BR112014015091B1 - METHOD OF TREATMENT OF AN UNDERGROUND HYDROCARBIDE RESERVOIR, SAMPLE TAKEN FROM AN UNDERGROUND HYDROCARBIDE RESERVOIR, UNDERGROUND HYDROCARBIDE RESERVOIR AND COMPOSITION TO TREAT THE UNDERGROUND HYDROCARBIDE RESERVOIR - Google Patents

Abstract

method and composition for treating an underground hydrocarbon reservoir, sample taken from an underground hydrocarbon reservoir and underground hydrocarbon reservoir The present invention relates to modifying the characteristics of carbonate reservoirs that produce oil/or gas. specifically, described herein is a method of treating an underground reservoir comprising a carbonate-containing substrate, a composition for treating an underground hydrocarbon reservoir comprising a carbonate-containing substrate, a sample taken from an underground hydrocarbon reservoir comprising a carbonate-containing substrate, and the treatment composition, and an underground hydrocarbon reservoir comprising a carbonate-containing substrate and the treatment composition.

Description

Field of Invention

[001] The present invention relates to the modification of the characteristics of an oil and/or gas producing carbonate reservoir.

Background of the Invention

[002] Reference to any prior art in this report is not and should not be considered a confirmation or any form of suggestion that this prior art forms part of common general knowledge in Australia or any other jurisdiction or that this prior art could be reasonably determined, understood and considered relevant by a person skilled in the art.

[003] There is a need to modify the characteristics of reservoirs that produce oil and/or gas to provide a more favorable production environment. Changing the characteristics of a reservoir can intensify oil and/or gas production or ameliorate the problems with water production that arise as a result of oil and/or gas extraction.

[004] It is known that the internal environment of a reservoir can be changed through the inclusion of compositions that comprise surface modifying agents such as macromolecules / organic polymers. These can be used to alter the physical properties of the inner reservoir environment. One of the main considerations is the anchoring or bonding of the macromolecule/organic polymer to a surface within the reservoir. In many cases, the macromolecule/organic polymer is an organosilicon compound.

[005] It is known that organosilicon compounds bind strongly to silicate surfaces. This makes their use particularly well suited to reservoirs comprising a large silicate component such as clay, feldspar, sandstone, or other silicate mineral surfaces. US patent publication 2007/0039732 (to Dawson et al.) and US patent publication 2011/0114314 (to Wang et al.) discuss the use of macromolecule compositions that can comprise organosilicon compounds for hydrocarbon recovery in a reservoir.

[006] The patent publication US 2007/0039732 is directed to the provision of a method for the enhanced recovery of hydrocarbons from an underground formation using a relative permeability modifier (RPM) which can be a macromolecule or microgel. In this method, an aqueous composition comprising the RPM is introduced into an injector well. The RPM is expected to be adsorbed within the well, thus improving hydrocarbon extraction by preventing water production or limiting water movement through permeable reservoir formation materials. This document discloses that the RPM can be an organosilicon compound, as these compounds further provide binding to silicate-containing substrate material including quartz, clay, chert, shale, silt, zeolite or combinations thereof.

[007] The patent publication US 2011/0114314 is directed towards providing a method for reducing the flow of unwanted water in an underground reservoir. This is achieved by gelling and/or polymerizing a soluble silicate with an activator and a hydrolyzable organosilane compound, such as thereby forming a network of silanols. Silanols react with the siliceous surfaces in the rock to covalently bond the network to the formation surfaces. Silanols also interact with sodium silicate, and bind them to each other and to the surfaces of the underground formation. This results in the formation of a gel layer. That is, the sodium silicate and silanols effectively form a buffer to stop or reduce the flow of water through the underground formation. As with US 2007/0039732, the application of this method is limited to silicate-containing formations.

[008] The prior art is directed to methods of improving the production of hydrocarbons in underground formation, in which the formation is primarily siliceous through the use of molecules that include organosilanes. However, the application of organosilicon is generally restricted to reservoirs comprising siliceous surfaces. In view of the above, it is evident that there is a need to develop a mechanism to modify the characteristics of a reservoir that is not siliceous in nature.

[009] It is an object of the invention to improve at least some of the aforementioned problems.

[010] As used herein, except where the context requires otherwise, the term "comprise" and variations of the term such as "comprising", "comprises" and "understood" are not intended to exclude other additives, components, numbers integers or steps.

Invention Summary

[011] It is desirable to develop a means to improve the production of hydrocarbons in the carbonaceous reservoir (ie containing carbonate). Thus, the present invention is directed to providing a method of treating an underground hydrocarbon reservoir comprising a carbonate-containing substrate. Broadly, the method comprises the step of adding an amount of a silicate or silicate-containing molecule to the reservoir to chemically interact with a carbonate surface of the carbonate-containing substrate within the reservoir.

[012] In one aspect of the invention, there is provided a method of treating an underground hydrocarbon reservoir comprising a carbonate-containing substrate, the method comprising: adding an amount of a silicate or a silicate-containing molecule to the reservoir to chemically interact with a carbonate surface of the carbonate-containing substrate; wherein silicate is added to the reservoir at a concentration greater than 0% and up to 8% by weight/volume.

[013] In another aspect of the invention, a sample made from an underground hydrocarbon reservoir is provided, the sample comprising: a carbonate-containing substrate that has a silicate layer or a silicate-containing molecule that has chemically interacted with at least one portion of a surface of the carbonate-containing substrate.

[014] The presence of a silicate in the base surface layer is evidenced by the silica concentration being higher on the substrate surface compared to the silica concentration of the sample volume.

[015] Silicate can be determined using any suitable technique available to one skilled in the art, including spectroscopic and X-ray techniques (eg, FTIR, Raman, UV/Vis, transmission electron microscopy or energy dispersive spectrometry display ).

[016] It is preferred that the sample provides an indication that the surface silica concentrations in the sample are greater than the silica concentration in the bulky sample by a weight ratio of at least 2:1. More preferably, the weight ratio of silica in the sample is to silica in the bulky sample in a weight ratio of at least 5:1. Even more preferably the weight ratio of silica in the sample is to silica in the bulky sample in a weight ratio of at least 10:1. It is expected that the % by weight of silica in the surface layer is determined by the electron microprobe (EPMA). Bulk composition is also preferably determined by EPMA, with the bulk sample prepared by initial micronization of the sample to obtain a homogeneous representation of the sample volume. The electron microprobe focus beam should be as large as applicable (eg, at least about 10 microns in diameter) to avoid localized compositional variations. Preferably, the silica concentration is based on the three microprobe measurements of each of substrate surface and substrate volume.

[017] In another aspect of the invention, an underground hydrocarbon reservoir is provided comprising: a carbonate-containing substrate that has been treated and has a silicate layer or a silicate-containing molecule chemically interacted with at least a portion of a surface of the carbonate-containing substrate .

