WO2013091023A2

WO2013091023A2 - Method for chemically adsorbing to carbonate surfaces

Info

Publication number: WO2013091023A2
Application number: PCT/AU2012/001599
Authority: WO
Inventors: Colin Wood; Karen KOZIELSKI; Khoa PHAM; Ghaithan A AL-MUNTASHERI
Original assignee: Commonwealth Scientific And Industrial Research Organisation; Aramco Overseas Company Bv
Priority date: 2011-12-21
Filing date: 2012-12-21
Publication date: 2013-06-27
Also published as: WO2013091023A3; MY166656A; CN104105776A; CN104105776B; BR112014015091B1; BR112014015091A2

Abstract

The present invention relates to modifying the characteristics of carbonate reservoirs producing oil and/or gas. Specifically, there is disclosed herein a method of treating a subterranean hydrocarbon reservoir comprising a carbonate containing substrate, a composition to treat subterranean hydrocarbon reservoir comprising a carbonate containing substrate, a sample taken from a subterranean hydrocarbon reservoir comprising a carbonate containing substrate and the treatment composition, and a subterranean hydrocarbon reservoir comprising a carbonate containing substrate and the treatment composition.

Description

Method for chemically adsorbing to carbonate surfaces

Field of the invention

The present invention relates to modifying the characteristics of carbonate reservoirs producing oil and/or gas. Background of the invention

Reference to any prior art in the specification is not, and should not be taken as, an acknowledgment or any form of suggestion that this prior art forms part of the common general knowledge in Australia or any other jurisdiction or that this prior art could reasonably be expected to be ascertained, understood and regarded as relevant by a person skilled in the art.

There is a need to modify the characteristics of reservoirs that produce oil and/or gas to provide a more favourable^"production environment. Modification of the characteristics of a reservoir can enhance the production of oil and/or gas, or to ameliorate issues with water production that arises as a result of oil and/or gas extraction. It is known that the internal environment of a reservoir may be altered through the inclusion of compositions that comprise surface modifying agents such as organic macromolecules/polymers. These can be used to alter the physical properties of the internal reservoir environment. One of the primary considerations is the anchoring or bonding of the organic macromolecule/polymer to a surface within the reservoir. In many instances, the organic macromolecule/polymer is an organosilicon compound.

Organosilicon compounds are known to bond strongly to silicate surfaces. This makes their use particularly well suited to reservoirs that comprise a large silicate component such as clay, feldspar, sandstone, or other silicate mineral surfaces. US 2007/0039732 patent publication (to Dawson et al.) and US patent publication 2011/0114314 (to Wang et al.) discuss the use of compositions of macromolecules that may comprise organosilicon compounds for hydrocarbon recovery in a reservoir. US patent publication 2007/0039732 is directed towards providing a method for the enhanced recovery of hydrocarbons from a subterranean formation using a relative permeability modifier (RPM) which can be a macromolecule or micro-gel. In this method, an aqueous composition comprising the RPM is introduced into an injector well. It is intended that the RPM adsorb within the well, thus improving the extraction of hydrocarbons by impeding the production of water, or restricting the movement of water through permeable reservoir formation materials. This document discloses that the RPM can be an organosilicon compound, as these compounds provide further binding to substrate silicate containing materials including quartz, clay, chert, shale, silt, zeolite, or combinations thereof.

US patent publication 2011/0114314 is directed towards providing a method for reducing the flow of unwanted water in a subterranean reservoir. This is achieved through gelation and/or polymerisation of a soluble silicate with an activator and a hydrolysable organosilane compound, such as silanols thus forming a network. The silanols react with the siliceous surfaces on the rock to covalently bind the network to the surfaces of the formation. The silanols also interact with the sodium silicate, and bind them to each other and to the surfaces of the subterranean formation. This results in the formation of a gel plug. That is, the sodium silicate and silanols effectively form a plug to stop or reduce the flow of water through the subterranean formation. As with US 2007/0039732, application of this method is limited to silicate containing formations.

The prior art addresses methods of improving production of hydrocarbons in a subterranean formation, where that formation is primarily siliceous through the use of molecules which include organosilanes. However, application of organosilicons is generally restricted to reservoirs comprising siliceous surfaces. In view of the foregoing, it is clear that there is a need to develop a mechanism for modifying the characteristics of a reservoir that is not siliceous in nature.

It is an object of the invention to at least ameliorate some of the above mentioned problems. As used herein, except where the context requires otherwise, the term "comprise" and variations of the term, such as "comprising", "comprises" and "comprised", are not intended to exclude further additives, components, integers or steps.

Summary of the invention

It is desirable to develop a means for improving the production of hydrocarbons in a carbonatious reservoir (i.e. carbonate containing). Thus, the present invention is directed toward providing a method of treating a subterranean hydrocarbon reservoir comprising a carbonate containing substrate. Broadly, the method comprises the step of 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 within the reservoir.

In one aspect of the invention there is provided a method of treating a subterranean 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 the silicate is added to the reservoir at a concentration of greater than 0% and up to 8% weight/volume.

In another aspect of the invention there is provided a sample taken from a subterranean hydrocarbon reservoir, the sample comprising: a carbonate containing substrate having a layer of silicate or a silicate containing molecule that has chemically interacted with at least a portion of a surface of the carbonate containing substrate.

The presence of a silicate based surface layer is evidenced by the concentration of silica being higher at the surface of the substrate compared to the silica concentration of the bulk of the sample. The silicate may be determined using any suitable technique available to a person skilled in the art including X-ray and spectroscopic techniques (e.g., FTIR, Raman, UV/Vis, transmission electron microscopy or energy dispersive spectrometry display). It is preferred that the sample provides an indication of the surface concentrations of silica in the sample is greater than the silica concentration in the bulk 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 bulk sample is by a weight ratio of at least 5:1. Even more preferably the weight ratio of silica in the sample is to silica in the bulk sample is by a weight ratio of at least 10:1. It is intended that the wt% silica in the surface layer is determined by electron microprobe (EPMA). The bulk composition is also preferably determined by EPMA, with the bulk sample prepared through initially micronising the sample to obtain a homogeneous representation of the bulk of the sample. The electron microprobe focus beam should be as wide as practicable (e.g. at least about 10 microns diameter) to avoid localised compositional variations. Preferably, the silica concentration is based upon three microprobe measurements of each of the substrate surface and substrate bulk.

In another aspect of the invention there is provided a subterranean hydrocarbon reservoir comprising: a carbonate containing substrate which has been treated and has a layer of silicate or a silicate containing molecule chemically interacted with at least a portion of a surface of the carbonate containing substrate.

In another aspect of the invention there is provided a composition to treat subterranean 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 carbonate containing substrate; an amount of an organosilicon compound; wherein the silicate or silicate containing material may be chemically reacted with the organosilicon compound.

