WO2019025810A1

WO2019025810A1 - Crosslinked polymer microparticles for use in conformance control

Info

Publication number: WO2019025810A1
Application number: PCT/GB2018/052221
Authority: WO
Inventors: Ian Ralph Collins
Original assignee: BP Exploration Operating Co Ltd
Current assignee: BP Exploration Operating Co Ltd
Priority date: 2017-08-03
Filing date: 2018-08-02
Publication date: 2019-02-07
Anticipated expiration: 2020-02-03
Also published as: AR112404A1; GB201712475D0

Abstract

The present invention relates to expandable polymeric microparticles comprising cross-linked copolymer chains having structural units derived from (i) a water-soluble or water-dispersible monomer with a betaine group, (ii) a water-soluble or water-dispersible non- ionic comonomer, and, (iii) a water-soluble or water-dispersible non-labile cross-linking monomer having at least two sites of ethylenic unsaturation wherein the copolymer chains of the polymeric microparticles comprise from 9.5 to 45 mol% of structural units derived from the betaine monomer and from 0.1 to 10 mol% of structural units derived from the non-labile cross-linking monomer; the polymeric microparticles have an unexpanded average particle diameter in the range from 0.05 to 5 µm and wherein the polymeric microparticles expand in size when dispersed in an aqueous fluid at or above a transition temperature.

Description

CROSSLINKED POLYMER MICROPARTICLES FOR USE

IN CONFORMANCE CONTROL

This invention relates to a method of modifying the permeability of a thief zone of a subterranean petroleum reservoir to water.

The invention also relates to a composition for use in a method of modifying the permeability to water of a thief zone of a subterranean petroleum reservoir, the composition comprising a dispersion of temperature sensitive polymeric microparticles in either a water-in- oil emulsion or in a continuous oil phase wherein the polymeric microparticles expand in size at above a threshold temperature.

Processes for modifying the permeability to water of subterranean petroleum reservoirs are particularly useful in the field of recovery of hydrocarbon fluids, for example, crude oil from a petroleum reservoir.

Crude oil may be recovered from a petroleum reservoir via natural pressure in the reservoir forcing hydrocarbon fluids towards production wells where they can flow or are pumped to a surface production facility (referred to as "primary recovery"). However, reservoir pressure is generally sufficient only to recover around 10 to 20 per cent of the total hydrocarbon present in a subterranean petroleum reservoir. Accordingly "secondary recovery" techniques are applied to recover hydrocarbon from subterranean reservoirs in which the hydrocarbon fluids no longer flow by natural forces.

Secondary recovery relies on the supply of external energy to maintain the pressure in a subterranean petroleum reservoir and to sweep hydrocarbon fluids towards a production well. One such technique involves the injection of water (such as aquifer water, river water, estuarine water, seawater, or a produced water) into the petroleum reservoir via one or more injection wells to drive the hydrocarbon fluids towards one or more production wells. The injection of water during secondary recovery is commonly referred to as water flooding.

Enhanced Oil Recovery (EOR) processes involve injecting an aqueous fluid into a petroleum reservoir that is formulated to increase recovery of hydrocarbon fluids over that which would be achieved by water injection alone. The processes employed during EOR can be initiated at any time during the productive life of a petroleum reservoir. If an EOR process is employed in secondary recovery, the aqueous fluid supplies the external energy to maintain the pressure of the reservoir as well as increasing recovery of hydrocarbon fluids over that which would be achieved by water injection alone. If an EOR process is employed in tertiary recovery, injection of the original aqueous fluid used in secondary recovery is stopped and a different aqueous fluid is injected into the petroleum reservoir that is formulated to increase recovery of hydrocarbon fluids over that which would be achieved with the original water alone. Thus, the purpose of EOR is not only to restore reservoir pressure and to sweep oil towards a production well, but also to improve oil displacement or fluid flow in the reservoir.

The efficiency of water flooding techniques depends on a number of variables, including the permeability of the reservoir rock and the viscosity of the hydrocarbon fluids in the reservoir.

A prevalent problem with secondary and tertiary recovery projects relates to the heterogeneity of the reservoir rock strata. Natural variations in the permeability of different zones (layers or areas) of a subterranean petroleum reservoir means that the injected aqueous fluid tends to travel most easily in, and therefore preferentially sweeps, the highest permeability zones (i.e. the injected aqueous fluid follows the lowest resistance path from the injection well to the production well), thereby potentially by-passing much of the hydrocarbon fluid present in lower permeability zones of the reservoir. Once the highest permeability zones are thoroughly swept they tend to accept most of the injected aqueous fluid and act as "thief zones". In such cases the injected aqueous fluid does not effectively sweep the hydrocarbon fluid from neighboring, lower permeability zones of the reservoir.

Herein, the term 'thief zone' refers to any region of high permeability relative to the permeabilities of the surrounding rock, such that a high proportion of the injected aqueous fluid flows through these regions. Such thief zones typically cannot be characterized by absolute values of permeability as the problem arises as a result of heterogeneity in the permeability of the reservoir rock; thus, a thief zone may simply be a region of higher permeability than the majority of the reservoir rock.

In order to improve sweep efficiency, these 'thief zones' can be partially or totally blocked deep in the reservoir, generating a new pressure gradient and diverting flow of subsequently injected aqueous fluid into lower permeability zones (layers or areas) of the reservoir with high hydrocarbon fluid (oil) saturation. Herein, sweep efficiency is taken to mean a measure of the effectiveness of a secondary or tertiary oil recovery process that depends on the proportion of the volume of the pore space of the reservoir contacted by the injected aqueous fluid.

Flow diversion involves changing the path of the injected aqueous fluid through the reservoir so that it contacts and displaces more hydrocarbon fluid (oil). Various physical and chemical treatment methods have been used to divert injected aqueous fluids from thief zones.

A few "deep reservoir flow diversion" processes have been developed with the aim of reducing the permeability in a substantial proportion of the thief zone at a significant distance from the injection and production wells. The use of swellable cross-linked superabsorbent polymer microparticles for modifying the permeability of subterranean formations is disclosed in U.S. Pat. Nos. 5,465,792 and 5,735,349.

Deep reservoir flow diversion may also be achieved by injecting polymeric

microparticles comprising polymeric chains linked together via thermally labile hydrolysable cross-linkers and non-thermally labile cross-linkers, as disclosed in U.S. Pat. Nos. 6,454,003, 6,729,402, 6,984,705 and 7,300,973. The suspension of microparticles travels through the thief zones and is progressively heated to a temperature at which the thermally labile cross- linkers hydrolyze and are broken and the microparticles absorb water, swell and block the pores of the reservoir rock. The permeability of the thief zone is thereby reduced and subsequently injected fluid is diverted into the lower permeability zones to displace hydrocarbon fluids towards a producing well. However, a feature of these expandable microparticles is that the block is permanent. In other words, the microparticles have no ability to shrink back to their original size and move to another location in the reservoir matrix rock and then re-expand to form a further block.

GB 2 262 117A describes certain latex microparticles that are temperature sensitive and reversibly flocculate, shrink and harden at higher temperatures, and disperse, expand and soften at lower temperatures and that these can form effective blocking agents in the presence of an ionic compound, in a petroleum reservoir. An advantage of the latex microparticles of GB 2 262 117A is that the block is reversible. This is because the microparticles deflocculate as the reservoir matrix cools in the vicinity of the original block such that the deflocculated microparticles become redispersed in the injection water and the resulting dispersion can propagate through the formation to set up a subsequent block deeper within the formation where the temperature is sufficiently high to promote reflocculation, shrinkage and hardening of the latex microparticles. However, a problem with the dispersions of GB 2 262 117A is that they are produced at the desired particle concentration for the fluid that is to be injected into the reservoir. Large amounts of the dispersion of GB 2 262 117 A would be required for the treatment of a reservoir. Accordingly, the cost of handling and shipping the required volume of dispersion renders the treatment uneconomic. Accordingly, the method of GB 2 262 117A has yet to be commercially deployed.

It has been reported (Schulz, D. N.; Peiffer, D. G.; Agarwal, P. K.; Larabee, J.;

Kaladas, J. J.; Soni, L.; Handwerker, B.; Garner, R. T. Polymer 1986, 27, 1734 and Huglin, M. B.; Radwan, M. A. Polymer International 1991, 26, 97) that polysulfobetaines exhibit temperature responsive solubility in aqueous fluids and have an Upper Critical Solution Temperature (UCST) above which the polysulfobetaines transition from being insoluble to soluble in water.

A synthetic method for the preparation of particles having a low level of incorporation of sulfobetaine groups (up to 8%) is disclosed in "Zwitterionic Poly(betaine-N- isopropylacrylamide) Microgels: Properties and Applications", Das, M.; Sanson, N.;

Kumacheva, E. Chemistry of Materials 2008, 20, 7157). The behaviour of these particles is dominated by the properties of the non-betainised structural units (units derived from N- isopropylacrylamide) such that the particles exhibit Lower Critical Solution Temperature (LCST) behaviour not UCST behaviour.

