscous materials that prevent or delay contact with aqueous fluids in the wet piping system, treating the surface of the compositions with hydrophobic surface treatments that prevents reaction with aqueous fluids in the wet piping system, and/or, in the case of dual injection wells, controlling flowrates of the compositions and hydrocarbon fluids in order to prevent the compositions from U-tubing and/or sinking into the aqueous sump of the dual injection well, and to enhance dilution and mixing of the compositions in the wellbores of the dual injection well. Combinations of these techniques can also be used to prevent, delay, and control the reaction of the compositions containing the water reactive chemicals with water until the composition reaches the location within the productive zone of the reserve where it can provide the maximum benefit.

[017] Thus, the methods of the invention may further comprise the step of encapsulating the composition in a non-reactive viscous material to form an encapsulated composition, wherein the non-reactive viscous material prevents or delays contact with the aqueous fluid. The methods of the invention may also comprise the step of treating the surface of the composition with a hydrophobic surface treatment to form a surface-treated composition. Furthermore, in a dual injection well, the methods of the invention may further comprise the steps of:

introducing the composition into a casing annulus or a production tubing of a vertical well; introducing the at least one hydrocarbon fluid into the production tubing if the composition is introduced into the casing annulus, or introducing the at least one hydrocarbon fluid into the casing annulus if the composition is introduced into the production tubing;

controlling the flowrate of the composition and the hydrocarbon fluid in order to:

prevent the composition from flowing into the production tubing at the bottom of the vertical well if the composition is introduced into the casing annulus, or to prevent the composition from flowing into the casing annulus at the bottom of the vertical well if the composition is introduced into the production tubing;

prevent the composition from reacting with the sump fluid in the vertical well; and/or mix the introduced composition with the introduced hydrocarbon fluid in the vertical well.

[018] The methods of the invention provide for enhanced delivery techniques of compositions containing water reactive chemicals, such as, for example, alkali metal silicides, metal silicides, or mixtures thereof. The compositions may contain only the water reactive chemicals or they may be mixed, dispersed, or suspended in other non-reactive materials. The alkali metal silicides, for example, react with water in subterranean reservoirs in order to enhance recoverability of hydrocarbons and bituminous materials from within the reservoir. The alkali metal silicide reacts rapidly and completely upon contact with water to release hydrogen and heat and produces an alkali metal silicate solution, all of which can contribute to energizing the reservoir and reducing crude oil viscosity thereby allowing the crude oil to be effectively driven to and/or collected at a production well.

[019] The invention utilizes compositions containing water reactive chemicals, such as alkali metal silicides, metal silicides, or mixtures thereof, which produce significant amounts of heat, hydrogen gas, and, in the case of compositions containing the silicides, a metal silicate solution upon contact with water. The combination of reaction products enhances the recovery of crude oil. For example, one metal silicide that can be used in the invention is a calcium silicide. The metal silicide material can be a solid such as a powder but converts completely and rapidly to a solution upon contact with greater-than-stoichiometric- quantities of water. Metal silicides can be useful in generating hydrogen and heat and can be useful in profile modification applications.

[020] The invention may also utilize an alkali metal silicide (such as disclosed in US Patent 7,811,541, Lefenfeld et al., and 9,657,549, Krumrine et al., which are hereby incorporated by reference in their entirety for all purposes) that rapidly produces significant amounts of heat, hydrogen gas, and an alkali metal silicate solution upon contact with water. The combination of reaction products provides great flexibility for the enhancement of crude oil recovery processes. The methods of the invention can deliver compositions containing alkali metal silicides of the alkali metal group consisting of lithium (Li), sodium (Na), and potassium (K). For example, the methods of the invention can utilize several example compositions including lithium silicide (Lii ₂ Si ₇ ), sodium silicide (Na ₄ Si ₄ ), and potassium silicide (K ₄ Si ₄ ) to improve the recovery of subterranean hydrocarbon and bituminous deposits. For example, sodium silicide, consisting of isolated (Si ₄ ) ^4" tetrahedral anions, can be effectively used to access heavy crude reserves due to its lower cost and performance advantages. Upon reaction with water, sodium silicide produces sodium silicate, hydrogen gas, and heat. Additionally, potassium silicide can be used in the presence of swelling clays where loss of fluid permeability can be a concern. Potassium ion tends to reduce the swelling and expansion of the clay layers. Although much of the discussion below focuses on methods of enhanced delivery techniques of the sodium forms of the alkali metal silicide composition as illustrative examples, other alkali metal versions of silicide (as well as other metal versions of silicide) can also be delivered effectively using the methods of the invention and are included in the scope of the inventions. Mixtures of metal silicides may be used as the metal silicide in the invention. Included within such mixtures are combinations of metal silicides as well as mixed metal silicides. That is, the metal in the metal silicide can be an individual metal (e.g., Ca, Na, K) or the metal can be a combination of metals (e.g., Ca and Na; Na and K; Ca, Na, and K)— a mixed metal silicide. Mixtures of all such silicides can be used.

[021] The alkali silicide utilized in the inventions are preferably a solid initially but converts completely and rapidly to a solution upon contact with greater-than-stoichiometric-quantities of water. The rate of reaction is proportional to particle size and corresponding surface area.