[018] In another aspect of the invention, there is provided a composition for treating the underground hydrocarbon reservoir comprising a carbonate-containing substrate, the composition comprising: an amount of a silicate or a silicate-containing molecule to chemically interact with a carbonate surface of the substrate containing carbonate; an amount of an organosilicon compound; wherein the silicate or silicate-containing material can be chemically reacted with the organosilicon compound.

[019] Silicates can be selected from any silicate-containing molecule. The term 'silicate' is used in its broadest sense to refer to any compound containing an anion that carries silicon. Preferably, the silicate is a silicon-oxygen containing anion, i.e., a Si-O anion, i.e., an anion including a silicon atom having at least one bond to an oxygen atom (i.e., having at least one bond of Si-O). Suitable silicate anions may include those of the type: [SiO4]4-, [Si2O7]6-, [SinO3n]2n-, [Si4nO11n]6n-([Si2nO5n]2n- or [AlxSiyO2(x+y)]x- More preferably the silicates are alkali metal silicates More preferably the silicate is sodium silicate or potassium silicate.

[020] Silicate can be added to the reservoir at a silicate concentration, calculated as silica, greater than 0% and up to 8% by weight/volume. It is preferred that this silicate is added to the reservoir at a concentration greater than 0.1% and up to 5% by weight/volume (calculated as silica). More preferably, silicate is added to the reservoir at a concentration greater than 0.2% and up to 4% weight/volume (calculated as silica). Even more preferably, silicate is added to the reservoir at a concentration greater than 0.3% and up to 3% by weight/volume (calculated as silica). Even more preferably, silicate is added to the reservoir at a concentration greater than 0.5% and up to 2% by weight/volume (calculated as silica).

[021] The amount of silicate added to the system is given in terms of silica fraction in weight/volume. This is because most commercial silicates quote concentration in terms of a silica concentration. Although the concentration is given in terms of the concentration to be added to the reservoir, it is preferred that the concentration of silicate (as silica) in the aqueous phase within the reservoir after addition is greater than 0% and up to 8% by weight/ volume. More preferably, silicate (such as silica) is added so that the concentration of the aqueous phase within the reservoir is greater than 0.1% and up to 5% by weight/volume. More preferably, the concentration of silicate (as silica) in the aqueous phase within the reservoir is greater than 0.2% and up to 4% by weight/volume. Even more preferably, the concentration of silicate (as silica) in the aqueous phase within the reservoir is greater than 0.3% and up to 3% by weight/volume. Even more preferably, the concentration of silicate (as silica) in the aqueous phase within the reservoir is greater than 0.5% and up to 2% by weight/volume.

[022] In a preferred embodiment, the method further comprises adding an organosilicon compound, such as an organosilane. The organosilicon compound chemically bonds with the silicate material. Together, the silicate and organosilicon compound form a siliceous layer on the surface of the carbonate substrate. Preferably, the organosilicon compound is added to the reservoir at a concentration greater than 0 and less than 1.0 mol/L. More preferably, the organosilicon compound is added to the reservoir at a concentration of between 0.05 and 0.2 mol/L. As above, it is preferred that the concentration of organosilicon compound in the aqueous phase within the reservoir is less than 1.0 mol/L. More preferably, the organosilicon compound is present in the aqueous phase within the reservoir at a concentration of between 0.05 and 0.2 mol/L. In an alternative embodiment, the silicate can be reacted with the organosilicon compound before being added to the underground hydrocarbon reservoir. It is preferred that the silicate and the organosilicon compound together provide a means to alter the surface characteristics within the underground hydrocarbon reservoir.

[023] In another aspect of the invention, the organosilicon compound includes a functional group that allows a surface modifying agent (for example, an organic polymer or macromolecule, excluding an organosilicon compound) to covalently bond the organosilicon compound through a suitable functional group on the organosilicon compound.

[024] The surface modifying agent can be added to the reservoir or pre-reacted with the organosilicon compound. The surface modifying agent can, for example, be a polymer. The surface modifying agent is expected to covalently bond with the organosilicon via an active group (or a linking group) on the surface modifying agent. This active group (or linking group) on the surface modifying agent is expected to covalently interact with a functional group on the organosilicon compound. Preferably, there is sufficient surface modifying agent in the system so that at least 70% of the organosilicon compound interacts with the surface modifying agent. More preferably, the surface modifying agent is added such that the ratio of active groups in the surface modifying agent to organosilicon is from 1:1.5 to 1:5. Even more preferably the ratio of active groups on the surface modifying agent to organosilicon is from 1:1.5 to 1:3.

[025] The net result of the surface modifying agent is to functionalize the surface of the carbonate reservoir for the purpose of stimulating the reservoir for purposes including: enhanced oil recovery, permeability modification (full fluid sealing and relative permeability modification) , fracturing and acid shift. The surface modifying agent is preferably selected from polymers, including macromolecules, and the selection must be combined with the R group of the organosilane to ensure that the surface modifying agent can chemically bond to the organosilane. The selection of suitable combinations of organosilane and surface modifying agent to ensure that a stable chemical bond is formed will be clear to the person skilled in the art. Within the R group may be the non-hydrolyzable organic radical(s) which has a functionality that imparts desired characteristics. This includes: alkyl, alkenyl, aryl, allyl, halogens, amines, sulfur functional groups, hydroxyl, aldehyde, epoxy, nitrobenzamide, cyano, pyridyl, azide, ester, isocyanate, phosphine, phosphate. For example, if the R group on the organosilane is an epoxy group then surface modifying agents containing the following functionality are suitable: urethanes, acrylics, polysulfides. If the R group on the organosilane is an amine then surface modifying agents containing the following functionality are suitable: acrylic, urethane, melamines, epoxy, N-hydroxysuccinimide (NHS) esters and hydroxylmethylacrylamide. NHS and hydroxylmethylacrylamide esters containing surface modifying agents can be prepared from polyacrylamide, polyacrylamide copolymers including hydrolyzed polyacrylamide or polyacrylamide-co-acrylic acid, polyacrylamide-co-acrylic acid partial sodium salt, poly(acrylic acid-co) acid -maleic acid), cationic polyacrylamides, anionic polyacrylamides and amphoteric polyacrylamides.

[026] Other aspects of the present invention and other embodiments of the aspects described in the preceding paragraphs will become apparent from the following description, given by way of example and with reference to the accompanying drawings.

[027] The recitation of ranges of values here is merely intended to serve as an abbreviated method of individual reference to each separate value and each potential range covered, unless otherwise recited. In addition, each separate value and each potential range is incorporated into the descriptive report as if it were individually recited here.

Brief Description of Drawings

[028] Figure 1 provides an illustration of the interaction between the organosilane, the silicate and a surface of a calcium carbonate substrate.