The silicates may be selected from any silicate containing molecule. The term 'silicate' is used in its broadest sense to refer to any compound containing a silicon bearing anion. Preferably, the silicate is a silicon-oxygen containing anion, i.e. an Si-0 type anion, that is an anion including a silicon atom having at least one bond to an oxygen atom (i.e. having at least one Si-0 bond). Suitable silicate anions may include those of the type: [SiO^^4-, [Si₂0₇]^6", [Si_n0_3n]²ⁿ-, [Si₄n0_11n]^6n" ₍ [Si₂n0₅n]^2n", or [Al_xSi_y0_2(x+y)r. More preferably the silicates are silicates of alkali metals. Most preferably the silicate is sodium silicate or potassium silicate.

The silicate may be added to the reservoir at a concentration of silicate, calculated as silica, of greater than 0% and up to 8% weight/volume. It is preferred that this silicate is added to the reservoir at a concentration of greater than 0.1% and up to 5% weight/volume (calculated as silica). More preferably, silicate is added to the reservoir at a concentration of 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 of greater than 0.3% and up to 3% weight/volume (calculated as silica). Yet even more preferably, silicate is added to the reservoir at a concentration of greater than 0.5% and up to 2% weight/volume (calculated as silica).

The quantity of silicate added to the system is given in terms of silica weight/volume fraction. This is because most commercial silicates quote the concentration in terms of a silica concentration. Whilst 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% weight/volume. More preferably, the silicate (as silica) is added so that the concentration of the aqueous phase within the reservoir is greater than 0.1% and up to 5% 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% 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% weight/volume. Yet 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% weight/volume. In a preferred embodiment, the method further comprises the addition of an organosilicon compound, such as an organosilane. The organosilicon compound chemically binds 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 of greater than 0 and less than 1.Omol/L. More preferably, the organosilicon compound is added to the reservoir at a concentration of between 0.05 and 0.2mol/L As above, it is preferred that the concentration of the organosilicon compound in the aqueous phase within the reservoir is less than 1. Omol/L. More preferably, the organosilicon compound is present in the aqueous phase within the reservoir at a concentration of between 0.05 and 0.2mol/L In an alternative embodiment, the silicate may be reacted with the organosilicon compound before being added to the subterranean hydrocarbon reservoir. It is preferred that the silicate and organosilicon compound, together provide a means for altering the surface characteristics within the subterranean hydrocarbon reservoir.

In a further aspect of the invention, the organosilicon compound includes a functional group that allows a surface modifying agent (e.g. an organic polymer or macromolecule, excluding an organosilicon compound) to covalently bind to the organosilicon compound via a suitable functional group on the organosilicon compound.

The surface modifying agent may be added either to the reservoir, or pre-reacted with the organosilicon compound. The surface modifying agent may for example be a polymer. It is intended that the surface modifying agent covalently bonds with the organosilicon via an active group (or a bonding group) on the surface modifying agent. It is intended that this active group (or bonding group) on the surface modifying agent covalently interacts 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 on 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.

The net result of the surface modifying agent is to functionalise the surface of the carbonate reservoir with the aim of stimulating the reservoir for purposes including: enhanced oil recovery, permeability modification (total fluid shutoff and relative permeability modification), fracturing, and acid diversion. The surface modifying agent is preferably selected from polymers, inclusive of macromolecules, and the selection should be matched to 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 a stable chemical bond is formed will be clear to the person skilled in the art. Within the R group may be nonhydrolyzable organic radical(s) that possess a functionality that imparts desired characteristics. This includes: alkyl, alkenyl, aryl, allyl, halogens, amines, sulphur functional groups, hydroxyl, aldehyde, epoxy, nitrobenzamide, cyano, pyridyl, azide, ester, isocyanate, phosphine, phosphate. For example, if the R group on the organosilane is an epoxide 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. The NHS esters and hydroxylmethylacrylamide containing surface modifying agents can be prepared from polyacrylamide, copolymers of polyacrylamide including hydrolyzed polyacrylamide or polyacrylamide-co-acrylic acid, polyacrylamide-co-acrylic acid partial sodium salt, poly(acrylic acid-co-maleic acid), cationic polyacrylamides, anionic polyacrylamides, and amphoteric polyacrylamides.

Further aspects of the present invention and further 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. Recitation of ranges of values herein are merely intended to serve as a short hand method of referring individually to each separate value and each potential range encompassed within, unless otherwise recited. Furthermore, each separate value and each potential range is incorporated into the specification as if it were individually recited herein. Brief description of the drawings

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

Figure 2 is a graph showing differential pressure across the carbonate core during brine injection after treatment with the adsorption system, the differential pressure stabilizes showing a 560 times reduction in permeability across the core in comparison to pre- adsorption treatment. Conditions: 100% water saturation, 3,500 psi confining stress, 500 psi backpressure, and temperature of 105°C.

Figure 3 provides an illustration of a mechanism for the adsorption system (with polymer) in the presence of brine and in the presence of oil.

Figure 4 shows the high resolution carbon spectra collected using XPS that shows the C-0 groups for the epoxy containing sample at 287eV (solid line) versus the carbonate control where the C-0 groups are not present without the adsorption system (dotted line). Detailed description of the embodiments

There is disclosed herein a method of treating a subterranean hydrocarbon reservoir comprising a carbonate containing substrate, the method comprising the step of adding an amount of a silicate to chemically interact on to the carbonate surface. Without wishing to be bound by theory, it is believed that the silicates react with partially dissolved cations at a surface of a carbonate substrate. This interaction results in the silicate adsorbing to the surface of the carbonate containing substrate. The silicates may also interact with each other to form a silica layer on the carbonate surface. This method is intended to provide a generic means for modifying a carbonate containing surface in a subterranean hydrocarbon reservoir. The silicate may be added so that the resultant concentration of silicate, calculated as silica, in the reservoir is at a concentration of greater than 0% and up to 8% weight/volume. It is preferred that this silicate is added to the reservoir so that the resultant concentration of silicate, when calculated as silica, is greater than 0.1 % and up to 5% weight/volume. More preferably, silicate is added to the reservoir so that the resultant 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 resultant concentration, when calculated as silica, is greater than 0.3% and up to 3% weight/volume. Yet even more preferably, silicate is added to the reservoir so that the resultant concentration, when calculated as silica, is greater than 0.5% and up to 2% weight/volume. The volume of the reservoir is the total aqueous volume (i.e. the volume of voids) of the reservoir; that is, the volume of the reservoir occupied by the aqueous phase.

The term 'carbonate' is used in its broadest sense to refer to any mineral, rock or compound that comprises a carbonate anion (CO₃ ² ). 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 dolostone. Preferably the carbonate minerals include: dolomite, calcite, vaterite, aragonite, ikaite, monohydrocalcite, magnesite and/or landsfordite. The carbonate substrate preferably comprises a carbonate component of at least 5wt%, more preferably at least 10 wt%, even more preferably at least 30 wt% and most preferably at least 50 wt%.