[022] In the case of the alkali metal silicides, the reaction products are soluble silicates, which can be used in water treatment applications due to their ability to precipitate and lower the activity of multivalent metal cations. An aqueous solution of an alkali metal silicate is alkaline and can be termed "an alkaline silicate solution." The silicate reaction product is one component of the solution. Generating sodium silicate in situ through reaction with reservoir brine creates an alkali metal silicate that is well suited to alkaline flooding and profile modification. An example of the generated alkali metal silicate has the consistency of "liquid rock or sand." This is the ratio that is achieved commercially via reaction of sand and caustic in an autoclave process, representing a quasi-equilibrium state. This liquid rock minimizes further undesirable reactions with reservoir minerals. There is sufficient alkalinity and pH to promote formation of in-situ surfactants, which form from reacting the alkali metal silicide with acidic hydrocarbons in the crude oil (hydrocarbon) or bituminous material deposit. The neutralized molecule then has a hydrophilic ionic end and a hydrophobic hydrocarbon end. That is, it is a surfactant and wants to partition between the oil and water phases. The surfactants that form vary in molecular weight and composition depending on the type of acidic components are present. The surfactants can affect wettability, promote emulsification of the crude, and can be foaming agents as gas is generated. As the alkalinity is consumed and the pH falls, or through reaction with multivalent cations, polymeric and colloidal silicate species are deposited in the higher permeability channels. This provides profile modification and sweep improvement. The formed surfactants also lower interfacial tension (IFT) and promote emulsification of the crude oil, which lowers viscosity and aids in the formation of an oil bank that can be propagated toward a producing well. These mechanisms are also present in an alkaline flood.

[023] Brief Description of the Figures

[024] FIG. 1 shows an exemplary well with dual injection of sodium silicide and diesel.

[025] FIG. 2 illustrates a comparative analysis of hydrogen generating capability for sodium silicide with water, sodium metal with water, silicon metal reaction with sodium hydroxide, and aluminum with sodium hydroxide.

[026] FIG. 3 shows a comparison of heat generation capacity of sodium silicide versus sodium metal.

[027] FIG. 4 illustrates a comparison of the expected temperature rise for resulting alkali solutions as a function of excess water.

[028] FIG. 5 shows comparative heat and hydrogen capacities for selected enhanced crude oil recovery techniques including the use of sodium silicide in accordance with the invention.

[029] Description of the Invention

[030] The invention relates to enhanced delivery techniques used to deliver compositions containing water reactive chemicals to a subterranean reservoir through a wet piping system in a wellbore casing. As used herein, "piping system" refers to the wellbore casing and the production tubing which is located within the wellbore casing. The "piping system" includes the casing perforations (i.e., holes), which are an array of radial holes that fluidically connect the wellbore to the subterranean reservoir. The "piping system" also includes the near region of the wellbore - about 1 m outside of the wellbore.

[031] The compositions that may be employed in any of the methods described herein may contain only the water reactive chemicals, such as, for example, alkali metal silicides, metal silicides, or mixtures thereof (described in detail below), or they may be mixed, dispersed, or suspended in other non-reactive materials, such as, for example, diesel, cutter stock, naphta, mineral oil, crude oil, vegetable oil, medium petroleum distillates with a flash point > 40 °C, other non-aqueous hydrocarbon fluids, or mixtures thereof. The composition employed in the methods of the invention may contain, for example, 5 wt.% to 100 wt.%, 20 wt.% to 90 wt.%, 30 wt.% to 60 wt.%, or 40 wt.% to 50 wt.% alkali metal silicides, and the balance being, for example, diesel, if less than 100 wt.% alkali metal silicide is present in the composition.

[032] In a wet piping system and an oil reservoir where there is both free water and/or water oil, the methods of the invention provide for the introduction of a composition containing water reactive chemicals into this fluid (liquid), and control of their contact in order to determine when and where the reaction takes place.

[033] The invention, therefore, relates to a method of delivering a composition containing at least one water reactive chemical to a subterranean reservoir through a wet piping system in a wellbore casing, comprising the steps of:

introducing the composition into the wet piping system;

optionally introducing at least one hydrocarbon fluid into the wet piping system ; and controlling the flowrate of the composition and the hydrocarbon fluid, if present;

wherein the composition is not reacted with aqueous fluid in the wet piping system.

[034] In the methods of the invention, the composition containing the water reactive chemicals may be introduced into the wet piping system alone, i.e., without the introduction of the hydrocarbon fluid. Alternatively, the composition containing the water reactive chemicals may be introduced into the wet piping system prior to, with, and/or after the hydrocarbon fluid is introduced into the wet piping system. The composition containing the water reactive chemicals may also be introduced into the wet piping system inside of the hydrocarbon fluid. The composition containing the water reactive chemicals and the hydrocarbon fluid may be introduced into the wet piping system at the same time, sequentially, and/or non-sequentially, with or without interruption between introducing the composition containing the water reactive chemicals and the hydrocarbon fluid, and in any amount and in any order. For example, one or more slugs of the composition containing the water reactive chemicals may be introduced into the wet piping system before, with, and/or after one or more slugs of the hydrocarbon fluid, and the respective slugs may contain the same or different amounts of the water reactive chemicals and hydrocarbon fluid. The composition and the hydrocarbon fluid may be introduced by any means, including, for example, injection.

[035] As discussed below, combinations of techniques may be used in the methods of the invention in order to prevent, delay, and control the reaction of the compositions with water until the composition reaches the desired target in the subterranean reservoir, including, for example, encapsulating the compositions in non-reactive viscous materials, treating the surface of the compositions with hydrophobic surface treatments, and/or controlling flowrates of the compositions and the hydrocarbon fluids in dual injection wells in order to prevent the compositions from U-tubing and/or sinking into the sump of the wells, and to enhance dilution and mixing of the compositions in the wellbores.