[029] Figure 2 is a graph showing the differential pressure across the carbonate core during saline injection after treatment with the adsorption system, the differential pressure stabilizes showing a 560 times reduction in permeability through the core compared with the pre-adsorption treatment. Conditions: 100% water saturation, 3500 psi (24131.65 kPa) confinement voltage, 500 psi (3447.38 kPa) back pressure, and 105°C temperature.

[030] Figure 3 provides an illustration of a mechanism for the adsorption system (with polymer) in the presence of saline solution and in the presence of oil.

[031] Figure 4 shows the carbon spectra with high resolution collected using XPS that shows the CO groups for the sample containing epoxy at 287eV (solid line) versus the carbonate control where the CO groups are not present without the adsorption system (dotted line).

Detailed Description of Modalities

[032] Described herein is a method of treating an underground hydrocarbon reservoir comprising a carbonate-containing substrate, the method comprising the step of adding an amount of a silicate to chemically interact with the carbonate surface. Without wishing to be bound by theory, silicates are believed to react with partially dissolved cations on a surface of a carbonate substrate. This interaction results in the adsorption of silicate to the surface of the carbonate-containing substrate. Silicates can also interact with each other to form a layer of silica on the carbonate surface. This method is intended to provide a generic means for modifying a carbonate-containing surface in an underground hydrocarbon reservoir.

[033] Silicate can be added so that the resulting concentration of silicate, calculated as silica, in the reservoir is at a concentration of greater than 0% and up to 8% by weight/volume. It is preferred that this silicate is added to the reservoir so that the resulting concentration of silicate, when calculated as silica, is greater than 0.1% and up to 5% by weight/volume. More preferably, silicate is added to the reservoir so that the resulting concentration, when calculated as silica, is greater than 0.2% and up to 4% weight/volume. Even more preferably, silicate is added to the reservoir so that the resulting concentration, when calculated as silica, is greater than 0.3% and up to 3% by weight/volume. Even more preferably, silicate is added to the reservoir so that the resulting concentration, when calculated as silica, is greater than 0.5% and up to 2% by weight/volume. The reservoir volume is the total aqueous volume (ie, the void volume) of the reservoir; that is, the volume of the reservoir occupied by the aqueous phase.

[034] The term 'carbonate' is used in its broadest sense to refer to any mineral, rock or compound that comprises a carbonate anion (CO32-). Preferably, the carbonates are calcium-containing carbonates, magnesium-containing carbonates or mixtures of both. Preferably, the rock is a carbonate rock such as: limestone and/or dolomite. Preferably, carbonate minerals include: dolomite, calcite, vaterite, aragonite, ikaite, monohydrocalcite, magnesite and/or landsfordite.

[035] The carbonate substrate preferably comprises a carbonate component of at least 5% by weight, more preferably at least 10% by weight, even more preferably at least 30% by weight and most preferably at least 50% by weight.

[036] The term "surface modifying agent" for the purposes of the present invention means an organic polymer or macromolecule, excluding organosilicon compounds, which once adsorbed by the surface of the reservoir will modify the physiochemical characteristics of the surface.

[037] Further described here is a method for chemically bonding a target material to the surface of a carbonate substrate by altering the wettability of that surface. A multi-component system can be used that chemically bonds to the surface of carbonates while providing functionality for the surface modification bond. The silicate and organosilicon molecules are combined that chemically interact with the carbonate surface and provide a siliceous layer where other target molecules can be bonded. This approach can be used to anchor target molecules such as water-soluble polymers or macromolecules to the surface of the carbonate substrate. Thus, this method provides a means for attaching organosilicon molecules to a surface of a carbonate-containing substrate by means of a silicate intermediate.

[038] The term 'organosilicon' is used in its broadest sense to refer to organic compounds containing carbon-silicon bonds and hydrolyzable groups (ie, a hydrolyzable organosilicon compound). Preferably, the hydrolyzable organosilicon compound is a hydrolyzable organosilane. The organosilane compound can be selected from the group consisting of water soluble organosilane compounds and organosilane compounds which hydrolyze in aqueous media to form water soluble silanols. More preferably, the organosilicon compound is an alkoxy silane or an amino organosilane. Other suitable compounds, which can be used as the hydrolyzable organosilicon compound in embodiments of the present invention, will be apparent to those skilled in the art and should be considered within the scope of the present invention. Among the organosilicon compounds suitable for use in this invention are organosilanes having the formula:

[039] X is a hydrolyzable group typically alkoxy, acyloxy, halogen or amine where n can be 1 to 4, but preferably is from 1 to 3. The group R is a non-hydrolyzable organic radical that has a functionality that imparts desired characteristics and includes: alkyl, alkenyl, aryl, allyl, halogens, amines, sulfur functional groups, hydroxyl, aldehyde, epoxy, nitrobenzamide, cyano, pyridyl, azide, ester, isocyanate, phosphine and phosphate, as well as multifunctional and organosilanes linked to polymers where the organosilane can further form a network with the silicate (eg organosilane modified polyethyleneimine).

[040] Suitable hydrolyzable compounds of organosilane that can be used in the present invention may include monomers, hydrolysed monomers, hydrolyzed and oligomers dimers hydrolysates trialcoxiorganossilano, aminopropiltrialcoxissilano, aminoetilaminopropiltrialcoxissilano, alquiltrialcoxissilano, viniltrialcoxissilano, feniltrialcoxissilano, mercaptotrialcoxissilano, stirilaminotrialcoxissilano, metacriloxipropiltrialcoxissilano, glicidoxipropiltrialcoxissilano, perfluorotrialcoxissilano , perfluoroether functionalized trialkoxysilane, azole functional trialkoxysilane, tetraalkoxysilane or combinations thereof. In a preferred embodiment, the hydrolyzable group on the organosilicon compound is an amine group.

[041] Specific examples of organosilanes suitable examples include: aminopropiltrietioxissilano, metildietilclorossilano, dimethyldichlorosilane, methyltrichlorosilane, dimetildibromossilano, dietildi-iodossilano, dipropildiclorossilano, dipropildibromossilano, butiltriclorossilano, feniltribromossilano, difenildiclorossilano, toliltribromossilano, metilfenildiclorossilano, metildietilclorossilano, dimethyldichlorosilane, methyltrichlorosilane, dimetildibromossilano , diethyldiiodosilane, dipropyldichlorosilane, dipropyldibromosilane, butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane, tolyltribromosilane, methylphenyldichlorosilane and the like. Preferably the organosilane is aminopropyltriethoxysilane (APTS).

[042] An advantage of the method of the present invention is that the combination of silicate and organosilicon molecules allows strong interaction with carbonate surface, unlike traditional approaches which only provide weak temporary interactions. The addition of silicate in combination with silane provides strong carbonate bonding. Existing methods do not include silicate which is essential to the operation of this method.