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

There is further disclosed herein a method for chemically bonding a target material to the surface of a carbonate substrate by altering the wet-ability of that surface. A multi- component system may be used that chemically bonds to carbonate surfaces whilst providing functionality for bonding and surface modification. Silicate and organosilicon molecules are combined that chemically interact with the carbonate surface and provide a siliceous layer where further target molecules may be bound. 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 via a silicate intermediary.

The term Organosilicon' is used in its broadest sense to refer to organic compounds" containing carbon-silicon bonds and hydrolysable groups (i.e. an hydrolysable organosilicon compound). Preferably the hydrolysable organosilicon compound is an hydrolysable organosilane. The hydrolysable organosilane compound can be selected from the group consisting of water-soluble organosilane compounds and organosilane compounds that 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 that can be used as the hydrolysable organosilicon compound in embodiments of the present invention will be apparent to those of skill in the art and are to be considered within the scope of the present invention. Among the organosilicon compounds suitable for use in this invention are organosilanes having the formula:

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 R group is a nonhydrolyzable organic radical that possesses a functionality that imparts desired characteristics this includes: alkyl, alkenyl, aryl, allyl, halogens, amines, sulphur functional groups, hydroxyl, aldehyde, epoxy, nitrobenzamide, cyano, pyridyl, azide, ester, isocyanate, phosphine, and phosphate, as well as multifunctional and organosilanes bonded to polymers where the organosilane can still form a network with silicate (e.g., organosilane modified polyethyleneimine). Suitable hydrolysable organosilane compounds that can be used in the present invention can include monomers, hydrolyzed monomers, hydrolyzed dimers, and hydrolyzed oligomers of trialkoxyorganosilane, aminopropyltrialkoxysilane, aminoethylaminopropyltrialkoxysilane, alkytrialkoxysilane, vinyltrialkoxysilane, phenyltrialkoxysilane, mercaptotrialkoxysilane, styrylaminotrialkoxysilane, methacryloxypropyltrialkoxysilane, glycidoxypropyltrialkoxysilane, perfluorotrialkoxysilane, perfluoroether functionalized trialkoxysilane, azole functional trialkoxysilane, tetraalkoxysilane, , or combinations thereof. In a preferred embodiment, the hydrolysable group on the organosilicon compound is an amine group. Specific examples of suitable organosilanes include: aminopropyltriethyoxysilane, methyldiethylchlorosilane, dimethyldichlorosilane, methyltrichlorosilane, dimethyldibromosilane, diethyldiiodosilane, dipropyldichlorosilane, dipropyldibromosilane, butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane, tolyltribromosilane, methylphenyldichlorosilane, methyldiethylchlorosilane, dimethyldichlorosilane, methyltri-chlorosilane, dimethyldibromosilane, diethyldiiodosilane, dipropyldichlorosilane, dipropyldibromosilane, butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane, tolyltribromosilane, methylphenyldichlorosilane and the like. Preferably, the organosilane is aminopropyltriethyoxysilane (APTS).

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

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

The quantity of each component that needs to be added to a reservoir is reservoir dependent and is likely to depend on data such as permeability, porosity and pore volumes, hydrocarbon production, proportion of the reservoir that requires treatment, or other physical, chemical or operational parameters such as fluid composition. In one embodiment of the invention, computer modelling is used to determine the quantity of silicate that needs to be added to the reservoir. Computer modelling may also be used to determine the amounts of organosilicon, polymer, or other additives to be added to the reservoir. In a further aspect, the computer modelling data is based on information including permeability, porosity and pore volumes, hydrocarbon production, proportion of the reservoir that requires treatment, the size or volume of the reservoir, or other physical, chemical or operational parameters.

In an alternative embodiment, the approach to determining the quantity of each component to be added to the reservoir may be empirical such that 1/2 to 1 day's production volume is added or specific volume per foot of pay or volume to achieve a certain radius from the well. This information may for example be obtained from reservoir logging tools and sampling data.

The concentration of the 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 - 0.2mol/L. It is also preferred that the concentration of the organosilicon in the reservoir is less than 1mol/L. More preferably, the concentration of the organosilicon compound in the reservoir is 0:05 - 0.2mol/L; wherein the volume of the reservoir is in terms of the total aqueous volume (i.e. the volume of voids) of the reservoir; that is, the volume of the reservoir occupied by the aqueous phase.

On addition of the surface modifying agent to the system, the surface modifying agent reacts with the reactive groups on the organosilicon molecule. The surface modifying agent may be activated to render it more reactive with the reactive groups on the organosilicon compound. In a preferred embodiment the surface modifying agent reacts with amine groups on an organosilane molecule.

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 mol of organosilicon there are 0.7 mol of active groups on the surface modifying agent. More preferably, the ratio of active groups on 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 silane is from 1 :1.5 to 1 :3.

The maximum concentration of the surface modifying agent needs to be low enough so that rheology of the solution is still workable, i.e. it will not be too viscous to pump or likely to self-gel. 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. The silicate is essential for interacting with the cations at the surface of the carbonate substrate. The organosilicon binds to the silicate and may provide an exposed functionality to allow attachment of further surface modifying agent(s) if desired. It is preferred that the silicate co-condenses with the organosilicon. The silicate, organosilicon, and other additives (such as a further surface modifying agent) may be delivered in aqueous solution either sequentially or in combination. The further surface modifying agent may be a water soluble polymer(s) or other organic macromolecule(s). The means of attachment may be through covalent bonding. The functionality of the organosilicon may be selected in consideration of the intended application or the nature of the intended the surface modifying agent. This approach has broad reaching applications in subterranean carbonate reservoirs producing oil and gas as it provides a method to chemically bond to the surface thus providing a long term effect.

Figure 1 shows the interaction between the silicate, organosilicon compound, 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) via a free silicate ion compound (103) i.e. from a sodium silicate solution that 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. This arrangement shown in Figure 1 overcomes the problem whereby without the inclusion of a silicate, silanes do not readily react with a carbonate surface (101). The dissolved surface calcium ions (104) atoms react with the free silicate ions (103) in 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 aminosilane (102) to form a siliceous layer at the surface of the calcium carbonate substrate (101).

The amino silane molecule (102) undergoes a condensation reaction forming 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) a further surface modifying agent (not shown) such as a polymer.

The methods disclosed herein are broad in application and are intended to be applicable where the surface modifying agents are provided to subterranean hydrocarbon reservoirs comprising carbonate substrates for the purposes including: enhanced oil recovery, surface modification, permeability modification (total shutoff and relative permeability modification), fracturing, and acid diversion.