[036] Generally, the hydrocarbon fluid that may be used in the methods of the invention should not react with the compositions containing the water reactive chemicals. For example, the hydrocarbon fluid includes, but is not limited to, diesel, cutter stock, naphta, mineral oil, crude oil, vegetable oil, petroleum distillates with a flash point > 40 °C, other non-aqueous hydrocarbon fluids, or mixtures thereof. Preferably, the hydrocarbon fluid is diesel. The hydrocarbon fluid may have a low viscosity (e.g., less than 15 cP, more preferably less than 10 cP, even more preferably less than 5 cP).

[037] In the methods of the invention, preferably less than 10 wt.%, more preferably less than 5 wt.%, even more preferably less than 1 wt.%, even more preferably less than 0.1 wt.%, most preferably less than 0.01 wt.%, of the water reactive chemicals in the composition reacts with aqueous fluid in the wet piping system when the composition is delivered to the subterranean reservoir.

[038] In the methods of the invention, in order to control the timing and location of the reaction of the water reactive chemicals with aqueous fluid, the flowrates of the compositions containing the water reactive chemicals and the at least one hydrocarbon fluid (if present) are evaluated to consider two major flow regimes: laminar and turbulent. Laminar flow is characterized by high momentum diffusion and low momentum convection, while turbulent flow is characterized by irregular changes in flow magnitude and direction.

[039] In laminar flow, velocity is zero at the walls and highest in the center of the pipe with a parabolic velocity shape. This profile can promote axial mixing when two fluids of differing viscosities are in contact. "Fingering" of the lower viscosity fluid can occur. In the application of water reactive chemicals, this can promote uncontrolled contact with water, so laminar flow regimes should be avoided.

[040] In turbulent flow, the velocity rapidly increases from zero near the wall to a flat profile across the majority of the pipe diameter. This flat profile promotes radial mixing, but limited axial mixing, and the flat velocity profile will not promote it. For application of water reactive chemicals, this pattern can "push" or displace wet fluids with hydrocarbon fluid to control contact of the water reactive chemicals with water.

[041] Flow in a pipe is generally laminar when the Reynolds number is less than about 2,000, whereas at values greater than 2,000, flow is usually turbulent. The transition between laminar and turbulent flow typically does not occur at a specific value of the Reynolds number, but in a range usually beginning between to 1,000 to 2,000 and extending upward to between 3,000 and 5,000. Thus, a Reynolds number of greater than 2000, preferably greater than 3000, more preferably greater than 4000, and even more preferably greater than 5000, will generally result in a turbulent flow. For a 7" casing pipe (inner diameter of 6.5" or ~0.166m), for example, water will achieve this at a volumetric flowrate of 40 liters per minutes (LPM) (assuming density of 1000 kg/m ³ and viscosity of 1 centipoise (cP)) (i.e., 40 liters/min * 0.166m * 1000 kg/m ³ / 1 cP). The invention, therefore, also relates to control of the flowrate of the composition containing the water reactive chemical and the optional hydrocarbon fluid in order to deliver the composition and the hydrocarbon fluid to the subterranean reservoir through a wet piping system in a turbulent flow regime and/or a non-laminar flow regime. When displacing water or other low viscosity fluid (i.e., less than 5 cP), a hydrocarbon fluid can be effectively used when delivered in a turbulent flow regime to effectively "push" or displace the wet fluids in the wellbore casing and the subterranean reservoir.

[042] High viscosity fluids, like heavy crude oil, with a viscosity of about 5000 cP present additional challenges. For example, at this viscosity, a flowrate of 220,000 LPM would be needed, which would generate a pressure drop of greater than 400 psi/m and require 11 MW of power. Instead, additional techniques can be employed when encountering high viscosity liquids.

[043] Therefore, the invention also relates to the use of hydrocarbon fluids that reduce the viscosity of the displaced high viscosity fluid in the wellbore casing and the subterranean reservoir. As the hydrocarbon fluid contacts the crude oil, for example, it acts as a diluent, reducing the viscosity and raising the Reynolds number. For example, addition of 5% to 50%, more preferably 10% to 40%, even more preferably 15 to 20%, diesel fuel into heavy crude can drop the viscosity dramatically to below 500 cP, more preferably below 100 cP, and even more preferably below 50 cP. More effective hydrocarbon fluid used in early slugs reduces the viscosity between fluid and the desired delivery location so that turbulent flow can be achieved before a water reactive chemical suspension reaches water.

[044] In addition to hydrocarbon fluid composition selection, in another aspect of the invention, the hydrocarbon fluid is sized based on the diluent effectiveness and the desired water reactive chemical delivery location. Diluent effectiveness, desired delivery location, and turbulent flow regimes are all factors that are used in the invention to determine an effective delivery system of the water reactive chemicals.

[045] The invention also relates to the placement of a water reactive chemicals through a wet fluid by using alternating slugs of low concentration water reactive chemicals (e.g., less than 5 wt.%, less than 2 wt.%, less than 1 wt.%, less than 0.5 wt.%, less than 0.1 wt.%, less than 0.01 wt.% concentration) in initial contact slugs. For example, a dilute alkali metal silicide can be used to "dry" the wet fluid. Low concentration contact will limit temperature and reaction speed so additional water reactive chemicals can be placed past the initial slugs in desired locations.

[046] Another variation of the above delivery method of the invention is to use a non-reactive viscous material to encapsulate water reactive chemicals, such as a sodium silicide slug, on either side to create a "core-shell" injection configuration. Thus, the methods of the invention may further comprise encapsulating the composition in a non-reactive viscous material to form an encapsulated composition, wherein the non-reactive viscous material prevents or delays contact with the aqueous fluid. As used herein, "delays contact with the aqueous fluid" means that less than 10 wt.%, preferably less than 5 wt.%, more preferably less than 1 wt.%, even more preferably less than 0.1 wt.%, most preferably less than 0.01 wt.%, of the water reactive chemicals in the composition reacts with aqueous fluid in the wet piping system when the encapsulated composition is delivered to the subterranean reservoir.