It has also been reported (Arjunan Vasantha, V.; Junhui, C; Ying, T. B.; Parthiban, A. Langmuir 2015, 31, 11124 and Vasantha, V. A.; Jana, S.; Parthiban, A.; Vancso, J. G. RSC Advances 2014, 4, 22596) that linear polysulfabetaines exhibit temperature responsive behavior in aqueous fluids.

The use of reversible addition-fragmentation chain transfer (RAFT) polymerization- induced self-assembly for the synthesis of UCST nanogels composed of a cross-linked poly(3- dimethyl(methacryloyloxyethyl)ammonium propane sulfonate (PDMAPS) core and a poly(poly(ethylene glycol)methyl ether methacrylate (PPEGMMA) corona has been reported (Wenix Fu, Chunhui Luo, Emily A Morin, Wei He, Zhibo Li and Bin Zhao, ACS Macro Lett. 2017, 6, 127-133). PPEGMMA with a dithiobenzoate end-group was used as a chain-transfer agent to polymerize DMAPS in a mixture of H₂0 and a water-miscible organic solvent

(ethanol or THF) with N,N'-methylenebis(acrylamide) (MBAc) as cross-linker. Although, the particles exhibit an UCST and are reported to swell and shrink when dispersed in water, the increase in particle size is relatively small. There is also no report of the particles forming aggregates. Accordingly, the reported nanogels are not suitable for use in blocking thief zones of a reservoir.

It is an object of the present invention to provide a method which overcomes or at least mitigates the disadvantages associated with conventional methods for reducing the permeability of a thief zone and in particular to increase or improve the recovery of hydrocarbon fluids from a reservoir.

According to the present invention there is provided a process for recovering

hydrocarbon fluids from a porous and permeable subterranean petroleum reservoir comprising at least one higher permeability zone and at least one lower permeability zone that are penetrated by at least one injection well and at least one production well, the process comprising:

a) injecting a dispersion of expandable polymeric microparticles in an aqueous fluid into the higher permeability zone of the reservoir from the injection well or from the production well wherein the expandable polymeric microparticles comprise cross- linked copolymer chains having structural units derived from (i) a water-soluble or water-dispersible monomer with a betaine group (hereinafter "betaine monomer"), (ii) a water-soluble or water-dispersible non-ionic comonomer (hereinafter "non-ionic comonomer"), and, (iii) a water-soluble or water-dispersible non-labile cross-linking monomer having at least two sites of ethylenic unsaturation (hereinafter "cross-linking monomer") wherein the copolymer chains of the polymeric microparticles comprise from 9.5 to 45 mol% of structural units derived from the betaine monomer and from 0.1 to 10 mol% of structural units derived from the cross-linking monomer (based on the total molar amount of structural units in the copolymer chains) and wherein the polymeric microparticles have an unexpanded average particle diameter in the range of 0.05 to 5 μηι and expand in size at a temperature at or above a transition temperature and wherein the injection well has a maximum temperature below the transition temperature and the higher permeability zone has a region between the injection well and production well having a temperature at or above the transition temperature;

b) propagating the dispersion through the higher permeability zone until the dispersion reaches the region of the higher permeability zone having the temperature at or above the transition temperature such that the polymeric microparticles expand in size thereby reducing the permeability of the higher permeability zone of the reservoir; c) diverting subsequently injected aqueous fluid from the higher permeability zone into the lower permeability zone of the reservoir; and

d) recovering hydrocarbon fluids from said at least one production well.

In the event that the dispersion of polymeric microparticles is injected into the higher permeability zone from the production well, the person skilled in the art will understand that the production well is taken off production before the dispersion is injected down the production well and into the higher permeability zone of the reservoir.

The polymeric microparticles of the dispersion are temperature responsive

microparticles which exhibit a change in solvation and consequently an increase in particle size when dispersed in water at a temperature at or above the transition temperature. The expanded microparticles may then aggregate to form aggregates thereby aiding the formation of a block to water in the thief zone.

The initial (unexpanded) size of the polymeric microparticles employed in the method of the present invention should be such that, prior to encountering a temperature within the thief zone (the higher permeability zone) that is at or greater than the transition temperature of the polymeric microparticles, efficient propagation of the composition through the pore structure of the reservoir rock, such as sandstone or carbonate, can be achieved. Thus, the polymeric microparticles may propagate through low temperature regions of the thief zone (the higher permeability zone) of the reservoir substantially unimpeded. Preferably, the average particle diameter of the unexpanded microparticles is in the range of 0.05 to 2 μηι, for example, 0.1 to 1 μιη.

Once the dispersion reaches a region of the thief zone (the higher permeability zone), having a temperature at or above the transition temperature, the polymeric microparticles become solvated and expand in size. Typically, the expanded microparticles then aggregate. Preferably, the ratio of the average particle diameter of the individual expanded microparticles to the average particle diameter of the unexpanded individual microparticles is at least 2: 1 preferably, at least 3: 1. Preferably, the ratio of the volume of the individual expanded microparticles to the initial volume of the unexpanded individual microparticles is at least 5: 1, preferably, at least 10: 1, more preferably, at least 20: 1.

Suitably, the aggregates of expanded microparticles have an average particle diameter of at least 1000 nm, preferably, at least 2000 nm. Preferably, the aggregates of expanded microparticles have an average particle diameter in the range of 1000 to 10000 nm.

Without wishing to be bound by any theory, the temperature at which the individual microparticles begin to expand may be below the temperature at which the polymeric microparticles begin to aggregate, for example, may be 10°C below the aggregation temperature. Accordingly, by "transition temperature" is meant the temperature at which aggregates are formed, for example, as determined in a laboratory experiment.

Suitably, the region of the thief zone (higher permeability zone), having a temperature above the transition temperature, is not so close to the injection well as to reduce injectivity of the dispersion and not so close to the production well that only a minor portion of the thief zone (higher permeability zone) of the reservoir is swept by the subsequently injected aqueous fluid. Preferably, the region of the thief zone having a temperature above the transition temperature is at least several metres, in particular, at least 10 metres from the injection well or production well. Typically, aqueous injection fluids are at a lower temperature than the petroleum (hydrocarbon) reservoir such that a previously injected aqueous fluid cools the reservoir giving rise to a temperature front in the reservoir which typically increases in radial distance from the injection well over time. The temperature front in the higher permeability zone (thief zone) is likely to be ahead of the temperature front in the lower permeability zone of the reservoir owing to the higher amounts of injected aqueous fluid that permeate through the thief zone. The region of the thief zone that is at a temperature at or above the transition temperature is preferably beyond the temperature front in the thief zone.

Suitably, in the process of the present invention, the maximum temperature in the well (from which the dispersion is injected into the higher permeability zone) is 30°C or less, preferably 25°C or less. Preferably, the dispersion is injected into the well at a temperature in the range of 4 to 25°C. Suitably, the dispersion injected into the well comprises polymeric microparticles with a transition temperature of at least 30°C when dispersed in the aqueous fluid of the dispersion.

The process of the present invention is particularly suitable for the recovery of hydrocarbon fluids, in particular, crude oil, from subterranean petroleum reservoirs containing at least one high permeability zone between said at least one injection well and said at least one production well having a region with a temperature of at least 30°C, preferably, at least 40°C, more preferably, at least 50°C, in particular, 60°C or greater with the proviso that the temperature is greater than the transition temperature for the polymeric microparticles of the dispersion.

Without wishing to be bound by any theory, the transition temperature of the polymeric microparticles of the dispersion used in the process of the present invention may be adjusted to match the temperature conditions encountered in the thief zone of a particular reservoir by:

(a) varying the amount of structural units derived from the betaine monomer in the cross- linked copolymer chains (the transition temperature was found to increase with increasing amounts of structural units in the cross-linked copolymer chains derived from the betaine monomer);

(b) varying the chemical structure of the units derived from the betaine monomer; or

(c) by changing the type of non-ionic comonomer used in the preparation of the polymeric microparticles.

Preferably, the amount of structural units derived from the betaine monomer in the copolymer chains of the polymeric microparticles is in the range of from 10 to 40 mol%, more preferably, from 15 to 35 mol% , most preferably from 20 to 35 mol% (based on the total molar amount of structural units in the copolymer chains). Microparticles comprising copolymer chains with these amounts of structural units derived from a betaine monomer typically have transition temperatures in the range of 15 to 90°C, preferably 20 to 90°C, in particular 30 to 80°C. Thus, microparticles are selected having cross-linked copolymer chains having a mol% of structural units derived from the betaine monomer (based on the total molar amount of structural units in the copolymer chains) that provides a transition temperature for the polymeric microparticles that matches the temperature in the region of the high

permeability zone between the injection well and production well.