Unless otherwise stated, reference to a polymer or macromolecule will be taken as¹ reference to a surface modifying agent. It will be understood that the invention disclosed 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 of these different combinations constitute various alternative aspects of the invention.

Examples

Example 1 - testing on model calcium carbonate

In order to determine adsorption to carbonate surfaces accurately weighed samples of calcium carbonate powder were exposed to target the surface modifying agent that bond to the surface and after extensive washing the samples were reweighed and gravimetric increases are indicative of adsorption. For example, a known amount of carbonate powder 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 wt % 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 decanting supernatant with water so that the total dilution factor is at least 10⁶, i.e. at most 1 part per million of the original solute remains. The sample is then dried in vacuo until constant weight. The dried sample is weighed and any change in weight is calculated. The carbonate samples were pre-treated to provide samples with different wettability profiles (water wet, oil wet, and mixed). In order to prepare these samples they were exposed to water, and/or water and mineral spirits prior to adsorption testing.

A silicate-based system consisting of sodium silicate and a functionalized silane (in particular aminopropyltriethoxysilane, APTS) displayed good adsorption to the carbonate material (table 1). The sodium silicate is an essential component as the APTS alone did not provide sufficient adsorption. It is widely accepted that silane molecules alone do not interact strongly with carbonate substrates as the silane cannot form a strong bond with the surface. The method described above was used to successfully identify inorganic silicate-based functionality that displayed good adsorption (>4%) to the above mentioned model reservoir material (Table 1, entry 1). This is a potential method to provide strong adsorption to carbonate reservoirs which would represent a significant breakthrough. Many reservoirs are typically neutral- to oil wet, therefore, the screening experiments were carried out with calcium carbonate that was exposed to an oil phase prior to adsorption studies. Therefore, the adsorption system was tested on a water-wet 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 same between sample 1 and 2. The amount of material adsorbed was determined gravimetrically and both samples gave the same uptake (4.1%) which shows that in this case the wettability did not have a big effect.

Sample→ 1. 2. 3. 4.

Silicate Adsorption Silicate Adsorption Silicate Adsorption Silicate Adsorption

System System System + polymer System+ polymer

(water wet) (mixed wetability) (water wet) (mixed wetability)

Mass gain %→ 4.1 4.1 7.8 6.3 Table 1: Experimental values for adsorption screening using calcium carbonate as a model material. Samples exposed to oil prior to the adsorption test are bolded. Silicate-based adsorption system is adsorbed onto a water wet sample (1) and an oil wet sample (2). The silicate-based adsorption system provides adsorption sites for a polymeric material to chemically bond to the samples (i.e. samples 3 and 4, which represent the water wet and oil wet systems respectively).

Table 1 shows 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, i.e. the silicate-based adsorption system adsorbs onto the water wet sample. Sample 2 shows the percent mass gain for a mixed wetted system, which in this case is an oil wet sample. Samples 3 and 4 (corresponding to water wet and oil wet systems respectively) report the percent mass gain where the adsorption sites of the silicate-based adsorption system are exposed for chemical bonding of a polymeric type material.

Essentially there are three interfaces to consider 1) carbonate substrate-to-silicate adsorption functionality; 2) silicate adsorption functionality-to-target groups (i.e. polymer); and 3) polymer-to-polymer in the case where layers are to be built up.

The silicate-based adsorption system (i.e. APTS) is capable of bonding to the calcium carbonate surface (interface number 1) based on the observations in Table 1. The surface modifying agent which consists of a N-hydroxysuccinimide ester of hydrolyzed polyacrylamide (Polyacrylamide-co-acrylic acid partial sodium salt, Mw 520,000, Mn 150,000, typical acrylamide level 80%) was then tested and found to be capable of bonding to the adsorption system (interface number 2) by reacting with the amine group from the APTS (table 2, entries 3 and 4). Interestingly, when this was attempted higher mass gains were observed than with just the adsorption system which can be attributed to the fact that the surface modifying agents were designed to covalently bind to the surface (7.8% and 6.3% with the surface modifying agent versus 4.1% without). Control experiments with the surface modifying agent that were incapable of bonding 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 model carbonate and no weight increase was observed. In the cases where the surface modifying agents were included the effect of wettability of the calcium carbonate did have an effect on the gravimetric uptake. For example, when a water wet calcium carbonate system was utilized with the adsorption system and a surface modifying agent a gravimetric uptake of 7.8% was observed (table 1, sample 3). When an oil wet calcium carbonate was used with the exact same system the uptake decreased to 6.3% under the same conditions (table 1, sample 4). The conclusion here is that the wettability has an effect on the adsorption - for oil wet samples the adsorption is lower. However, it is worth noting that despite the decrease in adsorption for an oil wet sample of calcium carbonate the adsorption is not completely compromised and still offers a viable adsorption approach that is believed to be due to strong chemical bonding (i.e. chemisorption).

Example 2 - testing on a sample from a carbonate reservoir

These data (Table 2) were carried out on an actual sample from a carbonate reservoir in the Middle East that was ground into a fine powder. The adsorption system was . tested at room temperature (sample 1 and 2), and 90°C (samples 3 and 4).

Table 2: Experimental values for gravimetric adsorption screening at room temperature and 90°C using a ground carbonate core sample from an oil reservoir as a model material.

As can be seen when the carbonate core sample was subjected to the sequence of washing described above at both room temperature (sample 1), and 90°C (sample 3), the sample actually lost weight and the amount lost increased at higher temperatures. This is to be expected as the washing removes 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 wt% and at 90°C (sample 4) the sample gained 11.2 wt%. This is indicative that the adsorption system works effectively with an actual reservoir sample at room temperature and elevated temperature.

Example 3 - Surface studies of silicate/silane system

The numbers given in examples 1 and 2 were obtained using a gravimetric technique which was complemented using X ray photoelectron spectroscopy (XPS) which is an advanced surface characterisation technique (table 3) that uses X-rays to eject electrons from the inner shell orbital's of elements at a surface providing information regarding the surface chemistry.

In carbonate reservoirs composed mainly of dolomite (which is based on calcium magnesium carbonate CaMg(C0₃)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 on from this observation the chemical adsorption system was tested and experiments were performed with silicate and silane (entry 2, table 3) as highlighted in example 2.

1. Control 2. Silicate Silane

Mean Dev. Mean Dev.

Zn 0.085 0.040 0.263 0.085

0 50.148 0.319 46.163 0.406

N 0.000 0.000 6.120 0.325

Ca 10.800 0.332 2.033 0.046

C 33.155 0.388 27.555 0.410

CI 0.110 0.024 0.810 0.102

Si 0.000 0.000 1&073 0.230

Mg 5.700 0.196 0.978 0.068 Table 3: Survey data measured by XPS (atomic percentage, %). Listed are the mean values (± deviation).