[043] In one embodiment, silicate is added to the reservoir and any other components such as an organosilicon compound or a polymer or other additives are bonded after the silicate has been added. In another embodiment, organosilicon is added to a silicate solution before being added to the underground hydrocarbon reservoir.

[044] The amount of each component that needs to be added to a reservoir is reservoir dependent and is preferably dependent on data such as permeability, porosity and pore volumes, hydrocarbon production, proportion of reservoir requiring treatment or other physical parameters , chemical or operational such as the composition of the fluid.

[045] In an embodiment of the invention, computational modeling is used to determine the amount of silicate that needs to be added to the reservoir. Computational modeling can also be used to determine the amounts of organosilicon, polymer or other additives to be added to the reservoir. In other respects, computational modeling data is based on information including permeability, porosity and pore volumes, hydrocarbon production, proportion of reservoir requiring treatment, reservoir size or volume, or other physical, chemical or operational parameters.

[046] In an alternative modality, the approach of determining the quantity of each component to be added to the reservoir can be empirical such that 1/2 to 1 production volume per day is added or specific volume per foot or payment volume to achieve right radius of the well. This information can, for example, be obtained from reservoir logging tools and sampling data.

[047] The concentration of organosilicon compound is preferably added to the reservoir at a concentration of less than 1mol/L. More preferably, the organosilicon compound is added at a concentration of between 0.05 - 0.2 mol/L. it is also preferred that the concentration of organosilicon in the reservoir is less than 1 mol/L. More preferably, the concentration of organosilicon compound in the reservoir is 0:05 - 0.2 mol/L; wherein the reservoir volume is in terms of the total aqueous volume (i.e., void volume) of the reservoir; that is, the volume of the reservoir occupied by the aqueous.

[048] Upon adding the surface modifying agent to the system, the surface modifying agent reacts with the reaction groups on the organosilicon molecule. The surface modifying agent can be activated to make it more reactive with the reaction groups on the organosilicon compound. In a preferred embodiment, the surface modifying agent reacts with amine groups on an organosilane molecule.

[049] Preferably, there is sufficient surface modifying agent in the system so that at least 70% of the silane interacts with the surface modifying agent. That is, for every 1 mole of organosilicon there are 0.7 mole of active groups on the surface modifier. More preferably, the ratio of active groups in the surface modifying agent to organosilicon is from 1:1.5 to 1:5. Even more preferably, the ratio of active groups in the surface modifying agent to silane is from 1:1.5 to 1:3.

[050] The maximum concentration of the surface modifying agent needs to be low enough so that the rheology of the solution is still workable, that is, it is not so viscous to pump or preferably autogel. It is preferred that the surface modifying agent is added to the reservoir in a 1 to 20% w/v solution of the surface modifying agent. However, this depends on the molecular weight of the surface modifying agent and the degree of activation of the surface modifying agent.

[051] The silicate is essential for the interaction with the cations on the surface of the carbonate substrate. Organosilicon binds to silicate and can provide exposed functionality to allow attachment of other surface modifier(s) if desired. It is preferred that the silicate cocondenses with the organosilicon. Silicate, organosilicon and other additives (such as an additional surface modifying agent) can be distributed in aqueous solution either sequentially or in combination. The additional surface modifying agent may be a water-soluble polymer(s) or other organic macromolecule(s). the means of attachment can be through covalent bonding. The functionality of organosilicon can be selected in consideration of the application for which it is intended or the nature of the intended surface modifier.

[052] This approach has broad applications achieved in the underground carbonate reservoir that produces oil and gas as it provides a method to chemically bond to the surface thus providing a long-term effect.

[053] Figure 1 shows the interaction between silicate, composed of organosilicon and the surface of a calcium carbonate substrate. In particular, Figure 1 shows the interaction between a calcium carbonate substrate (101) and an organosilicon compound (102) by means of a free silicate ion compound (103), i.e. a sodium silicate solution which interacts with the surface of the calcium carbonate substrate (101) via partially dissolved calcium ions (104) on the surface of the substrate (101). The organosilicon compound (102) in this case is an aminosilane.

[054] This arrangement shown in Figure 1 overcomes the problem that without the inclusion of a silicate, silanes do not readily react with a carbonate surface (101). The dissolved surface calcium ion atoms (104) react with the free silicate ions (103) in the solution. The dissolved surface calcium ions (104) form an ionic bond (105) with the silicate ions (103) and also form an ionic bond (107) with the surface of the carbonate substrate (101). The free silicate ions (103) coagulate with each other and with the aminosilane (102) to form a siliceous layer on the surface of the calcium carbonate substrate (101).

[055] The amino silane molecule (102) undergoes a condensation reaction that forms a bond (107) between the amino silane molecule (102) and the free silicate ion (103). The amino group on the silane (102) can be used to covalently attach (108) an additional surface modifying agent (not shown) such as a polymer.

[056] The methods described here are broad in application and are intended to be applicable where surface modifying agents are provided for underground hydrocarbon reservoirs comprising carbonate substrates for purposes including: enhanced oil recovery, surface modification, modification permeability (full sealing and relative permeability modification), fracturing and acid drift.

[057] Unless otherwise stated, reference to a polymer or macromolecule shall be taken as reference to a surface modifying agent.

[058] It will be understood that the invention described and defined in this specification extends to all alternative combinations of two or more of the individual features mentioned or evident from the text or drawings. All these different combinations constitute the various alternative aspects of the invention.

Examples Example 1 - Calcium Carbonate Model Test

[059] In order to determine the surface adsorption of carbonates, precisely weighed samples of calcium carbonate powder were exposed to direct the surface modifying agent that binds to the surface and, after extensive washing, the samples were reweighed and increased. gravimetrics are indicative of adsorption. For example, a known quantity of carbonate powders is weighed (~2.5 g, surface area ~37m2/g) and dispersed in water (10 mL). Various components of a treatment are added according to the relevant treatment procedure, typically silicate (0.68g of a 28 % by weight sodium silicate) diluted in 8.9 ml of water, followed by amine source (aminopropyltriethoxy silane , 0.5 ml). The solution is left for 12 hours and then the powder is washed by repeated centrifugation and decant supernatant with water so that the total dilution factor is at least 106, i.e. a maximum of 1 part per million of the original solute remains. The sample is then dried in vacuo to constant weight. The dry sample is weighed and any change in weight is calculated. The carbonate samples were pre-treated to provide samples with different wettability profiles (wettable with water, wettable with oil and mixed). In order to prepare these samples, they were exposed to water and/or mineral water and turpentine before the adsorption test.