[047] In this variation of the invention, the shell material comprising the non-reactive viscous material breaks apart and is removed once it makes contact with the reservoir. Temperature changes, pressure changes, and/or shear changes through the perforations in the wellbore casing can trigger the break and removal of the non-reactive viscous material from the encapsulated composition, thereby exposing the water reactive chemical to aqueous fluids in the subterranean reservoir.

[048] The non-reactive viscous material can include the following: a) chemically degradable polymers soluble in a hydrocarbon solvent; b) protected polymers that are hydrocarbon soluble, which when transformed or deprotected become water soluble and degradable; c) non-aqueous solvent/chemical combinations that result in viscous materials; d) non-aqueous solvent/chemical combinations that result in a thixotropic material; and e) hydrophobically modified silica, sand or other inorganic particles that play the role of viscosification of a hydrocarbon solvent. Once delivered into a well formation, the particles can act as a proppant in the fractured formation. Given the hydrophobic nature of the particles, in addition to being a proppant, they will help prevent "capillary end effect blocking."

[049] A non-reactive viscous material can include, for example, a non-aqueous solvent/chemical combination that results in a thixotropic material. A thixotropic material exhibits non-newtonian viscosities where viscosity decreases once shear force is applied. In one example, a thixotropic diluent spacer (for example, diesel with fumed silica added) is pumped down the well in a turbulent flow regime to encapsulate "wet" fluids resident in the delivery piping. Material that is not pushed out of the flow path is encapsulated in the spacer fluid. Once thixotropic spacer flow is stopped, the effective viscosity increases as it sets up. The water reactive chemical can then be delivered in a slow laminar flow regime, which then flows through the middle of the spacer fluid and limits contact with the wet fluid now encapsulated by the thixotropic spacer fluid.

[050] Another variation of the "core-shell" injection invention involves surface treated water reactive chemicals, such as sodium silicide particles. By treating the sodium silicide particles, for example, with a hydrophobic surface treatment chemistry (low Hydrophillic-Lipophillic Balance (HLB) values, such as an HLB of less than 10, more preferably less than 8, and even more preferably less than 6), penetration and reaction of sodium silicide with water can be slowed down. This allows the use of partially water wet hydrocarbon fluids (e.g., a hydrocarbon fluid containing less than 5 wt.% water) (negating the need for dry hydrocarbon) before and after the "treated" sodium silicide core slug.

[051] Therefore, the methods of the invention may further comprise the step of treating the surface of the composition with a hydrophobic surface treatment to form a surface-treated composition.

[052] The surface treatment chemistry can be chosen such that it is degraded or removed due to temperature change, pressure change, and/or shear changes perforations in the wellbore casing.

[053] During the treatment of the oil reservoir with this "surface modified" water reactive chemical material, the material can be kept separated from the hydrocarbon fluids until just before introduction into the well. In this way, introduction can be controlled in a sequential manner.

[054] The invention also relates to dual injection delivery techniques to stimulate vertical wells using the compositions containing water reactive chemicals. For example, the compositions may be introduced into the casing annulus due to its minimization of material in process and the decreased contact time with aqueous solutions in the wellbore sump (both in comparison with introduction into the production tubing). However, introduction into the casing may not prevent settling into an aqueous sump fluid and U-tubing up the production tubing due to hydrostatic pressure. The water reactive chemicals may be prevented from contacting the sump fluid and entering the tubing by simultaneously introducing a hydrocarbon fluid down the production tubing (see, e.g., FIG. 1). In order to reduce cost, for example, the compositions containing the water reactive chemicals may be transported at a high concentration and diluted on-site to the specific needs of the stimulation.

[055] The methods of the invention, therefore, may further comprise the steps of:

introducing the composition containing at least one water reactive chemical into a casing annulus or a production tubing of a vertical well;

introducing the at least one hydrocarbon fluid into the production tubing if the composition is introduced into the casing annulus, or introducing the at least one hydrocarbon fluid into the casing annulus if the composition is introduced into the production tubing;

controlling the flowrate of the composition and the hydrocarbon fluid in order to:

prevent the composition from flowing into the production tubing at the bottom of the vertical well if the composition is introduced into the casing annulus, or to prevent the composition from flowing into the casing annulus at the bottom of the vertical well if the composition is introduced into the production tubing;

prevent the composition from reacting with the sump fluid in the vertical well; and/or mix the introduced composition with the introduced hydrocarbon fluid in the vertical well.

[056] The flowrate of the composition containing the water reactive chemicals and the hydrocarbon fluid may be controlled by at least one means for controlling the flowrate, such as, for example, pressure trucks.

[057] Introduction of the hydrocarbon fluid down the tubing provides the advantage of diluting the introduced water reactive chemical as it enters the reservoir. Dilution will distribute the water reactive chemical particles deeper into the reservoir before reacting so that heat is distributed effectively. Thus, the amount of water reactive chemicals in the composition can be lowered by at least 10 wt.%, more preferably at least 25 wt.%, and even more preferably at least 50 wt.% in the piping system, as compared to the amount of water reactive chemicals in the composition before introduction. Additionally, it helps prevent a water reactive chemical, such as sodium silicide, in the casing from falling through the hydrocarbon fluid column into the well sump due to its density. Pauses during introduction can occur, which lead to denser water reactive chemical particles settling by gravity towards the aqueous sump. The flow of hydrocarbon fluid down the tubing drags the water reactive chemical particles into the reservoir instead of allowing them to settle. An additional pressure truck on the surface can be used to achieve the simultaneous pumping. Mixing and distribution of the hydrocarbon fluid can be altered and adjusted to achieve satisfactory dilution. Thus, the composition may be mixed with the hydrocarbon fluid in the vertical well.