If we consider the levels of silicon in the samples that have been 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 onto the surface. Further evidence is provided by the increase in nitrogen from 0 to 6% which can be attributed to the amine groups of the silane. It is noteworthy that the calcium and magnesium levels have 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 the calcium and magnesium.

Example 4 - Control System with no Silicate

Further testing using silane only (no silicate) was also performed on the ground reservoir samples and the silane-only system did not work in the gravimetric screen as shown in table 4 (entry 1 and 4 have no silicate present and the uptake is negative). It is clear from this data that when silane is used without silicate there is no increase in gravimetric uptake.

Silicate on the other hand is known to react with calcium and magnesium ions and at the surface of the reservoir sample partially dissolved surface calcium atoms are likely to exist that can react with free silicate ions in solution. Silicate ions coagulate with each other and with aminosilane to form a silica layer (Figure 1).

Table 4: Gravimetric uptake for silane only systems (data collected at 90°C).

The silane only systems were also investigated using XPS and these data are shown in table 5. 1. Silane only 2. Silane and polymer 3. Silane and polymer

90Ό (no silicate) 120'C (no silicate)

Mean Dev. Mean Dev. Mean Dev.

Zn 0.055 0.055 0.015 0.015 0.045 0.015

0 42.055 0.525 41.105 0.065 36.940 0.180

N 1.040 0.110 3.695 0.065 5.465 0.005

Ca 9.100 0.120 9.360 0.050 7.640 0.110

C 39.405 0.165 39.985 0.325 44.330 0.050

Ci 0.260 0.010 0.395 0.045 0.425 0.035

Si 1.255 0.055 0.430 0.050 0.520 0.040

Mg 6.570 0.030 4.980 0.230 4.520 0.210

Table 5: Survey data measured by XPS (atomic percentage, %) for Silane only systems. Listed are the mean values (± deviation).

As can be seen when silane only is used in the adsorption tests the amount of silicon increases (zero to 1.3%) in comparison to the control sample (carbonate core only) but the amount of silicon is low (1.3%) and if we compare this to the sample with silicate the amount is much less (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 anticipated to chemically bond tar the surface as evidenced by the gravimetric uptake tests (table 4). In addition, if we consider the calcium and magnesium levels in the silane only sample (table 5, entry 1) the calcium decreases only slightly (from 10.8% for the carbonate to 9.1%) and magnesium does not decrease. These are essentially the chemical handles in the reservoir where a material can bond so if these levels are not decreasing that demonstrates that the silane is not bonding strongly. Conversely, the samples containing silicate demonstrated dramatic decreases in calcium and magnesium unlike the silane only samples and silicate is known to react with calcium and magnesium whereas silane only cannot react.

Example 5 - Different Silane molecules Control Epoxy Silane Amine Silane

coated coated

Mean Dev Mean dev Mean dev

Na 0.940 0.020 1305 0.940 0.395 0.075

Fe 0.385 0.075 0.045 0.385 0.000 0.000

F 0.670 0.030 0.145 0.670 0.510 0.060

0 48.020 0.060 45.905 48.020 48.260 0.150

N 0.525 0.085 0.540 0.525 1.840 0.090

Ca 13.635 0.045 4.500 13.635 10.210 0.100

C 32.785 0.075 37.250 32.785 30.815 0.255

CI 0.295 0.045 0.265 0.295 0.625 0.045

S 0.365 0.035 0.000 0.365 0.000 0.000

Sr 0.240 0.000 0.090 0.240 0.165 0.005

Si 1.130 0.030 9.415 1.130 6.695 0.225

Mg 0.395 0.065 0.175 0.395 0.230 0.020

Af 0.605 0.025 0.365 0.605 0.250 0.040

Table 6: XPS surface analysis of carbonate rock (control) and epoxy terminated silane molecule included in the adsorption system and amine terminated silane.

Aminopropyltriethoxylsilane (APTS) has been utilized thus 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 adsorption system (table 6), and calcium and magnesium decreased. The nitrogen increased when APTS was included due to the amine groups. In the case of the epoxy terminated silane (which incorporates carbon and oxygen) the oxygen actually decreased but this could be in part due to the substantial increase in silicon masking the increase in oxygen. Interestingly from the binding energies (figure 4) determined using XPS confirms the presence of C-0 bonds (at 286eV, figure 4, solid line) were present from the epoxy groups that was not present in the original carbonate rock (absence of peak at 286eV, figure 4, dotted line).

Example 6 - Core flooding with Adsorption system at 100% water saturation Core flooding tests were performed that simulate conditions encountered in subterranean reservoirs using the adsorption system to determine the efficacy. The system tested includes a polymeric molecule that is bound to the carbonate using the adsorption system. These tests establish: the baseline permeability of the core to brine (and oil in the case of mixed wetability); can establish complex surface wetability in the core representative of the reservoir; the ability to place the adsorption system under reservoir conditions; adsorption system effect on brine (and oil) permeability (before and after treatment). This example was performed at 100% water saturation in order to determine the ability of the adsorption system to function at 100% water saturation. Example 7 includes further investigations were performed with systems with mixed wetability (oil and water present).

The permeability and porosity of the sample was measured using an automated helium porosity permeability measurement instrument under in-situ net effective pressure, the data is shown in table 7. These data are used to calculate treatment volumes based on the pore volume.

N et effective Pr, psi Pore volume, cc Porosity, % Pe rmeability, m D

3,000 9.46 21.09 151.58

Table 7: Porosity and permeability of cylindrical carbonate rock sample under full in-situ net effective pressure

Afterwards the cylindrical carbonate core sample from a subterranean reservoir was loaded into a core flooding instrument and the outer surface was pressurized to simulate the loads encountered in a reservoir (overburden pressure, 3500 psi, 500 psi back pressure, at 105°C).

Subsequently prolonged brine injection was performed at different flow rates to determine the baseline permeability of the core sample, the brine composition is shown in table 8 Component Grams

Distilled Water 100

CaCI₂.6H₂0 0.069

KCI 0.00265

MgS0 .7H₂0 0.06

NaHC0₃ 0.0235

NaCI 0.027

Table 8: Brine composition

Table 9 presents the results of step the brine injections and shows the differential pressure measured across the sample for each flow-rate after reaching steady-state conditions (i.e. stable and constant differential pressure across the sample), this can be used to calculate the actual core permeability using Darcy's law.