[060] A silicate-based system consisting of sodium silicate and a functionalized silane (in particular aminopropyltriethoxysilane, APTS) exhibited good adsorption to the carbonate material (table 1). Sodium silicate is an essential component as APTS alone did not provide sufficient adsorption. It is widely accepted that silane molecules alone do not strongly interact with carbonate substrates as the silane cannot form a strong bond with the surface.

[061] The method described above was used to successively identify functionality based on inorganic silicate that exhibited good adsorption (>4%) relative to the model reservoir material mentioned above (Table 1, entry 1). This is a potential method to provide strong adsorption to the carbonate pool that would represent a significant advance. Many reservoirs are typically neutral to oil wettable, so screening experiments were performed with calcium carbonate that was exposed to an oil phase prior to adsorption studies. Therefore, the adsorption system was tested on a water-wettable calcium carbonate sample (table 1, sample 1) and a calcium carbonate sample that was exposed to oil (table 1, sample 2) - everything else is the even between sample 1 and 2. The amount of material adsorbed was determined gravimetrically and both samples gave the same absorption (4.1%) which shows that in this case wetting did not have a good effect. Table 1: Experimental values for adsorption screening using calcium carbonate as a model material. Samples exposed to oil before the adsorption test are bold. Silicate-based adsorption system is adsorbed onto a water-wettable sample (1) and an oil-wettable sample (2). The silicate-based adsorption system provides the adsorption sites for a polymeric material to chemically bond to the samples (ie, samples 3 and 4, which represent the water-wettable and oil-wettable systems, respectively).

[062] Table 1 shows the values for an adsorption screening test using calcium carbonate as a model material: Sample 1 shows the percent mass gain for a fully wetted system, that is, the silicate adsorption-based system adsorbs onto the water-wettable sample. Sample 2 shows the percent mass gain for a wetted mixed system, which in this case is an oil wettable sample. Samples 3 and 4 (corresponding to the water-wettable and oil-wettable systems, respectively) report the percent mass gain where the adsorption sites of the silicate-based adsorption system are exposed to chemical bonding of a polymeric type material.

[063] Essentially there are three interfaces to consider 1) the adsorption functionality of the carbonate to silicate substrate; 2) target silicate adsorption functionality groups (i.e. polymer); and 3) polymer to polymer in the case where the layers are to be constructed.

[064] Silicate adsorption-based system (ie APTS) is able to bond to the calcium carbonate surface (interface number 1) based on the observations in Table 1. The surface modifying agent consisting of an ester of hydrolyzed polyacrylamide N-hydroxysuccinimide (polyacrylamide-co-acrylic acid partial sodium salt, Mw 520,000, Mn 150,000, typical acrylamide level 80%) was then tested and found to be able to bind to the adsorption system (interface number 2) by reacting with the amine group of the APTS (table 2, entries 3 and 4). Interestingly, when this was attempted, greater mass gains were observed than with just the adsorption system which can be attributed to the fact that surface modifying agents were designed to covalently bond to the surface (7.8% and 6. 3% with the surface modifier versus 4.1% without). Control experiments with the surface modifying agent that were unable to bind to the adsorption system did not show any increased adsorption. In addition, it is worth noting that the surface modifying agent alone did not show any adsorption to the carbonate model and no weight gain was observed.

[065] In cases where surface modifying agents were included, the wettability effect of calcium carbonate did not have the effect on gravimetric absorption. For example, when a water-wettable calcium carbonate system was used with the adsorption system and a surface modifier, a gravimetric absorption of 7.8% was observed (Table 1, Sample 3). When a petroleum-wettable calcium carbonate was used with the exact same system, the absorption decreased to 6.3% under the same conditions (Table 1, Sample 4). The conclusion here is that wettability has an effect on adsorption - for oil-wettable samples, adsorption is lower. However, it is worth noting that despite the decrease in adsorption for a sample wettable with calcium carbonate oil, adsorption is not completely compromised and still offers a viable adsorption approach that is believed to be due to strong chemical bonding (ie. , chemosorption).

Example 2 - Test on a sample from a carbonate reservoir

[066] These data (Table 2) were performed on a real sample from a carbonate reservoir in the Middle East which was ground into a fine powder. The adsorption system was tested at room temperature (samples 1 and 2), and 90°C (samples 3 and 4). Table 2: Experimental values for screening by gravimetric adsorption at room temperature and 90°C using a carbonate core sample ground from an oil reservoir as a model material.

[067] As can be seen, when the carbonate core sample was subjected to the washing sequence described above at both room temperature (sample 1), and 90°C (sample 3), the sample actually lost weight and quantity. lost increased at higher temperatures. Washing should be expected to remove any residual contaminants from the samples. When the silicate adsorption system was investigated each sample gained weight even after extensive washing: at room temperature (sample 2) the sample gained 6.8% in weight and at 90°C (sample 4) the sample gained 11.2% by weight. This is indicative that the adsorption system works effectively with the current reservoir sample at room temperature and elevated temperature.

Example 3 - Silicate/Silane System Surface Studies

[068] The numbers given in examples 1 and 2 were obtained using a gravimetric technique that was supplemented using X-ray photoelectron spectroscopy (XPS) which is an advanced surface characterization technique (Table 3) that uses X-rays to eject electrons of the orbit of the inner shell of elements on a surface that provides information regarding surface chemistry.

[069] In carbonate reservoirs composed mainly of dolomite (which is based on calcium and magnesium carbonate CaMg(CO3)2) and, as can be clearly seen from the results in table 3 (entry 1), the surface is predominantly based on these elements as measured by XPS. Following this observation, the chemical adsorption system was tested and the experiments were carried out with silicate and silane (entry 2, table 3) as highlighted in example 2.

[070] Table 3: Survey data measured by XPS (atomic percentage, %). Mean values (± deviation) are listed.

[071] If silicon levels are considered in the samples that were exposed to the adsorption system, there is a dramatic increase from 0% for the control (reservoir material only) to 16%. This can be attributed to the incorporation of silicon on the surface. Further evidence is provided by the 0 to 6% increase in nitrogen that can be attributed to the silane's amine groups. Importantly, calcium and magnesium levels decreased substantially (33 to 27% for calcium and 5.7 to 0.9%). This is indicative of the chemical mechanism proposed in Figure 1, as the silicate is interacting with calcium and magnesium.

Example 4 - Control System with no Silicate

[072] Another test using silane only (no silicate) was also performed on the milled reservoir samples and the silane only system did not work in the gravimetric screening as shown in table 4 (input 1 and 4 had no silicate present and absorption is negative ). It is clear from these data that when silane is used without silicate there is no increase in gravimetric adsorption.

[073] Silicate, on the other hand, is known to react with calcium and magnesium ions and on the surface of the reservoir sample, there are preferably partially dissolved surface calcium atoms that can react with free silicate ions in the solution. Silicate ions coagulate with each other and with the aminosilane to form a layer of silica (Figure 1). Table 4: Gravimetric adsorption for silane-only systems (data collected at 90°C).