[058] In these dual injection delivery techniques, which may also be used in the methods of the invention, the control of the flowrate can be determined by assuming that the flow of hydrocarbon fluid needs to be high enough so that the water reactive chemical material does not flow into the tubing. With a fluidic communication between the tubing and casing, the pressure exerted by each column of fluid equilibrates. This means that the density of each liquid determines the height difference in the liquid level since the pressure (P) is determined by Density (p) * gravity (g) * column height (h) (P=p*g*h). By setting the pressure equal (equilibrate), the density ratios (h _t = h _c *— ) control the height, where h _t is the tubing

Pt

height, he is the casing height, p _c is the density of the fluid in the casing, and p _t is the density of the fluid in the tubing.

[059] If the reservoir stops taking fluid or is taking fluid slower than the pumping rate, the hydrocarbon fluid flow in the tubing can be maintained so that the water reactive chemical material does not flow into the tubing. The minimum ratio to achieve this is determined by the respective diameters of the tubing and casing annulus and the liquid densities. For example, for a 7" wellbore (having an inner diameter of about 6.5" or 0.166 m) with a 2 7/8" production tubing (having an outer diameter of about 2 7/8" or 0.073 m and an inner diameter of about 2.45" or 0.062 m), the height in the annulus will increase by 57.3 m/m ³ of fluid added to the casing (i.e., 1/(π*(0.166 m) ² /4 - π*(0.073 m) ² /4)). Similarly, the tubing will increase in height by 331.2 m/m ³ of fluid added to the tubing (i.e., 1/(π*(0.062 m) ² /4). To determine a minimum flow ratio to prevent U-tubing, column pressures are set equal by adjusting for the difference in fluid densities. In the following examples, the water reactive chemical is chosen to be NaSi (20% NaSi by mass before addition to the well) having a density of 927.6 kg/m ³ , and the hydrocarbon fluid is chosen to be diesel having a density of 830 kg/m ³ . It is understood, however, that the minimum flow ratio can be calculated for any water reactive chemical and any hydrocarbon fluid as long as their respective densities are known.

[060] Production tubing pressure (p) = 331.2 m/m ³ (h) * 830 kg/m ³ (p) * 9.81 m/s ² (g) / 1000 (kPa/Pa) = 2697 kPa/m ³ of diesel.

[061] Casing Pressure = 57.3 m/m ³ * 927.6 kg/m ³ * 9.81 m/s ² / 1000 (kPa/Pa) = 521 kPa/m ³ of NaSi.

[062] atioing these numbers together give a minimum flow ratio of 5.2 (i.e., 2697 kPa/m ³ / 521 kPa/m ³ ). So, in this example, the NaSi material pump rate is set to no greater than 5.2 times the diesel pumping rate to prevent U-tubing of the NaSi into the production tubing.

[063] Table 1 below describes other dual injection scenarios for different concentrations of NaSi, including the minimum flow ratio to prevent U-tubing of the NaSi into the production tubing, the minimum flow rate in liters per minute (LPM) for the diluent assuming a 250 LPM flow rate for the NaSi, and the effective concentration of the NaSi in the reservoir.

[064] As calculated above, a minimum flow pumping ratio of 5.2 is necessary to prevent U-tubing of a 20% concentration of NaSi having a density of 927.6 Kg/m ³ and diesel having a density of 830 kg/m ³ . Assuming that the 20% NaSi is injected at 250 LPM, for example, the minimum flow rate of the diesel must be set to at least 48.3 LPM (i.e., 250 / 5.2). And the effective concentration of the NaSi in the reservoir is 17.1% (i.e., (250 LPM * 927.6 (p) * 0.20 (NaSi Concentration) / 1000) / ((250 LPM * 927.6 (p) / 1000) + (48.3 LPM * 830 (p) / 1000))).

[065] From this evaluation and field trial data, pump rates for diesel are easily achieved (all below 300 LPM) for the common equipment available. If the additional dilution is considered part of the prescribed operation, then the only additional operating cost is the cost of an additional pressure truck. Alternatively, if mixing is intended to take place downhole (as discussed below), the additional pressure truck may be eliminated.

[066] Another aspect of the dual injection delivery techniques, which may be used in conjunction with the methods of the invention, is diluting and distributing the water reactive chemical in the reservoir itself. Diluting of the water reactive chemical inside the reservoir will effectively spread the thermal energy released during the reaction phase over a larger volume. This allows more of the oil bearing volume to benefit from the enhanced temperature. In order for the mixing to take place, the flow resistance of the perforations in the casing must create a flow restriction. To ensure this occurs, the flow rate must be tuned to the perforation size and quantity. Therefore, the dual injection delivery techniques also relates to obtaining a lower concentration of the composition in the vertical well than the concentration of the composition before introduction. The lower concentration may be obtained by restricting the flow of the composition and the hydrocarbon fluid through the perforations in the casing. The flow may be restricted by controlling the size and number of perforations in the casing.