Injection phase Q, cc/hr Vol injected, cc dP, psi numbe r

1 Brine 60 36.1 0.4

2 Brine 120 44 0.8

3 Brine 240 58 1.8

4 Brine 360 88 2.8

5 Brine 480 82 3.9

6 Brine 360 56.5 2.8

7 Brine 240 57 1.9

8 Brine 120 24 0.9

9 Brine 60 20.5 0.5

Table 9: Differential pressure across the cylindrical carbonate rock sample at various flow rates used to calculate permeability to brine (before treatment with adsorption system) The rock is then treated with the adsorption system including a surface modifying agent that is a water soluble polymer capable of bonding to the adsorption system. A 4% (w/v) aqueous polymer solution of polyacrylamide-co-acrylic acid (PAM-co-AA) M_w 520,000, M„ 150,000 (Typical), acrylamide -80 wt.% 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 renders the polymer reactive to the amine groups found on 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) was 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 successfully injected into the core sample. The differential pressure across the sample was >2000 psi which is extremely high for a polymer injection which is indicative of adsorption to the rock surface, the pressure increased rapidly once the adsorption system passed onto the face of the carbonate rock. Prior to the adsorption system reaching the face of the rock an injection rate of 60cc hr was followed but was subsequently lowered to 2-3 cc/hr due to the strong adsorption causing high differential pressure across the sample.

After injection the sample was locked in with no fluid flow for 24 hours, after this the residual adsorption system (in pore space) was removed by injecting brine and after the pressure across the core had stabilized the permeability to brine was re-measured and found to be 560 times (determined as the point when the differential pressure across the rock is stable). Figure 2 shows the differential pressure across the carbonate core after treatment with the adsorption system and can be divided into three different parts: a) An early stage during which the brine is pushed through the core to break through the adsorption system; b) An intermediate stage during which the brine has broken through the outlet face of the sample after which as brine penetrates the pore space the differential pressure would start to decrease; and c) As brine continues to flow through the pore space the differential pressure across the sample starts to decrease but eventually stabilises as the adsorption system (including polymer) inhibits brine flow. This final stabilized differential pressure across the core demonstrates a 560 times reduction in permeability across the core in comparison to pre-adsorption treatment (Table 9). In addition, this effect was maintained for >140 pore volumes which provides strong evidence for effective adsorption, without adsorbing to the surface the water soluble adsorption system would be flushed out with brine. This demonstrates that the approach works under reservoir conditions.

Example 7 - Core flooding with Adsorption system at mixed wettablity conditions

The permeability and porosity of a carbonate core sample was measured using an automated helium porosity permeability measurement instrument under in-situ net effective pressure, the data is shown in table 10. These data are used to calculate treatment volumes based on the pore volume. This experiment was aimed at testing the adsorption system at water saturation with residual oil so the carbonate core sample is exposed to both brine and oil (ARAB D crude oil, API Gravity = 28.80, Density = 0.8820) prior to treatment with the adsorption system. Therefore, the permeability of the rock to brine and oil is determined by flowing brine and oil separately through the sample to provide a baseline permeability (calculated using Darcy's law).

Net effective Pr, psi Pore volume, cc Porosity, % Permeability, mD

3,000 10.50 23.20 197.12

Table 10: Porosity (expressed as a %) and permeability (mD is millidarcy) for carbonate core sample under full in-situ net effective pressure After loading the sample into the core-flooding the following sequence was performed on the sample: a) Pre-treatment in-situ permeability measurement to brine through multi-rate brine injection.

b) Pre-treatment cyclical oil-brine flooding under in-situ reservoir conditions.

This was necessary to establish a base case for the end-point relative permeability to both brine and oil to which the end-points measured after treatment.

c) Adsorption system injection.

d) Post-treatment cyclical oil-brine injection to assess the effect of treatment on the end-point permeabilities measures in step (b).

Overall the following oil-water injection sequence was performed: water - oil - water - oil - water - treatment - water -oil.

Table 11 presents the differential pressures measured across the sample during the results of the in-situ brine permeability measurements conducted on the sample as part of stage (a) of the core-flooding procedure. Injection step

Injection phase Q, cc/hr Vol injected, cc d P, psi numbe r

1 Brine 60 24.78 0.10 2 Brine 120 34.30 0.30 3 Brine 240 68.30 0.7 4 Brine 360 103.74 1.20 5 Brine 480 135.86 1.70 6 Brine 360 86.70 1.30 7 Brine 240 69.00 0.90 8 Brine 120 34.70 0.40 g Brine 60 23.10 0.10

Table 11: Brine permeability measurements at varying flow-rates prior to treatment with adsorption system.

As mentioned previously, in order to measure the pre-treatment stabilised end-point permeabilities to oil and brine a cyclical oil-brine injection pattern was implemented (stage (b)). This stage consisted of three oil injections conducted in alternation with three brine injections. Each flood was continued until steady-state conditions were achieved, that is steady and constant differential pressure across the sample and no more production of the displaced fluid on the outlet side of the core sample. Table 12 presents the results of the above described cyclical oil-brine flooding conducted and for each fluid the differential pressure remains relatively the same from the 2^nd injection cycle to the 3^rd one.

1st oil 1.6

1st brine 1.2

2nd oil 3.4

2nd brine 2.1

3rd oil 3.6

3rd brine 2.5

Table 12: Stabilisation of differential pressure across the sample with cyclical oil-brine injection

The rock is then treated with the adsorption system (same composition as example 6) including a surface modifying agent that is a water soluble polymer capable of bonding to the adsorption system. The treatment was added using an exchange piston and 3.7 times the pore volume of the core was successfully injected into the core sample. The differential pressure across the sample was >2000 psi which is extremely high for a polymer injection which is evidence of strong adsorption to the rock surface. Post treatment permeability data was then collected by injecting water and oil until a stable differential pressure was achieved. The reduction ratio to brine was measured to be 39.2 (96 pore volumes injected based on sample pore volume of 10.5 cm³) - determined as the point when the differential pressure across the rock is stable. Without strong adsorption to the surface the water soluble adsorption system would be flushed out. The reduction ratio was then determined by switching to oil injection and a stable differential pressure resulted in a permeability reduction ratio to oil of 16.94 (96 pore volumes injected) again determined as the point when the differential pressure across the rock is stable. Therefore, when a suitable polymer is bonded onto the adsorption system (via the functional group on the silane) the adsorption system can reduce permeability to brine more than oil, this is known as relative permeability modification.

After the core flood experiment the sample was removed from the instrument and extensively extracted with toluene to remove any oil and was then ground and XPS analysis was performed to try to detect the adsorption system (Table 13). The concentration of adsorption layer is anticipated to be extremely low as the porosity of the sample is 28% so the rock is mainly bulk material where the adsorption layer is not coated. However, approximately 1% of silicon was detected in the sample (note this is measuring the whole bulk material), and when combined with all of the core-flood data successful adsorption of the chemicals has occurred.