In the method of the present invention, most of the composition comprising the polymeric microparticles dispersed in an aqueous fluid will enter the thief zone of the reservoir since the composition will follow the most permeable and/or lowest pressure route or routes from the injection well to an associated production well. When the polymeric microparticles expand and aggregate in the region of the thief zone having a temperature at or above the transition temperature, they form a block to water. Thus, the permeability of water through the block of expanded and aggregated microparticles is lower than the permeability of water through neighbouring zones of the reservoir such that subsequently injected aqueous fluid (water injected into the reservoir after the dispersion) is largely diverted out of the thief zone and into neighbouring zones.

Advantageously, aggregation of the polymeric microparticles may be reversible such that cooling of the thief zone in the location of the block to a temperature below the transition temperature may result in disaggregation of the polymeric microparticles. Expansion of the polymeric microparticles may also be reversible such that cooling of the thief zone in the location of the block to a temperature below the transition temperature results in desolvation of the polymeric microparticles and consequently contraction (shrinkage) of the polymeric microparticles.

The person skilled in the art will understand that cooling of the thief zone in the location of the block may occur due to a subsequently injected water flowing through neighbouring zones of the reservoir such that the temperature front in the neighbouring zones advances through the reservoir until it is adjacent the region of the thief zone containing the block thereby cooling the thief zone in the location of the block. Accordingly, the disaggregated and contracted microparticles may become redispersed in water and the resulting dispersion may permeate through the thief zone until it reaches another location (region) where the

temperature is at or above the transition temperature where the polymeric microparticles again expand in size and aggregate. These steps of expansion, aggregation, disaggregation, contraction and redispersion may occur a plurality of times within the thief zone, thereby allowing a greater volume of the reservoir to be swept by the subsequently injected water.

In a further aspect of the present invention, there is provided a dispersion of polymeric microparticles in an aqueous fluid wherein the polymeric microparticles comprise cross-linked copolymer chains having structural units derived from (i) a water-soluble or water-dispersible monomer with a betaine group, (ii) a water-soluble or water-dispersible non-ionic comonomer, and, (iii) a water-soluble or water-dispersible non-labile cross-linking monomer having at least two sites of ethylenic unsaturation and wherein the copolymer chains of the polymeric microparticles have from 9.5 to 45 mol% of structural units derived from the monomer with the betaine group and from 0.1 to 10 mol% of structural units derived from the non-labile cross-linking monomer (based on the total molar amount of structural units in the copolymer chains); and, wherein the polymeric microparticles have an unexpanded average particle diameter in the range from 0.05 to 5 μηι and the polymeric microparticles expand in size and aggregate at or above a transition temperature.

The person skilled in the art will understand that the term "aqueous fluid" as used herein is intended to mean any water or aqueous solution suitable for use in a water flooding process in either secondary or tertiary (EOR) recovery mode.

The dispersion of polymeric microparticles in the aqueous fluid is of relatively low viscosity and can be injected into the porous and permeable subterranean petroleum reservoir at relatively low injection pressures, with the proviso that the injection pressure is maintained above the pressure within the pore space of the subterranean reservoir.

In yet a further aspect of the present invention, there is provided polymeric

microparticles comprising cross-linked copolymer chains having structural units derived from (i) a water-soluble or water-dispersible betaine monomer, (ii) a water-soluble or water- dispersible non-ionic comonomer, and, (iii) a water-soluble or water dispersible non-labile cross-linking monomer having at least two sites of ethylenic unsaturation and wherein the copolymer chains of the polymeric microparticles have from 9.5 to 45 mol% of structural units derived from the monomer with the betaine group and from 0.1 to 10 mol% of structural units derived the non-labile cross-linking monomer (based on the total molar amount of structural units in the copolymer chains); and, wherein the polymeric microparticles have an unexpanded (initial) average particle diameter in the range of 0.05 to 5 μηι and the polymeric

microparticles expand in size and aggregate when dispersed in an aqueous fluid at or above a transition temperature.

In accordance with a preferred embodiment of the invention, the polymeric

microparticles may be prepared by an inverse emulsion polymerization process in order to control the particle size distribution of the polymeric microparticles. An inverse emulsion polymerisation process is a polymerization process in which an aqueous solution of at least one water-soluble monomer is added to an oil phase containing at least one water-in-oil emulsifying agent that stabilizes the inverse emulsion. The resulting emulsion consists of a discontinuous phase (also referred to as "disperse phase") comprising small droplets of the aqueous solution of the water-soluble monomer dispersed in a continuous oil phase wherein the droplets typically have a diameter of in the range of 0.05 to 5 microns in particular less than 2 microns. Typically, the emulsion polymerization occurs with the application of shear. As discussed in more detail below, the size of the droplets of the aqueous phase (and hence the size of the polymeric microparticles) may be controlled by adjusting the shear energy applied when forming the inverse emulsion or by adjusting the amount and type of surfactant(s) used to stabilize the inverse emulsion. Typically, the more shear energy introduced during the emulsifi cation process (e.g. via ultra-high shear mixing) the smaller the droplets of the dispersed aqueous phase.

Thus, in yet a further aspect of the present invention, there is provided a method for preparing the expandable polymeric microparticles by inverse emulsion polymerization of (i) a water-soluble or water-dispersible monomer with a betaine group ("betaine monomer"), (ii) a water-soluble or water-dispersible non-ionic comonomer (non-ionic comonomer") and (iii) a cross-linking monomer having at least two sites of ethylenic unsaturation ("cross-linking monomer") in the presence of a radical initiator wherein droplets of an aqueous phase comprising an aqueous solution or dispersion of monomers (i), (ii) and (iii) are dispersed in a continuous oil phase comprising an organic solvent or mixture of organic solvents and wherein the droplets of the aqueous phase have an average diameter in the range of 0.05 to 5 μηι and wherein the betaine monomer comprises from 9.5 to 45 mol% and the cross-linking monomer from 0.1 to 10 mol% of the total moles of monomers.

Accordingly, the inverse emulsion polymerization reaction mixture comprises:

(a) an aqueous phase comprising an aqueous solution of at least one betaine monomer, at least one non-ionic comonomer, and at least cross-linking monomer; and

(b) an oil phase comprising a solution of at least one conventional surfactant for stabilizing a water-in-oil emulsion (i.e., a water-in-oil emulsifying agent) in an organic solvent wherein the organic solvent is immiscible with the aqueous phase (or is sparingly soluble in the aqueous phase).

Preferably, the oil phase comprises a solution of a mixture of surfactants in the organic solvent wherein the mixture of surfactants comprise:

(i) at least one surfactant selected from the group consisting of sorbitan ester surfactants having hydrophilic-lipophilic balance (HLB) values in the range of 4 to 9;

(ii) at least one surfactant selected from the group consisting of ethoxylated sorbitan esters

(also known in the art as polysorbates) having HLB values in the range of 14 to 20; and

(iii) at least one amphiphilic block copolymer surfactant.

The sorbitan ester surfactant is preferably a sorbitan monoester of a fatty acid

(hereinafter "sorbitan monoester surfactant"). Examples of suitable sorbitan monoester surfactants include sorbitan monolaurate (HLB = 8.6), sorbitan monopalmitate (HLB = 6.7), sorbitan monostearate (HLB = 4.7), and sorbitan oleate (HLB = 4.3).

The ethoxylated sorbitan ester surfactant is preferably an ethoxylated sorbitan monoester of a fatty acid (hereinafter "ethoxylated sorbitan monoester surfactant". Examples of suitable ethoxylated sorbitan monoester surfactants include polyoxy ethylene sorbitan monolaurate (HLB = 16.7), polyoxyethylene sorbitan monopalmitate (15.6), polyoxyethylene sorbitan monostearate (HLB = 14.9) and polyoxyethylene sorbitan monooleate (HLB = 15.0).

The amphiphilic block copolymer surfactant may be selected from:

(a) amphiphilic block copolymer surfactants having a block of a poly(alkylacrylate) and a block of poly(acrylate), for example, block copolymers having a block of

poly(alkylacrylate) selected from poly(octylacrylate), poly(decylacrylate) and

poly(dodecyl acrylate) and a block of poly(acrylate);

(b) amphiphilic block copolymer surfactants having a block of a poly(hydroxyalkanoic acid) selected from poly(hydroxystearic acid) and poly(hydroxylauric acid) and a block of a poly(alkylene oxide) selected from poly(ethylene oxide), poly(propylene oxide), and poly(ethylene oxide-co-propylene oxide); and

(c) a mixture of at least one amphiphilic block copolymer surfactant of class (a) and at least one amphiphilic block copolymer surfactant of class (b).

Preferred amphiphilic block copolymer surfactants of class (a) have a block of poly(octylacrylate) and a block of poly (aery late). Preferred amphiphilic block copolymer surfactants of class (b) have a block of poly(hydroxystearic acid) and a block of poly(ethylene oxide).

Preferably, the surfactant(s) comprise from 0.5 to 10%, more preferably from 1 to 5% by weight of the inverse emulsion.