[067] The column heights that the pumping produces due to the resistance to flow into the reservoir through the perforations is determined by the following orifice analysis extracted from Perry's Chem. Eng. Handbook 7 ^th ed. (equation 6-111).

where:

• Q is volumetric flow rate,

• Co is orifice coefficient,

• Ao is the orifice area,

• Δρ is pressure differential,

• p is density,

• A is the area of the perforations [068] The pressure differential is calculated assuming the reservoir exerts the equivalent pressure to its reported static fluid level. For example, a fluid level of 100 m above the perforations and a fluid density of 1000 kg/m ³ creates a static pressure of 981 kPa (i.e., 100 m * 9.81 m/m ³ * 1000 kg/m ³ / 1000). The pressure applied by the column height pushes diesel and the water reactive chemical into the perforations. To calculate the minimum column height where the pump flow is accepted by the perforations in the well, the flow of each fluid is divided by the single perforation flow rate to determine the number of perforations required for each fluid. For example, assuming 4 meters of perforations and 25 perforations per meter, there are 100 total perforations, and the height is adjusted to calculate the minimum height needed, so that the number of total perforations needed is less than the maximum 100 perforations available. Table 2 thus shows two different scenarios (assuming 100 perforations with ½" (1.27 cm) diameter orifices and a coefficient of 0.6): minimum flow ratio ("Min Flow Ratio") for different concentrations of NaSi (calculated above in Table 1) and the mixing in the bottom of the well for the same different concentrations of NaSi ("Mixing in Hole").

Table 2. Flow Throu h Perforations

[069] In order to assess the possibility of mixing in the bottom of the wellbore, the flow conditions must be estimated. Table 2 gives examples of minimum diesel ratio to prevent U-tubing and Mixing ratios required to dilute the feed concentration by half. First, the flow of diluent diesel is calculated based on a given NaSi concentration, flowrate, and desired effected reservoir concentration. With the overall flowrate known (sum of NaSi flow and diesel rate), the required pressure to achieve that flow is calculated from the orifice equation above. That pressure can be converted to a liquid column height to confirm that the overall flows are reasonable for the well depth. Once the column height is established, the flow distribution can be calculated. If the number of perforations required to accept the two fluids is reasonably even, the probability of even mixing before entering the reservoir is increased.

[070] From Table 2, the required column height varies based on the total flow into the well. For each of the minimum diesel ratios ("Min Ratio" scenarios in Table 2), about 17% of the perforations are required to absorb the diesel injection, with the remaining taking the NaSi material, regardless of concentration. This scenario suggests little mixing, and the diesel provides a buffer to prevent U-tubing and NaSi settling. The column height varies from 105m to 136m, as determined by the changing density of the NaSi as the concentration of the NaSi material changes.

[071] As demonstrated in the "Mixing in hole" scenarios" in Table 2, if the minimum diesel is increased by a factor of ~6, then downhole dilution cuts the concentration in half. In this scenario, the number of perforations needed for flow is closer to 50%, which provides the opportunity of mixing in the wellbore. To minimize the equipment needed, the NaSi material can be injected at full 40% strength and excess diesel pumped into the tubing. This minimizes the equipment requirements while changing the mixing effectiveness.

[072] The methods of the invention may also comprise the steps of:

reacting the composition containing water reactive chemicals with water to generate hydrogen gas, heat, and an alkali metal silicate (if the composition contains alkali metal silicides) that collectively enhance recovery of hydrocarbon or bituminous material from the subterranean reservoir; and

recovering the hydrocarbon or bituminous material to a producing well.

[073] Water Reactive Chemicals

[074] As discussed above, the methods of the invention employ compositions containing water reactive chemicals. The water reactive chemicals may be, for example, alkali metal silicides, metal silicides, and mixtures thereof. Alkali metal silicides that can be utilized in the methods of the invention are described in US Patent 7,811,541 and US Patent 9,657,549, which are incorporated herein by reference in their entirety. Alkali metal silicides include the silicides of lithium, (Li); sodium, (Na); potassium, (K). Mixtures of alkali metal silicides can be used as the metal silicide in the invention. Included within such mixtures are combinations of metal silicides as well as mixed metal silicides. That is, the metal in the alkali metal silicide can be an individual alkali metal (e.g., Li, Na, K) or the alkali metal can be a combination of metals (e.g., Ca and Na; Na and K; Ca, Na, and K)— a mixed alkali metal silicide. Mixtures of all such alkali metal silicides can be used.

[075] Preferred alkali metal silicides are available from SiGNa Chemistry, Inc. of New York, New York. They are generally free-flowing powders that may be easily handled in dry air. These alkali metal silicides do not react with oxygen and only slowly absorb water from the atmosphere and without ignition. In one embodiment of the invention, the alkali metal silicide is a sodium silicide (preferably having a 1:1 Na:Si molar ratio) or a potassium silicide (preferably having a 1:1 K:Si molar ratio). As illustrated by the chemical equation [1] for Na4Si4, alkali metal silicides react with water to produce hydrogen gas, the corresponding alkali metal silicate, and heat. The methods of the invention may utilize compositions containing sodium silicide, (Na4Si4), or a potassium silicide, (K4S14). As illustrated by the following chemical equation for Na4Si4, alkali metal silicides react with water to produce hydrogen gas, the corresponding alkali metal silicate, and heat.

Na ₄ Si ₄ (s) + 5H ₂ 0 (€) - 5H ₂ (g) + 2Na ₂ Si ₂ 0 ₅ (s) + energy [1]

[076] This reaction proceeds smoothly at room temperature and without the need of a catalyst.

[077] The alkali metal silicide reacts with greater-than-stoichiometric quantities of water in the reserve deposit. The release of hydrogen gas dissolves into the heavy crude it contacts, thereby lowering viscosity to make the crude easier to displace. The rapid evolution of hydrogen also creates a viscous foam phase that displaces the oil by raising the pore pressure. Likewise, the released hydrogen gas creates pressure in the well, which forces the crude oil toward the collection point. As outlined above, the production of the corresponding alkali metal silicate provides profile modification, sweep improvements, favorable wettability, and reduced interfacial tension, all of which contribute to forcing crude oil toward the collection point. Both the hydrogen gas and the alkali metal silicate are formed in situ.