[074] Silane-only systems were also investigated using XPS and this data is shown in table 5. Table 5: Survey data measured by XPS (atomic percent, %) for silane-only systems. Listed are the mean values (± deviation).

[075] As can be seen when only silane is used in the adsorption tests, the amount of silicon increases (zero to 1.3%) compared to the control sample (carbonate core only), but the amount of silicon is low (1.3%) and if the present order is compared to the silicate sample, the amount is much smaller (1% for silane only, 16% with silicate). In conclusion, the level of silicon on the surface is much lower, but small amounts of silane are retained on the surface, but it is not predicted to chemically bond to the surface as evidenced by the gravimetric adsorption tests (table 4). In addition, if the levels of calcium and magnesium in the silane-only sample are considered (Table 5, entry 1), the calcium decreases only slightly (from 10.8% for the 9.1% carbonate) and the magnesium does not decrease . These are essentially the chemical loops in the reservoir where a material can bind so if these levels are not going down this shows that the silane is not binding strongly. In contrast, samples containing silicate demonstrated dramatic decreases in calcium and magnesium unlike silane only samples and silicate is known to react with calcium and magnesium while silane alone cannot react. Example 5 - Different Silane Molecules Table 6: Analysis of the XPS surface of the carbonate rock (control) and epoxy-terminated silane molecule included in the adsorption system and amine-terminated silane.

[076] Aminopropyltriethoxylsilane (APTS) thus has been used so far, so for this set of experiments the tests were repeated using an epoxy-terminated silane. APTS was included in this sample set as the carbonate sample was different. Successful incorporation was confirmed as the percentage of silicon increased due to the adsorption system (Table 6) and calcium and magnesium decreased. Nitrogen increased when APTS was included due to amine groups. In the case of the epoxy-terminated silane (which incorporates carbon and oxygen), the oxygen did increase, but this could be in part due to the substantial increase in silicon masking the increase in oxygen. Interestingly the binding energies (figure 4) determined using XPS the presence of C-0 bonds (at 286eV, figure 4, solid line) that were present from epoxy groups that were not present in the original carbonate rock (absence of peak at 286eV, figure 4, dotted line).

Example 6 - Injection of the core with the Adsorption System at 100% water saturation

[077] Core injection tests were performed that simulate the conditions found in underground reservoirs using the adsorption system to determine effectiveness. The system tested includes a polymer molecule that is bonded to the carbonate using the adsorption system. These tests establish: the standard permeability of the core to saline (and oil in the case of mixed wettability); can establish the wettability of the complex surface in the representative core of the reservoir; the ability to place the adsorption system under reservoir conditions; the effect of the adsorption system on the permeability to saline (and oil) solution (before and after treatment). This example was run at 100% water saturation to determine the ability of the adsorption system to operate at 100% water saturation. Example 7 includes other investigations that were carried out with systems with mixed wettability (oil and water present).

[078] The permeability and porosity of the sample were measured using an instrument for measuring the permeability and porosity of automated helium under effective liquid pressure in situ, the data are shown in table 7. These data are used to calculate the treatment volumes based on pore volume. Table 7: Porosity and permeability of cylindrical carbonate rock sample under liquid effective pressure in situ complete

[079] Thereafter, the cylindrical carbonate core sample from an underground reservoir was loaded into a core injection instrument and the outer surface was pressurized to simulate the loads encountered in a reservoir (overhead pressure, 3500 psi (24131, 65 kPa), 500 psi (3447.38 kPa) back pressure, at 105°C).

[080] Subsequently, prolonged saline injection was performed at different flow rates to determine the standard permeability of the core sample, the saline composition is shown in table 8. Table 8: Saline composition

[081] Table 9 presents the results of the saline injections step and shows the measured differential pressure over the sample for each flow rate after reaching steady state conditions (ie, stable and constant differential pressure over the sample), this can be used to calculate the actual core permeability using Darcy's law. Table 9: Differential pressure over the cylindrical carbonate rock sample at various flow rates used to calculate permeability to saline solution (prior to treatment with the adsorption system)

[082] The rock is then treated with the adsorption system including a surface modifying agent which is a water-soluble polymer capable of binding to the adsorption system. A 4% (w/v) aqueous polymer solution of polyacrylamide-co-acrylic acid (PAM-co-AA) Mw 520,000, Mn 150,000 (Typical), acrylamide ~80% by weight was prepared. 0.275 g of a formaldehyde solution (37% solution) was added to 20.5 g of the 4% polymer solution (solution A), this gives the polymer reactive to the amine groups found in the amino-terminated silane. A separate solution was prepared using 7.15 g of sodium silicate solution (26.5% silicate), 92 ml of water, and 5.25 ml of 3-aminopropyl triethoxysilane (APTS) were prepared (solution B). Solution A was then added to solution B, the total volume is approximately 125 ml. The treatment was added using an exchange piston and 3.7 times the pore volume (Table 7) of the core was successively injected into the core sample. The differential pressure over the sample was >2000 psi (13789.51 kPa) which is extremely high for a polymer injection which is indicative of adsorption to the rock surface, the pressure rapidly increased as the adsorption system passed over the carbonate rock face. Before the adsorption system reached the rock face, an injection rate of 60cc h was followed, but was subsequently reduced to 2-3 cc/h due to strong adsorption causing high differential pressure over the sample.

[083] After injection, the sample was locked with no fluid flow for 24 hours, after which the residual adsorption system (in pore space) was removed by saline injection and after the pressure through the core had stabilized, the permeability to the saline solution was measured again and considered 560 times (determined as p point where the differential pressure on the rock is stable). Figure 2 shows the differential pressure over the carbonate core after treatment with the adsorption system and can be divided into three different parts: a) an initial stage during which the saline solution is pushed through the core to break the system. adsorption; b) an intermediate stage during which the saline solution broke the outer face of the sample after which, as the saline solution penetrates the pore space, the differential pressure would begin to decrease; and c) Since the saline solution continues to flow through the pore space, the differential pressure over the sample begins to decrease, but eventually stabilizes as the adsorption system (including polymer) inhibits the saline solution flow. This final stabilized differential pressure across the core demonstrates a 560-fold reduction in permeability across the core compared to the pre-adsorption treatment (Table 9). In addition, this effect was maintained for >140 pore volumes which provides strong evidence for effective adsorption, without surface adsorption the water-soluble adsorption system would be washed with saline. This demonstrates that the approach works under reservoir conditions.