The water-immiscible organic solvent is preferably a hydrocarbon solvent or mixture of hydrocarbon solvents containing less than 2% by weight of aromatics and having a boiling point higher than the temperature for the polymerization reaction. The solvent is preferably selected from liquid n-alkanes, liquid iso-alkanes, liquid cycloalkanes and mixtures thereof. Suitable solvents include hexane, heptane, octane, nonane, decane, 2-methylhexane

(isoheptane), 2,2,4-trimethylpentane (isooctane), cyclohexane, cycloheptane, and mixtures thereof. Alternative solvents include halocarbons such as dichloromethane, kerosene, mineral oils and Isopar M (produced by treating petroleum based raw materials with hydrogen in the presence of a catalyst and comprising mainly normal alkanes, isoalkanes and cycloalkanes) sold by ExxonMobil Chemical Company.

The inverse emulsion preferably comprises between 10 and 50 percent by weight, more preferably, 20 to 40 percent by weight, in particular, 25 to 45 percent by weight of the aqueous phase.

The person skilled in the art will understand that the mol% of structural units derived from the various monomers in the copolymer chains of the polymeric microparticles will correspond to the mol% of the various monomers in the inverse emulsion polymerization reaction mixture. Thus, the amount of structural units derived from the betaine monomer in the copolymer chains may be increased by increasing the mol% of this monomer in the inverse emulsion polymerization reaction mixture (based on the total moles of monomer).

The betaine monomer may be any water-soluble or water-dispersible vinyl monomer having the formulae:

CH₂=C(R)C(0)OR₂N⁺R'R"R₃X^" (I); or

CH₂=C(R)C(0)NHR₂N⁺R'R"R₃X^" (II)

wherein R is selected from hydrogen and an alkyl group having from 1 to 3 carbon atoms, preferably, methyl;

R₂ and R3 are alkylene groups, in particular, C₂ to Ce alkylene groups, and are preferably independently selected from the group consisting of ethylene, n-propylene or n-butylene groups;

R' and R' ' are independently selected from alkyl groups having from 1 to 3 carbon atoms, preferably, methyl and ethyl, most preferably methyl; or N⁺, R' and R' ' together form a saturated heterocyclic ammonium ring, optionally, having an oxygen heteroatom in the ring, preferably, a piperidinium or morpholinium ring; and

X is selected from sulfo (-S0₃ ^"), carboxy (-COO^"), sulfa (-OSO3^"), phospho (-OPO3^") and phosphonate (-PO₃ ) groups.

Examples of preferred sulfobetaine vinyl monomers of formula (I) include:

N,A^-dimethyl(methacryloyloxyethyl)ammonium propane sulfonate,

N,A^-diethyl(methacryloyloxyethyl)ammonium propane sulfonate, N,A^-dimethyl(methacryloyloxyethyl)ammonium ethane sulfonate,

N,A^-diethyl(methacryloyloxyethyl)ammonium ethane sulfonate,

N,A^-dimethyl(methacryloyloxyethyl)ammonium butane sulfonate, and

N,A^-diethyl(methacryloyloxyethyl)ammonium butane sulfonate.

A most preferred sulfobetaine vinyl monomer of formula (I) is

dimethyl(methacryloyloxyethyl)ammonium propane sulfonate (DMAPS).

Examples of preferred carboxybetaine vinyl monomers of formula (I) include: N,A^-dimethyl(methacryloyloxyethyl)ammonium propane carboxylate,

N,A^-diethyl(methacryloyloxyethyl)ammonium propane carboxylate,

N,A^-dimethyl(methacryloyloxyethyl)ammonium ethane carboxylate,

N,A^-diethyl(methacryloyloxyethyl)ammonium ethane carboxylate,

N,A^-dimethyl(methacryloyloxyethyl)ammonium butane carboxylate, and

N,A^-diethyl(methacryloyloxyethyl)ammonium butane carboxylate.

Examples of preferred sulfabetaine vinyl monomers of formula (I) include:

N,A^-dimethyl(methacryloyloxyethyl)ammonium propane sulfate,

N,A^-diethyl(methacryloyloxyethyl)ammonium propane sulfate,

N,A^-dimethyl(methacryloyloxyethyl)ammonium ethane sulfate,

N,A^-diethyl(methacryloyloxyethyl)ammonium ethane sulfate,

N,A^-dimethyl(methacryloyloxyethyl)ammonium butane sulfate, and

N,A^-diethyl(methacryloyloxyethyl)ammonium butane sulfate.

Examples of preferred phosphobetaine vinyl monomers of formula (I) include: N,A^-dimethyl(methacryloyloxyethyl)ammonium propane phosphate,

N,A^-diethyl(methacryloyloxyethyl)ammonium propane phosphate,

N,A^-dimethyl(methacryloyloxyethyl)ammonium ethane phosphate,

N,A^-diethyl(methacryloyloxyethyl)ammonium ethane phosphate,

N,A^-dimethyl(methacryloyloxyethyl)ammonium butane phosphate, and

N,A^-diethyl(methacryloyloxyethyl)ammonium butane phosphate.

Examples of preferred phosphonate vinyl betaine monomers of formula (I) include: N,A^-dimethyl(methacryloyloxyethyl)ammonium propane phosphonate, N,A^-diethyl(methacryloyloxyethyl)ammonium propane phosphonate,

N,A^-dimethyl(methacryloyloxyethyl)ammonium ethane phosphonate,

N,A^-diethyl(methacryloyloxyethyl)ammonium ethane phosphonate,

N,A^-dimethyl(methacryloyloxyethyl)ammonium butane phosphonate, and

N,A^-diethyl(methacryloyloxyethyl)ammonium butane phosphonate.

Examples of preferred sulfobetaine vinyl monomers of formula (II) include: N,A^-dimethyl(methacrylamide propyl)ammonium propane sulfonate,

N,iV-diethyl(methacrylamide propyl)ammonium propane sulfonate,

N,A^-dimethyl(methacrylamide propyl)ammonium ethane sulfonate,

N,iV-diethyl(methacrylamide propyl)ammonium ethane sulfonate,

N,A^-dimethyl(methacrylamide propyl)ammonium butane sulfonate, and

N,iV-diethyl(methacrylamide propyl)ammonium butane sulfonate.

Examples of preferred carboxybetaine vinyl monomers of formula (II) include: N,A^-dimethyl(methacrylamide propyl)ammonium propane carboxylate,

N,iV-diethyl(methacrylamide propyl)ammonium propane carboxylate,

N,A^-dimethyl(methacrylamide propyl)ammonium ethane carboxylate,

N,iV-diethyl(methacrylamide propyl)ammonium ethane carboxylate,

N,A^-dimethyl(methacrylamide propyl)ammonium butane carboxylate, and

N,iV-diethyl(methacrylamide propyl)ammonium butane carboxylate.

Examples of preferred sulfabetaine vinyl monomers of formula (II) include: N,A^-dimethyl(methacrylamide propyl)ammonium propane sulfate,

N,iV-diethyl(methacrylamide propyl)ammonium propane sulfate,

N,A^-dimethyl(methacrylamide propyl)ammonium ethane sulfate,

N,iV-diethyl(methacrylamide propyl)ammonium ethane sulfate,

N,A^-dimethyl(methacrylamide propyl)ammonium butane sulfate, and

N,iV-diethyl(methacrylamide propyl)ammonium butane sulfate.

Examples of preferred phosphobetaine vinyl monomers of formula (II) include: N,A^-dimethyl(methacrylamide propyl)ammonium propane phosphate,

N,iV-diethyl(methacrylamide propyl)ammonium propane phosphate, N,A^-dimethyl(methacrylamide propyl)ammonium ethane phosphate,

N^-diethy^methacrylamide propyl)ammonium ethane phosphate,

N,A^-dimethyl(methacrylamide propyl)ammonium butane phosphate, and

N^-diethy^methacrylamide propyl)ammonium butane phosphate.

Examples of preferred phosphonate vinyl betaine monomers of formula (II) include: N,A^-dimethyl(methacrylamide propyl)ammonium propane phosphonate,

N,iV-diethyl(methacrylamide propyl)ammonium propane phosphonate,

N,A^-dimethyl(methacrylamide propyl)ammonium ethane phosphonate,

N,iV-diethyl(methacrylamide propyl)ammonium ethane phosphonate,

N,A^-dimethyl(methacrylamide propyl)ammonium butane phosphonate, and

N,iV-diethyl(methacrylamide propyl)ammonium butane phosphonate.

Examples of preferred sulfobetaine monomers of formula (I) and (II) wherein N⁺, R' and R' ' together form a saturated heterocyclic ammonium ring (heterocyclic betaine monomers) include:

; and

The person skilled in the art will understand that the SO₃ ^" group of the above monomers may be replaced by a carboxy (-COO ), sulfa (-OSO₃ ), phospho (-OPO₃ ) or phosphonate (- PO₃ ^") group.