Table 13: XPS analysis of carbonate rock after core flood analysis (measuring bulk material) Example 8 - Core flooding with Adsorption system at mixed wettablity conditions with a different oil

This experiment matches example 7 except this time a different type of crude oil was utilized (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 under in-situ net effective pressure using the earlier mentioned automated helium porosity-permeability measurement instrument. Net effective Pr, psi Pore volume, cc Porosity, % Permeability, mD

3,000 12.19 28.56 187.08

Table 14: Porosity and permeability (mD is millidarcy ) under full in-situ net effective pressure

Table 15 presents the differential pressures measured across the sample during the results of the in-situ brine permeability measurements conducted on the sample as part of stage (a) of the core-flooding procedure (prior to treatment with adsorption system)

Injection step

Injection phase Q, cc/hr Vol injected, cc dP, psi number

1 Brine 60 24.03 0.1

2 Brine 120 27.13 0.55

3 Brine 240 62.17 1.2

8 Brine 120 25.70 0.55

9 Brine 60 25.00 0.20

Table 15: Differential pressure across the rock sample at various flow rates used to calculate permeability to brine

Table 16 presents the results of the pre-treatment cyclical oil-brine flooding conducted on the sample in order to establish the baseline end-point relative permeabilities.

1st oil 7

1st brine 1.5

2nd oil 16

2nd brine 4.4

3rd oil 20

3rd brine 5.5

Table 16: Differential pressure across the rock sample for cyclical oil and brine injections used to calculate permeability to brine

After cyclic oil/brine injections to determine baseline permeability the rock is then treated with the adsorption system (same as example 6 and 7) including a surface modifying agent that is a water soluble polymer capable of bonding to the adsorption system (same as example 7). The treatment was added using an exchange piston and .6 times the pore volume of the core was successfully injected into the core sample. The differential pressure across the sample was again >2000 psi which is extremely high for a polymer injection which is evidence of strong adsorption to the rock surface.

Post Treatment Permeability Data

Reduction ratio to brine was measured previously to be 296 - determined as the point when the differential pressure across the rock is stable, without adsorbing to the surface the water soluble adsorption system would be flushed out. The final differential pressure recorded at the end of the day resulted in a permeability reduction ratio to oil of 9.3 - determined as the point when the differential pressure across the rock is stable

Example 9 - Core flooding with lower concentration of adsorption system

Previously when the adsorption system was injected, excessive differential pressures were encountered (>2000 psi) which can be attributed to the ability of the system to chemically adsorb to the surface. The pressure during injection cannot reach the overburden pressure (3500 psi) otherwise the experiment will fail. For this experiment the adsorption system was diluted to 25% of the original formulation given in example 6 with water, and the differential pressure was approximately 600 psi (compared to 2000 psi 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/hr with 600 psi differential pressure whereas previously 2 - 3 cc/hr was the maximum injection rate giving differential pressures >2000 psi. Figure 3 shows a substrate (301) having an adsorption layer (302) with polymer (303) as described, in the presence of brine (304) the polymer (303) is hydrated and expands across the pore space (left image); in the presence of oil (305) the polymer (303) collapses and the pore space is more accessible.

By diluting the adsorption system this layer cannot build up as quickly resulting in excessive differential pressures (>2000 psi) 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 to brine was 62 and to oil it was 14.5.

Example 10: Core flood experiment with different rock sample This experiment was performed 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 cores tested thus far (#1) were determined using XPS (Table 17). Core #1 is the same data as that shown in table 3 (control) and core #2 is the different core sample. As can be seen in table 16 calcium and magnesium are still present which we have identified as being involved in the adsorption mechanism. However, there is a significant quantity of surface silicon in the synthetic core (8.2%) versus no surface silicon in the actual cores which is likely to make a difference in how the adsorption system interacts with the surface. The presence of silicon is more in line with sandstone reservoirs. Element Core 1 Core 2

Fe 0 0.790

F 0 0.615

0 50.148 49.520

N 0 0.360

Ca 10.8 5.345

K 0 1.190

C 33.155 25.430

CI 0.110 1.245

Si 0 8.250

. Mg 5.700 3.230

Al 0 3.765

Table 17: Survey data measured by X Ray Photoelectron Spectroscopy (atomic percentage, %) for different reservoir core samples

The same sequence of injections was performed on this different core and the post treatment permeability data shows a reduction ratio to brine of 11 - and to oil it was 4.0. This demonstrates that the adsorption system is still effective even with lower calcium and magnesium and significant presence of silicon in the sample.

The cores were also assessed in terms of porosity and permeability and there were again key differences, as previous cores had a permeability of 200mD and 28% porosity whereas the different cores had a permeability of 420mD and 40% porosity. As described in figure 3 if the porosity is higher 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

1. A method of treating a subterranean 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 the silicate is added to the reservoir at a concentration of greater than 0% and up to 8% weight/volume.

2. The method of claim 1 , further comprising the addition of an amount of an organosilicon compound.

3. The method of claim 2, wherein the silicate or silicate containing molecule is reacted with the organosilicon compound before being added to the subterranean hydrocarbon reservoir.

4. The method of claims 2 or 3, wherein the organosilicon compound is an organosilane having the formula:

[R-(CH₂)]₄._n— Si— X_(n) where X is a hydrolyzable group selected from the group consisting of alkoxy, acyloxy, halogen or amine;

R is a nonhydrolyzable organic radical selected from the group consisting of alkyl, alkenyl, aryl, allyl, halogens, amines, sulphur functional groups, hydroxyl, aldehyde, epoxy, nitrobenzamide, cyano, pyridyl, azide, ester, isocyanate, phosphine, phosphate, or multifunctional or polymeric silanes; and n is 1 to 4.

5. The method of claim 4, wherein the organosilane is selected from the group consisting of: monomers, hydrolyzed monomers, hydrolyzed dimers, and hydrolyzed oligomers of: an aminopropyltrialkoxysilane, an aminoethylaminopropyltrialkoxysilane, an alkytrialkoxysilane, a vinyltrialkoxysilane, a phenyltrialkoxysilane,

mercaptotrialkoxysilane, a styrylaminotrialkoxysilane, a

methacryloxypropyltrialkoxysilane, a glycidoxypropyltrialkoxysilane, a

perfluorotrialkoxysllane, a perfluoroether functionalized trialkoxysilane, an azole functional trialkoxysilane, a tetraalkoxysilane, methyldiethylchlorosilane, dimethyldichlorosilane, methyltri-chlorosilane, dimethyl-dibromosilane, diethyldiiodosilane, dipropyldichlorosilane, dipropyldibromosilane,

butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane,

tolyltribromosilane, methylphenyldichlorosilane, or combinations thereof; or methyldiethylchlorosilane, dimethyldichlorosilane, methyltrichlorosilane, dimethyldibromosilane, diethyldiiodosilane, dipropyldichlorosilane,

dipropyldibromosilane, butyltrichlorosilane, phenyltribromosilane,

diphenyldichlorosilane, tolyltribromosilane, methylphenyldichlorosilane.