[078] The energy created by the reaction above is heat energy that serves to reduce the viscosity of the crude oil reserve. For example, the exact stoichiometric reaction is as follows:

Sodium silicide to sodium disilicate

2NaSi(s) + 5H ₂ 0(/) => Na ₂ Si ₂ 0 ₅ (oc7) + 5H ₂ + 827 kJ [2] [079] The heat of reaction is estimated based upon the individual heats of formation, with Na ₂ Si ₂ 0s being Na ₂ 0 and 2:Si0 ₂ . A value of -126 kJ/mol is assumed for NaSi as the average value obtained by differential scanning calorimetry (DSC) for the heat of reaction of Na with Si. As can be seen from the above reaction [2], both the Na metal and the Si metal portions of the sodium silicide contribute to the formation/liberation of hydrogen. Sodium yields one H2 molecule, and silicon yields four H2 molecules.

[080] Utilization of alkali metal silicides in the methods of the invention is superior to other potentially cost-effective in situ hydrogen and heat generation systems such as Na metal alone (US Patent 4,085,799, Bousaid) or Si metal dissolved in NaOH (US Patent 4,634,540, opp) or Al metal dissolved in NaOH (US Patent 2009/0252671A1, Fullerton). The corresponding prior stoichiometric reactions for these systems are as follows:

Na metal in water to sodium hydroxide

2Na(sJ + 2H ₂ 0(/) => 2NaOH(oc/) + H ₂ (g) + 366.6 kJ [3]

Si metal in sodium hydroxide to sodium metasilicate

Si(s) + 2NaOH(oc7) + H ₂ 0 => Na ₂ Si0 ₃ (aq) + 2H ₂ (g) + 423.8 kJ [4]

Al metal in sodium hydroxide to sodium aluminate

2AI(s) + 2NaOH(oc7) + 2H ₂ 0 => Na ₂ AI ₂ 0 ₄ (oc7) + 3H ₂ (g) + 756.4 kJ [5]

[081] Hydrogen Generation

[082] In an example embodiment of the invention, prior techniques of generating in situ hydrogen and heat could be employed in conjunction with the improved performance provided by the alkali metal silicides, metal silicides, or mixtures thereof to extend or provide the benefits over a longer time frame. For example, the reaction rates of both Si and Al metal with caustic and consequent evolution of hydrogen is much slower in comparison to either sodium silicide or sodium metal. Also, the in situ generation of an amorphous aluminate in conjunction with the silicate provides the precursors for zeolite formation and is beneficial in promoting the hydrovisbreaking reactions. Al metal in NaOH can be employed as the initial slug in a sequence of subsequent sodium silicide slugs due to the longer reaction timeframe. As the reactant slugs disperse in the reservoir, the conditions for zeolite precursors to form are achieved. Concentrations can be modeled and controlled to provide a measure of profile modification due to particulate formation. Combinations of these various prior techniques with the reaction of alkali metal silicides, metal silicides, or mixtures thereof and water to enhance recovery fall within the scope of the invention.

[083] FIG. 2 demonstrates the superior ability of NaSi for generation of hydrogen gas compared to previous techniques. As can be seen, sodium silicide generates 2.25 times more hydrogen than sodium metal, and 3.5 times more hydrogen than silicon or aluminum metal dissolved in NaOH when compared on an equal weight basis of reactants.

[084] Heat Generation

[085] As outlined above, significant heat is also generated from the reactions of alkali metal silicides and water. Crude oil hydrogenation/cracking reactions begin to occur beyond about 325 to 350 °C. Such reactions can result in partial beneficiation and a lower molecular weight distribution (hydrovisbreaking) for the crude oil with resulting lower crude viscosity or pour point. The heats of reaction are included in the preceding comparative chemical reaction details in equations [3, 4, and 5] above. FIG. 3 shows a comparison of the number of moles of reactant required to generate a given quantity of heat. On a mole basis, about 44% fewer moles of sodium silicide are required to generate the same quantity of heat as sodium metal. Although dissolution of Si or Al metal can generate comparable heat, it is a much more gradual heating that is more readily dissipated into the reserve formation. As such, it is less likely to contribute to hydrovisbreaking in the vicinity of the reaction point. It is also dependent upon competing reactions from the formation that can deplete the alkalinity before it has a chance to dissolve the Si or Al.

[086] FIG. 4 shows the expected temperature rise resulting from an embodiment of the method of the invention in the immediate vicinity of the reaction site for the resulting alkali solutions as a function of the amount of excess water added. FIG. 4 compares the temperature rise of sodium disilicate [2] (sodium silicide/water), sodium hydroxide [3] (sodium metal/water), sodium metasilicate [4] (Si metal in NaOH), and sodium aluminate [5] (Al metal in NaOH) as a function of amount of excess water added. That is, there are greater-than-stoichiometric amounts of water in the reaction. Excess water dilutes the concentration of the effective alkali and heat much as would be expected to occur over time in the reservoir. This temperature rise estimate only accounts for the water phase and does not factor in heating of the reservoir rock or crude oil. Also, the temperature rise estimate incorporates sufficient reservoir pressure to keep the water as a liquid phase. If the pressure is too low to keep the water as a liquid, some water may flash off as steam. The reactions for sodium silicide, sodium metal and Al dissolution in NaOH all result in about the same temperature rise. However, the rate of reaction is considerably slower for Al metal dissolution in NaOH. Although the sodium silicide releases more heat per gmole, its higher molecular weight for the resulting reactant makes it equivalent to sodium metal when viewed in terms of the resulting reaction products. In either case, the expected temperature rise indicates that in the general vicinity of the sodium silicide/water reaction there is sufficient heat and hydrogen for hydrovisbreaking reactions to occur and enable improved crude oil recovery.