Alternatively, the betaine monomer may be a water-soluble or water-dispersible phosphobetaine vinyl monomer having the following general formulae:

CH₂=C(R)C(0)OR₂-OP(0)(0^")0-R₃NR'R' 'R' ' ' (III); or

CH₂=C(R)C(0)NHR₂-OP(0)(0^")0-R₃NR'R"R (IV) wherein R, R₂ R3, R' and R' ' are as defined above for general formula I, and R" ' is selected from an alkyl group having from 1 to 3 carbon atoms, preferably, methyl and ethyl, most preferably methyl.

Examples of preferred betaine monomers of general formula (II) include:

methacryloyloxy ethyl phosphorylcholine (MPC); methacryloyloxypropyl phosphorylcholine; methacrylamide ethyl phosphorylcholine; and, methacrylamide propyl phosphorylcholine.

Typically, the water-soluble or water-dispersible betaine monomer comprises from 9.5 to 45 mol% of the total moles of monomers in the inverse emulsion polymerization reaction mixture. Preferably, the mol% of betaine monomer in the inverse emulsion polymerization reaction mixture is from 10 to 40 mol%, more preferably, from 15 to 35 mol%, most preferably from 20 to 35 mol% (based on the total moles of monomers in the inverse emulsion polymerization reaction mixture).

Preferably, the mol% of non-ionic comonomer in the emulsion polymerization mixture is in the range of 50 to 90 mol%, preferably, 60 to 80 mol%, in particular, 65 to 75 mol% (based on the total moles of monomers in the inverse emulsion polymerization reaction mixture).

The non-ionic comonomer (a monomer that is electrically neutral) used to prepare the polymeric microparticles may be selected from monomers that are soluble or dispersible in the internal aqueous phase of the water- in-oil emulsion (inverse emulsion) including:

acrylamide, methacrylamide, N-methylacrylamide, Ν,Ν-dimethylacrylamide, acryloyl morpholine, hydroxy ethyl acrylate, hydroxyethyl methacrylate, hydroxypropyl acrylate, hydroxypropyl methacrylate, N-(2-hydroxyethyl) acrylamide, dimethylaminoethylacrylate (DMAEA), dimethylaminoethyl methacrylate (DMAEM), 2-sulfoethyl methacrylate, 3- sulfopropyl methacrylate, maleic anhydride, N-vinyl pyrrolidone, vinyl acetate and N-vinyl formamide.

Preferred non-ionic comonomers include acrylamide, Ν,Ν' -dimethyl acrylamide and methacrylamide. Acrylamide is more preferred.

The person skilled in the art will understand that the cross-linking monomer forms covalent linkages between two copolymer chains and/or between different regions of the same copolymer chain. Structural units derived from the cross-linking monomers are included in the polymeric microparticles of the present invention to constrain the microparticle conformation at temperatures at or above the transition temperature thereby preventing the polymer chains from dissolving in the water contained in the pore space of the thief zone(s). Accordingly, the structural units derived from the "cross-linking monomer" are non-labile, i.e., are not degraded under the reservoir conditions, for example, are not degraded at the temperature of the thief zone(s) or at the pH of the water contained within the pore space of the thief zone(s).

Preferably, the cross-linking monomer comprises from 0.1 to 10 mol%, more preferably from 0.5 to 3 mol%, in particular, from 0.75 to 2 mol%, for example, from 1 to 2 mol% of the mixture of monomers used to prepare the polymeric microparticles.

Examples of non-labile cross-linking monomers that may be used to prepare the polymeric microparticles include diacrylamides and methacrylamides of diamines such as the diacrylamide or dimethacrylamide of piperazine or the diacrylamide or dimethacrylamide of methylenediamine; methacrylate esters of di, tri, tetra hydroxy compounds including ethyleneglycol dimethacrylate, polyethyleneglycol dimethacrylate, trimethylolpropane trimethacrylate, and the like; divinylbenzene, 1,3-diisopropenylbenzene, and the like; the vinyl or allyl esters of di or trifunctional acids; and, diallylamine, triallylamine, divinyl sulfone, diethyleneglycol diallyl ether, and the like. Preferred non-labile cross linking monomers include ethyleneglycol dimethacrylate, methylene bisacrylamide and divinylbenzene. The emulsion polymerization process, may be initiated using a thermal or redox free- radical initiator. Suitable initiators include azo compounds, such as azobisisobutyronitrile (AIBN), 2,2'-azobis(2,4-dimethylvaleronitrile) (ADVN) and 4,4'-azobis(4-cyanovaleric acid) (ACVA); peroxides, such as di-t-butyl peroxide; inorganic compounds, such as potassium persulfate; and, redox couples, such as bromate/bisulfite or metabisulfite (for example, KBrC /NaHSC or KBr0₃ NaS₂0₅); benzoyl peroxide/dimethylaminopyridine; and, potassium persulfate/sodium metabisulfite.

Preferably, the polymerization initiator is present in the emulsion polymerisation composition in an amount of from 0.01 to 10 mol% (based on the moles of monomers used to prepare the polymeric microparticles).

In addition to the monomers, cross-linkers, and polymerization initiator and optional non-reactive stabilizer(s), other conventional additives may be used in the synthesis of the polymeric microparticles, for instance pH adjusters, and chelating agents used to remove polymerization inhibitors.

The polymeric microparticles may be delivered to the injection site (by tanker or tanker ship) in the form obtained by the inverse emulsion (water-in-oil emulsion) polymerization process, i.e., as a water-in-oil polymer emulsion with the polymeric microparticles contained in the aqueous phase. The polymer emulsion may be inverted (the dispersed aqueous phase becomes the continuous phase) upon dilution with an aqueous injection fluid (for example, an injection water available at the injection site) at a temperature below the transition temperature of the polymeric microparticles, thereby forming a dispersion of the polymeric microparticles in the aqueous fluid. Typically, the polymer emulsion is inverted using shear, and generally, an inverting surfactant (i.e., a demulsifier). As the skilled person will appreciate, an inverting surfactant may be added to the aqueous injection fluid prior to adding the polymer emulsion to the aqueous injection fluid, i.e., the inverting may be added to the aqueous injection fluid upstream of the polymer emulsion. The inverting surfactant may be any conventional demulsifier used to break water-in-oil (inverse) emulsions.

Alternatively, the polymeric microparticles may be obtained in dry form by precipitation from the inverse emulsion using a suitable solvent, such as isopropanol, acetone, isopropanol/acetone or methanol/acetone or other solvents or solvent mixtures that are miscible with both the hydrocarbon phase and aqueous phase of the emulsion. The polymeric microparticles may be isolated from the supernatant by centrifugation or filtration and may be dried by conventional procedures. The dried microparticles may be added directly to the aqueous injection fluid (e.g., an injection water available at the injection site), for example, via a powder hopper. Typically, a surfactant dispersant is preferably added to the aqueous injection fluid upstream of the point of addition of the dried microparticles to assist in dispersing the dried microparticles in the aqueous injection fluid.

However, it is preferred to form a concentrated dispersion of the dried microparticles in either an aqueous fluid or in a water-miscible organic solvent and to subsequently dilute this concentrated dispersion into the aqueous injection fluid to form a diluted dispersion of the polymeric microparticles for injection into the thief zone of the reservoir. Preferably, the concentrated aqueous dispersion of the polymeric microparticles may be prepared by dispersing the dry polymeric particles in the aqueous fluid or in a water-miscible organic solvent in the presence of a surfactant dispersant. Suitably, the polymeric microparticles comprise from 15 to 50% by weight of the concentrated dispersion. Agitation means, for example sonication or shear, may be used to promote the formation of a stable dispersion. The concentrated dispersion may be prepared either at the injection site or at a site remote from the injection site and is subsequently delivered to the injection site via a tanker or tanker ship.

Suitable water-miscible solvents include tetrahydrofuran, 1,3-butylene glycol, tetrahydrofurfuryl alcohol, ethylene glycol monobutyl ether, ethylene glycol methyl ether, mono ethylene glycol, and methyl ethyl ketone. Optionally, the water-miscible solvent may be subsequently removed from the diluted dispersion via a cross-flow ultrafiltration process, by a dialysis process or by evaporation.

Suitable surfactant dispersants are well known to the person skilled in the art and include sodium dodecylsulfate, nonylphenylethoxylates, polyoxyethylene-20-sorbitan monooleate, nonionic ethylene oxide/propylene oxide block copolymer surfactants, and zwitterionic surfactants such as cocamidopropyl hydroxysultaine and, in particular, betaine surfactants such as cocamidopropylbetaine. Preferably, the diluted dispersion of microparticles in the aqueous injection fluid (formed by inverting the polymer emulsion in the aqueous injection fluid, by dispersing dried microparticles in the aqueous injection fluid, or by diluting a concentrated dispersion of the dried microparticles in the aqueous injection fluid) comprises from 0.01 to 10 % by weight, more preferably from 0.02 to 5 % by weight, and most preferably from 0.05 to 1 % by weight of microparticles based on the total weight of the dispersion.

The person skilled in the art will recognize that the physical properties of the polymeric microparticles, for example, their size, dispersity and transition temperature, can be tailored to the conditions encountered in the thief zone of the reservoir.