Example 7-Injection into the Core as an Adsorption System under mixed wettability conditions

[084] The permeability and porosity of a carbonate core sample was measured using an automated helium permeability and porosity measuring instrument under effective liquid in situ pressure, the data are shown in table 10. These data are used to calculate the treatment volumes based on pore volume. This experiment was directed to testing the adsorption system in water saturation with residual oil so the carbonate core sample is exposed to both saline and petroleum (ARAB D crude oil, API gravity = 28.80, Density = 0, 8820) before treatment with the adsorption system. Therefore, the permeability of the rock to saline and petroleum solution is determined by draining the saline and petroleum solution separately through the sample to provide a standard permeability (calculated using Darcy's law). Table 10: Porosity (expressed as %) and permeability (mD is milli-Darcy) for carbonate core sample under complete liquid effective pressure in situ.

[085] After loading the sample into the core injection, the following sequence was performed on the sample: a) Measurement of in situ permeability in the pre-treatment for saline solution through saline injection with multiple rates. b) Injection of cyclic petroleum-saline solution in the pre-treatment under in situ reservoir conditions.

[086] This was necessary to establish a base case for the relative permeability of the turning point for both saline and oil whose turning points are measured after treatment. c) Adsorption system injection. d) Post-treatment cyclic petroleum-saline injection to evaluate the treatment effect on the permeability measurements at the turning point in step (b).

[087] In general, the following oil-water injection sequence was performed: water - oil - water - oil - water - treatment - water - oil.

[088] Table 11 presents the measured differential pressures on the sample during the results of the in situ saline permeability measurements conducted on the sample as part of stage (a) of the core injection procedure. Table 11: Permeability measurements of saline solution at variable flow rates before treatment with the adsorption system.

[089] As mentioned earlier, in order to measure the stabilized turning point permeabilities in the pre-treatment to oil and saline, a cyclical oil-saline injection pattern was implemented (stage (b)). This stage consisted of three petroleum injections conducted in alternation with three saline injections. Each injection continued until steady state conditions were reached, that is, stable and constant differential pressure over the sample and no further production of displaced fluid on the output side of the core sample.

[090] Table 12 presents the results of the cyclical saline solution injection described above conducted and for each fluid the differential pressure remains relatively the same from the 2nd injection cycle to the 3rd. Table 12: Stabilization of the differential pressure over the sample with cyclic petroleum-saline injection.

[091] The rock is then treated with the adsorption system (same composition as in example 6) including a surface modifying agent which is a water-soluble polymer capable of binding to the adsorption system. The treatment was added using an exchange piston and 3.7 times the core pore volume was injected into the core sample. The differential pressure over the sample was >2000 psi (13789.51 kPa) which is extremely high for a polymer injection which is evidence of strong adsorption to the rock surface.

[092] Post-treatment permeability data were then collected by injecting water and oil until a stable differential pressure was reached. The reduction ratio for the saline solution was measured to be 39.2 (96 pore volumes injected into the pore volume of the 10.5 cm3 sample) determined as the point where the differential pressure over the rock is stable. Without strong surface adsorption, the water-soluble adsorption system would be washed away. The reduction ratio was then determined by switching to oil injection and a stable differential pressure resulted in an oil permeability reduction ratio of 16.94 (96 injected pore volumes) again determined as the point where the differential pressure on the rock is stable. Therefore, when a suitable polymer is attached onto the adsorption system (via the functional group on the silane), the adsorption system can reduce the permeability to saline solution more than oil, this is known as relative permeability modification.

[093] After the core injection experiment, the sample was removed from the instrument and extensively extracted with toluene to remove any oil and then ground and XPS analysis was performed to try to detect the adsorption system (Table 13). The concentration of the adsorption layer is predicted to be extremely low as the porosity of the sample is 28%, so the rock is mostly bulky material where the adsorption layer is uncoated. However, approximately 1% silicon was detected in the sample (note this is measuring the total bulky material) and when combined with all the core injection data successful adsorption of the chemicals occurred. Table 13: XPS analysis of carbonate rock after core injection analysis (measuring bulk material).

Example 8 - Core Injection with Adsorption System under wettability conditions mixed with a different oil.

[094] This experiment matches example 7 except that this time a different type of crude oil was used (API gravity = 18.3, Density = 0.9442) and therefore the composition of the oil is substantially different . Table 14 presents the sample porosity and permeability measured over the net effective pressure in situ using the automated helium porosity-permeability measurement instrument mentioned above. Table 14: Porosity and permeability (mD is milli-Darcy) under complete liquid effective pressure in situ.

[095] Table 15 shows the differential pressures measured on the sample during the results of the in situ measurements of saline permeability conducted on the sample as part of stage (a) of the core injection procedure (prior to treatment with the adsorption) Table 15: Differential pressure over the rock sample at various flow rates used to calculate permeability to saline solution.

[096] Table 16 presents the results of the cyclic petroleum-saline injection in the pre-treatment conducted on the sample in order to establish the relative permeabilities of the standard turning point. Table 16: Differential pressure over the rock sample for the cyclic oil and saline injections used to calculate the permeability to the saline solution.

[097] After cyclic petroleum/saline injections to determine the standard permeability, the rock is then treated with the adsorption system (same as in examples 6 and 7) including a surface modifying agent that is a polymer soluble in water capable of binding to the adsorption system (same as in example 7). The treatment was added using an exchange piston and 1.6 times the core pore volume was successively injected into the core sample. The differential pressure over the sample was again >2000 psi (13789.51 kPa) which is extremely high for a polymer injection which is evidence of strong adsorption to the rock surface.

Post-treatment Permeability Data

[098] The reduction ratio for saline solution was previously measured to be 296 - determined as the point when the differential pressure over the rock is stable, without adsorbing to the surface, the water-soluble adsorption system would be washed away. The final differential pressure recorded at the end of the day resulted in an oil permeability reduction ratio of 9.3 - determined as the point when the differential pressure over the rock is stable.

Example 9 - Injection into the Core with lower concentration of adsorption system

[099] Previously, when the adsorption system was injected, excessive differential pressures were found (>2000 psi = 13789.51 kPa) which can be attributed to the capacity of the system to chemically adsorb to the surface. The pressure during injection cannot reach the overload pressure (3500 psi = 24131.65 kPa) otherwise the experiment will fail. For this experiment, the adsorption system was diluted 25% of the original formulation given in example 6 with water and the differential pressure was approximately 600 psi = 4136.85 kPa (compared to 2000 psi (13789.51 kPa) at the original concentration ) which is an improvement on previous experiments and, at this concentration, multiple pore volumes of the adsorption system could be injected at higher flow rates. At 25%, the adsorption system could be injected at 60cc/h with 600 psi (4136.85 kPa) differential pressure whereas previously 2 - 3 cc/h was the maximum injection rate giving differential pressures >2000 psi (13789, 51 kPa).

[100] Figure 3 shows a substrate (301) having an adsorption layer (302) with polymer (303) as described, in the presence of saline (304), the polymer (303) is hydrated and expands over the space of the pore (left image); in the presence of oil (305), the polymer (303) collapses and the pore space is more accessible.