[087] FIG. 5 displays the combined effects of hydrogen and heat in an XY plot to show the advantages of utilizing sodium silicide as an example of an alkali metal silicide to improve heavy crude recovery potential in accordance with the invention. These heat and hydrogen values are expressed as pseudo densities. The heat density is defined as the amount of heat available via the stoichiometric reaction products or kJ/gram of products. The hydrogen density is defined as the amount of hydrogen available via the solid reactants, that is, excluding any water. Water is excluded because the reaction ultimately includes a solution of varying concentration in the reservoir environment. The solid reactants are purchased and pumped downhole. As shown in FIG. 5, materials with higher hydrogen density and heat density (upper right corner of graph in FIG. 5) are superior and provide more energy to the reservoir either directly via heat released, or indirectly via pressurization of the reservoir.

[088] Alkali Metal Silicate Solution

[089] In addition to the hydrogen generation and heat of reaction, the resultant solution from the methods of the invention is used for enhanced oil recovery performance as well. For example, sodium silicide reacts completely with water to form a multimeric 2.0 mole ratio sodium silicate. Sodium metal reacts to form a sodium hydroxide solution. Dissolving Si metal in sodium hydroxide can yield a variety of alkaline silicate solutions depending on proportions, but the most likely species are a monomeric sodium orthosilicate or metasilicate for stoichiometric purposes. The driving force for continued dissolution of Si metal to higher ratios decreases as the concentration in solution increases.

[090] These are strong alkalis with sodium hydroxide being the strongest. A 1% sodium hydroxide solution has a pH value of about 13.1. An orthosilicate is only a little less at a pH value of 12.9, while a 2.0 mole ratio sodium silicate has a pH value of about 11.85. They are sufficient to react with acidic crude components to generate surfactants in situ, but injection of dissolved silicates can avoid the normal dissolution reactions (see example, US Patent 4,458,755, Southwick et al.). The buffered 2.0 mole ratio sodium silicate is less aggressive toward the reservoir matrix, thereby leading to less of the non-productive consumptive alkali reactions over time. [091] In a reservoir environment where the oil bearing zone is made up of sand (silica), clays (aluminosilicates) and various other minerals (calcite, gypsum, siderite, etc.), a high pH value tends to promote consumptive reactions. Reactions with aluminosilicate clays and other reservoir minerals tend to convert clays and minerals to a sodium-enriched form, thereby depleting alkalinity reserves. The higher the pH value, the more readily and completely these non-productive reactions occur. High reservoir temperatures also increase alkali reaction kinetics, often limiting alkali application to reservoirs less than 150 °F. For example, in these high temperature reservoirs, an alkaline flood may not survive for a period of time long enough to be effective. The alkali can be depleted by non-productive reactions with reservoir minerals and clays rather than by reaction with the crude oil acids. In that case, insufficient surfactants would be generated. In the methods of the invention, the use of a metal silicide or alkali metal silicide generates heat and hydrogen in the reserve deposit formation. The benefit of the reaction is greatest in the immediate vicinity of the reaction, and the alkali does not necessarily have to survive a long period of time to affect collection of the hydrocarbon or bituminous deposit. In a caustic or sodium hydroxide environment, the hydroxide dissolution of sand (crystalline SiC ) produces silicates in situ. Over time, a quasi-equilibrium lower pH value state will be achieved at about a 2.0 to 2.4 ratio silicate. On the other hand, sodium silicide reaction with water naturally results in this "liquid rock" quasi-equilibrium state, thereby partially avoiding the high pH value consumptive reactions experienced in a purely caustic environment resulting from sodium metal application.

[092] Reservoir brine hardness (resulting from multi-valent cations) is detrimental to surfactant and polymer performance. Reservoir clays act as natural ion-exchangers to feed hardness back into whatever fluid is flowing through the reservoir. Sodium hydroxide lowers the activity of these hardness ions, but sodium silicate can lower it by two additional orders of magnitude at the same pH value. The resulting silicates from the reaction of the alkali metal silicides and water serve to minimize detrimental effects of the reservoir brine hardness. The reduced activity of hardness ions by alkalis in combination with natural silica polymerization into colloids as alkali is depleted results in precipitate formation in the reservoir. This silicate precipitation and colloid deposition in the higher flow channels is a method of profile modification (see examples, US Patents 3,871,452 and 3,871,453, Sarem). It results in a moderate flow diverting agent so that chemicals/surfactants and the emulsified oil flow more readily into and through the capillaries and tighter oil zones that had been largely bypassed during any prior secondary (water flooding) recovery efforts.

[093] Injected sodium hydroxide used in alkaline flooding eventually produces a silica rich solution by dissolution of reservoir sand grains, but the effect is delayed compared to direct injection of a silicate solution. That is, sodium hydroxide leads to more non-productive consumption of the available alkali compared to alkali metal silicides such as sodium silicate, for example. The high pH value of hydroxide tends to consume alkalinity at an increased rate until a quasi-equilibrium dissolved silica state is reached and as a result provides less protection against the natural hardness resulting from the reservoir brine and clays.

[094] The methods of the invention apply alkali metal silicides, including sodium silicide, to the recovery of viscous crude oils from subterranean reservoirs. The alkali metal silicides can be powders and solids that react rapidly and completely upon contact with water to release hydrogen and heat, and results in an alkali metal silicate solution, all of which contribute to energizing the reservoir and reducing crude oil viscosity so that the crude oil can be effectively driven to and collected at a production well.