The particle size distribution of the polymeric microparticles can be varied by varying the size of the emulsion droplets in the emulsion polymerization process used to prepare the polymeric microparticles. This may be achieved by varying the stirring method or stirrer speed used in the emulsion polymerization process. Suitable methods of stirring the emulsion include the use of magnetic stirrers or paddle stirrers. The particle size distribution may also be varied by varying the types and concentrations of the surfactants used to stabilize the inverse emulsion, and the concentration of monomers used in the inverse emulsion polymerization process. Such methods of varying the particle size distribution are well known to the person skilled in the art.

The dispersity of the polymeric microparticles may be varied by changing the amount or type of monomer with the betaine group used in the preparation of the polymeric

microparticles and/or the amount or type of surfactant employed when dispersing the polymeric microparticles into the aqueous fluid.

Without wishing to be bound by any theory, the transition temperature of the polymeric microparticles may be varied by varying one or more of:

(a) the mol% of betaine monomer used in the preparation of the polymeric microparticles by inverse emulsion polymerization and hence the mol% of units derived from this monomer in the cross-linked copolymer chains of the polymeric microparticles; (b) the mol% of cross-linking monomer used in the preparation of the polymeric microparticles by inverse emulsion polymerization and hence the extent of cross- linking of the copolymer chains;

(c) the chemical structure of the betaine monomer used in the preparation of the polymeric microparticles by inverse emulsion polymerisation; and

(d) the chemical structure of the non-ionic comonomer used in the preparation of the polymeric microparticles by inverse emulsion polymerization.

It has been found that the transition temperature for the polymeric microparticles increases with increasing mol% of units derived from the betaine monomer.

Without wishing to be bound by any theory, the transition temperature of the polymeric microparticles increases with increasing salinity of the aqueous fluid in which the polymeric microparticles are dispersed. The person skilled in the art will understand that the injected dispersion of the polymeric microparticles in the aqueous fluid may mix with the formation water contained within the pore space of the thief zone such that the transition temperature of the polymeric microparticles may be dependent upon both the salinity of the aqueous fluid of the dispersion and the salinity of the formation water. The target amount of structural units derived from the monomer with the betaine group in the copolymer chains may therefore be varied depending on the salinity to which the polymeric microparticles are exposed within the thief zone. The salinity to which the polymeric microparticles are exposed in the thief zone may be estimated by modelling dispersive mixing of the injected dispersion with the formation water, for example, using a reservoir simulator such as STARS™.

It has also been found that the transition temperature of the polymeric microparticles increases with increasing carbon chain length of the alkylene group that links the cationic group and the anionic group of the betaine monomers. Typically, there is at least a 5 °C increase in the transition temperature at which the polymeric microparticles begin to expand in size with each additional carbon atom in the alkylene linker group of the betaine groups of the structural units derived from the betaine monomer.

The dispersion of the present invention is preferably injected into a thief zone of a reservoir in an amount that is suitable for reducing the permeability of a thief zone to water. The skilled person could determine a suitable amount which will be dependent upon the pore volume of the thief zone. As the skilled person will appreciate, the amount of the dispersion that is required may also be dependent on the concentration (weight percent) of the polymeric microparticles dispersed in the aqueous fluid. Thus, the required pore volume of the dispersion will decrease with increasing concentration of the polymeric microparticles dispersed in the aqueous fluid.

Suitably, the dispersion comprising the polymeric microparticles of the present invention dispersed in an aqueous fluid is injected into the reservoir in a pore volume amount in the range of 0.05 to 1, preferably 0.2 to 0.5, typically about 0.3 PV.

The term "pore volume" is used herein to mean the "effective pore volume" between an injection well and a production well. The "effective pore volume" is the interconnected pore volume or void space in a rock that contributes to fluid flow or permeability in a reservoir. Effective pore volume excludes isolated pores and pore volume occupied by water adsorbed on clay minerals or other grains. Effective pore volume may be determined using techniques well known to the person skilled in the art such as from reservoir modelling or reservoir engineering calculations.

According to the process of the present invention, the dispersion is injected down an injection well (or alternatively a production well that has been taken off production) and into a thief zone so as to reduce the permeability of the thief zone to water. Initial expansion and aggregation of the polymeric microparticles may occur in a single location in a thief zone or at a plurality of locations. For instance, different forms or grades of microparticles may be present in a single dispersion according to the present invention. These different grades of microparticles may undergo expansion and aggregation at different transition temperatures. In turn, expansion and aggregation of the different grades of microparticles may occur in the thief zone at different locations having different temperatures, thereby reducing the permeability of the thief zone to water at a plurality of locations. In an embodiment, the dispersion of the present invention may be used to reduce the permeability of a plurality of thief zones. The well into which the dispersion of the present invention is injected may be an injection well or a production well that penetrates at least one thief zone and at least one hydrocarbon-bearing zone of the petroleum reservoir. Where the dispersion of the present invention is injected into a production well, the well is taken off production prior to injection of the composition.

The transition temperature of the polymeric microparticles of the dispersion should be greater than the maximum temperature encountered in the well into which the dispersion of the polymeric microparticles is injected. It will be understood that by using microparticles having a transition temperature which is greater than the maximum temperature encountered in the well, expansion and aggregation of the polymeric microparticles before they enter the thief zone can be avoided. The maximum temperature encountered in a particular well may be readily determined by the skilled person.

The transition temperature of the polymeric microparticles should also be at or below the maximum temperature encountered in the thief zone such that the polymeric microparticles expand and aggregate within the thief zone of the reservoir. The person skilled in the art will understand that the temperature of the thief zone of the reservoir may vary with increasing radial distance from the well into which the dispersion comprising the temperature sensitive microparticles is injected. For example, in reservoirs where a waterflood has already taken place, the previously injected water typically has a temperature significantly below the original temperature of the reservoir and therefore injection of the water results in a temperature gradient across the reservoir, i.e., the injection of cold water has a cooling effect in the vicinity of the injection well and for some distance beyond it. Thus, typically, there is a temperature front in various layers of the reservoir at a radial distance from the injection well with the temperature front advancing through the layers of the reservoir over time. Thus, although the original temperature of the reservoir may be in the range of 80 to 140°C, substantial cooling of the layers of the reservoir, and hence the thief zone or zones, may have occurred during a waterflood. Typically, the temperature of the reservoir in the cooled region of the thief zone or zones (behind the temperature front) may be in the range of 25 to 120°Cu, in particular 25 to 80°C, for example 25 to 60°C. Generally, the temperature in the cooled region of the thief zone or zones is 10 to 60°C below, for example, 20 to 50°C below the original reservoir temperature. Accordingly, the temperature at which expansion and aggregation of the dispersed microparticles is induced (i.e. the transition temperature) may be significantly less than the original reservoir temperature prior to waterflooding. The person skilled in the art will understand that the extent of any cooling of the thief zone in the near wellbore region of a production well is likely to be less than the extent of any cooling of the thief zone in the near wellbore region of an injection well. Preferably, the transition temperature of the polymeric microparticles is at or slightly below (e.g. less than 30 °C below, preferably less than 20 °C below and more preferably less than 10 °C below) the maximum temperature encountered in the thief zone, so that the polymeric microparticles expand only after they have propagated deep into the thief zone.

The transition temperature of the polymeric microparticles of the dispersion employed in the process of the present invention may be readily determined by the person skilled in the art. As discussed above, the transition temperature may be adjusted by appropriate selection of the amount of monomer with the betaine group used to prepare the polymeric

microparticles, the composition of the monomer with the betaine group, the composition of the non-ionic comonomer. Accordingly, dispersions of microparticles may be prepared which have an appropriate transition temperature for the temperatures encountered within the thief zone where it is desired to form a block, or multiple blocks of expanded and aggregated microparticles.

Once expansion and aggregation of the polymeric microparticles is triggered, it is believed that the aggregated microparticles block the pore throats of the thief zone and the flow of subsequently injected water is largely diverted into neighbouring, previously unswept zones of the reservoir. After a period of time, the subsequently injected water flowing through neighbouring zones of the reservoir acts to cool the blocked region of the thief zone to below the transition temperature resulting in de-aggregation of the aggregates and contraction of the expanded microparticles such that the contracted microparticles become redispersed in water. The resulting microparticle dispersion then flows on through the thief zone before forming a subsequent block once a further region of the thief zone having a temperature at or above the transition temperature is reached. In this way, the present invention allows for the formation of multiple, successive blocks within a thief zone such that a greater volume of the reservoir may be swept by subsequently injected water. The net result is that more water passes through the previously unswept zones, with more oil being swept towards the production well, i.e. sweep efficiency is improved.

Where the dispersion is injected from a production well into a thief zone or zones, if necessary, ambient temperature water (for example, seawater, estuarine water, river water, lake water or desalinated water having a temperature of about 3 to 15°C), may be injected into the thief zone ahead of the composition of the present invention in order to cool the production well and thief zone thereby mitigating the risk of premature expansion and aggregation of the polymeric microparticles in the production well or in the near wellbore region of the thief zone (close to the production well).