6. The method of claim 4, wherein the organosilane is an amino organosilane.

7. The method of any one of claims 2 to 6, further comprising the addition of an amount of a surface modifying agent.

8. The method of any one of the preceding claims, wherein the silicate or silicate containing molecule is added to the reservoir at a concentration of greater than 0.1 % and up to 5% weight/volume.

9. The method of claim 7, wherein the silicate or silicate containing molecule is added to the reservoir at a concentration of greater than 0.2% and up to 4%

weight/volume.

10. The method of any one of claims 2 to 9, wherein the organosilicon compound is added to the reservoir at a concentration of less than 1.Omol/L.

11. The method of claim 10 wherein the organosilicon compound is added to the reservoir at a concentration of between 0.05 and 0.2mol/L. 12. The method of any one of claims 7 to 11 wherein the surface modifying agent is added such that the ratio of active groups on the surface modifying agent to

organosilicon is from 1:1.5 to 1:5

13. A sample taken from a subterranean hydrocarbon reservoir, the sample comprising: a carbonate containing substrate having a layer of silicate or a silicate containing molecule that has chemically interacted with at least a portion of a surface of the carbonate containing substrate.

14. The sample of claim 13, further comprising an organosilicon compound that is covalently bonded to the silicate. 15. The sample of claim 14, wherein 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 nonhydrolyzable organic radical selected from the group consisting of alkyl, alkenyl, aryl, allyl, halogens, amines, sulphur functional groups, hydroxyl, aldehyde, epoxy, nitrobenzamide, cyano, pyridyl, azide, ester, isocyanate, phosphine, phosphate, or multifunctional or polymeric silanes; and n is 1 to 4.

16. The sample of claim 15, wherein the organosilane is selected from the group consisting of: monomers, hydrolyzed monomers, hydrolyzed dimers, and hydrolyzed oligomers of: an aminopropyltrialkoxysilane, an aminoethylaminopropyltrialkoxysilane, an alkytrialkoxysilane, a vinyltrialkoxysilane, a phenyltrialkoxysilane,

mercaptotrialkoxysilane, a styrylaminotrialkoxysilane, a

methacryloxypropyltrialkoxysilane, a glycidoxypropyltrialkoxysilane, a

perfluorotrialkoxysilane, a perfluoroether functionalized trialkoxysilane, an azole functional trialkoxysilane, a tetraalkoxysilane, methyldiethylchlorosilane, dimethyldichlorosilane, methyltri-chlorosilane, dimethyl-dibromosilane, diethyldiiodosilane, dipropyldichlorosilane, dipropyldibromosilane,

butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane,

dipropyldibromosilane, butyltrichlorosilane, phenyltribromosilane,

diphenyldichlorosilane, tolyltribromosilane, methylphenyldichlorosilane.

17. The sample of claim 15, wherein the organosilane is an amino organosilane.

18. The sample of any one of claims 14 to 17, further comprising a surface modifying agent that is covalently bonded to the organosilicon compound.

19. A subterranean hydrocarbon reservoir comprising: a carbonate containing substrate which has been treated and has a layer of silicate or a silicate containing molecule chemically interacted with at least a portion of a surface of the carbonate containing substrate.

20. The subterranean hydrocarbon reservoir of claim 19, further comprising an organosilicon compound that is covalently bonded to the silicate.

21. The subterranean hydrocarbon reservoir of claim 19, wherein the organosilicon compound is an organosilane having the formula: [R^— (CH₂)]₄__n— Si— X_(n) where X is a hydrolyzable group selected from the group consisting of alkoxy, acyloxy, halogen or amine;

22. The subterranean hydrocarbon reservoir of claim 21 , wherein the organosilane is selected from the group consisting of: monomers, hydrolyzed monomers, hydrolyzed dimers, and hydrolyzed oligomers of: an aminopropyltrialkoxysilane, an aminoethylaminopropyltrialkoxysilane, an alkytrialkoxysilane, a vinyltrialkoxysilane, a phenyltrialkoxysilane,

mercaptotrialkoxysilane, a styrylaminotrialkoxysilane, a

methacryloxypropyltrialkoxysilane, a glycidoxypropyltrialkoxysilane, a

butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane,

tolyltribromosilane, methylphenyldichlorosilane, or combinations thereof; or methyldiethylchlorosilane, dimethyldichlorosilane, methyltrichlorosilane, dimethyldibromosilane, diethyldiipdosilane, dipropyldichlorosilane,

dipropyldibromosilane, butyltrichlorosilane, phenyltribromosilane,

diphenyldichlorosilane, tolyltribromosilane, methylphenyldichlorosilane. <23. The subterranean hydrocarbon reservoir of claim 21 , wherein the organosilane is an amino organosilane.

24. The subterranean hydrocarbon reservoir of any one of claims 20 to 23, further comprising a surface modifying agent that is covalently bonded to the organosilicon compound. 25. A composition to treat subterranean 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 carbonate containing substrate; an amount of an organosilicon compound; wherein the silicate or silicate containing material may be chemically reacted with the organosilicon compound.

26. The composition of claim 25 wherein the silicate or silicate containing molecule includes an anion having at least one silicon-oxygen bond.

27. The composition of any one of claims 25 or 26, wherein the organosilicon compound is an organosilane having the formula:

[R-(CH₂)]₄._n— Si— X_(n) where X is a hydrolyzable group selected from the group consisting of alkoxy, acyloxy, halogen or amine; R is a nonhydrolyzable organic radical selected from the group consisting of alkyl, alkenyl, aryl, allyl, halogens, amines, sulphur functional groups, hydroxyl, aldehyde, epoxy, nitrobenzamide, cyano, pyridyl, azide, ester, isocyanate, phosphine, phosphate, or multifunctional or polymeric silanes; and n is 1 to 4.

28. The composition of claim 27, wherein the organosilane is selected from the group consisting of: monomers, hydrolyzed monomers, hydrolyzed dimers, and hydrolyzed oligomers of: an aminopropyltrialkoxysilane, an aminoethylaminopropyltrialkoxysilane, an alkytrialkoxysilane, a vinyltrialkoxysilane, a phenyltrialkoxysilane,

mercaptotrialkoxysilane, a styrylaminotrialkoxysilane, a

methacryloxypropyltrialkoxysilane, a glycidoxypropyltrialkoxysilane, a

butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane,

dipropyldibromosilane, butyltrichlorosilane, phenyltribromosilane,

diphenyldichlorosilane, tolyltribromosilane, methylphenyldichlorosilane.

29. The composition of any one of claim 27, wherein the organosilane is an amino organosilane.

30. The composition of any one of claims 25 to 29, further comprising an amount of a surface modifying agent that may or may not be covalently bound with the organosilicon compound.