[101] When diluting the adsorption system, this layer cannot accumulate as quickly resulting in excessive differential pressures (>2000 psi = 13789.51 kPa) during injection. Despite using a lower concentration of adsorption system, the effectiveness is maintained as evidenced by the post-treatment permeability data: the reduction ratio for saline was 62 and for oil was 14.5.

Example 10: Flood core experiment with different rock sample

[102] This experiment was carried out on an alternative carbonate core sample using the same procedure outlined in examples 6 and 8 using ARAB D oil. The surface chemistry of the different carbonate cores (#2) versus the cores tested so far (#1) was different using XPS (Table 17). Core #1 has the same data as those shown in table 3 (control) and core #2 is the sample from the different core. As can be seen in table 16, calcium and magnesium are still present which have been identified as being involved in the adsorption mechanism. However, there is a significant amount of surface silicon in the synthetic core (8.2%) versus no surface silicon in today's cores which preferably makes a difference in how the adsorption system interacts with the surface. The presence of silicon is more in line with sandstone reservoirs. Table 17: Survey data measured by X-ray Photoelectron Spectroscopy (atomic percentage, %) for different samples of the reservoir core.

[103] The same sequence of injections was performed in this different core and the post-treatment permeability data show a reduction ratio for saline solution of 11 - and for petroleum it was 4.0. This demonstrates that the adsorption system is still effective even with less calcium and magnesium and a significant presence of silicon in the sample.

[104] The cores were also evaluated for porosity and permeability and these were again key differences as the previous cores had a permeability of 200mD and 28% porosity while the different cores had a permeability of 420mD and 40% porosity . As described in Figure 3, if the porosity is greater then more of the adsorption system is required in order to fill the pore space. Therefore, for this experiment the adsorption system was not diluted and was used at the concentration given in example 6.

Claims (13)

1. A method of treating an underground hydrocarbon reservoir comprising a carbonate-containing substrate, the method characterized in that it comprises: adding an amount of a silicate or a silicate-containing molecule to the reservoir to chemically interact with a carbonate surface of the substrate containing carbonate to form a silicate layer or silicate-containing molecule chemically interacted with at least a portion of the carbonate surface; adding an amount of organosilicon compound to chemically bond with the silicate-containing material; adding an amount of a surface modifying agent comprising an organic polymer or macromolecule excluding an organosilicon compound to covalently bond to the organosilicon compound through a suitable functional group on the organosilicon compound; wherein silicate is added to the reservoir at a concentration greater than 0% and up to 8% by weight/volume. 2. Method according to claim 1, characterized in that the silicate or silicate-containing molecule is reacted with the organosilicon compound before being added to the underground hydrocarbon reservoir. 3. Method according to claim 1 or 2, characterized in that the organosilicon compound is an organosilane having the formula:

where X is a hydrolyzable group selected from the group consisting of alkoxy, acyloxy, halogen or amine; R is a non-hydrolyzable organic radical selected from the group consisting of alkyl, alkenyl, aryl, allyl, halogens, amines, sulfur functional groups, hydroxyl, aldehyde, epoxy, nitrobenzamide, cyano, pyridyl, azide, ester, isocyanate, phosphine, phosphate or polymeric or multifunctional silanes; and n is 1 to 4. 4. Method according to claim 3, characterized in that the organosilane is selected from the group consisting of: monomers, hydrolyzed monomers, hydrolyzed dimers, and hydrolyzed oligomers of: an aminopropyltrialkoxysilane, an aminoethylaminopropyltrialkoxysilane, an alkyltrialkoxysilane, a vinyltrialkoxysilane one feniltrialcoxissilano, mercaptotrialcoxissilano a estirilaminotrialcoxissilano a metacriloxipropiltrialcoxissilano a glicidoxipropiltrialcoxissilano a perfluortrialcoxissilano a trialkoxysilane functionalized perfluoréter one functional trialkoxysilane azole, a tetra-alkoxysilane, metildietilclorossilano, dimethyldichlorosilane, methyltrichlorosilane, dimetildibromossilano, dietildi-iodossilano, dipropildiclorossilano, dipropildibromossilano, butiltriclorossilano, phenyltribromosilane, diphenyldichlorosilane, tolyltribromosilane, methylphenyldichlorosilane or combinations thereof; or methyldiethylchlorosilane, dimethyldichlorosilane, methyltrichlorosilane, dimethyldibromosilane, diethyldiiodosilane, dipropyldichlorosilane, dipropyldibromosilane, butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane, tolyltribromodichlorosilane, methyl. 5. Method according to claim 3, characterized in that the organosilane is an amino organosilane. 6. Method according to any one of claims 1 to 5, characterized in that the silicate or silicate-containing molecule is added to the reservoir at a concentration greater than 0.1% and up to 5% by weight/volume. 7. Method according to any one of claims 1 to 6, characterized in that the silicate or silicate-containing molecule is added to the reservoir at a concentration greater than 0.2% and up to 4% by weight/volume. 8. Method according to any one of claims 1 to 7, characterized in that the organosilicon compound is added to the reservoir at a concentration of less than 1.0 mol/L. 9. Method according to claim 8, characterized in that the organosilicon compound is added to the reservoir at a concentration between 0.05 and 0.2 mol/L. 10. Method according to any one of claims 1 to 9, characterized in that the surface modifying agent is added so that the ratio of active groups in the surface modifying agent to organosilicon is 1:1.5 to 1:5. 11. Sample taken from an underground hydrocarbon reservoir, subjected to the method as defined in claim 1, the sample characterized by the fact that it comprises: a carbonate-containing substrate having a silicate layer or a silicate-containing molecule that has chemically interacted with at least one portion from a surface of the carbonate-containing substrate; an organosilicon compound that is covalently bonded to the silicate; and a surface modifying agent that is covalently bonded to the organosilicon compound. Underground hydrocarbon reservoir treated according to the method as defined in claim 1, the treated reservoir characterized by comprising: a carbonate-containing substrate having a silicate layer or a silicate-containing molecule chemically interacted with at least a portion of a surface of the carbonate-containing substrate; an organosilicon compound that is covalently bonded to the silicate; and a surface modifying agent that is covalently bonded to the organosilicon compound. 13. Composition for treating an underground hydrocarbon reservoir comprising a carbonate-containing substrate, according to the method as defined in claim 1, the composition characterized by the fact that it comprises: an amount of a silicate or a silicate-containing molecule to chemically interact with a carbonate surface of the carbonate-containing substrate; an amount of an organosilicon compound; and an amount of a surface modifying agent which may or may not be covalently bonded with the organosilicon compound; wherein the silicate or silicate-containing material can be chemically reacted with the organosilicon compound and the organosilicon compound includes a functional group that allows the surface modifying agent to covalently bond to the organosilicon compound.

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