The thief zone of the reservoir may be a layer of reservoir rock having a permeability greater than the permeability of adjacent hydrocarbon-bearing layers of the reservoir, for example, at least 50% greater. For example, the by-passed adjacent hydrocarbon-bearing layers of the reservoir may have a permeability, for example, in the range of 30 to 100 millidarcies while the thief layer may have a permeability, for example, in the range of 90 to less than 6,000 millidarcies, in particular, 90 to 1,000 millidarcies, with the proviso that the thief layer has a permeability at least 3 times greater, preferably, at least 4 times greater than that of the adjacent by-passed layers of the reservoir.

Alternatively, the thief zone of the reservoir may be a layer of reservoir rock having fractures therein that may be up to several hundreds of metres in length. Depending on the temperature of the surrounding rock and on the length of the fracture, the dispersion of the polymeric microparticles may penetrate a significant distance into a fracture, for example, to the fracture tip, before encountering the threshold temperature at which the polymeric microparticles expand and block the fracture.

Without wishing to be bound by any theory, the transition temperature for the polymeric microparticles of the aqueous dispersion may be dependent of the salinity (total dissolved solids content) of the aqueous fluid of the dispersion with the transition temperature increasing with increasing salinity.

The aqueous injection fluid may be any water suitable for injection into a subterranean formation via an injection well. Suitably, the polymeric microparticles are dispersed in an aqueous fluid having a total dissolved solids (TDS) content in the range of 200 to 50,000 mg/L, preferably, 200 to 40,000 mg/L, for example, in the range of 500 to 17,500 mg/L.

Suitably, the aqueous fluid of the dispersion may be low salinity water having a total dissolved solids content of less than 10,000 mg/L, preferably, less than 5000 mg/L, most preferably, less than 3000 mg/L. Suitably, the aqueous fluid of the dispersion is a low salinity water having a total dissolved solids content in the range of 500 to 3000 mg/L, in particular, 500 to 1000 mg/L. However, it is also envisaged that the polymeric microparticles may be formulated to solvate, expand in size and aggregate in higher salinity waters such as seawater.

The multivalent cation content of the aqueous fluid may be up to 50 mol% (based on the total moles of inorganic cations).

In at least some examples of the process for modifying the permeability to water of a thief zone, the composition comprises a dispersion of the polymeric microparticles in a high salinity water (such seawater, sulfate reduced seawater or a high salinity produced water), a brackish water (such as estuarine water, sulfate reduced estuarine water, a brackish produced water, or a brackish aquifer water) or a fresh water (such as lake water, river water, desalinated water, aquifer water). By "produced water" is meant water produced in the process of recovering hydrocarbons from the reservoir or in any other process.

Optionally, the composition (dispersion of microparticles in an aqueous injection fluid) employed in the method of the present invention may further comprise one or more conventional additives used in enhanced oil recovery, such as viscosifiers, polymers and/or pH adjusters.

Owing to the difference in permeability between thief zones and adjacent hydrocarbon fluid-bearing zones of the reservoir, in the process of the present invention, most of the injected composition of the present invention enters the thief zone. However, if desired, the hydrocarbon fluid-bearing zones of the reservoir may be isolated from the well, for example, packers may be arranged in the well, above and below a thief zone, in order to mitigate the risk of the injected dispersion entering adjacent hydrocarbon fluid-bearing zones of the reservoir.

In at least some examples of the present invention, the composition of the present invention is injected continuously or intermittently, preferably, continuously, into the reservoir for up to 4 weeks, for example for 5 to 15 days.

The invention will now be demonstrated by reference to the following Examples.

Example 1

Polymeric microparticles comprising a copolymer of acrylamide and is N,N- dimethyl(methacryloyloxyethyl)ammonium propane sulfonate (DMAPS) (90/10 mol/mol) cross-linked by 0.2 mol percent of Ν,Ν'-methylenebisacrylamide (MBA) was prepared by inverse emulsion polymerisation. The mol percent of MBA was based on the total moles of monomer.

The polymer synthesis comprised two steps: preparation of the emulsion and polymerization.

Emulsion Preparation:

At room temperature in a 2 litre glass flask were mixed 26.3 grams ("g") of sorbitan monolaurate surfactant (Alkamuls S20), 75.1 g of ethoxylated sorbitan laurate surfactant (Alkamuls S80), 16.5 g of an amphiphilic block copolymer surfactant (Rhodibloc RS), 7.1 g of a block copolymer surfactant comprising a block of poly(12-hydrostearic acid) and a block of poly(ethylene oxide) (Hypermer B246SF) and 797 g of Exxsol™ D100S fluid (a hydrocarbon solvent comprised of n-alkanes, isoalkanes, cyclic hydrocarbons and less than 2% aromatics). The resulting mixture was stirred by magnetic stirring until a clear solution was obtained (mixture 1).

In another 2 litre glass flask were mixed 250.9 g of

sulphopropyldimethylammoniopropylmethacrylamide (SPP; molecular weight: 292.39), 1097.2 g of a 50 percent solution of acrylamide in water (548.6 g of acrylamide; molecular weight: 71.09), 2.644g of MBA (molecular weight: 154.17), 2.44 g of 2,2'-azobis(2- methylpropionamidine)dihydrochloride initiator (Wako V-50) and 2 g of Versene™ 100 chelating agent (an aqueous solution of tetrasodium diethylenetriaminetetraacetic). The resulting mixture was subjected to magnetic stirring until a clear solution was obtained (mixture 2).

Mixture 2 was then added to mixture 1 under magnetic stirring. The resulting mixture was then mixed using a rotor stator mixer (Ultra- turrax mixture) at 1000 revolutions per minute (rpm) over 10 seconds (s) to obtain an inverse emulsion (water- in-oil emulsion). Copolymerization :

The polymerization step was carried out by circulating the mixture obtained in step 1 in a continuous tubular reactor wherein the temperature was kept at 60°C, with a 2 hour residence time.

The final product obtained contained 30 to 35 percent by weight of polymeric microparticles having a particle size of about 500 to 600 nm average (determined by light scattering using a Malvern Zeta-sizer device). Particle size can be adjusted by controlling both the surfactant content and the shear applied during the preparation of the emulsion. Particle size may be controllable in a range of 50 nm to 2,000 nm (0.05 to 2 μηι), preferably 75 to 1000 nm (0.075 to 1 μιη), more preferably 100 to 1000 nm (0.1 to 1 μιη), in particular 150 to 750 nm (0.15 to 0.75 μπι).

Example 2

Polymeric microparticles comprising a copolymer of acrylamide and is N,N- dimethyl(methacryloyloxyethyl)ammonium propane sulfonate (DMAPS) (75/25 mol/mol) cross-linked by 1.0 mol percent of Ν,Ν'-methylenebisacrylamide (MBA) was prepared by inverse emulsion polymerisation. The process of Example 1 was repeated except that the ratio of acrylamide to DMAPS was adjusted and the amount of MBA was increased to 13.22 g.

Claims

1. Expandable polymeric microparticles comprising cross-linked copolymer chains having structural units derived from (i) a water-soluble or water-dispersible monomer with a betaine group ("betaine monomer"), (ii) a water-soluble or water-dispersible non-ionic comonomer ("non-ionic comonomer"), and, (iii) a water-soluble or water-dispersible non- labile cross-linking monomer having at least two sites of ethylenic unsaturation ("non-labile cross-linking monomer") wherein the copolymer chains of the polymeric microparticles comprise from 9.5 to 45 mol% of structural units derived from the betaine monomer and from 0.1 to 10 mol% of structural units derived from the non-labile cross-linking monomer; and wherein the polymeric microparticles have an unexpanded average particle diameter in the range of from 0.05 to 5μηι and the polymeric microparticles expand in size when dispersed in an aqueous fluid at or above a transition temperature.

2. Polymeric microparticles according to Claim 1, wherein the copolymer chains have structural units derived from a betaine monomer of general formulae:

CH₂=C(R)C(0)OR₂N⁺R'R"R₃X^" (I); or

CH₂=C(R)C(0)NHR₂N⁺R'R"R₃X^" (II)

X is selected from sulfo (-SO₃ ), carboxy (-COO ), sulfa (-OSO₃ ), phospho (-OPO₃ ) and phosphonate (-PO₃ ) groups.

3. Polymeric microparticles according to Claim 1, wherein the copolymer chains have structural units derived from a betaine monomer of general formulae: CH₂=C(R)C(0)OR₂-OP(0)(0^")0-R₃NR'R' 'R' ' ' (III); or

CH₂=C(R)C(0)NHR₂-OP(0)(0^")0-R₃NR'R' 'R' ' ' (IV)

R' and R' ' are independently selected from alkyl groups having from 1 to 3 carbon atoms, preferably, methyl and ethyl, most preferably methyl; or N⁺, R' and R' ' together form a saturated heterocyclic ammonium ring, optionally, having an oxygen heteroatom in the ring, preferably, a piperidinium or morpholinium ring and R" ' is selected from an alkyl group having from 1 to 3 carbon atoms, preferably, methyl and ethyl, most preferably methyl.

4. Polymeric microparticles according to Claims 2 or 3, wherein the copolymer chains have structural units derived from a betaine monomer selected from the group consisting of:

NJ*T -dimethyl(methacryloylethyl)ammonium propane sulfonate NJ*T - diethyl(methacryloylethyl)ammonium propane sulfonate, NJ - dimethyl(methacryloylethyl)ammonium ethane sulfonate, NJ - diethyl(methacryloylethyl)ammonium ethane sulfonate, methacryloyloxyethyl

phosphorylcholine (MPC); and methacryloyloxypropyl phosphorylcholine.

5. Polymeric microparticles according to any one of Claims 1 to 4, wherein the copolymer chains have structural units derived from a non-ionic comonomer selected from the group consisting of acrylamide, methacrylamide, N-methylacrylamide, N,N-dimethylacrylamide, acryloyl morpholine, hydroxy ethyl acrylate, hydroxyethyl methacrylate, hydroxypropyl acrylate, hydroxypropyl methacrylate, N-(2-hydroxyethyl) acrylamide,

dimethylaminoethylacrylate (DMAEA), dimethylaminoethyl methacrylate (DMAEM), 2- sulfoethyl methacrylate, 3-sulfopropyl methacrylate, maleic anhydride, N- vinyl pyrrolidone, vinyl acetate and N-vinyl formamide.

6. Polymeric microparticles according to any one of Claims 1 to 5, wherein the copolymer chains have structural units derived from a cross-linking monomer selected from the group consisting of diacrylamides and methacrylamides of diamines; methacrylate esters of di, tri, and tetra hydroxy compounds; divinylbenzene, 1,3-diisopropenylbenzene; vinyl or allyl esters of di or trifunctional acids; diallylamine, triallylamine, divinyl sulfone, and diethyleneglycol diallyl ether.

7. A dispersion of polymeric microparticles in an aqueous fluid wherein the polymeric microparticles are as defined in any one of claims 1 to 6.

8. A dispersion according to Claim 7 wherein the initial average particle diameter of the polymeric microparticles is in the range of 0.05 to 2 μηι, the average particle diameter of the expanded microparticles in the range of 1 to 10 μηι and wherein the ratio of the volume of the expanded microparticles to the initial volume of the unexpanded microparticles is at least 5: 1, preferably, at least 10: 1, more preferably, at least 20: 1.

9. A process for recovering hydrocarbon fluids from a porous and permeable subterranean petroleum reservoir comprising at least one higher permeability zone and at least one lower permeability zone that are penetrated by at least one injection well and at least one production well, the process comprising:

(a) injecting a dispersion of expandable polymeric microparticles in an aqueous fluid into the higher permeability zone of the reservoir from the injection well or from the production well wherein the expandable polymeric microparticles comprise cross-linked copolymer chains having structural units derived from (i) a water-soluble or water-dispersible monomer with a betaine group ("betaine monomer"), (ii) a water-soluble or water-dispersible non-ionic comonomer ("non-ionic comonomer"), and, (iii) a water-soluble or water-dispersible non- labile cross-linking monomer having at least two sites of ethylenic unsaturation ("cross- linking monomer") wherein the copolymer chains of the polymeric microparticles comprise from 9.5 to 45 mol% of structural units derived from the non-ionic comonomer and from 0.1 to 10 mol% of structural units derived from the cross-linking monomer; and wherein the polymeric microparticles have an unexpanded average particle diameter of from 0.05 to 5 μηι and expand in size at or above a transition temperature and wherein the injection well has a maximum temperature below the transition temperature of the polymeric microparticles and the higher permeability zone has a region between the injection well and production well having a temperature at or above the transition temperature of the polymeric microparticles;

(b) propagating the dispersion through the higher permeability zone until the dispersion reaches the region of the higher permeability zone having the temperature at or above the transition temperature such that the polymeric microparticles expand in size thereby reducing the permeability of the higher permeability zone of the reservoir;

(c) diverting subsequently injected aqueous fluid from the higher permeability zone into the lower permeability zone of the reservoir; and

(d) recovering hydrocarbon fluids from said at least one production well.

10. A process according to Claim 9, wherein the dispersion comprises polymeric

microparticles as defined in any one of Claims 2 to 6.

11. A process according to any one of Claims 9 or 10 wherein the transition temperature of the polymeric microparticles is adjusted by adjusting the molar ratio of structural units in the copolymer chains derived from the non-ionic comonomer and from the monomer with the betaine group.

12. A process according to any one of Claims 9 to 11, wherein the high permeability zone is a layer of reservoir rock having at least 50% greater permeability than the permeability of the lower permeability zone of the reservoir.

13. A process according to any one of Claims 9 to 12, wherein the initial average particle diameter of the polymeric microparticles is in the range of 0.05 to 2 μηι, the average particle diameter of the expanded polymeric microparticles in the range of 1 to 10 μηι, and the ratio of the volume of the expanded polymeric microparticles to the initial volume of the unexpanded polymeric microparticles is at least 5: 1, preferably, at least 10: 1, more preferably, at least 20: 1.

14. A process according to any one of Claims 9 to 13 wherein the expanded polymeric microparticles form aggregates within the high permeability zone that have an average particle diameter in the range of 1000 to 10000 nm.

15. A process according to any one of Claims 9 to 14, wherein the dispersion comprises polymeric microparticles with a transition temperature in the range of 40 to 90°C, preferably, 50 to 80°C, the temperature in the well into which the dispersion is injected is 30°C or less, and the high permeability zone has a region between the injection well and production well having a temperature above the transition temperature of the polymeric microparticles.

16. A process according to any one of the Claims 9 to 15 wherein cooling of the high permeability zone in the location of the block to a temperature below the transition temperature results in contraction and de-aggregation of the polymeric microparticles and wherein the polymeric microparticles become redispersed in water and the resulting dispersion permeates through the thief zone until it reaches another region where the temperature is at or above the transition temperature where the polymeric microparticles expand in size to form a further block.

17. A method for preparing expandable polymeric microparticles by inverse emulsion polymerization of (i) a water-soluble or water-dispersible monomer with a betaine group ("betaine monomer"), (ii) a water-soluble or water-dispersible non-ionic comonomer (non- ionic comonomer") and (iii) a cross-linking monomer having at least two sites of ethylenic unsaturation ("cross-linking monomer") in the presence of a radical initiator wherein droplets of an aqueous phase comprising an aqueous solution or dispersion of monomers (i), (ii) and (iii) are dispersed in a continuous oil phase comprising an organic solvent or mixture of organic solvents and wherein the droplets of the aqueous phase have an average diameter in the range of 0.05 to 5 μηι and wherein the betaine monomer comprises from 9.5 to 45 mol% and the cross-linking monomer from 0.1 to 10 mol% of the total moles of monomers.

18. A method according to Claim 17 wherein the betaine monomer is of general formulae:

CH₂=C(R)C(0)OR₂N⁺R'R"R₃X^" (I); or

CH₂=C(R)C(0)NHR₂N⁺R'R"R₃X^" (II)

19. A method according to Claim 17 wherein the betaine monomer is of general formulae:

CH₂=C(R)C(0)OR₂-OP(0)(0^")0-R₃NR'R' 'R' ' ' (III); or

CH₂=C(R)C(0)NHR₂-OP(0)(0^")0-R₃NR'R"R (IV)

R₂ and R₃ are alkylene groups, in particular, C₂ to C₆ alkylene groups, and are preferably independently selected from the group consisting of ethylene, n-propylene or n-butylene groups;

20. A method according to Claims 18 or 19 wherein the betaine monomer is selected from the group consisting of:

phosphorylcholine (MPC); and methacryloyloxypropyl phosphorylcholine.

21. A method according to any one of Claims 17 to 20 wherein the non-ionic comonomer is selected from the group consisting of acrylamide, methacrylamide, N-methylacrylamide, N,N- dimethylacrylamide, acryloyl morpholine, hydroxyethyl acrylate, hydroxyethyl methacrylate, hydroxypropyl acrylate, hydroxypropyl methacrylate, N-(2-hydroxyethyl) acrylamide, dimethylaminoethylacrylate (DMAEA), dimethylaminoethyl methacrylate (DMAEM), 2- sulfoethyl methacrylate, 3-sulfopropyl methacrylate, maleic anhydride, N-vinyl pyrrolidone, vinyl acetate and N-vinyl formamide.

22. A method according to any one of Claims 17 to 21 wherein the cross-linking monomer is selected from the group consisting of diacrylamides and methacrylamides of diamines;

methacrylate esters of di, tri, and tetra hydroxy compounds; divinylbenzene, 1,3- diisopropenylbenzene; vinyl or allyl esters of di or trifunctional acids; diallylamine, triallylamine, divinyl sulfone, and diethyleneglycol diallyl ether.